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As filed with the Securities and Exchange Commission on December 2, 2014

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

RICE ENERGY INC.

(AND CERTAIN SUBSIDIARIES OF RICE ENERGY INC. IDENTIFIED IN

FOOTNOTE (*) BELOW)

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware		1311		46-3785773
(State or Other Jurisdiction of Incorporation or Organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

400 Woodcliff Drive

Canonsburg, Pennsylvania 15317

(724) 746-6720

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

 

Daniel J. Rice IV

Chief Executive Officer

Rice Energy Inc.

400 Woodcliff Drive

Canonsburg, Pennsylvania 15317

(724) 746-6720

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)

 

 

Copies to:

Douglas E. McWilliams

Alan Beck

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002

(713) 758-2222

 

 

Approximate date of commencement of proposed sale of the securities to the public:

As soon as practicable after the effective date of this Registration Statement.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer		¨		Accelerated filer		¨
Non-accelerated filer		x  (Do not check if a smaller reporting company)		Smaller reporting company		¨

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issue Tender Offer)  ¨

Exchange Act Rule 14d-1(d) (Cross-Border Third-Party Tender Offer)  ¨

 

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to Be Registered		Amount to be Registered		Amount of Registration Fee(1)
6.25% Senior Notes due 2022		$900,000,000		$104,580
Guarantees of 6.25% Senior Notes due 2022(2)				None(3)

(1)	Calculated pursuant to Rule 457(f)(2) under the Securities Act of 1933.

(2)	Each subsidiary of Rice Energy Inc. that is listed on the Table of Additional Registrant Guarantors has guaranteed the notes being registered.

(3)	Pursuant to Rule 457(n) of the Securities Act of 1933, no registration fee is required for the Guarantees.

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

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TABLE OF ADDITIONAL REGISTRANT GUARANTORS

 

*	The following are co-registrants that guarantee the debt securities:

 

Exact Name of Registrant Guarantor(1)		State or Other Jurisdiction of Incorporation or Formation		IRS Employer Identification Number
Rice Marketing LLC		Delaware			47-2089524
Rice Energy Marketing LLC		Delaware			45-4877837
Rice Energy Appalachia, LLC		Delaware			61-1671607
Rice Drilling B LLC		Delaware			26-1953720
Rice Drilling C LLC		Pennsylvania			27-0970344
Rice Drilling D LLC		Delaware			90-0779528
Rice Poseidon Midstream LLC		Delaware			30-0787520
Rice Olympus Midstream LLC		Delaware			61-1715254
Blue Tiger Oilfield Services LLC		Delaware			61-1671607
Alpha Shale Holdings, LLC		Delaware			27-1785095
Alpha Shale Resources, LP		Delaware			27-1785246

 

(1)	The address for each Registrant Guarantor is 400 Woodcliff Drive, Canonsburg, Pennsylvania 15317, and the telephone number for each Registrant Guarantor is (724) 746-6720. The Primary Industrial Classification Code for each Registrant Guarantor is 1311.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

Subject to completion, dated December 2, 2014

PROSPECTUS

Rice Energy Inc.

Offer to Exchange

Up To $900,000,000 of

6.25% Senior Notes due 2022

That Have Not Been Registered Under

The Securities Act of 1933

For

Up To $900,000,000 of

6.25% Senior Notes due 2022

That Have Been Registered Under

The Securities Act of 1933

 

 

Terms of the New 6.25% Senior Notes due 2022 Offered in the Exchange Offer:

 

•

The terms of the new notes are identical to the terms of the old notes that were issued on April 25, 2014, except that the new notes will be registered under the Securities Act of 1933 (the “Securities Act”) and will not contain restrictions on transfer, registration rights or provisions for additional interest.

Terms of the Exchange Offer:

 

•

We are offering to exchange up to $900,000,000 of our old notes for new notes with materially identical terms that have been registered under the Securities Act and are freely tradable.

 

•

We will exchange all old notes that you validly tender and do not validly withdraw before the exchange offer expires for an equal principal amount of new notes.

 

•

The exchange offer expires at 5:00 p.m., New York City time, on                     , 2014, unless extended.

 

•

Tenders of old notes may be withdrawn at any time prior to the expiration of the exchange offer, in accordance with the procedures set forth herein.

 

•

We believe that the exchange of new notes for old notes will not be a taxable event for U.S. federal income tax purposes.

 

•

Broker-dealers who receive new notes pursuant to the exchange offer acknowledge that they will deliver a prospectus in connection with any resale of such new notes.

 

•

Broker-dealers who acquired the old notes as a result of market-making or other trading activities may use the prospectus for the exchange offer, as supplemented or amended, in connection with resales of the new notes.

 

 

You should carefully consider the risk factors beginning on page 7 of this prospectus before participating in the exchange offer.

We are not asking you for a proxy and you are requested not to send us a proxy.

 

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

The date of this prospectus is                     , 2014.

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This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than its respective date.

TABLE OF CONTENTS

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			iii
PROSPECTUS SUMMARY			1
RISK FACTORS			7
EXCHANGE OFFER			37
USE OF PROCEEDS			44
SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA			45
RATIOS OF EARNINGS TO FIXED CHARGES			47
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			48
BUSINESS			75
MANAGEMENT			101
EXECUTIVE COMPENSATION			107
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			115
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			117
DESCRIPTION OF NOTES			120
PLAN OF DISTRIBUTION			168
MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES			169
LEGAL MATTERS			170
EXPERTS			170
INDEX TO FINANCIAL STATEMENTS			F-1
Annex A—Letter of Transmittal			A-1
Annex B—Glossary of Oil and Natural Gas Terms			B-1

 

 

This prospectus refers to important business and financial information about Rice Energy Inc. that is not included or delivered with this prospectus. Such information is available without charge to holders of old notes upon written or oral request made to the office of Rice Energy Inc., 400 Woodcliff Drive, Canonsburg, Pennsylvania 15317 (Telephone: (724) 746-6720). To obtain timely delivery of any requested information, holders of old notes must make any request no later than                     , 2015 which is five business days prior to the expiration of the exchange offer.

 

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Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the following terms have the following meanings:

 

•

“Rice Energy,” the “Company,” “we,” “our,” “us” or like terms refer to Rice Energy Inc. and its consolidated subsidiaries, including Rice Drilling B LLC;

 

•

“Rice Drilling B” refers to Rice Drilling B LLC, our wholly-owned subsidiary;

 

•

“Rice Partners” refers to Rice Energy Family Holdings, LP (formerly known as Rice Energy Limited Partners), an entity affiliated with members of the Rice family, which was dissolved in November 2014;

 

•

“Rice Holdings” refers to Rice Energy Holdings LLC;

 

•

“Rice Appalachia” refers to Rice Energy Appalachia, LLC, the parent company of Rice Drilling B prior to our initial public offering;

 

•

“Alpha Holdings” refers to Foundation PA Coal Company, LLC, a wholly owned indirect subsidiary of Alpha Natural Resources, Inc.;

 

•

“Marcellus joint venture” refers collectively to Alpha Shale Resources, LP and its general partner, Alpha Shale Holdings, LLC;

 

•

“Natural Gas Partners” refers to a family of private equity investment funds organized to make direct equity investments in the energy industry, including the funds invested in us; and

 

•

“NGP Holdings” refers to NGP Rice Holdings, LLC.

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and income/losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

 

•

business strategy;

 

•

reserves;

 

•

financial strategy, liquidity and capital required for our development program;

 

•

realized natural gas, NGL and oil prices;

 

•

timing and amount of future production of natural gas, NGLs and oil;

 

•

hedging strategy and results;

 

•

future drilling plans;

 

•

competition and government regulations;

 

•

pending legal or environmental matters;

 

•

marketing of natural gas, NGLs and oil;

 

•

leasehold or business acquisitions;

 

•

costs of developing our properties and conducting our gathering and other midstream operations;

 

•

general economic conditions;

 

•

credit markets;

 

•

uncertainty regarding our future operating results; and

 

•

plans, objectives, expectations and intentions contained in this prospectus that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility; inflation, lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital; the timing of development expenditures; and the other risks described under “Risk Factors” in this prospectus.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.

 

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If significant, such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, and NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

 

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RISK FACTORS

This offering involves a high degree of risk. You should carefully consider and evaluate all of the information and data included in this prospectus before deciding to participate in the exchange offer. The risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations. If any of the following risks actually occur, our business, financial condition and results of operations could be materially and adversely affected and we may not be able to achieve our goals. We cannot assure you that any of the events discussed in the risk factors below will not occur. If these risks occur, the value of our securities could decline and you could lose some or all of your investment. The trading price of the new notes could decline, and you may lose all or part of your investment. The risks described below are not the only ones facing our company.

Risks Related to Our Business

Natural gas, NGL and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our natural gas production heavily influence, and to the extent we produce oil and NGLs in the future, the prices we receive for oil and NGL production will heavily influence, our revenue, operating results profitability, access to capital, future rate of growth and carrying value of our properties. Natural gas, NGLs and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

 

•

worldwide and regional economic conditions affecting the global supply of and demand for natural gas, NGLs and oil;

 

•

the price and quantity of imports of foreign natural gas, including liquefied natural gas;

 

•

political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

 

•

the level of global exploration and production;

 

•

the level of global inventories;

 

•

prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

 

•

the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;

 

•

localized and global supply and demand fundamentals and transportation availability;

 

•

weather conditions and natural disasters;

 

•

technological advances affecting energy consumption;

 

•

the cost of exploring for, developing, producing and transporting reserves;

 

•

speculative trading in natural gas and crude oil derivative contracts;

 

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risks associated with operating drilling rigs;

 

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the price and availability of competitors’ supplies of natural gas and oil and alternative fuels; and

 

•

domestic, local and foreign governmental regulation and taxes.

 

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Furthermore, the worldwide financial and credit crisis in recent years has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide resulting in a slowdown in economic activity and recession in parts of the world. This has reduced worldwide demand for energy and resulted in lower natural gas, NGL and oil prices.

In addition, substantially all of our natural gas production is sold to purchasers under contracts with market-based prices. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of location differentials. Location differentials to NYMEX Henry Hub prices, also known as basis differentials, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors. We may experience differentials to NYMEX Henry Hub prices in the future, which may be material.

Lower commodity prices and negative increases in our differentials will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that we can produce economically.

If commodity prices further decrease or our negative differentials further increase, a significant portion of our development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices or an increase in our negative differentials may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our natural gas reserves.

The natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas reserves. In 2014, we plan to invest $1,230.0 million in our operations (excluding acquisitions), including $430.0 million for drilling and completion in the Marcellus Shale, $150.0 million for drilling and completion in the Utica Shale, $385.0 million for leasehold acquisitions and $265.0 million for midstream infrastructure development. Our capital budget excludes acquisitions, other than leasehold acquisitions. We expect to fund our 2014 capital expenditures with cash generated by operations, borrowings under our revolving credit facility, a portion of the net proceeds of our IPO, the proceeds from our offering of $900.0 million in aggregate principal amount of the notes completed on April 25, 2014 (our “Senior Notes Offering”) and the proceeds from our August 2014 public offering of 13,729,650 shares of our common stock (the “August 2014 Equity Offering”). A portion of our 2014 capital budget is projected to be financed with cash flows from operations derived from wells drilled on drilling locations not associated with proved reserves in our reserve reports. The failure to achieve projected production and cash flows from operations from such wells could result in a reduction to our 2014 capital budget. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in natural gas prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

Our cash flow from operations and access to capital are subject to a number of variables, including:

 

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our proved reserves;

 

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the level of hydrocarbons we are able to produce from existing wells;

 

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our access to, and the cost of accessing end markets for our production;

 

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the prices at which our production is sold;

 

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our ability to acquire, locate and produce new reserves;

 

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the levels of our operating expenses; and

 

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our ability to borrow under our revolving credit facility.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling, including or as a result of the application of these techniques, include, but are not limited to, the following:

 

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effectively controlling the level of pressure flowing from particular wells;

 

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landing our wellbore in the desired drilling zone;

 

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staying in the desired drilling zone while drilling horizontally through the formation;

 

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running our casing the entire length of the wellbore; and

 

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being able to run tools and other equipment consistently through the horizontal wellbore.

Risks that we face while completing our wells, including or as a result of the application of these techniques, include, but are not limited to, the following:

 

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the ability to fracture stimulate the planned number of stages;

 

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the ability to run tools the entire length of the wellbore during completion operations; and

 

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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

Drilling for and producing natural gas are high-risk activities with many uncertainties that could result in a total loss of investment or otherwise adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production or that we will not recover all or any portion of our investment in such wells or that various characteristics of the well will cause us to plug or abandon the well prior to producing in commercially viable quantities.

Our decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty

 

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involved in these processes, see “—Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

 

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delays imposed by or resulting from compliance with regulatory requirements including limitations resulting from wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;

 

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pressure or irregularities in geological formations;

 

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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

 

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equipment failures, accidents or other unexpected operational events;

 

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lack of available gathering facilities or delays in construction of gathering facilities;

 

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lack of available capacity on interconnecting transmission pipelines;

 

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adverse weather conditions, such as blizzards and ice storms;

 

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issues related to compliance with environmental regulations;

 

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environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

 

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declines in natural gas prices;

 

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limited availability of financing at acceptable terms;

 

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title problems; and

 

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limitations in the market for natural gas.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.

Our producing properties are geographically concentrated in the Marcellus Shale and Upper Devonian Shale formations in Washington and Greene Counties, Pennsylvania. As of December 31, 2013 and 2012, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs and changes in regional and local political regimes and regulations. Such conditions could have a material adverse effect on our financial condition and results of operations. In addition, a number of areas within the Marcellus Shale and Utica Shale have historically been subject to mining operations. For example, third parties may engage in subsurface mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling or adversely impact our midstream activities or those on which we rely. In such event, our operations may be impaired or interrupted, and we may not be able to recover the costs incurred as a result of temporary shut-ins, the plugging and abandonment of any of our wells or the repair of our midstream

 

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facilities. Furthermore, the existence of mining operations near our properties could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. In connection our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture on January 29, 2014 (“the “Marcellus JV Buy-In”), we agreed to continue to acknowledge the dominance of mining by Alpha Natural Resources, Inc. within the area of mutual interest of our Marcellus joint venture. As such, in addition to coordinating with Alpha Holdings on, and in certain circumstances obtaining the prior approval of Alpha Holdings for, future drilling operations, we may also be required to take steps to assure the dominance of the mining operations of Alpha Natural Resources, Inc., including the plugging and abandonment of wells at the direction of Alpha Holdings upon two years notice. These restrictions on our operations, and any similar restrictions, can cause delays or interruptions or can prevent us from executing our business strategy, which could have a material adverse effect on our financial condition and results of operations. Due to the concentrated nature of our portfolio of natural gas properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

We have been an early entrant into new or emerging plays. As a result, our initial drilling results in these areas may be less certain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

We completed our first horizontal well in the Marcellus Shale in October 2010 and completed our first horizontal well in the Utica Shale in June 2014. While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are more developed and have a longer history of established production. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. Additionally, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. For example, as a result of unexpected levels of pressure, in December 2013 we plugged and abandoned the first well we spud in the Utica Shale. We have since drilled and completed our second well in the Utica Shale and obtained an initial production test from this well in the second quarter of 2014. We cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

During the term of the Utica Development Agreements, we will rely on Gulfport for the success of our project in the Southern Contract Area in Belmont County, Ohio, and we may not be able to maximize the value of our properties in the Southern Contract Area as we deem best because we are not in full control of this project.

During the term of the Utica Development Agreements, the success of our operation in the Southern Contract Area in Belmont County, Ohio, will depend in part on the ability of Gulfport to effectively exploit the acreage it operates under the Development Agreement. Please read “Business—Our Properties—Utica Shale—Development Agreement and Area of Mutual Interest Agreement.” Pursuant to the Development Agreement, we have designated Gulfport as the operator of our existing and future acreage in the Southern Contract Area. A failure or inability of Gulfport to adequately exploit the acreage it operates would have a significant impact on our results of operations. In addition, other than limitations set forth in the terms of the Development Agreement, we do not control the amount of capital that Gulfport may require for development of properties in the Southern Contract Area. Accordingly, we may be required to allocate capital to development of the Southern Contract Area at times when we otherwise would allocate capital to the Northern Contract Area, our Marcellus Shale acreage or elsewhere or otherwise be forced to terminate the Utica Development Agreements. Under any of these circumstances, our prospects for realization of the potential value of the oil, natural gas and NGL reserves associated with the Southern Contract Area could be adversely affected. Our lack of control may limit our ability to develop our properties in the manner we believe to be in our best interest.

 

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Insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices.

The Appalachian Basin natural gas business environment has recently experienced periods in which production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers such as us. Although additional Appalachian Basin takeaway capacity was added in 2013 and 2012, the existing and expected capacity may not be sufficient to keep pace with the increased production caused by accelerated drilling in the area. We expect that a significant portion of our production from the Utica Shale will be transported on pipelines that experience a differential to NYMEX Henry Hub prices. If we are unable to secure additional gathering and compression capacity and long-term firm takeaway capacity on major pipelines that are in existence or under construction in our core operating area to accommodate our growing production and to manage basis differentials, it could have a material adverse effect on our financial condition and results of operations.

We are required to pay fees to our service providers based on minimum volumes regardless of actual volume throughput.

We have various gas transportation service agreements in place, each with minimum volume delivery commitments. As of June 30, 2014, our average annual contractual firm transportation and firm sales obligations for 2014 (July through December), 2015 and 2016 were approximately 450,000 MMBtu/d, 810,000 MMBtu/d, and 920,000 MMBtu/d, respectively, which are in excess of our pro forma average daily gross operated production of approximately 380,000 MMBtu/d for June 2014. While we believe that our future natural gas volumes will be sufficient to satisfy the minimum requirements under our gas transportation services agreements based on our current production and our exploration and development plan, we can provide no such assurances that such volumes will be sufficient. We are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput, which could be significant. If these fees on minimum volumes are substantial, we may not be able to generate sufficient cash to cover these obligations, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Our revolving credit facility contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

 

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sell assets;

 

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make loans to others;

 

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make investments;

 

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enter into mergers;

 

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make certain payments;

 

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hedge future production or interest rates;

 

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incur liens;

 

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engage in certain other transactions without the prior consent of the lenders; and

 

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pay dividends.

In addition, our credit facilities require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. On certain occasions in the past we have not met these financial covenants. These restrictions may also limit our ability to obtain future financings to withstand a future downturn

 

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in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our credit facilities and our convertible debentures impose on us.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other natural gas properties as additional collateral after applicable grace periods. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our revolving credit facility. The borrowing base under our revolving credit facility is currently $550.0. Our next scheduled borrowing base redetermination is expected to occur in April 2015.

A breach of any covenant in our revolving credit facility would result in a default under such facility after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under such facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements that include cross default provisions. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management.

We completed our IPO in January 2014. As a public company, we incur significant legal, accounting and other expenses that we did not incur as a private company. We also incur costs associated with our public company reporting requirements and with corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. These rules and regulations will increase our legal and financial compliance costs and make some activities more time consuming and costly, and we expect that these costs may increase further after we are no longer an “emerging growth company.” These rules and regulations make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.

However, for as long as we remain an “emerging growth company” as defined in the JOBS Act, we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.

We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, become a large accelerated filer, or issue more than $1.0 billion of non-convertible debt over a three-year period.

 

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After we are no longer an “emerging growth company,” we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not emerging growth companies.

In connection with past audits and reviews of our financial statements and those of our Marcellus joint venture, our independent registered public accounting firms identified and reported adjustments to management. Certain of such adjustments were deemed to be the result of internal control deficiencies that constituted a material weakness in internal controls over financial reporting. If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Prior to the completion of our IPO, we were a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. In addition, our Marcellus joint venture previously relied on our accounting personnel for its accounting processes. Historically, we and our Marcellus joint venture had not maintained effective internal control environments in that the design and execution of such controls had not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare the financial statements of us and our Marcellus joint venture. We concluded that these control deficiencies constituted material weaknesses in our control environment for the year ended December 31, 2012. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment as further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Material Weaknesses in Internal Control over Financial Reporting.”

To address these control deficiencies, we have hired additional accounting and financial reporting staff, implemented additional analysis and reconciliation procedures and increased the levels of review and approval. Additionally, we have begun taking steps to comprehensively document and analyze our system of internal control over financial reporting in preparation for our first management report on internal control over financial reporting in connection with our annual report for the year ending December 31, 2014. Due to the recent implementation of these changes to our control environment, management continues to evaluate the design and effectiveness of these control changes in connection with its ongoing evaluation, review, formalization and testing of our internal control environment over the remainder of 2014. We have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2014. Based upon the status of our review, we and our independent auditors have concluded that the material weakness previously identified had not been remediated as of September 30, 2014. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weakness previously identified. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

For the year ended December 31, 2013, we were not required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act internal control over financial reporting. As a public company, we are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes Oxley Act, which require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the

 

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requirements of being a publicly traded company, we have upgraded our systems, including information technology, implemented additional financial and management controls, reporting systems and procedures and hired additional accounting and finance staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ending December 31, 2014, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2019. We can provide no assurance that our independent registered public accounting firm will be satisfied with the level at which our controls are documented, designed, or operating at the time it issues its report.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our shares of common stock. company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our shares of common stock.

In certain circumstances we may have to purchase commodities on the open market or make cash payments under our hedging arrangements and these payments could be significant.

If our production is less than the volume commitments under our hedging arrangements, or if natural gas or oil prices exceed the price at which we have hedged our commodities, we may be obligated to make cash payments to our hedge counterparties or purchase the volume difference at market prices, which could, in certain circumstances, be significant. As of December 31, 2013, on a pro forma basis, we had entered into hedging contracts through December 31, 2017 covering a total of approximately 186 Bcf of our projected natural gas production at a weighted average price of $4.09 per MMBtu. For the period from January 1, 2014 until December 31, 2014, we have hedged approximately 62.9 Bcf of our projected natural gas production at a weighted average price of $4.05 per MMBtu. If we have to purchase additional commodities on the open market or post cash collateral to meet our obligations under such arrangements, our cash otherwise available for use in our operations would be reduced.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

 

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In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates. As a substantial portion of our reserve estimates are made without the benefit of a lengthy production history, any significant variance from the above assumption could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated natural gas reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Most of our producing wells have been operational for less than two years and estimated reserves vary substantially from well to well. Furthermore, the lack of operational history for horizontal wells in the Utica Shale may also contribute to the inaccuracy of future estimates of reserves and could result in our failing to achieve expected results in the play. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates or, in the case of the Utica Shale, management expectations, would have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our gross drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our drilling locations.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in the future may require unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to unitize such leaseholds with ours, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified.

As a result of the limitations described above, we may be unable to drill many of our drilling locations. As a result of the limitations described above, we may be unable to drill many of our drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

 

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Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on our oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2013, on a pro forma basis, we had leases representing 1,054 undeveloped acres scheduled to expire in 2014, 2,365 undeveloped acres scheduled to expire in 2015, 4,132 undeveloped acres scheduled to expire in 2016, 35,639 undeveloped acres scheduled to expire in 2017 and 28,161 undeveloped acres scheduled to expire in 2018 and thereafter. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Moreover, many of our leases require lessor consent to unitize, which may make it more difficult to hold our leases by production. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases scheduled to expire in 2014 and 2015, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy rigs when needed, or that commodity prices will warrant operating such a drilling program. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially and adversely affect our ability to so develop such acreage.

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2013, 2012 and 2011, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

 

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actual prices we receive for oil and natural gas;

 

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actual cost of development and production expenditures;

 

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the amount and timing of actual production; and

 

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changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. As a limited liability company, our predecessor was not subject to federal taxation. Accordingly, our standardized measure does not provide for federal corporate income taxes because taxable income was passed through to its members. As a corporation, we are treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus which could have a material effect on the value of our reserves.

We may incur losses as a result of title defects in the properties in which we invest.

Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due to the long history of land ownership in the area, resulting in extensive and complex chains of title. In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to execute a lease agreement with

 

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payment subject to title verification. In most cases, we incur the expense of retaining lawyers to verify the rightful owners of the oil and gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to its lease’s oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

As of December 31, 2013, approximately 58% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 352 Bcf of pro forma estimated proved undeveloped reserves will require an estimated $313 million of development capital over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A writedown constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand

 

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for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas, we enter into derivative instrument contracts for a significant portion of our natural gas production, including fixed-price swaps. As of December 31, 2013, we had entered into hedging contracts through December 31, 2017 covering a total of approximately 186 Bcf of our projected natural gas production at a weighted average price of $4.09 per MMBtu. For the period from January 1, 2014 until December 31, 2014, we have hedged approximately 62.9 Bcf of our projected natural gas production at a weighted average price of $4.05 per MMBtu. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

 

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production is less than the volume covered by the derivative instruments;

 

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the counterparty to the derivative instrument defaults on its contractual obligations;

 

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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

 

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there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. As of May 1, 2014, the estimated fair value of our commodity derivative contracts was approximately $4.0 million. Any default by the counterparties to these derivative contracts, Wells Fargo Bank N.A. and Bank of Montreal, when they become due would have a material adverse effect on our financial condition and results of operations. In addition to the counterparties above at December 31, 2013, subsequent to December 31, 2013, we also executed hedging transactions with Barclays Bank PLC.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, which could also have an adverse effect on our financial condition.

The inability of our significant customers to meet their obligations to us may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($82.2 million as of September 30, 2014) and the sale of our natural gas production ($52.3 million in receivables as of September 30, 2014), which we market to multiple natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with one natural gas marketing company.

 

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The largest purchaser of our natural gas during the three months ended September 30, 2014 represented approximately 87% of our total sales. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities that could exceed current expectations.

Substantial costs, liabilities, delays and other significant issues could arise from environmental laws and regulations inherent in drilling and well completion, gathering, transportation, and storage, and we may incur substantial costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, regional, state and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:

 

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Clean Air Act (“CAA”) and analogous state law, which impose obligations related to air emissions;

 

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Clean Water Act (“CWA”), and analogous state law, which regulate discharge of wastewaters and storm water from some of our facilities into state and federal waters, including wetlands;

 

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Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state law, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

 

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Resource Conservation and Recovery Act (“RCRA”), and analogous state law, which impose requirements for the handling and disposal of any solid and hazardous waste from our facilities;

 

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National Environmental Policy Act (“NEPA”), which requires federal agencies to study likely environmental impacts of a proposed federal action before it is approved, such as drilling on federal lands;

 

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Safe Drinking Water Act (“SDWA”), and analogous state law, which restrict the disposal, treatment or release of water produced or used during oil and gas development;

 

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Endangered Species Act (“ESA”), and analogous state law, which seek to ensure that activities do not jeopardize endangered or threatened animals and plant species, nor destroy or modify the critical habitat of such species; and

 

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Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulates above ground storage tanks and sets forth liability for spills by responsible parties.

Various governmental authorities, including, for example, the U.S. Environmental Protection Agency (“EPA”), the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and/or criminal fines and penalties and liability for non-compliance, the imposition of remedial obligations, costs of corrective action, cleanup or restoration, compensation for personal injury, property damage or other losses, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions or declaratory relief limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases.

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint

 

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and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate may be located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

The EPA’s National Enforcement Initiatives for 2014 to 2016 includes “Assuring Energy Extraction Sector Compliance with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” This initiative could involve a large-scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and any new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our products and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability. Further, new environmental laws and regulations might adversely affect our customers, which in turn could affect our profitability.

Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which we can operate and reduce our oil and natural gas production, which could adversely impact our business.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding alleged potential impacts to the environment due to hydraulic fracturing, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. The SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program and exempts hydraulic fracturing from the definition of “underground injection”. However, Congress has from time to time considered legislation that would amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as require disclosure of the chemical constituents of the fluids used in the fracturing process. The U.S. Congress may consider similar SDWA legislation in the future.

 

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In February 2014, the EPA asserted federal regulatory authority under the SDWA’s UIC program over hydraulic fracturing involving diesel additives, and requested comments in May 2014 on a proposal to require disclosure of chemical ingredients in hydraulic fracturing fluids under the Toxic Substances Control Act. Because EPA’s Advanced Notice of Proposed Rulemaking did not propose any actual regulation, it is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations. Further, on October 21, 2011, the EPA announced its intention to propose federal CWA regulations governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the U.S. Department of the Interior published a Supplemental Notice of Proposed Rulemaking on May 16, 2013 that would update existing regulation of hydraulic fracturing activities on federal and Indian lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. Studies by the EPA and other federal agencies are underway that focus on the environmental aspects of hydraulic fracturing activities, with draft reports expected for public comment and peer review in late 2014. These studies could spur further regulation. Additional regulations adopted at the federal or state level could result in permitting delays and cost increases.

Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Along with several other states, Pennsylvania and Ohio (where we conduct operations) have adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. The chemical ingredient information is generally available to the public via online databases, and this may bring more public scrutiny to hydraulic fracturing operations. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing, in particular. In Pennsylvania, although the legislature passed legislation to make regulation of drilling uniform throughout the state, the Pennsylvania Supreme Court in Robinson Township v. Commonwealth of Pennsylvania struck down portions of that legislation. Following this decision, local governments in Pennsylvania may adopt ordinances regulating drilling and hydraulic fracturing activities, especially within residential areas. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

Restrictions on our ability to obtain, use, manage or dispose of water may have an adverse effect on our operations.

Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations.

Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The CWA and similar state laws impose restrictions and strict controls on the discharge of produced waters and other natural gas and oil waste where such discharges could affect surface or ground waters. For example, state and federal regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. We must obtain permits for certain discharges into waters and wetlands and for construction activities that may affect regulated water resources. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. The CWA and similar state laws provide for civil, criminal and/or administrative penalties for any unauthorized discharges of pollutants, reportable quantities of oil and other hazardous substances. Moreover, sending wastewater to publicly-owned treatment works in Pennsylvania and Ohio requires certain levels of pretreatment that may effectively prohibit such

 

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disposal, and our continued ability to use injection wells as a disposal option not only will depend on federal or state regulations, but also on whether available injection wells have sufficient storage capacities. Compliance with current and future federal, state and local environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be accurately predicted.

We are subject to risks associated with climate change.

Climate change, the costs that may be associated with its effects and the regulation of greenhouse gases (“GHGs”) have the potential to affect our business in many ways, including increasing the costs to provide our products and services, reducing the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHGs and climate change may increase our operating costs. The U.S. Congress has previously considered legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions. For example, in June 2013, the Obama Administration announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas sector.

In September 2009, the EPA finalized a mandatory GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions beginning January 1, 2010. The rule applies to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent (CO2e) emissions per year and to most upstream suppliers of fossil fuels, as well as manufacturers of vehicles and engines. Subsequently, in November 2010, the EPA issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2e per year. The rule required reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. We are required to report our GHG emissions to the EPA each year in March under this rule. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. However, in June 2014, the U.S. Supreme Court, in UARG v. EPA, limited the application of the GHG permitting requirements under the Prevention of Significant deterioration and Title V permitting programs to sources that would otherwise need permits based on the emission of conventional pollutants.

Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the passage of any federal or state climate change laws or regulations in the future could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.

 

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We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of:

 

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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

 

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abnormally pressured formations;

 

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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

 

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fires, explosions and ruptures of pipelines;

 

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personal injuries and death;

 

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natural disasters; and

 

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terrorist attacks targeting natural gas and oil related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

 

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injury or loss of life;

 

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damage to and destruction of property, natural resources and equipment;

 

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pollution and other environmental damage;

 

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regulatory investigations and penalties;

 

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suspension of our operations; and

 

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repair and remediation costs.

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since hydraulic fracturing activities are a large part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

 

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Properties that we decide to drill may not yield natural gas, NGLs or oil in commercially viable quantities.

Properties that we decide to drill that do not yield natural gas, NGLs or oil in commercially viable quantities will adversely affect our results of operations and financial condition. Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. In addition, there is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

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unexpected drilling conditions;

 

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title problems;

 

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pressure or lost circulation in formations;

 

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equipment failure or accidents;

 

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adverse weather conditions;

 

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compliance with environmental and other governmental or contractual requirements; and

 

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increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. However, we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our revolving credit facility and the indenture governing the notes impose certain limitations on our ability to enter into mergers or combination transactions. Our revolving credit facility and the indenture governing the notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

 

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Market conditions or operational impediments may hinder our access to natural gas, NGL or oil markets or delay our production.

Market conditions or the unavailability of satisfactory natural gas, NGL or oil transportation arrangements may hinder our access to markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, NGLs or oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGL or oil pipeline or gathering system capacity. In addition, if quality specifications for the third-party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our natural gas exploration, production and transportation operations are subject to complex and stringent federal, state and local laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations and the permits and other approvals issued thereunder. In addition, our costs of compliance may increase or operational delays may occur if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations. Also, we might not be able to obtain or maintain all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.

In addition, new or additional regulations or permitting requirements, new interpretations of requirements or changes in our operations could also trigger the need for Environmental Assessments or more detailed Environmental Impact Statements under NEPA and analogous state laws, as well as litigation over the adequacy of those reviews, which could result in increased costs or delays of, or denial of rights to conduct, our development programs. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our business, financial condition and results of operations. Further, the discharges of oil, natural gas, NGLs and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. See “Business—Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. We intend to continue our four-rig drilling program in the Marcellus Shale and two-rig drilling program in the Utica Shale; however, certain of the rigs performing work for us do so on a well-by-well basis and can refuse to provide such services at the conclusion of drilling on the current well. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number

 

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of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, (“NGA”), exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”), as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulation may have on our activities. Such regulations may have a material adverse effect on our financial condition, result of operations and cash flows.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005 (“EPAct 2005”), FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Competition in the natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and

 

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retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.

We have grown rapidly over the last several years and more than doubled our employee workforce during 2013. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

 

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increased responsibilities for our executive level personnel;

 

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increased administrative burden;

 

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increased capital requirements; and

 

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increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information included herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations. We began development of our properties in 2010 with a two-rig drilling program. Recently, we expanded our development operations and are currently managing a six-rig drilling program. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

Seasonal weather conditions and regulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect various wildlife. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

 

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We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing and undeveloped properties requires an assessment of several factors, including:

 

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recoverable reserves;

 

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future natural gas, NGL or oil prices and their applicable differentials;

 

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operating costs; and

 

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potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review may neither reveal all existing or potential problems nor permit us to fully assess the environmental and other liabilities of the properties. Inspections may not always be performed on every well or pipeline, and environmental and structural problems, such as groundwater contamination and pipe corrosion, are not necessarily observable during an inspection. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the liabilities created prior to the purchase of our property. Moreover, we often acquire properties on an “as is” basis and, thus, are not entitled to contractual indemnification for environmental liabilities.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized some regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant”, others remain to be finalized and it is not possible at this time to predict when this will be accomplished.

The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s initial position limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, on November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.

The Dodd-Frank Act and regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts,

 

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materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is lower commodity prices.

Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

In February 2012, the state legislature of Pennsylvania passed a new natural gas impact fee in Pennsylvania. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices from the last day of each month. There can be no assurance that the impact fee will remain as currently structured or that new or additional taxes will not be imposed.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

The Fiscal Year 2015 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations.

In February 2013, the governor of the state of Ohio proposed a plan to enact new severance taxes in fiscal 2014 and 2015. However, the Ohio State Senate did not include a severance tax increase in the version of the budget bill that it passed on June 7, 2013. The possibility remains that the severance tax increase on horizontal wells will resurface during compromise talks on the budget.

Risks Related to Exchange Offer

If you do not properly tender your old notes, you will continue to hold unregistered old notes and your ability to transfer old notes will remain restricted and may be adversely affected.

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes.

 

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If you do not exchange your old notes for new notes pursuant to the exchange offer, the old notes you hold will continue to be subject to the existing transfer restrictions. In general, you may not offer or sell the old notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not plan to register old notes under the Securities Act unless our registration rights agreement with the initial purchasers of the old notes require us to do so. Further, if you continue to hold any old notes after the exchange offer is consummated, you may have trouble selling them because there will be fewer of these notes outstanding.

Risks Related to the Notes

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our revolving credit facility and the notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

The borrowing base under our revolving credit facility is currently $550.0 million. Our next scheduled borrowing base redetermination is expected to occur in April 2015. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

 

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Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on the notes.

As of September 30, 2014, we and our subsidiaries had approximately $901.0 million of outstanding indebtedness, including no borrowings under our revolving credit facility, $66.8 million of outstanding letters of credit, and we had approximately $318.2 million of borrowing capacity under our revolving credit facility. Our level of indebtedness could affect our operations in several ways, including the following:

 

•

require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;

 

•

limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

 

•

increase our vulnerability to downturns and adverse developments in our business and the economy generally;

 

•

limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

 

•

place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

 

•

make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;

 

•

make us vulnerable to increases in interest rates as our indebtedness under any revolving credit facility may vary with prevailing interest rates;

 

•

place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and

 

•

make it more difficult for us to satisfy our obligations under the notes or other debt and increase the risk that we may default on our debt obligations.

The notes and the guarantees are unsecured obligations and are effectively subordinated to all of our existing and future secured indebtedness and structurally subordinated to liabilities of any non-guarantor subsidiaries.

The notes and the guarantees are general unsecured senior obligations ranking effectively junior to all of our existing and future secured indebtedness (including all borrowings under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness. If we or a guarantor is declared bankrupt, becomes insolvent or is liquidated or reorganized, the holders of our secured indebtedness or the secured indebtedness of such guarantor will be entitled to be paid in full from the proceeds of the assets, if any, securing such indebtedness before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably in any remaining proceeds with all holders of our unsecured indebtedness, including unsecured indebtedness incurred after the notes are issued that does not rank junior to the notes, including trade payables and all of our other general indebtedness, based on the respective amounts owed to each holder or creditor. In any of the foregoing events, there may not be sufficient funds to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

The notes are structurally subordinated to any indebtedness and other liabilities of any subsidiaries that do not guarantee the notes. The indenture governing the notes permits us to form or acquire additional subsidiaries that are not guarantors of the notes in certain circumstances.

Holders of the notes will have no claim as a creditor against any of our non-guarantor subsidiaries. See “Description of Notes—Brief Description of the Notes and Subsidiary Guarantees—The Subsidiary Guarantees.”

 

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We and the guarantors may incur substantial additional indebtedness. This could increase the risks associated with the notes.

Subject to the restrictions in the indenture governing the notes and in other instruments governing our other outstanding indebtedness (including our revolving credit facility), we and our subsidiaries may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the indenture governing the notes and our revolving credit facility contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial.

If we or a guarantor incurs any additional indebtedness that ranks equally with the notes (or with the guarantees thereof), including additional unsecured indebtedness or trade payables, the holders of that indebtedness will be entitled to share ratably with holders of the notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us or a guarantor. This may have the effect of reducing the amount of proceeds paid to holders of the notes in connection with such a distribution.

Any increase in our level of indebtedness will have several important effects on our future operations, including, without limitation, whether:

 

•

we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;

 

•

increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry conditions, as well as to competitive pressure; and

 

•

depending on the levels of our outstanding indebtedness, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be limited.

We cannot assure you that we will be able to maintain or improve our leverage position.

An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves which may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil, NGL and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control.

Our revolving credit facility and the indenture governing the notes have restrictive covenants that could limit our financial flexibility. Our revolving credit facility and the indenture governing the notes contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our ability to borrow under our revolving credit facility is subject to compliance with certain financial covenants, including the maintenance of certain financial ratios, including a minimum current ratio, an asset coverage ratio and a minimum interest coverage ratio. Our revolving credit facility and the indenture governing the notes contain covenants, that, among other things, limit our ability and the ability of our restricted subsidiaries to:

 

•

incur additional indebtedness;

 

•

sell assets;

 

•

pay dividends or make certain investments;

 

•

create liens that secure indebtedness;

 

•

enter into transactions with affiliates; and

 

•

merge or consolidate with another company.

 

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See “Description of Notes—Certain Covenants.” Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. We would not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

The borrowing base under our revolving credit facility is subject to periodic redetermination.

The borrowing base under our revolving credit facility is redetermined at least semi-annually. The administrative agent under the revolving credit facility may elect to cause interim redeterminations under certain circumstances. In addition, we and the administrative agent may each request one additional redetermination in each 12-month period. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors. As of December 31, 2013, our borrowing base was $350.0 million. In October 2014 we had a redetermination of our borrowing base under our revolving credit facility which increased the borrowing base to $550.0 million. The next redetermination is scheduled for April 2015. We could be required to repay a portion of our bank debt to the extent that after a redetermination our outstanding borrowings at such time exceed the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the facility and an acceleration of the loans thereunder requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results.

If we are unable to comply with the restrictions and covenants in the agreements governing the notes and our other indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would affect our ability to make principal and interest payments on the notes.

Any default under the agreements governing our indebtedness that is not cured or waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal, premium, if any, and interest, or special interest, if any, on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest, or special interest, if any, on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our indebtedness (including covenants in our revolving credit facility and the indenture governing the notes), we could be in default under the terms of the agreements governing such indebtedness. In the event of such default:

 

•

the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;

 

•

the lenders under our revolving credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and

 

•

we could be forced into bankruptcy or liquidation.

If our operating performance declines, we may in the future need to obtain waivers under our revolving credit facility to avoid being in default. If we breach our covenants under our revolving credit facility and seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, we would be in default under the facilities, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.

We may not be able to repurchase the notes upon a change of control.

If we experience certain kinds of changes of control followed by a rating decline, we may be required to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued and unpaid interest, if any. We may not be able to repurchase the notes upon a change of control because we may not have sufficient

 

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financial resources to purchase all of the notes that are tendered following a change of control. In addition, the terms of our revolving credit facility would prohibit, and the terms of other future indebtedness may prohibit, us from repurchasing notes upon a change of control. Our failure to repurchase the notes upon a change of control could cause a default under the indenture governing the notes and could lead to a cross default under our revolving credit facility. Additionally, using cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future, which could negatively impact our ability to conduct our business operations. See “Description of Notes—Repurchase at the Option of Holders—Change of Control.”

Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from guarantors.

Federal bankruptcy and state fraudulent transfer laws permit a court to avoid all or a portion of the obligations of a guarantor pursuant to its guarantee of the notes, or to subordinate any guarantor’s obligations under such guarantee to claims of its other creditors, reducing or eliminating the noteholders’ ability to recover under such guarantee. Although laws differ among these jurisdictions, in general, under applicable fraudulent transfer or conveyance laws, a guarantee could be voided as a fraudulent transfer or conveyance if (i) the guarantee was incurred with the intent of hindering, delaying or defrauding creditors; or (ii) the guarantor received less than reasonably equivalent value or fair consideration in return for incurring the guarantee and either:

 

•

the guarantor was insolvent or rendered insolvent by reason of the incurrence of the guarantee or subsequently became insolvent for other reasons;

 

•

the incurrence of the guarantee left the guarantor with an unreasonably small amount of capital to carry on the business; or

 

•

the guarantor intended to, or believed that it would, incur debts beyond its ability to pay such debts as they mature.

A court would likely find that a guarantor did not receive reasonably equivalent value or fair consideration for its guarantee if the guarantor did not substantially benefit directly or indirectly from the issuance of the notes. If a court were to void a guarantee, you would no longer have a claim against the guarantor. Sufficient funds to repay the notes may not be available from other sources, including the remaining guarantors, if any. In addition, the court might direct you to repay any amounts that you already received from the guarantor. The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law of the applicable jurisdiction. Generally, a guarantor would be considered insolvent if:

 

•

the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;

 

•

the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they became absolute and mature; or

 

•

it could not pay its debts as they became due.

Each guarantee will contain a provision intended to limit the guarantor’s liability under the guarantee to the maximum amount that the guarantor could incur without causing the incurrence of obligations under its guarantee to be deemed a fraudulent transfer. This provision may not be effective to protect the guarantees from being voided under fraudulent transfer law.

Many of the covenants contained in the indenture will be terminated if the notes are rated investment grade by Standard & Poor’s and Moody’s and no default has occurred and is continuing.

Many of the covenants in the indenture governing the notes will be terminated if the notes are rated investment grade by Standard & Poor’s and Moody’s, provided at such time no default or event of default has

 

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occurred and is continuing. These covenants include restrictions on our ability to pay dividends, to incur debt and to enter into certain transactions. There can be no assurance that the notes will ever be rated investment grade. However, termination of these covenants would allow us to engage in certain transactions that would not have been permitted while these covenants were in force. The covenant termination will continue even if the notes are subsequently downgraded below investment grade. See “Description of Notes—Certain Covenants—Covenant Termination.”

We face risks related to rating agency downgrades.

We expect one or more rating agencies to rate the notes. If such rating agencies either assign the notes a rating lower than the rating expected by the investors, or reduce the rating in the future, the market price of the notes may be adversely affected, raising capital may become more difficult and borrowing costs under our revolving credit facility and other future borrowings may increase.

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop for the notes.

The old notes have not been registered under the Securities Act, and may not be resold by purchasers thereof unless the old notes are subsequently registered or an exemption from the registration requirements of the Securities Act is available. However, we cannot assure you that, even following registration or exchange of the old notes for new notes, that an active trading market for the old notes or the new notes will exist, and we will have no obligation to create such a market. At the time of the private placement of the old notes, the initial purchasers advised us that they intended to make a market in the old notes and, if issued, the new notes. The initial purchasers are not obligated, however, to make a market in the old notes or the new notes and any market-making may be discontinued at any time at their sole discretion. No assurance can be given as to the liquidity of or trading market for the old notes or the new notes.

The liquidity of any trading market for the notes and the market price quoted for the notes will depend upon the number of holders of the notes, the overall market for high yield securities, our financial performance or prospects or the prospects for companies in our industry generally, the interest of securities dealers in making a market in the notes and other factors.

 

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EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

At the closing of the offering of the old notes, we entered into a registration rights agreement with the initial purchasers pursuant to which we agreed, for the benefit of the holders of the old notes, at our cost, to do the following:

 

•

file an exchange offer registration statement with the SEC with respect to the exchange offer for the new notes,

 

•

use reasonable best efforts to cause the exchange offer registration statement to be declared effective under the Securities Act, and

 

•

use reasonable best efforts to have the exchange offer completed by the 365th day following the date of the initial issuance of the notes (April 25, 2015).

Upon the SEC’s declaring the exchange offer registration statement effective, we agreed to offer the new notes in exchange for surrender of the old notes. We agreed to use reasonable best efforts to cause the exchange offer registration statement to be effective continuously, to keep the exchange offer open for a period of not less than 20 business days and to use reasonable best efforts to cause the exchange offer to be commenced promptly after the exchange offer registration statement is declared effective by the SEC.

For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date on which interest was paid on the surrendered old note, November 1, 2014. The registration rights agreement also obligates us to include in the prospectus for the exchange offer certain information necessary to allow a broker-dealer who holds old notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of new notes received by such broker-dealer in the exchange offer. We agreed to amend or supplement the prospectus contained in the exchange offer registration statement for a period of 180 days after the last exchange date, which period may be extended under certain circumstances.

The preceding agreement is needed because any broker-dealer who acquires old notes for its own account as a result of market-making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This prospectus covers the offer and sale of the new notes pursuant to the exchange offer and the resale of new notes received in the exchange offer by any broker-dealer who held old notes acquired for its own account as a result of market-making activities or other trading activities other than old notes acquired directly from us or one of our affiliates.

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the exchange offer would in general be freely tradable after the exchange offer without further registration under the Securities Act. However, any purchaser of old notes who is an “affiliate” of ours or who intends to participate in the exchange offer for the purpose of distributing the related new notes:

 

•

will not be able to rely on the interpretation of the staff of the SEC,

 

•

will not be able to tender its old notes in the exchange offer, and

 

•

must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the old notes unless such sale or transfer is made pursuant to an exemption from such requirements.

 

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Each holder of the old notes (other than certain specified holders) who desires to exchange old notes for the new notes in the exchange offer will be required to make the representations described below under “—Procedures for Tendering—Your Representations to Us.”

We further agreed to file with the SEC a shelf registration statement to register for public resale of old notes held by any holder who provides us with certain information for inclusion in the shelf registration statement if:

 

i.

the exchange offer would violate any applicable law or applicable interpretation of the staff of the SEC,

 

ii.

the exchange offer is not consummated within 365 days of the issuance of the old notes,

 

iii.

any initial purchaser so requests with respect to the old notes not eligible to be exchanged for the new notes and held by it following the consummation of the exchange offer, or

 

iv.

any holder, other than a broker-dealer, is not eligible to participate in the exchange offer, or if any holder, other than a broker-dealer, that participates in the exchange offer does not receive freely tradeable new notes in exchange for tendered old notes.

We have agreed, at our expense, (a) as promptly as practicable (but in no event more than 30 days after such filing obligation arises) file a shelf registration statement, (b) to use our reasonable best efforts to cause the shelf registration statement to be declared effective (unless it becomes effective automatically upon filing) under the Securities Act on or prior to April 25, 2015 in the case of clauses (i) and (ii) above and on or prior to the 180^th day after the date on which the shelf registration statement is required to be filed in the case of clauses (iii) and (iv) above, and (c) to keep effective the shelf registration statement until two years after its effective date (or such shorter period that will terminate when all the notes covered thereby have been sold pursuant thereto or in certain other circumstances).

If (a) the exchange offer is not consummated on or before to the 365^th calendar day following the date of issuance of the old notes, (b) a shelf registration statement applicable to the notes is not filed or declared effective when required, or (c) a registration statement applicable to the notes is declared effective as required but thereafter fails to remain effective or usable in connection with resales for more than 60 days (each such event referred to in clauses (a) through (c) above, a “Registration Default”), we will pay liquidated damages in the form of additional interest in cash to each holder of notes in an amount equal to 0.25% per annum of the aggregate principal amount of notes for the 90-day period immediately following the occurrence of the Registration Default until such time as no Registration Default is in effect, which rate shall increase by 0.25% per annum for each subsequent 90-day period during which such Registration Default continues up to a maximum of 1.00% per annum. Following the cure of all Registration Defaults, such additional interest will cease to accrue and the interest rate on the notes will revert to the original rate; provided, however, that, if after the date such additional interest ceases to accrue, a different Registration Default occurs, such additional interest may again commence accruing pursuant to the foregoing provisions. All references herein to “interest” include any additional interest payable pursuant to this paragraph.

Holders of the old notes will be required to make certain representations to us (as described in the registration rights agreement) in order to participate in the exchange offer and may be required to deliver information to be used in connection with the shelf registration statement and to provide comments on the shelf registration statement within the time periods set forth in the registration rights agreement in order to have their old notes included in the shelf registration statement.

This summary of the material provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, copies of which are filed as exhibits to the registration statement which includes this prospectus.

Except as set forth above, after consummation of the exchange offer, holders of old notes which are the subject of the exchange offer have no registration or exchange rights under the registration rights agreement. See “—Consequences of Failure to Exchange.”

 

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Terms of the Exchange Offer

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this prospectus, $900,000,000 in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934 and the rules and regulations of the SEC. Old notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes and the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender old notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important that you read the section labeled “—Fees and Expenses” for more details regarding fees and expenses incurred in the exchange offer.

We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offer.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on                     , 2014, unless, in our sole discretion, we extend it.

Extensions, Delays in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

 

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If any of the conditions described below under “—Conditions to the Exchange Offer” have not been satisfied, we reserve the right, in our sole discretion:

 

•

to delay accepting for exchange any old notes,

 

•

to extend the exchange offer, or

 

•

to terminate the exchange offer,

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

Any such delay in acceptance, extension, termination or amendment will be followed promptly by oral or written notice thereof to the registered holders of old notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the exchange offer. In the event of a material change in the exchange offer, including the waiver by us of a material condition, we will extend the exchange offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

Conditions to the Exchange Offer

We will not be required to accept for exchange, or exchange any new notes for, any old notes if the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under “—Purpose and Effect of the Exchange Offer,” “—Procedures for Tendering” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give prompt oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

In addition, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

Procedures for Tendering

In order to participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

 

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If you have any questions or need help in exchanging your notes, please call the exchange agent, whose address and phone number are set forth in “Prospectus Summary—The Exchange Offer—Exchange Agent.”

All of the old notes were issued in book-entry form, and all of the old notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the old notes may be tendered using the Automated Tender Offer Program (“ATOP”) instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

There is no procedure for guaranteed late delivery of the notes.

Determinations Under the Exchange Offer

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

When We Will Issue New Notes

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

 

•

a book-entry confirmation of such old notes into the exchange agent’s account at DTC; and

 

•

a properly transmitted agent’s message.

Return of Old Notes Not Accepted or Exchanged

If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

Your Representations to Us

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

 

•

any new notes that you receive will be acquired in the ordinary course of your business;

 

•

you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes;

 

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•

you are not our “affiliate,” as defined in Rule 405 of the Securities Act; and

 

•

if you are a broker-dealer that will receive new notes for your own account in exchange for old notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus (or to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the expiration date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC’s ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any old notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under “—Procedures for Tendering” above at any time prior to 5:00 p.m., New York City time, on the expiration date.

Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by facsimile, telephone, electronic mail or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

 

•

all registration and filing fees and expenses;

 

•

all fees and expenses of compliance with federal securities and state “blue sky” or securities laws;

 

•

accounting and legal fees, disbursements and printing, messenger and delivery services, and telephone costs; and

 

•

related fees and expenses.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

Consequences of Failure to Exchange

If you do not exchange new notes for your old notes under the exchange offer, you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the

 

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offer or sale is either registered under the Securities Act or exempt from the registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Other

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

 

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USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in outstanding indebtedness.

 

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SELECTED HISTORICAL CONSOLIDATED AND UNAUDITED PRO FORMA FINANCIAL DATA

The following table shows selected historical consolidated financial data of Rice Energy Inc. and the summary unaudited pro forma financial data for the periods and as of the dates indicated. Our historical results are not necessarily indicative of future operating results. The selected financial data presented below are qualified in their entirety by reference to, and should be read in conjunction with, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere herein.

The selected historical consolidated financial data as of and for the years ended December 31, 2011, 2012 and 2013 are derived from the audited consolidated financial statements of Rice Energy included elsewhere in this prospectus. The summary historical consolidated statement of operations data for each of the nine month periods ended September 30, 2013 and 2014 and the historical consolidated balance sheet data as of September 30, 2014 are derived from the unaudited consolidated financial statements of Rice Energy Inc. included elsewhere in this prospectus. The selected historical unaudited historical consolidated interim financial data has been prepared on a consistent basis with the audited consolidated financial statements of Rice Energy. In the opinion of management, such selected unaudited historical consolidated financial interim data reflects all adjustments (consisting of normal and recurring accruals) considered necessary to present our financial position for the periods presented. The results of operations for the interim periods are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received from oil and natural gas, natural production declines, the uncertainty of exploration and development drilling results and other factors.

The summary unaudited pro forma consolidated statements of operations data for the year ended December 31, 2013 and nine months ended September 30, 2014 has been prepared to give pro forma effect to (i) the Marcellus JV Buy-In and (ii) our IPO and the application of the net proceeds therefrom as if each had been completed as of January 1, 2013. Each of our IPO and the Marcellus JV Buy-In was completed prior to September 30, 2014 and is thus fully reflected in our historical consolidated balance sheet as of such date. The summary unaudited pro forma consolidated statements of operations data do not give pro forma effect to our April 2014 acquisition of certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania, the Senior Notes Offering, the Greene County Acquisition or our August 2014 equity offering. These data are subject and give effect to the assumptions and adjustments described in the notes accompanying the unaudited pro forma financial statements included elsewhere in this prospectus. The summary unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had (i) the Marcellus JV Buy-In and (ii) our IPO and the application of the net proceeds therefrom been completed as of January 1, 2013, and do not purport to be indicative of statements of financial position or results of operations as of any future date or for any future period.

 

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		Rice Energy Inc.																				Rice Energy Inc. Pro Forma
		Year Ended December 31,												Nine Months Ended September 30,								Year Ended December 31, 2013				Nine Months Ended September 30, 2014
		2011				2012				2013				2013				2014
(in thousands, except per share data)																		(unaudited)
Statement of operations data:
Revenues:
Natural gas, oil and NGL sales		$	13,972			$	26,743			$	87,847			$	60,219			$	246,816			$	178,524			$	258,752
Firm transportation sales, net			—				—				—				—				11,851				—				11,851
Other revenue			—				457				757				580				2,878				757				2,878
Total revenues			13,972				27,200				88,604				60,799				261,545				179,281				273,481
Operating expenses:
Lease operating			1,617				3,688				8,309				5,794				16,406				16,502				16,826
Gathering, compression and transportation			540				3,754				9,774				6,951				25,904				25,437				27,294
Production taxes and impact fees			—				1,382				1,629				1,029				2,624				2,887				2,693
Exploration			660				3,275				9,951				1,784				1,706				9,951				1,706
Incentive unit expense			—				—				—				—				101,695				—				101,695
Restricted unit expense			170				—				32,906				40,087				—				32,906				—
Stock compensation expense			—				—				—				—				3,274				—				3,274
General and administrative			5,208				7,599				16,953				9,952				36,733				20,209				36,805
Depreciation, depletion and amortization			5,981				14,149				32,815				23,215				91,912				71,886				94,768
Write-down of abandoned leases			109				2,253				—				—				748				146				748
Acquisition expense			—				—				—				—				2,246				—				2,246
Loss (gain) from sale of interest in gas properties			(1,478	)			—				4,230				—				—				4,230				—
Total expenses			12,807				36,100				116,567				88,812				283,248				184,154				288,055
Operating income (loss)			1,165				(8,900	)			(27,963	)			(28,013	)			(21,703	)			(4,873	)			(14,574	)
Interest expense			(531	)			(3,487	)			(17,915	)			(13,033	)			(38,737	)			(16,422	)			(38,972	)
Gain on purchase of Marcellus joint venture			—				—				—				—				203,579				—				—
Other income (expense)			161				112				(357	)			(408	)			180				(1,153	)			180
Gain (loss) on derivative instruments			574				(1,381	)			6,891				16,698				5,357				10,238				(6,834	)
Amortization of deferred financing costs			(2,675	)			(7,220	)			(5,230	)			(4,760	)			(1,728	)			(5,394	)			(1,743	)
Loss on extinguishment of debt			—				—				(10,622	)			(10,622	)			(3,934	)			(10,622	)			(3,934	)
Write-off of deferred financing costs			—				—				—				—				(6,896	)			—				(6,896	)
Equity in income (loss) of joint ventures			370				1,532				19,420				19,297				(2,656	)			90				—
Gain (loss) before income taxes			(936	)			(19,344	)			(35,776	)			(20,841	)			133,462				(28,136	)			(72,773	)
Income tax benefit (expense)			—				—				—				—				(18,787	)			11,674				(11,024	)
Net income (loss)		$	(936	)		$	(19,344	)		$	(35,776	)		$	(20,841	)		$	114,675			$	(16,462	)		$	(83,797	)
Balance sheet data (at period end):
Cash		$	4,389			$	8,547			$	31,612							$	131,978
Total property and equipment, net			150,646				273,640				734,331
Total assets			190,240				344,971				879,810								2,895,786
Total debt			107,795				149,320				426,942								901,006
Total stockholders’ capital			46,821				138,191				298,647								1,412,558
Net cash provided by (used in):
Operating activities		$	5,131			$	(3,014	)		$	33,672			$	22,491			$	69,679
Investing activities			(79,245	)			(119,973	)			(458,595	)			(342,625	)			(1,154,548	)
Financing activities			73,447				127,145				447,988				339,249				1,185,235
Other financial data (unaudited):
Loss per share—basic																						$	(0.13	)		$	(0.65	)
Loss per share—diluted																						$	(0.13	)		$	(0.65	)

 

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RATIOS OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratios of consolidated earnings to fixed charges for the periods presented:

 

		Year Ended December 31,(b)																				Nine Months Ended September 30, 2014
		2009				2010				2011				2012				2013
Ratio of earnings to fixed charges(a)(c)			(11.51	)x			(2.14	)x			0.20x				(0.33	)x			0.24x				4.29x

 

(a)

For purposes of calculating the ratios of consolidated earnings to fixed charges, “earnings” consists of pre-tax income (loss) from continuing operations, (income) loss from equity investees, distributed income of equity investees and interest capitalized, plus fixed charges. “Fixed charges” consist of interest expense, including amortization of discounts, interest capitalized and deferred financing amortization.

(b)	We would have needed to generate additional earnings of $24.6 million, $25.2 million, $6.9 million, $3.9 million and $7.2 million to achieve coverage of 1:1 for the years ended December 31, 2013, 2012, 2011, 2010 and 2009, respectively.

(c)	We had no preferred stock outstanding for any period presented, and accordingly, the ratio of earnings to combined fixed charges and preferred stock dividends is the same as the ratio of earnings to fixed charges.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Risk Factors” included elsewhere in this prospectus. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.

Overview

We are an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. We are focused on creating shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We strive to be an early entrant into the core of a shale play by identifying what we believe to be the core of the play and aggressively executing our acquisition strategy to establish a largely contiguous acreage position.

As of September 30, 2014, we held approximately 82,626 net acres in the southwestern core of the Marcellus Shale, primarily in Washington County and Greene County, Pennsylvania. We established our Marcellus Shale acreage position through a combination of largely contiguous acreage acquisitions in 2009 and 2010 and through numerous bolt-on acreage acquisitions. In 2012, we acquired approximately 33,499 of our 53,816 net acres as of September 30, 2014 in the southeastern core of the Utica Shale, primarily in Belmont County, Ohio. We believe this area to be in the core of the Utica Shale based on publicly available drilling results. We operate a substantial majority of our acreage in the Marcellus Shale and a majority of our acreage in the Utica Shale.

Our average net daily production for the third quarter of 2014 is 247 Mcfe/d. We brought five operated net horizontal Marcellus wells and one operated net Utica well online during the third quarter of 2014.

Factors That Significantly Affect Our Financial Condition and Results of Operations

We derive substantially all of our revenues from the sale of natural gas that is produced from our interests in properties located in the Marcellus Shale. In the coming years, we expect to derive an increasing amount of our revenues from the sale of natural gas and, in a more limited amount, NGLs, that are produced from our interests in properties located in the Utica Shale. Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Natural gas prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace and geopolitical events such as wars or natural disasters. In the future, we will also be subject to fluctuations in oil and NGL prices. Sustained periods of low natural gas prices could materially and adversely affect our financial condition, our results of operations, the quantities of natural gas that we can economically produce and our ability to access capital.

 

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We use commodity derivative instruments, such as swaps, puts and collars, to manage and reduce price volatility and other market risks associated with our natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is accomplished through over-the-counter commodity derivative contracts with large financial institutions. We use a combination of fixed price natural gas swaps; zero cost collars and deferred puts for which we receive a fixed price (via either swap price, floor of collar or put price) for future production in exchange for a payment of the variable market price received at the time future production is sold. The prices contained in these derivative contracts are based on NYMEX Henry Hub prices. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of location differentials. Location differentials to NYMEX Henry Hub prices, also known as basis differential, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors. During the fourth quarter of 2013 we began hedging basis differentials associated with our natural gas production. We elected not to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings.

Like other businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, a natural gas exploration and production company depletes part of its asset base with each unit of natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost effective manner and to timely obtain drilling permits and regulatory approvals.

Our financial condition and results of operations, including the growth of production, cash flows and reserves, are driven by several factors, including:

 

•

success in drilling new wells;

 

•

natural gas prices;

 

•

our access to, and the cost of accessing end markets for our production;

 

•

the availability of attractive acquisition opportunities and our ability to execute them;

 

•

the amount of capital we invest in the leasing and development of our properties;

 

•

facility or equipment availability and unexpected downtime;

 

•

delays imposed by or resulting from compliance with regulatory requirements; and

 

•

the rate at which production volumes on our wells naturally decline.

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Public Company Expenses. As a result of our IPO, we will incur direct, incremental general and administrative (“G&A”) expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation.

 

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Corporate Reorganization and Marcellus JV Buy-In. The reorganization constituted a common control transaction and the discussion herein is contemplated as though this reorganization had occurred for the earliest period presented herein. As a result, the historical financial data may not give you an accurate indication of what our actual results would have been had the IPO and the transactions been completed at the beginning of the periods presented or of what our future results of operations are likely to be. For example, concurrently with the closing of our IPO, we acquired Alpha Holdings’ 50% interest in our Marcellus joint venture (the “Marcellus JV Buy-In”) and, as a result, for periods following January 29, 2014, the complete results of operations of our Marcellus joint venture are consolidated into our results of operations, as opposed to periods prior to January 29, 2014, for which the results of operations of our Marcellus joint venture are not consolidated, but rather reflected as equity in income (loss) from our 50% equity investment therein.

Income Taxes. We are a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings, and, as such, our future income taxes will be dependent upon our future taxable income. We did not report any income tax benefit or expense for periods prior to the consummation of our IPO because Rice Drilling B, our accounting predecessor, is a limited liability company that was not and currently is not subject to federal income tax. The reorganization of our business in connection with the closing of the IPO, such that it is now held by a corporation subject to federal income tax, required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of IPO. Because we anticipate that our deductions primarily related to intangible drilling costs (“IDCs”) will exceed 2014 earnings, we expect to generate significant net operating loss assets and deferred tax liabilities. No current tax expense was recorded as of the date of the IPO. For periods following completion of the IPO, we began recording a federal and state income tax liability associated with our status as a corporation.

Increased Drilling Activity. In the third quarter of 2014, we brought online five net horizontal Marcellus wells and one net horizontal Utica well and we expect to bring online 15 net horizontal Marcellus wells in the fourth quarter of 2014. From 2010 through June 2013, we ran a one-horizontal rig drilling program. In June 2013, we began operating a two-horizontal rig drilling program on our Marcellus Shale properties. In the first quarter of 2014, we operated a three-horizontal rig program, one of which operated in the Utica Shale. In the second and third quarters of 2014, we averaged two horizontal rigs. In the fourth quarter of 2014, we plan to average three horizontal rigs, with an average of one rig operating in the Utica Shale and two rigs operating in the Marcellus Shale. We expect our future drilling activity will become increasingly weighted towards the development of our Utica Shale acreage. The costs and production associated with the wells we expect to drill in the Utica Shale may differ substantially from those we have historically drilled in the Marcellus Shale.

Financing Arrangements. During the third quarter of 2014, our capital expenditures were financed with proceeds from our public offering (“August 2014 Equity Offering”) of 13,729,650 shares of our common stock at $27.30 per share, which included 7,500,000 shares sold by us and 6,229,650 shares sold by affiliates of Natural Gas Partners and Alpha Natural Resources, Senior Notes Offering (as defined below) and net cash provided by operating activities. In the future, we may incur additional indebtedness and issue additional equity to fund our acquisition and development activities. Please read “—Capital Resources and Liquidity—Debt Agreements” below for additional discussion of our financing arrangements.

On April 25, 2014, we issued $900.0 million (our “Senior Notes Offering”) of 6.25% senior notes due 2022 (the “notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds to us of $882.7 million after deducting estimated expenses and initial purchasers’ discounts of approximately $17.3 million. We used $301.8 million of the net proceeds to repay and retire the Second Lien Term Loan Facility (defined below), with the remainder expected to be used to fund a portion of our capital expenditures program.

In April 2013, we entered into our $300.0 million Second Lien Term Loan Facility agreement (“Second Lien Term Loan Facility”). Net proceeds of our Second Lien Term Loan Facility of $288.3 million after offering fees and expenses were used to repay existing debt of $176.1 million and to partially fund the acquisition of

 

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approximately 33,499 net acres in the Utica Shale in Belmont County, Ohio. On April 25, 2014, the Company used a portion of the net proceeds from the Senior Notes Offering to repay and retire the Second Lien Term Loan Facility in the amount of $301.8 million.

In April 2013, we entered into our $500.0 million Senior Secured Revolving Credit Facility (“Senior Secured Revolving Credit Facility”). Concurrently with the closing of our IPO, on January 29, 2014, the Senior Secured Revolving Credit Facility was amended to, among other things, allow for the corporate reorganization that was completed simultaneously with the closing of the IPO, add us as a guarantor, increase the maximum commitment amount to $1.5 billion, increase the borrowing base to $350.0 million as a result of the Marcellus JV Buy-In and lower the interest rate owed on amounts borrowed under the Senior Secured Revolving Credit Facility. We used a portion of the net proceeds of the IPO to repay $115.0 million of borrowings under our Senior Secured Revolving Credit Facility and $75.4 million of borrowings outstanding under the revolving credit facility of our Marcellus joint venture. Concurrently with the Senior Notes Offering, we, as borrower, and Rice Drilling B, as predecessor borrower, amended the Senior Secured Revolving Credit Facility (“Amended Credit Agreement”) to, among other things, assign all of Rice Drilling B’s rights and obligations under the Senior Secured Revolving Credit Facility to us, and we assumed all such rights and obligations as borrower under the Amended Credit Agreement. As of September 30, 2014, the borrowing base under our Senior Secured Revolving Credit Facility was $385.0 million with zero borrowings outstanding and $66.8 million of letters of credit outstanding. Availability under the borrowing base of our Senior Secured Revolving Credit Facility was $318.2 million as of September 30, 2014. In October 2014, we had a redetermination of the borrowing base under our Senior Secured Revolving Credit Facility which increased the borrowing base to $550.0 million.

Sources of Revenues

The substantial majority of our revenues are derived from the sale of natural gas and do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. The following table provides detail of our operating revenues from the condensed consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013.

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2014				2013				2014				2013
		(in thousands)
Natural gas sales		$	67,625			$	23,526			$	246,583			$	60,219
Oil and natural gas liquids (NGL) sales			206				—				233				—
Firm transportation sales, net			9,733				—				11,851				—
Third party gathering revenue			1,563				24				2,878				61
Other revenue			—				139				—				519
Total operating revenues		$	79,127			$	23,689			$	261,545			$	60,799

NYMEX Henry Hub prompt month contract prices are widely-used benchmarks in the pricing of natural gas. The following table provides the high and low prices for NYMEX Henry Hub prompt month contract prices and our differential to the average of those benchmark prices for the periods indicated.

 

		Year Ended December 31,												Nine Months Ended September 30,
		2013(1)				2012(1)				2011(1)				2014(2)				2013(2)
NYMEX Henry Hub High		$	4.46			$	3.90			$	4.85			$	7.94			$	4.38
NYMEX Henry Hub Low			3.11				1.91				2.99				3.74				3.08
Differential to Average NYMEX Henry Hub			(0.01	)			0.08				(0.12	)			(0.62	)			(0.04	)

 

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(1)	Differential is calculated by comparing the average NYMEX Henry Hub price to our volume weighted average realized price per MMBtu, including our proportionate 50% share of the volumes sold by our Marcellus joint venture.

(2)

Differential is calculated by comparing the average NYMEX Henry Hub price to our volume weighted average realized price per MMBtu before hedges, including 50% of the volumes sold by our Marcellus joint venture for the period from January 1, 2014 through January 28, 2014, contained within the three and nine months ended September 30, 2014 and for the three and nine months ended September 30, 2013. The remainder of the three months ended September 30, 2014 reflect (i) the completion of the corporate reorganization in connection with our IPO and (ii) the consummation of the Marcellus JV Buy-In, each on January 29, 2014.

We sell a substantial majority of our production to a single natural gas marketer, Sequent Energy Management, LP (“Sequent”). For the year ended December 31, 2013, sales to Sequent and Dominion Field Services (“Dominion”) represented 94% and 6% of our total sales, respectively. For the three and nine months ended September 30, 2014, sales to Sequent represented 83% and 87% of our total sales, respectively. If our natural gas marketers decided to stop purchasing natural gas from us, our revenues could decline and our operating results and financial condition could be harmed. Although a substantial portion of production is purchased by this customer, we do not believe the loss of this customer would have a material adverse effect on our business, as other customers or markets would be accessible to us.

Principal Components of our Cost Structure

 

•

Lease operating expense. These are the day to day operating costs incurred to maintain production of our natural gas producing wells. Such costs include produced water disposal, maintenance and repairs. Cost levels for these expenses can vary based on supply and demand for oilfield services.

 

•

Gathering, compression and transportation. These are costs incurred to bring natural gas to the market. Such costs include the costs to operate and maintain our low- and high-pressure gathering and compression systems as well as fees paid to third parties who operate low- and high-pressure gathering systems that transport our natural gas. We often enter into firm transportation contracts that secure takeaway capacity that includes minimum volume commitments, the cost for which is included in these expenses.

 

•

Production taxes and impact fees. Pennsylvania imposes an annual impact fee on each producing shale well for a period of 15 years. Ohio imposes a production tax which is based upon annual production. As we expand our operations into the Utica Shale in Ohio, the proportion of our production and producing wells from each state may change over time and, as a result, the proportion of our production taxes and impact fees will vary depending on our quantities produced from the Utica Shale, the number of producing shale wells in Pennsylvania, and the applicable production tax rates and impact fees then in effect.

 

•

Exploration expense. These include geological and geophysical costs, seismic costs, delay rental payments and costs incurred in the development of an unsuccessful exploratory well.

 

•

General and administrative expense. We expect that we will incur additional general and administrative expenses as a result of being a publicly-traded company. Please see “—Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations—Public Company Expenses.” In addition, certain of our employees hold incentive units in Rice Holdings and NGP Holdings that entitle the holder to a portion of distributions by Rice Holdings and NGP Holdings. While any such distributions did not and will not involve any cash payment by us, we recognized non-cash compensation expense of approximately $101.7 million during the first nine months of 2014. As of September 30, 2014, the unrecognized compensation expense related to such incentive units is approximately $77.3 million, which will be recognized over the remaining expected service period.

 

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•

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas. As a “successful efforts” company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts and allocate these costs to each unit of production using the units of production method.

 

•

Write-down of abandoned leases. These write-downs include the cost of expensing certain lease acquisition costs associated with properties that we no longer expect to drill.

 

•

Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under our revolving credit facility and term loan. As a result, we incur interest expense that is affected by the level of drilling, completion and acquisition activities, as well as fluctuations in interest rates and our financing decisions. We also incur interest expense on our convertible debentures. We will likely continue to incur significant interest expense as we continue to grow. To date, we have not entered into any interest rate hedging arrangements to mitigate the effects of interest rate changes. Additionally, we capitalized $8.0 million, $7.7 million and $5.4 million of interest expense for the years ended December 31, 2013, 2012 and 2011, respectively.

 

•

Derivative fair value loss (gain). We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are recorded at fair value at each balance sheet date with changes in fair value recognized as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

 

•

Equity in income (loss) of joint ventures. This line item represents our proportionate share of earnings and losses from our equity method investments, including our Marcellus joint venture. Concurrently with the closing of our IPO, we acquired Alpha Holdings’ 50% interest in our Marcellus joint venture and, as a result, for periods following the completion of our IPO, the results of operations of our Marcellus joint venture will be included in our results of operations.

 

•

Income tax expense. Rice Drilling B, our accounting predecessor, is a limited liability company not subject to federal income taxes. Accordingly, no provision for federal income taxes has been provided for in our historical results of operations because taxable income was passed through to Rice Drilling B’s members. Although we are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings, we did not report any income tax benefit or expense until the consummation of our IPO. Based on our deductions primarily related to IDCs that are expected to exceed 2014 earnings, we expect to generate significant net operating loss deferred tax assets and deferred tax liabilities. We may report and pay state income or franchise taxes in periods where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis.

 

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Historical Results of Operations

Three and Nine Months Ended September 30, 2014 Compared to Three and Nine Months Ended September 30, 2013

Below are some highlights of our financial and operating results for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013:

 

•

Our natural gas, oil and NGL sales were $67.8 million and $23.5 million in the three months ended September 30, 2014 and 2013, respectively and $246.8 million and $60.2 million in the nine months ended September 30, 2014 and 2013, respectively.

 

•

Our production volumes were 22,757 MMcfe and 6,618 MMcfe in the three months ended September 30, 2014 and 2013, respectively and 61,116 MMcfe and 15,728 MMcfe in the nine months ended September 30, 2014 and 2013, respectively.

 

•

Our firm transportation sales, net were $9.7 million and zero in the three months ended September 30, 2014 and 2013, respectively and $11.9 million and zero in the nine months ended September 30, 2014 and 2013, respectively.

 

•

Our per unit cash production costs were $0.67 per Mcfe and $0.86 per Mcfe in the three months ended September 30, 2014 and 2013, respectively and $0.73 per Mcfe and $0.88 per Mcfe in the nine months ended September 30, 2014 and 2013, respectively.

 

•

Our G&A expenses were $10.5 million and $4.2 million in the three months ended September 30, 2014 and 2013, respectively and $36.7 million and $10.0 million in the nine months ended September 30, 2014 and 2013, respectively.

The following tables set forth selected operating and financial data for the three and nine months ended September 30, 2014 compared to the three and nine months ended September 30, 2013:

 

		Three Months Ended September 30,												Nine Months Ended September 30,
		2014				2013				Change				2014				2013				Change
Natural gas sales (in thousands)		$	67,625			$	23,526			$	44,099			$	246,583			$	60,219			$	186,364
Oil and NGL sales (in thousands)			206				—				206				233				—				233
Natural gas, oil and NGL sales (in thousands)		$	67,831			$	23,526			$	44,305			$	246,816			$	60,219			$	186,597
Firm transportation sales, net (in thousands)		$	9,733			$	—			$	9,733			$	11,851			$	—			$	11,851
Natural gas production (MMcf)			22,740				6,618				16,122				61,096				15,728				45,368
Oil and NGL production (Bbls)			2,841				—				2,841				3,390				—				3,390
Total production (MMcfe)			22,757				6,618				16,139				61,116				15,728				45,388
Average natural gas prices before effects of hedges per Mcf		$	2.97			$	3.55			$	(0.58	)		$	4,04			$	3.83			$	0.21
Average realized natural gas prices after effects of hedges per Mcf(1)			2.98				3.67				(0.69	)			3.70				3.76				(0.06	)
Average oil and NGL prices per Bbl			72.48				—				72.48				68.82				—				68.82
Average costs per Mcfe
Lease operating		$	0.20			$	0.27			$	(0.07	)		$	0.27			$	0.37			$	(0.10	)
Gathering, compression and transportation			0.42				0.51				(0.09	)			0.42				0.44				(0.02	)
Production taxes and impact fees			0.05				0.08				(0.03	)			0.04				0.07				(0.03	)
General and administrative			0.46				0.63				(0.17	)			0.60				0.63				(0.03	)
Depreciation, depletion and amortization			1.49				1.47				0.02				1.50				1.48				0.02

 

(1)	The effect of hedges includes realized gains and losses on commodity derivative transactions.

 

 

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		Rice Energy Inc.												Rice Energy Inc.
		Three Months Ended September 30,												Nine Months Ended September 30,
		2014				2013				Change				2014				2013				Change
		(in thousands)
Operating revenues:
Natural gas, oil and NGL sales		$	67,831			$	23,526			$	44,305			$	246,816			$	60,219			$	186,597
Firm transportation sales, net			9,733				—				9,733				11,851				—				11,851
Other revenue			1,563				163				1,400				2,878				580				2,298
Total operating revenues			79,127				23,689				55,438				261,545				60,799				200,746
Operating expenses:
Lease operating			4,553				1,777				2,776				16,406				5,794				10,612
Gathering, compression and transportation			9,597				3,365				6,232				25,904				6,951				18,953
Production taxes and impact fees			1,114				522				592				2,624				1,029				1,595
Exploration			747				338				409				1,706				1,784				(78	)
Incentive unit expense			26,418				—				26,418				101,695				—				101,695
Restricted unit expense			—				32,381				(32,381	)			—				40,087				(40,087	)
Stock compensation expense			2,058				—				2,058				3,274				—				3,274
General and administrative			10,458				4,169				6,289				36,733				9,952				26,781
Depreciation, depletion and amortization			33,853				9,722				24,131				91,912				23,215				68,697
Acquisition expense			2,246				—				2,246				2,246				—				2,246
Amortization of intangible assets			408				—				408				748				—				748
Total operating expenses			91,452				52,274				39,178				283,248				88,812				194,436
Operating loss			(12,325	)			(28,585	)			16,260				(21,703	)			(28,013	)			6,310
Interest expense			(15,754	)			(5,943	)			(9,811	)			(38,737	)			(13,033	)			(25,704	)
Gain on purchase of Marcellus joint venture			—				—				—				203,579				—				203,579
Other income (loss)			(216	)			38				(254	)			180				(408	)			588
Gain on derivative instruments			36,935				8,050				28,885				5,357				16,698	)			(11,341	)
Amortization of deferred financing costs			(707	)			(958	)			251				(1,728	)			(4,760	)			3,032
Loss on extinguishment of debt			(790	)			(10,622	)			9,832				(3,934	)			(10,622	)			6,688
Write-off of deferred financing costs			—				—				—				(6,896	)			—				(6,896	)
Equity in income (loss) of joint ventures			—				4,368				(4,368	)			(2,656	)			19,297				(21,953	)
Income (loss) before income taxes			7,143				(33,652	)			40,795				133,462				(20,841	)			154,303
Income tax expense			(14,005	)			—				(14,005	)			(18,787	)			—				(18,787	)
Net income (loss)		$	(6,862	)		$	(33,652	)		$	26,790			$	114,675			$	(20,841	)		$	135,516
Weighted average number of shares of common stock—basic			132,269				88,000				44,269				125,412				77,895				47,517
Weighted average number of shares of common stock—diluted			132,269				88,000				44,269				125,678				77,895				47,783
Earnings per share—basic		$	(0.05	)		$	(0.38	)		$	0.33			$	0.91			$	(0.27	)		$	1.18
Earnings per share—diluted		$	(0.05	)		$	(0.38	)		$	0.33			$	0.91			$	(0.27	)		$	1.18

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Total operating revenues. The $44.3 million increase in natural gas, oil and NGL sales was mainly a result of an increase in production in the third quarter of 2014 compared to the third quarter of 2013. The increase in production was a result of increased drilling and completion activity, mainly in Washington County, Pennsylvania and Belmont County, Ohio and production from seven wells acquired in our acquisition of approximately 22,000 net acres and 12 developed Marcellus wells in western Greene County, Pennsylvania from Chesapeake Appalachia, L.L.C. and Statoil USA Onshore Properties Inc. for approximately $329 million on August 1, 2014 (the “Greene

 

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County Acquisition”). Production volume increases were partially offset by approximately, 60 days of capacity restricted volumes from four pads as a result of longwall coal undermining. The impact of increased production volumes on operating revenues was partially offset by a decrease in realized prices in 2014 compared to 2013. In addition, operating revenues for the third quarter of 2014 were positively impacted by approximately $8.5 million in firm transportation sales, net, from the sale of unutilized capacity in September 2014 to a third party.

Lease operating expenses. The $2.8 million increase in lease operating expenses is attributable to an increase in the number of producing wells in 2014 as compared to the prior year. However, lease operating expenses per unit of production decreased due to improved efficiencies, primarily due to more producing wells per pad and lower fixed costs per well.

Gathering, compression and transportation. The $6.2 million increase in gathering, compression and transportation expenses is primarily attributable to increased firm transportation contracts in the third quarter of 2014 compared to the third quarter of 2013.

Incentive unit expense. The $26.4 million increase in incentive unit expense was due to $14.4 million of non-cash compensation expense recognized in relation to the incentive unit awards based on fair market value assumptions as of September 30, 2014. Additionally, NGP Holdings paid approximately $12.0 million to holders of certain NGP Holdings incentive units as a result of our August 2014 Equity Offering. See “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—8. Incentive Units” for additional information.

G&A. The $6.3 million increase was primarily attributable to the additions of personnel to support our growth activities and related salary and employee benefits. At September 30, 2014, we had 250 employees as compared to 116 employees at September 30, 2013.

DD&A. The $24.1 million increase was a result of an increase in production and greater number of producing wells in the third quarter of 2014 compared to 2013. This is consistent with our expanded drilling program and increased production during the period.

Interest expense. The $9.8 million increase was a result of higher levels of average borrowings outstanding during the third quarter of 2014 in order to fund our capital programs.

Gain on derivative instruments. The $36.9 million gain on derivative contracts in the third quarter of 2014 was comprised of $36.8 million in unrealized gains and $0.1 million of cash receipts on the settlement of maturing contracts. In the third quarter of 2013, the $8.0 million gain was comprised of $7.3 million in unrealized gains and $0.8 million of cash receipts made on the settlement of maturing contracts. The gain in the third quarter of 2014 as compared to the gain in the same period in 2013 was attributable to a decrease in market prices.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

Total operating revenues. The $186.6 million increase in natural gas, oil and NGL sales was mainly a result of an increase in production in the nine months ended 2014 compared to the nine months ended 2013. The increase in production was a result of increased drilling and completion activity, primarily in Washington County, Pennsylvania and Belmont County, Ohio, and production from seven wells acquired in our Greene County Acquisition on August 1, 2014. Production volume increases were partially offset by approximately 60 days of capacity restricted volumes from four pads as a result of longwall coal undermining. The impact of increased production volumes on operating revenues was partially offset by a decrease in realized prices in 2014 compared to 2013. In addition, operating revenues for the nine months ended September 30, 2014 were positively impacted by approximately $8.5 million in firm transportation sales, net, from the sale of unutilized capacity for the month of September 2014 to a third party.

 

 

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Lease operating expenses. The $10.6 million increase in lease operating expenses is attributable to an increase in the number of producing wells in 2014 as compared to the prior year. However, lease operating expenses per unit of production decreased due to improved efficiencies, primarily due to more producing wells per pad and lower fixed costs per well.

Gathering, compression and transportation. The $19.0 million increase in gathering, compression and transportation expenses is primarily attributable to increased firm transportation contracts in 2014 compared to 2013.

Incentive unit expense. The $101.7 million increase in incentive unit expense was due to approximately $81.9 million of non-cash compensation expense related to incentive units still outstanding which related to the service period from date of grant through September 30, 2014. In addition, the increase was due to approximately $12.0 million paid to holders of certain NGP Holdings incentive units by NGP Holdings as a result of our August 2014 Equity Offering, payment by NGP Holdings of approximately $4.4 million related to payments made at IPO due to the New Tier I payout multiple being achieved and the payment by Daniel J. Rice III of approximately $3.4 million related to his incentive unit burden. See “Item 1. Financial Statements—Notes to Condensed Consolidated Financial Statements—8. Incentive Units” for additional information.

G&A. The $26.8 million increase was primarily attributable to the additions of personnel to support our growth activities and related salary and benefit expenses. At September 30, 2014, we had 250 employees as compared to 116 employees at September 30, 2013.

DD&A. The $68.7 million increase was a result of an increase in production and a greater number of producing wells in 2014 compared to 2013. This is consistent with our expanded drilling program and increased production during the period.

Interest expense. The $25.7 million increase was a result of higher levels of average borrowings outstanding during 2014 in order to fund our capital programs.

Gain on purchase of Marcellus joint venture. The $203.6 million gain on acquisition in the first quarter of 2014 was attributable to the Marcellus JV Buy-In transaction. As a result of our acquiring the remaining ownership in our Marcellus joint venture, we are required to remeasure our equity investment at fair value, which resulted in a non-recurring gain of approximately $203.6 million during the nine months ended September 30, 2014.

Gain on derivative instruments. The $5.4 million gain on derivative contracts in 2014 was comprised of $26.1 million in unrealized gains and $20.8 million of cash payments on the settlement of maturing contracts. In 2013, the $16.7 million gain was comprised of $17.8 million in unrealized gains and $1.1 million of cash payments made on settlement of maturing contracts. The gain in 2014 as compared to the gain in 2013 was attributable to an increase in market prices accompanied by a greater hedged volume of our natural gas production.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Below are some highlights of our financial and operating results for the year ended December 31, 2013:

 

•

Our production volumes, including our 50% share of the production in our Marcellus joint venture, increased 164% to 34,438 MMcf in the year ended December 31, 2013 compared to 13,065 MMcf in the year ended December 31, 2012.

 

•

Our natural gas sales increased 229% to $87.8 million in the year ended December 31, 2013 compared to $26.7 million in the year ended December 31, 2012.

 

 

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•

Our per unit cash production costs decreased 15% to $1.60 per Mcf in the year ended December 31, 2013 compared to $1.88 per Mcf in the year ended December 31, 2012. Cash production costs include amounts paid for Pennsylvania impact fees of $0.07 per Mcf and $0.16 per Mcf for the year ended December 31, 2013 and December 31, 2012, respectively. Pennsylvania began assessing an impact fee on wells spud in the first quarter of 2012 and retroactively assessed fees for wells spud prior to 2012. Of the $0.16 per Mcf incurred in the year ended December 31, 2012, approximately $0.07 per Mcf relates to charges assessed by the state of Pennsylvania for wells spud prior to 2012. The remaining $0.09 relates to wells spud in 2012.

 

•

Our general and administrative expenses increased 123% to $17.0 million in the year ended December 31, 2013 compared to $7.6 million for the year ended December 31, 2012.

 

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The following tables set forth selected operating and financial data for the year ended December 31, 2013 compared to the year ended December 31, 2012:

 

		Year Ended December 31,								Amount of Change
		2013				2012
		(in thousands)
Revenues:
Natural gas sales		$	87,847			$	26,743			$	61,104
Other revenue			757				457				300
Total revenues			88,604				27,200				61,404
Operating expenses:
Lease operating			8,309				3,688				4,621
Gathering, compression and transportation			9,774				3,754				6,020
Production taxes and impact fees			1,629				1,382				247
Exploration			9,951				3,275				6,676
Restricted unit expense			32,906				—				32,906
General and administrative			16,953				7,599				9,354
Depreciation, depletion and amortization			32,815				14,149				18,666
Write-down of abandoned leases			—				2,253				(2,253	)
Loss from sale of interest in gas properties			4,230				—				4,230
Total operating expenses			116,567				36,100				80,467
Operating loss			(27,963	)			(8,900	)			(19,063	)
Other income (expense):
Interest expense			(17,915	)			(3,487	)			(14,428	)
Other income (expense)			(357	)			112				(469	)
Gain (loss) on derivative instruments			6,891				(1,381	)			8,272
Amortization of deferred financing costs			(5,230	)			(7,220	)			1,990
Loss on extinguishment of debt			(10,622	)			—				(10,622	)
Equity in income of joint ventures			19,420				1,532				17,888
Total other expense			(7,813	)			(10,444	)			2,631
Net loss		$	(35,776	)		$	(19,344	)		$	(16,432	)
Natural gas sales (in thousands):
Rice Energy Inc.		$	87,847			$	26,743			$	61,104
Marcellus joint venture(1)			45,339				13,142				32,197
Production data (MMcf):
Rice Energy Inc.			22,995				8,769				14,226
Marcellus joint venture(1)			11,443				4,296				7,147
Average prices before effects of hedges per Mcf:
Rice Energy Inc.		$	3.82			$	3.05			$	0.77
Marcellus joint venture			3.96				3.06				0.90
Average realized prices after effects of hedges per Mcf(2):
Rice Energy Inc.		$	3.85			$	3.15			$	0.70
Marcellus joint venture			4.16				3.07				1.09
Average costs per Mcf:
Rice Energy Inc.
Lease operating		$	0.36			$	0.42			$	(0.06	)
Gathering, compression and transportation			0.43				0.43
General and administrative			0.74				0.87				(0.13	)
Depletion, depreciation and amortization			1.43				1.61				(0.18	)
Marcellus joint venture:
Lease operating		$	0.36			$	0.39			$	(0.03	)
Gathering, compression and transportation			0.68				0.78				(0.10	)
General and administrative			0.14				0.24				(0.10	)
Depletion, depreciation and amortization			1.09				1.10				(0.01	)

 

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(1)	Amounts presented for our Marcellus joint venture give effect to our 50% equity investment therein during the periods presented.

(2)	The effect of hedges includes realized gains and losses on commodity derivative transactions.

Natural gas sales revenues. The $61.1 million increase was a result of an increase in production of 14,226 MMcf in 2013 compared to the prior year. The increase in production was a result of increased drilling and completion activity in Washington County, Pennsylvania. In addition, average prices before the effect of hedges increased from $3.05 per Mcf in 2012 to $3.82 per Mcf in 2013.

Lease operating expenses. The $4.6 million increase in lease operating expenses is attributable to higher production during 2013. However, lease operating expenses per unit of production decreased due to having more wells in early stages of production in 2013 as compared to 2012.

Gathering, compression and transportation. The $6.0 million increase in gathering, compression and transportation expenses is primarily attributable to increased production. The cost per Mcf of these expenses increased during 2013 primarily as a result of increased utilization of firm transportation.

Restricted unit expense. The $32.9 million increase in restricted unit expense relates to an increase in the fair value of the units during 2013. For a description of the restricted units, please see Note 9 to the audited consolidated financial statements included herein. In connection with our IPO, the restricted units were exchanged for shares of our common stock. Accordingly, we will not recognize such restricted unit expense subsequent to the exchange.

G&A. The $9.4 million increase was primarily attributable to the additions of personnel to support our growth activities.

DD&A. The $18.7 million increase was a result of higher average capitalized costs in 2013 compared to the prior year. The increase in capitalized costs is consistent with our expanded drilling program and increased production during the period.

Write-down of abandoned leases. The $2.3 million write-down in 2012 was attributable to our abandonment of certain leases that are outside our core areas of drilling focus.

Exploration expense. The $6.7 million increase in 2013 was primarily the result of the $8.1 million write-off of costs associated with the abandonment of the Bigfoot 7H in the fourth quarter of 2013.

Loss from sale of interest in gas properties. The $4.2 million loss from sale of interest in gas properties was attributable to the sale of interests in noncore assets in Lycoming County, Pennsylvania.

Gain (loss) on derivative instruments. The $6.9 million gain on derivatives contracts in 2013 was comprised of $6.2 million in unrealized gains and $0.7 million of cash receipts received on settlement of maturing contracts. In 2012, the $1.4 million loss was comprised of $2.3 million in unrealized losses and $0.9 million of cash receipts received on settlement of maturing contracts. The gain in 2013 was due to a decrease in market prices after we executed significant derivative contracts.

Interest expense. The $14.4 million increase was a result of higher levels of average borrowings outstanding during 2013 in order to fund our drilling programs.

Loss on extinguishment of debt. The $10.6 million loss on extinguishment of debt in 2013 was attributable to our repurchasing $53.1 million of outstanding convertible debentures, resulting in a put premium of $10.6 million being paid in accordance with the terms thereof.

 

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Equity in income of joint ventures. The $17.9 million increase was primarily a result of operations at our Marcellus joint venture. Approximately $1.7 million of the increased income from our Marcellus joint venture was attributable to net realized gains associated with its hedging program. Substantially all of the remaining increase in income was due to higher revenues, attributable to increased production volumes resulting from the execution of our Marcellus joint venture’s drilling program.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Below are some highlights of our financial and operating results for the year ended December 31, 2012:

 

•

Our production volumes, including our 50% share of the production in our Marcellus joint venture, increased 219% to 13,065 MMcf in the year ended December 31, 2012 compared to 4,089 MMcf in the year ended December 31, 2011.

 

•

Our natural gas sales increased 91% to $26.7 million in the year ended December 31, 2012 compared to $14.0 million in the year ended December 31, 2011.

 

•

Our per unit cash production costs decreased 14% to $1.88 per Mcf in the year ended December 31, 2012 compared to $2.18 per Mcf in the year ended December 31, 2011. Cash production costs include amounts paid for Pennsylvania impact fees of $0.16 per Mcf for year ended December 31, 2012. Pennsylvania began assessing an impact fee in the first quarter of 2012 and retroactively assessed fees for wells spud prior to 2012. Of the $0.16 per Mcf incurred in the year ended December 31, 2012, approximately $0.07 per Mcf relates to charges assessed by the state of Pennsylvania for wells spud prior to 2012. The remaining $0.09 relates to wells spud in 2012.

 

•

Our total operating expenses increased 180% to $43.3 million in the year ended December 31, 2012 compared to $15.5 million in the year ended December 31, 2011. This increase was generally in line with our increase in revenue resulting from the execution of our drilling program.

 

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The following table sets forth selected operating and financial data for the year ended December 31, 2012 compared to the year ended December 31, 2011:

 

		Year Ended December 31,								Amount of Change
		2012				2011
		(in thousands)
Revenues:
Natural gas sales		$	26,743			$	13,972			$	12,771
Other revenue			457				—				457
Total revenues			27,200				13,972				13,228
Operating expenses:
Lease operating			3,688				1,617				2,071
Gathering, compression and transportation			3,754				540				3,214
Production taxes and impact fees			1,382				—				1,382
Exploration			3,275				660				2,615
Restricted unit expense			—				170				(170	)
General and administrative			7,599				5,208				2,391
Depreciation, depletion and amortization			14,149				5,981				8,168
Write-down of abandoned leases			2,253				109				2,144
Gain from sale of interest in gas properties			—				(1,478	)			1,478
Total operating expenses			36,100				12,807				23,293
Operating income (loss)			(8,900	)			1,165				(10,065	)
Other income (expense):
Interest expense			(3,487	)			(531	)			(2,956	)
Other income			112				161				(49	)
Gain (loss) on derivative instruments			(1,381	)			574				(1,955	)
Amortization of deferred financing costs			(7,220	)			(2,675	)			(4,545	)
Equity in income of joint ventures			1,532				370				1,162
Total other expenses			(10,444	)			(2,101	)			(8,343	)
Net loss		$	(19,344	)		$	(936	)		$	(18,408	)
Natural gas sales (in thousands):
Rice Energy Inc.		$	26,743			$	13,972			$	12,771
Marcellus joint venture(1)			13,142				2,872				10,270
Production data (MMcf):
Rice Energy Inc.			8,769				3,392				5,377
Marcellus joint venture(1)			4,296				697				3,599
Average prices before effects of hedges per Mcf:
Rice Energy Inc.		$	3.05			$	4.12			$	(1.07	)
Marcellus joint venture			3.06				4.12				(1.06	)
Average realized prices after effects of hedges per Mcf(2):
Rice Energy Inc.		$	3.15			$	4.29			$	(1.14	)
Marcellus joint venture			3.07				4.12				(1.05	)
Average costs per Mcf:
Rice Energy Inc.
Lease operating		$	0.42			$	0.48			$	(0.06	)
Gathering, compression and transportation			0.43				0.16				0.27
General and administrative			0.87				1.54				(0.67	)
Depletion, depreciation and amortization			1.61				1.76				(0.15	)
Marcellus joint venture:
Lease operating		$	0.39			$	0.51			$	(0.12	)
Gathering, compression and transportation			0.78				0.04				0.74
General and administrative			0.24				0.26				(0.02	)
Depletion, depreciation and amortization			1.10				1.57				(0.47	)

 

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(1)	Amounts presented for our Marcellus joint venture give effect to our 50% equity investment therein during the period presented.

(2)	The effect of hedges includes realized gains and losses on commodity derivative transactions.

Natural gas sales revenues. The $12.8 million increase was a result of an increase in production of 5,377 MMcf in 2012 compared to the prior year, partially offset by a 26% decrease in average prices before the effect of hedges. The increase in production was a result of a significant acceleration of our drilling and completion program.

Lease operating expenses. The $2.1 million increase in lease operating expenses is generally consistent with the increase in production volumes in 2012 compared to 2011.

Gathering, compression and transportation. Of the $3.2 million increase, $2.4 million is attributable to our purchase of firm transportation to transport our produced natural gas to the markets where it is sold. The firm transportation commitment was made in anticipation of increasing production volumes, which resulted in increased utilization of this firm transportation throughout 2012 and into 2013. The remaining increase in gathering, compression and transportation is due to overall higher production volumes in 2012 compared to 2011.

G&A. The increase of $2.4 million was primarily attributable to the addition of personnel to support our growth activities.

DD&A. The increase of $8.2 million was a result of higher average capitalized costs in 2012 compared to 2011. The increase in capitalized costs is consistent with our expanded drilling program and increased production during the period.

Amortization of deferred financing costs. The increase of $4.5 million was a result of the amendment to our Marcellus joint venture’s credit agreement (“Wells Fargo Credit Facility”) with Wells Fargo Bank, N.A. (“Wells Fargo”) during the 2012 period in order to fund our drilling programs.

Write-down of abandoned leases. The $2.3 million write-off in 2012 was attributable to our abandonment of certain leases that are outside our core areas of drilling focus.

Gain from sale of interest in gas properties. In 2011, we recognized a gain related to the sale of a 50% working interest in certain gas properties in the Marcellus Shale.

Gain (loss) on derivative instruments. The $1.4 million loss on derivatives contracts in 2012 was comprised of $2.3 million in unrealized losses and $0.9 million of cash payments received on settlement of maturing contracts. In 2011, the $0.6 million gain was represented by cash payments received on settlement of maturing contracts.

Interest expense. The increase of $3.0 million was primarily attributable to higher levels of average borrowings outstanding during the 2012 period in order to fund our drilling programs.

Equity in income of joint ventures. The increase of $1.2 million was primarily a result of an increase in operating income attributable to higher production volumes of our Marcellus joint venture.

Capital Resources and Liquidity

Our primary sources of liquidity have been the proceeds from our IPO, August 2014 Equity Offering, Senior Notes Offering, equity contributions from our sponsors, our Amended Credit Agreement and net proceeds from the sale of Rice Drilling B’s convertible debentures. Our primary use of capital has been the acquisition and development of natural gas properties. As we pursue reserve and production growth, we monitor which capital

 

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resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. We also expect to fund a portion of these requirements with cash flow from operations as we continue to bring additional production online.

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us. In 2014, excluding (i) $100.0 million paid with respect to the Marcellus JV Buy-In, (ii) approximately $111.4 million paid with respect to our acquisition of certain gas gathering assets in eastern Washington and Green Counties, Pennsylvania and (iii) approximately $329.5 million paid with respect to the Greene County Acquisition, we plan to invest $1,230.0 million in our operations, including $430.0 million for drilling and completion in the Marcellus Shale, $150.0 million for drilling and completion in the Utica Shale, $385.0 million for leasehold acquisitions and $265.0 million for midstream infrastructure development. Our capital budget excludes acquisitions, other than $385.0 million for leasehold acquisitions. This represents a 96% increase over our $629.0 million pro forma 2013 capital expenditures. Without giving pro forma effect to the Marcellus JV Buy-In, our 2013 capital budget was $578.0 million. We expect to fund the remainder of our 2014 capital expenditures with cash generated by operations, a portion of the net proceeds of our Senior Notes Offering, the net proceeds of our IPO and August 2014 Equity Offering and borrowings under our Senior Secured Revolving Credit Facility. A portion of our 2014 capital budget is projected to be financed with cash flows from operations derived from wells drilled on drilling locations not associated with proved reserves in our December 31, 2013 reserve report. The failure to achieve projected production and cash flows from operations from such wells could result in a reduction to our 2014 capital budget. Our 2014 capital budget may be further adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will have the highest expected rates of return and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

We believe that operating cash flows and available borrowings under our Senior Secured Revolving Credit Facility should be sufficient to meet our current cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies. However, to the extent that we consider market conditions favorable, we may access the capital markets to raise capital from time to time to fund acquisitions, pay down our Senior Secured Revolving Credit Facility and for general working capital purposes.

See “—Debt Agreements” below for additional details on our outstanding borrowings and available liquidity under our various financing arrangements.

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $69.7 million for the nine months ended September 30, 2014, compared to $22.5 million of net cash provided by operating activities for the nine months ended September 30, 2013. The change in operating cash flow was primarily the result of higher production in 2014 at a higher realized gas price, along with net decreases in per unit production costs.

Net cash provided by operating activities was $33.7 million for the year ended December 31, 2013, compared to $3.0 million of net cash used in operating activities for the year ended December 31, 2012. The change in operating cash flow was primarily the result of a $2.2 million increase in net income before DD&A; $17.9 million of which was attributable to undistributed earnings from our Marcellus joint venture and changes in working capital.

 

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For the year ended 2012, net cash used in operating activities was $3.0 million compared to net cash provided by operating activities of $5.1 million for the year ended December 31, 2011. The decrease in cash flow from operations for the year ended December 31, 2012 compared to 2011 was primarily due to an approximate $4.7 million change in working capital items.

Cash Flow Used In Investing Activities

During the nine months ended September 30, 2014 cash flows used in investing activities increased to $1,154.5 million from $342.6 million for the nine months ended September 30, 2013. This was primarily related to increased capital expenditures for drilling, development and acquisition costs. The acquisitions of our Marcellus Shale joint venture, Momentum and Greene County resulted in a net cash outflow of $523.7 million.

During the years ended December 31, 2013 and 2012, cash flows used in investing activities were $458.6 million and $120.0 million, respectively, primarily related to our capital expenditures for drilling, development and acquisition costs. In addition, we made a $10.0 million investment in our Marcellus Shale joint venture during the year ended December 31, 2012.

During the years ended December 31, 2012 and 2011, cash flows used in investing activities were $120.0 million and $79.2 million, respectively, primarily related to our capital expenditures for drilling, development and acquisition costs, net of sales proceeds. Nearly all of our investments in unconsolidated joint ventures of $10.0 million and $15.2 million for the years ended December 31, 2012 and 2011 related to our Marcellus joint venture.

Cash Flow Provided By Financing Activities

Net cash provided by financing activities of $1,185.2 million during the nine months ended September 30, 2014 was primarily the result of the proceeds from our Senior Notes Offering, our IPO and August 2014 Equity Offering (net of offering costs) which was offset by repayments of debt. Net cash provided by financing activities of $339.2 million during the nine months ended September 30, 2013 was primarily related to borrowings under our Second Lien Term Loan facility.

Net cash provided by financing activities of $448.0 million during the year ended December 31, 2013 was primarily the result of debt borrowings net of repayments that are more fully described in “—Debt Agreements” below. In addition, we received capital contributions from our stockholders of $196.0 million and $96.8 million during the years ended December 31, 2013 and 2012, respectively.

Net cash provided by financing activities of $127.1 million during the year ended December 31, 2012 was primarily attributable to capital contributions from our stockholders and net borrowings under debt agreements that are further described in “—Debt Agreements” below. Net cash provided by financing activities of $73.4 million during the year ended December 31, 2011 was primarily the result of debt borrowings net of repayments.

Debt Agreements

6.25% Senior Notes Due 2022

On April 25, 2014, we offered $900.0 million in aggregate principal amounts of the notes due 2022 in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds to us of $882.7 million after deducting estimated expenses and underwriting discounts and commissions of approximately $17.3 million. We used $301.8 million of the net proceeds to repay and retire the Second Lien Term Loan Facility and expect to use the remainder to fund our capital expenditure plan. See “Description of Notes” section of this prospectus for a detailed description of the terms of the notes.

 

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Senior Secured Revolving Credit Facility

Concurrently with our Senior Notes Offering, we, as borrower, and Rice Drilling B, as predecessor borrower, entered into the Amended Credit Agreement to, among other things, assign all of the rights and obligations of Rice Drilling B as borrower under its Senior Secured Revolving Credit Facility to us. Furthermore, the Amended Credit Agreement (i) allowed for the Senior Notes Offering and (ii) provided that we did not incur an immediate reduction in the borrowing base under the Senior Secured Revolving Credit Facility as a result of the Senior Notes Offering. The Amended Credit Agreement also extended the maturity date of the Senior Secured Revolving Credit Facility from April 25, 2018 to January 29, 2019.

The Amended Credit Agreement is secured by liens on at least 80% of the proved oil and gas reserves of us and our subsidiaries (other than any subsidiary that is designated as an unrestricted subsidiary), as well as significant unproved acreage and substantially all of the personal property of us and such restricted subsidiaries, and the Amended Credit Agreement is guaranteed by such restricted subsidiaries. The Amended Credit Agreement contains restrictive covenants that limit the ability of us and our restricted subsidiaries to, among other things:

 

•

incur additional indebtedness;

 

•

sell assets;

 

•

make loans to others;

 

•

make investments;

 

•

enter into mergers;

 

•

make or declare dividends;

 

•

hedge future production or interest rates;

 

•

incur liens; and

 

•

engage in certain other transactions without the prior consent of the lenders.

The Amended Credit Agreement also requires us to maintain certain financial ratios, which are measured at the end of each calendar quarter:

 

•

a current ratio, which is the ratio of consolidated current assets (including unused commitments under the Amended Credit Agreement and excluding non-cash derivative assets) to consolidated current liabilities (excluding current maturities under the Amended Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and

 

•

a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as such term is defined in the Amended Credit Agreement) based on the trailing twelve month period to consolidated interest expense, of not less than 2.5 to 1.0.

We were in compliance with such covenants and ratios as of September 30, 2014.

Second Lien Term Loan Facility

On April 25, 2013, Rice Drilling B entered into a Second Lien Term Loan Facility with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million. Rice Drilling B estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $4.5 million. The discount was being amortized over the life of the note using an effective interest rate of 0.284% using the effective yield method. On April 25, 2014, we used a portion of the net proceeds from our Senior Notes Offering to repay and retire the Second Lien Term Loan Facility, in the amount of $301.8 million. The $301.8 million included the outstanding principal balance of $297.0 million, a prepayment premium in the amount of approximately $3.0 million, and accrued but unpaid interest of $1.8 million.

 

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Convertible Debentures

In June of 2011, Rice Drilling B sold $60.0 million of its 12% Senior Subordinated Convertible Debentures due 2014 (the “Debentures”) in a private placement to certain accredited investors as defined in Rule 501 of Regulation D. The Debentures accrued interest at 12% per year payable monthly in arrears by the 15th day of the month and had a scheduled maturity date of July 31, 2014 (“Maturity Date”). The Debentures were Rice Drilling B’s unsecured senior obligations and ranked equally with all of Rice Drilling B’s then-current and future senior unsecured indebtedness.

In connection with the IPO, the Debentures and warrants of Rice Drilling B were amended to become convertible or exercisable for shares of our common stock. On February 28, 2014, Rice Drilling B issued a redemption notice on the remaining Debentures, which set a redemption date of March 28, 2014. Prior to the redemption date, $6.6 million of the Debentures were converted into 570,945 shares of Rice Energy Inc. common stock. The remaining principal balance of $0.3 million that was not converted will be paid upon request from holders of the remaining Debentures. The premium of $0.1 million was recorded to expense in the nine months ended September 30, 2014. As of September 30, 2014, the remaining principal balance was $0.2 million.

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our natural gas production. Realized pricing is primarily driven by the spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in oil and natural gas prices, we have entered into financial commodity derivative contracts in the form of swaps, zero cost collars, calls, puts and basis swaps to ensure that we receive minimum prices for a portion of our future oil and natural gas production when management believes that favorable future prices can be secured. We typically hedge the NYMEX Henry Hub price for natural gas. The Amended Credit Agreement adjusted our hedging limitation. In the prior Senior Secured Revolving Credit Facility agreement, we were permitted to hedge volumes based on a percentage of expected production from proved reserve volumes. We are now permitted to hedge the greater of (i) the percentage of internally forecasted production (Column A) and (ii) the percentage of proved reserve volumes (Column B) according to the table below.

 

Months next succeeding the time as of which compliance is measured		Column A				Column B
Months 1 through 12			75	%			85	%
Months 13 through 24			50	%			85	%
Months 25 through 36			40	%			85	%
Months 37 through 48			25	%			65	%
Months 49 through 60			15	%			65	%

Our hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price. These contracts may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty and zero cost collars that set a floor and ceiling price for the hedged production. For a description of our commodity derivative contracts, please see Note 11 to the consolidated financial statements of Rice Energy Inc. as of and for the year ended December 31, 2013 included elsewhere in this this prospectus.

 

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By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with six different counterparties. As of September 30, 2014, our contracts with Wells Fargo Bank N.A. accounted for 60% of the net fair market value of our derivative assets. We believe Wells Fargo Bank N.A. is an acceptable credit risk. We are not required to provide credit support or collateral to Wells Fargo Bank N.A. under current contracts, nor are they required to provide credit support or collateral to us. As of September 30, 2014 and December 31, 2013, we did not have any past due receivables from counterparties.

Contractual obligations. A summary of our contractual obligations as of December 31, 2013 is provided in the following table, which does not reflect our IPO, our Senior Notes Offering or the respective uses of proceeds therefrom.

 

		Payments due by period
		For the Year Ended December 31,
		2014				2015				2016				2017				2018				Thereafter				Total
		(in thousands)
Revolving Credit Facility(1)		$	—			$	—			$	—			$	—			$	115,000			$	—			$	115,000
Term Loan Facility(1)			3,000				3,000				3,000				3,000				285,750				—				297,750
Convertible Debentures(2)			7,372				—				—				—				—				—				7,372
NPI Note			8,500				—				—				—				—				—				8,500
Drilling rig commitments(3)			11,732				9,707				—				—				—				—				21,439
Gathering and firm transportation			28,327				52,072				65,557				65,420				63,968				361,842				637,186
Asset retirement obligations(4)			—				—				—				—				—				11,725				11,725
Other			3,360				2,205				1,396				1,302				898				352				9,513
Total		$	62,291			$	66,984			$	69,953			$	69,722			$	465,616			$	373,919			$	1,108,485

 

(1)

Includes outstanding principal amounts at December 31, 2013. This table does not include future commitment fees, amortization of deferred financing costs, interest expense or other fees on these facilities because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2)

Includes accrued interest and put premium for each period through maturity. From July 31, 2013 through August 20, 2013, any holder of convertible debentures had the right to cause us to repurchase all or any portion of the convertible debentures it owned at 100% of the portion of the principal amount of the convertible debentures as to which the right was being exercised, plus a premium of 20%. During this period, we repurchased $53.1 million of outstanding convertible debentures and paid a put premium of $10.6 million in accordance with the terms of the convertible debentures.

(3)

As of December 31, 2013, we had two horizontal drilling rigs under contract. One of these contracts expires in 2014. A third rig, which we took delivery of in February 2014, expires in 2015. Any other rig performing work for us is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the table above. The values in the table represent the gross amounts that we are committed to pay. However, we will record in our financials our proportionate share based on our working interest.

(4)	Represents gross retirement costs with no discounting impact.

 

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Material Weakness in Internal Control over Financial Reporting

Prior to the completion of our IPO, we were a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. In addition, our Marcellus joint venture historically relied on our accounting personnel for its accounting processes. We and our Marcellus joint venture had not maintained effective control environments in that the design and execution of our controls had not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare the financial statements of us and our Marcellus joint venture. We concluded that these control deficiencies constituted a material weakness in our control environment and in the control environment of our Marcellus joint venture. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

In 2011, we and our Marcellus joint venture did not maintain effective controls to ensure proper close processes, formal account reconciliations and technical accounting matter resolution and documentation. In 2012, we and our Marcellus joint venture did not maintain effective controls to ensure proper staffing and supervisory review. For each of these periods, effective controls were not adequately designed or consistently operating to ensure that key computations were properly reviewed before the amounts were recorded in our accounting records. The above identified control deficiencies resulted in audit adjustments to our consolidated financial statements during 2011 and 2012.

To address these control deficiencies, we have implemented additional analysis and reconciliation procedures and increased the levels of review and approval. In addition, we have hired 24 additional accounting and financial reporting staff to complement our historical accounting staff of four individuals as of December 31, 2012. These hires were made to allow for additional preparation and review time during our monthly accounting close process. Additionally, we have begun taking steps to comprehensively document and analyze our system of internal control over financial reporting in preparation for our first management report on internal control over financial reporting required in connection with our annual report for the year ended December 31, 2014. Although remediation efforts are still in progress, we believe the implementation of these changes has substantially improved our control environment as evidenced by the timely filing of our Annual Report on Form 10-K for the year ended December 31, 2013 and a significant decrease in audit adjustments as compared to prior periods. None of these audit adjustments were deemed material.

Due to the recent implementation of these changes to our control environment, management will continue to evaluate the design and effectiveness of these control changes in connection with its ongoing evaluation, documentation, review, formalization and testing of our internal control environment over the remainder of 2014. We have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2014. Based upon the status of our review, we and our independent auditors have concluded that the material weakness had not been fully remediated as of September 30, 2014.

During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weakness previously identified. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of

 

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contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. See Note 1 of the notes to the audited consolidated financial statements for an expanded discussion of our significant accounting policies and estimates made by management.

Incentive units

We recognize non-cash compensation expense for incentive units awarded to certain of our employees by NGP Holdings and Rice Holdings. In connection with our IPO and related corporate reorganization, the holders of incentive units in Rice Appalachia contributed a portion of their incentive units to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. This resulted in the incentive units being deemed to have been modified, and the performance conditions were considered to be probable of occurring. Therefore, their fair values were measured and compensation expense from the date of initial grant through September 30, 2014 has been recognized in the nine months ended September 30, 2014.

It is currently expected that the NGP Holdings incentive units will be satisfied in cash and the Rice Holdings incentive units will be satisfied in shares of our common stock held by Rice Holdings. As a result of these different manners of payment satisfaction, the incentive units are accounted for differently, with the NGP Holdings incentive units being accounted for as liability awards and the Rice Holdings incentive units being accounted for as equity awards. For the NGP Holdings incentive units, for the nine months ended September 30, 2014, the fair value was measured as of September 30, 2014. For future reporting periods, the fair value used to determine the applicable compensation expense will be re-measured at each reporting period. For the Rice Holdings incentive units, the fair value of the incentive units was measured as of January 29, 2014, the date of modification. This fair value will underlie compensation expense charges for future reporting periods.

Determination of the fair value of the awards requires judgments and estimates regarding, among other things, the appropriate methodologies to follow in valuing the incentive units and the related inputs required by those valuation methodologies. The fair values underlying the compensation expense for both types of incentive units were estimated using a Monte Carlo simulation. The Monte Carlo simulation projected the share price for our common stock using the expected volatility, the risk free rate and other variables. The service period, which began on the date of grant and continues through final distribution, has been estimated primarily based upon our assumptions regarding the timing and size of secondary offerings of shares of our common stock by NGP Holdings and/or other liquidity events.

Future results of operations for any particular quarterly or annual period could be materially affected by changes in the Company’s assumptions. Any change in inputs or number of inputs to this calculation could impact the valuation and thus the non-cash compensation expense recognized. See Note 8 to our Condensed Consolidated Financial Statements for the nine months ended September 30, 2014 included elsewhere in this prospectus for additional information. Non-cash compensation expenses related to the incentive units is included in incentive unit expense within the Condensed Consolidated Statement of Operations.

Income taxes

We are a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings and, as such, our future income taxes will be dependent upon our future taxable income. We did not report any income tax benefit or expense for periods prior to the consummation of our IPO because Rice Drilling B, our accounting predecessor, is a limited liability company that was not and currently is not subject to federal income tax. The reorganization of our business in connection with the closing of the IPO, such

 

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that it is now held by a corporation subject to federal income tax, required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of the completion of the IPO as it represents a transaction among shareholders. Additionally, we have presented pro forma EPS for the nine month period ending September 30, 2014 assuming a statutory rate as disclosed in the accompanying condensed consolidated statements of operations.

Based on management’s analysis, the Company did not have any uncertain tax positions as of September 30, 2014 and December 31, 2013.

Income taxes are accounted for under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which differences are expected to be recovered or settled pursuant to the provisions of ASC 740-Income Taxes. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We will record a valuation allowance if it is deemed more likely than not that all or a portion of its deferred income tax assets will not be realized. In addition, income tax rules and regulations are subject to interpretation and the application of those rules and regulations require judgment by us and may be challenged by the taxation authorities. We follow ASC 740-10-25, which requires the use of a two-step approach for recognizing and measuring tax benefits taken or expected to be taken in a tax return and disclosures regarding uncertainties in income tax positions. Only tax positions that meet the more likely than not recognition threshold are recognized.

Business Combinations

For acquisitions of working interests that are accounted for as business combinations, the results of operations are included in the Consolidated Statement of Operations from the date of acquisition. Purchase prices are allocated to assets acquired based on their estimated fair values at the time of acquisition. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the assumptions of market participants and not those of the reporting entity. Therefore, entity-specific intentions do not impact the measurement of fair value. The fair value of natural gas properties is determined using a risk-adjusted after-tax discounted cash flow analysis based upon significant inputs including: 1) gas prices, 2) projections of estimated quantities of natural gas reserves, including those classified as proved, probable and possible, 3) projections of future rates of production, 4) timing and amount of future development and operating costs, 5) projected reserve recovery factors, and 6) weighted average cost of capital.

Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by us under contract with our natural gas marketers. Pricing provisions are tied to the Platts Gas Daily market prices.

Investments in Joint Ventures

We account for our oilfield service company joint venture investment and for periods prior to the completion of the Marcellus JV Buy-In accounted for our Marcellus joint venture investment, under the equity method of accounting as we have significant influence, but not control, over the joint ventures.

 

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Under the equity method of accounting, investments are carried at cost, adjusted for our proportionate share of the undistributed earnings or losses and reduced for any distributions from the investment. We also evaluate our equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in value of the investment. Such events may include sustained operating losses by the investee or long-term negative changes in the investee’s industry. These indicators were not present, and as a result, we did not recognize any impairment charges related to our equity method investments for any of the periods presented in the consolidated financial statements.

Gas Properties

We use the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in gas properties and to drill and equip exploratory wells that result in proved reserves are capitalized. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and costs of carrying and retaining unproved properties are expensed.

Unproved gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the units of production method. Support equipment and other property and equipment not directly related to gas properties are depreciated over their estimated useful lives.

Management’s estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, we adjust natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have a material effect on our net income or loss.

On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.

Asset Retirement Obligations

We record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. Our retirement obligations relate to the abandonment of gas-producing facilities and include costs to reclaim drilling sites and dismantle and relocate or dispose of gathering systems, wells, and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.

When a new liability is recorded, we capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. To the extent future revisions to assumptions impact the present value of the existing asset retirement obligation a corresponding adjustment is made to the natural gas and oil property balance. For

 

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example, as we analyze actual plugging and abandonment information, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.

Equity Incentives

We have entered into certain compensation arrangements with employees and, in limited cases, consultants. These arrangements have resulted in certain of the awards contained within the arrangements being accounted for as equity awards whereas other awards do not have the characteristics of equity and accordingly are not accounted for as such. These compensation arrangements require us to estimate the fair value of such arrangements. Management established an estimated fair value for issued units based upon an income approach prior to December 31, 2013. At December 31, 2013, in connection with our IPO, a market approach was used. Certain of the compensation arrangements contain performance conditions that need to be achieved in order for vesting in the arrangements to occur. We routinely monitor these performance conditions in order to determine if compensation expense is required to be recorded in the consolidated financial statements.

Depletion

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, is computed using proved developed reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.

Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity Price Risk and Hedges

For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commodity Hedging Activities.”

Interest Rate Risks

As of September 30, 2014, we had zero borrowings and approximately $66.8 million in letters of credit outstanding under our Senior Secured Revolving Credit Facility. Concurrently with the closing of our IPO, we amended our Senior Secured Revolving Credit Facility to, among other things, increase the maximum commitment amount to $1.5 billion and lower the interest rate owed on amounts borrowed under the Senior Secured Revolving Credit Facility. After giving effect to the amendment, the borrowing base under our Senior Secured Revolving Credit Facility was increased to $350.0 million as a result of the Marcellus JV Buy-In. As of September 30, 2014, we had availability under our Senior Secured Revolving Credit Facility of approximately $318.2 million and the borrowing base was increased to $385.0 million. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 basis points following the closing of our IPO, depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for

 

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one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points following the closing of our IPO as a result of the Marcellus JV Buy-In, depending on the percentage of our borrowing base utilized. The interest rate did not change under the Amended Credit Agreement.

As of September 30, 2014, we did not have any derivatives in place to mitigate the effects of interest rate risk. We may implement an interest rate hedging strategy in the future.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through joint interest receivables ($82.2 million as of September 30, 2014) and the sale of our natural gas production ($52.3 million in receivables as of September 30, 2014), which we market to multiple natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with one natural gas marketing company. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP.

 

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BUSINESS

We are an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. We are focused on creating shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We strive to be an early entrant into the core of a shale play by identifying what we believe to be the core of the play and aggressively executing our acquisition strategy to establish a largely contiguous acreage position. We believe we were an early identifier of the core of both the Marcellus Shale in southwestern Pennsylvania and the Utica Shale in southeastern Ohio.

All of our current and planned development is located in what we believe to be the core of the Marcellus and Utica Shales. The Marcellus Shale is one of the most prolific unconventional resource plays in the United States, and we believe the Utica Shale, based on initial drilling results, is a premier North American shale play. Together, these resource plays offer what we believe to be among the highest rate of return wells in North America. As of September 30, 2014, we held approximately 82,626 net acres in the southwestern core of the Marcellus Shale, primarily in Washington County and Greene County, Pennsylvania. We established our Marcellus Shale acreage position through a combination of largely contiguous acreage acquisitions in 2009 and 2010 and through numerous bolt-on acreage acquisitions. In 2012, we acquired approximately 33,499 of our 53,816 net acres in the southeastern core of the Utica Shale, primarily in Belmont County, Ohio. We believe this area to be the core of the Utica Shale based on publicly available drilling results. We operate a substantial majority of our acreage in the Marcellus Shale and a majority of our acreage in the Utica Shale.

 

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Since completing our first horizontal well in the fourth quarter of 2010, our pro forma average net daily production has grown approximately 120 times to 241 MMcf/d for the second quarter of 2014. Substantially all of our production through the second quarter of 2014 has been dry gas attributable to our operations in the Marcellus Shale. Prior to the second quarter of 2013, we ran a two-rig drilling program focused on delineating and defining the boundaries of our Marcellus Shale acreage position. In the second quarter of 2013, we shifted our operational focus from exploration to development, commencing a four-rig drilling program consisting of two rigs specifically for drilling the tophole sections of our horizontal wells and two rigs specifically for drilling the curve and lateral sections of our horizontal wells. In the first quarter of 2014, we increased to a six-rig drilling program (consisting of three tophole rigs and three horizontal rigs). In the second quarter of 2014, we averaged three horizontal rigs. We expect to continue to operate a six-rig drilling program through the remainder of 2014. The following chart shows our pro forma average net daily production for each quarter since completing our first horizontal well in the Marcellus Shale.

 

As of June 30, 2014, we had drilled and completed 51 horizontal Marcellus wells with lateral lengths ranging from 2,444 feet to 9,648 feet and averaging 6,291 feet. Our estimated ultimate recoveries (“EUR”) from our 37 producing wells at December 31, 2013, as estimated by our independent reserve engineer, NSAI, and normalized for each 1,000 feet of horizontal lateral, range from 1.2 Bcf per 1,000 feet to 3.0 Bcf per 1,000 feet, with an average of 1.9 Bcf per 1,000 feet. Additionally, we have drilled and completed three Upper Devonian horizontal wells on our Marcellus Shale acreage. Based on our Upper Devonian wells and those of other operators in the vicinity of our acreage as well as other geologic data, we estimate that substantially all of our Marcellus Shale acreage in Southwestern Pennsylvania is prospective for the slightly shallower Upper Devonian Shale.

For the Utica Shale, we applied the same shale analysis and acquisition strategy that we developed and employed in the Marcellus Shale to acquire our acreage. In June 2014 we completed our first Utica well, the Bigfoot 9H, which tested at a stabilized rate of 41.7 MMcf/d. Please see “—Recent Developments—Utica Update.” Our delineation operations are being conducted with a two-rig drilling program (one tophole rig and one horizontal rig). We intend to maintain this two-rig drilling program in the Utica Shale through 2014. In 2015, we intend to transition to a primarily development-focused strategy in the Utica Shale.

 

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As of December 31, 2013, our pro forma estimated proved reserves were 602 Bcf, all of which were in southwestern Pennsylvania, with 42% proved developed and 100% natural gas. In 2014, we plan to invest $1,230.0 million in our operations (excluding acquisitions) as follows:

 

•

$430.0 million for drilling and completion in the Marcellus Shale;

 

•

$150.0 million for drilling and completion in the Utica Shale;

 

•

$385.0 million for leasehold acquisitions; and

 

•

$265.0 million for midstream infrastructure development.

This represents a 96% increase over our $629.0 million pro forma 2013 capital expenditures. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity.” The following table provides a summary of our net acreage, average working interest, producing wells and projected 2014 net wells online as of June 30, 2014:

 

		Net Acreage				Average Working Interest				Producing Wells								2014 Projected Net Wells Online
										Gross				Net
Marcellus Shale(1)			53,834				95	%			51				47				34
Utica Shale			50,772				96	%			1				1				5	(2)
Upper Devonian Shale(3)			—				—				3				3				—
Total(3)			104,606				—				55				51				39

 

(1)	Excludes non-strategic properties consisting of 548 net acres in Fayette and Tioga Counties, Pennsylvania. Includes 1,338 net acres that were included as a leasehold payable on our balance sheet as of June 30, 2014.

(2)	Includes wells to be drilled by Gulfport Energy Corporation. Please see “—Our Properties—Utica Shale—Development Agreement and Area of Mutual Interest Agreement.”

(3)	Approximately 39,020 gross (36,932 net) acres in the Marcellus Shale is also prospective for the Upper Devonian Shale. The Upper Devonian and the Marcellus Shale are stacked formations within the same geographic footprint.

Our Properties

The Appalachian Basin, which covers over 185,000 square miles in portions of Kentucky, Tennessee, Virginia, West Virginia, Ohio, Pennsylvania and New York, is considered a highly attractive energy resource producing region with a long history of oil, natural gas and coal production. More importantly, the Appalachian Basin is strategically located near the high energy demand markets of the northeast United States, which has historically resulted in higher realized sales prices due to the reduced transportation costs a purchaser must incur to transport commodities to end users. Over the past five years, the focus of many producers has shifted from the younger, shallower conventional sandstone and carbonate reservoirs to the older, deeper Marcellus Shale and the newly emerging Utica Shale plays, which has driven Appalachian basin production growth.

Marcellus Shale

The Devonian-aged Marcellus Shale is an unconventional reservoir that produces natural gas, NGLs and oil and is the largest unconventional natural gas field in the U.S. The productive limits of the Marcellus Shale cover over 90,000 square miles within Pennsylvania, West Virginia, Ohio and New York. The Marcellus Shale is a black, organic-rich shale deposit generally productive at depths between 6,000 to 10,000 feet. Production from the brittle, natural gas-charged shale reservoir is best derived from hydraulically fractured horizontal wellbores that exceed 2,000 feet in lateral length and involve multi-stage fracture stimulations.

In addition, we believe substantially all of our acreage is prospective for the Upper Devonian Shale, which is a black, organic rich shale comprised of the Geneseo Shale, Middlesex Shale and Rhinestreet Shale and is at shallower depths than the Marcellus Shale formation. In Washington and Greene Counties, Pennsylvania, the

 

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Upper Devonian Shale and Marcellus Shale are separated by the Tully Limestone which is approximately 30 feet thick in this area. We have drilled and completed three wells in the Upper Devonian Shale and confirmed the presence of the Upper Devonian Shale formation in each of our Marcellus Shale wells drilled as of June 30, 2014.

We have experienced virtually no geologic complexity in our drilling activities through December 31, 2013, which has resulted in a fairly predictable band of expected recoveries per 1,000 feet of lateral length on our wells. We completed 9 gross (9 net) horizontal Marcellus Shale wells in 2012 and 22 gross (19.9 net) horizontal Marcellus Shale wells in 2013. As of June 30, 2014, we had a total of 51 gross (47.2 net) producing wells in the Marcellus Shale.

For the quarter ended June 30, 2014, we had average pro forma net daily production of 241 MMcf/d. As of June 30, 2014, we had four rigs operating in the Marcellus Shale (two tophole rigs and two horizontal rigs) and two rigs operating in the Utica Shale (one tophole rig and one horizontal rig).

The following table provides a summary of our current gross and net acreage by county in Pennsylvania as of June 30, 2014.

 

County		Gross Acres				Net Acres
Core Southwestern Pennsylvania:
Washington			40,591				39,013
Greene			15,257				14,624
Allegheny			197				197
Total			56,045				53,834

 

(1)	Our other acreage within the Marcellus Shale is located in Fayette and Tioga Counties, Pennsylvania.

In December 2013, we sold all of our Lycoming County acreage (100% non-operated) and related assets to a third party in exchange for $7.0 million. There was no production or net proved reserves attributable to the interests sold. We incurred a loss of $4.2 million in the fourth quarter of 2013 as a result of this transaction.

Utica Shale

The Ordovician-aged Utica Shale is an unconventional reservoir underlying the Marcellus Shale. The productive limits of the Utica Shale cover over 80,000 square miles within Ohio, Pennsylvania, West Virginia and New York. The Utica Shale is an organic-rich continuous black shale, with most production occurring at vertical depths between 7,000 to 10,000 feet. To date, the rich and dry gas windows of the southern Utica Shale play with BTUs ranging from 1,050 to 1,250 have yielded the strongest well results. We estimate that approximately 20% of our Utica acreage is in this rich gas window, with BTUs ranging from 1,100 to 1,200, and the remaining 80% is in the dry gas window. The richest and thickest concentration of organic-carbon content is present within the Point Pleasant Shale layer of the Lower Utica formation. The Point Pleasant Shale is our primary targeted development play of the Utica Shale.

As of June 30, 2014, we owned 50,772 net acres in the core of the Utica Shale and expect to add to our sizeable land position. The proximity of our Utica acreage position to our operations in the Marcellus Shale allows us to capitalize on operating and midstream synergies.

 

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The following table provides a summary of our current gross and net acreage by county in Ohio as of June 30, 2014.

 

County		Gross Acres(1)				Net Acres
Belmont			48,281				48,281
Guernsey			3,899				1,727
Harrison			764				764
Total			52,944				50,772

 

(1)	Excludes Gulfport’s acreage covered by our Development Agreement and AMI Agreement.

In October 2013, we commenced drilling our initial Utica well, the Bigfoot 7H, in Belmont County, Ohio. In December 2013, after drilling approximately 1,200 feet of the lateral section within the Point Pleasant formation, the well unexpectedly began flowing gas with higher than anticipated bottomhole pressures. We employed certain steps, including increasing our drilling mud weight, that successfully controlled the gas flow. However, certain uncased sections in the vertical portions of the wellbore were compromised by the higher mud weight, which ultimately inhibited our efforts to stabilize the gas flow and pressures. We elected to plug the Bigfoot 7H in late December 2013 and drilled a new horizontal well adjacent to the Bigfoot 7H with reconfigured mud and intermediate casing designs to better manage higher anticipated pressures and gas flows. We wrote off approximately $8.1 million of exploratory costs associated with the drilling of the Bigfoot 7H in the fourth quarter of 2013.

On June 2, 2014, we announced the production test results of our first operated Utica Shale well, the Bigfoot 9H. After five days of flowback, the Bigfoot 9H stabilized at a rate of 41.7 MMcf/d of gas on a 33/64” choke with flowing casing pressures of 5850 psi. Based upon a gas composition analysis, the heat content is 1086 Btu and therefore will not require processing. We own an approximate 93% working interest in the well, which has an effective lateral length of 6,957 feet and was completed with 40 frac stages. First production from the Bigfoot 9H well was delivered into sales in late June 2014. In addition, in June 2014, we drilled and cased our second and third Utica Shale wells, the Blue Thunder 10H and 12H. We are in the process of completing both of these wells, each with lateral lengths of approximately 9,000 feet.

We believe that the production test results obtained on the Bigfoot 9H indicate a highly permeable and porous Point Pleasant formation. However, these pressures may not be an indicator of the production amounts to be expected from future Utica wells. In addition, we may experience further difficulties drilling and completing Utica wells. Please read “Risk Factors—Risks Related to Our Business—We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.”

Development Agreement and Area of Mutual Interest Agreement

On October 14, 2013, we entered into a Development Agreement and AMI Agreement with Gulfport covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. We refer to these agreements as our “Utica Development Agreements.” Pursuant to the Utica Development Agreements, we have an approximately 68.80% participating interest in the Northern Contract Area and an approximately 42.63% participating interest in the Southern Contract Area, each within Belmont County, Ohio. The remaining participating interests are held by Gulfport. The participating interests of us and Gulfport in each of the Northern and Southern Contract Areas approximate our current relative acreage positions in each area.

Pursuant to the Development Agreement, we are named the operator (or Gulfport will agree to vote in favor of our operatorship) of drilling units located in the Northern Contract Area, and Gulfport is named the operator (or we will agree to vote in favor of its operatorship) of drilling units located in the Southern Contract Area. Upon development of a well on the subject acreage, we and Gulfport will convey to one another, pursuant to a

 

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cross conveyance, a working interest percentage equal to the amount of the underlying working interest multiplied by the applicable participating interest. For example, upon development of a well:

 

•

Assuming an aggregate 90% working interest is held by us and/or Gulfport in the Northern Contract Area, we and Gulfport will make cross conveyances to one another such that we hold an approximately 61.92% working interest (representing 68.80% of 90%) and Gulfport holds an approximately 28.08% (representing 31.20% of 90%) working interest in the drilling unit; and

 

•

Assuming an aggregate 90% working interest is held by us and/or Gulfport in the Southern Contract Area, we and Gulfport will make cross conveyances to one another such that we hold an approximate 38.37% working interest (representing 42.63% of 90%) and Gulfport holds an approximate 51.63% (representing 57.37% of 90%) working interest in the drilling unit.

As a result of the Development Agreement, as of December 31, 2013, we are the operator of approximately 27,000 aggregate net acres in the Northern Contract Area, and Gulfport is the operator of approximately 23,000 aggregate net acres in the Southern Contract Area. In addition, as wells are developed in the respective contract area, our average working interests in the Utica Shale will decrease as the applicable participating interests are applied to the developed wells.

Each quarter during the term of the Development Agreement, we and Gulfport will establish a work program and budget detailing the proposed exploration and development to be performed in the Northern and Southern Contract Areas, respectively, for the following year. The number of horizontal wells proposed to be drilled in each of the Northern Contract Area and Southern Contract Area is limited by the Development Agreement as follows: in 2014, between eight and 40 wells; in 2015, between eight and 50 wells; and thereafter, unlimited.

Pursuant to the AMI Agreement, each party has the right to participate at the level of its applicable participating interest in any acquisition by the other party of working interests or leases acquired within the AMIs. Unless a party elects not to participate therein upon notice by the other party, the subject working interest or lease will be governed by the Development Agreement.

The Utica Development Agreements have terms of ten years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint operating agreement and we and Gulfport shall remain operators of drilling units located in the Northern Contract Area and Southern Contract Area, respectively, following such termination.

Midstream Operations

Our exploration and development activities are supported by our operated natural gas low- and high-pressure gathering, compression and transportation assets, as well as by third-party arrangements. Unlike many producing basins in the United States, certain portions of the Appalachian Basin do not have sufficient midstream infrastructure to support the existing and expected increasing levels of production. Actively managing these midstream operations enhances our ability to obtain the necessary takeaway capacity for our production.

We maintain a strong commitment to developing the necessary midstream infrastructure to support our drilling schedule and production growth. We seek to accomplish this goal through a combination of internal asset developments and contractual relationships with third-party midstream service providers. We have invested in building low- and high-pressure gathering lines and water pipeline systems. We will continue to invest in our midstream infrastructure, as it allows us to optimize our gathering and takeaway capacity to support our expected-production growth, affords us more control over the direction and planning of our drilling schedule and has historically lowered our operating costs. In 2014, we estimate we will spend a total of approximately $265.0 million on midstream infrastructure development (excluding amounts paid in connection with our acquisition of certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania which was completed on April 17, 2014).

 

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As of December 31, 2013, we owned and operated 27 miles of high-pressure gathering pipelines on our Marcellus Shale acreage in Washington County, Pennsylvania. Due to the high flow rates and flowing tubing pressures experienced with our Marcellus wells, none of our wells requires nor utilizes artificial lift or compression.

Our midstream infrastructure in Pennsylvania also includes 33 miles of high-density polyethylene pipelines connected to multiple freshwater impoundments for transporting water to our well completion operations. We commenced construction of this system in 2010 and first utilized the system during the completion of our second horizontal Marcellus well. Since then, we have continued to expand this system and, as of December 31, 2013, this system has been utilized for the completion on substantially all of our Marcellus wells. We will continue to expand this system as our well development progresses. This system delivers year-round water supply, lessens water handling costs and decreases water truck traffic on local roadways. The cost savings associated with sourcing our water through this system, when compared to wells completed with water sourced only by truck, is approximately $500,000 per horizontal well.

On February 12, 2014, we entered into a purchase and sale agreement with M3 to acquire certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania, for aggregate consideration of approximately $110.0 million in cash. Please see Note 16 to the Consolidated Financial Statements included herein.

Transportation and Takeaway Capacity

As of June 30, 2014, our average annual contractual firm transportation and firm sales obligations for 2014 (July through December), 2015 and 2016 were approximately 450,000 MMBtu/d, 810,000 MMBtu/d, and 920,000 MMBtu/d, respectively, which are in excess of our pro forma average daily gross operated production of approximately 380,000 MMBtu/d for June 2014. These amounts include approximately 115,000 MMBtu/d of firm sales contracted with a third party through October 2017, subject to annual renewal. Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. We continue to actively identify and evaluate additional takeaway capacity to facilitate production growth in our Appalachian Basin position.

Business Strategies

Our objective is to create shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We seek to achieve this objective by executing the following strategies:

 

•

Pursue High-Graded Core Shale Acreage as an Early Entrant. Our acreage acquisition strategy has been predicated on our belief that core acreage provides superior production, ultimate recoveries and returns on investment. We leverage our technical expertise and analyze third-party data to be an early entrant into the core of a shale play. We develop an internally generated geologic model and then study publicly available third-party data, including well results and drilling and completion reports, to confirm our geologic model and define the core acreage position of a play. Once we believe that we have identified the core location, we aggressively execute on our acquisition strategy to establish a largely contiguous acreage position. By virtue of this strategy, we eliminate the need for large exploration programs requiring significant time and capital, and instead pursue areas that have been substantially de-risked, or high-graded, by our competitors. We have applied the expertise and approach that we employed in the Marcellus Shale to the Utica Shale, and we believe we will be able to achieve similar results.

 

•

Target Contiguous Acreage Positions in Prolific Unconventional Resource Plays. We will seek to continue to expand on our success in targeting contiguous acreage positions within the core of the Marcellus and Utica Shales. We believe a concentrated acreage position requires fewer wells and

 

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inherently less capital to define the geologic properties across the play and allows us to optimize our wellbore economics. As of June 30, 2014, we had drilled and completed 51 horizontal Marcellus wells, several of which have tested the outer boundaries of our Marcellus acreage position. Additionally, as a result of optimizing our wellbore design with a limited number of wells, we believe our ability to transition from exploration drilling to development drilling in the Marcellus Shale was accomplished with less capital invested than our peers. We intend to replicate this strategy in the Utica Shale.

 

•

Aggressively Develop Leasehold Positions to Economically Grow Production, Cash Flow and Reserves. We intend to continue to aggressively drill and develop our portfolio of drilling locations with a goal of growing production, cash flow and reserves in an economically-efficient manner. In the first quarter of 2014, we increased to a six-rig drilling program (consisting of three tophole rigs and three horizontal rigs). In the second quarter of 2014, we averaged three horizontal rigs. We expect to continue to operate a six-rig drilling program through the remainder of 2014. In executing our development strategy, we intend to leverage our operational control and the expertise of our technical team to deliver attractive production and cash flow growth. As the operator of a substantial majority of our acreage in the Marcellus and Utica Shales, we are able to manage (i) the timing and level of our capital spending, (ii) our exploration and development drilling strategies and (iii) our operating costs. We will seek to optimize our wellbore economics through a meticulous focus on rig efficiency, wellbore accuracy and completion design and execution. We believe that the combination of our operational control and technical expertise will allow us to build on our track record of superior production, cash flow and reserve growth.

 

•

Maximize Pipeline Takeaway Capacity to Facilitate Production Growth. We maintain a strong commitment to construct, acquire and control the midstream infrastructure necessary to meet our production growth. We will also continue to enter into long-term firm transportation arrangements with third party midstream operators to ensure our access to market. We believe our commitment to midstream infrastructure allows us to commercialize our production more quickly and provides us with a competitive advantage in acquiring bolt-on acreage.

Competitive Strengths

We possess a number of competitive strengths that we believe will allow us to successfully execute our business strategies:

 

•

Large, Contiguous Positions Concentrated in the Core of the Marcellus and Utica Shales. We own extensive and contiguous acreage positions in the core of two of the premier North American shale plays. We believe we were an early identifier of both the Marcellus Shale core in southwestern Pennsylvania and the Utica Shale core, primarily in Belmont County, Ohio, which allowed us to acquire concentrated acreage positions. Our core position and contiguous acreage in the Marcellus Shale have allowed us to delineate our position as well as produce industry-leading well results, as our wells have some of the highest initial production rates and EURs in the Marcellus Shale. Through a consolidated approach, we are able to increase rig efficiency, turning wells into sales faster, and de-risk our acreage position more efficiently. Additionally, to service our concentrated acreage positions, we construct and acquire water and midstream infrastructure, which enable us to reduce reliance on third party operators, minimize costs and increase our returns. This has been a strength in the Marcellus Shale and we believe our position in the Utica Shale will allow us to achieve similar results.

 

•

Expertise in Unconventional Resource Plays and Technology. We have assembled a strong technical staff of shale petroleum engineers and shale geologists that have extensive experience in horizontal drilling, operating multi-rig development programs and using advanced drilling technology. We have been early adopters of new oilfield services and techniques for drilling (including rotary steerable tools) and completions (including reduced-length frac stages). In the Marcellus Shale as of June 30, 2014, we have completed 51 gross horizontal wells totaling approximately 320,000 lateral feet. We have realized improvements in our drilling efficiency over time and we are now drilling lateral sections

 

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approximately 50% longer in approximately half the time as it has taken us historically. Our average horizontal lateral drilled in 2011 was 4,733 feet and took 13.0 days to drill from kickoff to total depth. Our average horizontal lateral drilled in 2013 was 7,700 feet and took 5.8 days to drill from kickoff to total depth. Our operating proficiency has also led to increased wellbore accuracy, completion design efficiencies and has yielded top tier production results as reflected in the fact that out of approximately 550 producing horizontal Marcellus Shale wells in Washington County, Pennsylvania, we drilled and completed the top two and four of the top six wells in terms of cumulative production through June 30, 2013, as reported by Pennsylvania’s oil and gas department. Further, we are able to enhance our wellbore economics through multi-well pad drilling (one to nine wells per rig move) and long laterals targeting 6,000 to 10,000 feet.

 

•

Successful Infill Leasing Program. We have increased our acreage position in the core of the Marcellus Shale through bolt-on leases in the same targeted area. This strategy has allowed us to acquire acreage that provides additional drilling locations and/or adds horizontal feet to future wells. By implementing this strategy, we have grown our Marcellus Shale acreage position from our initial acquisition of 642 net acres in 2009 to 53,834 net acres as of June 30, 2014. We have replicated this strategy successfully in the Utica Shale in Belmont County as well, leasing an additional 17,273 net acres as of June 30, 2014 since our initial acquisition of approximately 33,499 net acres in November 2012. We intend to continue to focus our near-term leasing program on Greene and Washington Counties in Pennsylvania and on Belmont County in Ohio, with the strategy of using bolt-on leases to acquire acreage that immediately increases our drilling locations and/or drillable horizontal feet.

 

•

Access to Committed Takeaway Capacity. Our gas gathering pipeline system is currently designed to handle up to approximately 2 Bcf/d in the aggregate and, as of June 30, 2014, has an operating capacity of approximately 1 Bcf/d in the aggregate. This system connects our producing wells to multiple interstate transmission and other third-party pipelines. We plan to continue to build out our Pennsylvania gathering system congruent with our future development plans. We plan to replicate our strategy of constructing and controlling our own midstream system in Ohio and expect to have our gathering system in Belmont County substantially complete by the second quarter of 2015. We believe our commitment to constructing and controlling midstream assets allows us to efficiently bring wells online, mitigates the risk of unplanned shut-ins and creates pricing and transportation optionality by connecting to multiple interstate pipelines. To further ensure the deliverability of our Utica Shale production, we have entered into a precedent agreement for 175,000 dth/d firm transportation on the Rockies Express Pipeline beginning in June 2015 for a term of 20 years, which will provide us with greater access to Gulf Coast and Midwest markets. With this capacity, our firm transportation and firm sales portfolio will cover approximately 810,000 MMBtu/d in 2015 and 920,000 MMBtu/d in 2016. By securing firm transportation and firm sales contracts, we are better able to accommodate our growing production and manage basis differentials.

 

•

Significant Liquidity and Active Hedging Program. As of June 30, 2014, we had cash on hand of approximately $471.5 million, of which we used approximately $329 million to fund the purchase price of our recently completed Greene County Acquisition described under “Recent Developments,” and as of August 1, 2014, we had availability under our revolving credit facility of approximately $313.4 million. We believe this liquidity, along with our cash flow from operations and the proceeds of this offering, is sufficient to execute our current capital program. Additionally, our hedging program mitigates commodity price volatility and protects our future cash flows. We review our hedge position on an ongoing basis, taking into account our current and forecasted production volumes and commodity prices. As of August 11, 2014, we had entered into hedging contracts covering approximately 41 Bcf (224 MMcf/d) of natural gas production for June 2014 through December 2014 at a weighted average index floor price of $4.06 per MMBtu. Furthermore, as of August 11, 2014, we had entered into hedging contracts covering approximately 84 Bcf (231 MMcf/d) of natural gas production for 2015 at a weighted average index floor price of $4.04 per MMBtu.

 

 

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•

Proven and Stockholder-Aligned Management Team. Our management team possesses extensive oil and natural gas acquisition, exploration and development expertise in shale plays. For a discussion of our management’s experience, please read “Management.” Our Chief Executive Officer, Chief Operating Officer, Vice President of Exploration & Geology and Vice President of Drilling have worked for us since we drilled our first horizontal Marcellus well. Our management team includes certain members of the Rice family who, along with other members of the management team, are also highly aligned with stockholders through a 31.3% economic interest in us after giving effect to this offering. In addition, our management team has a significant indirect economic interest in us through their ownership of incentive units in the form of interests in Rice Holdings and NGP Holdings. The value of these incentive units may increase over time, without diluting public investors, if our stock price appreciates in the future. For additional information regarding our incentive units, please read “Executive Compensation—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year—Long-Term Incentive Compensation.” We believe that our management team’s direct and indirect ownership interest in us will provide significant incentives to grow the value of our business.

Initial Public Offering, Corporate Reorganization and Related Transactions

Initial Public Offering

On January 29, 2014, we completed our initial public offering (“IPO”) of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by us, 14,000,000 shares sold by NGP Holdings, the selling stockholder in our IPO and 6,000,000 shares subject to an option granted to the underwriters by the selling stockholder.

The net proceeds of our IPO, based on the public offering price of $21.00 per share, were approximately $993.5 million, which resulted in net proceeds to us of $593.6 million after deducting expenses and underwriting discounts and commissions of approximately $36.4 million and net proceeds to the selling stockholder of approximately $399.0 million after deducting underwriting discounts of approximately $21.0 million. We did not receive any proceeds from the sale of the shares by the selling stockholder. A portion of the net proceeds from our IPO were used to repay all outstanding borrowings under the revolving credit facility of our Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In and to repay all outstanding borrowings under our revolving credit facility. The remainder of the net proceeds from our IPO are being used to fund a portion of our capital expenditure plan.

Corporate Reorganization

A corporate reorganization occurred concurrently with the completion of our IPO on January 29, 2014. As a part of this corporate reorganization, we acquired all of the outstanding membership interests in Rice Appalachia in exchange for shares of our common stock. Our business continues to be conducted through Rice Drilling B, as a wholly owned subsidiary. As of January 29, 2014, upon (a) the completion of the IPO, (b) the issuance of (i) 43,452,550 shares of common stock to NGP Holdings, (ii) 20,300,923 shares of common stock to Rice Holdings, (iii) 2,356,844 shares of common stock to Daniel J. Rice III, (iv) 20,000,000 shares of common stock to Rice Partners, (v) 160,831 shares of common stock to the persons holding incentive units representing interests in Rice Appalachia and (vi) 1,728,852 shares of common stock to the members of Rice Drilling B (other than Rice Appalachia), each of which were issued by us in connection with the closing of the IPO, and (c) the issuance of 9,523,810 shares of common stock to Alpha Holdings in connection with the completion of the Marcellus JV Buy-In described below under “—Marcellus JV Buy-In,” we had 127,523,810 shares of common stock outstanding.

Marcellus JV Buy-In

On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between us and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), we completed our

 

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acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture in exchange for total consideration of $322 million, consisting of $100 million of cash and our issuance to Alpha Holdings of 9,523,810 shares of our common stock.

Our Operations

Reserve Data

The information with respect to our estimated reserves presented below has been prepared in accordance with the rules and regulations of the SEC.

Reserves Presentation

Our estimated proved reserves and PV-10 as of December 31, 2013 and 2012 are based on evaluations prepared by our independent reserve engineers, NSAI. Copies of the summary reports of NSAI with respect to our reserves as of December 31, 2013 are filed as exhibits to this prospectus. See “—Preparation of Reserve Estimates” for definitions of proved reserves and the technologies and economic data used in their estimation.

The following table summarizes our historical and pro forma estimated proved reserves and related PV-10 at December 31, 2013 and 2012.

 

		Natural Gas
		Estimated Net Reserves (Bcf)(1)
		As of December 31, 2013												As of December 31, 2012
		Rice Energy Inc. Pro Forma				Rice Energy Inc.				Marcellus Joint Venture(2)				Rice Energy Inc. Pro Forma				Rice Energy Inc.				Marcellus Joint Venture(2)
Estimated Proved Reserves:
Total proved reserves			602				382				110				561				304				128
Total proved developed reserves			250				144				53				131				61				35
Total proved developed producing reserves			177				91				43				101				57				22
Total proved developed non-producing reserves			73				53				10				30				4				13
Total proved undeveloped reserves			352				238				57				430				243				93
Percent proved developed			42	%			38	%			48	%			23	%			20	%			27	%
PV-10 of proved reserves (in millions)(3)		$	709			$	417			$	146			$	245			$	102			$	71

 

(1)

Our historical and pro forma estimated proved reserves, PV-10 and standardized measure were determined using a 12-month average price for natural gas. The prices used in our reserve reports yield weighted average wellhead prices, which are based on index prices and adjusted for energy content, transportation fees and regional price differentials. The index prices and the equivalent wellhead prices are shown in the table below.

 

		Index Prices Natural Gas (per MMBtu)												Weighted Average Wellhead Prices— Natural Gas (per Mcf)
		Rice Energy Inc. Pro Forma				Rice Energy Inc.				Marcellus Joint Venture				Rice Energy Inc. Pro Forma				Rice Energy Inc.				Marcellus Joint Venture
December 31, 2013			3.67				3.67				3.67				3.90				3.91				3.90
December 31, 2012			2.76				2.76				2.76				2.85				2.86				2.84

 

(2)	Amounts presented for our Marcellus joint venture give effect to our 50% equity investment in our Marcellus joint venture.

 

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(3)

PV-10 is a non-GAAP financial measure and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. However, the respective historical PV-10s and standardized measures of us and our Marcellus joint venture are equivalent because as of December 31, 2013 and 2012, we and our Marcellus joint venture were not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to our respective equity holders. However, in connection with the closing of our IPO, as a result of our corporate reorganization, we became subject to federal income tax and, as such, our future income taxes will be dependent upon our future taxable income. We estimate that our pro forma standardized measure, our historical standardized measure and the historical standardized measure for our Marcellus joint venture as of December 31, 2013, would have been approximately $444 million, $269 million and $175 million, respectively, as adjusted to give effect to the present value of approximately $265 million, $148 million and $117 million, respectively, of future income taxes as a result of our being treated as a corporation for federal income tax purposes. We estimate that our pro forma standardized measure, our historical standardized measure and the historical standardized measure for our Marcellus joint venture as of December 31, 2012, would have been approximately $163 million, $67 million and $96 million, respectively, as adjusted to give effect to the present value of approximately $84 million, $37 million and $47 million, respectively, of future income taxes as a result of our being treated as a corporation for federal income tax purposes. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

Proved Undeveloped Reserves

Proved undeveloped reserves are included in the previous table of total proved reserves. The following table summarizes the changes in the estimated historical and pro forma proved undeveloped reserves of us and our Marcellus joint venture during 2013 and 2012 (in MMcf):

 

		Rice Energy Inc. Pro Forma				Rice Energy Inc.				Marcellus joint venture(1)
Proved undeveloped reserves, December 31, 2011			294,857				207,599				43,629
Conversions into proved developed reserves			(33,908	)			(15,120	)			(9,394	)
Extensions			330,851				164,561				83,145
Price revisions			(162,543	)			(113,993	)			(24,275	)
Proved undeveloped reserves, December 31, 2012			429,257				243,047				93,105
Conversions into proved developed reserves			(156,136	)			(79,266	)			(38,435	)
Extensions			105,366				65,744				19,811
Price revisions			(25,510	)			8,826				(17,168	)
Proved undeveloped reserves, December 31, 2013			352,977				238,351				57,313

 

(1)	Amounts presented for our Marcellus joint venture give effect to our 50% equity investment in our Marcellus joint venture.

During 2013, on a pro forma basis, extensions, discoveries, and other additions of 105,366 MMcf proved undeveloped reserves were added through the drillbit in the Marcellus Shale. The negative revision was primarily due to four Marcellus joint venture wells being removed from our current development plan. During 2012, on a pro forma basis, extensions, discoveries, and other additions of 330,851 MMcf proved undeveloped reserves were added through the drillbit in the Marcellus Shale. Downward price revisions resulted in a reduction of proved undeveloped reserves by 162,543 MMcf.

During 2013, on a pro forma basis, we incurred costs of approximately $156.0 million to convert 156,136 MMcf of proved undeveloped reserves to proved developed reserves. During 2012, on a pro forma basis, we

 

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incurred costs of approximately $36.0 million to convert 33,908 MMcf of proved undeveloped reserves to proved developed reserves. Estimated future development costs relating to the development of our proved undeveloped reserves as of December 31, 2013 on a pro forma basis are approximately $313.0 million over the next five years, which we expect to finance through proceeds from our IPO, cash flow from operations, borrowings under our revolving credit facility and other sources of capital financing. Our drilling programs are focused on proving our undeveloped leasehold acreage through delineation drilling. While we will continue to drill leasehold delineation wells and build on our current leasehold position, we will also focus on drilling our proved undeveloped reserves. Based on our reserve reports as of December 31, 2013, we had 44 gross (39 net) pro forma locations in the Marcellus Shale associated with proved undeveloped reserves and 13 gross (12 net) locations in the Marcellus Shale associated with proved developed not producing reserves. All of our proved undeveloped reserves are expected to be developed over the next five years. See “Risk Factors—Risks Related to Our Business—The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”

Preparation of Reserve Estimates

Our pro forma reserve estimates as of December 31, 2013 and 2012 included in this prospectus were based on evaluations prepared by the independent petroleum engineering firm of NSAI in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. Our independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources.

Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. Our independent reserve engineers use this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis and analogy. The proved developed reserves and EURs per well are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves and EURs for each developed well are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy). Proved undeveloped locations that are more than one offset from a proved developed well utilized reliable technologies to confirm reasonable certainty. The reliable technologies that were utilized in estimating these reserves include log data, performance data, log cross sections, seismic data, core data, and statistical analysis.

Internal Controls

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to NSAI in their reserves estimation process. Ryan I. Kanto, our Vice President of Operations, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has substantial industry experience with positions of increasing responsibility in engineering and evaluations. Throughout each fiscal year, our technical team meets with representatives of our independent reserve engineers to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, a preliminary

 

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copy of the reserve report is reviewed by our senior management with representatives of our independent reserve engineers and internal technical staff.

Qualifications of Responsible Technical Persons

Ryan I. Kanto joined Rice Energy in June 2011 and serves as our Vice President of Operations. Prior to Rice Energy, Mr. Kanto worked at EnCana Oil & Gas (USA) Inc. from June 2007 to May 2011. During this time he served as a facilities engineer in the Deep Bossier from June 2007 to January 2008, a reservoir engineer in the Barnett Shale until February 2009, and completion engineer in the Haynesville Shale until his departure. Mr. Kanto has bachelors degrees in Chemical Engineering and Engineering Management from the University of Arizona and has significant experience in unconventional shale gas plays.

Our proved reserve estimates shown herein at December 31, 2013 and 2012 and the proved reserve estimates shown herein for our Marcellus joint venture have been independently prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI letters, each of which is filed as an exhibit to this registration statement, was Richard B. Talley, Jr., Vice President, Team Leader, and a consulting petroleum engineer. Mr. Talley is a Registered Professional Engineer in the State of Texas (License No. 102425). Mr. Talley joined NSAI in 2004 after serving as a Senior Engineer at ExxonMobil Production Company. Mr. Talley’s areas of specific expertise include probabilistic assessment of exploration prospects and new discoveries, estimation of oil and gas reserves, and workovers and completions. Mr. Talley received an MBA degree from Tulane University in 2001 and a BS degree in Mechanical Engineering from University of Oklahoma in 1998. Mr. Talley meets or exceeds the education, training and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

Production, Revenues and Price History

Natural gas, NGLs, and oil are commodities; therefore, the price that we receive for our production is largely a function of market supply and demand. While demand for natural gas in the United States has increased dramatically since 2000, natural gas and NGL supplies have also increased significantly as a result of horizontal drilling and fracture stimulation technologies which have been used to find and recover large amounts of oil and natural gas from various shale formations throughout the United States. Demand is impacted by general economic conditions, weather and other seasonal conditions. Over or under supply of natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of natural gas reserves that may be economically produced and our ability to access capital markets. See “Risk Factors—Risks Related to Our Business—Natural gas, NGL and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

 

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The following table sets forth information regarding production, revenues and realized prices and production costs on a historical basis for the years ended December 31, 2013, 2012 and 2011, for us and our Marcellus joint venture on a standalone basis and on a pro forma basis for the year ended December 31, 2013. Amounts shown for our Marcellus joint venture give effect to the 50% equity investment we held therein as of December 31, 2013. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

		For the Year Ended December 31,
		2013				2012				2011
Natural gas sales (in thousands):
Pro Forma Rice Energy Inc.		$	178,525
Rice Energy Inc.			87,847			$	26,743			$	13,972
Marcellus joint venture			45,339				13,142				2,872
Production data (MMcf):
Pro Forma Rice Energy Inc.			45,881
Rice Energy Inc.			22,995				8,769				3,392
Marcellus joint venture			11,443				4,296				697
Average prices before effects of hedges per Mcf:
Pro Forma Rice Energy Inc.		$	3.89
Rice Energy Inc.			3.82			$	3.05			$	4.12
Marcellus joint venture			3.96				3.06				4.12
Average realized prices after effects of hedges per Mcf(1):
Pro Forma Rice Energy Inc.		$	4.01
Rice Energy Inc.			3.85			$	3.15			$	4.29
Marcellus joint venture			4.16				3.07				4.12
Average costs per Mcf(2):
Pro Forma Rice Energy Inc.:
Lease operating		$	0.36
Gathering, compression and transportation			0.55
General and administrative			0.44
Depletion, depreciation and amortization			1.57
Rice Energy Inc.:
Lease operating		$	0.36			$	0.42			$	0.48
Gathering, compression and transportation			0.43				0.43				0.16
General and administrative			0.74				0.87				1.54
Depletion, depreciation and amortization			1.43				1.61				1.76
Marcellus joint venture:
Lease operating		$	0.36			$	0.39			$	0.51
Gathering, compression and transportation			0.68				0.78				0.04
General and administrative			0.14				0.24				0.26
Depletion, depreciation and amortization			1.09				1.10				1.57

 

(1)	The effect of hedges includes realized gains and losses on commodity derivative transactions.

(2)	Does not include production taxes and impact fees. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Principal Components of our Cost Structure.”

Productive Wells

As of June 30, 2014, we had a total of 55 gross (51 net) operated wells producing gas in Pennsylvania and Ohio. In addition, as of June 30, 2014, we had 3 gross (0 net) non-operated wells producing gas, oil and NGLs in Ohio.

 

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Acreage

The following table sets forth certain information regarding the total developed and undeveloped acreage in which we owned an interest as of June 30, 2014. Approximately 45% of our Marcellus acreage and none of our Utica acreage was held by production at June 30, 2014. Acreage related to royalty, overriding royalty and other similar interests is excluded from this table.

 

		Developed Acres								Undeveloped Acres								Total Acres
Basin		Gross				Net				Gross				Net				Gross				Net
Marcellus			5,619				5,056				50,426				48,778				56,045				53,834
Utica			129				120				52,815				50,652				52,944				50,772
Total			5,748				5,176				103,241				99,430				108,989				104,606

Undeveloped Acreage Expirations

The following table sets forth the number of total undeveloped acres as of June 30, 2014 that will expire in 2014, 2015, 2016, 2017 and 2018 and thereafter unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed. We have not attributed any PUD reserves to acreage for which the expiration date precedes the scheduled date for PUD drilling. In addition, we do not anticipate material delay rental or lease extension payments in connection with such acreage.

 

Basin		2014				2015				2016				2017				2018+
Marcellus—Southwestern Pennsylvania Core			1,054				2,365				2,485				2,622				21,073
Utica			—				—				397				33,017				17,357
Total			1,054				2,365				2,882				35,639				38,430

Drilling Activity

The following table describes our drilling activity on our acreage during the years ended December 31, 2013, 2012 and 2011 on a pro forma basis:

 

		Productive Wells								Dry Wells								Total
		Gross				Net				Gross				Net				Gross				Net
2013			23.0				20.9				—				—				23.0				20.9
2012			10.0				10.0				—				—				10.0				10.0
2011			6.0				5.5				—				—				6.0				5.5

During 2013, we began drilling our Bigfoot 7H well, our first exploratory well in the Utica Shale. Please see “—Our Properties—Utica Shale.” We drilled no exploratory wells during 2012 or 2011.

Major Customers

For the year ended December 31, 2013, sales to Sequent and Dominion represented 94% and 6% of our total sales, respectively, on a pro forma basis. For the year ended December 31, 2012, sales to Sequent accounted for 100% of our total sales. Although a substantial portion of production is purchased by these major customers, we do not believe the loss of one or both customers would have a material adverse effect on our business, as other customers or markets would be accessible to us. However, if we lose one or both of these customers, there is no guarantee that we will be able to enter into an agreement with a new customer which is as favorable as our current agreements.

 

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Title to Properties

In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment subject to title verification. In most cases, we incur the expense of retaining lawyers to verify the rightful owners of the oil and gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to its lease’s oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Investigations are made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

 

•

customary royalty interests;

 

•

liens incident to operating agreements and for current taxes;

 

•

obligations or duties under applicable laws;

 

•

development obligations under natural gas leases; or

 

•

net profits interests.

Seasonality

Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do. Many of these companies not only explore for and produce natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing natural gas properties.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing natural gas and oil properties have statutory provisions regulating the exploration for and production of natural gas and oil,

 

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including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production of Natural Gas and Oil

The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

We own interests in properties located onshore in two U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas transportation

 

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rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services.

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act (“NGPA”), and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the NGA, and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

Beginning in 1992, FERC issued a series of orders to implement its open access policies. As a result, the interstate pipelines’ traditional role as wholesalers of natural gas has been greatly reduced and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

The EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EPAct 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EPAct 2005. The rules make it unlawful: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704.

On December 26, 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

 

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We cannot accurately predict whether FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

Our sales of natural gas are also subject to requirements under the Commodity Exchange Act (“CEA”), and regulations promulgated thereunder by the CFTC. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Regulation of Pipeline Safety and Maintenance

We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), of the Department of Transportation (the “DOT”_, pursuant to the Natural Gas Pipeline Safety Act of 1968 (the “NGPSA”), and the Pipeline Safety Improvement Act of 2002 (the “PSIA”), which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that

 

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require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “Pipeline Safety Act”), was signed into law. In addition to reauthorizing the PSIA through 2015, the Pipeline Safety Act expanded the DOT’s authority under the PSIA and requires the DOT to evaluate whether integrity management programs should be expanded beyond high consequence areas, authorizes the DOT to promulgate regulations requiring the use of automatic and remote-controlled shut-off valves for new or replaced pipelines, and requires the DOT to promulgate regulations requiring the use of excess flow values where feasible. Any new or amended pipeline safety regulations may require us to incur additional capital expenditures and may increase our operating costs. We cannot predict what future action the DOT will take, but we do not believe that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas gatherers with which we compete.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep facilities in compliance with pipeline safety requirements.

Regulation of Environmental and Occupational Safety and Health Matters

General

Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Clean Water Act (“CWA”) and the Clean Air Act (“CAA”). These laws and regulations govern environmental cleanup standards, require permits for air emissions, water discharges, underground injection, solid and hazardous waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Public and regulatory scrutiny of the energy industry has resulted in increased environmental regulation and enforcement being either proposed or implemented. For example, EPA’s 2014—2016 National Enforcement Initiatives include “Assuring Energy Extraction Sector Compliance with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” The EPA has emphasized that this initiative will be focused on those areas of the country where energy extraction activities are concentrated, and the focus and nature of the enforcement

 

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activities will vary with the type of activity and the related pollution problem presented. This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive or declaratory relief. Accidental releases or spills may occur in the course of our operations, and we cannot be sure that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.

Hazardous Substances and Wastes

CERCLA, also known as “Superfund,” imposes joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be potentially responsible for the release of a “hazardous substance” into the environment. These persons include the current and past owners or operators of the site or sites where the release occurred, and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA and any state analogs, such as Pennsylvania’s Hazardous Sites Cleanup Act, may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for the costs of certain health studies and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. While petroleum and crude oil fractions are not considered hazardous substances under CERCLA and its analogs because of the so-called “petroleum exclusion,” adulterated petroleum products containing other hazardous substances have been treated as hazardous substances in the past, and governmental agencies or third parties may seek to hold us responsible for all or part of the costs to clean up sites at which such hazardous substances have been deposited.

RCRA and analogous state laws and regulations regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” Instead, these wastes are regulated under RCRA’s less stringent non-hazardous solid waste provisions, state laws or other federal laws. However, legislation has been proposed from time to time that could reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general. Moreover, some ordinary industrial wastes which we generate, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous wastes.

In addition, current and future regulations governing the handling and disposal of Naturally Occurring Radioactive Materials (“NORM”) may affect our operations. For example, the Pennsylvania Department of Environmental Protection has asked operators to identify technologically enhanced NORM (“TENORM”) in their processes, such as hydraulic fracturing sand. Local landfills only accept such waste when it meets their TENORM permit standards. Similarly, the Ohio Department of Health and the Ohio Environmental Protection Agency regulate the disposal of TENORM in Ohio. As a result, we may have to locate out-of-state landfills to accept TENORM waste from time to time, potentially increasing our disposal costs.

Some of our leases may have had prior owners who commenced exploration and production of natural gas and oil operations on these sites. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the

 

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properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties may have been operated by third parties whose waste management and disposal practices were not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA, and/or analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

Regulation of Well Completion and Stimulation

Hydraulic fracturing and similar techniques are important and common practices we use to stimulate production of oil and gas. Hydraulic fracturing involves the injection of water, sand and trace chemicals under pressure into underground oil and gas bearing rock formations to create or enlarge fractures and stimulate the flow of oil and gas into the oil and gas production well. Although these stimulation techniques have been safely utilized for decades, numerous federal and state agencies and certain local governments seek to further regulate them.

In February 2014, the EPA asserted regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s (“SDWA”) Underground Injection Control (“UIC”) Program, and requested comments in May 2014 on a proposal to require disclosure of chemical ingredients in hydraulic fracturing fluids under the Toxic Substances Control Act. In May 2013, the Bureau of Land Management proposed rules governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used, confirmation that wells used in hydraulic fracturing operations meet defined construction standards, and development of plans for managing water that flows back to the surface. In addition, studies by EPA and other federal agencies are underway that focus on environmental aspects of hydraulic fracturing activities, with draft reports expected for public comment and peer review in late 2014. These studies could spur further regulation. Additional regulations adopted at the federal level could result in permitting delays and cost increases.

Waste Discharges

The CWA and its state analogs and regulations impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit or waiver issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Obtaining these permits may delay our development of oil and natural gas projects and associated facilities. The CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. In addition, federal spill prevention, control and countermeasure requirements require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and/or criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. The imposition of new or additional regulations could further limit or prohibit our ability to manage or dispose of wastewater, including produced water, drilling and completion fluids and other wastes associated with our operations.

Air Emissions

The CAA and its state analogs and regulations restrict the emission of various air pollutants from many sources, including oil and gas operations, through the issuance of permits and the imposition of various pre-construction, monitoring and reporting requirements. New facilities may be required to obtain permits before

 

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construction can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. In addition, the EPA has developed more stringent regulations governing emissions of toxic air pollutants and greenhouse gases (“GHG”), which may increase the costs of compliance for some facilities.

Some of our producing wells and associated facilities are subject to restrictive emission limitations and permitting requirements for volatile organic compounds (“VOCs”), particulate matter (“PM”), nitrogen oxides (“NOx”) and other air pollutants. In 2012, the EPA issued federal regulations affecting our operations under the New Source Performance Standards provisions (Subpart OOOO) and expanded regulations under the National Emission Standards for Hazardous Air Pollutants, although implementation of some of the more rigorous requirements is not required until 2015. Also in 2012, seven states sued the EPA to compel the agency to make a determination as to whether standards of performance limiting methane emissions from oil and gas sources is appropriate and, if so, to promulgate performance standards for methane emissions from existing oil and gas sources. In April 2014, the EPA released a set of five white papers analyzing methane emissions from the industry, and, based on responses received, is expected to determine by fall 2014 whether to issue a rule governing methane emissions from the oil and gas industry. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego construction, modification or certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil and/or criminal penalties for non-compliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.

Oil Pollution Act

The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns strict liability to each responsible party for oil cleanup costs and a variety of public and private damages arising from an oil spill in waters of the United States. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior and its Bureau of Land Management, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an Environmental Assessment or a more detailed Environmental Impact Statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. This process may result in delaying the permitting and development of projects, increase costs and, in certain instances, could result in the cancellation of existing leases.

Endangered Species Act and Migratory Bird Treaty Act

The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”).

 

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The U.S. Fish and Wildlife Service and state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands and could delay or prohibit oil and gas development. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species or that may attract migratory birds, we believe that we are in substantial compliance with the ESA, MBTA and similar statutes, and we are not aware of any proposed ESA listings that will materially affect our operations. However, the designation of previously unidentified endangered or threatened species, or critical or suitable habitat, could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Abandonment, Decommissioning and Remediation Requirements

Federal, state and local laws and regulations provide detailed requirements for the abandonment of wells, the closure or decommissioning of production and transportation facilities and the environmental restoration of sites where operations have ceased. These regulations can impose significant costs related to (i) plugging, abandonment and restoration of facilities, (ii) cleanup costs and compensation for property damage due to releases or discharges, and (iii) penalties imposed for releases or non-compliance with applicable laws and regulations. As is customary in the oil and natural gas industry, we typically have contractually assumed, and may assume in the future, certain obligations relating to plugging and abandonment, cleanup, and other environmental costs in connection with our acquisition of operating interests in oil and gas fields, and these costs can be significant.

Climate Change Legislation and Greenhouse Gas Regulations

A number of federal, state and regional efforts have emerged that seek to track or reduce emissions of GHG. The EPA has adopted regulations that restrict GHG emissions under existing provisions of the CAA and rules requiring certain operations, including onshore and offshore oil and natural gas production facilities, to monitor and report GHG emissions on an annual basis. If we are unable to recover or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy.

Safe Drinking Water Act

The SDWA, the UIC program and comparable state provisions regulate the disposal, treatment or release of water produced or used during oil and gas development and the drilling and operation of water disposal wells and fluid injection wells to enhance recovery of hydrocarbons. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. Permits are required to drill wells for water disposal or for fluid injection in enhanced oil recovery, and casing integrity must be periodically monitored to ensure the casing is adequate to prevent fluids from migrating outside of targeted zones. Non-compliance with regulations or groundwater contamination by oil and natural gas drilling operations may result in fines, penalties, and/or remediation costs, among other enforcement mechanisms under the SDWA and analogous state laws. In addition, landowners and other parties may assert claims for personal injury, alternative water supplies, property damage and other claims. These regulations and attendant liabilities may increase operating costs for some facilities. Furthermore, in response to alleged seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, some agencies have imposed moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase.

 

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Worker Safety

The Occupational Safety and Health Act (“OSHA”) and any analogous state laws regulate the protection of the safety and health of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Employees

As of June 30, 2014, we had 226 full-time employees. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We utilize the services of independent contractors to perform various field and other services.

Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.

 

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MANAGEMENT

Officers and Directors

The following table sets forth names, ages and titles of our officers and directors as of November 26, 2014.

 

Name		Age		Position with Rice Energy
Daniel J. Rice IV		34		Director, Chief Executive Officer
Toby Z. Rice		32		Director, President and Chief Operating Officer
Derek A. Rice		29		Vice President of Exploration & Geology
Grayson T. Lisenby		28		Vice President and Chief Financial Officer
James W. Rogers		34		Vice President, Chief Accounting & Administrative Officer, Treasurer
William E. Jordan		34		Vice President, General Counsel and Corporate Secretary
Robert F. Vagt		67		Director (Chairman)
Daniel J. Rice III		63		Director
Scott A. Gieselman		51		Director
James W. Christmas		66		Director

Set forth below is the description of the background of our directors and executive officers. References to positions held at Rice Energy include positions held at Rice Drilling B prior to our corporate reorganization.

Daniel J. Rice IV has served as a member of our board of directors and our Chief Executive Officer since October 2013. Mr. Rice joined Rice Partners in October 2008 and served as the Vice President and Chief Financial Officer of Rice Energy from October 2008 through October 2012. From October 2012 through September 2013, Mr. Rice served as the Chief Operating Officer of Rice Energy. Prior to joining Rice Energy, he served as an investment banker for Tudor Pickering Holt & Co., LLC, an integrated energy investment bank in Houston, Texas, from February 2008 to October 2008. Prior to his employment at Tudor Pickering Holt, he served as a senior analyst of corporate planning for Transocean Inc., responsible for mergers and acquisitions and business development, from March 2005 to February 2008. He was appointed Chief Executive Officer in October 2013. Daniel J. Rice IV holds a BS in Finance from Bryant University. He is the son of Daniel J. Rice III and the brother of Toby Rice and Derek Rice.

The board believes that Mr. Rice’s considerable financial and operational experience brings important and valuable skills to the board of directors.

Toby Z. Rice has served as our President and Chief Operating Officer since October 2013. Mr. Rice joined Rice Partners in February 2007 and later joined Rice Energy as its President and Chief Executive Officer when it was formed in February 2008 through September 2013. He has also served as a Manager of Rice Energy since its formation. From September 2005 until March 2008, he also served as founder and president of ZFT LLC, a consulting company specializing in the application of new hydraulic fracturing technologies for unconventional shale and tight sandstone reservoirs. Toby Rice was appointed to his current role in October 2013. He holds a BS in Chemistry from Rollins College and is the son of Daniel J. Rice III and the brother of Daniel J. Rice IV and Derek Rice.

The board believes that Mr. Rice’s considerable operational experience brings important and valuable skills to the board of directors.

Derek A. Rice has served as Rice Energy’s Vice President of Exploration & Geology since 2009 and is responsible for geologic and geophysical interpretations. Prior to joining Rice Partners and Rice Energy in August 2009, from June 2007 to September 2007 and from June 2008 until September 2008, he worked as a wellbore geologist for a large oilfield service company, where he analyzed the Marcellus, Haynesville, and Barnett shales. Derek Rice holds a BS in geological sciences from Tufts University and a MS in geology from the University of Houston. He is the son of Daniel J. Rice III and the brother of Daniel J. Rice IV and Toby Rice.

 

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Grayson T. Lisenby has served as our Vice President and Chief Financial Officer since October 2013. Mr. Lisenby joined Rice Energy in February 2013, initially serving as our Vice President of Finance. Prior to joining Rice Energy, Mr. Lisenby was an investment professional at Natural Gas Partners from July 2011 to January 2013 and concentrated on transaction analysis and execution as well as the monitoring of active portfolio companies. Mr. Lisenby was involved in NGP’s original $100 million investment into Rice Energy and spent a significant amount of his time monitoring and advising the company during his tenure at Natural Gas Partners. Prior to his employment at NGP, he served an investment banker for Barclays Capital Inc.’s energy group in Houston from August 2009 to July 2011. Mr. Lisenby holds a BBA in Finance from the University of Texas, where he was a member of the Business Honors Program.

James W. Rogers has served as our Vice President, Chief Accounting & Administrative Officer and Treasurer, since October 2013. Mr. Rogers joined Rice Energy in April 2011 as Controller and subsequently served as our Vice President and Chief Accounting Officer from January 2012 through October 2012 and our Chief Financial Officer from November 2012 through September 2013. Prior to joining Rice Energy, Mr. Rogers served as a Financial Specialist with EQT Corporation, working in the Corporate Accounting Group, from May 2010 to March 2011. Prior to EQT, Mr. Rogers served as an assurance manager for Ernst & Young in their Pittsburgh office from September 2007 to April 2010. He began his career in 2002 as an auditor with PricewaterhouseCoopers LLP, in its Pittsburgh office. Mr. Rogers is a certified public accountant in the state of Pennsylvania and holds a BSBA in accounting from the University of Pittsburgh. He is also a member of the AICPA.

William E. Jordan has served as our Vice President, General Counsel and Corporate Secretary since January 2014. From September 2005 through December 2013, Mr. Jordan practiced corporate law at Vinson & Elkins L.L.P., representing public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. He is a graduate of Davidson College with a BA in Mathematics and a graduate of the Duke University School of Law with a Doctor of Jurisprudence degree.

Robert F. Vagt has served as the chairman of our board of directors since January 2014. Mr. Vagt has served as a member of the board of directors of Kinder Morgan, Inc. since May 2012, where he serves as a member of the audit committee. Mr. Vagt has served as a member of the board of directors of El Paso Corporation from May 2005 until June 2012, where he was a member of the compensation and health, safety and environmental committees. From January 2008 until January 2014, Mr. Vagt was also the President of The Heinz Endowments. Prior to his tenure at The Heinz Endowments, Mr. Vagt served as President of Davidson College from July 1997 to August 2007. Mr. Vagt served as President and Chief Operating Officer of Seagull Energy Corporation from 1996 to 1997. From 1992 to 1996, he served as President, Chairman and Chief Executive Officer of Global Natural Resources. Mr. Vagt served as President and Chief Operating Officer of Adobe Resources Corporation from 1989 to 1992. Prior to 1989, he served in various positions with Adobe Resources Corporation and its predecessor entities.

The board believes that Mr. Vagt’s professional background in both the public and private sectors make him an important advisor and member of our board of directors. Mr. Vagt brings to the board operations and management expertise in both the public and private sectors. In addition, Mr. Vagt provides the board with a welcomed diversity of perspective gained from service as President of The Heinz Endowments, as well as from service as the president of an independent liberal arts college.

Daniel J. Rice III has served as a member of our board of directors since October 2013. He has also served as Managing General Partner of Rice Partners. Since January 2013, Mr. Rice has served as Lead Portfolio Manager for GRT Capital’s energy division. From 2005 to December 2012, Mr. Rice served as a Managing Director and Portfolio Manager for BlackRock, Inc. and was a member of BlackRock, Inc.’s Global Resources team, responsible for Small Cap and All Cap Energy funds. Prior to joining BlackRock, Inc. in 2005, he was a Senior Vice President and Portfolio Manager at State Street Research & Management, responsible for the Small Cap Energy and All Cap Energy Global Resources Funds. Prior to joining State Street Research in 1984, he was

 

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a Vice President and Portfolio Manager with Fred Alger Management. Earlier in his career, Mr. Rice was a Vice President and Analyst with EF Hutton and an Analyst with Loomis Sayles and Co. He began his career in 1975 as an auditor with Price Waterhouse & Co. He earned a BS degree from Bates College in 1973 and an MBA degree from New York University in 1975. Mr. Rice has more than 30 years of experience in the oil and gas industry. He is the father of Toby Rice, Daniel J. Rice IV and Derek Rice.

The board believes that Mr. Rice’s considerable financial and energy investing experience brings important and valuable skills to the board of directors.

Scott A. Gieselman has served as a member of our board of directors since April 2013. Mr. Gieselman has been a managing director of Natural Gas Partners since April 2007. From 1988 to April 2007, Mr. Gieselman worked in various positions in the investment banking energy group of Goldman, Sachs & Co., where he became a partner in 2002. Mr. Gieselman received a BS from the Boston College Carroll School of Management in 1985 and a MBA from the Boston College Carroll Graduate School of Management in 1988.

The board believes that Mr. Gieselman’s considerable financial and energy investment banking experience, as well as his experience on the boards of numerous private energy companies, bring important and valuable skills to the board of directors.

James W. Christmas has served as a member of our board of directors since January 2014. Mr. Christmas has served as a member of the board of directors of Halcón Resources Corporation since February 2012. Mr. Christmas began serving as a director of Petrohawk Energy Corporation in July 2006, effective upon the merger of KCS Energy, Inc. (“KCS”) into Petrohawk. He continued to serve as a director, and as Vice Chairman of the Board of Directors, for Petrohawk until BHP Billiton acquired all of Petrohawk in August 2011. He also served on the audit committee and the Nominating and Corporate Governance Committee. Currently, Mr. Christmas serves as a member of the Board of Directors of Petrohawk, a wholly-owned subsidiary of BHP Billiton, and as chair of the Financial Reporting Committee of such board. He also serves on the Advisory Board of the Tobin School of Business of St. John’s University and as a member of the board of directors of a private oil and gas company. He served as President and Chief Executive Officer of KCS from 1988 until April 2003 and Chairman of the Board and Chief Executive Officer of KCS until its merger into Petrohawk. Mr. Christmas was a Certified Public Accountant in New York and was with Arthur Andersen & Co. from 1970 until 1978 before leaving to join National Utilities & Industries (“NUI”), a diversified energy company, as Vice President and Controller. He remained with NUI until 1988, when NUI spun out its unregulated activities that ultimately became part of KCS. As an auditor and audit manager, controller and in his role as CEO of KCS, Mr. Christmas was directly or indirectly responsible for financial reporting and compliance with SEC regulations, and as such has extensive experience in reviewing and evaluating financial reports, as well as in evaluating executive and board performance and in recruiting directors.

The board believes that Mr. Christmas’s prior experience as an executive and director and his past audit, accounting and financial reporting experience provide significant contributions to our board of directors.

Board of Directors

Our board of directors currently consists of six members: Robert F. Vagt (Chairman), Daniel J. Rice IV, Toby Z. Rice, Daniel J. Rice III, Scott A. Gieselman and James W. Christmas.

In connection with the closing of our IPO, we entered into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc. Please see “Certain Relationships and Related Party Transactions.” Pursuant to the stockholders’ agreement, we and our principal stockholders agreed to appoint individuals designated by the principal stockholders to our board of directors and nominate such persons for election at each annual meeting of our stockholders.

 

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We expect to add another independent director to our board of directors and audit committee within one year of the initial listing of our common stock on the NYSE. Our board has reviewed the independence of our current directors using the independence standards of the NYSE and, based on this review, determined that Messrs. Gieselman, Vagt and Christmas are independent within the meaning of the NYSE listing standards currently in effect. As a result, we expect that our board of directors will consist of seven members within one year of the initial listing of our common stock on the NYSE, four of whom will be independent.

In evaluating director candidates, we assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board to fulfill their duties. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.

Our directors are divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors serve until our annual meetings of stockholders in 2015, 2016 and 2017, respectively. Messrs. Daniel J. Rice IV and Christmas are assigned to Class I, Messrs. Toby Z. Rice and Vagt are assigned to Class II and Messrs. Daniel J. Rice III and Gieselman are assigned to Class III. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Committees of the Board of Directors

We have an audit committee, a compensation committee, a nominating and corporate governance committee and a health, safety & environmental committee of our board of directors, and we may form such other committees as the board of directors shall determine from time to time in the future. Each of the standing committees of the board of directors has the composition and responsibilities described below.

Audit Committee

Rules implemented by the NYSE and SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief during the one-year period following the initial listing of our common stock on the NYSE. Our audit committee consists of Messrs. Christmas (Chair) and Vagt, each of whom is independent under the rules of the SEC. Subsequent to the transitional period, we will comply with the requirement to have three independent directors on our audit committee. As required by the rules of the SEC and listing standards of the NYSE, the audit committee consists solely of independent directors. Our board has determined that Mr. Christmas satisfies the definition of “audit committee financial expert.”

This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to legal and regulatory requirements. We have an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. A copy of our audit committee charter is posted on our website at http://investors.riceenergy.com/committee-charters.

Compensation Committee

Our compensation committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee also administers our incentive compensation and benefit plans. Our compensation committee charter defines the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. Our compensation committee consists of

 

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Messrs. Vagt (Chair) and Christmas, each of whom is independent under the rules of the NYSE. A copy of our compensation committee charter is posted on our website at http://investors.riceenergy.com/committee-charters.

Nominating and Corporate Governance Committee

Because we are a controlled company within the meaning of the NYSE corporate governance standards, we are not required to have a nominating and governance committee composed entirely of independent directors. However, we have a nominating and corporate governance committee, which identifies, evaluates and recommends qualified nominees to serve on our board of directors, develops and oversees our internal corporate governance processes and maintains a management succession plan. Our nominating and corporate governance committee charter defines the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. Our nominating and governance committee consists of Messrs. Gieselman (Chair), Daniel J. Rice III and Robert F. Vagt. A copy of our nominating and corporate governance committee charter is posted on our website at http://investors.riceenergy.com/committee-charters.

Health, Safety and Environmental Committee

We have a health, safety and environmental committee. This committee assists the board in fulfilling its risk oversight responsibilities relating to health, safety and environmental-related matters, including environmental regulations, health and safety initiatives and accountabilities, and crisis response. Our health, safety and environmental committee consists of Messrs. Toby Z. Rice (Chair) and Vagt.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board or compensation committee. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Code of Business Conduct and Ethics

Our board of directors has adopted a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Corporate Governance Guidelines

Our board of directors believes that sound governance practices and policies provide an important framework to assist it in fulfilling its duty to stockholders. Our Corporate Governance Guidelines cover the following principal subjects:

 

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Role and functions of the board of directors

 

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Qualifications and independence of directors

 

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Size of the board of directors and director selection process

 

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Committee functions and independence of committee members

 

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Meetings of non-employee directors

 

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Self-evaluation

 

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Ethics and conflicts of interest (a copy of the current “Code of Business Conduct and Ethics” is posted on the our website at http://investors.riceenergy.com/codeofconduct)

 

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•

Compensation of the board of directors

 

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Succession planning

 

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Access to senior management and to independent advisors

 

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New director orientation

 

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Continuing education

The “Corporate Governance Guidelines” are posted on the our website at http://investors.riceenergy.com/corporate-governance. The Corporate Governance Guidelines will be reviewed periodically and as necessary by our nominating and governance committee, and any proposed additions to or amendments of the Corporate Governance Guidelines will be presented to the board of directors for its approval.

The NYSE has adopted rules that require listed companies to adopt governance guidelines covering certain matters. We believe that the Corporate Governance Guidelines comply with the NYSE rules.

 

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EXECUTIVE COMPENSATION

Named Executive Officers

For fiscal year 2013, our Named Executive Officers were as follows. Please see “Management” for a description of our current executive officers, including historical roles held by our 2013 Named Executive Officers.

 

Daniel J. Rice IV		Chief Executive Officer/Vice President and Chief Operating Officer(1)
Toby Z. Rice		President and Chief Operating Officer/Chief Executive Officer(2)
Grayson T. Lisenby		Vice President and Chief Financial Officer/Vice President of Finance(3)
James W. Rogers		Vice President and Chief Accounting & Administrative Officer, Treasurer/Vice President and Chief Financial Officer(4)

 

(1)	Mr. Daniel J. Rice IV’s role with our company changed during 2013. In 2013, he served as our Vice President and Chief Operating Officer from January through September and thereafter as our Chief Executive Officer.

(2)	Mr. Toby Z. Rice’s role with our company changed during 2013. In 2013, he served as our Chief Executive Officer from January through September and thereafter as our President and Chief Operating Officer.

(3)	Mr. Lisenby’s role with our company changed during 2013. Mr. Lisenby joined our company in February 2013, initially serving as our Vice President of Finance through September. Thereafter, Mr. Lisenby served as our Vice President and Chief Financial Officer.

(4)	Mr. Rogers’s role with our company changed during 2013. In 2013, he served as our Vice President and Chief Financial Officer from January through September and thereafter as our Vice President and Chief Accounting & Administrative Officer, Treasurer.

Summary Compensation Table

The following table summarizes, with respect to our Named Executive Officers, information relating to the compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2013.

 

Name and Principal Position		Year				Salary ($)				Bonus (1)($)				Non-Equity Incentive Plan Compensation ($)(2)				All Other Compensation ($)(3)				Total ($)
Daniel J. Rice, IV			2013			$	110,000			$	65,000			$	—			$	2,200			$	177,200
(CEO/VP and COO)
Toby Z. Rice			2013			$	110,000			$	65,000			$	—			$	3,850			$	178,850
(President and COO/CEO)
Grayson T. Lisenby			2013			$	126,389			$	145,000			$	—			$	108			$	271,497
(VP CFO/VP of Finance)
James W. Rogers			2013			$	149,063			$	126,750			$	—			$	—			$	275,813
(VP and Chief Accounting and Administrative Officer, Treasurer/VP and CFO)

 

(1)	The amounts in this column represent the aggregate amount of annual discretionary cash bonuses paid to our Named Executive Officers for fiscal year 2013 performance.

(2)

As discussed more fully below in the “Long Term Incentive Compensation” section of the narrative accompanying this table, each of the Named Executive Officers holds outstanding Incentive Units that are not classified as equity for accounting purposes. However, because satisfaction of the performance conditions related to these awards is not probable, no amounts have been treated as earned in 2013 for purposes of this table.

 

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(3)	Amounts reported in the “All Other Compensation” column reflect company matching contributions to the Named Executive Officers’ 401(k) plan retirement accounts.

Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year

In connection with our IPO, we engaged Alvarez & Marsal (“A&M”), a global professional services firm, as our compensation consultant to provide recommendations regarding our compensation arrangements. The following discussion describes the elements of our 2013 executive compensation program.

Base Salary

Each Named Executive Officer’s base salary is a fixed component of compensation for each year for performing specific job duties and functions. Prior to our IPO, an informal compensation committee comprised of Messrs. D. Rice IV, T. Rice, and D. Rice III (collectively, the “Committee”) established the annual base salary rate for each of the Named Executive Officers at a level necessary to retain the individual’s services and reviewed base salaries on an annual basis at the end of each year, with adjustments implemented at the beginning of the next year. The Committee historically made adjustments to the base salary rates of the Named Executive Officers upon consideration of any factors that it deemed relevant, including but not limited to: (a) any increase or decrease in the executive’s responsibilities, (b) the executive’s job performance, and (c) the level of compensation paid to executives of other companies with which we compete for executive talent, as estimated based on publicly available information and the experience of members of the Committee. Notwithstanding the foregoing, under the Limited Liability Company Agreement of Rice Appalachia, dated January 25, 2012, as amended from time to time (the “REA LLC Agreement”), annual compensation and benefits (except for Incentive Units granted by Rice Appalachia’s Board of Managers under the REA LLC Agreement) for our Named Executive Officers historically required the approval of Natural Gas Partners, except to extent that such annual salaries did not exceed $150,000 for each of Messrs. T. Rice and D. Rice IV. Such requirement was eliminated with the amendment of the REA LLC Agreement in connection with our IPO.

In connection with our IPO, the Committee analyzed the appropriateness of the base salary for each of our Named Executive Officers in light of the base salaries of other executives in the peer group that we identified with the assistance of A&M, both on a stand-alone basis and as a component of total compensation. This review resulted in the establishment of the following annual base salaries for each of our Named Executive Officers, effective upon the IPO: $400,000 for each of Messrs. D. Rice IV and T. Rice and $300,000 for each of Messrs. Lisenby and Rogers. After further analysis, in May of 2014 our new compensation committee increased Messrs. Lisenby and Rogers’ base salaries to $400,000 and $350,000, respectively.

Annual Cash Bonus

Prior to the IPO, annual cash bonus awards for Messrs. T. Rice and D. Rice IV were discretionary awards awarded by the Committee at the end of each fiscal year. The determination of the amount of these discretionary cash bonus awards, if any, was made based on an overall assessment of our company’s performance in light of overall market conditions, along with these Named Executive Officers’ individual performance, for the fiscal year, and was not based on any one or more specific performance objective or criteria.

The amount of annual bonus for Messrs. Lisenby and Rogers for 2013 was determined under a separate award program that applies to certain of our key employees. This program is administered under the Rice Energy Management Bonus Plan (the “Bonus Plan”), as established in January 2010 and amended from time to time. Under the Bonus Plan, for 2013, a targeted bonus amount expressed as a percentage of annual base salary was established for each of Messrs. Lisenby and Rogers. The determination of the amount of annual bonus payable for 2013 for each of Messrs. Lisenby and Rogers was made in the discretion of the Committee. In making this determination, the Committee historically considered each participating employee’s targeted bonus award amount (expressed as a percentage of the employee’s base salary) and the employee’s individual performance

 

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and contributions during the year, including his completion of job-specific duties, but the Committee retained full discretion to pay less than or more than the individual’s targeted bonus award amount. Due to our strong performance in 2013 and the contributions of Messrs. Lisenby and Rogers thereto, these two executives were awarded the full amount of their targeted bonus of $145,000, and $126,750, respectively.

We intend to continue to provide annual incentive cash bonuses under the Rice Energy Inc. Long-Term Incentive Plan (the “LTIP”) to reward achievement of financial or operational goals so that total compensation reflects actual company and individual performance. In May 2014, our new compensation committee established performance goals under the LTIP to be used in determining the cash bonuses that may become payable for the 2014 performance period.

Long-Term Incentive Compensation

Incentive Units

Prior to our IPO, the only long-term incentives offered to our Named Executive Officers were through grants of Incentive Units, which were profits interests representing an interest in the future profits (once a certain level of proceeds has been generated) of our predecessor parent entity Rice Appalachia and granted pursuant to the REA LLC Agreement. These profits interests (the “REA Incentive Units”) represented interests in Rice Appalachia that had no value for tax purposes on the date of grant and were designed to gain value only after the underlying assets had realized a certain level of growth and return to those individuals who hold certain classes of Rice Appalachia’s equity. The REA Incentive Units were intended to provide the holders with the ability to benefit from the growth in our operations and business. In connection with our IPO and the related corporate reorganization, the Named Executive Officers (and other REA Incentive Unit holders) contributed their REA Incentive Units (except for those related to the incentive burden attributable to Mr. Daniel J. Rice III) to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities.

In 2013, each of the Named Executive Officers held outstanding REA Incentive Units granted pursuant to the REA LLC Agreement. The profits interest awards were divided into seven tiered classes as follows: Legacy Tier I Units, Legacy Tier II Units, Legacy Tier III Units, New Tier I Units, New Tier II Units, New Tier III Units, and New Tier IV Units. A potential payout for each tier would have occurred only after a specified level of cumulative cash distributions had been received by Natural Gas Partners. Legacy Tier I Units were designed to vest in three equal annual installments, with such annual vesting occurring on the anniversaries of the grant date and with pro-rata monthly vesting between these annual anniversary dates. Legacy Tier II Units and Legacy Tier III Units would each have vested only upon the payment threshold established for that tier (described below). New Tier I Units and New Tier II Units were designed to vest in five equal annual installments on each anniversary of the grant date of such awards and with pro-rata monthly vesting between these annual anniversary dates. New Tier III Units and New Tier IV Units would each have vested only upon the payment threshold established for that tier (described below). In addition to the time-based vesting that applied to the Legacy Tier I Units, New Tier I Units, and New Tier II Units, such awards were also subject to accelerated vesting in full upon the occurrence of a “Fundamental Change” (as defined in the REA LLC Agreement and described below).

The difference between a vested and unvested unit was that once a unit vested, the executive would retain all vested profits interest awards as non-voting interests, unless such executive’s employment was terminated for “Cause” (as defined below) or voluntarily resigns. All profits interest awards that had not vested according to their original vesting schedule at the time an executive’s employment was terminated for any reason would be forfeited without payment. If we terminated an executive for Cause, or the executive voluntarily terminated his or her employment, all vested profits interest awards would also be forfeited at the time of the termination. If distributions were made with respect to a tier of these profits interest awards, both vested and unvested units (to the extent not previously forfeited) would receive the distributions and the holder of such units would be entitled to keep any such distributions regardless of whether the units were subsequently forfeited.

Under the REA LLC Agreement, the Legacy Tier I, Legacy Tier II and Legacy Tier III Units were entitled to 10%, 10% and 10%, respectively, of distributions to members only after Natural Gas Partners had received

 

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cumulative distributions in respect of their membership interests equal to two times, three times and four times, respectively, of the cumulative capital contributions made prior to April 18, 2013. The New Tier I Units and New Tier II Units were entitled to 20% and 5%, respectively, of distributions to members only after Natural Gas Partners had received cumulative distributions in respect of their membership interests equal to their cumulative capital contributions made on or after April 18, 2013, multiplied by (1.08)n and (1.20)n, respectively, where “n” was equal to a weighted average capital contribution factor determined as of the dates of the distributions. The New Tier III Units and New Tier IV Units were entitled to 5% and 5%, respectively, of distributions to members only after Natural Gas Partners had received cumulative distributions in respect of their membership interests equal to two times and 2.5 times, respectively, their cumulative capital contributions made on or after April 18, 2013.

As used in the paragraphs above, a “capital contribution” to Rice Appalachia generally means, for any member thereof, the dollar amount of any cash and the fair market value of any property contributed to Rice Appalachia.

A termination for “Cause” would have generally occurred upon the individual’s (i) conviction of, or plea of nolo contendere to, any felony or crime causing substantial harm to us or our affiliates or involving acts of theft, fraud, embezzlement, moral turpitude or similar conduct; (ii) repeated intoxication by alcohol or drugs during the performance of the individual’s duties in a manner that materially and adversely affects the individual’s performance of such duties; (iii) malfeasance in the conduct of the individual’s duties; (iv) violation of any voting or transfer restriction agreement or a confidentiality and noncompete agreement that the individual has executed with us; and (v) failure to perform the duties of the individual’s service relationship with us or our affiliates, or failure to follow or comply with the reasonable and lawful written directives of our board of managers or the board of an affiliate employing or engaging the service of such individual, as applicable.

A “Fundamental Change” was generally deemed to have occurred when Rice Appalachia entered into any merger or consolidation with another entity, the outstanding interests in the company were sold or exchanged, or Rice Appalachia sold, leased, exchanged, or licensed all or substantially all of its assets, in each case other than with or to a related entity and only if Rice Appalachia’s existing board members did not continue to constitute at least a majority of the members of the board of the surviving or acquiring entity immediately following the transaction. A Fundamental Change was also deemed to have occurred if any single person or entity (or groups of such related persons or entities) purchased or acquired the right to vote or dispose of the company’s securities in an amount representing 50% or more of the total voting power of all the then outstanding voting securities of Rice Appalachia unless such transaction has been approved by Rice Appalachia’s board of managers (provided that no capital contribution by certain Natural Gas Partners entities shall constitute a Fundamental Change). Our IPO, and the related corporate reorganization did not constitute a Fundamental Change.

Prior to our IPO, no tier of the profits interest awards had received a payout. Since no amount of the outstanding REA Incentive Units held by our Named Executive Officers had been earned (as the performance conditions related to payout were not probable of occurring) as of December 31, 2013 and the awards were not accounted for under Financial Accounting Standards Board Accounting Standards Topic 718 (“FASB ASC Topic 718”), the value of these profits interests had not been included in our Summary Compensation Table. In connection with our corporate reorganization, approximately 160,831 shares of our common stock were issued to certain of the incentive holders in exchange for the portion of their REA Incentive Units related to the incentive burden attributable to Mr. Daniel J. Rice III. In connection with our IPO, in the first quarter of 2014, we recognized a non-cash compensation expense of $3.4 million. Also, in connection with our IPO, in the first quarter of 2014, certain incentive units granted by NGP Holdings to certain members of management triggered the pre-determined payout criteria, resulting in a cash payment of $4.4 million. This resulted in additional non-cash compensation expense.

In connection with our IPO and the related corporate reorganization, the Named Executive Officers (and other REA Incentive Unit holders) contributed their REA Incentive Units (except for those related to the

 

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incentive burden attributable to Mr. Daniel J. Rice III) to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. As a result, the burden of the incentive units previously attributable to Rice Partners and Natural Gas Partners was replicated in the limited liability company agreements of Rice Holdings and NGP Holdings, respectively. The limited liability company agreement of NGP Holdings entitles holders of incentive units to a portion of distributions made by NGP Holdings. Generally, it is anticipated that such distributions will occur in connection with sales of our common stock by NGP Holdings. Accordingly, if the requisite cumulative cash distribution thresholds to Natural Gas Partners have been met, incentive unitholders are entitled to cash distributions on any applicable class of incentive units at such time. Following the end of the 2013 fiscal year, on January 30, 2014, a distribution threshold was satisfied and NGP Holdings made certain cash distributions to incentive unit holders; Messrs. Daniel Rice, Toby Rice, Lisenby and Rogers received aggregate payments in the amount of $376,376; $486,647; $557,076 and $114,626, respectively, related to their incentive units. Similarly, the limited liability company agreement of Rice Holdings entitles holders of incentive units to a portion of distributions made by Rice Holdings. However, incentive unitholders in Rice Holdings are not entitled to receive distributions of distributable funds until the earlier of January 2, 2016, or 30 days following the date on which NGP Holdings has sold in excess of 50% of its Rice Energy Inc. common stock (including pursuant to our IPO). On such date and each of the three anniversaries thereafter, Rice Holdings will distribute one-quarter of its distributable funds, including shares of our common stock, to its members. Accordingly, if requisite cumulative distribution thresholds to Rice Partners have been met, incentive unitholders are entitled to distributions of either cash or our common stock on any applicable class of incentive units at such times. As of the date of this filing, no distributions have been made to the incentive unit holders from Rice Holdings. Because we are not a party to the limited liability company agreements of Rice Holdings or NGP Holdings, we cannot be certain that the terms of the profits interest units will not change in the future.

Long-Term Incentive Plan

In order to incentivize management members, our board of directors adopted the LTIP, an omnibus long-term incentive plan for employees, consultants, and directors. Our Named Executive Officers are eligible to participate in the LTIP which provides for the grant of bonus stock, restricted stock, restricted stock units, options, stock appreciation rights, dividend equivalent rights, performance awards, annual incentive awards and other stock-based awards intended to align the interests of key employees (including the Named Executive Officers) with those of our stockholders. We did not grant any equity awards under the LTIP to our Named Executive Officers during the 2013 year. In May of 2014, our compensation committee approved grants of performance stock units and restricted stock units to each of our Named Executive Officers. The terms and conditions of these awards will be more fully described in our definitive proxy statement filed pursuant to Section 14(a) of the Securities Exchange Act of 1934 with respect to our 2015 annual meeting of stockholders.

Other Compensation Elements

We also offer participation in broad-based retirement and health and welfare plans to all of our employees. We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code whereby employees, including our Named Executive Officers, are allowed to contribute portions of their compensation (which includes all compensation reported on Form W-2 for the year) to a tax-qualified retirement account. See “—Additional Narrative Disclosure Regarding Retirement Benefits and Other Potential Payments Upon Termination or a Change in Control—Retirement Benefits” for more information.

Outstanding Equity Awards at 2013 Fiscal Year-End

None of our Named Executive Officers held any outstanding equity awards that were accounted for under FASB ASC Topic 718 as of December 31, 2013.

 

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Additional Narrative Disclosure Regarding Retirement Benefits and Other Potential Payments Upon Termination or a Change in Control

Retirement Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan or a nonqualified deferred compensation plan providing for retirement benefits. We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code, under which employees, including our Named Executive Officers, are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under our 401(k) plan, we provide matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan.

Employment, Severance or Change in Control Agreements

As described in more detail under “—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year—Long-Term Incentive Compensation” above, the REA Incentive Units held by our Named Executive Officers were to be either forfeited or remain outstanding following the officer’s termination of employment, with no acceleration of vesting or payment being made under the awards upon such termination of employment.

Prior to our IPO, we historically had not maintained any employment, severance or change in control agreements with any of our Named Executive Officers. In addition, none of the Named Executive Officers were entitled to any payments or other benefits in connection with a termination of their employment or a change in control during the 2013 year, except that in certain instances, (1) our employees may be entitled to receive, upon a sale of the company or substantially all of our assets, amounts of already earned annual bonus awards under our Bonus Plan to the extent such amounts have not yet been paid at the time such transaction occurs, and (2) a change in control (a “Fundamental Change,” as such term is defined in the REA LLC Agreement and summarized under “—Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year—Long Term Incentive Compensation-Incentive Units” above may result in a cash distribution being made to holders of vested REA Incentive Units, in accordance with the distribution priority specified in the REA LLC Agreement (unvested REA Incentive Units do not become vested upon a change in control).

In connection with our IPO, our Named Executive Officers entered into employment agreements with us on January 29, 2014. Under these new employment agreements, each of our Named Executive Officers is entitled to certain severance benefits upon a qualifying termination of employment and the employment agreements preclude the executives from soliciting employees or competing with us for a period of one year following termination of employment.

The description of the employment agreements set forth below is a summary of the material features of the agreements regarding potential payments upon termination or a change in control. This summary, however, does not purport to be a complete description of all the provisions of the agreements with the executives. This summary is qualified in its entirety by reference to the employment agreements, which are filed as exhibits to our Annual Report on Form 10-K for the year ended December 31, 2013.

Under the terms of the new employment agreements, each Named Executive Officer is entitled to receive the following amounts (the “Accrued Rights”) upon a termination by the company for “cause” (as such term is defined below), upon a termination of employment by reason of death, disability, or expiration of the term of the employment agreement, or upon the executive’s termination without “good reason” (as such term is defined below): (a) payment of all accrued and unpaid base salary to the date of termination, (b) reimbursement of all incurred but unreimbursed business expenses to which the executive would have been entitled to reimbursement, and (c) benefits to which the executive is entitled under the terms of any applicable benefit plan or program. If the termination is due to death or disability, such Named Executive Officer is also entitled to accelerated vesting of any outstanding LTIP awards.

 

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Under the terms of the employment agreements, each Named Executive Officer is also entitled to receive the following amounts upon a termination by the executive for “good reason” (as such term is defined below) or by the company without “cause” (as such term is defined below): (a) the Accrued Rights; (b) any earned but unpaid annual bonus for the prior year; (c) a prorated annual bonus for the year of termination; (d) a severance payment equal to one times (two times in the event of a qualifying termination within the 12-month period following a “change in control” as such term is defined below) the sum of the executive’s base salary on the date of termination and the average annual bonus for the three prior calendar years; and (e) accelerated vesting of any outstanding LTIP awards held by the executive as of the date of termination. The Named Executive Officers are also entitled to continued coverage under our group health plan for any COBRA period (up to 18 months) elected for the executive and the executive’s spouse and eligible dependents, at no greater premium cost than that which applies to our active senior executive employees.

The following terms are defined under the employment agreements for the Named Executive Officers, as described below:

 

•

“Cause” means a determination by the board of directors (or its delegates) that the executive (a) has engaged in gross negligence, gross incompetence, or misconduct in the performance of the executive’s duties to us, (b) has failed without proper legal reason to perform the executive’s duties and responsibilities to us, (c) has breached any material provision of the employment agreement or any written agreement or corporate policy or code of conduct established by us, (d) has engaged in conduct that is, or could reasonably expected to be, materially injurious to us, (e) has committed an act of theft, fraud, embezzlement, misappropriation, or breach of a fiduciary duty to us, or (f) has been convicted of, pleaded no contest to, or received adjudicated probation or deferred adjudication in connection with a crime involving fraud, dishonesty, or moral turpitude or any felony (or a crime of similar import in a foreign jurisdiction).

 

•

“Good Reason” means (a) a material diminution in the executive’s base salary (as defined in the employment agreements), other than as a part of one or more decreases that (i) shall not exceed, in the aggregate, more than 10% of the base salary as in effect on the date immediately prior to such decrease, and (ii) are applied similarly to all of our similarly situated executives; (b) a material diminution in the executive’s authority, duties, or responsibilities; or (c) the involuntary relocation of the geographic location of the executive’s principal place of employment by more than 75 miles from the location of the executive’s principal place of employment as of the effective date of the employment agreement.

 

•

“Change in Control” generally means (a) a merger, consolidation, or sale of all or substantially all of our assets if (i) our shareholders do not continue to own at least 50% of the voting power of the resulting entity in substantially the same proportions that they owned our equity securities prior to the transaction or event or (ii) the members of our board immediately prior to the transaction or event do not constitute at least a majority of the board of directors of the resulting entity immediately after the transaction or event; (b) the dissolution or liquidation of the company; (c) when any person, entity, or group acquires or gains ownership or control of more than 50% of the combined voting power of the outstanding securities of the company, or (d) as a result of or in connection with a contested election of directors, the persons who were members of our board immediately before such election cease to constitute a majority of the board.

Compensation of Directors

We did not award any compensation to our non-employee directors during 2013. Going forward, our board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance of our company. Our board of directors also believes that the compensation package for our non-employee directors should require a portion of the total compensation package to be equity-based to align the interest of these directors with our stockholders.

 

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Except with respect to designees of Rice Holdings and NGP Holdings, we have implemented the following non-employee director compensation program: (a) an annual cash retainer valued at approximately $250,000 for the chairman of our board, $60,000 for our committee chairmen and $50,000 for all other non-employee directors, and (b) an annual LTIP award valued at approximately $250,000 for the chairman of our board and $175,000 for our committee chairmen, and $165,000 for all other non-employee directors. We do not pay any additional fees for attendance at board or committee meetings, but we do reimburse each director for travel and miscellaneous expenses to attend meetings and activities of our board or its committees. In addition, two of our non-employee directors, Robert F. Vagt and James W. Christmas, received initial grants of restricted stock units upon the closing of our IPO in the amount of 11,905 and 5,238, respectively, that are subject to a one-year cliff vesting schedule. Directors who are also our employees and directors who are designees of Rice Holdings and NGP Holdings do not receive any additional compensation for their service on our board of directors.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Beneficial Ownership

The following table sets forth certain information regarding the beneficial ownership of our common stock as of December 1, 2014 by (i) each person who is known by us to own beneficially more than five percent of our outstanding shares of common stock, (ii) each of our named executive officers, (iii) each member of our board of directors and (iv) all of our directors and executive officers as a group. Unless otherwise noted, the mailing address of each person or entity named below is c/o Rice Energy Inc., 400 Woodcliff Drive, Canonsburg, Pennsylvania 15317.

 

		Shares Beneficially Owned(1)
Name and Address of Beneficial Owner		Number				Percentage
5% Stockholders:
Rice Energy Irrevocable Trust(2)			19,800,000				14.5	%
Rice Holdings(3)			20,300,923				14.9
NGP Holdings(4)			20,337,725				14.9
Alpha Holdings(5)			6,408,985				4.7
Citadel Advisors LLC and affiliates(6)			7,014,188				5.1
Directors and Named Executive Officers:
Daniel J. Rice IV(7)			25,009				*
Toby Z. Rice(8)			27,594				*
Grayson T. Lisenby(9)			30,014				*
James W. Rogers(10)			23,088				*
Robert F. Vagt(11)			25,869				*
Daniel J. Rice III(2)			22,356,844				16.4
Scott A. Gieselman			40,000				*
James W. Christmas(12)			112,694				*
All Directors and Executive Officers as a Group (10 Persons)(13)			22,702,496				16.7

 

*	Less than one percent.

(1)	Based upon an aggregate of 136,280,766 shares outstanding as of December 1, 2014.

(2)

Rice Energy Irrevocable Trust’s shares are held in a trust for the benefit of Daniel J. Rice III’s children and descendants. Daniel J. Rice III’s spouse is a trustee of the trust. By virtue of his relationship with Rice Energy Irrevocable Trust, Daniel J. Rice III is deemed to have an indirect beneficial interest in the shares of common stock held by Rice Energy Irrevocable Trust. Daniel J. Rice III disclaims beneficial ownership of these securities. Daniel J. Rice III directly owns 2,556,844 shares of our common stock.

(3)	Rice Holdings is controlled by a board of managers consisting of Daniel J. Rice IV, Toby Z. Rice and Daniel J. Rice III.

(4)

NGP Holdings is indirectly owned by Natural Gas Partners IX, L.P. and an affiliate thereof (“NGP IX”) and NGP Natural Resources X, L.P. and an affiliate thereof (“NGP X”). NGP IX and NGP X may be deemed to share voting and dispositive power over the reported securities, and therefore, may also be deemed to be the beneficial owner of these securities. NGP IX and NGP X disclaim beneficial ownership of the reported securities in excess of such entity’s respective pecuniary interest in the securities. G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to share voting and dispositive power over the reported securities, and therefore, may also be deemed to be the beneficial owner of these shares by virtue of GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the sole general partner of NGP IX). G.F.W. Energy X, L.P. and GFW X, L.L.C. may be deemed to share voting and dispositive power over the reported securities, and therefore, may also be deemed to be the beneficial owner of these shares by virtue of GFW X, L.L.C. being the sole general partner of G.F.W. Energy X, L.P. (which is the sole general partner of NGP X). David R. Albin and Kenneth A. Hersh, each an Authorized Member of GFW IX, L.L.C. and GFW X, L.L.C.,

 

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may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of the securities owned by NGP Holdings. Mr. Hersh and Mr. Albin disclaim beneficial ownership of the securities, except to the extent of their respective pecuniary interest therein. Neither Mr. Hersh nor Mr. Albin owns directly any such securities. GFW IX, L.L.C. and GFW X, L.L.C. have delegated full power and authority to manage NGP IX and NGP X, respectively to NGP Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these securities and therefore may also be deemed to be the beneficial owner of these securities.

(5)

Alpha Holdings is a wholly owned indirect subsidiary of Alpha Natural Resources, Inc., and as such, Alpha Natural Resources, Inc. will be deemed to be the beneficial owner of these securities. The mailing address for each of Alpha Holdings and Alpha Natural Resources Inc. is One Alpha Place, P.O. Box 16429, Bristol, Virginia.

(6)

Based solely on the Schedule 13G filed on June 16, 2014 by Citadel Advisors LLC, Citadel Advisors Holdings II LP, Citadel GP LLC and Mr. Kenneth Griffin reporting the beneficial ownership, shared power to vote or direct the vote, and shared power to dispose or direct the disposition of 7,014,188 shares of our common stock. The address for each of Citadel Advisors LLC, Citadel Advisors Holdings II LP, Citadel GP LLC and Mr. Kenneth Griffin is c/o Citadel LLC, 131 S. Dearborn Street, 32nd Floor, Chicago, Illinois 60603.

(7)	Includes 13,770 unvested restricted stock units.

(8)	Includes 13,770 unvested restricted stock units.

(9)	Includes 13,770 unvested restricted stock units.

(10)	Includes 12,049 unvested restricted stock units.

(11)	Includes 22,869 unvested restricted stock units.

(12)	Includes 12,694 unvested restricted stock units.

(13)	Includes an aggregate of 139,067 unvested restricted stock units granted to all directors and executive officers of the Company.

Equity Compensation Plans

At December 31, 2013, we had no securities authorized for issuance under equity compensation plans.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Historical Transactions with Affiliates

Since its inception, Rice Drilling B, our subsidiary, has issued additional membership interests as consideration for capital contributions received from Rice Appalachia. Capital contributions for the year ended December 31, 2013 and the year ended December 31, 2012 were $198.2 million and $113.0 million, respectively. Rice Appalachia made no capital contributions to Rice Drilling B for the year ended December 31, 2011 or for the nine months ended September 30, 2014.

The capital contributions made by Rice Appalachia were the result of capital contributions made to Rice Appalachia by the following individuals and entities:

 

•

Daniel J. Rice III: $0.2 million and $14.0 million for the years ended December 31, 2013 and 2012, respectively;

 

•

Rice Partners: $49.9 million for the year ended December 31, 2012; and

 

•

Natural Gas Partners $198.0 million and $99.0 million for the years ended December 31, 2013 and 2012, respectively.

In addition, Rice Drilling B paid legal fees of Natural Gas Partners totaling approximately $30 thousand and $0.4 million for the years ended December 31, 2013 and 2012, respectively, in connection with these transactions.

NGP received a put right with respect to their equity investment in Rice Drilling B (indirectly, through its investment in Rice Appalachia) which is contingently exercisable upon the occurrence of certain events. The earliest date that this put right could be exercised is January 25, 2017. The fair value of this put right is de minimis given the accretion in fair value of Rice Appalachia and this put right is no longer applicable following the completion of our IPO.

In prior periods, we reimbursed Rice Partners for expenses incurred on our behalf. General and administrative expenses incurred by Rice Partners and reimbursed by us were $9.3 million, $4.8 million and $3.1 million for the years ended December 31, 3013, 2012 and 2011, respectively. As of December 31, 2013 and 2012, $6.1 million and $2.5 million, respectively, of general and administrative expenses was due to Rice Partners and is recorded as due to affiliate on the consolidated balance sheet. This agreement was terminated prior to the closing of our IPO, and no general and administrative expenses incurred by Rice Partners were reimbursed us in the nine months ended September 30, 2014.

We are reimbursed for costs incurred on behalf of our Marcellus joint venture. General and administrative expenses incurred by us and reimbursed by our Marcellus joint venture were $1.6 million, $1.3 million and $0.0 million for the years ended December 31, 2013, 2012 and 2011, respectively, and no amounts were reimbursed by our Marcellus joint venture for the nine months ended September 30, 2014. As of December 31, 2012, we recorded a receivable from our Marcellus joint venture for $4.6 million representing leaseholds that were approved to be contributed to the joint venture. There was no such receivable as of December 31, 2013 or as of September 30, 2014.

In January 2010, Rice Energy Limited Partnership assigned its 100% membership interest in Rice Drilling C LLC (“Rice C”) to Rice Drilling B. At the date of the transfer of membership interest, Rice C’s assets consisted solely of approximately $0.9 million.

In November 2009, we entered into restricted unit agreements with an employee and certain consultants. Under separate and individual restricted unit agreements, the eligible employee and consultants were granted units which vest over a specified period of time. Each unit entitles the holder to an equity ownership in us. The restricted units are accounted for as liability awards, which require re-measurement each reporting period, as a

 

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result of the existence of a call option that permits us to repurchase the awards at a fixed amount that could be above or below fair market value of the units. Management established an estimated fair value for issued units based upon an income approach prior to December 31, 2013. At December 31, 2013, in connection with the IPO, a market approach was used. During the years ended December 31, 2013, 2012 and 2011 and the nine months ended September 30, 2014, $32.9 million, $0.0 million, $0.2 million and $0.0 million, respectively, of restricted unit expense was recognized for these awards. During 2012, Rice Appalachia, as the designee of Rice Drilling B, exercised the option to repurchase certain restricted units from a consultant. In connection with our IPO, the balance of the restricted units outstanding was exchanged for 1,728,852 shares of our common stock.

On October 28, 2009, we entered into a subordinated working capital promissory note payable to Daniel J. Rice III in the amount of $4.0 million. The note accrued interest at a rate of 1.20% and interest only is due at maturity on February 1, 2018. This note was converted to equity in January 2012.

On February 1, 2009, the terms of a $10.0 million subordinated related party promissory note payable to Daniel J. Rice III were modified. For accounting purposes, the cash flows of the promissory note were considered substantially different resulting in extinguishment accounting. There were no financing fees recorded for the promissory note. The fair value of the modified promissory note was compared to the carrying value of the original promissory note with the difference resulting in a capital contribution from the related party of $3.6 million. The fair value was estimated based upon an estimate of market rates at the inception of the promissory note. The discount was amortized over the life of the instruments using an effective interest rate of 4.6%. This note was converted to equity in January 2012.

Marcellus JV Buy-In Transaction Agreement

On January 29, 2014, in connection with the closing of our IPO and pursuant to the Transaction Agreement, we completed our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture to us in exchange for total consideration of $322 million, consisting of $100 million of cash and our issuance to Alpha Holdings of 9,523,810 shares of our common stock.

Registration Rights Agreement

In connection with the closing of our IPO, we entered into a registration rights agreement with Rice Holdings, Rice Partners, Daniel J. Rice III, NGP Holdings and Alpha Holdings, referred to herein as the Initial Holders. Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.

Demand Rights. Subject to the limitations set forth below, any Initial Holder (or their permitted transferees) has the right to require us by written notice to prepare and file a registration statement registering the offer and sale of a number of their shares of common stock. Generally, we are required to provide notice of the request within five business days following the receipt of such demand request to all additional holders of our common stock, who may, in certain circumstances, participate in the registration. In no event shall more than one demand registration occur during any six-month period or within 180 days (with respect to our IPO) or 90 days (with respect to any public offering other than our IPO) after the effective date of a final Annual Report we file. Further, we are not obligated to effect:

 

•

(i) through December 31, 2016, more than a total of three demand registrations or (ii) on or after January 1, 2017, more than a total of one demand registration per calendar year at the request of Rice Holdings;

 

•

more than one demand registration for Daniel J. Rice III;

 

•

(i) through December 31, 2016, more than a total of three demand registrations or (ii) on or after January 1, 2017, more than a total of one demand registration per calendar year at the request of NGP Holdings; or

 

•

more than one demand registration for Alpha Holdings.

 

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We are also not obligated to effect any demand registration in which the anticipated aggregate offering price included in such offering is less than $30 million. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. Any demand for an underwritten offering pursuant to an effective shelf registration statement shall constitute a demand request subject to the limitations set forth above. We will be required to maintain the effectiveness of any such registration statement until the earlier of 180 days (or two years if a “shelf registration” is requested) after the effective date and the consummation of the distribution by the participating holders.

Piggy-back Rights. If, at any time, we propose to register an offering of common stock (subject to certain exceptions) for our own account, then we must give at least five business days’ notice to all holders of registrable securities to allow them to include a specified number of their shares in that registration statement.

Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.

Stockholders’ Agreement

In connection with the closing of our IPO, we entered into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc. Pursuant to the stockholders’ agreement, we and our principal stockholders agreed to appoint individuals designated by the principal stockholders to our board of directors and nominate such persons for election at each annual meeting of our stockholders, subject to the following:

 

•

Rice Holdings has the right to nominate three members of our board of directors, provided that such number of nominees shall be reduced to two and zero if Rice Holdings and its affiliates, which includes Rice Energy Irrevocable Trust, collectively own less than 15% and 5%, respectively, of the outstanding shares of our common stock;

 

•

NGP Holdings has the right to nominate two members of our board of directors, provided that such number of nominees shall be reduced to one and zero if NGP Holdings and its affiliates collectively own less than 15% and 5%, respectively, of the outstanding shares of our common stock;

 

•

Alpha Natural Resources, Inc. has the right to nominate one member of our board of directors, provided that such number of nominees shall be reduced to zero if Alpha Natural Resources, Inc. and its affiliates collectively own less than 5% of the outstanding shares of our common stock.

The nominee designated by Alpha Natural Resources, Inc. must be either (i) the Chief Executive Officer of Alpha Natural Resources, Inc. at the time of designation or (ii) a member of senior management (with a title of Senior Vice President or greater) of Alpha Natural Resources, Inc. that is reasonably satisfactory to us.

The stockholders’ agreement also requires the stockholders party thereto to take all necessary actions, including voting their shares of common stock, for the election of the nominees designated by such principal stockholders. The stockholders’ agreement will terminate on the earlier of the date on which (i) none of our principal stockholders beneficially own at least 2.5% of our outstanding common stock and (ii) we receive written notice from each principal stockholder requesting the termination of the stockholders’ agreement. The stockholders’ agreement terminates with respect to a particular principal stockholder party thereto when such principal stockholder beneficially owns less than 2.5% of our outstanding common stock.

 

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DESCRIPTION OF NOTES

The new notes will be issued and the old notes were issued (in this section, together, the “Notes”) under an indenture dated as of April 25, 2014 (the “Indenture”) by and among itself, the Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”), in a private transaction that is not subject to the registration requirements of the Securities Act. The terms of the Notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939 (the “Trust Indenture Act”).

The following description is a summary of the material provisions of the Indenture and the Registration Rights Agreement. It does not restate those agreements in their entirety. The Company urges you to read the Indenture and the Registration Rights Agreement because they, and not this description, define the rights of Holders of the Notes. Copies of the Indenture and the Registration Rights Agreement are filed as exhibits to the registration statement of which this prospectus is a part.

You can find the definitions of certain terms used in this description under the subheadings “—Certain Definitions,” “—Principal, Maturity and Interest” and “—Registration Rights.” In this description, the word “Company” refers only to Rice Energy Inc. and not to any of its subsidiaries.

The registered holder of a Note will be treated as the owner of it for all purposes. Only registered holders of Notes have rights under the Indenture.

Brief Description of the Notes and Subsidiary Guarantees

The Notes

The Notes:

 

•

will be general unsecured senior obligations of the Company;

 

•

will be equal in right of payment to all existing and future senior Indebtedness of the Company;

 

•

will be effectively subordinate in right of payment to any secured Indebtedness of the Company to the extent of the collateral securing such Indebtedness, including Indebtedness under the Credit Agreement;

 

•

will be senior in right of payment to any future subordinated Indebtedness of the Company;

 

•

will be effectively subordinated to the Indebtedness of future subsidiaries that do not guarantee the Notes; and

 

•

will be guaranteed by the Guarantors.

The Subsidiary Guarantees

These Notes will be jointly and severally guaranteed by each of the Company’s Restricted Subsidiaries (other than RDB Real Estate Holdings LLC), and by any of its future Restricted Subsidiaries that guarantee Indebtedness of the Company or another Guarantor under a Credit Facility.

The Subsidiary Guarantees of the Notes:

 

•

will be general unsecured senior obligations of each Guarantor;

 

•

will be equal in right of payment to all existing and future senior Indebtedness of each Guarantor;

 

•

will be effectively subordinate in right of payment to any secured Indebtedness of each Guarantor to the extent of the collateral securing such Indebtedness, including Indebtedness of the Guarantors under the Credit Agreement; and

 

•

will be senior in right of payment to any future subordinated Indebtedness of each Guarantor.

 

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As of the Issue Date, all of the Company’s Subsidiaries were “Restricted Subsidiaries.” However, under the circumstances described below under the subheading “—Certain Definitions—Unrestricted Subsidiary,” the Company will be permitted to designate certain of its Subsidiaries as “Unrestricted Subsidiaries.” Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the Indenture and will not guarantee the Notes.

Principal, Maturity and Interest

The Company issued Notes with an aggregate principal amount of $900 million on April 25, 2014 (the “Initial Notes”). The Company may issue Additional Notes (“Additional Notes”) from time to time after this offering in an unlimited amount, without the consent of the Holders but subject to the provisions of the Indenture described below under the caption “—Certain Covenants—Incurrence of Indebtedness.” The Initial Notes and any Additional Notes subsequently issued under the Indenture, together with any Exchange Notes issued under the Registration Rights Agreement, will be treated as a single class for all purposes under the Indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. Unless otherwise provided or the context otherwise requires, for all purposes of the Indenture and this “Description of Notes”, references to the Notes include any Additional Notes and Exchange Notes actually issued.

The Company will issue Notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The Notes will mature on May 1, 2022.

Interest on the Notes accrues at the rate of 6.250% per year and will be payable semiannually in arrears on May 1 and November 1, commencing on November 1, 2014. The Company will make each interest payment to the Holders of record of the Notes on the immediately preceding April 15 and October 15.

Interest on the Notes accrues from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

The interest rate on the Notes is subject to increase if certain conditions specified by the Registration Rights Agreement are not satisfied, all as further described under the caption “—Registration Rights.” All references to interest on the Notes include any such additional interest that may be payable.

Methods of Receiving Payments on the Notes

If a Holder of not less than $5.0 million aggregate principal amount of any Notes held in definitive form has given wire transfer instructions to the Company, the Company will make all principal, premium and interest payments on those Notes in accordance with those instructions. All other payments on the Notes will be made at the office or agency of the Paying Agent unless the Company elects to make interest payments by check mailed to the Holders at their addresses set forth in the register of Holders.

The Company will make all principal, premium and interest payments on each Note in global form registered in the name of The Depository Trust Company (“DTC”) or its nominee in immediately available funds to DTC or its nominee, as the case may be, as the Holder of such global Note.

Paying Agent and Registrar for the Notes

The Trustee will initially act as Paying Agent and Registrar. The Company may change the Paying Agent or Registrar without prior notice to the Holders of the Notes, and the Company or any of its Subsidiaries may act as Paying Agent or Registrar.

Transfer and Exchange

A Holder may transfer or exchange Notes in accordance with the Indenture. The Registrar and the Trustee may require a Holder, among other things, to furnish appropriate endorsements and transfer documents and the

 

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Company may require a Holder to pay any taxes and fees required by law or permitted by the Indenture. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

The registered Holder of a Note will be treated as the owner of it for all purposes.

Subsidiary Guarantees

The Guarantors have jointly and severally guaranteed the Company’s obligations under the Notes on a senior unsecured basis. The obligations of each Guarantor under its Subsidiary Guarantee will be limited in a manner intended to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance under applicable laws, although no assurance can be given that a court would give the Holders the benefit of such a provision. Please read “Risk Factors—Risks Related to the Notes—Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from guarantors.”

Except in a transaction resulting in the release of a Subsidiary Guarantee of a Guarantor, the Company will not permit a Guarantor to consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another Person (other than the Company or another Guarantor) unless:

 

(1)

immediately after giving effect to that transaction, no Default or Event of Default shall have occurred and be continuing; and

 

(2)

the Person formed by or surviving any such consolidation or merger (if other than such Guarantor) assumes all the obligations of that Guarantor under its Subsidiary Guarantee pursuant to a supplemental indenture satisfactory to the Trustee.

The Subsidiary Guarantee of a Guarantor will be released in accordance with the applicable provisions of the Indenture:

 

(1)

in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) other than to the Company or another Guarantor, if such transaction as of the time of such disposition complies with the provisions of the Indenture described under the caption “—Repurchase at the Option of Holders—Asset Sales”;

 

(2)

in connection with any sale or other disposition of the Capital Stock of a Guarantor (including by way of merger or consolidation) other than to the Company or another Guarantor, if such transaction at the time of such disposition complies with the provisions of the Indenture described under the caption “—Repurchase at the Option of Holders—Asset Sales” and the Guarantor ceases to be a Restricted Subsidiary of the Company as a result of such transaction;

 

(3)

if the Company designates any Restricted Subsidiary that is a Guarantor as an Unrestricted Subsidiary in accordance with the provisions of the Indenture;

 

(4)

if the Company effects a Legal Defeasance or Covenant Defeasance as described under “—Legal Defeasance and Covenant Defeasance” or if it satisfies and discharges the Indenture as described under “—Satisfaction and Discharge”; or

 

(5)

unless a Default or Event of Default has occurred and is continuing, at such time as such Guarantor ceases to guarantee any other Indebtedness of the Company or any other Guarantor under a Credit Facility.

Optional Redemption

Prior to May 1, 2017, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of Notes (including any Additional Notes) originally issued prior to the redemption date under the Indenture in an amount not greater than the Net Cash Proceeds of one or more Equity Offerings, at a

 

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redemption price of 106.250% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date); provided that

 

(1)

at least 65% in aggregate principal amount of Notes (including any Additional Notes) originally issued under the Indenture remain outstanding immediately after the occurrence of such redemption (excluding Notes held by the Company and its Subsidiaries); and

 

(2)

each such redemption must occur within 180 days of the date of the closing of the related Equity Offering.

In addition, at any time prior to May 1, 2017, the Company may redeem all or part of the Notes at a redemption price equal to the sum of:

 

(i)

the principal amount thereof, plus

 

(ii)

the Make Whole Premium at the redemption date,

plus accrued and unpaid interest, if any, to the redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

On or after May 1, 2017, the Company may redeem all or a part of these Notes at any time or from time to time at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest, if any, to the applicable redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), if redeemed during the twelve-month period beginning on May 1 of the years indicated below:

 

Year		Percentage
2017			104.688	%
2018			103.125	%
2019			101.563	%
2020 and thereafter			100.000	%

Except pursuant to the preceding paragraphs, or as described below in the last paragraph under “—Repurchase at the Option of Holders—Change of Control,” the Notes will not be redeemable at the Company’s option prior to maturity.

Selection and Notice

If less than all of the Notes are to be redeemed at any time, the Trustee will select Notes for redemption as follows:

 

(1)

if the Notes are listed, in compliance with the requirements of the principal national securities exchange on which the Notes are listed; or

 

(2)

if the Notes are not so listed, on a pro rata basis (or, in the case of Notes in global form, the Notes represented thereby will be selected in accordance with DTC’s prescribed method).

Notes or portions of Notes the Trustee selects for redemption shall be in minimum amounts of $2,000 or a whole multiple of $1,000 in excess thereof. Notices of redemption shall be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each Holder of Notes to be redeemed at its registered address, except that notices of redemption may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the Notes or a satisfaction and discharge of the Indenture. Notices of redemption may be subject to one or more conditions precedent specified in the notice of redemption, including completion of an Equity Offering or other corporate transaction.

If any Note is to be redeemed in part only, the notice of redemption that relates to that Note shall state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed

 

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portion of the original Note will be issued in the name of the Holder thereof upon cancellation of the original Note. Notes called for redemption become due on the date fixed for redemption, subject to satisfaction of any conditions to the redemption. On and after the redemption date, interest will cease to accrue on Notes or portions of them called for redemption.

Mandatory Redemption; Offers to Purchase; Open Market Purchases

The Company is not required to make any mandatory redemption or sinking fund payments with respect to the Notes. However, under certain circumstances, the Company may be required to offer to purchase Notes as described under the captions “—Repurchase at the Option of Holders—Change of Control” and “—Asset Sales.” The Company may at any time and from time to time purchase Notes in the open market or otherwise.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, unless the Company has previously or concurrently exercised its right to redeem all of the Notes as described under “—Optional Redemption,” each Holder of Notes will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that Holder’s Notes pursuant to the offer described below (the “Change of Control Offer”). In the Change of Control Offer, the Company will offer a payment (the “Change of Control Payment”) in cash equal to 101% of the aggregate principal amount of Notes to be repurchased plus accrued and unpaid interest thereon, if any, to the date of purchase (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of purchase).

No later than 30 days following any Change of Control, the Company will mail a notice to each Holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase Notes on the Change of Control Payment Date specified in such notice, which date will be no earlier than 30 days nor later than 60 days from the date such notice is mailed, pursuant to the procedures required by the Indenture and described in such notice. The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the repurchase of the Notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the covenant described herein, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under this covenant by virtue of the Company’s compliance with such securities laws or regulations.

On the Change of Control Payment Date, the Company will, to the extent lawful:

 

(1)

accept for payment all Notes or portions thereof properly tendered pursuant to the Change of Control Offer;

 

(2)

deposit with the Paying Agent an amount equal to the Change of Control Payment in respect of all Notes or portions thereof so tendered; and

 

(3)

deliver or cause to be delivered to the Trustee the Notes so accepted together with an officers’ certificate stating the aggregate principal amount of Notes or portions thereof being purchased by the Company.

The Paying Agent will promptly mail to each Holder of Notes so tendered and not withdrawn the Change of Control Payment for such tendered Notes, with such payments to be made through the facilities of DTC for all Notes in global form, and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each Holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any, by such Holder; provided that each such new Note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess thereof.

 

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The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

The provisions described above that require the Company to make a Change of Control Offer following a Change of Control will be applicable regardless of whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the Holders of the Notes to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

The Credit Agreement currently treats certain change of control events with respect to the Company as an event of default entitling the lenders to terminate all further lending commitments, to accelerate all loans then outstanding and to exercise other remedies. The occurrence of a Change of Control may result in a default under future Indebtedness of the Company and its Subsidiaries, and give the lenders thereunder the right to require the Company to repay obligations outstanding thereunder. Moreover, the exercise by Holders of their right to require the Company to repurchase the Notes could cause a default under such future Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. The Company’s ability to repurchase Notes following a Change of Control also may be limited by the Company’s then existing financial resources.

The Company will not be required to make a Change of Control Offer upon a Change of Control if (1) a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Company and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer, (2) a notice of redemption for all outstanding Notes has been given, unless and until there is a default in payment of the applicable redemption price or (3) in connection with or in contemplation of any publicly announced Change of Control, the Company has made an offer to purchase (an “Alternate Offer”) any and all Notes validly tendered at a cash price equal to or higher than the Change of Control Payment and has purchased all Notes properly tendered in accordance with the terms of the Alternate Offer.

A Change of Control Offer or Alternate Offer may be made in advance of a Change of Control, and conditioned upon the occurrence of a Change of Control, if a definitive agreement is in place for the Change of Control at the time of making the Change of Control Offer or Alternate Offer.

The definition of Change of Control includes a phrase relating to the sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the assets of the Company and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of Notes to require the Company to repurchase such Notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Company and its Subsidiaries taken as a whole may be uncertain.

If Holders of not less than 90% in aggregate principal amount of the outstanding Notes validly tender and do not withdraw such Notes in a Change of Control Offer or Alternate Offer and the Company, or any other Person making a Change of Control Offer in lieu of the Company as described above, purchases all of the Notes validly tendered and not withdrawn by such Holders, the Company will have the right, upon not less than 30 nor more than 60 days’ prior notice, given not more than 30 days following such purchase pursuant to the Change of Control Offer described above, to redeem all Notes that remain outstanding following such purchase at a redemption price in cash equal to the applicable Change of Control Payment or Alternate Offering price, as applicable, plus, to the extent not included in the Change of Control Payment or Alternate Offer price, as applicable, accrued and unpaid interest, if any, to the date of redemption (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of purchase).

 

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Asset Sales

The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

 

(1)

the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of such Asset Sale at least equal to the Fair Market Value of the Equity Interests or other assets issued or sold or otherwise disposed of (which may be determined at the time of entering into any agreement with respect to such Asset Sale); and

 

(2)

(A) at least 75% of the aggregate consideration therefor received by the Company or such Restricted Subsidiary, as the case may be, from such Asset Sale and all other Asset Sales since the Issue Date, on a cumulative basis, is in the form of cash, Cash Equivalents or assets of the type referred to in clauses (2) or (3) of the next succeeding paragraph, or any combination of the foregoing (together, “Permitted Consideration”) or (B) the Fair Market Value of all forms of consideration other than Permitted Consideration since the Issue Date does not exceed in the aggregate 10% of the ACNTA of the Company at the time when such determination is made. For purposes of this provision, each of the following shall be deemed to be cash:

 

(a)

any liabilities (as shown on the Company’s or such Restricted Subsidiary’s most recent balance sheet) of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the Notes or any Subsidiary Guarantee) that are assumed by the transferee of any such assets pursuant to a novation agreement or similar agreement that releases the Company or such Restricted Subsidiary from further liability;

 

(b)

with respect to any Asset Sale of properties used or useful in the Oil and Gas Business by the Company or any of its Restricted Subsidiaries where the Company or such Restricted Subsidiary retains an interest in such property, the amount of the costs and expenses of the Company or such Restricted Subsidiary related to the exploration, development, completion or production of such properties and activities related thereto which the transferee (or an Affiliate thereof) agrees to pay;

 

(c)

Indebtedness (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or a Guarantee) of any Restricted Subsidiary that is no longer a Restricted Subsidiary as a result of such Asset Sale; provided that the Company and each other Restricted Subsidiary are released from any Guarantee of such Indebtedness in connection with such Asset Sale;

 

(d)

any securities, notes or other obligations received by the Company or any such Restricted Subsidiary from such transferee that are converted within 180 days by the Company or such Restricted Subsidiary into cash (to the extent of the cash received in that conversion); and

 

(e)

solely in the case of any Asset Sale of Midstream Assets, Permitted MLP Securities.

Notwithstanding the foregoing, in the case of any Asset Sale pursuant to a condemnation, appropriation or similar taking, including by deed in lieu of condemnation, such Asset Sale shall not be required to satisfy the requirements of clauses (1) and (2) above.

Within the later of (x) one year after the date of receipt of any Net Proceeds from an Asset Sale and (y) six months after the date of an agreement entered into within such one-year period committing the Company or Restricted Subsidiary to make an acquisition or expenditure referred to in clauses (2) or (3) below, the Company or a Restricted Subsidiary may apply such Net Proceeds at its option, in any one or more of the following:

 

(1)

to repay, prepay, redeem or repurchase any Indebtedness of the Company or any Restricted Subsidiary (other than Subordinated Indebtedness);

 

(2)

to acquire all or substantially all of the assets of, or a majority of the Voting Stock of, a Company principally engaged in the Oil and Gas Business that will, upon such acquisition, become a Restricted Subsidiary or acquire any minority interest in a Restricted Subsidiary; or

 

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(3)

to make capital expenditures or to acquire properties or assets, in each case that are used or useful in the Oil and Gas Business.

Pending the final application of any such Net Proceeds, the Company may temporarily reduce revolving credit borrowings or otherwise invest such Net Proceeds in any manner not prohibited by the Indenture.

Any Net Proceeds from Asset Sales that are not applied or invested as provided in the preceding paragraph will constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $25.0 million, the Company will make an offer (the “Asset Sale Offer”) to all Holders of Notes and, to the extent required by the terms thereof, all holders of other Indebtedness that is pari passu in right of payment with the Notes containing provisions similar to those set forth in the Indenture with respect to offers to purchase or redeem with the proceeds of sales of assets to purchase the maximum principal amount of Notes and such other pari passu Indebtedness that may be purchased out of the Excess Proceeds. The offer price with respect to the Notes in any Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of purchase), and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, the Company may use such Excess Proceeds for any purpose not otherwise prohibited by the Indenture. If the aggregate principal amount of Notes and such other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the Trustee shall select the Notes and such other pari passu Indebtedness to be purchased on a pro rata basis, on the basis of the aggregate principal amounts tendered in round denominations (which in the case of the Notes will be minimum denominations of $2,000 principal amount or multiples of $1,000 in excess thereof). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds shall be reset at zero.

The Company will publicly announce the results of the Asset Sale Offer on or as soon as practicable after the date such Asset Sale Offer is completed.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the provisions of the covenant described herein, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under this covenant by virtue of the Company’s compliance with such securities laws or regulations.

Certain Covenants

Restricted Payments

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

 

(1)

declare or pay any dividend or make any other payment or distribution on account of the Company’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment by the Company or any Restricted Subsidiary in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company or to the Company or a Restricted Subsidiary of the Company);

 

(2)

purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company or any direct or indirect parent of the Company (other than any such Equity Interests owned by the Company or any Restricted Subsidiary of the Company);

 

(3)

make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity or scheduled sinking fund payment, any Subordinated Indebtedness

 

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of the Company or any Guarantor, except (a) a payment of interest or principal on or after the date when due or within three Business Days prior thereto, (b) in anticipation of satisfying a sinking fund obligation, principal installment payment or payment due at final maturity, in each case due within one year of the date of such payment, purchase or other acquisition or retirement or (c) payments on Indebtedness owed to the Company or a Restricted Subsidiary; or

 

(4)

make any Investment other than a Permitted Investment (all such payments and other actions set forth in clauses (1) through (3) above and this clause (4) being collectively referred to as “Restricted Payments”),

unless, at the time of and after giving effect to such Restricted Payment:

 

(1)

no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof;

 

(2)

the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “—Incurrence of Indebtedness;” and

 

(3)

such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Restricted Subsidiaries after the Issue Date (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (6), (7), (8), (9), (10), (11), (12) or (13) of the next succeeding paragraph, but including Restricted Payments permitted by clause (1) of such paragraph), is less than the sum, without duplication, of:

 

(a)

50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from April 1, 2014 to the end of the Company’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit); plus

 

(b)

100% of the aggregate Net Cash Proceeds and 100% of the Fair Market Value of securities or other property other than cash (including Capital Stock of Persons engaged in the Oil and Gas Business or assets used in the Oil and Gas Business) received by the Company or a Restricted Subsidiary since the Issue Date from the issue or sale of Equity Interests of the Company (other than Disqualified Stock), other than Equity Interests sold to a Subsidiary of the Company or to an employee stock ownership plan or to a trust established by the Company or any of its Subsidiaries for the benefit of their employees; plus

 

(c)

the amount by which Indebtedness is reduced on the Company’s consolidated balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (plus the amount of any accrued interest then outstanding on such Indebtedness to the extent the obligation to pay such interest is extinguished less the amount of any cash, or the Fair Market Value of any property (as determined in good faith by an officer of the Company), distributed by the Company upon such conversion or exchange); provided, however, that the foregoing amount shall not exceed the Net Cash Proceeds received by the Company or any Restricted Subsidiary from the sale of such Indebtedness (excluding Net Cash Proceeds from sales to a Subsidiary of the Company or to an employee stock ownership plan or to a trust established by the Company or any of its Subsidiaries for the benefit of their employees); plus

 

(d)

an amount equal to the sum of (i) the net reduction in the Investments (other than Permitted Investments) made by the Company or any Restricted Subsidiary in any Person resulting from repurchases, repayments or redemptions of such Investments by such Person, proceeds realized on

 

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the sale of such Investments and proceeds representing the return of capital (excluding dividends and distributions to the extent included in Consolidated Net Income), in each case received by the Company or any Restricted Subsidiary since the Issue Date, and (ii) to the extent such Person is an Unrestricted Subsidiary, the portion (proportionate to the Company’s equity interest in such Subsidiary) of the Fair Market Value of the net assets of such Unrestricted Subsidiary at the time such Unrestricted Subsidiary is designated a Restricted Subsidiary; provided, however, that to the extent the foregoing sum exceeds, in the case of any such Person or Unrestricted Subsidiary, the amount of Investments (excluding Permitted Investments) previously made (and treated as a Restricted Payment) by the Company or any Restricted Subsidiary in such Person or Unrestricted Subsidiary since the Issue Date, such excess shall not be included in this clause (d) unless the amount represented by such excess has not been and will not be taken into account in one of the foregoing clauses (a)-(c).

The preceding provisions will not prohibit:

 

(1)

the payment of any dividend or the consummation of any redemption within 60 days after the date of declaration or giving of redemption notice, as the case may be, thereof, if at said date of declaration or notice such payment would have complied with the provisions of the Indenture (and such payment shall be deemed to be paid on the date of payment for purposes of any calculation required by this covenant);

 

(2)

any Restricted Payment made in exchange for, or out of the Net Cash Proceeds of the substantially concurrent sale (other than to a Subsidiary of the Company) of, Equity Interests of the Company (other than Disqualified Stock), with any such payment being deemed to be “substantially concurrent” if made within 180 days of the sale of the Equity Interests in question; provided that the amount of any such Net Cash Proceeds that are utilized for any such redemption, repurchase, retirement, defeasance or other acquisition shall be excluded from clause (3)(b) of the preceding paragraph;

 

(3)

the defeasance, redemption, repurchase, retirement or other acquisition of any Subordinated Indebtedness of the Company or any Guarantor with the Net Cash Proceeds from an incurrence of any Permitted Refinancing Indebtedness permitted to be incurred under the caption “—Incurrence of Indebtedness”;

 

(4)

the payment of any dividend or other distribution by a Restricted Subsidiary of the Company to the holders of its common Equity Interests on a pro rata basis or on a basis more favorable to the Company or any Restricted Subsidiary;

 

(5)

the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company held by any employees, former employees, directors or former directors of Company or any of its Restricted Subsidiaries (or heirs, estates or other permitted transferees of such employees or directors) pursuant to any agreements (including employment agreements), management equity subscription agreements or stock option agreements or plans (or amendments thereto), approved by the Board of Directors, under which such individuals purchase or sell or are granted the right to purchase or sell shares of Capital Stock; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests shall not exceed $15.0 million in any calendar year, with unused amounts in any calendar year being permitted to be carried over to succeeding calendar years subject to a maximum of $30.0 million in any calendar year; provided, further, however, that such amount in any calendar year may be increased by an amount not to exceed;

 

(a)

the cash proceeds received by the Company or any of the Restricted Subsidiaries from the sale of Equity Interests (other than Disqualified Stock) of the Company or any direct or indirect parent of the Company (to the extent contributed to the Company) to members of management, directors, managers or consultants of the Company and the Restricted Subsidiaries or any direct or indirect parent of the Company that occurs after the Issue Date (provided that the amount of such cash

 

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proceeds utilized for any such repurchase, retirement, other acquisition or dividend will not increase the amount available for Restricted Payments under clause (3)(b) of the preceding paragraph), plus

 

(b)

the cash proceeds of key man life insurance policies received by the Company or any direct or indirect parent of the Company (to the extent contributed to the Company) or the Restricted Subsidiaries after the Issue Date;

provided that the Company may elect to apply all or any portion of the aggregate increase contemplated by clauses (a) and (b) above in any calendar year; and provided, further, that cancellation of Indebtedness owing to the Company or any Restricted Subsidiary from any present or former employees, directors, managers, officers or consultants of the Company, any Restricted Subsidiary or the direct or indirect parents of the Company in connection with a repurchase of Equity Interests of the Company or any of its direct or indirect parents will not be deemed to constitute a Restricted Payment for purposes of this covenant or any other provision of the Indenture;

 

(6)

loans or advances to employees of the Company or employees or directors of any Subsidiary of the Company, in each case as permitted by Section 402 of the Sarbanes-Oxley Act of 2002, the proceeds of which are used to purchase Capital Stock of the Company, or to refinance loans or advances made pursuant to this clause (6), in an aggregate amount not in excess of $2.0 million at any one time outstanding;

 

(7)

repurchases or other acquisitions for value of Capital Stock deemed to occur upon the exercise or exchange of stock options, warrants or other convertible securities if such Capital Stock represents a portion of the exercise or exchange price thereof or made in lieu of withholding taxes in connection with any such exercise or exchange;

 

(8)

upon the occurrence of a Change of Control or an Asset Sale and within 60 days after the completion of the offer to repurchase the Notes under the covenants described under “—Repurchase at the Option of Holders—Change of Control” or “—Asset Sales” above (including the purchase of all Notes tendered and required to be purchased), any purchase, repurchase, redemption, defeasance, acquisition or other retirement for value of Subordinated Indebtedness required under the terms thereof as a result of such Change of Control or Asset Sale at a purchase or redemption price not to exceed 101% of the outstanding principal amount thereof, plus accrued and unpaid interest thereon, if any, provided that, in the notice to Holders relating to a Change of Control or Asset Sale hereunder, the Company shall describe this clause (8);

 

(9)

the purchase by the Company of fractional shares arising out of stock dividends, splits or business combinations or conversion of convertible or exchangeable securities of debt or equity issued by the Company;

 

(10)

payments to dissenting stockholders (x) pursuant to applicable law or (y) in connection with the settlement or other satisfaction of legal claims made pursuant to or in connection with a consolidation, merger or transfer of assets in connection with a transaction that is not prohibited by the Indenture;

 

(11)

dividends on Disqualified Stock of the Company or preferred stock of any Restricted Subsidiary if such dividends are included in the calculation of Fixed Charges;

 

(12)

payments made by any Person other than the Company or any Restricted Subsidiary to the stockholders of the Company in connection with or as part of (a) a merger or consolidation of the Company with or into such Person or a subsidiary of such Person, or (b) a merger of a subsidiary of such Person into the Company; or

 

(13)

other Restricted Payments not to exceed $30.0 million in the aggregate since the Issue Date.

The amount of all Restricted Payments (other than cash) shall be the Fair Market Value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The Fair Market Value of any

 

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assets or securities other than cash that are required to be valued by this covenant will be determined, in the case of amounts in excess of $20.0 million, by an officer of the Company and, in the case of amounts in excess of $50.0 million, by the Board of Directors of the Company whose resolution with respect thereto will be delivered to the Trustee.

For purposes of determining compliance with this covenant, if a Restricted Payment meets the criteria of more than one of the types of Restricted Payments described in clauses (1)-(14) above or pursuant to the first paragraph of this covenant, the Company, in its sole discretion, may order and classify, and subsequently reorder and reclassify, such Restricted Payment in any manner in compliance with this covenant.

Incurrence of Indebtedness

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, Guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt); provided, however, that the Company and any Restricted Subsidiary may incur Indebtedness (including Acquired Debt), if the Fixed Charge Coverage Ratio for the Company’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred would have been at least 2.0 to 1, determined on a pro forma basis (including a pro forma application of the Net Cash Proceeds therefrom), as if the additional Indebtedness had been incurred at the beginning of such four-quarter period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Indebtedness”):

 

(1)

the incurrence by the Company and any Guarantor of Indebtedness under one or more Credit Facilities; provided that the aggregate principal amount of all Indebtedness incurred under this clause (1) and outstanding at any time does not exceed an amount equal to the greater of (a) $500.0 million and (b) the sum of (x) $250.0 million and (y) 35.0 % of ACNTA at the time of incurrence;

 

(2)

the incurrence by the Company and its Restricted Subsidiaries of Existing Indebtedness (other than Indebtedness described under clauses (1), (3) or (6) of this paragraph);

 

(3)

the incurrence by the Company and the Guarantors of Indebtedness represented by (a) the Initial Notes, (b) any Exchange Notes issued pursuant to the Registration Rights Agreement in exchange for the Notes, and (c) any Subsidiary Guarantees;

 

(4)

the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings, industrial revenue bonds, purchase money obligations or other Indebtedness or preferred stock, or synthetic lease obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of design, development, construction, installation or improvement of property (real or personal and including Capital Stock), plant or equipment used in the business of the Company or any of its Restricted Subsidiaries (in each case, whether through the direct purchase of such assets or the Equity Interests of any Person owning such assets), in an aggregate principal amount, taken together with Permitted Refinancing Indebtedness in respect thereof, that does not exceed the greater of $75.0 million and 7.5% of ACNTA at the time of incurrence;

 

(5)

the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the Net Cash Proceeds of which are used to refund, refinance, replace, defease or discharge Indebtedness (other than intercompany Indebtedness) that was permitted by the Indenture to be incurred under the first paragraph of this covenant or clauses (2), (3), (4), (12) or (15) or this clause (5) of this paragraph;

 

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(6)

the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries; provided, however, that:

 

(a)

(i) if the Company is the obligor on such Indebtedness and the obligee is not a Guarantor, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all obligations with respect to the Notes, and (ii) if a Guarantor is the obligor of such Indebtedness and the obligee is neither the Company nor a Guarantor, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all obligations of such Guarantor with respect to its Subsidiary Guarantee; and

 

(b)

(i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary thereof and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either the Company or a Restricted Subsidiary thereof, shall be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause;

 

(7)

in-kind obligations relating to net oil and natural gas balancing positions arising in the ordinary course of business;

 

(8)

any obligations in respect of completion bonds, performance bonds, bid bonds, appeal bonds, surety bonds, bankers acceptances, letters of credit, insurance obligations or bonds and other similar bonds and obligations incurred by the Company or any Restricted Subsidiary in the ordinary course of business and any Guarantees or letters of credit functioning as or supporting any of the foregoing bonds or obligations;

 

(9)

any obligation (including deferred premiums) under Interest Rate Agreements, Currency Agreements and Commodity Agreements; provided, that such Interest Rate Agreements, Currency Agreements and Commodity Agreements are entered into for bona fide hedging purposes of the Company or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of the Company);

 

(10)

any obligation arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, Guarantee, adjustment of purchase price, holdback, contingency payment obligation based on the performance of the acquired or disposed asset or similar obligations, in each case, incurred or assumed in connection with the acquisition or disposition of any business, asset or Capital Stock;

 

(11)

any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business, provided, however, that such Indebtedness is extinguished within five Business Days of incurrence;

 

(12)

the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Acquisition Indebtedness;

 

(13)

any Guarantee of Indebtedness of the Company or a Restricted Subsidiary to the extent that the guaranteed Indebtedness was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is subordinated or pari passu with the Notes, the Guarantee must be subordinated or pari passu, as applicable, to the same extent as the Indebtedness guaranteed;

 

(14)

Indebtedness incurred on behalf of, or representing guarantees of Indebtedness of, Persons other than the Company or any Restricted Subsidiaries in which the Company or a Restricted Subsidiary has an Investment; provided, however, that the aggregate principal amount of Indebtedness incurred under this clause (14), when aggregated with the principal amount of all other Indebtedness then outstanding and incurred pursuant to this clause (14), does not exceed the greater of $50.0 million and 5.0% of ACNTA at the time of incurrence; and

 

(15)

the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness in addition to Indebtedness permitted by clauses (1) through (14) above or the first paragraph above in an aggregate

 

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principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (15), not to exceed the greater of (a) $75.0 million and (b) 5.0% of the Company’s ACNTA, determined as of the date of incurrence of such Indebtedness after giving effect to such incurrence and the application of the proceeds therefrom.

For purposes of determining compliance with this “Indebtedness” covenant:

 

(1)

in the event that an item of proposed Indebtedness meets the criteria of more than one of the categories of Permitted Indebtedness described in clauses (1) through (15) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to classify such item of Indebtedness (or any portion thereof) on the date of its incurrence and, subject to clause (2) below, may later reclassify such items of Indebtedness (or any portion thereof), in any manner that complies with this covenant, and only be required to include the amount and type of such Indebtedness in one of such clauses or may include the amount and type of such Indebtedness partially in one such clause and partially in one or more other such clauses;

 

(2)

all Indebtedness outstanding on the Issue Date under the Credit Agreement after giving effect to the offering and the use of proceeds of the Initial Notes thereof shall be deemed initially incurred on the Issue Date under clause (1) of the second paragraph of this covenant and not the first paragraph or clause (2) of the second paragraph of this covenant;

 

(3)

Guarantees of, or obligations in respect of letters of credit relating to, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;

 

(4)

the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP;

 

(5)

Indebtedness of any Person existing at the time such Person becomes a Restricted Subsidiary shall be deemed to have been incurred by the Company and the Restricted Subsidiary at the time such Person becomes a Restricted Subsidiary; and

 

(6)

the accrual of interest or dividends, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, the reclassification of preferred equity as Indebtedness due to a change in accounting principles, the payment of dividends on Disqualified Stock or preferred equity in the form of additional shares of the same class of Disqualified Stock or preferred equity will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock or preferred equity for purposes of this covenant.

For purposes of determining compliance with any U.S. dollar-denominated restriction on the incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-dominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-dominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Permitted Refinancing Indebtedness, if incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Permitted Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

 

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Liens

The Company will not, and will not permit any of its Restricted Subsidiaries to create, incur, assume or suffer to exist any Lien on any property or asset now owned or hereafter acquired, except Permitted Liens, to secure (a) any Indebtedness of the Company unless prior to, or contemporaneously therewith, the Notes are equally and ratably secured for so long as such other Indebtedness is so secured, or (b) any Indebtedness of any Guarantor, unless prior to, or contemporaneously therewith, the Subsidiary Guarantee of such Guarantor is equally and ratably secured for so long as such other Indebtedness is so secured; provided, however, that if such Indebtedness is expressly subordinated to the Notes or a Subsidiary Guarantee, the Lien securing such Indebtedness will be subordinated and junior to the Lien securing the Notes or such Subsidiary Guarantee, as the case may be, with the same relative priority as such Indebtedness has with respect to the Notes or such Subsidiary Guarantee.

Dividend and Other Payment Restrictions Affecting Subsidiaries

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

 

(a)

pay dividends or make any other distributions on its Capital Stock to the Company or any of the Company’s Restricted Subsidiaries, or pay any Indebtedness owed to the Company or any of the Company’s Restricted Subsidiaries (it being understood that the priority of any preferred stock in receiving dividends, distributions or liquidating distributions prior to dividends, distributions or liquidating distributions being paid on Capital Stock shall not be deemed a restriction on the ability to make distributions on Capital Stock);

 

(b)

make loans or advances to the Company or any of the Company’s Restricted Subsidiaries (it being understood that the subordination of loans or advances made to the Company or any of its Restricted Subsidiaries to other Indebtedness incurred by the Company or any of its Restricted Subsidiaries shall not be deemed a restriction on the ability to make loans or advances); or

 

(c)

transfer any of its properties or assets to the Company or any of the Company’s Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

 

(1)

agreements existing on the Issue Date, including the Credit Agreement as in effect on the Issue Date and the Indenture;

 

(2)

any instrument governing Indebtedness or Capital Stock of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired, provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the Indenture to be incurred;

 

(3)

any agreement for the sale or other disposition of Capital Stock or assets of a Restricted Subsidiary that restricts distributions by such Restricted Subsidiary pending such sale or other disposition;

 

(4)

any amendment, restatement, modification, supplement, extension, renewal, refunding, replacement or refinancing of Indebtedness referred to in clauses (1) or (2), provided that the encumbrances or restrictions contained in the agreements governing the foregoing are not materially more restrictive, taken as a whole, than those contained in the agreements governing such Indebtedness as determined in good faith by the Company;

 

(5)

cash or other deposits, or net worth requirements or similar requirements, imposed by suppliers, landlords or customers or required by insurance, security or bonding companies, or restrictions on cash or other deposits by parties under agreements entered into in the ordinary course of the Oil and Gas Business of the types described in the definition of Permitted Business Investments;

 

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(6)

any applicable law, rule, regulation, order, approval, license, permit or similar restriction;

 

(7)

provisions limiting the disposition or distribution of assets or property or transfer of Capital Stock in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements, limited liability company organizational documents, and other similar agreements entered into in the ordinary course of business, consistent with past practice or with the approval of the Company’s Board of Directors or any of its officers, which limitation is applicable only to the assets, property or Capital Stock that are the subject of such agreements;

 

(8)

any encumbrance or restriction contained in the terms of any Indebtedness or Capital Stock permitted to be incurred under the Indenture or any agreement pursuant to which such Indebtedness was incurred if either (x) in the case of Indebtedness, the encumbrance or restriction applies only in the event of a payment default or a default with respect to a financial covenant in such Indebtedness or agreement or (y) the Company determines that any such encumbrance or restriction either (i) will not materially affect the Company’s ability to make principal or interest payments on the Notes and such restrictions are not materially less favorable to Holders of Notes than is customary in comparable financings or (ii) are not materially more restrictive, taken as a whole, with respect to any Restricted Subsidiary than those in effect on the Issue Date with respect to that Restricted Subsidiary pursuant to agreements in effect on the Issue Date or those contained in the Indenture or the Credit Agreement, in each case as determined in good faith by the Board of Directors or an officer of the Company; and

 

(9)

with respect to clause (c) of the preceding paragraph only, any of the following encumbrances or restrictions:

 

(a)

purchase money obligations for property acquired in the ordinary course of business or otherwise permitted under the Indenture that impose restrictions on the property so acquired;

 

(b)

Permitted Liens or Liens securing Indebtedness otherwise permitted to be incurred pursuant to the provisions of the covenant described above under the caption “—Liens” that limit the right of the Company or any of its Restricted Subsidiaries to dispose of the assets subject to such Lien;

 

(c)

restrictions contained in asset sale agreements limiting the transfer of such assets pending the closing of such sale;

 

(d)

restrictions on the subletting, assignment or transfer of any property or asset that is subject to a lease, license, sub-license or similar contract, or on the assignment or transfer of any such lease, license, sub-license or other contract;

 

(e)

agreements governing Hedging Obligations entered into in the ordinary course of business; and

 

(f)

customary restrictions on the disposition or distribution of assets or property in agreements entered into in the ordinary course of the Oil and Gas Business of the types described in the definition of Permitted Business Investments.

Merger, Consolidation or Sale of Assets

The Company may not: (1) consolidate or merge with or into another Person (whether or not the Company is the surviving corporation); or (2) sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the properties or assets of the Company and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:

 

(1)

either:

 

(a)

the Company is the surviving corporation; or

 

(b)

the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made is a Person existing under the laws of the United States, any state thereof or the District of Columbia;

 

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(2)

the Person formed by or surviving any such consolidation or merger (if other than the Company) or the Person to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made assumes all the obligations of the Company under the Notes and the Indenture pursuant to a supplemental indenture reasonably satisfactory to the Trustee;

 

(3)

immediately after such transaction no Default or Event of Default exists;

 

(4)

either (a) the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company) would, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four- quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Certain Covenants—Incurrence of Indebtedness” or (b) immediately after giving effect to such transaction on a pro forma basis and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, the Fixed Charge Coverage Ratio of the Company is equal to or greater than the Fixed Charge Coverage Ratio of the Company immediately before such transaction; and

 

(5)

the Company has delivered to the Trustee an officers’ certificate and an Opinion of Counsel, each stating that such consolidation, merger or disposition and such supplemental indenture (if any) comply with the Indenture and all conditions precedent therein relating to such transaction have been satisfied.

The surviving or transferee Person in any of the above transactions (if not the Company) will succeed to, and be substituted for the Company under the Indenture and the Notes and the Company (if not the surviving Person) will be fully released from its obligations under the Indenture and the Notes, except in the case of a lease of all or substantially all of its assets.

For purposes of this covenant, the sale, assignment, transfer, lease, conveyance or other disposition of all or substantially all of the properties or assets of one or more Subsidiaries of the Company, which properties or assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the properties or assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties or assets of the Company.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

Clauses (3) and (4) of this “Merger, Consolidation or Sale of Assets” covenant will not apply to a sale, assignment, transfer, conveyance or other disposition of assets between or among the Company and any of its Restricted Subsidiaries that are Guarantors.

Transactions with Affiliates

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or Guarantee with, or for the benefit of, any Affiliate (each, an “Affiliate Transaction”) involving aggregate consideration to or from the Company or a Restricted Subsidiary in excess of $5.0 million, unless:

 

(1)

such Affiliate Transaction is on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that could reasonably be expected to be obtained at the time of such transaction in arm’s-length dealings by the Company or such Restricted Subsidiary with a Person that is not an Affiliate or, if in the good faith judgment of the Company, no comparable transaction is available with which to compare such Affiliate Transaction, such Affiliate Transaction is otherwise fair to the Company or such Restricted Subsidiary from a financial point of view; and

 

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(2)

(a) the Company delivers to the Trustee with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration to or from the Company or a Restricted Subsidiary in excess of $20.0 million, an officers’ certificate certifying that such Affiliate Transaction complies with the requirements of clause (1) above, and (b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration to or from the Company or a Restricted Subsidiary in excess of $50.0 million, a majority of the Disinterested Members of the Board of Directors, if any, (or, if there is only one Disinterested Member, such Disinterested Member) have determined that the criteria set forth in clause (1) are satisfied with respect to such Affiliate Transaction(s) and have approved such Affiliate Transaction(s), as evidenced by a resolution delivered to the Trustee and certified by an officers’ certificate as having been adopted by the Board of Directors.

The following items shall not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

 

(1)

any employment or severance agreement or other employee, consulting, service, termination or director compensation agreement, arrangement or plan, (or any amendment thereto with respect thereto), or indemnification agreements, entered into by the Company or any Restricted Subsidiary with officers and employees of the Company or any Restricted Subsidiary thereof and the payment of compensation to officers and employees of the Company or any Restricted Subsidiary thereof (including amounts paid pursuant to employee benefit plans, employee stock option or similar plans), so long as such agreement or payment is in the ordinary course of business or has been approved by a majority of the Disinterested Members of the Board of Directors (or, if there is only one Disinterested Member, such Disinterested Member);

 

(2)

transactions between or among the Company and/or its Restricted Subsidiaries;

 

(3)

Restricted Payments that, in each case, are permitted by the provisions of the Indenture described above under the caption “—Restricted Payments” or Permitted Investments;

 

(4)

loans or advances to employees, officers or directors in the ordinary course of business of the Company or any of its Restricted Subsidiaries, in each case only as permitted by Section 402 of the Sarbanes- Oxley Act of 2002, but in any event not to exceed $2.0 million in the aggregate outstanding at any one time;

 

(5)

any transactions undertaken pursuant to any contracts in existence on the Issue Date (as in effect on the Issue Date) and any renewals, replacements or modifications of such contracts (pursuant to new transactions or otherwise) on terms no less favorable to the holders of the Notes than those in effect on the Issue Date;

 

(6)

in the case of (i) contracts for (A) drilling or other oil-field services or supplies, (B) the sale, storage, gathering or transport of hydrocarbons or (C) the lease or rental of office or storage space or (ii) other operation-type contracts, any such contracts that are entered into in the ordinary course of business on terms substantially similar to those contained in similar contracts entered into by the Company or any Restricted Subsidiary and third parties or, if neither the Company nor any Restricted Subsidiary has entered into a similar contract with a third party, that the terms are on the whole not materially less favorable than those that would be reasonably expected to be available from third parties on an arm’s-length basis, as determined in good faith by the Company;

 

(7)

transactions with a Person (other than an Unrestricted Subsidiary) that is an Affiliate of the Company solely because the Company owns, directly or through a Subsidiary, an Equity Interest in, or controls, such Person;

 

(8)

any sale or other issuance of Equity Interests (other than Disqualified Stock) of the Company to, or receipt of a capital contribution from, an Affiliate (or a Person that becomes an Affiliate) of the Company;

 

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(9)

any transaction in which the Company or any of its Restricted Subsidiaries, as the case may be, deliver to the Trustee a letter from an accounting, appraisal or investment banking firm of national standing stating that such transaction meets the requirements of clause (1) of the first paragraph of this covenant;

 

(10)

any Transaction between the Company or any Restricted Subsidiary on the one hand and any Person deemed to be an Affiliate solely because a director of such Person is also a director of the company or a Restricted Subsidiary, on the other hand; provided that such director abstains from voting as a director of the Company or the Restricted Subsidiary, as applicable, in connection with the approval of the transaction; and

 

(11)

Transactions with customers, clients, suppliers or purchasers or sellers of goods or services, in each case in the ordinary course of the business of the Company and its Restricted Subsidiaries and otherwise in compliance with the Indenture; provided that such Transactions are on terms substantially similar to those obtained by the Company or any Restricted Subsidiary in similar Transactions with third parties or, if neither the Company nor any Restricted Subsidiary has entered into a similar Transaction with a third party, that are on the whole not materially less favorable than those that would be reasonably expected to be available from third parties on an arm’s-length basis, as determined in good faith by the Company.

Additional Subsidiary Guarantees

If, after the Issue Date, any Restricted Subsidiary of the Company that is not already a Guarantor guarantees any Indebtedness of the Company or any Guarantor under a Credit Facility, then that Subsidiary will become a Guarantor by executing a supplemental indenture and delivering it to the Trustee within 30 days of the date on which it guaranteed such Indebtedness. Any such guarantee shall be subject to release as described under “—Subsidiary Guarantees.”

Business Activities

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except to such extent as would not be material in the opinion of the Board of Directors (which opinion shall be reasonable and made in good faith) to the Company and its Restricted Subsidiaries taken as a whole.

Reports

Whether or not required by the SEC, so long as any Notes are outstanding, the Company will furnish to the Holders of Notes, within the time periods specified in the SEC’s rules and regulations:

 

(1)

all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if the Company were required to file such Forms, including a section on “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual information only, a report on the annual financial statements by the Company’s certified independent public accountants; and

 

(2)

all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports.

If the Company has designated as an Unrestricted Subsidiary any of its Subsidiaries that is a Significant Subsidiary (or that, taken together with other Unrestricted Subsidiaries, would be a Significant Subsidiary), then the quarterly and annual financial information required by the preceding paragraph shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

 

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The availability of the foregoing materials on the SEC’s website or on the Company’s website shall be deemed to satisfy the foregoing delivery obligations.

In the event that any direct or indirect parent company of the Company becomes a guarantor of the Notes, the Company may satisfy its obligations in this covenant with respect to financial information relating to the Company by furnishing financial information relating to such parent company; provided that the same is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such parent, on the one hand, and the information relating to the Company and its Subsidiaries on a standalone basis, on the other hand.

In addition, the Company will agree that, for so long as any Notes remain outstanding and are “restricted securities” under Rule 144 under the Securities Act, if at any time it is not required to file with the SEC the reports required by the preceding paragraphs, it will furnish to beneficial owners of Notes and to prospective investors, upon request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Covenant Termination

From and after the occurrence of an Investment Grade Rating Event, the Company and its Restricted Subsidiaries will no longer be subject to the provisions of the Indenture described in “—Repurchase at the Option of Holders—Asset Sales” or in “—Certain Covenants” above under the following headings:

 

•

“Restricted Payments,”

 

•

“Incurrence of Indebtedness,”

 

•

“Dividend and Other Payment Restrictions Affecting Subsidiaries,”

 

•

Clause (4) of “Merger, Consolidation or Sale of Assets,”

 

•

“Transactions with Affiliates,” and

 

•

“Business Activities”

(collectively, the “Eliminated Covenants”). As a result, after the date on which the Company and its Restricted Subsidiaries are no longer subject to the Eliminated Covenants, the Notes will be entitled to substantially reduced covenant protection.

After the foregoing covenants have been terminated, the Company may not designate any of its Subsidiaries as Unrestricted Subsidiaries pursuant to the second sentence of the definition of “Unrestricted Subsidiary.”

Events of Default and Remedies

Each of the following is an Event of Default:

 

(1)

default for 30 days in the payment when due of interest on the Notes;

 

(2)

default in payment when due of the principal of or premium, if any, on the Notes;

 

(3)

failure by the Company to comply with the provisions described under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets;”

 

(4)

failure by the Company or any of its Restricted Subsidiaries to comply for 30 days after receipt of written notice from the Trustee or the Holders of 25% in principal amount of the Notes with the provisions described under the captions “—Repurchase at the Option of the Holders—Change of Control” and “—Asset Sales” and “—Certain Covenants—Restricted Payments,” “—Incurrence of Indebtedness,” “—Liens,” “—Dividend and Other Payment Restrictions Affecting Subsidiaries,” “—Transactions with Affiliates,” and “—Additional Subsidiary Guarantees”;

 

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(5)

failure by the Company for 60 days (or 180 days with respect to the covenant described under “—Certain Covenants—Reports”) after receipt of written notice from the Trustee or the Holders of 25% in principal amount of the Notes to comply with any of its other agreements in the Indenture;

 

(6)

default under any mortgage, indenture or instrument under which there is issued or by which there is secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is Guaranteed by the Company or any of its Restricted Subsidiaries), whether such Indebtedness or Guarantee now exists, or is created after the Issue Date, if that default:

 

(a)

is caused by a failure to pay when due any principal on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (a “Payment Default”); or

 

(b)

results in the acceleration of such Indebtedness prior to its Stated Maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $25.0 million or more (the “Cross-Acceleration Provision”); provided, however, that if any such Payment Default is cured or waived or any such acceleration rescinded, or such Indebtedness is repaid, within a period of 30 days from the continuation of such Payment Default beyond the applicable grace period or the occurrence of such acceleration, as the case may be, such Event of Default and any consequential acceleration of the Notes shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree;

 

(7)

failure by the Company or any of its Restricted Subsidiaries to pay final judgments aggregating in excess of $25.0 million (net of any amounts covered by insurance or a binding indemnity agreement), which judgments are not paid, discharged or stayed for a period of 60 days (the “Judgment Provision”);

 

(8)

any Subsidiary Guarantee of a Guarantor shall be held in any judicial proceeding to be unenforceable or invalid or, except as permitted by the Indenture, shall cease for any reason to be in full force and effect or any Guarantor, or any Person acting on behalf of any Guarantor, shall deny or disaffirm its obligations under its Subsidiary Guarantee (the “Guarantee Default Provision”), in each case with respect to any Guarantor that is a Significant Subsidiary or any group of Guarantors that, taken together, would constitute a Significant Subsidiary; and

 

(9)

certain events of bankruptcy or insolvency with respect to the Company or any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary (the “Bankruptcy Provision”).

In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to the Company, any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the Holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Under certain circumstances, the Holders of a majority in principal amount of the then outstanding Notes may rescind an acceleration with respect to the Notes and its consequences.

Holders of the Notes may not enforce the Indenture or the Notes except as provided in the Indenture.

Subject to certain limitations, Holders of a majority in principal amount of the then outstanding Notes may direct the Trustee in its exercise of any trust or power. The Trustee may withhold from Holders of the Notes notice of any continuing Default or Event of Default (except a Default or Event of Default relating to the payment of principal, premium or interest) if it determines that withholding notice is in their interest.

 

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The Holders of a majority in aggregate principal amount of the Notes then outstanding by notice to the Trustee may on behalf of the Holders of all of the Notes waive any existing Default or Event of Default and its consequences under the Indenture except a Default or Event of Default in respect of a provision that under “—Amendment, Supplement and Waiver” below cannot be amended or waived without the consent of each Holder affected.

The Company is required to deliver to the Trustee annually a statement regarding compliance with the Indenture. Upon becoming aware of any Default or Event of Default, the Company is required to deliver to the Trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator, member, partner or stockholder of the Company or any Guarantor, as such, shall have any liability for any obligations of the Company or the Guarantors under the Notes, the Indenture, the Subsidiary Guarantees, the Registration Rights Agreement or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

Legal Defeasance and Covenant Defeasance

The Company may, at its option and at any time, elect to have all of its obligations discharged with respect to the outstanding Notes and the Indenture and all obligations of the Guarantors discharged with respect to their Subsidiary Guarantees (“Legal Defeasance”) except for:

 

(1)

the rights of Holders of outstanding Notes to receive payments in respect of the principal of, premium, if any, and interest on such Notes when such payments are due from the trust referred to below;

 

(2)

the Company’s obligations with respect to the Notes concerning issuing temporary Notes, registration of Notes, mutilated, destroyed, lost or stolen Notes and the maintenance of an office or agency for payment and money for security payments held in trust;

 

(3)

the rights, powers, trusts, duties and immunities of the Trustee, and the Company’s obligations in connection therewith; and

 

(4)

the Legal Defeasance provisions of the Indenture.

In addition, the Company may, at its option and at any time, elect to terminate its obligations under “—Repurchase at the Option of Holders—Change of Control” and “—Asset Sales” and under the covenants described under “—Certain Covenants” (other than the covenant described under “—Merger, Consolidation or Sale of Assets”), the operation of the Cross-Acceleration Provision, the Judgment Provision, the Guarantee Default Provision and (with respect only to Significant Subsidiaries) the Bankruptcy Provision described under “—Events of Default and Remedies” above and the limitations contained in clause (4) of the first paragraph under “—Certain Covenants—Merger, Consolidation or Sale of Assets” above (collectively, “Covenant Defeasance”) and certain other covenants or obligations of the Company set forth in the Indenture, and thereafter any omission to comply with such obligations or provisions will not constitute a Default or Event of Default.

The Company may exercise its Legal Defeasance option notwithstanding its prior exercise of its Covenant Defeasance option. If the Company exercises its Legal Defeasance option, payment of the Notes may not be accelerated because of any Event of Default. If the Company exercises its Covenant Defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clauses (4), (5), (6), (7), (8) or (with respect only to Significant Subsidiaries) (9) under “—Events of Default and Remedies” above or because of the failure of the Company to comply with clause (4) of the first paragraph under “—Certain Covenants—Merger, Consolidation or Sale of Assets” above. If the Company exercises its Legal Defeasance or Covenant Defeasance option, each Guarantor will be released from its obligations with respect to its Subsidiary Guarantee.

 

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In order to exercise either Legal Defeasance or Covenant Defeasance:

 

(1)

the Company must irrevocably deposit with the Trustee, in trust, for the benefit of the Holders of the Notes, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, premium, if any, and interest on the outstanding Notes on the Stated Maturity or on the applicable redemption date, as the case may be, and the Company must specify whether the Notes are being defeased to Stated Maturity or to a particular redemption date;

 

(2)

in the case of Legal Defeasance, the Company shall have delivered to the Trustee an Opinion of Counsel reasonably acceptable to the Trustee confirming that (a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the Issue Date, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such Opinion of Counsel shall confirm that, the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

 

(3)

in the case of Covenant Defeasance, the Company shall have delivered to the Trustee an Opinion of Counsel reasonably acceptable to the Trustee confirming that the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

 

(4)

no Default or Event of Default shall have occurred and be continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit or the grant of any Lien securing such borrowings);

 

(5)

such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under any material agreement or instrument (other than the Indenture) to which the Company or any of its Restricted Subsidiaries is a party or by which the Company or any of its Restricted Subsidiaries is bound;

 

(6)

the Company must deliver to the Trustee an officers’ certificate stating that the deposit was not made by the Company with the intent of preferring the Holders of Notes over the other creditors of the Company with the intent of defeating, hindering, delaying or defrauding creditors of the Company or others; and

 

(7)

the Company must deliver to the Trustee an officers’ certificate and an Opinion of Counsel, stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Satisfaction and Discharge

The Company may discharge its and the Guarantors’ obligations under the Indenture if (a) all outstanding Notes have been delivered for cancellation, (b) all outstanding Notes have become due and payable at their scheduled maturity or (c) all outstanding Notes are scheduled for redemption, and the Company has deposited with the Trustee an amount sufficient to pay and discharge all outstanding Notes, not previously delivered for cancellation, on the date of their scheduled maturity or the scheduled date of redemption.

Amendment, Supplement and Waiver

Except as provided below, the Indenture, the Notes and Subsidiary Guarantees may be amended with the consent of the Holders of at least a majority in principal amount of the Notes then outstanding (including consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes), and any existing default or compliance with any provision of the Indenture, the Notes or the Subsidiary Guarantees may

 

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be waived with the consent of the Holders of a majority in principal amount of the then outstanding Notes (including consents obtained in connection with a tender offer or exchange offer for Notes).

Without the consent of each Holder affected, an amendment, supplement or waiver may not (with respect to any Notes held by a non-consenting Holder):

 

(1)

reduce the principal amount of Notes whose Holders must consent to an amendment, supplement or waiver;

 

(2)

reduce the principal of or change the fixed maturity of any Note or alter the provisions with respect to the redemption of the Notes (other than provisions relating to the covenants described above under the caption “—Repurchase at the Option of Holders” or provisions relating to minimum notices required for redemption of Notes described under the caption “—Optional Redemption”);

 

(3)

reduce the rate of or change the time for payment of interest on any Note;

 

(4)

waive a Default or Event of Default in the payment of principal of or premium, if any, or interest on the Notes, except a Default in payments that have become due solely because of an acceleration of the Notes that has been rescinded;

 

(5)

make any Note payable in a currency other than that stated in the Notes;

 

(6)

make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of Holders of Notes to receive payments of principal of or premium, if any, or interest on the Notes (except as permitted by clause (7) below);

 

(7)

waive a redemption payment with respect to any Note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);

 

(8)

modify any Subsidiary Guarantee in any manner adverse to Holders of the Notes or release any Guarantor from its obligations under its Subsidiary Guarantee except in accordance with the terms of the Indenture;

 

(9)

make any change in the ranking of the Notes or the Subsidiary Guarantees in a manner adverse to the Holders of the Notes or the Subsidiary Guarantees; or

 

(10)

make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any Holder of Notes, the Company, the Guarantors and the Trustee may amend or supplement the Indenture, the Notes or the Subsidiary Guarantees:

 

(1)

to cure any ambiguity, defect, inconsistency, omission or mistake;

 

(2)

to provide for uncertificated Notes in addition to or in place of certificated Notes;

 

(3)

to provide for the assumption of the Company’s or a Guarantor’s obligations to Holders of Notes in the case of a merger or consolidation or sale of all or substantially all of the Company’s or a Guarantor’s properties or assets in compliance with the Indenture;

 

(4)

to add or release Guarantors in compliance with the Indenture;

 

(5)

to make any change that would provide any additional rights or benefits to the Holders of Notes, add Events of Default or surrender any right or power conferred upon the Company or any Guarantor or that does not adversely affect in any material respect the legal rights under the Indenture of any such Holder; provided, however, that any change to the Indenture to conform it to this “Description of Notes” shall not be deemed to adversely affect such legal rights;

 

(6)

to secure the Notes, including pursuant to the requirements of the covenant described above under the caption “—Certain Covenants—Liens;”

 

(7)

to comply with requirements of the SEC in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;

 

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(8)

to comply with requirements of any securities depository with respect to the Notes; or

 

(9)

to provide for the issuance of Exchange Notes or Additional Notes.

Concerning the Trustee

If the Trustee becomes a creditor of the Company or any Guarantor, the Indenture will limit its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest after a Default has occurred and is continuing it must eliminate such conflict within 90 days, apply to the SEC for permission to continue or resign.

The Holders of a majority in principal amount of the then outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. If an Event of Default shall occur and be continuing, the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent person in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any Holder of Notes, unless such Holder shall have offered to the Trustee security and indemnity satisfactory to it against any loss, liability or expense as provided in the Indenture.

Governing Law

The Indenture, the Notes and the Subsidiary Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

“ACNTA” means (without duplication), as of the date of determination:

 

(a)

the sum of:

 

(i)

discounted future net revenue from proved oil and natural gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated by the Company or independent engineers in one or more reserve reports prepared as of the end of the Company’s most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from:

 

(A)

estimated proved oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such year-end reserve report, and

 

(B)

estimated proved oil and natural gas reserves of the Company and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior year end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such year-end reserve report, in the case of the determination made under each of clauses (A) and (B) above, calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report) before any state or federal income taxes,

 

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and decreased by, as of the date of determination, the discounted future net revenue attributable to:

 

(C)

estimated proved oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report produced or disposed of since the date of such year-end reserve report (before any state or federal income taxes), and

 

(D)

reductions in the estimated proved oil and natural gas reserves of the Company and its Restricted Subsidiaries reflected in such year-end reserve report since the date of such year-end reserve report attributable to downward determinations of estimates of proved oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such year-end reserve report, in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report) before any state or federal income taxes;

provided, however, that, in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by the Company’s internal engineers or third party engineers;

 

(ii)

the capitalized costs that are attributable to oil and natural gas properties of the Company and its Restricted Subsidiaries to which no proved oil and natural gas reserves are attributed, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest annual or quarterly financial statements;

 

(iii)

the Net Working Capital on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

 

(iv)

the greater of (I) the net book value on a date no earlier than the date of the Company’s latest annual or quarterly financial statements and (II) the appraised value, as estimated by independent appraisers within the immediately preceding 12 months, of other tangible assets of the Company and its Restricted Subsidiaries (provided that the Company shall not be required to obtain such an appraisal of such assets if no such appraisal has been performed);

minus

 

(b)

to the extent not otherwise taken into account in the immediately preceding clause (a), the sum of:

 

(i)

minority interests;

 

(ii)

any net gas or other balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest audited financial statements;

 

(iii)

the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report) before any state or federal income taxes, attributable to reserves subject to participation interests, royalty interests, overriding royalty interests, net profits interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;

 

(iv)

the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Company’s year-end reserve report) before any state or federal income taxes, attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto; and

 

(v)

the discounted future net revenue, calculated in accordance with SEC guidelines before any state or federal income taxes, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production included in determining the discounted future net revenue specified in the immediately preceding clause (a)(i) (utilizing the same prices utilized

 

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in the Company’s year-end reserve report), would be necessary to satisfy fully the obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

If the Company changes its method of accounting from the successful efforts method to the full cost method or a similar method of accounting, ACNTA will continue to be calculated as if the Company were still using the successful efforts method of accounting. For the avoidance of doubt, references in this definition to “oil and natural gas reserves” shall include any reserves attributable to natural gas liquids or other hydrocarbons.

“Acquired Debt” means, with respect to any specified Person:

 

(1)

Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Restricted Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and

 

(2)

Indebtedness secured by a Lien encumbering any asset acquired by such specified Person, provided that the amount of any such Acquired Debt shall not exceed the Fair Market Value of the assets subject to such Lien.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” shall have correlative meanings.

“Asset Sale” means:

 

(1)

the sale, lease, conveyance or other disposition (including, without limitation, by means of a sale and leaseback transaction) of any assets, including, without limitation, any sale of hydrocarbons or other mineral products as a result of the creation of Production Payments and Reserve Sales; provided that the sale, lease conveyance or other disposition of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the Indenture described above under the caption “—Repurchase at the Option of Holders—Change of Control,” and/ or the provisions described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions described above under the caption “—Certain Covenants— Asset Sales;” and

 

(2)

the issuance of Equity Interests by any of the Company’s Restricted Subsidiaries or the sale of Equity Interests in any of its Subsidiaries (other than directors’ qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary).

Notwithstanding the preceding, the following items shall not be deemed to be Asset Sales:

 

(1)

any single transaction or series of related transactions that: (a) involves assets having a Fair Market Value of less than $20.0 million; or (b) results in Net Proceeds to the Company and its Restricted Subsidiaries of less than $20.0 million;

 

(2)

a transfer of assets between or among the Company and its Restricted Subsidiaries;

 

(3)

an issuance of Equity Interests by a Restricted Subsidiary to the Company or to another Restricted Subsidiary;

 

(4)

a disposition of cash or Cash Equivalents, inventory, accounts receivable, surplus or obsolete equipment or other similar property or any other disposition of property in the ordinary course of

 

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business (excluding the disposition of oil and gas in place and other interests in real property unless made in connection with a Permitted Business Investment) or the early termination or unwinding of any Hedging Obligation;

 

(5)

a Permitted Investment or a Restricted Payment that is permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments;”

 

(6)

a disposition of oil, natural gas or other hydrocarbons or other mineral products in the ordinary course of business of the oil and gas production operations of the Company and its Subsidiaries;

 

(7)

any abandonment, relinquishment, farm-in, farm-out, lease and sub-lease of developed and/or undeveloped properties made or entered into in the ordinary course of business, but excluding any disposition as a result of the creation of a Production Payment and Reserve Sale;

 

(8)

the creation or perfection of a Lien or disposition of any asset subject to such Lien in connection with enforcement thereof;

 

(9)

any trade or exchange by the Company or any Restricted Subsidiary of properties or assets used or useful in the Oil and Gas Business for other properties or assets used or useful in the Oil and Gas Business owned or held by another Person (including Capital Stock of a Person engaged in the Oil and Gas Business that is or becomes a Restricted Subsidiary), including any cash or Cash Equivalents necessary in order to achieve an exchange of equivalent value, provided that the Fair Market Value of the properties or assets traded or exchanged by the Company or such Restricted Subsidiary (including any cash or Cash Equivalents to be delivered by the Company or such Restricted Subsidiary) is reasonably equivalent to the Fair Market Value of the properties or assets (together with any cash or Cash Equivalents) to be received by the Company or such Restricted Subsidiary, and provided, further, that any cash received in the transaction must be applied in accordance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales” as if such transaction were an Asset Sale;

 

(10)

the surrender or waiver of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind;

 

(11)

any assignment of an overriding royalty or net profits interest to an employee or consultant of the Company or any of its Restricted Subsidiaries in the ordinary course of business in connection with the generation of prospects or the development of oil and natural gas projects;

 

(12)

the sale or other disposition (whether or not in the ordinary course of business) of oil and gas properties, provided at the time of such sale or other disposition such properties do not have associated with them any proved reserves;

 

(13)

any Production Payment or Reserve Sale, provided that any such Production Payment or Reserve Sales shall have been created, incurred, issued, assumed or guaranteed in connection with the acquisition or financing of, and within 180 days after the acquisition of, the property that is subject thereto;

 

(14)

the licensing or sublicensing of intellectual property or other general intangibles to the extent that such license does not prohibit the licensor from using the intellectual property and licenses, leases or subleases of other property; and

 

(15)

any sale of Equity Interests in, or Indebtedness or other securities of, an Unrestricted Subsidiary.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act.

“Board of Directors” means:

 

(1)

with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

 

(2)

with respect to a partnership, the Board of Directors or other governing body of the general partner of the partnership;

 

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(3)

with respect to a limited liability company, the Board of Directors or other governing body, and in the absence of same, the manager or board of managers or the managing member or members or any controlling committee thereof; and

 

(4)

with respect to any other Person, the board or committee of such Person serving a similar function.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the applicable Person to have been duly adopted by the Board of Directors of such Person and to be in full force and effect on the date of such certification, and delivered to the Trustee.

“Business Day” means any day other than a Saturday, Sunday or other day on which commercial banks in New York, New York are authorized or required by law to close.

“Capital Lease Obligation” means, at the time any determination thereof is to be made, the amount of the liability of a Person in respect of a capital lease that would at that time be required to be capitalized on a balance sheet of such Person in accordance with GAAP. Notwithstanding the foregoing, any lease (whether entered into before or after the Issue Date) that would have been classified as an operating lease pursuant to GAAP as in effect on the Issue Date will be deemed not to represent a Capital Lease Obligation.

“Capital Stock” means:

 

(1)

in the case of a corporation, corporate stock;

 

(2)

in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

 

(3)

in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and

 

(4)

any other interest or participation (other than any debt security convertible into an equity interest) that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

“Cash Equivalents” means:

 

(1)

United States dollars;

 

(2)

securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality thereof (provided that the full faith and credit of the United States is pledged in support thereof) having maturities of not more than one year from the date of acquisition;

 

(3)

demand accounts, time deposit accounts, certificates of deposit and Eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any domestic commercial bank having capital and surplus in excess of $250.0 million and a Thomson Bank Watch Rating of “B” or better;

 

(4)

repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

 

(5)

commercial paper having one of the two highest ratings obtainable from Moody’s or S&P Ratings Services (or its successor) and in each case maturing within 270 days after the date of acquisition;

 

(6)

deposits and certificates of deposit with any commercial bank not meeting the qualifications specified in clause (3) above, provided all such deposits do not exceed $1.0 million in the aggregate at any one time;

 

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(7)

securities issued and fully guaranteed by any state, commonwealth or territory of the United States of America, or by any political subdivision or taxing authority thereof, rated at least “A” by Moody’s or S&P and having maturities of not more than 365 days from the date of acquisition;

 

(8)

Indebtedness or preferred stock issued by Persons with a rating of “A” or higher from S&P or “A-2” from Moody’s, with maturities of 365 days or less from the date or acquisition; and

 

(9)

money market or other mutual funds substantially all of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (8) of this definition.

“Change of Control” means the occurrence of any of the following:

 

(1)

the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Subsidiaries taken as a whole, which disposition is followed by a Rating Decline within 90 days after its consummation;

 

(2)

the adoption by the Board of Directors of a plan of liquidation or dissolution of the Company; or

 

(3)

the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any Person, entity or “group” (within the meaning of Section 13(d) or 14(d) of the Exchange Act), other than one or more Permitted Holders (or the Permitted Control Group or any intermediate companies owned directly or indirectly by one or more Permitted Holders), becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Company, measured by voting power rather than number of shares, which occurrence is followed by a Rating Decline within 90 days thereafter.

“Commodity Agreement” means any oil or natural gas hedging agreement and other agreement or arrangement designed to protect the Company or any Restricted Subsidiary against or manage exposure to fluctuations in oil or natural gas prices and not for speculative purposes.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the net income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that there shall be excluded therefrom:

 

(1)

the net income (or loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting, except to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary thereof;

 

(2)

the net income of any Restricted Subsidiary that is not a Subsidiary Guarantor to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that net income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders;

 

(3)

the cumulative effect of a change in accounting principles;

 

(4)

any write-downs or impairments of non-current assets;

 

(5)

any unrealized non-cash gains or losses or charges in respect of hedge or non-hedge derivatives (including those resulting from the application of ASC 815);

 

(6)

any gain (or loss), together with any related provision for taxes on such gain (or loss), realized in connection with: (a) any Asset Sale or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries;

 

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(7)

any extraordinary or non-recurring gain (or loss), together with any related provision for taxes on such extraordinary or non-recurring gain (or loss); and

 

(8)

any non-cash compensation charge arising from any grant or vesting of stock, stock options or other equity-based awards, including profits interests in Rice Energy Holdings LLC or NGP Rice Holdings LLC.

“Credit Agreement” means the Third Amended and Restated Credit Agreement dated as of April 10, 2014, and effective on or about the Issue Date by and among the Company, as borrower, and the commercial lending institutions and other parties that are agents and lenders thereunder, as amended, restated, modified, supplemented, extended, renewed, refunded, replaced or refinanced in whole or in part from time to time.

“Credit Facilities” means, with respect to the Company or any Guarantor, one or more credit facilities, debt facilities, indentures or commercial paper facilities (including, without limitation, the Credit Agreement), in each case with banks or other financial institutions or lenders or investors, providing for revolving credit loans, term loans, private placements, debt securities, receivables financings (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit or letter of credit guarantees, in each case, as amended, restated, modified, supplemented, extended, renewed, refunded, replaced or refinanced in whole or in part from time to time.

“Currency Agreements” means, at any time as to the Company and its Restricted Subsidiaries, any foreign currency exchange agreement, option or future contract or other similar agreement or arrangement designed to protect against or manage the Company or any of its Restricted Subsidiaries’ exposure to fluctuations in foreign currency exchange rates and not for speculative purposes.

“Customary Recourse Exceptions” means, with respect to any Non-Recourse Debt of an Unrestricted Subsidiary, exclusions from the exculpation provisions with respect to such Non-Recourse Debt for the voluntary bankruptcy of such Unrestricted Subsidiary, fraud, misapplication of cash, environmental claims, waste, willful destruction and other circumstances customarily excluded by lenders from exculpation provisions or included in separate indemnification agreements in non-recourse financings.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Disinterested Member” means, with respect to any transaction, a member of the Company’s Board of Directors who does not have any material direct or indirect financial interest (other than as an owner of Equity Interests in the Company or as an officer, manager or employee of the Company or any Restricted Subsidiary) in or with respect to such transaction and is not an Affiliate, or an officer, director, member of a supervisory, executive or management board or employee of any Person (other than the Company or a Restricted Subsidiary), who has any direct or indirect financial interest in or with respect to such transaction.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder thereof), or upon the happening of any event, matures or is mandatorily redeemable, for any consideration (other than Capital Stock) pursuant to a sinking fund obligation or otherwise, or is redeemable for any consideration (other than Capital Stock) at the option of the holder thereof, in whole or in part, on or prior to the date that is 91 days after the date on which the Notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or an asset sale shall not constitute Disqualified Stock if the terms of such Capital Stock provide that the Company may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments.”

 

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“Dollar-Denominated Production Payments” mean production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“EBITDAX” means, with respect to any Person for any period, without duplication, the Consolidated Net Income of such Person for such period,

 

(i)

plus the sum of the following, without duplication and to the extent deducted (and not added back) in calculating such Consolidated Net Income:

 

(1)

provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period;

 

(2)

consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued and whether or not capitalized (including, without limitation, amortization of original issue discount, non-cash interest payments (other than amortization of debt issuance costs), the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings, and net payments, if any, pursuant to Interest Rate Agreements);

 

(3)

depreciation, depletion, amortization (including amortization of goodwill and other intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period other than non-cash charges resulting from the application of ASC 410) of such Person and its Restricted Subsidiaries for such period; and

 

(4)

consolidated exploration and abandonment expense of such Person and its Restricted Subsidiaries;

 

(ii)

and minus the sum of:

 

(1)

non-cash items increasing such Consolidated Net Income for such period, other than items that were accrued in the ordinary course of business, in each case, on a consolidated basis and determined in accordance with GAAP; and

 

(2)

(to the extent included in determining Consolidated Net Income) the sum of (a) the amount of deferred revenues that are amortized during the period and are attributable to reserves that are subject to Volumetric Production Payments; and (b) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments.

“Equity Interests” mean Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means any public or private sale after the date of the Indenture of Capital Stock (other than Disqualified Stock) of the Company or any contribution to the capital of the Company in respect of Capital Stock (other than Disqualified Stock) of the Company, other than issuances to any Subsidiary of the Company.

“Existing Indebtedness” means Indebtedness outstanding on the Issue Date, other than under the Credit Agreement.

“Fair Market Value” means, with respect to any Asset Sale (or Permitted Asset Exchange) or Restricted Payment (or Investment or Permitted Investment), the price that would be negotiated in an arm’s-length transaction between a willing seller and a willing and able buyer, neither of which is under any compulsion to complete the transaction, as such price is determined in good faith by an officer of the Company.

 

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“Fixed Charge Coverage Ratio” means, with respect to any specified Person for any period, the ratio of the EBITDAX of such Person and its Restricted Subsidiaries for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, Guarantees, redeems or repays any Indebtedness (other than revolving credit borrowings unless, in connection with any such repayment, the commitments to lend associated with such revolving credit borrowings are permanently reduced or canceled) or issues or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated but prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect to such incurrence, assumption, Guarantee, redemption or repayment of Indebtedness, or such issuance or redemption of preferred stock, as if the same had occurred at the beginning of the applicable four-quarter reference period.

In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

 

(1)

acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations and including any related financing transactions, and increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date shall be given pro forma effect as if they had occurred on the first day of the four-quarter reference period;

 

(2)

the EBITDAX attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, shall be excluded;

 

(3)

the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, shall be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

 

(4)

any Person that is a Restricted Subsidiary on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period; and

 

(5)

any Person that is not a Restricted Subsidiary on the Calculation Date will be deemed not to have been a Restricted Subsidiary at all times during such four-quarter period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting officer of the Company; provided that such officer may in his or her discretion include any reasonably identifiable and factually supportable pro forma changes to EBITDAX, including any pro forma expenses and cost reductions, that have occurred or in the judgment of such officer are reasonably expected to occur within 12 months of the date of the applicable transaction (regardless of whether such expense or cost reduction or any other operating improvements could then be reflected properly in pro forma financial statements prepared in accordance with Regulation S-X under the Securities Act or any other regulation or policy of the SEC). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness, but if the remaining term of such Interest Rate Agreement is less than 12 months, then such Interest Rate Agreement shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company may designate.

 

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“Fixed Charges” means, with respect to any Person for any period, the sum, without duplication, of:

 

(1)

the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued and whether or not capitalized, including, without limitation, amortization of original issue discount, non-cash interest payments (other than amortization of debt issuance costs or debt extinguishment costs), the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, commissions, discounts, and other fees and charges incurred in respect of letters of credit or bankers’ acceptance financings, and net payments, if any, pursuant to Interest Rate Agreements; plus

 

(2)

any interest expense on Indebtedness of another Person that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; plus

 

(3)

all dividend payments, whether or not in cash, on any series of Disqualified Stock of such Person or any of its Restricted Subsidiaries, or preferred stock of any of its Restricted Subsidiaries, in each case other than dividend payments on Equity Interests payable solely in Equity Interests of the Company (other than Disqualified Stock) or to the Company or a Restricted Subsidiary of the Company.

“GAAP” means accounting principles generally accepted in the United States set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements, and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time.

“Guarantee” means, without duplication, any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any other obligation, direct or indirect, contingent or otherwise, of such Person:

 

(a)

to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person, or

 

(b)

entered into for the purpose of assuring in any other manner the obligee of such Indebtedness of the payment therefor to protect such obligee against loss in respect thereof (in whole or in part);

provided, however, that the term “Guarantee” shall not include endorsements for collection or deposit in the ordinary course of business. The term “Guarantee” used as a verb has a corresponding meaning.

“Guarantors” means each Subsidiary that executes the Indenture as an initial Subsidiary Guarantor, any Restricted Subsidiary of the Company that becomes a Subsidiary Guarantor in accordance with the provisions of the Indenture, and their respective successors and assigns.

“Hedging Obligations” means, with respect to any Person, the obligations of such Person under Currency Agreements, Interest Rate Agreements and Commodity Agreements.

“Holder” means a person in whose name a Note is registered on the Registrar’s books.

“Indebtedness” means, with respect to any specified Person, without duplication,

 

(a)

all obligations of such Person, whether or not contingent, in respect of:

 

(i)

the principal of and premium, if any, in respect of outstanding (A) Indebtedness of such Person for money borrowed and (B) Indebtedness evidenced by Notes, debentures, bonds or other similar instruments for the payment of which such Person is responsible or liable;

 

(ii)

all Capital Lease Obligations of such Person;

 

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(iii)

the deferred purchase price of property, which purchase price is due more than six months after the date of taking delivery of title to such property, including all obligations of such Person for the deferred purchase price of property under any title retention agreement, but excluding accrued expenses and trade accounts payable arising in the ordinary course of business; and

 

(iv)

the reimbursement obligation of any obligor for the principal amount of any letter of credit, banker’s acceptance or similar transaction (excluding obligations with respect to letters of credit securing obligations (other than obligations described in clauses (i) through (iii) above) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no later than the tenth Business Day following receipt by such Person of a demand for reimbursement following payment on the letter of credit);

 

(b)

all net obligations in respect of Currency Agreements, Interest Rate Agreements and Commodity Agreements, except to the extent such net obligations are otherwise included in this definition;

 

(c)

all liabilities of others of the kind described in the preceding clause (a) or (b) that such Person has Guaranteed or that are otherwise its legal liability;

 

(d)

with respect to any Production Payment and Reserve Sale, any warranties or guaranties of production or payment by such Person with respect to such Production Payment and Reserve Sale but excluding other contractual obligations of such Person with respect to such Production Payment and Reserve Sale;

 

(e)

Indebtedness (as otherwise defined in this definition) of another Person secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person, the amount of such obligations being deemed to be the lesser of:

 

(i)

the full amount of such obligations so secured; and

 

(ii)

the fair market value of such asset as determined in good faith by such specified Person;

 

(f)

Disqualified Stock of such Person or a Restricted Subsidiary in an amount equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

 

(g)

the aggregate preference in respect of amounts payable on the issued and outstanding shares of preferred stock of any of the Company’s Restricted Subsidiaries in the event of any voluntary or involuntary liquidation, dissolution or winding up (excluding any such preference attributable to such shares of preferred stock that are owned by such Person or any of its Restricted Subsidiaries; provided, that if such Person is the Company, such exclusion shall be for such preference attributable to such shares of preferred stock that are owned by the Company or any of its Restricted Subsidiaries); and

 

(h)

any and all deferrals, renewals, extensions, refinancings and refundings (whether direct or indirect) of, or amendments, modifications or supplements to, any liability of the kind described in any of the preceding clauses (a), (b), (c), (d), (e), (f), (g) or this clause (h), whether or not between or among the same parties, if and to the extent that any of the preceding items (other than in respect of letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP.

Notwithstanding the foregoing, “Indebtedness” shall not include:

 

(1)

accrued expenses, royalties and trade payables;

 

(2)

contingent obligations incurred in the ordinary course of business;

 

(3)

asset-retirement obligations or obligations in respect of reclamation and workers’ compensation(including pensions and retiree medical care) that are not overdue by more than 90 days;

 

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(4)

except as provided in clause (d) above, Production Payments and Reserve Sales;

 

(5)

in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business;

 

(6)

any obligation of a Person in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or natural gas property; and

 

(7)

any repayment or reimbursement obligation of such Person or any of its Restricted Subsidiaries with respect to Customary Recourse Exceptions, unless and until an event or circumstance occurs that triggers the Person’s or such Restricted Subsidiary’s direct repayment or reimbursement obligation (as opposed to contingent or performance obligations) to the lender or other Person to whom such obligation is actually owed, in which case the amount of such direct payment or reimbursement obligation shall constitute Indebtedness.

For purposes hereof, the maximum fixed repurchase price of any Disqualified Stock which does not have a fixed repurchase price shall be calculated in accordance with the terms of such Disqualified Stock as if such Disqualified Stock were purchased on any date on which Indebtedness shall be required to be determined pursuant to the Indenture, and if such price is based upon, or measured by, the fair market value of such Disqualified Stock, such fair market value to be determined in good faith by the Board of Directors of the issuer of such Disqualified Stock.

Notwithstanding the foregoing, Indebtedness shall not include any indebtedness that has been defeased or discharged in accordance with GAAP or defeased or discharged pursuant to the deposit of cash, U.S. government obligations and Cash Equivalents (sufficient to satisfy all obligations relating thereto at maturity or redemption, as applicable) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, in accordance with the terms of the instruments governing such indebtedness.

“Interest Rate Agreements” means, with respect to the Company and its Restricted Subsidiaries, interest rate agreements, interest rate cap agreements and interest rate collar agreements and other agreements or arrangements designed to protect such Person against fluctuations in or manage exposure to interest rates, with respect to any Indebtedness that is permitted to be incurred under the Indenture.

“Investment Grade Rating” means a rating equal to or higher than:

 

(1)

Baa3 (or the equivalent) with a stable or better outlook by Moody’s; and

 

(2)

BBB- (or the equivalent) with a stable or better outlook by S&P,

or, if either such entity ceases to make a rating on the Notes publicly available for reasons outside of the Company’s control, the equivalent investment grade credit rating from any other rating agency.

“Investment Grade Rating Event” means the first day on which the Notes have an Investment Grade Rating from each of S&P and Moody’s, and no Default has occurred and is then continuing under the Indenture.

“Investments” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the forms of direct or indirect loans (including Guarantees of Indebtedness or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as

 

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investments on a balance sheet prepared in accordance with GAAP. If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Company, the Company shall be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of the Equity Interests of such Restricted Subsidiary not sold or disposed of.

“Issue Date” means the first date on which the Notes were issued, authenticated and delivered under the Indenture.

“Joint Marketing Arrangement” means any joint venture, partnership, lease, joint marketing agreement, operating agreement or other arrangement (which may or may not include joint ownership of any Person) pursuant to which the Company or one of its Restricted Subsidiaries arrange for the marketing, lease or sale of products and services and share in the profits therefrom.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, encumbrance for security purposes, or security interest of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in any assets and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction.

“Make Whole Premium” means, with respect to a Note at any time, the excess, if any, of (a) the present value at such time of (i) the redemption price of such note at May 1, 2017 set forth in the table under “—Optional Redemption” plus (ii) any required interest payments due on such note through May 1, 2017 (except for currently accrued and unpaid interest), discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) using a discount rate equal to the Treasury Rate plus 50 basis points, over (b) the principal amount of such Note.

“Midstream Assets” means (i) assets used primarily for gathering, transmission, compression, storage, processing, marketing, fractionation, dehydration, stabilization or treatment of natural gas, natural gas liquids, oil or other hydrocarbons, carbon dioxide or water and (ii) Equity Interests of any Person whose assets primarily consist of assets referred to in clause (i).

“Moody’s” means Moody’s Investors Service, Inc. and any successor to its rating agency business.

“Net Cash Proceeds” means, with respect to any issuance or sale of Capital Stock or the sale or incurrence of any Indebtedness, the cash proceeds of such issuance or sale net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually incurred in connection with such issuance or sale and net of taxes paid or payable as a result of such issuance or sale.

“Net Proceeds” means the aggregate cash proceeds received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of, without duplication:

 

(1)

the direct costs relating to such Asset Sale, including, without limitation, legal, title, engineering, environmental, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result thereof;

 

(2)

taxes paid or payable as a result thereof;

 

(3)

amounts required to be applied to the repayment of Indebtedness secured by a Lien on the asset or assets that were the subject of such Asset Sale;

 

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(4)

any reserve established in accordance with GAAP against liabilities associated with such Asset Sale or any amount placed in escrow for adjustment in respect of the purchase price of such Asset Sale, until such time as such reserve is reversed or such escrow arrangement is terminated, in which case Net Proceeds shall be increased by the amount of the reserve so reversed or the amount returned to the Company or its Restricted Subsidiaries from such escrow arrangement, as the case may be; and

 

(5)

any distributions and other payments required to be made to minority interest holders in any Restricted Subsidiaries as a result of such Asset Sale.

“Net Working Capital” means:

 

(a)

all current assets of the Company and its Restricted Subsidiaries, minus

 

(b)

all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness; in each case determined in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness:

 

(1)

as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable as a guarantor or otherwise, in each case except for Customary Recourse Exceptions; and

 

(2)

no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness of the Company or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its Stated Maturity.

“Oil and Gas Business” means:

 

(1)

the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, liquefied natural gas and other hydrocarbons, mineral or renewable energy properties or products produced in association with any of the foregoing;

 

(2)

the business of gathering, marketing, distributing, treating, processing, storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other hydrocarbons, minerals and renewable energy;

 

(3)

any other related energy business, directly or indirectly, from oil, natural gas and other hydrocarbons, minerals and renewable energy produced substantially from properties in which the Company or its Restricted Subsidiaries, directly or indirectly, participate;

 

(4)

any business relating to oil field sales and service or drilling rigs; and

 

(5)

any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (1) through (4) of this definition.

“Oil and Gas Liens” means:

 

(1)

Liens on any specific property or any interest therein, construction thereon or improvement thereto to secure all or any part of the costs incurred for surveying, exploration, drilling, extraction, development, operation, production, construction, alteration, repair or improvement of, in, under or on such property and the plugging and abandonment of wells located thereon (it being understood that, in the case of oil and gas producing properties, or any interest therein, costs incurred for “development” will include costs incurred for all facilities relating to such properties or to projects, ventures or other arrangements of which such properties form a part or that relate to such properties or interests);

 

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(2)

Liens on an oil or gas producing property to secure obligations incurred or Guarantees of obligations incurred in connection with or necessarily incidental to commitments for the purchase or sale of, or the transportation or distribution of, the products derived from such property;

 

(3)

Liens arising under partnership agreements, oil and gas leases, overriding royalty agreements, net profits agreements, production payment agreements, royalty trust agreements, incentive compensation programs on terms that are reasonably customary, in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of oil, gas or other hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, operating agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements that are customary in the Oil and Gas Business; provided, however, that in all instances such Liens are limited to the assets that are the subject of the relevant agreement, program, order or contract;

 

(4)

Liens securing Production Payments and Reserve Sales; provided that such Liens are limited to the property that is subject to such Production Payments and Reserve Sales, and such Production Payments and Reserve Sales; and

 

(5)

Liens on pipelines or pipeline facilities that arise by operation of law.

“Permitted Acquisition Indebtedness” means Indebtedness (including Disqualified Stock) of the Company or any of the Restricted Subsidiaries to the extent such Indebtedness was Indebtedness:

 

(1)

of an acquired Person prior to the date on which such Person became a Restricted Subsidiary as a result of having been acquired and not incurred in contemplation of such acquisition; or

 

(2)

of a Person that was merged, consolidated or amalgamated with or into the Company or a Restricted Subsidiary that was not incurred in contemplation of such merger, consolidation or amalgamation,

provided that on the date such Person became a Restricted Subsidiary or the date such Person was merged, consolidated and amalgamated with or into the Company or a Restricted Subsidiary, as applicable, after giving pro forma effect thereto,

 

(a)

the Company would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test described under “—Certain Covenants—Incurrence of Indebtedness,” or

 

(b)

the Fixed Charge Coverage Ratio for the Company would be not less than the Fixed Charge Coverage Ratio for the Company immediately prior to such transaction.

“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business, including through agreements, transactions, interests or arrangements that permit one to share risk or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including without limitation:

 

(1)

ownership of oil, natural gas, other related hydrocarbon and mineral properties or any interest therein or gathering, transportation, processing, storage or related systems; and

 

(2)

the entry into operating agreements, joint ventures, processing agreements, working interests, royalty interests, mineral leases, farm-in agreements, farm-out agreements, development agreements, production sharing agreements, area of mutual interest agreements, contracts for the sale, transportation or exchange of oil and natural gas and related hydrocarbons and minerals, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, partnership agreements (whether

 

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general or limited), limited liability company agreements or other similar or customary agreements, transactions, properties, interests or arrangements, and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, Investments in corporations and publicly-traded limited partnerships.

“Permitted Control Group” means the “group” within the meaning of Section 13(d) or 14(d) of the Exchange Act comprised of (a) Rice Energy Holdings LLC, (b) Rice Energy Family Holdings, LP, (c) NGP Rice Holdings, LLC and (d) Alpha Natural Resources, Inc.; provided that such “group” shall cease to be a “Permitted Control Group” if at any time Alpha Natural Resources, Inc. (or its Affiliates) becomes the Beneficial Owner, directly or indirectly, of a percentage of the Voting Stock of the Company, measured by voting power rather than number of shares, that is greater than the percentage of the Voting Stock of the Company, measured by voting power rather than number of shares, that is Beneficially Owned in the aggregate, directly or indirectly, by the Permitted Holders.

“Permitted Holders” means, collectively, (a) (i) Rice Energy Family Holdings, LP, a Delaware limited partnership, Rice Energy Holdings LLC, a Delaware limited liability company, Rice Energy Management LLC, a Delaware limited liability company, and Rice Irrevocable Trust, a Delaware trust, and (ii) Daniel J. Rice III and his spouse, the descendants of Daniel J. Rice III and their spouses, and any executor or personal representative of, or trust for the benefit of, or limited liability company, corporation or partnership owned 50% or more by, any of the foregoing and (b) (i) NGP RE Holdings, L.L.C., a Delaware limited liability company, (ii) NGP RE Holdings II, L.L.C., a Delaware limited liability company, (iii) NGP Rice Holdings LLC, a Delaware limited liability company, and (iii) any investment fund (or Affiliate thereof) managed by NGP Energy Capital Management, L.L.C., a Texas limited liability company (but not any portfolio company of any such fund).

“Permitted Investments” means:

 

(1)

any Investment in the Company or in a Restricted Subsidiary of the Company;

 

(2)

any Investment in Cash Equivalents;

 

(3)

any Investment by the Company or any Restricted Subsidiary of the Company in a Person if as a result of such Investment:

 

(a)

such Person becomes a Restricted Subsidiary of the Company; or

 

(b)

such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company;

or any Investment held by such Person at the time of such transaction, provided such Investment was not made in contemplation of such transaction;

 

(4)

any Investment made as a result of the receipt of non-cash consideration from an Asset Sale (or other disposition excluded from the definition thereof) that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales;”

 

(5)

any Investment to the extent made in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Company;

 

(6)

receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

 

(7)

payroll, travel, relocation and similar advances to officers, directors and employees to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

 

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(8)

loans or advances to employees made in the ordinary course of business of the Company or such Restricted Subsidiary made for bona fide business purposes;

 

(9)

Capital Stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments or pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of a debtor or received in connection with a work-out or recapitalization of the issuer or as a result of a foreclosure or other transfer of title or perfection or enforcement of any lien with respect to any secured Investment in default;

 

(10)

Hedging Obligations, which transactions or obligations are incurred in compliance with “—Certain Covenants—Incurrence of Indebtedness;”

 

(11)

Permitted Business Investments and/or Permitted Other Business Investments;

 

(12)

Investments in accounts receivable, prepaid expenses, negotiable instruments held for collection and lease, utility and worker’s compensation, performance and other similar deposits provided to third parties and endorsements for collection or deposit arising in the ordinary course of business;

 

(13)

advances, deposits and prepayments for purchases of any assets, including any Equity Interests;

 

(14)

Permitted Joint Venture Investments and Joint Marketing Arrangements entered into by the Company and its Restricted Subsidiaries in an aggregate amount (measured on the date on which each such Investment was made and without giving effect to subsequent changes in value) that, when taken together with all other Investments pursuant to this clause, do not exceed $75.0 million at any time outstanding;

 

(15)

Investments arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, adjustment of purchase price, earn-outs or similar obligations, in each case incurred or assumed in connection with the disposition or acquisition of any business, assets or a Restricted Subsidiary in accordance with the Indenture;

 

(16)

any Investment by the Company or any Restricted Subsidiary in the Oil and Gas Business having an aggregate Fair Market Value (as determined in good faith by the Company), taken together with all other Investments made pursuant to this clause (16) that are at that time outstanding, not to exceed the greater of (x) $75.0 million and (y) 7.5% of ACNTA at the time of such Investment (with the Fair Market Value of each Investment being measured at the time made and without giving effect to subsequent changes in value); provided, however, that if any Investment pursuant to this clause (16) is made in any Person that is not the Company or a Restricted Subsidiary at the date of the making of such Investment and such Person becomes the Company or a Restricted Subsidiary after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1) above and shall cease to have been made pursuant to this clause (16) for so long as such Person continues to be the Company or a Restricted Subsidiary; and

 

(17)

other Investments in any Person having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (17) since the Issue Date, not to exceed the greater of $75.0 million and 7.5% of ACNTA determined at the time of such Investment.

In connection with any assets or property contributed or transferred to any Person as an Investment, such property and assets shall be equal to the Fair Market Value at the time of the Investment, without regard to subsequent changes in value.

With respect to any Investment, the Company may, in its sole discretion, allocate or re-allocate all or any portion of any Investment to one or more of the above clauses so that the entire Investment is a Permitted Investment.

 

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“Permitted Joint Venture Investment” means an Investment by such Person in any other Person engaged in the Oil and Gas Business (a) over which such Person is responsible (either directly or through a services agreement) for day-to-day operations or otherwise has operational and managerial control of such other Person, or veto power over significant management decisions affecting such other Person, and (b) of which at least 30% of the outstanding Equity Interests of such other Person are at the time owned directly or indirectly by such Person.

“Permitted Liens” means:

 

(1)

Liens on any property or assets of the Company and any Restricted Subsidiary securing Indebtedness and other obligations under Credit Facilities that were permitted by the terms of the Indenture to be incurred;

 

(2)

Liens in favor of the Company or a Restricted Subsidiary;

 

(3)

Liens on any property or assets of a Person existing at the time such Person is merged with or into or consolidated with the Company or any Restricted Subsidiary of the Company, provided that such Liens were in existence prior to and not incurred in the contemplation of such merger or consolidation and do not extend to any property or assets other than those of the Person merged into or consolidated with the Company or the Restricted Subsidiary;

 

(4)

Liens on any property or assets existing at the time of acquisition thereof by the Company or any Restricted Subsidiary of the Company, provided that such Liens were not incurred in contemplation of such acquisition;

 

(5)

Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business;

 

(6)

Liens existing on the Issue Date;

 

(7)

Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

 

(8)

Liens securing Indebtedness incurred to refinance Indebtedness that was previously so secured, provided that (i) the amount of such Indebtedness is not increased except as necessary to pay premiums or expenses incurred in connection with such refinancing and (ii) any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property that is the security for a Permitted Lien hereunder;

 

(9)

Liens securing Hedging Obligations of the Company or any of its Restricted Subsidiaries;

 

(10)

Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capital Lease Obligations, purchase money obligations or other payments incurred to finance the acquisition, lease, improvement or construction of or repairs or additions to, assets or property acquired or constructed in the ordinary course of business; provided that:

 

(a)

the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be incurred under the Indenture and does not exceed the cost of the assets or property so acquired or constructed; and

 

(b)

such Liens are created within 180 days of the later of the acquisition, lease, completion of improvements, construction, repairs or additions or commencement of full operation of the assets or property subject to such Lien and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property (plus improvements, accessions, proceeds, insurance, and dividends or distributions in respect thereof);

 

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(11)

any Lien incurred in the ordinary course of business incidental to the conduct of the business of the Company or the Restricted Subsidiaries or the ownership of their property (including (a) easements, rights of way and similar encumbrances, (b) rights or title of lessors under leases (other than Capital Lease Obligations), (c) rights of collecting banks having rights of setoff, revocation, refund or chargeback with respect to money or instruments of the Company or the Restricted Subsidiaries on deposit with or in the possession of such banks, (d) Liens imposed by law, including Liens under workers’ compensation or similar legislation and mechanics’, carriers’, warehousemen’s, materialmen’s, suppliers’ and vendors’ Liens, (e) Liens incurred to secure performance of obligations with respect to statutory or regulatory requirements, performance or return-of-money bonds, surety bonds or other obligations of a like nature and incurred in a manner consistent with industry practice and (f) Oil and Gas Liens, in each case which are not incurred in connection with the borrowing of money, the obtaining of advances or credit or the payment of the deferred purchase price of property (other than trade accounts payable arising in the ordinary course of business));

 

(12)

Liens for taxes, assessments and governmental charges not yet due or the validity of which are being contested in good faith by appropriate proceedings, promptly instituted and diligently conducted, and for which adequate reserves have been established to the extent required by GAAP as in effect at such time;

 

(13)

Liens on the Capital Stock of any Unrestricted Subsidiary to the extent securing Indebtedness of Unrestricted Subsidiaries;

 

(14)

any extension, renewal, refinancing or replacement, in whole or in part, of any Lien described in the foregoing clauses so long as (x) no additional collateral is granted as security thereby and (y) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (i) the outstanding principal amount, or, if greater, committed amount, of the Indebtedness renewed, refunded, refinanced, replaced, defeased or discharged with such Indebtedness and (ii) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;

 

(15)

Liens created for the benefit of (or to secure) all of the Notes (including Additional Notes) issued under the Indenture;

 

(16)

Liens on property securing a defeasance trust; and

 

(17)

in addition to the foregoing, Liens securing obligations the outstanding principal amount of which does not, taken together with the principal amount of all other obligations secured by Liens Incurred under this clause (17) that are at that time outstanding, exceed the greater of $75.0 million and 5.0% of ACNTA at the time of incurrence.

“Permitted MLP Securities” means equity securities (including incentive distribution rights) of a master limited partnership (or limited liability company or similar business entity with pass-through treatment for U.S. Federal income tax purposes) that has a class of equity securities traded on the New York Stock Exchange, the NYSE AMEX Equities or the Nasdaq Stock Market (or any successor thereof).

“Permitted Other Business Investments” means Investments by the Company or any of its Restricted Subsidiaries in any Person (including in any Unrestricted Subsidiary or joint venture of the Company), provided that:

 

(1)

at the time of such Investment and immediately thereafter, the Company could incur $1.00 of additional Indebtedness under the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness” ;

 

(2)

if such Person has outstanding Indebtedness at the time of such Investment, either (a) all such Indebtedness is Non-Recourse Debt or (b) any such Indebtedness of such Person that is recourse to the Company or any of its Restricted Subsidiaries (which shall include, without limitation, all Indebtedness

 

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of such Person for which the Company or any of its Restricted Subsidiaries may be directly or indirectly, contingently or otherwise, obligated to pay, whether pursuant to the terms of such Indebtedness, by law or pursuant to any guarantee, including, without limitation, any “claw-back,” “make-well” or “keep-well” arrangement) could, at the time such Investment is made, be incurred at that time by the Company and its Restricted Subsidiaries under the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness”; and

 

(3)

such Person is not engaged, in any material respect, in any business other than the Oil and Gas Business.

“Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the Net Cash Proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

 

(1)

the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount of, plus premium, if any, and accrued and unpaid interest on the Indebtedness so extended, refinanced, renewed, replaced, defeased or refunded (plus the amount of reasonable expenses incurred in connection therewith);

 

(2)

the Permitted Refinancing Indebtedness has a final maturity date no earlier than the earlier of the final maturity date of the Indebtedness being extended, refinanced, renewed, replaced, deferred or refunded or 91 days after the final maturity date of the Notes;

 

(3)

the Permitted Refinancing Indebtedness has a Weighted Average Life to Maturity at the time such Permitted Refinancing Indebtedness is incurred that is equal to or greater than the shorter of (A) the Weighted Average Life to Maturity of the Indebtedness being extended, refinanced, renewed, replaced, deferred or refunded and (B) 91 days after the Weighted Average Life to Maturity of the Notes;

 

(4)

if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the Notes or a Subsidiary Guarantee, such Permitted Refinancing Indebtedness is subordinated in right of payment to the Notes or such Subsidiary Guarantee on terms at least as favorable, taken as a whole, to the Holders of Notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and

 

(5)

such Indebtedness is not incurred by a Restricted Subsidiary if the Company is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; provided, however, that a Restricted Subsidiary that is also a Guarantor may Guarantee Permitted Refinancing Indebtedness incurred by the Company, whether or not such Restricted Subsidiary was an obligor or guarantor of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; provided further, however, that if such Permitted Refinancing Indebtedness is subordinated to the Notes, such Guarantee shall be subordinated to such Restricted Subsidiary’s Subsidiary Guarantee to at least the same extent.

“Person” means any individual, corporation, partnership, limited liability company, joint venture, association, joint stock company, trust, unincorporated organization, government or any agency or political subdivision thereof or any other entity.

“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.

“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest or Production Payment in oil and natural gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where, in the case of each of the foregoing, the holder of such

 

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interest has recourse solely to such production or proceeds of production for the recovery of its investment in such interest, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard and subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary with respect to the foregoing interests.

“Rating Category” means:

 

(1)

with respect to S&P, any of the following categories: AAA, AA, A, BBB, BB, B, CCC, CC, C and D (or equivalent successor categories); and

 

(2)

with respect to Moody’s, any of the following categories: Aaa, Aa, A, Baa, Ba, B, Caa, Ca, C and D (or equivalent successor categories).

“Rating Decline” means a decrease in the rating of the Notes by either Moody’s or S&P by one or more gradations (including gradations within Rating Categories as well as between Rating Categories). In determining whether the rating of the Notes has decreased by one or more gradations, gradations within Rating Categories, namely + or-for S&P, and 1, 2, and 3 for Moody’s, will be taken into account; for example, in the case of S&P, a rating decline either from BB+ to BB or BB- to B+ will constitute a decrease of one gradation.

“Restricted Subsidiary” of a Person means any Subsidiary of the referenced Person that is not an Unrestricted Subsidiary.

“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., and any successor to its rating agency business.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the Issue Date.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which such payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and shall not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subordinated Indebtedness” means Indebtedness of the Company (or a Guarantor) that is expressly subordinated or junior in right of payment to the Notes (or a Subsidiary Guarantee, as appropriate) pursuant to a written agreement to that effect.

“Subsidiary” means any subsidiary of the Company. A “subsidiary” of any Person means:

 

(1)

a corporation a majority of whose Voting Stock is at the time, directly or indirectly owned by such Person, by one or more subsidiaries of such Person or by such Person and one or more subsidiaries of such Person; or

 

(2)

a partnership, joint venture, limited liability company or similar entity, in which such Person or a subsidiary of such Person is, at the date of determination, either entitled to receive more than 50 percent of the assets of such entity upon its dissolution, or in the case of a limited partnership or limited liability company, is the controlling general partner or managing or controlling member, as applicable.

“Subsidiary Guarantee” means a Guarantee by a Subsidiary Guarantor of the Company’s obligations with respect to the Notes.

“Treasury Rate” means the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release

 

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H.15(519) which has become publicly available at least two Business Days prior to the date fixed for redemption (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to May 1, 2017; provided, however, that if such period is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Company shall obtain the Treasury Rate by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to May 1, 2017 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used. The Company will (a) calculate the Treasury Rate on the second Business Day preceding the applicable redemption date and (b) prior to such redemption date file with the Trustee an officers’ certificate setting forth the Make Whole Premium and the Treasury Rate and showing the calculation of each in reasonable detail.

“Unrestricted Subsidiary” means any Subsidiary of the Company that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution (and any Subsidiary thereof), but only to the extent that such Subsidiary:

 

(1)

has no Indebtedness other than Non-Recourse Debt, except as permitted under clause (2)(b) of the definition of “Permitted Other Business Investments”;

 

(2)

is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary or the Company unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company, except as permitted under the covenant described under the caption “—Certain Covenants—Transactions with Affiliates”; and

 

(3)

is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition.

The Board of Directors may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation is in compliance with the next succeeding sentence and would not otherwise cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, such designation shall be deemed an Investment in the Subsidiary so designated and all outstanding Investments owned by the Company and its Restricted Subsidiaries in the Subsidiary so designated, shall be valued at their Fair Market Value at the time of such designation for purposes of determining compliance with the covenant described above under the caption “—Certain Covenants—Restricted Payments;” provided, however, that such covenant need not be complied with if the Subsidiary to be so designated has total assets of $1,000 or less. That designation will only be permitted if the amount of such Investment is either permitted as a Restricted Payment under the covenant described under “—Certain Covenants—Restricted Payments” or a Permitted Investment at that time and if such Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

Any designation of a Subsidiary of the Company as an Unrestricted Subsidiary shall be evidenced to the Trustee by filing with the Trustee a copy of the Board Resolution giving effect to such designation certified in an officers’ certificate that also certifies that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments” in which case such designation shall be effective as of the date specified in such resolution. If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be incurred by a Restricted Subsidiary of the Company as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness,” the Company shall be in default of such covenant.

 

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The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that such designation shall be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary and such designation shall only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period; and (2) no Default or Event of Default would be in existence following such designation.

“Volumetric Production Payments” mean production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled (without reference to the occurrence of any contingency) to vote in the election of the directors, managers or trustees of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

 

(1)

the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect thereof, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

 

(2)

the then outstanding principal amount of such Indebtedness.

Book-Entry, Delivery and Form

The new notes will be issued initially only in the form of one or more global notes (the “Global Notes”) and will be deposited with the Trustee as custodian for, and registered in the name of a nominee of, DTC.

Ownership of beneficial interests in a Global Note will be limited to persons who have accounts with DTC (“participants”) or persons who hold interests through participants.

Ownership of beneficial interests in a Global Note will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect to interests of participants) and the records of participants (with respect to interests of persons other than participants). Qualified institutional buyers may hold their interests in a Restricted Global Note directly through DTC if they are participants in such system, or indirectly through organizations that are participants in such system. Indirect access to the DTC system is available to organizations such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly (“indirect participants”).

Investors may hold their interests in a Regulation S Global Note through organizations that are participants in the DTC system, including Euroclear Bank S.A./N.V, as operator of the Euroclear System (“Euroclear”), and Citibank, N.A., as operator of Clearstream Banking, S.A. (“Clearstream”). Clearstream and Euroclear will hold interests in the Regulation S Global Notes on behalf of their participants through DTC.

So long as DTC, or its nominee, is the registered owner or holder of a Global Note, DTC or such nominee, as the case may be, will be considered the sole owner or holder of the Notes represented by such Global Note for all purposes under the Indenture and the Note. No beneficial owner of an interest in a Global Note will be able to transfer that interest except in accordance with DTC’s applicable procedures, in addition to those provided for under the Indenture and, if applicable, those of Euroclear and Clearstream.

 

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All payments on a Global Note will be made to DTC or its nominee, as the case may be, as the registered owner thereof. Neither the Company, the Guarantors, the Trustee nor any Paying Agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in a Global Note or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests.

The Company expects that DTC or its nominee, upon receipt of any payment in respect of a Global Note, will credit participants’ accounts on the applicable payment date with payments in amounts proportionate to their respective beneficial interests in the principal amount of such Global Note as shown on the records of DTC. The Company also expects that payments by participants to owners of beneficial interests in a Global Note held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. Such payments will be the responsibility of the participants.

Transfers between participants in DTC will be effected in the ordinary way in accordance with DTC rules and will be settled in same-day funds. Transfers between participants in Euroclear and Clearstream will be effected in the ordinary way in accordance with their respective rules and operating procedures.

The Company expects that DTC will take any action permitted to be taken by a holder of Notes (including the presentation of Notes for exchange as described below) only at the direction of one or more participants to whose account DTC interests in a Global Note are credited and only in respect of such portion of the aggregate principal amount of Notes as to which such participant or participants has or have given such direction. However, if there is an Event of Default under the Notes, DTC reserves the right to exchange the applicable Global Note for Notes in certificated form (“Certificated Notes”), which it will distribute to its participants and which may be legended as set forth under the heading “Transfer Restrictions.”

The Company understands that: DTC is a limited purpose trust company organized under the laws of the State of New York, a “banking organization” within the meaning of New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the Uniform Commercial Code and a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participants and to facilitate the clearance and settlement of securities transactions between participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need for physical movement of certificates.

Although DTC, Euroclear and Clearstream are expected to follow the foregoing procedures described in this section of the prospectus in order to facilitate transfers of interests in a Global Note among participants of DTC, Euroclear and Clearstream, they are under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. Neither the Company, the Guarantors, the Trustee nor any Paying Agent will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

 

(1)

DTC (a) notifies the Company that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and in either event the Company fails to appoint a successor depositary within 90 days; or

 

(2)

there has occurred and is continuing an Event of Default and DTC notifies the Trustee of its decision to exchange the Global Notes for Certificated Notes.

In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of DTC (in accordance with its customary procedures) and may bear the restrictive legend referred to in “Transfer Restrictions.”

 

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PLAN OF DISTRIBUTION

You may transfer new notes issued under the exchange offer in exchange for the old notes if:

 

•

you acquire the new notes in the ordinary course of your business;

 

•

you have no arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of such new notes in violation of the provisions of the Securities Act; and

 

•

you are not our “affiliate” (within the meaning of Rule 405 under the Securities Act).

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We and the subsidiary guarantors have agreed that, starting on the expiration date of the exchange offer and ending on the close of business 180 days after the date of such expiration date, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale.

If you wish to exchange new notes for your old notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer—Purpose and Effect of the Exchange Offer” and “—Procedures for Tendering—Your Representations to Us” in this prospectus and in the letter of transmittal. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale by you of such new notes.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time on one or more transactions in any of the following ways:

 

•

in the over-the-counter market;

 

•

in negotiated transactions;

 

•

through the writing of options on the new notes or a combination of such methods of resale;

 

•

at market prices prevailing at the time of resale;

 

•

at prices related to such prevailing market prices; or

 

•

at negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes.

Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities may be deemed to be an “underwriter” within the meaning of the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. We agreed to permit the use of this prospectus for a period of up to 180 days after the completion of the exchange offer by such broker-dealers to satisfy this prospectus delivery requirement. Furthermore, we agree to amend or supplement this prospectus during such period if so requested in order to expedite or facilitate the disposition of any new notes by broker-dealers.

We have agreed to pay all expenses incident to the exchange offer other than fees and expenses of counsel to the holders and brokerage commissions and transfer taxes, if any, and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

 

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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

The following discussion is a summary of material federal income tax considerations relevant to the exchange of old notes for new notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. We cannot assure you that the Internal Revenue Service will not challenge one or more of the tax considerations described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the IRS or an opinion of counsel with respect to the U.S. federal income tax consequences described herein. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, persons whose functional currency is not the U.S. dollar, or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below. We recommend that each holder consult his own tax advisor as to the holder’s particular tax consequences of exchanging such holder’s old notes for new notes, including the applicability and effect of any foreign, state, local or other tax laws or estate or gift tax considerations.

We believe that the exchange of old notes for new notes will not be an exchange or otherwise a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange, and the holder’s tax basis and holding period in the new note will be the same as its tax basis and holding period in the corresponding old note immediately before the exchange.

 

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LEGAL MATTERS

The validity of the new notes offered in this exchange offer will be passed upon for us by Vinson & Elkins L.L.P.

EXPERTS

The consolidated financial statements of Rice Energy Inc. as of December 31, 2013 and 2012 and for each of the years then ended, appearing in this prospectus have been audited by Ernst & Young LLP, an independent registered public accounting firm, as set forth in their report appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Countrywide Energy Services, LLC as of and for the periods ended December 31, 2012 and 2013 have been included in reliance upon the report of Grossman Yanak & Ford LLP, independent auditors, appearing elsewhere herein and upon the authority of said firm as experts in accounting and auditing.

The financial statements of Alpha Shale Resources, LP as of December 31, 2013 and 2012 and for each of the years then ended, appearing in this prospectus have been audited by Ernst & Young LLP, independent auditors, as set forth in their report appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

The financial statements of Alpha Shale Resources, LP as of December 31, 2011 and for the year ended December 31, 2011, appearing in this prospectus have been audited by Schneider Downs & Co., Inc., independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Estimates of our oil and natural gas reserves, related future net cash flows and the present values thereof related to our properties as of December 31, 2012 and 2013 included elsewhere in this prospectus were based upon reserve reports prepared by independent petroleum engineers, Netherland, Sewell and Associates, Inc. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

Estimates of oil and natural gas reserves, related future net cash flows and the present values thereof related to the properties of Alpha Shale Resources, LP as of December 31, 2012 and 2013 included elsewhere in this prospectus were based upon reserve reports prepared by independent petroleum engineers, Netherland, Sewell and Associates, Inc. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

 

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INDEX TO FINANCIAL STATEMENTS

 

Rice Energy Inc.
Unaudited Historical Financial Statements
Introduction to the Condensed Consolidated Financial Statements			F-2
Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013			F-4
Condensed Consolidated Statements of Operation as of September 30, 2014 and September 30, 2013			F-5
Condensed Consolidated Statements of Cash Flows as of September 30, 2014 and December 31, 2013			F-6
Statements of Condensed Consolidated Equity as of September 30, 2014 and September 30, 2013			F-7
Notes to Condensed Consolidated Financial Statements			F-8
Unaudited Pro Forma Financial Statements
Introduction			F-25
Pro Forma Condensed Consolidated Statement of Operations for the Year Ended December  31, 2013—Unaudited			F-27
Pro Forma Condensed Consolidated Statement of Operations for the Nine Months Ended September  30, 2014—Unaudited			F-28
Notes to Pro Forma Financial Data—Unaudited			F-29
Audited Historical Financial Statements
Report of Independent Registered Public Accounting Firm			F-32
Consolidated Balance Sheets as of December 31, 2013 and 2012			F-33
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011			F-34
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011			F-35
Consolidated Statements of Equity for the Years Ended December 31, 2013, 2012 and 2011			F-36
Notes to Consolidated Financial Statements			F-37
Alpha Shale Resources, LP
Report of Independent Auditors			F-64
Balance Sheets as of December 31, 2013 and 2012			F-65
Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011			F-66
Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011			F-67
Statements of Partners’ Capital for the Years Ended December 31, 2013, 2012 and 2011			F-68
Notes to Financial Statements			F-69
Independent Auditors’ Report			F-80
Balance Sheet as of December 31, 2011			F-81
Statement of Operations for the Years Ended December 31, 2011			F-82
Statement of Cash Flows for the Years Ended December 31, 2011			F-83
Statement of Partners’ Capital for the Years Ended December 31, 2011			F-84
Notes to Financial Statements			F-85
Countrywide Energy Services, LLC
Independent Accountants’ Compilation Report			F-90
Independent Auditors’ Report			F-91
Balance Sheets as of December 31, 2013 (Unaudited) and 2012			F-92
Statements of Operations for the Years Ended December  31, 2013 (Unaudited), 2012 and for the Period from May 9, 2011 to December 31, 2011			F-93
Statements of Cash Flows for the Years Ended December  31, 2013 (Unaudited), 2012 and for the Period from May 9, 2011 to December 31, 2011			F-94
Statements of Members’ Capital for the Years Ended December  31, 2013 (Unaudited), 2012 and for the Period from May 9, 2011 to December 31, 2011			F-96
Notes to Financial Statements			F-97

 

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Introduction to the Condensed Consolidated Financial Statements

The unaudited condensed consolidated financial statements have been prepared on the basis that Rice Energy Inc. is a corporation under the Internal Revenue Code subject to federal income tax. The unaudited condensed consolidated financial statements should be read in conjunction with the notes accompanying such unaudited condensed consolidated financial statements as well as “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” each included elsewhere in this Quarterly Report. Please see “—Notes to Condensed Consolidated Financial Statements (Unaudited)—5. Acquisitions” for further details on the purchase price allocations and resulting impact on the corresponding condensed consolidated balance sheet and for the related pro forma information.

The unaudited condensed consolidated financial statements as of and for the three and nine months ended September 30, 2014 reflect the following transactions:

Initial Public Offering

On January 29, 2014, we completed our initial public offering (“IPO”) of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by us, 14,000,000 shares sold by NGP Holdings, the selling stockholder in our IPO, and 6,000,000 shares sold subject to an option granted to the underwriters by the selling stockholder.

The net proceeds of our IPO, based on the public offering price of $21.00 per share, were approximately $992.6 million, which resulted in net proceeds to us of $593.6 million after deducting expenses and underwriting discounts and commissions of approximately $36.4 million and the net proceeds to the selling stockholder of approximately $399.0 million after deducting expenses and underwriting discounts of approximately $21.0 million. We did not receive any proceeds from the sale of the shares by the selling stockholder. A portion of the net proceeds from our IPO were used to repay all outstanding borrowings under the revolving credit facility of our Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In (as defined below) and to repay all outstanding borrowings under our Senior Secured Revolving Credit Facility (as defined below). We used the remainder of the net proceeds from our IPO to fund a portion of our capital expenditure plan.

Corporate Reorganization

A corporate reorganization occurred concurrently with the completion of our IPO on January 29, 2014. As a part of this corporate reorganization, we acquired all of the outstanding membership interests in Rice Appalachia and Rice Drilling B (other than those already held by Rice Appalachia) in exchange for shares of our common stock. Our business continues to be conducted through Rice Drilling B, now a wholly owned subsidiary. This reorganization constituted a common control transaction and the accompanying consolidated financial statements are presented as though this reorganization had occurred for the earliest period presented.

As of January 29, 2014, upon (a) the completion of the IPO, (b) the issuance of (i) 43,452,550 shares of common stock to NGP Holdings, (ii) 20,300,923 shares of common stock to Rice Holdings, (iii) 2,356,844 shares of common stock to Daniel J. Rice III, (iv) 20,000,000 shares of common stock to Rice Partners, (v) 160,831 shares of common stock to the persons holding incentive units representing interests in Rice Appalachia and (vi) 1,728,852 shares of common stock to the members of Rice Drilling B (other than Rice Appalachia), each of which were issued by us in connection with the closing of the IPO, and (c) the issuance of 9,523,810 shares of common stock to Alpha Holdings in connection with the completion of the Marcellus JV Buy-In, we had 127,523,810 shares of common stock outstanding.

Compensation Charge in Connection with the Reorganization

Rice Appalachia, as the parent company of Rice Drilling B, historically granted incentive units to certain members of management and other employees. The incentive units provided the holder with a performance bonus for fair value accretion of Rice Appalachia equity.

 

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In connection with the IPO and the related corporate reorganization, the holders of incentive units in Rice Appalachia contributed their Rice Appalachia incentive units (except for those incentive units related to the incentive burden attributable to Mr. Daniel J. Rice III, which we acquired from the holder of such incentive units in exchange for the issuance of 160,831 shares of our common stock as described above) to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. In the first quarter of 2014, certain incentive units granted by NGP Holdings to certain employees triggered the pre-determined payout criteria, resulting in a cash payment by NGP Holdings of $4.4 million. No payments were made in respect of incentive units prior to the completion of the IPO. The exchange of incentive units and cash payment collectively resulted in non-cash compensation expense of $7.8 million being recorded in the first quarter of 2014 by the Company. As a result of the IPO, the payment likelihood related to the incentive units was deemed probable, requiring the Company to recognize expense.

During the nine months ended September 30, 2014, we recognized approximately $101.7 million of compensation expense relative to these incentive units. We expect to recognize approximately $79.8 million of additional compensation expense over the remaining expected service periods related to the Rice Holdings interests. The NGP Holdings interests are considered a liability-based award and will be adjusted on a quarterly basis until all payments have been made. As of September 30, 2014, the unrecognized compensation expense related to the NGP Holdings units is approximately $77.3 million, which will be recognized over the remaining expected service period. The compensation expense related to these interests is treated as additional paid in capital from Rice Holdings and NGP Holdings in our financial statements and is not deductible for federal or state income tax purposes. The compensation expense recognized is a non-cash charge, with the settlement obligation resting on NGP Holdings and Rice Holdings, and as such are not dilutive to Rice Energy Inc. As of September 30, 2014, approximately $19.8 million had been paid on the incentive units.

In August 2014, the triggering event for the Rice Holdings incentive units was achieved. As a result, in August of 2015, 2016 and 2017, Rice Holdings will distribute one third, one half and all, respectively, of its then-remaining assets (consisting solely of shares of our common stock) to its members pursuant to the terms of its limited liability company agreement. As a result, over time, the shares of our common stock held by Rice Holdings will be transferred in their entirety to Rice Partners (or its successors) and the incentive unitholders.

Marcellus JV Buy-In

On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between us and Alpha Holdings dated as of December 6, 2013, we completed our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture in exchange for total consideration of $322.0 million, consisting of $100.0 million of cash and our issuance to Alpha Holdings of 9,523,810 shares of our common stock (the “Marcellus JV Buy-In”). This transaction resulted in a non-recurring gain of $203.6 million in the first quarter of 2014 due to the remeasurement of our previously recorded equity investment at fair value.

 

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Rice Energy Inc.

Condensed Consolidated Balance Sheets

(Unaudited)

 

(in thousands)		September 30, 2014				December 31, 2013
Assets
Current assets:
Cash		$	131,978			$	31,612
Restricted cash			—				8,268
Accounts receivable			136,560				31,765
Receivable from affiliate			222				2,244
Deposits			760				601
Prepaid expenses and other			2,374				262
Derivative assets			8,546				—
Total current assets			280,440				74,752
Investments in joint ventures			—				49,814
Gas collateral account			3,995				3,700
Proved natural gas properties, net			1,023,603				270,523
Unproved natural gas properties			1,158,483				457,836
Property and equipment, net			13,637				5,972
Deferred financing costs, net			20,452				12,292
Goodwill			338,036				—
Intangible assets, net			48,199				—
Other non-current assets			386				—
Derivative assets			8,555				4,921
Total assets		$	2,895,786			$	879,810
Liabilities and stockholders’ equity
Current liabilities:
Current portion of long-term debt		$	1,006			$	20,120
Accounts payable			95,218				51,219
Royalties payable			28,906				9,393
Accrued interest			24,219				250
Accrued capital expenditures			176,087				16,753
Other accrued liabilities			19,378				8,283
Leasehold payable			24,940				18,606
Derivative liability			—				965
Payable to affiliate			—				6,148
Operated prepayment liability			1,886				1,201
Total current liabilities			371,640				132,938
Long-term liabilities:
Long-term debt			900,000				406,822
Leasehold payable			3,330				1,675
Deferred tax liabilities			199,040				—
Restricted units			—				36,306
Other long-term liabilities			9,218				3,422
Total liabilities			1,483,228				581,163
Stockholders’ equity			1,412,558				298,647
Total liabilities and stockholders’ equity		$	2,895,786			$	879,810

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

 

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Rice Energy Inc.

Condensed Consolidated Statements of Operations

(Unaudited)

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands, except per share data)		2014				2013				2014				2013
Operating revenues:
Natural gas, oil and natural gas liquids (NGL) sales		$	67,831			$	23,526			$	246,816			$	60,219
Firm transportation sales, net			9,733				—				11,851				—
Other revenue			1,563				163				2,878				580
Total operating revenues			79,127				23,689				261,545				60,799
Operating expenses:
Lease operating			4,553				1,777				16,406				5,794
Gathering, compression and transportation			9,597				3,365				25,904				6,951
Production taxes and impact fees			1,114				522				2,624				1,029
Exploration			747				338				1,706				1,784
Incentive unit expense			26,418				—				101,695				—
Restricted unit expense			—				32,381				—				40,087
Stock compensation expense			2,058				—				3,274				—
General and administrative			10,458				4,169				36,733				9,952
Depreciation, depletion and amortization			33,853				9,722				91,912				23,215
Acquisition expense			2,246				—				2,246				—
Amortization of intangible assets			408				—				748				—
Total operating expenses			91,452				52,274				283,248				88,812
Operating loss			(12,325	)			(28,585	)			(21,703	)			(28,013	)
Interest expense			(15,754	)			(5,943	)			(38,737	)			(13,033	)
Gain on purchase of Marcellus joint venture			—				—				203,579				—
Other income (loss)			(216	)			38				180				(408	)
Gain on derivative instruments			36,935				8,050				5,357				16,698
Amortization of deferred financing costs			(707	)			(958	)			(1,728	)			(4,760	)
Loss on extinguishment of debt			(790	)			(10,622	)			(3,934	)			(10,622	)
Write-off of deferred financing costs			—				—				(6,896	)			—
Equity in income (loss) of joint ventures			—				4,368				(2,656	)			19,297
Income (loss) before income taxes			7,143				(33,652	)			133,462				(20,841	)
Income tax expense			(14,005	)			—				(18,787	)			—
Net income (loss)		$	(6,862	)		$	(33,652	)		$	114,675			$	(20,841	)
Weighted average number of shares of common stock—basic			132,269,081				88,000,000				125,411,524				77,894,855
Weighted average number of shares of common stock—diluted			132,269,081				88,000,000				125,678,095				77,894,855
Earnings (loss) per share—basic		$	(0.05	)		$	(0.38	)		$	0.91			$	(0.27	)
Earnings (loss) per share—diluted		$	(0.05	)		$	(0.38	)		$	0.91			$	(0.27	)
Pro forma income tax benefit										$	5,560
Pro forma net income										$	120,235
Earnings per share—basic										$	0.96
Earnings per share—diluted										$	0.96

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

 

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Rice Energy Inc.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

 

(in thousands)		Nine Months Ended September 30,
		2014				2013
Cash flows from operating activities:
Net income (loss)		$	114,675			$	(20,841	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			91,912				23,215
Amortization of deferred financing costs			1,728				4,760
Amortization of intangibles			748				—
Incentive unit expense			101,695				—
Write-off of deferred financing costs			6,896				—
Loss on extinguishment of debt			3,934				—
Restricted unit expense			—				40,087
Stock compensation expense			3,274				—
Derivative instruments fair value gain			(5,357	)			(16,698	)
Cash payments for settled derivatives			(20,782	)			(1,053	)
Deferred income tax expense			18,787				—
Fair value gain on purchase of Marcellus joint venture			(203,579	)			—
Equity in (income) loss of joint ventures			2,656				(19,297	)
(Increase) decrease in:
Accounts receivable			(89,443	)			(12,398	)
Receivable from affiliate			2,033				6,897
Gas collateral account			—				4,343
Prepaid expenses and other			(2,165	)			(270	)
Increase (decrease) in:
Accounts payable			2,845				(133	)
Royalties payable			11,605				5,916
Accrued interest			23,315				(1,324	)
Other accrued expenses			14,546				5,029
Payable to affiliate			(9,644	)			4,258
Net cash provided by operating activities			69,679				22,491
Cash flows from investing activities:
Capital expenditures for natural gas properties			(634,129	)			(341,347	)
Acquisition of Marcellus joint venture, net of cash acquired			(82,766	)			—
Acquisition of Momentum assets			(111,447	)			—
Acquisition of Greene County assets			(329,469	)			—
Capital expenditures for property and equipment			(8,279	)			(1,278	)
Proceeds from sale of interest in gas properties			11,542				—
Net cash used in investing activities			(1,154,548	)			(342,625	)
Cash flows from financing activities:
Proceeds from borrowings			900,000				321,003
Repayments of debt obligations			(498,983	)			(159,726	)
Restricted cash for convertible debt			8,268				(8,268	)
Debt issuance costs			(19,401	)			(9,480	)
Common stock issuance			—				197,987
Repurchase of common stock			—				(2,267	)
Costs relating to IPO			(1,412	)			—
Proceeds from conversion of warrants			1,975				—
Proceeds from issuance of common stock sold in IPO, net of underwriting fees			598,500				—
Costs relating to August 2014 Equity Offering			(784	)			—
Proceeds from issuance of common stock sold in August 2014 Equity Offering, net of underwriting fees			197,072				—
Net cash provided by financing activities			1,185,235				339,249
Net increase in cash			100,366				19,115
Cash at the beginning of the year			31,612				8,547
Cash at the end of the year		$	131,978			$	27,662

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

 

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Rice Energy Inc.

Statements of Condensed Consolidated Equity

(Unaudited)

 

(in thousands)		Common Stock ($0.01 par)				Additional Paid-In Capital				Accumulated Deficit				Total
Balance, January 1, 2013		$	622			$	166,901			$	(29,332	)		$	138,191
Capital contributions, net			258				197,732				—				197,990
Consolidated net loss			—				—				(20,841	)			(20,841	)
Balance, September 30, 2013		$	880			$	364,633			$	(50,173	)		$	315,340

 

(in thousands)		Common Stock ($0.01 par)				Additional Paid-In				Accumulated (Deficit) Earnings				Total
Balance, January 1, 2014		$	880			$	362,875			$	(65,108	)		$	298,647
Shares of common stock issued in initial public offering, net of offering costs			300				593,113				—				593,413
Shares of common stock issued in purchase of Marcellus joint venture			95				221,905				—				222,000
Conversion of restricted units into shares of common stock at IPO			—				36,306				—				36,306
Conversion of convertible debentures into shares of common stock after IPO			6				6,599				—				6,605
Conversion of warrants into shares of common stock after IPO			7				1,968				—				1,975
Shares of common stock issued in August 2014 Equity Offering, net of offering costs			75				196,213				—				196,288
Incentive unit compensation			—				101,695				—				101,695
Stock compensation			—				3,274				—				3,274
Tax impact of IPO and corporate reorganization			—				(162,320	)			—				(162,320	)
Consolidated net income			—				—				114,675				114,675
Balance, September 30, 2014		$	1,363			$	1,361,628			$	49,567			$	1,412,558

The accompanying notes are an integral part of these Condensed Consolidated Financial Statements.

 

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Rice Energy Inc.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

 

1.	Basis of Presentation

The accompanying unaudited condensed consolidated financial statements of Rice Energy Inc. (the “Company,” “we,” “our,” and “us”) have been prepared by the Company’s management in accordance with generally accepted accounting principles in the United States (“GAAP”) for interim financial information and applicable rules and regulations promulgated under the Exchange Act. Accordingly, they do not include all of the information and footnotes required by GAAP for annual financial statements. The unaudited condensed consolidated financial statements included herein contain all adjustments which are, in the opinion of management, necessary to present fairly the Company’s financial position as of September 30, 2014 and its condensed consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013 and of cash flows for the nine months ended September 30, 2014 and 2013. The condensed consolidated statements of operations for the three and nine months ended September 30, 2014 and 2013 are not necessarily indicative of the results to be expected for future periods. A corporate reorganization occurred concurrently with the completion of our IPO on January 29, 2014. As a part of this corporate reorganization, we acquired all of the outstanding membership interests in Rice Appalachia and Rice Drilling B (other than those already held by Rice Appalachia) in exchange for shares of our common stock. Our business continues to be conducted through Rice Drilling B, now a wholly owned subsidiary. This reorganization constituted a common control transaction and the accompanying consolidated financial statements are presented as though this reorganization had occurred for the earliest period presented. These condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes therein for the year ended December 31, 2013, as filed with the Securities and Exchange Commission by the Company in its 2013 Annual Report. Certain prior period financial statement amounts have been reclassified to conform to current period presentation.

 

2.	Long-Term Debt

Long-term debt consists of the following as of September 30, 2014 and December 31, 2013.

 

(in thousands)		September 30, 2014				December 31, 2013
Long-term Debt
Senior Notes Due 2022 (a)		$	900,000			$	—
Second Lien Term Loan Facility (b)			—				293,821
Senior Secured Revolving Credit Facility (c)			—				115,000
Debentures (d)			—				6,890
NPI Note			—				8,028
Other			1,006				3,203
Total debt		$	901,006			$	426,942
Less current portion			1,006				20,120
Long-term debt		$	900,000			$	406,822

6.25% Senior Notes Due 2022 (a)

On April 25, 2014, the Company issued $900.0 million (the “Senior Notes Offering”) in the aggregate principal amount of 6.25% senior notes due 2022 (the “Notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act, which resulted in net proceeds of $882.7 million, after deducting expenses and the initial purchasers’ discounts of approximately $17.3 million. The Company used $301.8 million of the net proceeds to repay and retire the Second Lien Term Loan Facility (defined below), with the remainder having been used to fund a portion of the Company’s 2014 capital expenditure program.

 

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The Notes will mature on May 1, 2022, and interest is payable on the Notes on each May 1 and November 1. At any time prior to May 1, 2017, the Company may redeem up to 35% of the Notes at a redemption price of 106.25% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings so long as the redemption occurs within 180 days of completing such equity offering and at least 65% of the aggregate principal amount of the Notes remains outstanding after such redemption. Prior to May 1, 2017, the Company may redeem some or all of the notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. Upon the occurrence of a Change of Control (as defined in the indenture governing the notes (the “Indenture”), unless the Company has given notice to redeem the Notes, the holders of the Notes will have the right to require the Company to repurchase all or a portion of the Notes at a price equal to 101% of the aggregate principal amount of the Notes, plus any accrued and unpaid interest to the date of purchase. On or after May 1, 2017, the Company may redeem some or all of the Notes at redemption prices (expressed as percentages of principal amount) equal to 104.688% for the twelve-month period beginning on May 1, 2017, 103.125% for the twelve-month period beginning May 1, 2018, 101.563% for the twelve-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020, plus accrued and unpaid interest to the redemption date.

The Notes are the Company’s senior unsecured obligations, rank equally in right of payment with all of the Company’s existing and future senior debt, and will rank senior in right of payment to all of the Company’s future subordinated debt. The Notes will be effectively subordinated to all of the Company’s existing and future secured debt to the extent of the value of the collateral securing such indebtedness.

The Company, as the parent company, has no independent assets or operations. The Notes are guaranteed on a senior unsecured basis by the Guarantors (as defined in the Indenture). The guarantees are full and unconditional, subject to customary exceptions pursuant to the Indenture, as discussed below. Other than the Guarantors, Company has no subsidiaries other than minor subsidiaries. In addition, there are no restrictions on the ability of the Company to obtain funds from its subsidiary by dividend or loan. Finally, the Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Company in the form of loans, advances or cash dividends by the subsidiary without the consent of a third party.

Guarantees of the Notes will be released under certain circumstances, including:

 

•

in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as defined in the Indenture) of the Company;

 

•

in connection with any sale or other disposition of the capital stock of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, such that, immediately after giving effect to such transaction, such Guarantor would no longer constitute a subsidiary of the Company;

 

•

if the Company designates any Restricted Subsidiary that is a Guarantor to be an unrestricted subsidiary in accordance with the Indenture;

 

•

upon legal defeasance or satisfaction and discharge of the Indenture; or

 

•

if such Guarantor ceases to guarantee any other indebtedness of the Company or a Guarantor under a credit facility, provided no Event of Default (as defined in the Indenture) has occurred and is continuing.

The Indenture restricts the Company’s ability and the ability of certain of its subsidiaries to: (i) incur or guarantee additional debt or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire our capital stock or subordinated debt; (iii) make certain investments; (iv) incur liens;

 

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(v) enter into transactions with affiliates; (vi) merge or consolidate with another company; (vii) transfer and sell assets; and (viii) create unrestricted subsidiaries. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the Indenture) has occurred and is continuing, many of such covenants will terminate and the Company and its subsidiaries will cease to be subject to such covenants.

The Indenture contains customary events of default, including:

 

•

default in any payment of interest on any Note when due, continued for 30 days;

 

•

default in the payment of principal of or premium, if any, on any Note when due;

 

•

failure by the Company to comply with its other obligations under the Indenture, in certain cases subject to notice and grace periods;

 

•

payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries (as defined in the Indenture) in the aggregate principal amount of $25.0 million or more;

 

•

certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the Indenture) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;

 

•

failure by the Company or Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; and

 

•

any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

In connection with the issuance and sale of the Notes, the Company and certain of the Company’s subsidiaries (the “Guarantors”) entered into a registration rights agreement with the Initial Purchasers, dated April 25, 2014. Pursuant to the registration rights agreement, the Company and the Guarantors have agreed to file a registration statement with the Securities and Exchange Commission so that holders of the Notes can exchange the Notes for registered notes that have substantially identical terms as the Notes. In addition, the Company and the Guarantors have agreed to exchange the guarantee related to the Notes for a registered guarantee having substantially the same terms as the original guarantee. The Company and the Guarantors will use commercially reasonable efforts to cause the exchange to be completed within 365 days after the issuance of the Notes. The Company and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the Notes within the specified time periods.

Second Lien Term Loan Facility (b)

On April 25, 2013, Rice Drilling B entered into a Second Lien Term Loan Facility (“Second Lien Term Loan Facility”) with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million. Rice Drilling B estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $4.5 million. The discount was being amortized over the life of the note using an effective interest rate of 0.284%. Approximately $7.4 million in fees were capitalized in connection with the Second Lien Term Loan Facility.

On April 25, 2014, the Company used a portion of the net proceeds from the Senior Notes Offering to repay and retire the Second Lien Term Loan Facility in the amount of $301.8 million. The payment was comprised of repayment of the principal balance of $297.0 million, a pre-payment penalty of $0.8 million and accrued but unpaid interest of $1.8 million. The prepayment penalty is presented as loss on extinguishment of debt in the condensed consolidated statements of operations for the nine months ended September 30, 2014. The pre-payment also resulted in a debt extinguishment and subsequent write-off of the unamortized deferred finance costs of $6.9 million presented in the condensed consolidated statements of operations for the nine months ended September 30, 2014.

 

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Senior Secured Revolving Credit Facility (c)

On April 25, 2013, Rice Drilling B entered into a Senior Secured Revolving Credit Facility (“Senior Secured Revolving Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $500.0 million and a sublimit for letters of credit of $10.0 million. Concurrently with the closing of the IPO, on January 29, 2014, Rice Drilling B amended its Senior Secured Revolving Credit Facility to, among other things, allow for the corporate reorganization that was completed simultaneously with the closing of the IPO, add the Company as a guarantor, increase the maximum commitment amount to $1.5 billion and lower the interest rate on amounts borrowed under the Senior Secured Revolving Credit Facility. The Company used a portion of the net proceeds of the IPO to repay $115.0 million of borrowings under the Senior Secured Revolving Credit Facility. After giving effect to the amendment, the borrowing base under the Senior Secured Revolving Credit Facility was increased to $350.0 million as a result of the Marcellus JV Buy-In.

In April 2014, concurrently with the Senior Notes Offering, the Company, as borrower, and Rice Drilling B, as predecessor borrower, amended and restated its Senior Secured Revolving Credit Facility (“Amended Credit Agreement”) to, among other things, assign all of the rights and obligations of Rice Drilling B as borrower under the Senior Secured Revolving Credit Facility to the Company. Furthermore, the Amended Credit Agreement (i) allowed for the issuance of the Notes described below and (ii) provided that the Company did not incur an immediate reduction in the borrowing base under the Senior Secured Revolving Credit Facility as a result of the issuance of the Notes. As such, the borrowing base under the Amended Credit Agreement immediately following the issuance of the Notes remained at $350.0 million. The Amended Credit Agreement also extended the maturity date of the Senior Secured Revolving Credit Facility from April 25, 2018 to January 29, 2019. The amount available to be borrowed under the Amended Credit Agreement is subject to a semi-annual borrowing base redetermination that depends on, among other factors, the volumes of the Company’s proved oil and gas reserves. A redetermination occurred in May 2014, which increased the borrowing base to $385.0 million. As of September 30, 2014, the borrowing base was $385.0 million and the sublimit for letters of credit was $100.0 million. The Company had zero borrowings outstanding and $66.8 million in letters of credit outstanding under its Amended Credit Agreement as of September 30, 2014, resulting in availability of $318.2 million. In October 2014, a subsequent redetermination occurred which increased the borrowing base to $550.0 million. The next redetermination is scheduled for April 2015 based on the redetermination criteria as of January 1, 2015.

Eurodollar loans under the Senior Secured Revolving Credit Facility bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of borrowing base utilized.

The Amended Credit Agreement is secured by liens on at least 80% of the proved oil and gas reserves of the Company and its subsidiaries (other than any subsidiary that is designated as an unrestricted subsidiary), as well as significant unproved acreage and substantially all of the personal property of the Company and such restricted subsidiaries, and the Amended Credit Agreement is guaranteed by such restricted subsidiaries. The Amended Credit Agreement contains restrictive covenants that limit the ability of the Company and its restricted subsidiaries to, among other things:

 

•

incur additional indebtedness;

 

•

sell assets;

 

•

make loans to others;

 

•

make investments;

 

•

enter into mergers;

 

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•

make or declare dividends;

 

•

hedge future production or interest rates;

 

•

incur liens; and

 

•

engage in certain other transactions without the prior consent of the lenders.

The Amended Credit Agreement also requires the Company to maintain certain financial ratios, which are measured at the end of each calendar quarter:

 

•

a current ratio, which is the ratio of consolidated current assets (including unused commitments under the Amended Credit Agreement and excluding non-cash derivative assets) to consolidated current liabilities (excluding current maturities under the Amended Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and

 

•

a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as such term is defined in the Amended Credit Agreement) based on the trailing 12 month period to consolidated interest expense, of not less than 2.5 to 1.0.

The Company was in compliance with such covenants and ratios effective as of September 30, 2014.

Debentures (d)

In June of 2011, Rice Drilling B sold $60.0 million of its 12% Senior Subordinated Convertible Debentures due 2014 (the “Debentures”) in a private placement to certain accredited investors as defined in Rule 501 of Regulation D. The Debentures accrued interest at 12% per year payable monthly in arrears by the 15th day of the month and had a scheduled maturity date of July 31, 2014 (“Maturity Date”). The Debentures were Rice Drilling B’s unsecured senior obligations and ranked equally with all of Rice Drilling B’s then-current and future senior unsecured indebtedness.

From July 31, 2013 through August 20, 2013 (the “put redemption period”), any holder of Debentures had the right to cause Rice Drilling B to repurchase all or any portion of the Debentures owned by such holder at 100% of the portion of the principal amount of the Debentures as to which the right was being exercised, plus a premium of 20%. During the put redemption period, Rice Drilling B repurchased $53.1 million of outstanding Debentures and paid a put premium of $10.6 million in accordance with the terms of the agreements.

At any time after July 31, 2013 until the Maturity Date, Rice Drilling B had the right to redeem all, but not less than all, of the Debentures on 30 days prior written notice at a redemption price equal to 100% of the principal amount of the Debentures plus a premium of 50%. In connection with the IPO, the Debentures and warrants of Rice Drilling B were amended to become convertible or exercisable for shares of common stock of the Company. On February 28, 2014, Rice Drilling B issued a redemption notice on the remaining Debentures, which set a redemption date of March 28, 2014. Prior to the redemption date, $6.6 million of the Debentures were converted into 570,945 shares of the Company’s common stock. The remaining principal balance of $0.3 million that was not converted will be paid upon request from holders of the remaining Debentures. The premium of $0.1 million was recorded to expense in the nine months ended September 30, 2014. As of September 30, 2014, the remaining principal balance was $0.2 million.

In connection with the convertible debenture offering, Rice Drilling B granted warrants that were issued on August 15, 2011 to certain of the broker-dealers involved in the private placement. These warrants are considered to be separate instruments issued solely in lieu of cash compensation for services provided by the broker-dealers. Two separate classes of warrants were issued with the sole difference being the exercise price. At September 30,

 

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2014, 90 warrants remain exercisable at a weighted average price of $11.57 per share of the Company’s common stock. The 90 warrants are exercisable in exchange for up to 77,363 shares. For the three and nine months ended September 30, 2014, warrants were exercised in exchange for 126,240 and 686,006 shares of the Company’s common stock, respectively.

Expected Aggregate Maturities

Expected aggregate maturities of notes payable as of September 30, 2014 are as follows (in thousands):

 

Remainder of Year Ending December 31, 2014		$	326
Year Ending December 31, 2015			680
Year Ending December 31, 2016
Year Ending December 31, 2017
Year Ending December 31, 2018 and Beyond			900,000
Total		$	901,006

Interest paid in cash was $30 thousand and $8.9 million for the three and nine months ended September 30, 2014, respectively, and $6.5 million and $17.2 million for the three and nine months ended September 30, 2013, respectively.

 

3.	Derivative Instruments

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. Our derivative counterparties share in the Amended Credit Agreement collateral. The Company’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses are recognized in income currently. As of September 30, 2014, the Company has entered into derivative instruments with various financial institutions, fixing the price it receives for a portion of its natural gas through December 1, 2017, as summarized in the following table:

 

Swap Contract Expiration		MMBtu/day				Weighted Average Price
Fourth quarter of 2014			173,000			$	4.15
2015			166,000			$	4.09
2016			214,000			$	4.14
2017			60,000			$	4.24
Collar Contract Expiration		MMBtu/day				Floor/Ceiling
Fourth quarter of 2014			10,000			$	3.00/5.80
2015			139,000			$	3.96/4.65
Basis Contract Expiration		MMBtu/day				Swap ($/MMBtu)
Fourth quarter of 2014			60,000			$	(0.46	)
2015			62,000			$	(0.57	)
2016			38,000			$	(0.63	)
Put Contract Expiration		MMBtu/day				Put Premium ($/MMBtu)
2014			50,000			$	0.45

 

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The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the condensed consolidated balance sheets for the periods presented, all at fair value:

 

		As of September 30, 2014
(in thousands)		Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross				Derivative instruments subject to master netting arrangements				Derivative Instruments, net
Derivative assets		$	39,672			$	(22,571	)		$	17,101
Derivative liabilities		$	22,571			$	(22,571	)		$	—

 

		As of December 31, 2013
(in thousands)		Derivative instruments, recorded in the Condensed Consolidated Balance Sheet, gross				Derivative instruments subject to master netting arrangements				Derivative Instruments, net
Derivative assets		$	13,000			$	(4,700	)		$	8,300
Derivative liabilities		$	256			$	(4,600	)		$	(4,344	)

The following table presents the realized and unrealized gains or losses presented as gain or loss on derivatives in the condensed consolidated statements of operations for the periods presented:

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands)		2014				2013				2014				2013
Realized gain (loss)		$	171			$	788			$	(20,782	)		$	(1,053	)
Unrealized gain		$	36,764			$	7,262			$	26,139			$	17,751

 

4.	Fair Value of Financial Instruments

The Company determines fair value on a recurring basis for its liability related to restricted units and recorded amounts for derivative instruments as these instruments are required to be recorded at fair value for each reporting amount. Certain amounts in the Company’s financial statements were measured at fair value on a nonrecurring basis including discounts associated with long-term debt. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.

The Company has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The Company’s fair value measurements relating to restricted units are included in Level 3. The Company’s fair value measurements relating to derivative instruments are included in Level 2. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in each category.

Items included in Level 3 are valued using internal models that use significant unobservable inputs. Items included in Level 2 are valued using management’s best estimate of fair value corroborated by third-party quotes.

 

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The following assets and liabilities were measured at fair value on a recurring basis during the period (refer to Note 3 for details relating to derivative instruments):

 

		As of September 30, 2014
						Fair Value Measurements at Reporting Date Using
(in thousands)		Carrying Value				Total Fair Value				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Assets:
Derivative instruments, at fair value		$	17,101			$	17,101			$	—			$	17,101			$	—
Total assets		$	17,101			$	17,101			$	—			$	17,101			$	—
Liabilities:
Derivative instruments, at fair value		$	—			$	—			$	—			$	—			$	—
Total liabilities		$	—			$	—			$	—			$	—			$	—

 

		As of December 31, 2013
						Fair Value Measurements at Reporting Date Using
(in thousands)		Carrying Value				Total Fair Value				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Assets:
Derivative instruments, at fair value		$	4,921			$	4,921			$	—			$	4,921			$	—
Total assets		$	4,921			$	4,921			$	—			$	4,921			$	—
Liabilities:
Restricted units, at fair value		$	36,306			$	36,306			$	—			$	—			$	36,306
Derivative instruments, at fair value			965				965			$	—				965			$	—
Total liabilities		$	37,271			$	37,271			$	—			$	965			$	36,306

 

		Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
(in thousands)		2014				2013
Balance as of January 1,		$	36,306			$	5,667
Total gain or losses:			—				—
Included in earnings			—				—
Transfers in and/or out of Level 3			—				—
Repurchase of restricted units			—				(2,267	)
Converted to shares of common stock			(36,306	)			—
Balance as of September 30,		$	—			$	3,400

Gains and losses related to restricted units included in earnings for the period are reported in operating expenses in the statements of consolidated operations.

The carrying value of cash equivalents approximates fair value due to the short maturity of the instruments.

 

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The estimated fair value and carrying amount of long-term debt as reported on the condensed consolidated balance sheets as of September 30, 2014 and December 31, 2013 is shown in the table below (refer to Note 2 for details relating to the borrowing arrangements). The fair value was estimated using Level 2 inputs based on rates reflective of the remaining maturity as well as the Company’s financial position.

 

		As of September 30, 2014								As of December 31, 2013
		Carrying Value				Fair Value				Carrying Value				Fair Value
Long-Term Debt (in thousands)
Senior Notes Offering		$	900,000			$	866,864			$	—			$	—
Second Lien Term Loan Facility			—				—				293,821				315,284
Senior Secured Revolving Credit Facility			—				—				115,000				115,000
Debentures			—				—				6,890				12,671
NPI Note			—				—				8,028				8,028
Other			1,006				1,006				3,203				3,203
Total		$	901,006			$	867,870			$	426,942			$	454,186

 

5.	Acquisitions

Marcellus JV Buy-In

Prior to the completion of the Marcellus JV Buy-In, the Company accounted for its 50% equity interest in the Marcellus joint venture under the equity method of accounting. Immediately prior to the completion of the Marcellus JV Buy-In, the fair value of the existing equity in the Marcellus joint venture was approximately $250.6 million. The acquisition date fair value of the existing equity investment was based on an income approach. The income approach, considered to be a Level 3 fair value method, calculated the present value of the future cash flows related to the natural gas properties as of the date of the transaction, utilizing a discount rate based upon market participant assumptions, natural gas strip prices as of the date of the transaction, and a decline curve consistent with our geographic peers. As a result of the Marcellus JV Buy-In, the Company was required to remeasure its equity investment at fair value, which resulted in a non-recurring gain of approximately $203.6 million during the nine months ended September 30, 2014. Based on valuations performed as of the acquisition date, the natural gas properties had a fair value of approximately $343.0 million. The acquisition consolidated the resources of the Company and the Marcellus joint venture, which enables management to optimize and prioritize the development of their combined natural gas properties. The management team of the Company historically served as the management team of the Marcellus joint venture, providing it with familiarity with its assets and operations. As a result of these factors, the excess purchase price over net assets and liabilities assumed of $338.0 million was allocated to goodwill.

 

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The purchase price allocation and resulting impact on the corresponding condensed consolidated balance sheet relating to the Marcellus JV Buy-In is as follows:

 

(in thousands)
Financial assets		$	34,242
Proved natural gas properties, net			288,000
Unproved natural gas properties			55,000
Goodwill			338,036
Financial liabilities			(49,313	)
Long-term debt			(75,400	)
Deferred tax liability			(17,933	)
Total identifiable net assets		$	572,632
Cash paid for acquisitions		$	100,000
Fair value of equity issued			222,000
Fair value of pre-existing equity investment			250,632
Total consideration		$	572,632

Subsequent to the completion of the Marcellus JV Buy-In and excluding the related gain of $203.6 million recorded at January 29, 2014, the 100%-owned Marcellus joint venture contributed the following to the Company’s consolidated operating results for the three and nine months ended September 30, 2014:

 

(in thousands)		Three Months Ended September 30, 2014				Nine Months Ended September 30, 2014
Revenue		$	30,689			$	103,290
Net income		$	12,008			$	57,419

Pro Forma Information (Unaudited)

The following unaudited pro forma combined financial information presents the Company’s results as though the Marcellus JV Buy-In had been completed at January 1, 2014 and January 1, 2013, respectively.

 

(in thousands, except per share data)		Three Months Ended September 30,								Nine Months Ended September 30,
		2014				2013				2014				2013
Pro forma net revenues		$	79,127			$	42,959			$	273,480			$	123,676
Pro forma net loss		$	(6,862	)		$	(29,088	)		$	(83,794	)		$	(1,540	)
Pro forma loss per share (basic)		$	(0.05	)		$	(0.33	)		$	(0.65	)		$	(0.02	)
Pro forma loss per share (diluted)		$	(0.05	)		$	(0.33	)		$	(0.65	)		$	(0.02	)

Momentum Acquisition

On February 12, 2014, the Company, through its indirect wholly-owned subsidiary Rice Poseidon Midstream LLC, a Delaware limited liability company (“Rice Poseidon”), entered into a purchase and sale agreement with M3 Appalachia Gathering LLC, a Delaware limited liability company (“M3”), to acquire (the “Momentum Acquisition”) certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania. On April 17, 2014, the Company completed the Momentum Acquisition for aggregate consideration of approximately $111.4 million (the “Purchase Price”). The Company funded the Purchase Price with cash on hand.

As of September 30, 2014, $48.9 million of the Purchase Price was allocated to intangible assets related to customer contracts on the condensed consolidated balance sheets and the remaining balance was recorded to proved and unproved natural gas properties. The customer contracts are amortized over 30 years using a straight

 

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line method and amortization expense recorded in the condensed consolidated statements of operations for the three and nine months ended September 30, 2014 was $0.4 million and $0.7 million, respectively. The estimated annual amortization expense over the next five years is as follows: remainder of 2014—$0.4 million, 2015—$1.6 million, 2016—$1.6 million, 2017—$1.6 million, and 2018—$1.6 million.

The properties acquired in the Momentum Acquisition consist of a 28-mile, 6-16 inch gathering system in eastern Washington County, Pennsylvania, and permits and rights of way in Washington and Greene Counties, Pennsylvania, necessary to construct an 18-mile, 30 inch gathering system connecting the northern system to the Texas Eastern pipeline. The northern system is supported by long-term contracts with acreage dedications covering approximately 20,000 acres from third parties. Once fully constructed, the acquired systems are expected to have an aggregate capacity of over 1 billion cubic feet of natural gas per day.

Greene County Acquisition

On July 7, 2014, the Company entered into a definitive purchase and sale agreement to acquire 21,913 net acres and 12 developed Marcellus wells in southwestern Greene County, Pennsylvania from Chesapeake Appalachia, L.L.C. and its partners for approximately $329.5 million (the “Greene County Acquisition”). The purchase price was allocated to proved and unproved natural gas properties in the amounts of $151.3 million and $178.2 million, respectively. The transaction closed on August 1, 2014, with an effective date of February 1, 2014. The Company funded the Greene County Acquisition with cash on hand.

 

6.	Commitments and Contingencies

On October 14, 2013, the Company entered into a Development Agreement and Area of Mutual Interest (“AMI”) Agreement with Gulfport Energy Corporation (“Gulfport”) covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. The Company refers to these agreements as “Utica Development Agreements.” Pursuant to the Utica Development Agreements, the Company had approximately 68.80% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Goshen and Smith Townships (the “Northern Contract Area”) and an approximately 42.63% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Wayne and Washington Townships (the “Southern Contract Area”), each within Belmont County, Ohio. The remaining participating interests are held by Gulfport. The participating interests of the Company and Gulfport in each of the Northern and Southern Contract Areas approximated the Company’s then-current relative acreage positions in each area.

Each quarter during the term of the Development Agreement, the Company and Gulfport will establish a work program and budget detailing the proposed exploration and development to be performed in the Northern and Southern Contract Areas, respectively, for the following year. The number of horizontal wells proposed to be drilled in each of the Northern Contract Area and Southern Contract Area is limited by the Development Agreement as follows: in 2014, between eight and 40 wells; in 2015, between eight and 50 wells; and thereafter, unlimited.

The Utica Development Agreements have terms of ten years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint operating agreement and the Company and Gulfport shall remain operators of drilling units located in the Northern and Southern Contract Areas, respectively, following such termination.

The Company has commitments for gathering and firm transportation under existing contracts with third parties. Future payments under these contracts as of September 30, 2014 totaled $2,887.2 million (remainder of 2014—$15.7 million, 2015—$94.3 million, 2016—$113.6 million, 2017—$113.4 million, 2018—$112.0 million, 2019 – $141.8 million and thereafter—$2,296.4 million).

 

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As of September 30, 2014, the Company had seven drilling rigs (four horizontal and three tophole) under contract, of which five expire in 2015 and two expire in 2017. Future payments under these contracts as of September 30, 2014 totaled $85.9 million (remainder of 2014—$12.2 million, 2015—$46.0 million, 2016—$20.8 million and 2017—$6.9 million). Any other rig performing work for us is performed on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the amounts above. The values above represent the gross amounts that we are committed to pay without regard to our proportionate share based on our working interest.

The Company is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.

 

7.	Stockholders’ Equity

On January 29, 2014, pursuant to the Master Reorganization Agreement (the “Master Reorganization Agreement”) among the Company, Rice Drilling B, Rice Appalachia, Rice Holdings, Rice Partners, NGP Holdings, NGP RE Holdings, L.L.C., (“NGP RE Holdings”) NGP RE Holdings II, L.L.C. (“NGP RE II” and, together with NGP RE Holdings, “Natural Gas Partners”), Mr. Daniel J. Rice III, Rice Merger LLC (“Merger Sub”) and each of the persons holding incentive units representing interests in Rice Appalachia (collectively, the “Incentive Unitholders”) dated as of January 23, 2014, (i) (a) Rice Partners contributed a portion of its interests in Rice Appalachia to Rice Holdings, (b) Natural Gas Partners contributed its interests in Rice Appalachia to NGP Holdings and (c) the Incentive Unitholders contributed a portion of their incentive units to Rice Holdings and NGP Holdings, in each case in return for substantially similar incentive units in such entities; (ii) NGP Holdings, Rice Holdings and Mr. Daniel J. Rice III contributed their respective interests in Rice Appalachia to the Company in exchange for 43,452,550, 20,300,923 and 2,356,844 shares of common stock, respectively; (iii) Rice Partners contributed its remaining interest in Rice Appalachia to the Company in exchange for 20,000,000 shares of common stock; (iv) the Incentive Unitholders contributed their remaining interests in Rice Appalachia to the Company in exchange for 160,831 shares of common stock, each of which were issued by the company in connection with the closing of the IPO. In connection with the IPO, in the first quarter of 2014, we recognized non-cash compensation expense of $3.4 million for these 160,831 shares.

In addition, on January 29, 2014, pursuant to the Agreement and Plan of Merger (the “Merger Agreement”) among the Company, Rice Drilling B and Merger Sub dated as of January 23, 2014, the Company issued 1,728,852 shares of common stock to the members of Rice Drilling B (other than Rice Appalachia) in exchange for their units in Rice Drilling B.

In August 2014, we completed a public offering (“August 2014 Equity Offering”) of 13,729,650 shares of our common stock at $27.30 per share, which included 7,500,000 shares sold by us and 6,229,650 shares sold by affiliates of Natural Gas Partners and Alpha Natural Resources (the “Selling Stockholders”). After deducting underwriting discounts and commissions of $7.7 million and transaction costs, the Company received net proceeds of $196.3 million. The Company received no proceeds from the sale of shares by the Selling Stockholders. The net proceeds from this offering are being used to fund a portion of our 2014 capital budget.

The Company’s Board of Directors did not declare or pay a dividend for the three or nine months ended September 30, 2014 or 2013.

 

8.	Incentive Units

In connection with the IPO and the related corporate reorganization, the Rice Appalachia incentive unit holders contributed their Rice Appalachia incentive units to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities (except for those incentive units related to the incentive burden attributable to Mr. Daniel J. Rice III, which we acquired from the holders of such incentive units in

 

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exchange for the issuance of 160,831 shares of our common stock). In the first quarter of 2014, certain incentive units granted by NGP Holdings to certain employees triggered the pre-determined payout criteria, resulting in a cash payment by NGP Holdings of $4.4 million. No payments were made in respect of incentive units prior to the completion of the Company’s IPO. These two transactions resulted in non-cash compensation expense of $7.8 million being recorded in the first quarter of 2014 by the Company. As a result of the IPO, the payment likelihood related to the incentive units was deemed probable, requiring the Company to recognize expense.

For the three and nine months ended September 30, 2014, we recognized approximately $26.4 million and $101.7 million of compensation expense, respectively, relative to these interests, of which $12.0 million and $19.8 million has been paid by Mr. Daniel J. Rice III and NGP Holdings for the three and nine months ended September 30, 2014, respectively. We expect to recognize approximately $79.8 million of additional compensation expense over the remaining expected service periods, related to the Rice Holdings interests. The NGP Holdings interests are considered a liability-based award and will be adjusted on a quarterly basis until all payments have been made. As of September 30, 2014, the unrecognized compensation expense related to the NGP Holdings units is approximately $77.3 million which will be recognized over the remaining expected service period. The compensation expense related to these interests is treated as additional paid in capital from Rice Holdings and NGP Holdings in our financial statements and is not deductible for federal or state income tax purposes. The compensation expense recognized is a non-cash charge, with the settlement obligation resting on NGP Holdings and Rice Holdings, and as such are not dilutive to Rice Energy Inc.

In August 2014, the triggering event for the Rice Holdings incentive units was achieved. As a result, in August of 2015, 2016 and 2017, Rice Holdings will distribute one third, one half and all, respectively, of its then-remaining assets (consisting solely of shares of our common stock) to its members pursuant to the terms of its limited liability company agreement. As a result, over time, the shares of our common stock held by Rice Holdings will be transferred in their entirety to Rice Partners (or its successors) and the incentive unitholders.

As a result of our August 2014 Equity Offering, NGP Holdings paid approximately $12.0 million to holders of certain NGP Holdings incentive units.

Three tranches of the incentive units have a time vesting feature. A rollforward of those units from IPO to September 30, 2014 is included below.

 

Vested Units Balance, January 29, 2014			853,630
Vested During Period			565,881
Forfeited During Period			(214,869	)
Granted During Period			214,869
Cancelled During Period			—
Vested Units Balance, September 30, 2014			1,419,511

 

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Four tranches of the incentive units do not have a time vesting feature, and their payouts are triggered upon a future payment condition. The fair value of the incentive units was estimated using a Monte Carlo simulation valuation model with the following assumptions:

 

Rice Holdings
Valuation Date			1/29/2014
Dividend Yield			0.00	%
Expected Volatility			47.00	%
Risk-Free Rate			1.11	%
Expected Life (Years)			4.0
Rice Holdings
Valuation Date			4/14/2014
Dividend Yield			0.00	%
Expected Volatility			45.19	%
Risk-Free Rate			1.13	%
Expected Life (Years)			3.8
Rice Holdings
Valuation Date			4/16/2014
Dividend Yield			0.00	%
Expected Volatility			44.32	%
Risk-Free Rate			1.18	%
Expected Life (Years)			3.8
NGP Holdings
Valuation Date			9/30/2014
Dividend Yield			0.00	%
Expected Volatility			40.20	%
Risk-Free Rate			0.58	%
Expected Life (Years)			2.0

 

9.	Stock Compensation

During the nine months ended September 30, 2014, the Company granted stock compensation awards to certain non-employee directors and employees. The awards consisted of restricted stock units, which vest upon the passage of time, and performance units, which vest based upon attainment of specified performance criteria. Stock compensation expense related to these awards was $2.1 million and $3.3 million for the three and nine months ended September 30, 2014, respectively. As of September 30, 2014, the Company has unrecognized compensation expense related to these equity awards of $17.5 million.

 

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10.	Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted earnings per share takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of nonvested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their issuance is contingent upon vesting. The following is a calculation of the basic and diluted weighted-average number of shares of common stock outstanding and EPS for the three and nine months ended September 30, 2014 and 2013. As indicated in Note 1, our corporate reorganization was considered a transaction amongst entities under common control. Therefore, the weighted average shares used in our EPS calculation assume that the Rice Energy Inc. corporate structure was in place for all periods presented.

 

		Three Months Ended September 30,								Nine Months Ended September 30,
(in thousands, except share data)		2014				2013				2014				2013
Income (loss) (numerator):
Net income (loss)		$	(6,862	)		$	(33,652	)		$	114,675			$	(20,841	)
Weighted-average shares (denominator):
Weighted-average number of shares of common stock—basic			132,269,081				88,000,000				125,411,524				77,894,855
Weighted-average number of shares of common stock—diluted			132,269,081				88,000,000				125,678,095				77,894,855
Earnings (loss) per share:
Basic		$	(0.05	)		$	(0.38	)		$	0.91			$	(0.27	)
Diluted		$	(0.05	)		$	(0.38	)		$	0.91			$	(0.27	)

Due to the net loss for the periods presented herein, loss per share excludes dilution for 76,800 shares and 1,671,800 shares for the three months ended September 30, 2014 and for the three and nine months ended September 30, 2013, respectively.

 

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11.	Income Taxes

We are a corporation under the Internal Revenue Code subject to federal income tax at a statutory rate of 35% of pretax earnings and, as such, our future income taxes will be dependent upon our future taxable income. We did not report any income tax benefit or expense for periods prior to the consummation of our IPO because Rice Drilling B, our accounting predecessor, is a limited liability company that was not and currently is not subject to federal income tax. The reorganization of our business in connection with the closing of the IPO, such that it is now held by a corporation subject to federal income tax, required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of the completion of the IPO as it represents a transaction among shareholders. Additionally, the pro forma EPS for the nine month period ending September 30, 2014 disclosed in the accompanying condensed consolidated statements of operations assumes a statutory tax rate. The components of the income tax provision are as follows:

 

(in thousands)		Three Months Ended September 30, 2014				Nine Months Ended September 30, 2014
Current tax expense:
Federal		$	—			$	—
State			—				—
Total			—				—
Deferred tax expense:
Federal			11,813				15,847
State			2,192				2,940
Total			14,005				18,787
Total income tax expense		$	14,005			$	18,787

Tax expense for the three months ended September 30, 2014 is approximately $14.0 million resulting in an effective tax rate of 196%. Tax expense for the nine months ended September 30, 2014 is approximately $18.8 million resulting in an effective tax rate of 14%. The Company estimates an annual effective income tax rate based on projected results for the year and applies this rate to income before taxes to calculate income tax expense. The effective tax rate for the three and nine months ended September 30, 2014 differ from the statutory rate due principally to non-deductible incentive unit expense and for the nine months ended September 30, 2014 pre-tax income prior to the IPO. The Company recognizes deferred tax liabilities for temporary differences between the financial statement and tax basis of assets and liabilities. The deferred tax liabilities reflected above primarily relate to intangible drilling costs, depletion, and depreciation. The effect of changes in the tax laws or tax rates is recognized in income in the period such changes are enacted.

Based on management’s analysis, the Company did not have any uncertain tax positions as of September 30, 2014 and December 31, 2013.

 

12.	New Accounting Pronouncements

In May 2014, the FASB issued ASU, No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” or ASU No. 2014-09. The FASB created Topic 606 which supersedes the revenue recognition requirements in Topic 605, “Revenue Recognition,” and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 will enhance comparability of revenue recognition practices across entities, industries and capital markets compared to existing guidance. Additionally, ASU 2014-09 will reduce the number of requirements to which an entity must consider in recognizing revenue as this update will replace multiple locations for guidance. The FASB and International Accounting Standards Board initiated this joint

 

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project to clarify the principles for recognizing revenue and to develop a common revenue standard for both U.S. GAAP and International Financial Reporting Standards. ASU 2014-09 is effective for fiscal and interim periods beginning after December 15, 2016 and should be applied retrospectively. Early adoption of this standard is not permitted. The Company is currently evaluating the impact of the provisions of ASU 2014-09.

 

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RICE ENERGY INC.

PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Introduction

The following unaudited pro forma condensed consolidated statements of operations of Rice Energy Inc. for the year ended December 31, 2013 and the nine months ended September 30, 2014 are derived from the historical financial statements of Rice Energy Inc. and Alpha Shale Resources, LP, set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical financial statements and related notes contained therein. These unaudited pro forma condensed consolidated financial statements have been prepared to reflect our acquisition of a 50% interest in our Marcellus joint venture and our initial public offering, each of which is described below.

Initial Public Offering

On January 29, 2014, we completed our IPO of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by us, 14,000,000 shares sold by the selling stockholder and 6,000,000 shares subject to an option granted to the underwriters by the selling stockholder.

The net proceeds of our IPO, based on the public offering price of $21.00 per share, were approximately $992.6 million, which resulted in net proceeds to us of $593.6 million after deducting estimated expenses and underwriting discounts and commissions of approximately $36.4 million and the net proceeds to the selling stockholders of approximately $399.0 million after deducting estimated expenses and underwriting discounts of approximately $21.0 million. We did not receive any proceeds from the sale of the shares by the selling stockholder. A portion of the net proceeds from our IPO were used to repay all outstanding borrowings under the revolving credit facility of our Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In and to repay all outstanding borrowings under our revolving credit facility. The remainder of the net proceeds from our IPO will be used to fund a portion of our capital expenditure plan.

Marcellus JV Buy-In

On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between us and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), we completed our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture in exchange for total consideration of $322 million, consisting of $100 million of cash and our issuance to Alpha Holdings of 9,523,810 shares of our common stock.

The unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2013 and the nine months ended September 30, 2014 were derived by adjusting the historical audited and unaudited financial statements of Rice Energy Inc. The adjustments are based upon information available as of November 12, 2014, and certain estimates and assumptions. Actual effects of the transactions may differ from the pro forma adjustments. Management believes, however, that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial data.

The pro forma adjustments have been prepared as if the Marcellus JV Buy-In and our IPO had each taken place as of January 1, 2013. The unaudited pro forma condensed consolidated financial statements have been prepared on the fact that Rice Energy Inc. is treated as a corporation for federal income tax purposes. The unaudited pro forma condensed consolidated statements of operations should be read in conjunction with the

 

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notes accompanying such unaudited pro forma statements of operations and with the historical audited financial statements of Rice Energy Inc. and Alpha Shale Resources, LP and related notes, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” each included elsewhere in this prospectus.

The unaudited pro forma condensed consolidated statements of operations give pro forma effect to the following adjustments, among others:

the acquisition of a 50% interest in our Marcellus joint venture from our joint venture partner in return for 9,523,810 shares of common stock of Rice Energy Inc. and $100 million in cash;

the repayment of all outstanding borrowings under the revolving credit facility of us and our Marcellus joint venture; and

the issuance by Rice Energy Inc. of 30,000,000 shares in the IPO and the use of the net proceeds therefrom.

The unaudited pro forma condensed consolidated statements of operations exclude certain transaction costs, such as costs associated with the IPO that were not capitalized as part of the IPO. The unaudited pro forma condensed consolidated financial data are presented for illustrative purposes only and do not purport to indicate the financial condition or results of operations of future periods or the financial condition or results of operations that actually would have been realized had the transactions described above been consummated on the dates or for the periods presented.

The unaudited pro forma condensed consolidated statements of operations constitute forward-looking information and are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated. See “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” included elsewhere in this prospectus.

 

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RICE ENERGY INC.

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2013

(Unaudited)

 

(in thousands, except per share data)		Historical Rice Energy Inc.				Consolidation of Marcellus JV Pro Forma Adjustments (a)				Offering Pro Forma Adjustments				Pro Forma Rice Energy Inc.
Revenues:
Natural gas sales		$	87,847			$	90,677			$	—			$	178,524
Other revenue			757				—				—				757
Total revenues			88,604				90,677				—				179,281
Operating expenses:
Lease operating			8,309				8,193				—				16,502
Gathering, compression and transportation			9,774				15,663				—				25,437
Production taxes and impact fees			1,629				1,258				—				2,887
Exploration			9,951				—				—				9,951
Restricted unit expense			32,906				—				—				32,906
General and administrative			16,953				3,256				—				20,209
Depreciation, depletion and amortization			32,815				39,071	(b)			—				71,886
Loss on impairment of natural gas properties			—				146				—				146
Loss from sale of interest in gas properties			4,230				—				—				4,230
Total operating expenses			116,567				67,587				—				184,154
Operating income (loss)			(27,963	)			23,090				—				(4,873	)
Interest income (expense)			(17,915	)			(880	)			2,373	(d)			(16,422	)
Other expense			(357	)			(796	)			—				(1,153	)
Gain on derivative instruments			6,891				3,347				—				10,238
Amortization of deferred financing costs			(5,230	)			(164	)			—				(5,394	)
Loss on extinguishment of debt			(10,622	)			—				—				(10,622	)
Equity in income (loss) of joint ventures			19,420				(19,330	)			—				90
Income (loss) before income taxes			(35,776	)			5,267				2,373				(28,136	)
Income tax benefit			—				—				11,674	(c)			11,674
Net income (loss)		$	(35,776	)		$	5,267			$	14,047			$	(16,462	)
Loss per share—basic														$	(0.13	)
Loss per share—diluted (e)														$	(0.13	)

See accompanying Notes to Pro Forma Financial Data (Unaudited)

 

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RICE ENERGY INC.

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE NINE

MONTHS ENDED SEPTEMBER 30, 2014

(Unaudited)

 

		Rice Energy Inc.				Consolidation of Marcellus JV Pro Forma Adjustments				Re-organization and Offering Pro Form Adjustments				Pro Forma Rice Energy Inc.
Revenues:
Operating revenues		$	261,545			$	11,936							$	273,481
Operating expenses:
Lease Operating			16,406				420								16,826
Gathering, compression and transportation			25,904				1,390								27,294
Production taxes and impact fees			2,624				69								2,693
Exploration			1,706												1,706
Incentive unit expense			101,695												101,695
Stock compensation			3,274												3,274
General and administrative			36,733				72								36,805
Depreciation, depletion and amortization			91,912				2,856								94,768
Acquisition expense			2,246												2,246
Amortization of intangible assets			748												748
Total operating expense			283,248				4,807				—				288,055
Operating income (loss)			(21,703	)			7,129				—				(14,574	)
Interest expense			(38,737	)			(235	)							(38,972	)
Gain on purchase of Marcellus joint venture			203,579							$	(203,579	)
Other income			180												180
Gain (loss) on derivative instruments			5,357				(12,191	)							(6,834	)
Amortization of deferred financing costs			(1,728	)			(15	)							(1,743	)
Loss on extinguishment of debt			(3,934	)											(3,934	)
Write-off of deferred financing costs			(6,896	)											(6,896	)
Equity in income (loss) of joint ventures			(2,656	)							2,656				—
Income (loss) before income taxes			133,462				(5,312	)			(200,923	)			(72,773	)
Income tax benefit (expense)			(18,787	)							7,763				(11,024	)
Net income (loss)		$	114,675			$	(5,312	)		$	(193,160	)		$	(83,797	)
Earnings per share—basic														$	(0.65	)
Earnings per share—diluted														$	(0.65	)

See accompanying Notes to Pro Forma Financial Data (Unaudited)

 

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RICE ENERGY INC.

NOTES TO PRO FORMA FINANCIAL DATA

(Unaudited)

 

1.	Basis of Presentation, Transactions and this Offering

The historical financial information is derived from the historical financial statements of Rice Energy Inc. The pro forma adjustments have been prepared as if the Marcellus JV Buy-In and the IPO described in this prospectus had each taken place as of January 1, 2013. The adjustments are based on information available as of November 12, 2014, and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments.

 

2.	Pro Forma Condensed Consolidated Statement of Operations Adjustments and Assumptions—Unaudited

The adjustments are based on information available as of November 12, 2014, and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. A description of these transactions and adjustments is provided as follows:

 

(a)

Reflects the consolidation of Alpha Shale Resources, L.P. and elimination of the investment in joint ventures associated therewith as a result of the Marcellus JV Buy-In.

 

(b)

Reflects the impact of applying purchase accounting to the acquisition of Alpha Shale Resources, L.P. The assigned fair values are subject to final purchase accounting valuation adjustments under GAAP and may change.

 

(c)

Reflects estimated incremental income tax provision assuming the earnings of Rice Energy Inc. and Alpha Shale Resources, L.P. had been subject to federal income tax as a subchapter C corporation using an effective tax rate of approximately 41%. This rate is inclusive of federal, state and local income taxes.

 

(d)

Reflects the elimination of interest expense related to the revolving credit facilities of Rice Drilling B, LLC and Alpha Shale Resources, L.P., which were repaid in full in connection with the IPO, partially offset by an increase in unused commitment fees related to the revolving credit facility of Rice Drilling B, LLC.

 

(e)

Reflects basic and diluted income per common share giving effect to (i) the issuance of 9,523,810 shares of common stock to Alpha Holdings as partial consideration of the Marcellus JV Buy-In and (ii) the issuance of 30,000,000 shares of common stock in the IPO. As we incurred a loss for the period presented, no dilutive impact occurred.

 

(f)

Reflects the elimination of the non-recurring gain on acquisition of our Marcellus joint venture resulting from the remeasurement of our equity investment at fair value at the time of purchase.

 

3.	Income Taxes—Unaudited

At the date of IPO, Rice Energy Inc. owned 100% of Rice Drilling B and Subsidiaries. Rice Drilling B was a limited liability company not subject to federal income taxes before IPO. However, in connection with the closing of the IPO, as a result of our corporate reorganization, we became a corporation subject to federal income tax and, as such, our future income taxes will be dependent upon our future taxable income. The change in tax status would require the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting deferred tax liability is approximately $145.1 million.

No current tax expense would result as of the date of the change in status. The recognition of the initial deferred tax liability will be recorded in equity at the date of IPO, but not in the financials as of December 31, 2013.

 

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4.	Supplemental Information on Gas-Producing Activities—Unaudited

The historical pro forma supplemental natural gas disclosure is derived from the combined financial statements of Rice Energy and our Marcellus joint venture included elsewhere in this prospectus and valuations prepared by the independent petroleum engineering firm of Netherland, Sewell and Associates, Inc. for us and our Marcellus joint venture. For information regarding our independent petroleum engineers and the basis and assumptions for our reserve estimates, please see Note 17 to the consolidated financial statements of Rice Energy and Note 11 to the financial statements for Alpha Shale Resources, LP as of and for the year ended December 31, 2013. The unaudited pro forma combined supplemental natural gas disclosures of the Company reflect the combined historical results of Rice Energy and Alpha Shale Resources, LP, on a pro forma basis to give effect to the transactions, described above, as if they had occurred on December 31, 2013 for pro forma supplemental natural gas disclosure purposes.

In accordance with SEC regulations, reserves at December 31, 2013 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing natural gas properties. Accordingly, the estimates may change as future information becomes available.

Pro forma reserve quantity information for the year ended December 31, 2013 is as follows (in millions of cubic feet, MMcf):

 

		Historical Rice Energy				Consolidation of Marcellus JV Pro Forma Adjustments				Pro Forma Rice Energy Inc.
Proved developed and undeveloped reserves:
Beginning of year			304,272				256,236				560,508
Extensions and discoveries			100,626				39,623				140,249
Revisions of previous estimates			757				(53,605	)			(52,848	)
Production			(22,995	)			(22,886	)			(45,881	)
End of year			382,660				219,368				602,028
Proved developed reserves:
Beginning of year			61,225				70,026				131,251
End of year			144,310				104,741				249,051
Proved undeveloped reserves:
Beginning of year			243,047				186,210				429,257
End of year			238,350				114,627				352,977

Extensions, Discoveries and Other Additions

On a pro forma basis, we added 140,249 MMcf through its drilling program in the Marcellus Shale in 2013.

 

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Information with respect to our pro forma estimated discounted future net cash flows related to proved natural gas reserves as of December 31, 2013 is as follows (in thousands):

 

		Historical Rice Energy				Consolidation of Marcellus JV Pro Forma Adjustments				IPO Pro Forma Adjustments				Pro Forma Rice Energy Inc.
Future cash inflows		$	1,496,294			$	854,334			$	—			$	2,350,628
Future production costs			(517,101	)			(264,853	)			—				(781,954	)
Future development costs			(219,879	)			(92,689	)			—				(312,568	)
Future income tax expenses			—				—				(451,493	)			(451,493	)
Future net cash flows			759,314				496,792				(451,493	)			804,613
10% discount for estimated timing of cash flows			(342,150	)			(204,586	)			185,781				(360,955	)
Standardized measure of discounted future net cash flows		$	417,164			$	292,206			$	(265,712	)		$	443,658

For information on our assumptions regarding pricing, please see Note 17 to the consolidated financial statements of Rice Energy and Note 11 to the financial statements for Alpha Shale Resources, LP as of and for the year ended December 31, 2013.

The following are the principal sources of changes in our pro forma standardized measure of discounted future net cash flows for 2013 (in thousands):

 

		Historical Rice Energy				Consolidation of Marcellus JV Pro Forma Adjustments				IPO Pro Forma Adjustments				Pro Forma Rice Energy Inc.
Balance at beginning of period		$	102,218			$	142,154			$	(23,942	)		$	220,430
Net change in prices and production costs			101,345				163,948				—				265,293
Net change in future development costs			29,336				5,563				—				34,899
Natural gas net revenues			(68,135	)			(65,563	)			—				(133,698	)
Extensions			114,489				37,901				—				152,390
Revisions of previous quantity estimates			1,133				(29,504	)			—				(28,371	)
Previously estimated development costs incurred			66,894				62,507				—				129,401
Changes in taxes			—				—				(241,770	)			(241,770	)
Accretion of discount			10,230				14,222				—				24,452
Changes in timing and other			59,654				(39,022	)			—				20,632
Balance at end of period		$	417,164			$	292,206			$	(265,712	)		$	443,658

Gains on sales of interests in gas properties are not included in the information set forth above. We have also allocated certain general and administrative expenses to our results of operations as these expenses relate to production activities.

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Rice Energy Inc.

We have audited the accompanying consolidated balance sheets of Rice Energy Inc. as of December 31, 2013 and 2012, and the related consolidated statements of operations, cash flows and equity for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Rice Energy Inc. at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

March 21, 2014 (except for Note 1, Note 8, Note 15 and Note 16,

as to which the date is August 8, 2014)

 

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RICE ENERGY INC.

CONSOLIDATED BALANCE SHEETS

 

		December 31,
(in thousands)		2013				2012
Assets
Current assets:
Cash		$	31,612			$	8,547
Restricted cash			8,268				—
Accounts receivable			31,765				8,557
Receivable from affiliate			2,244				11,879
Prepaid expenses and other			863				321
Total current assets			74,752				29,304
Investments in joint ventures			49,814				30,976
Gas collateral account			3,700				5,843
Proved natural gas properties, net			270,523				159,988
Unproved natural gas properties			457,836				111,030
Property and equipment, net			5,972				2,622
Deferred financing costs, net			12,292				5,208
Other non-current assets			4,921				—
Total assets		$	879,810			$	344,971
Liabilities and stockholders’ equity
Current liabilities:
Current portion of long-term debt		$	20,120			$	8,814
Accounts payable			51,219				19,793
Royalties payable			9,393				1,960
Accrued interest			250				2,004
Accrued capital expenditures			16,753				2,359
Other accrued liabilities			8,283				5,585
Leasehold payable			18,606				3,954
Derivative liabilities			965				2,260
Payable to affiliate			6,148				2,482
Operated prepayment liability			1,201				11,553
Total current liabilities			132,938				60,764
Long-term liabilities:
Long-term debt			406,822				140,506
Leasehold payable			1,675				106
Restricted units			36,306				3,400
Other long-term liabilities			3,422				2,004
Total liabilities			581,163				206,780
Stockholders’ equity			298,647				138,191
Total liabilities and stockholders’ equity		$	879,810			$	344,971

See accompanying Notes to Consolidated Financial Statements.

 

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RICE ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

 

		Years Ended December 31,
(in thousands)		2013				2012				2011
Revenues:
Natural gas sales		$	87,847			$	26,743			$	13,972
Other revenue			757				457				—
Total revenues			88,604				27,200				13,972
Operating expenses:
Lease operating			8,309				3,688				1,617
Gathering, compression and transportation			9,774				3,754				540
Production taxes and impact fees			1,629				1,382				—
Exploration			9,951				3,275				660
Restricted unit expense			32,906				—				170
General and administrative			16,953				7,599				5,208
Depreciation, depletion and amortization			32,815				14,149				5,981
Write-down of abandoned leases			—				2,253				109
Loss (gain) from sale of interest in gas properties			4,230				—				(1,478	)
Total operating expenses			116,567				36,100				12,807
Operating income (loss)			(27,963	)			(8,900	)			1,165
Other income (expense):
Interest expense			(17,915	)			(3,487	)			(531	)
Other income (expense)			(357	)			112				161
Gain (loss) on derivative instruments			6,891				(1,381	)			574
Amortization of deferred financing costs			(5,230	)			(7,220	)			(2,675	)
Loss on extinguishment of debt			(10,622	)			—				—
Equity in income of joint ventures			19,420				1,532				370
Total other expense			(7,813	)			(10,444	)			(2,101	)
Net loss		$	(35,776	)		$	(19,344	)		$	(936	)
Weighted average common shares outstanding;
Basic and Diluted			80,441				57,967				39,958
Net loss per common share
Basic and Diluted		$	(0.44	)		$	(0.33	)		$	(0.02	)
Pro forma income tax benefit			14,844
Pro forma net loss		$	(20,932	)
Pro forma net loss per common share
Basic and Diluted		$	(0.26	)

See accompanying Notes to Consolidated Financial Statements.

 

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RICE ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Years Ended December 31,
(in thousands)		2013				2012				2011
Cash flows from operating activities:
Net loss		$	(35,776	)		$	(19,344	)		$	(936	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			32,815				14,149				5,981
Amortization of deferred financing costs			5,230				7,220				2,675
Loss (gain) from sale of interest in gas properties			4,230				—				(1,478	)
Restricted unit expense			32,906				—				170
Write-off of unsuccessful exploratory well costs			8,143				—				—
Derivative instruments fair value (gain) loss			(6,891	)			1,381				(574	)
Equity in income of joint ventures			(19,420	)			(1,532	)			(370	)
Write-down of abandoned leases and other leasehold costs			—				2,253				109
(Increase) decrease in:
Accounts receivable			(17,208	)			(3,828	)			(4,310	)
Receivable from affiliate			9,635				(8,403	)			(76	)
Gas collateral account			643				(4,137	)			(207	)
Prepaid expenses and other			(541	)			(212	)			73
Cash receipts for settled derivatives			676				879				574
Increase (decrease) in:
Accounts payable			2,273				(30	)			(125	)
Royalties payable			7,432				775				1,117
Other accrued expenses			5,859				7,391				746
Payable to affiliate			3,666				424				1,762
Net cash provided by (used in) operating activities			33,672				(3,014	)			5,131
Cash flows from investing activities:
Capital expenditures for natural gas properties			(463,128	)			(109,149	)			(69,077	)
Investment in joint ventures			—				(9,957	)			(15,205	)
Capital expenditures for property and equipment			(2,259	)			(867	)			(673	)
Proceeds from sale of interest in gas properties			6,792				—				5,710
Net cash used in investing activities			(458,595	)			(119,973	)			(79,245	)
Cash flows from financing activities:
Proceeds from borrowings			435,500				44,361				82,972
Repayments of debt obligations			(160,760	)			(10,152	)			(7,726	)
Restricted cash for convertible debt			(8,268	)			—				—
Debt issuance costs			(12,194	)			(1,913	)			(9,699	)
Common stock issuance			195,977				96,782				7,900
Repurchase of common stock			(2,267	)			(1,133	)			—
Return of capital			—				(800	)			—
Net cash provided by financing activities			447,988				127,145				73,447
Net increase (decrease) in cash			23,065				4,158				(667	)
Cash at the beginning of the year			8,547				4,389				5,056
Cash at the end of the year		$	31,612			$	8,547			$	4,389
Supplemental disclosure of noncash investing and financing activities
Capital expenditures for natural gas properties financed by accounts payable		$	48,615			$	18,083			$	10,529
Capital expenditures for natural gas properties financed by other accrued liabilities			16,753				2,359				5,936
Natural gas properties financed through borrowings			—				18,328				1,016
Accretion of debt discount			2,099				—				—
Gas collateral financed by accounts payable			—				1,500				—
Capital expenditures for property, office furniture and equipment funded by capital lease borrowings			1,557				419				—
Property and equipment financed through borrowings			503				1,270				—
Natural gas properties financed through deferred payment obligations			20,281				3,577				5,314
Natural gas properties financed through other liabilities			—				8,261				—
Application of advances from joint interest owners			(10,415	)			—				—
Warrants issued in exchange for services			—				—				3,294
Conversion of related-party note payable to common stock			255				11,332				—

See accompanying Notes to Consolidated Financial Statements.

 

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RICE ENERGY INC.

CONSOLIDATED STATEMENTS OF EQUITY

YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

 

		Common Stock ($0.01 par)				Additional Paid-In Capital				Accumulated Deficit				Total
Balance as December 31, 2010		$	392			$	45,223			$	(9,052	)		$	36,563
Capital Contributions			14				7,886				—				7,900
Issuance of warrants			—				3,294				—				3,294
Net loss			—				—				(936	)			(936	)
Balance as December 31, 2011			406				56,403				(9,988	)			46,821
Capital Contributions, net			192				99,990				—				100,182
Return of Capital			(1	)			(799	)			—				(800	)
Conversion of related-party notes payable			25				11,307				—				11,332
Net loss			—				—				(19,344	)			(19,344	)
Balance at December 31, 2012			622				166,901				(29,332	)			138,191
Capital Contributions, net			258				195,974				—				196,232
Net loss			—				—				(35,776	)			(35,776	)
Balance at December 31, 2013		$	880			$	362,875			$	(65,108	)		$	298,647

See accompanying Notes to Consolidated Financial Statements.

 

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RICE ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1.	Summary of Significant Accounting Policies and Related Matters

Organization, Operations and Principles of Consolidation

The consolidated financial statements of the Company include the accounts of Rice Energy Inc. (“the Company” or “Rice Energy”) and its wholly owned subsidiaries, Rice Drilling B LLC (“Rice Drilling B”), Rice Drilling C LLC (“Rice C”), Rice Drilling D LLC (“Rice D”), RDB Real Estate Holdings LLC (“RDB Real Estate”), Blue Tiger Oilfield Services LLC (“Blue Tiger”), Rice Poseidon Midstream LLC (“Rice PM”), and Rice Olympus Midstream LLC (“Rice OM”). All significant intercompany accounts have been eliminated in consolidation.

In October 2013, the Company was formed as a Delaware corporation for the purpose of becoming a publicly traded company and the holding company of Rice Drilling B. The historical financial information contained in this report relates to periods that ended prior to the completion of the IPO of Rice Energy. In connection with the completion of its IPO and corporate reorganization on January 29, 2014, Rice Energy became a holding company whose sole material asset consists of a 100% indirect ownership interest in Rice Drilling B. As the sole managing member of Rice Drilling B, Rice Energy is responsible for all operational, management and administrative decisions relating to Rice Drilling B. Accordingly, this reorganization constituted a common control transaction and the accompanying consolidated financial statements are presented as though this reorganization had occurred for the earliest period presented herein.

On January 25, 2012, Rice Partners, the owner of 90% of the total shares outstanding in Rice Energy, assigned its preferred units in Rice Energy to its wholly owned subsidiary, Rice Energy Appalachia LLC (“REA”). Concurrent with Rice Partners’ assignment of its shares to REA, REA and Natural Gas Partners (“NGP”), a private equity firm, finalized a $100.0 million equity commitment to REA from NGP of which $75 million of NGP’s commitment was funded at closing on January 25, 2012. Cash proceeds from the investments were contributed by REA to Rice Energy. NGP received a put right with respect to their equity investment at REA which was contingently exercisable upon the occurrence of certain events. The earliest date that this put right could have been exercised is January 25, 2017. The fair value of this put right was de minimis given the accretion in fair value of REA. In conjunction with the equity investment in NGP, Daniel J. Rice III converted his outstanding promissory notes into equity of REA. On August 30, 2012, NGP funded the remaining $25 million of its commitment at REA.

During the year ended December 31, 2013, REA finalized a $300 million equity commitment from NGP, of which approximately $200 million was funded in April 2013 and contributed to Rice Energy. Cash proceeds from the investment were used to partially fund our Utica Shale leasehold acquisitions in southeastern Ohio. NGP’s equity commitments terminated in connection with the closing of the Rice Energy Inc. (“Rice Energy”) initial public offering (“IPO”).

Rice Drilling B is the operating company of Rice Energy and as such is engaged in the acquisition, exploration, and development of natural gas properties in the Appalachian Basin.

Use of Estimates

The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates and changes in these estimates are recorded when known.

 

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Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Company under contracts with the Company’s natural gas marketers. Pricing provisions are tied to the Platts Gas Daily market prices.

Cash

The Company maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed consolidated balance sheet amounts due to outstanding checks. The Company has no other accounts that are considered cash equivalents.

Accounts Receivable

Accounts receivable are primarily from the Company’s two gas marketers. The Company extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. There was no allowance recorded for any of the periods presented in the consolidated financial statements. Accounts receivable as of December 31, 2013 and 2012 are detailed below.

 

		December 31,
(in thousands)		2013				2012
Natural gas sales		$	16,534			$	5,564
Joint interest			6,391				1,810
Other			8,840				1,183
Total accounts receivable		$	31,765			$	8,557

Investments in Joint Ventures

The Company accounts for its oilfield service company joint venture investment and for periods prior to the completion of the Marcellus JV Buy-In accounted for our Marcellus joint venture investment, under the equity method of accounting as we have significant influence, but not control, over the joint ventures as of December 31, 2013.

Under the equity method of accounting, investments are carried at cost, adjusted for the Company’s proportionate share of the undistributed earnings or losses and reduced for any distributions from the investment. The Company also evaluates its equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in value of the investment. Such events may include sustained operating losses by the investee or long-term negative changes in the investee’s industry. These indicators were not present, and as a result, the Company did not recognize any impairment charges related to its equity method investments for any of the periods presented in the consolidated financial statements.

On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between it and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), Rice Energy completed its acquisition of Alpha Holdings’ 50% interest in its Marcellus joint venture (“Marcellus JV Buy-In”) in exchange for total consideration of $322 million, consisting of $100 million of cash and its issuance to Alpha Holdings of 9,523,810 shares of our common stock. See Note 15 for additional information.

 

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Natural Gas Properties

The Company uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in gas properties, to drill and equip exploratory wells that result in proved reserves, are capitalized. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. The Company wrote off approximately $8.1 million of costs associated with the drilling of the Bigfoot 7H in the fourth quarter of 2013.

Unproved gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the units of production method. Support equipment and other property and equipment not directly related to gas properties are depreciated over their estimated useful lives.

Management’s estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Company adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Company’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Company’s depreciation, depletion, and amortization expense, a change in the Company’s estimated reserves could have a material effect on the Company’s operating results.

On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.

Interest

The Company capitalizes interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Upon completion of construction of the asset, the associated capitalized interest costs are included within our asset base and depleted accordingly. The following table summarizes the components of the Company’s interest incurred for the periods indicated (in thousands):

 

		2013				2012				2011
Interest incurred:
Interest capitalized		$	8,034			$	7,695			$	5,405
Interest expensed			17,915				3,487				531
Total incurred		$	25,949			$	11,182			$	5,936

 

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Property and Equipment

Property and equipment are recorded at cost and are being depreciated over estimated useful lives of three to forty years on a straight-line basis. Accumulated depreciation was $1.3 million and $0.6 million at December 31, 2013 and 2012, respectively. Depreciation expense was $0.7 million, $0.6 million and $0.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in depreciation, depletion, and amortization expense in the accompanying statements of consolidated operations.

Long-Lived Assets

Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used or disposed other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less selling costs.

Deferred Financing Costs

Deferred financing costs are amortized on a straight-line basis, which approximates the interest method, over the term of the related agreement. Accumulated amortization was $14.3 million and $9.9 million at December 31, 2013 and 2012, respectively. Amortization expense was $5.2 million , $7.2 million and $2.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. The annual amortization of deferred financing costs for years subsequent to December 31, 2013, is expected to be approximately $1.9 million in 2014, $1.9 million in 2015, $1.9 million in 2016, $1.9 million in 2017 and $1.1 million in 2018.

Delay Rental Agreements

The Company has leased drilling rights under agreements which specify additional payments for the privilege of deferring drilling operations for another year. Costs incurred to extend such agreements were $1.6 million and $3.1 million for the years ended December 31, 2013 and 2012, respectively.

Asset Retirement Obligations

The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. The Company’s retirement obligations relate to the abandonment of gas-producing facilities and include costs to reclaim drilling sites and dismantle and relocate or dispose of gathering systems, wells, and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.

When a new liability is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.

Equity Incentives

The cost of employee and consultant services received in exchange for an award of equity instruments, such as restricted units, is measured based on the fair value of those instruments. Management established an estimated fair value for issued units based upon an income approach prior to December 31, 2013. At December 31, 2013, in connection with the IPO, a market approach was used. The restricted units are subject to a call option held by the Company which requires liability accounting for the restricted units. Details related to the restricted units are included in Notes 8 and 9.

 

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Income Taxes

The Company is treated as a partnership for federal and state income tax purposes. Consequently, the Company is not subject to income taxes; instead its members include the income in their tax returns.

Reclassifications

Certain reclassifications have been made to prior periods’ financial information related to post production costs, restricted unit liability and asset retirement obligations to conform to the 2013 presentation.

Correction of Errors

The Company’s net income for the year ended December 31, 2012 included expense of approximately $1.7 million that related to prior periods. These corrections resulted in additional exploration expense of approximately $1.1 million, lease operating expense of $0.5 million, and other expense of $0.1 million recorded in 2012. These errors were not material to prior periods, individually or in the aggregate, and were not material to the 2012 period. These errors did not impact debt covenant compliance nor distort operating results. Therefore, these items were corrected in fiscal 2012.

 

2.	Capitalized Costs Relating to Gas-Producing Activities

Proved and unproved capitalized costs related to the Company’s gas-producing activities are as follows (in thousands):

 

		2013				2012
Capitalized costs:
Unproved properties		$	457,836			$	111,030
Proved, producing properties			244,771				119,374
Proved, nonproducing properties			78,441				61,434
Total			781,048				291,838
Accumulated depreciation, depletion and amortization			52,689				20,820
Net capitalized costs		$	728,359			$	271,018
Entity’s share of equity method investees’ net capitalized costs		$	91,166			$	57,110

 

3.	Sale of Interests in Gas Properties

In December 2013, the Company agreed to sell interests in noncore assets in Guernsey County, Ohio and Lycoming County, Pennsylvania in two separate transactions. The Company agreed to sell an undivided 75.0% interest in certain of its Guernsey County leaseholds (representing approximately 2,136 net acres) to a third party in exchange for approximately $22.0 million, consisting of $11.0 million in cash and an $11.0 million carried working interest. Of the 2,136 net acres, 1,033 net acres closed subsequent to December 31, 2013. No gain or loss was recorded on this transaction.

In addition, the Company sold all of its Lycoming County acreage (100% non-operated) and related assets to another third party in exchange for $7.0 million of which $6.0 million will be paid on or before April 30, 2014. This receivable is included in accounts receivable on the accompanying consolidated balance sheet. There was no production or net proved reserves attributable to the interests sold in either transaction. The Company incurred a loss of $4.2 million in the fourth quarter of 2013 as a result of this transaction.

In March 2011, the Company entered into a joint operating agreement with US Energy Development Corporation (US Energy) covering those certain properties whereby the Company sold a 50% non-operated working interest in the properties to US Energy. Subsequent to this transaction, the Company owns a 50%

 

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working interest in approximately 1,000 acres in the Whipkey field and has retained operatorship. The Company received cash consideration of $1.7 million and recorded a gain of $1.5 million on this transaction in the accompanying consolidated statements of operations.

 

4.	Long-Term Debt

Long-term debt consists of the following as of December 31, 2013 and 2012 (in thousands):

 

Description		December 31, 2013				December 31, 2012
Long-term Debt
Debentures (a)		$	6,890			$	60,000
Wells Fargo Energy Capital Credit Facility (b)			—				70,000
Second Lien Term Loan Facility (c)			293,821				—
NPI Note (d)			8,028				15,282
Senior Secured Revolving Credit Facility (e)			115,000				—
Other			3,203				4,038
Total debt		$	426,942			$	149,320
Less current portion			20,120				8,814
Long-term debt		$	406,822			$	140,506

Debentures (a)

In June of 2011, the Company sold $60.0 million of its 12% Senior Subordinated Convertible Debentures due 2014 (“the Debentures”) in a private placement to certain accredited investors as defined in Rule 501 of Regulation D. The Debentures accrue interest at 12% per year payable monthly in arrears by the 15th day of the month and mature on July 31, 2014 (“Maturity Date”). The Debentures are the Company’s unsecured senior obligations and rank equally with all of the Company’s current and future senior unsecured indebtedness.

From July 31, 2013 through August 20, 2013 (“the put redemption period”), any holder of Debentures had the right to cause the Company to repurchase all or any portion of the Debentures owned by such holder at 100% of the portion of the principal amount of the Debentures as to which the right was being exercised, plus a premium of 20%. During the put redemption period, the Company repurchased $53.1 million of outstanding Debentures and paid a put premium of $10.6 million in accordance with the terms of the agreements. The put redemption period expired in the nine months ended September 30, 2013 and the Company recorded the premium of $10.6 million as a loss on extinguishment of debt in the statement of consolidated operations for the year ended December 31, 2013.

At any time after July 31, 2013 until the Maturity Date, the Company has the right to redeem all, but not less than all, of the Debentures on 30 days prior written notice at a redemption price equal to 100% of the principal amount of the Debentures plus a premium of 50%. In connection with the IPO, the convertible debentures and warrants of Rice Drilling B were amended to become convertible or exercisable for an aggregate 1,671,800 shares of common stock of Rice Energy Inc. Through March 10, 2014, approximately $5.0 million of the convertible debentures had been converted into 433,073 shares of Rice Energy Inc. common stock. On February 28, 2014, the Company issued a call notice on the remaining convertible debentures, requiring a response by March 30, 2014. Amounts not converted by the redemption date will receive a cash payment from the Company of 100% of the principal amount plus a premium of 50%, which could result in additional costs of $1.0 million if all remaining convertible debentures are redeemed. As the principal amount of the convertible debentures outstanding has been reduced to less than $5.0 million, the Company is no longer required to maintain restricted cash.

In connection with the convertible debt offering, Rice Drilling B granted warrants that were issued on August 15, 2011, to certain of the broker-dealers involved in the private placement. These warrants are

 

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considered to be separate instruments issued solely in lieu of cash compensation for services provided by the broker-dealers. Two separate classes of warrants were issued (Normal and Bonus), the sole difference being the exercise price.

The fair value of these warrants at the date of grant was estimated using the Black-Scholes valuation model with the following assumptions:

 

Dividend yield			—	%
Expected volatility			72.1	%
Risk-free rate			0.96	%
Expected life			5 years
“Normal” warrant
Number of warrants issued			1,044
Exercise price		$	10,000
Grant date fair value, per unit		$	2,569
Weighted average contractual life			5 years
“Bonus” warrant
Number of warrants issued			192
Exercise price		$	6,250
Grant date fair value, per unit		$	3,184
Weighted average contractual life			5 years

The fair value of $3.3 million of the above warrants were recorded as a deferred financing cost during the year ended December 31, 2011, and were amortized over the term of the Debentures. Subsequent to December 31, 2013, two warrants had been exercised in exchange for 1,728 shares of Rice Energy Inc. common stock. If all warrants are exercised approximately 1.1 million shares of Rice Energy Inc. common stock would be issued.

Wells Fargo Energy Capital Credit Facility (b)

In November of 2012, the Company amended and restated its then existing credit facility with Wells Fargo. In connection with the amendment and restatement, a lender was added to the new facility. The amendment and restatement was accounted for as a modification of the debt, resulting in $0.2 million of third-party costs associated with the amendment and restatement being expensed. The Wells Fargo Energy Capital Credit Facility (“Wells Fargo Energy Capital Credit Facility”) was subject to a maximum borrowing base equal to $200.0 million, as determined unanimously by Wells Fargo Energy Capital, in accordance with customary lending practices. This loan was repaid using proceeds from the Second Lien Term Loan Facility during the second quarter of 2013.

Second Lien Term Loan Facility (c)

On April 25, 2013, the Company entered into a Second Lien Term Loan Facility (“Second Lien Term Loan Facility”) with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million. The Company estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $4.5 million. The discount is being amortized over the life of the note using an effective interest rate of 0.284% using the effective yield method. As of December 31, 2013, the Company had a balance of $293.8 million relating to the Second Lien Term Loan Facility, this includes borrowings outstanding of $297.7 million less a discount of $3.9 million. The Second Lien Term Loan Facility matures October 25, 2018. Approximately $7.3 million in fees were capitalized in connection with the Second Lien Term Loan Facility.

 

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Principal amounts borrowed under the Second Lien Term Loan Facility are payable in an amount equal to 0.25% of the initial principal amount at the end of each quarter with the remainder payable on the maturity date. Interest is payable in arrears at the end of each quarter and on the maturity date. The Company has the choice to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus 725 basis points. Base rate loans bear interest at a rate per annum equal to the greatest of (i) 2.25%, (ii) the agent bank’s reference rate, (iii) the federal funds effective rate plus 50 basis points and (iv) the rate for one month Eurodollar loans plus 100 basis points, plus 625 basis points. The Company may prepay the borrowings under the Second Lien Term Loan Facility at any time, provided that any prepayments of principal amounts during the first year following the closing date are subject to a 2% premium and any prepayments of principal during the second year following the closing date are subject to 1% premium. The interest rate was 8.5% as of December 31, 2013.

The Second Lien Term Loan Facility is secured by liens on substantially all of the Company’s properties that are subordinated to the liens securing the revolving credit facility and guarantees from the Company’s subsidiaries other than any subsidiary that have been designated as an unrestricted subsidiary. The Second Lien Term Loan Facility contains restrictive covenants that may limit the Company’s ability to, among other things:

 

•

incur additional indebtedness;

 

•

sell assets;

 

•

withdraw funds from specified restricted account;

 

•

make loans to others;

 

•

make investments;

 

•

enter into mergers;

 

•

make or declare dividends;

 

•

hedge future production or interest rates;

 

•

incur liens; and

 

•

engage in certain other transactions without the prior consent of the lenders.

The Second Lien Term Loan Facility also requires the Company to maintain an asset coverage ratio, which is the ratio of the present value of oil and gas reserves (discounted at 10% per annum) to the sum of all secured debt (including any debt incurred by the Company’s Marcellus joint venture under its credit facility or any replacement or refinancing of its credit facility) of not less than 1.5 to 1.0.

The Company was in compliance with such covenants and ratios as of December 31, 2013.

NPI Note (d)

In November of 2012, in connection with the amendment of the Wells Fargo Credit Facility, the Company repurchased the NPI it had previously assigned to Wells Fargo for $26.5 million, of which $9.5 million was paid at the closing of the Wells Fargo Energy Capital Credit Facility and $17.0 million was financed by a note to Wells Fargo. The Company accounted for this as the acquisition of a mineral right and therefore capitalized this amount in proved properties and will amortize using the units of production method. There is no stated interest rate associated with this note and as a result, this note was considered to have below market financing rates. The Company estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $2.0 million. The discount is being amortized over the life of the note using an effective interest rate of 12.10% using the effective yield method. As part of the use of proceeds from the Second Lien Term Loan Facility, the Company repaid $8.5 million of this note during the second quarter of 2013. A final payment of $8.5 million is due to be repaid in June of 2014.

 

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Senior Secured Revolving Credit Facility (e)

On April 25, 2013, the Company entered into a revolving credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $500.0 million and a sublimit for letters of credit of $10.0 million. As of December 31, 2013, the sublimit for the letters of credit was $100.0 million. The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is redetermined semiannually as of each January 1 and July 1 and depends on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and our commodity hedge positions. The next redetermination is scheduled to occur in April 2014. As of December 31 2013, the borrowing base was $200.0 million. As of December 31, 2013, we had $115.0 million in borrowings and approximately $22.5 million in letters of credit outstanding under our revolving credit facility. The revolving credit facility matures April 25, 2018.

Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. The Company has a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 175 to 275 basis points, depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the percentage of our borrowing base utilized. The Company may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. The weighted average interest rate was 2.39% as of December 31, 2013.

The credit facility is secured by liens on substantially all of the properties of the Company and guarantees from its subsidiaries other than any subsidiary that we have designated as an unrestricted subsidiary. The credit facility contains restrictive covenants that may limit our ability to, among other things:

 

•

incur additional indebtedness;

 

•

sell assets;

 

•

make loans to others;

 

•

make investments;

 

•

enter into mergers;

 

•

make or declare dividends;

 

•

hedge future production or interest rates;

 

•

incur liens; and

 

•

engage in certain other transactions without the prior consent of the lenders.

The credit facility also requires the Company to maintain the following three financial ratios, which are measured at the end of each calendar quarter:

 

•

a current ratio, which is the ratio of the Company’s consolidated current assets (includes unused commitment under the credit facility and excludes derivative assets) to its consolidated current liabilities, of not less than 0.75 to 1.0 as of March 31, 2013 and 1.0 to 1.0 at the end of each fiscal quarter thereafter;

 

•

a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX based on the trailing twelve month period to consolidated interest expense, of not less than 2.5 to 1.0; and

 

•

an asset coverage ratio, which is the ratio of the present value of the Company’s oil and gas reserves (discounted at 10% per annum) to the sum of all our secured debt (including 50% of any debt incurred

 

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by the Company’s Marcellus joint venture under its credit facility or any replacement or refinancing of its credit facility) of not less than 1.5 to 1.0 so long as any debt is outstanding under the term loan facility.

The Company was in compliance with such covenants and ratios as of December 31, 2013.

Concurrently with the closing of Rice Energy’s IPO, the Company amended its revolving credit facility to, among other things, increase the maximum commitment amount to $1.5 billion and lower the interest rate owed on amounts borrowed under the revolving credit facility. After giving effect to the amendment, the borrowing base under the credit facility was increased to $350 million as a result of the Marcellus JV Buy-In. Eurodollar loans under the amended revolving credit facility bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of borrowing base utilized. The Company will be subject to the same financial ratios and substantively the same restricted covenants as under the revolving credit facility prior to such amendment. The amended revolving credit facility will mature upon the earlier of the date that is five years following the closing of the amendment and the date that is 180 days prior to the maturity of the second lien term loan facility, if any amounts are outstanding under that facility as of such date.

Expected aggregate maturities of notes payable subsequent to December 31, 2013, are as follows (in thousands):

 

2014		$	20,120
2015			3,058
2016			2,277
2017			2,173
2018			399,314
Total		$	426,942

Interest paid in cash was $27.7 million and $10.2 million for years ended December 31, 2013 and 2012, respectively. See Note 1 for information on capitalized interest.

 

5.	Fair Value of Financial Instruments

The Company determines fair value on a recurring basis for its liability related to restricted units and recorded amounts for derivative instruments as these instruments are required to be recorded at fair value for each reporting amount. Certain amounts in the Company’s financial statements are measured at fair value on a nonrecurring basis including discounts associated with long-term debt. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.

The Company has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The Company’s fair value measurements relating to restricted units are included in Level 3. The Company’s fair value measurements relating to derivative instruments are included in Level 2. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in each category.

 

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Items included in Level 3 are valued using internal models that use significant unobservable inputs. Items included in Level 2 are valued using management’s best estimate of fair value corroborated by third-party quotes.

The following liabilities were measured at fair value on a recurring basis during the period (refer to Notes 9 and 11 for details relating to the restricted units and derivative instruments) (in thousands):

 

						Fair Value Measurements at Reporting Date Using
Description		December 31, 2013				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Assets:
Derivative Instruments, at fair value		$	4,921			$	—			$	4,921			$	—
Total assets		$	4,921			$	—			$	4,921			$	—
Liabilities:
Restricted units, at fair value		$	36,306			$	—			$	—			$	36,306
Derivative Instruments, at fair value			965				—				965				—
Total liabilities		$	37,271			$	—			$	965			$	36,306

 

						Fair Value Measurements at Reporting Date Using
Description		December 31, 2012				Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Liabilities:
Restricted units, at fair value		$	5,667			$	—			$	—			$	5,667
Derivative Instruments, at fair value			2,260				—				2,260				—
Total liabilities		$	7,927			$	—			$	2,260			$	5,667

 

		Fair Value Measurements Using
		Significant Unobservable Inputs (Level 3)
Balance at December 31, 2011		$	6,800
Total gain or losses:
Included in earnings			115
Transfers in and/or out of Level 3			—
Repurchase of restricted units			(1,133	)
Settlement			(115	)
Balance at December 31, 2012		$	5,667
Total gain or losses:
Included in earnings			32,906
Transfers in and/or out of Level 3			—
Repurchase of restricted units			(2,267	)
Settlement			—
Balance at December 31, 2013		$	36,306

 

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Gains and losses related to restricted units included in earnings for the period are reported in operating expenses in the statements of consolidated operations.

The carrying value of cash equivalents approximates fair value due to the short maturity of the instruments.

The estimated fair value of long-term debt on the consolidated balance sheets at December 31, 2013 and 2012 is shown in the table below (refer to Note 4 for details relating to the borrowing arrangements) (in thousands). The fair value was estimated using Level 3 inputs based on rates reflective of the remaining maturity as well as the Company’s financial position.

 

Description		2013				2012
Long-term debt, at fair value
Debentures		$	12,671			$	70,220
Wells Fargo Energy Capital Credit Facility			—				70,000
Second Lien Term Loan Facility			315,284				—
NPI Note			8,028				15,282
Senior Secured Revolving Credit Facility			115,000				—
Other			3,203				4,038
Total		$	454,186			$	159,540

 

6.	Lease Obligations

The Company leases drilling rights under agreements which expire at various times. The following represents the future minimum lease payments under the agreements as of December 31, 2013 (in thousands):

 

2014		$	18,606
2015			1,398
2016			153
2017			124
2018 and thereafter			—
Total future minimum lease payments		$	20,281

These lease payments are included as leasehold payables in the accompanying consolidated balance sheets.

Additionally, the Company has leased drilling rights under agreements which specify additional payments due in the event that the Company does not meet predetermined criteria within a specified period of time. The Company could be required to pay up to approximately $2.0 million, $1.0 million and $0.3 million in 2014, 2015 and 2016, respectively, under these agreements.

 

7.	Asset Retirement Obligations

The Company is subject to certain legal requirements which result in recognition of a liability related to the obligation to incur future plugging and abandonment costs. The Company records a liability for such asset retirement obligations and capitalizes a corresponding amount for asset retirement costs. The liability is estimated using the present value of expected future cash flows, adjusted for inflation and discounted at the Company’s credit adjusted risk-free rate.

 

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A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the years ended December 31, 2013 and 2012 is as follows (in thousands):

 

Balance at December 31, 2010		$	289
Liabilities incurred			493
Accretion expense			53
Balance at December 31, 2011		$	835
Liabilities incurred			382
Accretion expense			164
Balance at December 31, 2012		$	1,381
Liabilities incurred			583
Accretion expense			150
Balance at December 31, 2013		$	2,114

 

8.	Stockholders’ Equity

Stockholders include consultants and employees of the Company as well as REA.

As of December 31, 2012, all common stock associated with the Class A units was reserved for issuance pursuant to a Restricted Unit Agreement (see Note 9). Additionally, in connection with NGP’s $100.0 million equity investment into REA in 2012, of which 100% of the net proceeds were invested into Rice Energy, Rice Energy issued 13,252,145 shares of common stock to REA.

During 2013, the Company finalized a $300.0 million equity commitment from NGP of which approximately $200.0 million of NGP’s commitment was funded at closing in April 2013. Cash proceeds from the investment were used to fund Utica Shale leasehold acquisitions in southeastern Ohio. As a part of the reorganization that occurred in connection with the Rice Energy IPO, the Company became a wholly-owned subsidiary of REA and the restricted units were exchanged for common stock of Rice Energy. Furthermore, NGP’s equity commitments terminated in connection with the closing of the Rice Energy IPO.

Liquidation Preference

Prior to the reorganization in connection with the Rice Energy IPO, the terms of the governance documents of the Company provided that in the event of any liquidation, dissolution or winding up of the Company, distributions would first be made to members holding senior preferred units until such members have received cumulative distributions in an amount equal to the preferred return as defined in the REA agreement, second to the members holding preferred units in the amount of $49.9 million, then, until the Company had achieved breakeven operations, as defined, to the members holding preferred and Class A common units in proportion to their ownership interests and thereafter to the members in proportion to their ownership units. Following the restructuring, distributions in such event would be made to the sole member.

Repurchase Option

Up until the third anniversary of the grant of Class A and B restricted units, the Company or a member of its affiliates had the right to repurchase all of the units from the member at $1,700 per unit, as defined and in accordance with the Company’s then-existing limited liability company agreement. Subsequent to the third anniversary of the grant of Class A and B restricted units, the Company or a member of its affiliates has the right to repurchase all of the units from the member at fair market value, not less than $1,700 per unit, in accordance with the Company’s then-existing limited liability company agreement.

 

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During 2012, REA exercised the option to repurchase all common shares associated with the 2,000 Class B restricted units for $3.4 million. In December 2012, a payment of $1.1 million was made by the Company to the member on behalf of REA. Additional payments of $2.3 million were made by the Company on behalf of REA in 2013. The Company was reimbursed these costs.

 

9.	Restricted Unit Agreements

Effective November 13, 2009, the Company entered into restricted unit agreements with an employee and consultants. Under separate and individual restricted unit agreements, the eligible employee and consultants are granted units which vest over a specified period of time. Each unit entitles the holder to an equity ownership in the Company. The restricted units are accounted for as liability awards, which require remeasurement each reporting period, as a result of the existence of a call option that permits the Company to repurchase the awards at a fixed amount that could be above or below fair market value of the units. Prior to November 13, 2012, the Company had the ability to exercise the call option at a specified amount. Subsequently, the Company’s call right is at fair market value. As of December 31, 2013, the remaining liability recorded for the restricted units represented fair value. Management established an estimated fair value for issued units based upon an income approach prior to December 31, 2013. The income approach requires use of internal business plans that are based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates, among other factors. At December 31, 2013, in connection with the Rice Energy IPO, a market approach was used.

During 2012, REA exercised its option to repurchase all of the 2,000 Class B restricted units. A summary of the change in vested restricted units is as follows:

 

		Restricted Units
Class A and Class B restricted units
Vested restricted units			4,000
Repurchased Class B restricted units			(2,000	)
Vested restricted units as of December 31, 2012			2,000
Repurchased Class B restricted units			—
Vested restricted units as of December 31, 2013			2,000

 

10.	Incentive Units

REA, as the parent company of Rice Drilling B, granted Incentive Units to certain members of management. The Incentive Units are not accounted for as equity instruments as the Incentive Units do not have the characteristics of a substantive class of equity. Rather, the Incentive Units provide the holders with a performance bonus for fair value accretion of REA equity. In connection with the January 2012 NGP investment in REA, 100,000 Tier I Legacy units, 13,000 Tier II Legacy units, and 17,000 Tier III Legacy units were issued. The Incentive Units will only be paid in cash and payout for each tier occurs when a specified level of cumulative cash distributions has been received by NGP.

In connection with the April 2013 NGP investment in REA, an additional 900,000 Tier I Legacy units, 987,000 Tier II Legacy Units and 983,000 Tier III Legacy Units were issued. In addition, 100,000 New Tier I Units, 100,000 New Tier II Units, 100,000 New Tier III Units, and 100,000 New Tier IV Units were issued. In June 2013, an additional 717,546 New Tier I Units, 577,546 New Tier II Units, 577,546 New Tier III Units, and 577,546 New Tier IV Units were issued to certain members of management. Similar to above, there is no payout of the awards until specified level of cumulative cash distributions has been received by NGP.

During 2012 and 2013, no payments were made in respect of Incentive Units. The Company has not recognized compensation cost on the Incentive Units because the payment conditions, which relate to a liquidity

 

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event are not probable at December 31, 2013. The estimated payout under these awards at December 31, 2013 is approximately $142.3 million if a liquidity event were to occur. Prior to December 31, 2013, this estimate was based upon an option pricing model with various Level 3 assumptions including internal business plans that were based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates, among other factors. To the extent market transactions were known, this information was factored into the fair value estimate. At December 31, 2013, the Company no longer used an income approach to estimate the fair value and instead utilized a market approach to estimate the fair value. This change in fair value method was a result of the Rice Energy IPO.

On January 23, 2014, in connection with our IPO and corporate reorganization, the incentive units described above were modified. As a result of these modifications, certain of these incentive units are to be settled in cash and others are to be settled by the issuance of stock. The Company has not yet quantified the amount of the expense associated with the modifications.

 

11.	Derivative Instruments

The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. Our derivative counterparties share in the Credit Agreement collateral. The Company’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently. As of December 31, 2013, the Company entered into derivative instruments with Wells Fargo Bank, N.A. and Bank of Montreal fixing the price it receives for natural gas through November 28, 2017, as summarized in the following table:

 

Swap Contract Expiration		MMbtu/day				Weighted Average Price
2014			87,219			$	4.112
2015			58,781			$	4.153
2016			68,326			$	4.233
2017			30,000			$	4.343

 

Collar Contract Expiration		MMbtu/day				Floor/Ceiling
2014			10,000			$	3.000/$5.800
2015			45,000			$	4.000/$4.500

 

Basis Contract Expiration		MMbtu/day				Swap ($/MMBtu)
2014			15,000			$	(0.205	)
2015			10,000			$	(0.410	)

The following is a summary of the Company’s derivative instruments, which are recorded in the consolidated balance sheets as of December 31, 2013 and 2012 (in thousands):

 

		December 31, 2013				December 31, 2012
Current derivative assets		$	2,270			$	46
Long-term derivative assets			6,030				—
		$	8,300			$	46
Current derivative liabilities		$	3,235			$	2,306
Long-term derivative liabilities			1,109				—
		$	4,344			$	2,306
Net current value of derivative liabilities		$	(965	)		$	(2,260	)
Net long-term value of derivative assets		$	4,921			$	—

 

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The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value (in thousands):

 

		December 31, 2013
Description		Gross Amounts of Recognized Assets				Gross Amounts Offset on Balance Sheet				Net Amounts of Assets (Liabilities) on Balance Sheet
Derivative assets		$	13,000			$	(4,700	)		$	8,300
Derivative liabilities		$	256			$	(4,600	)		$	(4,344	)

 

		December 31, 2012
Description		Gross Amounts of Recognized Assets				Gross Amounts Offset on Balance Sheet				Net Amounts of Assets (Liabilities) on Balance Sheet
Derivative assets		$	416			$	(370	)		$	46
Derivative liabilities		$	—			$	(2,306	)		$	(2,306	)

Both realized and unrealized gains and losses are recorded as a gain or loss on derivatives in the consolidated statement of operations under other income/expense. The Company had an unrealized gain of $6.2 million for the year ended December 31, 2013 and an unrealized loss of $2.3 million for the year ended December 31, 2012. There were no unrealized gains or losses for the year ended December 31, 2011. The Company had realized gains related to contract settlements of $0.7 million, $0.9 million and $0.6 million for the years ended December 31, 2013, 2012 and 2011 respectively.

 

12.	Commitments and Contingencies

On October 14, 2013, the Company entered into a Development Agreement and Area of Mutual Interest (“AMI”) Agreement with Gulfport Energy Corporation (“Gulfport”) covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. The Company refers to these agreements as “Utica Development Agreements.” Pursuant to the Utica Development Agreements, the Company had approximately 68.80% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Goshen and Smith Townships (the “Northern Contract Area”) and an approximately 42.63% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Wayne and Washington Townships (the “Southern Contract Area”), each within Belmont County, Ohio. The remaining participating interests are held by Gulfport. The participating interests of the Company and Gulfport in each of the Northern and Southern Contract Areas approximate the Company’s current relative acreage positions in each area.

Each quarter during the term of the Development Agreement, the Company and Gulfport will establish a work program and budget detailing the proposed exploration and development to be performed in the Northern and Southern Contract Areas, respectively, for the following year. The number of horizontal wells proposed to be drilled in each of the Northern Contract Area and Southern Contract Area is limited by the Development Agreement as follows: in 2013, no more than five wells; in 2014, between eight and 40 wells; in 2015, between eight and 50 wells; and thereafter, unlimited.

The Utica Development Agreements have terms of ten years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint operating agreement and the Company and Gulfport shall remain operators of drilling units located in the Northern AMI and Southern AMI, respectively, following such termination.

The Company is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.

 

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The Company has commitments for gathering and firm transportation under existing contracts with third parties. Future payments for these items as of December 31, 2013 totaled $637.2 million (2014—$28.3 million, 2015—$52.1 million, 2016—$65.6 million, 2017—$65.4 million, 2018—$64.0 million and thereafter—$361.8 million).

As of December 31, 2013, the Company had two horizontal drilling rigs under contract. One of these contracts expires in 2014. A third rig, which we took delivery of in February 2014, expires in 2015. Future payments for these items as of December 31, 2013 totaled $21.4 million (2014—$11.7 million and 2015—$9.7 million). Any other rig performing work for us is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the amounts above. The values above represent the gross amounts that we are committed to pay without regard to our proportionate share based on our working interest.

Capital leases are entered into for vehicle purchases. The acquisition value of vehicles recorded under capital leases is $2.0 million. Accumulated amortization related to capital leases was $0.2 million and $8 thousand as of December 31, 2013 and 2012, respectively. Amortization expense related to capital leases was $0.2 million, $8 thousand and $0 as of December 31, 2013, 2012 and 2011, respectively. Future lease payments under capital leases as of December 31, 2013 totaled $1.6 million (2014—$0.4 million, 2015—$0.3 million, 2016—$0.3 million, 2017—$0.5 million and 2018—$0.1 million).

Operating leases are primarily entered into for various office locations. Rental expense under operating leases was $0.2 million, $0.2 million and $0.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Future lease payments under non-cancelable operating leases as of December 31, 2013 totaled $4.5 million (2014—$0.6 million, 2015—$1.0 million, 2016—$0.9 million, 2017—$0.8 million, 2018—$0.8 million and thereafter—$0.4 million).

 

13.	Related-Party Transactions

In prior periods, the Company reimbursed Rice Partners for expenses incurred on behalf of the Company. General and administrative expenses incurred by Rice Partners and reimbursed by the Company were $9.3 million, $4.8 million and $3.1 million for the years ended December 31, 2013 , 2012 and 2011, respectively. As of December 31, 2013 and 2012, $6.1 million and $2.5 million, respectively, of general and administrative expenses was due to Rice Partners and is recorded as due to affiliate on the consolidated balance sheet. Prior to the closing of the Rice Energy IPO, the Company terminated its agreement to reimburse Rice Partners for expenses incurred on its behalf.

Payments totaling $2.2 million, $0.8 million and $0.6 million were made during the years ended December 31, 2013, 2012 and 2011 respectively to Geological Engineering Services, Inc. (“GES”) in respect of consultancy services. GES is a drilling and completion engineering consulting company specializing in unconventional reservoirs like the Marcellus Shale. John P. LaVelle, Rice Energy’s Vice President of Drilling, served as president of GES from February 1994 until February 2010. There were no amounts outstanding between the Company and GES as of any period presented.

The Company was reimbursed for costs incurred on behalf of the Company’s Marcellus joint venture. General and administrative expenses incurred by the Company and reimbursed by the Company’s Marcellus joint venture were $1.6 million, $1.3 million and $0.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.

As of December 31, 2012, the Company recorded a receivable from its Marcellus joint venture for $6.0 million representing capitalized costs that were approved to be contributed to the joint venture.

 

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14.	Acquisitions

On December 31, 2012, the Company entered into a transaction to acquire certain producing shallow natural gas wells and unproved properties (the “Shallow-Well Acquisition”). Total firm consideration in the Shallow-Well Acquisition was approximately $10.0 million of which $3.3 million was paid to the seller in January 2013. An additional $1.0 million was paid to the seller as of December 31, 2013, reducing the notes payable. The remaining consideration will be transferred to the seller from 2014 to 2015. In addition to the firm consideration, the seller has the right to participate in the development of the unproved properties and the Company is responsible for funding $3.7 million of these activities. The Company has recorded the $10.0 million purchase price with the offset to proved and unproved properties.

 

15.	Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted earnings per share takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with warrants and convertible debentures. As indicated in Note 1, our corporate reorganization was considered a transaction amongst entities under common control. Therefore, the weighted average shares used in our EPS calculation assume that the Rice Energy Inc. corporate structure was in place for all periods presented. The following is a calculation of the basic and diluted weighted-average number of shares of common stock outstanding and EPS for the years ended December 31, 2013, 2012 and 2011:

 

		Year Ended December 31,
(in thousands, except per share data)		2013				2012				2011
Loss (numerator):
Net loss		$	(35,776	)		$	(19,344	)		$	(936	)
Weighted-average shares (denominator):
Weighted-average number of shares of common stock – basic			80,441,905				57,966,572				39,958,066
Weighted-average number of shares of common stock - diluted			80,441,905				57,966,572				39,958,066
Loss per share:
Basic		$	(0.44	)		$	(0.33	)			(0.02	)
Diluted		$	(0.44	)		$	(0.33	)			(0.02	)

Approximately 1,671,800, 1,671,800 and 648,404 shares at December 31, 2013, 2012 and 2011, respectively, were not considered dilutive as we incurred a net loss in all periods presented herein.

 

16.	Subsequent Events

Initial Public Offering

On January 29, 2014, Rice Energy completed their IPO of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by Rice Energy Inc., 14,000,000 shares sold by the selling stockholder and 6,000,000 shares subject to an option granted to the underwriters by the selling stockholder.

The net proceeds of the IPO, based on the public offering price of $21.00 per share, were approximately $993.5 million, which resulted in net proceeds to Rice Energy of $593.6 million after deducting estimated

 

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expenses and underwriting discounts and commissions of approximately $36.4 million and the net proceeds to the selling stockholders of approximately $399.0 million after deducting underwriting discounts of approximately $21.0 million. Rice Energy did not receive any proceeds from the sale of the shares by the selling stockholders. A portion of the net proceeds from the IPO were used to repay all outstanding borrowings under the revolving credit facility of the Company’s Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In and to repay all outstanding borrowings under the Company’s revolving credit facility. The remainder of the net proceeds from the IPO will be used to fund a portion of our capital expenditure plan.

Marcellus JV Buy-In

On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between Rice Energy and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), Rice Energy completed its acquisition of Alpha Holdings’ 50% interest in the Company’s Marcellus joint venture in exchange for total consideration of $300.0 million, consisting of $100.0 million of cash and the issuance to Alpha Holdings of 9,523,810 shares of Rice Energy common stock. Prior to the completion of the acquisition of Alpha Holdings’ 50% interest in the Company’s Marcellus joint venture, the Company accounted for its investment under the equity method of accounting.

The company is currently assessing the fair value of assets acquired and liabilities assumed. Immediately prior to the acquisition, the fair value of the existing equity in the Marcellus joint venture, based upon preliminary valuations, was approximately $245.0 million. The acquisition-date fair value of the existing equity was based on an income approach. The income approach calculated the present value of the future cash flows related to the natural gas properties as of the date of the transaction, utilizing a discount rate based upon market participant assumptions, natural gas strip prices as of the date of the transaction, and a decline curve consistent with our geographic peers. As we acquired the remaining ownership in the Marcellus joint venture we are required to remeasure our equity investment at fair value which will result in a non-recurring gain of approximately $195.2 million during the quarter ended March 31, 2014. On a preliminary basis and based on preliminary valuations performed to determine the fair value of the assets as of the acquisition date, the company anticipates the natural gas properties have fair value of approximately $320.0 million. The preliminary estimate of excess purchase price over net assets and liabilities assumed which is to be allocated to goodwill is approximately $365.0 million and will be deductible for tax purposes.

The acquisition consolidates the resources of the Company and the Marcellus joint venture which will enable the Company to efficiently develop the natural gas properties concurrently. The management team of the Company has historically also served as the management team of the joint venture, so the team is intimately familiar with the assets. These factors resulted in the aforementioned goodwill.

The following unaudited pro forma combined financial information presents the Company’s results as though the Company and the incremental 50% interest in our Marcellus joint venture had occurred at January 1, 2013.

 

(in thousands)		Year Ended December 31, 2013 (Pro forma)
Pro forma net revenues		$	179,281
Pro forma net loss		$	(30,509	)
Pro forma earnings per share		$	(0.24	)

The Company expects to complete the purchase price allocation during 2014 and may adjust the preliminary amounts set forth above to reflect the final valuation. This final valuation of the assets and liabilities could have a material impact on the pro forma information and preliminary purchase price allocation discussed above.

 

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Income Taxes

At the date of IPO, Rice Energy owned 100% of Rice Drilling B and its subsidiaries. Rice Drilling B was a limited liability company not subject to federal income taxes before IPO. However, in connection with the closing of the IPO, as a result of our corporate reorganization, we became a corporation subject to federal income tax and, as such, our future income taxes will be dependent upon our future taxable income. The change in tax status would require the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting deferred tax liability is approximately $145.1 million.

No current tax expense would result as of the date of the change in status. The recognition of the initial deferred tax liability will be recorded in equity at the date of IPO, but not in the financials as of December 31, 2013.

Unregistered Sales of Equity Securities

On January 29, 2014, pursuant to the Master Reorganization Agreement (the “Master Reorganization Agreement”) among Rice Energy Inc., Rice Drilling B, REA, Rice Holdings, Rice Partners, NGP Holdings, NGP RE Holdings, L.L.C., (“NGP RE Holdings”) NGP RE Holdings II, L.L.C. (“NGP RE II” and, together with NGP RE Holdings, “Natural Gas Partners”), Mr. Daniel J. Rice III, Rice Merger LLC (“Merger Sub”) and each of the persons holding incentive units representing interests in REA (collectively, the “Incentive Unitholders”) dated as of January 23, 2014, (i) (a) Rice Partners contributed a portion of its interests in REA to Rice Holdings, (b) Natural Gas Partners contributed its interests in REA to NGP Holdings and (c) the Incentive Unitholders contributed a portion of their incentive units to Rice Holdings and NGP Holdings, each in return for substantially similar incentive units in such entities; (ii) NGP Holdings, Rice Holdings and Mr. Daniel J. Rice III contributed their respective interests in Rice Appalachia to the Company in exchange for 43,452,550, 20,300,923 and 2,356,844 shares of Common Stock, respectively; (iii) Rice Partners contributed its remaining interest in Rice Appalachia to Rice Energy Inc. in exchange for 20,000,000 shares of Common Stock; (iv) the Incentive Unitholders contributed their remaining interests in Rice Appalachia to the Company in exchange for 160,831 shares of Common Stock, each of which were issued by the company in connection with the closing of the IPO. In connection with the IPO, in the first quarter of 2014, we recognized a non-cash compensation expense of $3.4 million.

In addition, on January 29, 2014, pursuant to the Agreement and Plan of Merger (the “Merger Agreement”) among the Company, Rice Drilling B and Merger Sub dated as of January 23, 2014, Rice Energy Inc. issued 1,728,852 shares of Common Stock to the members of Rice Drilling B (other than Rice Appalachia) for settlement of the restricted units.

Incentive Units

In connection with the IPO, in the first quarter of 2014, certain incentive units granted by NGP Holdings to certain members of management triggered the pre-determined payout criteria, resulting in a cash payment by NGP Holdings of $4.4 million. This resulted in additional non-cash compensation expense being recorded in the first quarter of 2014 by the Company.

Convertible Debentures and Warrants

In connection with the IPO, the convertible debentures and warrants of Rice Drilling B were amended to become convertible or exercisable for an aggregate 1,671,800 shares of common stock of Rice Energy. Through March 10, 2014, approximately $5.0 million of the convertible debentures have been converted into 433,073 shares of Rice Energy Inc. common stock. On February 28, 2014, the Company issued a call notice on the remaining convertible debentures, requiring a response by March 30, 2014. Amounts not converted by the response date will require payment by the Company of 100% of the principal amount plus a premium of 50%, which could result in additional costs of $1.0 million. As the principal amount of the convertible debentures

 

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outstanding has been reduced to less than $5.0 million, the Company is no longer required to maintain restricted cash. Through March 10, 2014, two warrants have been exercised in exchange for 1,728 shares of Rice Energy common stock.

Amendment to Senior Secured Revolving Credit Facility

On January 29, 2014, Rice Energy, as parent guarantor, and Rice Drilling B, as borrower, entered into an amendment (the “Sixth Amendment”) to the Second Amended and Restated Credit Agreement, dated as of April 25, 2013 with Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (the “Second Amended and Restated Credit Agreement”). Rice Drilling B is a wholly-owned subsidiary of Rice Energy Inc. Among other things, the Sixth Amendment (i) added Rice Energy Inc. as a guarantor, (ii) increased the maximum commitment to $1.5 billion from $500.0 million, (iii) increased the borrowing base to $350.0 million from $200.0 million, (iv) lowered the interest rate on amounts borrowed, and (v) allowed for the corporate reorganization that was completed simultaneously with the closing of the IPO.

Subsequent to December 31, 2013, the Company issued additional letters of credit with Wells Fargo Bank, N.A. of $55.9 million (refer to Note 4 for further details on letters of credit as required by the Company’s natural gas marketer and pipeline).

Momentum Acquisition

On February 12, 2014, the Company’s wholly owned subsidiary, Rice Poseidon, entered into a Purchase Agreement with M3 to acquire certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania, for aggregate consideration of approximately $110.0 million in cash, subject to customary purchase price adjustments. Rice Energy expects the Momentum Acquisition to close in the second quarter of 2014, subject to customary closing conditions. The effective date for the Momentum Acquisition is March 1, 2014 and will be funded with proceeds received from our IPO.

The properties to be acquired in the Momentum Acquisition consist of a 28-mile, 6”-16” gathering system in eastern Washington County, Pennsylvania, and permits and rights of way in Washington and Greene Counties, Pennsylvania, necessary to construct an 18-mile, 30” gathering system connecting the northern system to the Texas Eastern pipeline. The northern system is supported by long-term contracts with acreage dedications covering approximately 20,000 acres from third parties. Once fully constructed, the acquired systems are expected to have an aggregate capacity of over 1 Bcf/d.

Subsequent events have been considered for disclosure and recognition through March 21, 2014, the same date the consolidated financial statements were available to be issued.

 

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17.	Quarterly Financial Information (Unaudited)

The Company’s quarterly financial information for the years ended December 31, 2013 and 2012 is as follows (in thousands):

 

		First quarter				Second quarter				Third quarter				Fourth quarter
Year ended December 31, 2013:
Total operating revenues		$	13,233			$	23,840			$	23,665			$	27,866
Total operating expenses			10,705				25,833				52,274				27,755
Operating income (loss)			2,528				(1,993	)			(28,609	)			111
Net income (loss)		$	(6,775	)		$	19,586			$	(33,652	)		$	(14,935	)

 

		First quarter				Second quarter				Third quarter				Fourth quarter
Year ended December 31, 2012:
Total operating revenues		$	4,792			$	4,155			$	6,580			$	11,673
Total operating expenses			6,353				11,984				8,123				9,640
Operating income (loss)			(1,561	)			(7,829	)			(1,543	)			2,033
Net income (loss)		$	(2,334	)		$	(12,884	)		$	(6,523	)		$	2,397

 

18.	Supplemental Information on Gas-Producing Activities (Unaudited)

Costs incurred for property acquisitions, exploration and development are as follows for Rice Energy (in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Acquisitions:
Unproved leaseholds		$	305,000			$	47,396			$	16,877
Development costs			184,217				89,307				72,776
Exploration costs:
Geological and geophysical			9,951				3,275				660
Total costs incurred		$	499,168			$	139,978			$	90,313

The following table presents the results of operations related to natural gas production for Rice Energy (in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Revenues		$	87,847			$	26,743			$	13,972
Production costs			19,712				8,824				2,157
Exploration costs			9,951				3,275				660
Depreciation, depletion and amortization			29,808				13,329				5,920
Write-down of abandoned leases			—				2,253				109
General and administrative expenses			5,108				3,050				2,212
Results of operations from producing activities		$	23,268			$	(3,988	)		$	2,914

 

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Reserve quantity information is as follows for Rice Energy:

 

		Natural Gas (MMcf)
		For the Years Ended December 31,
		2013				2012				2011
Proved developed and undeveloped reserves:
Beginning of year			304,272				232,996				12,230
Extensions and discoveries			100,626				176,956				223,538
Revision of previous estimates			757				(96,911	)			620
Production			(22,995	)			(8,769	)			(3,392	)
End of year			382,660				304,272				232,996
Proved developed reserves:
End of year			144,310				61,225				25,397
Proved undeveloped reserves:
End of year			238,350				243,047				207,599

Extensions, Discoveries and Other Additions

The Company added 100,626 MMcf, 176,956 MMcf and 223,538 MMcf through its drilling program in the Marcellus Shale in 2013, 2012 and 2011, respectively.

Revision of Previous Estimates

In 2012, the Company had net negative revisions of 96,911 MMcf, as 32 proved undeveloped locations were removed from its estimate of reserves at December 31, 2011 due primarily to declines in natural gas pricing and changes to the Company’s drilling plans with regards to horizontal drilling.

The reserve quantity information is limited to reserves which had been evaluated as of December 31, 2013. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves are expected to be recovered from new wells after substantial development costs are incurred. Netherland, Sewell and Associates, Inc. reviewed 100% of the total net gas proved reserves attributable to the Company’s interests and the Company’s Marcellus joint venture as of December 31, 2013 and 2012.

The information presented represents estimates of proved natural gas reserves based on evaluations prepared by the independent petroleum engineering firms of Netherland, Sewell and Associates, Inc. and Wright & Company in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. The Company’s independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources. Since 1961, Netherland, Sewell and Associates, Inc. has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. Wright & Company was founded in 1988 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers.

Certain information concerning the assumptions used in computing the standardized measure of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. Future cash inflows are computed by applying the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through, respectively, to the period-end quantities of those reserves. Gas prices are held constant throughout the lives of the properties.

 

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The assumptions used to compute estimated future net revenues do not necessarily reflect the Company’s expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rates also could result directly or indirectly from factors outside of the Company’s control, such as unintentional delays in development, changes in prices, or regulatory controls. The standardized measure calculation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, this could affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved natural gas reserves at the end of the year, based on period-end costs and assuming continuation of existing economic conditions.

An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved natural gas reserves.

Information with respect to Rice Energy’s estimated discounted future net cash flows related to its proved natural gas reserves is as follows (in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Future cash inflows		$	1,496,294			$	869,882			$	1,015,589
Future production costs			(517,101	)			(323,855	)			(208,733	)
Future development costs			(219,879	)			(262,084	)			(206,612	)
Future net cash flows			759,314				283,943				600,244
10% annual discount for estimated timing of cash flows			(342,150	)			(181,725	)			(330,924	)
Standardized measure of discounted future net cash flows(1)		$	417,164			$	102,218			$	269,320

 

(1)

Does not include the effects of income taxes on future revenues at December 31, 2013 and 2012 because as of December 31, 2013 and 2012, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. However, in connection with the closing of the IPO, as a result of the corporate reorganization, the Company became a corporation subject to federal income tax and, as such, its future income taxes will be dependent upon its future taxable income.

For 2013, the reserves for Rice Energy were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013, adjusted for energy content and a regional price differential. For 2013, this adjusted gas price was $3.91 per Mcf.

For 2012, the reserves for Rice Energy were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.86 per Mcf.

For 2011, the reserves for Rice Energy were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.36 per Mcf.

 

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The following are the principal sources of changes in the standardized measure of discounted future net cash flows for Rice Energy (in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Balance at beginning of period		$	102,218			$	269,320			$	46,422
Net change in prices and production costs			101,345				(83,873	)			(15,929	)
Net change in future development costs			29,336				(31,811	)			(3,695	)
Natural gas net revenues			(68,135	)			(18,376	)			(11,815	)
Extensions			114,489				38,937				243,003
Revisions of previous quantity estimates			1,133				(108,209	)			(14,259	)
Previously estimated development costs incurred			66,894				17,036				3,040
Accretion of discount			10,230				26,932				4,642
Changes in timing and other			59,654				(7,738	)			17,911
Balance at end of period		$	417,164			$	102,218			$	269,320

Gains on sales of interests in gas properties are not included in the information set forth above. We have also allocated certain general and administrative expenses to the Company’s results of operations as these expenses relate to production activities.

Costs incurred for property acquisitions, exploration and development related to the Company’s Marcellus joint venture (“the Marcellus joint venture”) are as follows (represents Rice Energy’s proportionate share, in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Acquisitions:
Unproved leaseholds		$	—			$	—			$	519
Development costs			46,571				46,725				21,700
Exploration costs:
Geological and geophysical			—				—				—
Total costs incurred		$	46,571			$	46,725			$	22,219

The following table presents Rice Energy’s share of the results of operations related to natural gas production of the Marcellus joint venture (represents Rice Energy’s proportionate share, in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Revenues		$	45,339			$	13,142			$	2,872
Production costs			12,557				5,436				379
Impairment of oil and gas properties			—				—				1,296
Depreciation, depletion and accretion			12,500				4,702				1,092
General and administrative expenses			1,557				986				—
Results of operations from producing activities		$	18,725			$	2,018			$	105

 

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Reserve quantity information is as follows for the Marcellus joint venture (represents Rice Energy’s proportionate share, in thousands):

 

		Natural Gas (MMcf)
		For the Years Ended December 31,
		2013				2012				2011
Proved developed and undeveloped reserves:
Beginning of year			128,118				58,103				—
Extensions and discoveries			19,812				98,119				58,800
Revision of previous estimates			(26,803	)			(23,808	)			—
Production			(11,443	)			(4,296	)			(697	)
End of year			109,684				128,118				58,103
Proved developed reserves:
End of year			52,370				35,013				14,474
Proved undeveloped reserves:
End of year			57,314				93,105				43,629

Rice Energy’s 50% equity interest in the Marcellus joint venture added 19,812 MMcf, 98,119 MMcf and 58,800 MMcf through its drilling program in the Marcellus Shale in 2013, 2012 and 2011, respectively. In 2013, Rice Energy’s 50% equity interest in the Marcellus joint venture had net negative revisions of 26,803 MMcf due primarily to performance revisions. In 2012, Rice Energy’s 50% equity interest in the Marcellus joint venture had net negative revisions of 23,808 MMcf due primarily to declines in natural gas pricing.

Information with respect to Rice Energy’s share of the Marcellus joint venture’s estimated discounted future net cash flows related to its proved natural gas reserves is as follows (in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Future cash inflows		$	427,167			$	364,157			$	252,384
Future production costs			(132,427	)			(127,086	)			(29,683	)
Future development costs			(46,344	)			(86,213	)			(51,882	)
Future net cash flows			248,396				150,858				170,819
10% annual discount for estimated timing of cash flows			(102,293	)			(79,781	)			(100,232	)
Standardized measure of discounted future net cash flows(1)		$	146,103			$	71,077			$	70,587

 

(1)

Does not include the effects of income taxes on future revenues at December 31, 2013 and 2012 because as of December 31, 2013 and 2012, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. However, in connection with the closing of the IPO, as a result of the corporate reorganization, the Company became a corporation subject to federal income tax and, as such, its future income taxes will be dependent upon its future taxable income.

For 2013, the reserves for the Marcellus joint venture were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013, adjusted for energy content and a regional price differential. For 2013, this adjusted gas price was $3.90 per Mcf.

For 2012, the reserves for the Marcellus joint venture were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.84 per Mcf.

 

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For 2011, the reserves for the Marcellus joint venture were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.34 per Mcf.

The following is for the Marcellus joint venture (represents Rice Energy’s proportionate share, in thousands), the principal sources of changes in the standardized measure of discounted future net cash flows:

 

		For the Years Ended December 31,
		2013				2012				2011
Balance at beginning of period		$	71,077			$	70,587			$	—
Net change in prices and production costs			81,974				(26,855	)			—
Net change in future development costs			2,781				(262	)			—
Natural gas net revenues			(32,782	)			(7,707	)			(2,494	)
Extensions			18,950				38,131				73,081
Revisions of previous quantity estimates			(14,752	)			(28,923	)			—
Previously estimated development costs incurred			31,253				12,862				—
Accretion of discount			7,111				7,059				—
Changes in timing and other			(19,509	)			6,185				—
Balance at end of period		$	146,103			$	71,077			$	70,587

 

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Report of Independent Auditors

The Partners of

Alpha Shale Resources, LP

We have audited the accompanying financial statements of Alpha Shale Resources, LP, which comprise the balance sheets as of December 31, 2013 and 2012, and the related statements of operations, partners’ capital and cash flows for the years then ended, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Alpha Shale Resources, LP at December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

Report of Other Auditors on December 31, 2011 Financial Statements Not Reissued

The financial statements of Alpha Shale Resources, LP for the year ended December 31, 2011 were audited by other auditors whose report dated April 20, 2012, expressed an unqualified opinion on those statements.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania

March 21, 2014

 

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ALPHA SHALE RESOURCES, LP

BALANCE SHEETS

 

		December 31,
(in thousands)		2013				2012
Assets
Current assets:
Cash		$	11,299			$	4,445
Accounts receivable			14,842				5,716
Receivable from affiliate			10				1
Prepaid expenses and other			93				108
Total current assets			26,244				10,270
Gas collateral account			295				295
Proved natural gas properties, net			182,333				114,128
Property and other equipment, net			83				91
Deferred financing costs, net			851				387
Other non-current assets			1,010				—
Total assets		$	210,816			$	125,171
Liabilities and partners’ capital
Current liabilities:
Accounts payable		$	20,024			$	18,953
Royalties payable			6,831				2,082
Accrued interest			16				413
Accrued capital expenditures			1,775				3,489
Other accrued liabilities			2,048				726
Leasehold payables			69				331
Derivative liabilities			2,427				138
Payable to affiliate			2,026				8,538
Total current liabilities			35,216				34,670
Long-term liabilities:
Long-term debt			75,400				29,200
Leasehold payable			69				—
Other long-term liabilities			712				542
Total liabilities			111,397				64,412
Partners’ capital			99,419				60,759
Total liabilities and partners’ capital		$	210,816			$	125,171

See accompanying Notes to Financial Statements.

 

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ALPHA SHALE RESOURCES, LP

STATEMENTS OF OPERATIONS

 

		Years Ended December 31,
(in thousands)		2013				2012				2011
Revenue:
Natural gas sales		$	90,677			$	26,284			$	5,744
Operating expenses:
Depreciation, depletion and amortization			25,008				9,411				2,184
Gathering, compression and transportation			15,663				6,671				53
Lease operating			8,193				3,331				704
Production taxes and impact fees			1,258				869				—
Loss on impairment of natural gas properties			146				—				2,592
General and administrative expenses			3,256				2,058				359
Total operating expenses			53,524				22,340				5,892
Operating income (loss)			37,153				3,944				(148	)
Other income (expense):
Other expense			(796	)			—				—
Gain (loss) on derivative instruments			3,347				(74	)			—
Amortization of deferred financing costs			(164	)			(15	)			—
Interest expense			(880	)			(372	)			—
Total other income (expenses)			1,507				(461	)			—
Net income (loss)		$	38,660			$	3,483			$	(148	)

See accompanying Notes to Financial Statements.

 

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ALPHA SHALE RESOURCES, LP

STATEMENTS OF CASH FLOWS

 

		Years Ended December 31,
(in thousands)		2013				2012				2011
Cash flows from operating activities:
Net income (loss)		$	38,660			$	3,483			$	(148	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			25,008				9,411				2,184
Amortization of deferred financing costs			164				15				—
Loss on impairment of natural gas properties			146				—				2,592
Derivative instruments fair value (gain) loss			(3,347	)			74				—
(Increase) decrease in:
Accounts receivable			(9,126	)			(5,067	)			(623	)
Receivable from affiliate			—				25				(26	)
Gas collateral account			—				(295	)			—
Prepaid expenses and other			15				55				(123	)
Cash receipts for settled derivatives			4,627				64				—
Increase (decrease) in:
Accounts payable			69				347				7
Royalties payable			4,749				1,734				337
Other accrued expenses			928				1,050				16
Payable to affiliate			(6,512	)			2,499				—
Net cash provided by operating activities			55,381				13,395				4,216
Cash flows from investing activities:
Capital expenditures for natural gas properties			(94,099	)			(63,847	)			(29,499	)
Capital expenditures for property and other equipment			—				(12	)			—
Net cash used in investing activities			(94,099	)			(63,859	)			(29,499	)
Cash flows from financing activities:
Proceeds from borrowings			46,200				29,200				—
Debt issuance costs			(628	)			(402	)			—
Capital contributions			—				20,000				29,600
Net cash provided by financing activities			45,572				48,798				29,600
Net increase (decrease) in cash			6,854				(1,666	)			4,317
Cash at the beginning of the year			4,445				6,111				1,794
Cash at the end of the year		$	11,299			$	4,445			$	6,111
Supplemental disclosure of non-cash investing and financing activities:
Capital expenditures for natural gas properties financed by accounts payable		$	19,599			$	18,597			$	8,357
Capital expenditures for natural gas properties financed by other accrued liabilities			1,775				3,489				8,823
Capital expenditures for natural gas properties financed by affiliate payable			—				6,038				—
Natural gas properties financed through deferred payment obligations			138				331				—

See accompanying Notes to Financial Statements.

 

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ALPHA SHALE RESOURCES, LP

STATEMENTS OF PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011

 

(in thousands)		Managing General Partner				Limited Partners				Total
Balance as of December 31, 2010		$	8			$	7,816			$	7,824
Capital contributions			30				29,570				29,600
Net loss			—				(148	)			(148	)
Balance as of December 31, 2011		$	38			$	37,238			$	37,276
Capital contributions			20				19,980				20,000
Net income			3				3,480				3,483
Balance as of December 31, 2012		$	61			$	60,698			$	60,759
Net income			39				38,621				38,660
Balance as of December 31, 2013		$	100			$	99,319			$	99,419

See accompanying Notes to Financial Statements.

 

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ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2013 AND 2012

 

1.	Summary of Significant Accounting Policies and Related Matters

Organization and Operations

These financial statements present the activities for Alpha Shale Resources, LP (hereinafter referred to as the “Partnership”). The Partnership was organized as a limited partnership in accordance with the laws of the State of Delaware on February 3, 2010 (date of inception) through funding from its limited partners, Rice Drilling C, LLC (“Rice C”); a wholly-owned subsidiary of Rice Drilling B, LLC (“Rice B”) which in turn is a wholly-owned subsidiary of Rice Energy Inc. (“Rice Energy Inc.”); Foundation PA Coal Company, LLC (“PA Coal”), which is a wholly-owned indirect subsidiary of Alpha Natural Resources, Inc. (“ANR Holdings”); and its managing general partner, Alpha Shale Holdings, LLC (“Holdings”). According to the terms of the limited partnership agreement, revenues, costs and cash distributions of the Partnership are allocated 49.95% each to PA Coal and Rice and 0.10% to Holdings.

The Partnership is engaged primarily in the acquisition, exploration, development, production and sale of natural gas in the Marcellus Shale region of Southwestern Pennsylvania.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates and changes in these estimates are recorded when known.

Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Partnership under contract with the Partnership’s natural gas marketer and only current customer. Pricing provisions are tied to the Platts Gas Daily market prices.

Cash

The Partnership maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed balance sheet amounts due to outstanding checks. The Partnership has no other accounts that are considered cash equivalents.

Accounts Receivable

Accounts receivable are primarily from the Partnership’s sole gas marketer. The Partnership extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. There was no allowance recorded for any of the periods presented in the financial statements.

 

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		December 31,
(in thousands)		2013				2012
Natural gas sales		$	14,458			$	5,570
Other			384				146
Total accounts receivable		$	14,842			$	5,716

Natural Gas Properties

The Partnership uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in natural gas properties, to drill and equip exploratory wells that result in proved reserves are capitalized. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and cost of carrying and retaining unproved properties are expensed.

Unproved natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Management determined that no impairment allowance was necessary as of December 31, 2013 and 2012. Capitalized costs of producing natural gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment not directly related to natural gas properties are depreciated over their estimated useful lives.

The Partnership assesses its proved natural gas properties for possible impairment on an annual basis, as events or changes in circumstances indicate that the carrying amount of an asset might not be recoverable. Management determined that no impairment allowance was necessary as of December 31, 2013 and 2012. During 2013, it was decided by the Operating Committee of the Partnership not to complete three vertical wells that had previously commenced drilling, as such an impairment charge of $0.1 million was recorded during the year ended December 31, 2013. There was no impairment charge during the year ended December 31, 2012. During 2011, it was decided by the Operating Committee of the Partnership not to complete two vertical wells that had previously commenced drilling. As such, an impairment charge of approximately $2.6 million was recorded during the year ended December 31, 2011.

Partnership estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Partnership adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization expense, as well as its impairment assessment of proved properties, a change in the Partnership’s estimated reserves could have a material effect on the Partnership’s net income or loss.

On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.

 

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Interest

The Partnership capitalizes interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. The following table summarizes the components of the Partnership’s interest incurred for the year indicated (in thousands):

 

		Year Ended December 31,
		2013				2012
Interest capitalized		$	216			$	143
Interest expensed			880				372
Total incurred		$	1,096			$	515

Property and Other Equipment

Property and other equipment is recorded at cost and is being depreciated over estimated useful lives of five to fifteen years on a straight-line basis. Accumulated depreciation was $18 thousand and $9 thousand at December 31, 2013 and 2012, respectively. Depreciation expense was $9 thousand, $8 thousand and $1 thousand for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in depreciation, depletion and amortization expense in the accompanying statements of operations.

Long-Lived Assets

Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used or disposed other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less selling costs.

Deferred Financing Costs

Deferred financing costs are amortized on a straight-line basis over the term of the related agreement. Accumulated amortization was $0.2 million and $15 thousand at December 31, 2013 and 2012, respectively. Amortization expense was $0.2 million, $15 thousand and $0 for the years ended December 31, 2013, 2012 and 2011, respectively. The annual amortization of deferred financing costs for years subsequent to December 31, 2013 is expected to be $0.3 million in each of the years through 2016 and $0.2 million in 2017.

Asset Retirement Obligations

The Partnership records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. The Partnership’s retirement obligations relate to the abandonment of gas-producing facilities and include costs to dismantle and relocate or dispose of the production platforms, gathering systems, wells and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.

When a new liability is recorded, the Partnership capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.

 

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Lease Obligations

The Partnership leases drilling rights under agreements which expire at various times. As of December 31, 2013, future minimum lease payments under these agreements expected to be paid during 2014 and 2015 are $0.1 million and $0.1 million, respectively, and are included as leasehold payables in the accompanying balance sheets.

Income Taxes

The Partnership is treated as a limited partnership for federal and state income tax purposes. Consequently, the Partnership is not subject to income taxes; instead its partners include the income in their tax returns.

Reclassifications

Certain reclassifications have been made to prior periods’ financial information related to accrued interest, other accrued liabilities and derivative liabilities to conform to the 2013 presentation.

 

2.	Capitalized Costs Relating to Natural Gas-Producing Activities

Proved and unproved capitalized costs related to the Partnership’s natural gas-producing activities are as follows (in thousands):

 

		December 31,
		2013				2012
Capitalized costs:
Proved, producing properties		$	173,117			$	50,437
Proved, non-producing properties			45,861				75,338
Total			218,978				125,775
Accumulated depreciation, depletion and amortization			36,645				11,647
Net capitalized costs		$	182,333			$	114,128

 

3.	Long-Term Debt

The Partnership had long-term debt outstanding as follows (in thousands):

 

		December 31,
Description		2013				2012
Long-term Debt
Wells Fargo Credit Facility		$	75,400			$	29,200
Total long-term debt		$	75,400			$	29,200

Wells Fargo Credit Facility

On September 7, 2012, the Partnership entered into a credit agreement (“Wells Fargo Credit Facility”) with Wells Fargo Bank, N.A. (“Wells Fargo”). The maximum credit amount allowed under the promissory note agreement is $200.0 million, payable at maturity with interest only due in monthly installments at the higher of the prime rate, the federal funds rate plus 0.5% or the adjusted LIBOR plus 1%; all unpaid balances are due September 7, 2017; secured by substantially all assets of the Partnership. The weighted average interest rate was 2.42% as of December 31, 2013. As of December 31, 2013, the Partnership issued letters of credit of $10.4 million with Wells Fargo as required by the Partnership’s natural gas marketer. The borrowing base as of

 

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December 31, 2013 was $145.0 million with approximately $59.2 million undrawn at that date. This credit facility was repaid using proceeds from the Rice Energy Inc. IPO during the first quarter of 2014.

The Wells Fargo Credit Facility provides for borrowings to be used for the purpose of funding capital expenditures related to the Partnership’s drilling program, providing working capital for lease acquisitions, exploration and production operations, and development (including the drilling and completion of producing wells), and for general business purposes, including fees and expenses. The Wells Fargo Credit Facility is subject to a maximum borrowing base equal to the maximum value, for credit purposes, of the subject properties as determined by Wells Fargo in accordance with its customary lending practices. The borrowing base is determined by the lenders on a quarterly basis and such determination is primarily based upon the value of the Partnership’s proved developed reserves. If the lenders were to decrease the borrowing base below the amounts outstanding under the facility, the Partnership would have to repay these amounts within 30 days, repay these amounts in six monthly installments, or add sufficient collateral value.

The Wells Fargo Credit Facility is subject to certain covenants which are ordinary to such credit facilities and include, among other things, minimum financial ratios, restrictions as to additional debt and changes to the Partnership’s structure. The Partnership was in compliance with such covenants and ratios as of December 31, 2013.

Interest paid in cash was $1.5 million and $0.1 million for the years ended December 31, 2013 and 2012, respectively. See Note 1 for information on capitalized interest.

 

4.	Fair Value of Financial Instruments

The Partnership determines fair value on a recurring basis for its amounts related to its derivative instruments as the amounts are required to be recorded at fair value each reporting period. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.

The Partnership has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). All of the Partnership’s fair value measurements are included in Level 2. Since the adoption of fair value accounting, the Partnership has not made any changes to its classification of financial instruments in each category.

Items included in Level 2 are valued using management’s best estimate of fair value corroborated by third-party quotes.

 

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The following items were measured at fair value on a recurring basis during the period (refer to Note 7 for details relating to derivative instruments) (in thousands):

 

		December 31, 2013				Fair Value Measurements at Reporting Date Using
Description						Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Assets:
Derivative Instruments, at fair value		$	1,010			$	—			$	1,010			$	—
Total assets		$	1,010			$	—			$	1,010			$	—
Liabilities:
Derivative Instruments, at fair value		$	2,427			$	—			$	2,427			$	—
Total liabilities		$	2,427			$	—			$	2,427			$	—

 

		December 31, 2012				Fair Value Measurements at Reporting Date Using
Description						Quoted Prices in Active Markets for Identical Assets (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)
Liabilities:
Derivative Instruments, at fair value		$	138			$	—			$	138			$	—
Total liabilities		$	138			$	—			$	138			$	—

The carrying amount of cash, receivables and accounts payable approximate their fair value due to the short-term nature of such instruments.

The estimated fair value of long-term debt on the balance sheet at December 31, 2012 is shown in the table below (refer to Note 3 for details relating to the borrowing arrangements (in thousands). The fair value was estimated using Level 3 inputs based on rates reflective of the remaining maturity as well as the Partnership’s financial position.

 

		December 31,
Description		2013				2012
Long-term debt, at fair value:
Wells Fargo Credit Facility		$	75,400			$	29,200
Total		$	75,400			$	29,200

 

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5.	Asset Retirement Obligations

The Partnership is subject to certain legal requirements which result in recognition of a liability related to the obligation to incur future plugging and abandonment costs. The Partnership records a liability for such asset retirement obligations and capitalizes a corresponding amount for asset retirement costs. The liability is estimated using the present value of expected future cash flows, adjusted for inflation and discounted at the Partnership’s credit adjusted risk-free rate. No wells were plugged or abandoned during 2012, nor were there any changes to assumptions. A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the years ended December 31, 2013, 2012 and 2011 is as follows (in thousands):

 

Balance at December 31, 2010		$	235
Liabilities incurred			67
Accretion expense			5
Balance at December 31, 2011		$	307
Liabilities incurred			138
Accretion expense			97
Balance at December 31, 2012		$	542
Liabilities incurred			110
Accretion expense			60
Balance at December 31, 2013		$	712

 

6.	Partners’ Capital

The Partnership consists of three partners: Holdings, which is the managing general partner, and PA Coal and Rice C, the limited partners. The Partnership authorized and issued 10,000 units during 2010. In February 2010, Holdings contributed $6 thousand for 10 units, or a 0.10% ownership, and PA Coal and Rice each contributed $3.0 million for 4,995 shares, or 49.95% ownership each. In 2011, 2012 and 2013 the managing partner contributed an additional $30 thousand, $20 thousand, and $39 thousand, respectively, and the limited partners contributed an additional $29.6 million, $20.0 million and $38.6 million, respectively.

Since inception, the three partners have continued to make additional contributions into the Partnership, in accordance with ownership percentages, and no additional units were issued as depicted on the statements of changes in partners’ capital.

 

7.	Derivative Instruments

The Partnership uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. Our derivative counterparties share in the Credit Agreement collateral. The Partnership’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently. As of December 31, 2013, the Partnership entered into derivative instruments with Wells Fargo Bank, N.A. and Bank of Montreal fixing the price it receives for natural gas through December 31, 2017, as summarized in the following table:

 

Swap Contract Expiration		MMbtu/day				Weighted Average Price
2014			83,648			$	4.120
2015			33,240			$	4.173
2016			30,000			$	4.127
2017			30,000			$	4.127
Collar Contract Expiration		MMbtu/day				Floor/Ceiling
2015			25,000			$	3.750/$5.000

 

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The following is a summary of the Partnership’s derivative instruments, which are recorded in the balance sheet as of December 31, 2013 and 2012 (in thousands):

 

		December 31, 2013				December 31, 2012
Current derivative assets		$	1,140			$	141
Long-term derivative assets			1,577				—
		$	2,717			$	141
Current derivative liabilities		$	3,567			$	279
Long-term derivative liabilities			567				—
		$	4,134			$	279
Net current value of derivative liabilities		$	(2,427	)		$	(138	)
Net long-term value of derivative assets		$	1,010			$	—

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value:

 

		December 31, 2013
Description		Gross Amounts of Recognized Assets				Gross Amounts Offset on Balance Sheet				Net Amounts of Assets (Liabilities) on Balance Sheet
Derivative assets		$	3,719			$	(1,002	)		$	2,717
Derivative liabilities		$	736			$	(4,870	)		$	(4,134	)

 

		December 31, 2012
Description		Gross Amounts of Recognized Assets				Gross Amounts Offset on Balance Sheet				Net Amounts of Assets (Liabilities) on Balance Sheet
Derivative assets		$	324			$	(183	)		$	141
Derivative liabilities		$	122			$	(401	)		$	(279	)

Both realized and unrealized gains and losses are recorded as a gain or loss on derivatives in the consolidated statement of operations under other income/expense. Unrealized losses were $1.3 million and $0.1 million for the years ended December 31, 2013 and 2012, respectively. Realized gains related to contract settlements were $4.6 million and $0.1 million for the years ended December 31, 2013 and 2012, respectively. The Partnership did not have any derivative instruments as of December 31, 2011.

 

8.	Commitments and Contingencies

The Partnership is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.

The Partnership has drilling commitments which management expects to meet in the ordinary course of business.

 

9.	Related-Party Transactions

During the years ended December 31, 2013 and 2012, the Partnership was billed for management services provided in the amount of $2.1 million and $1.3 million, respectively, which is included with general and administrative expenses on the statements of operations. As of December 31, 2013 and 2012, $2.0 million and

 

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$8.5 million, respectively, of costs were due to related entities and recorded as payable to affiliate on the balance sheets. Included in the 2013 amount are management service fees as described above as well as fees for gathering and transportation incurred by the Partnership that were billed to related parties. Included in the 2012 amount is $6.0 million relating to capitalized costs that were approved to be contributed from related entities.

During 2011, management services were provided by related entities; however, the partners agreed to waive charging a fee to the Partnership for these services for 2011.

Payments totaling $1.2 million, $0.5 million and $0.4 million were made during the years ended December 31, 2013, 2012 and 2011 respectively to Geological Engineering Services, Inc. (“GES”) in respect of consultancy services. GES is a drilling and completion engineering consulting company specializing in unconventional reservoirs like the Marcellus Shale. John P. LaVelle, Rice Energy’s Vice President of Drilling, served as president of GES from February 1994 until February 2010. There were no amounts outstanding between the Partnership and GES as of any period presented.

 

10.	Subsequent Events

Transaction Agreement

On January 29, 2014, pursuant to the Transaction Agreement between Rice Energy Inc., Rice C and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), Rice Energy Inc. completed their acquisition of Alpha Holdings’ 50% interest in the Partnership in exchange for total consideration of $322 million, consisting of $100 million of cash and the issuance to Alpha Holdings of 9,523,810 shares of Rice Energy Inc. common stock.

Subsequent events have been considered for disclosure and recognition through March 21, 2014, the same date the financial statements were available to be issued.

 

11.	Supplemental Information on Gas-Producing Activities (Unaudited)

Costs incurred for property acquisitions, exploration and development for the years ended December 31, 2013, 2012 and 2011 are as follows (in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Acquisitions:
Unproved leaseholds		$	—			$	—			$	1,038
Development costs			93,142				93,450				43,400
Exploration costs:
Geological and geophysical			—				—				—
Total costs incurred		$	93,142			$	93,450			$	44,438

The following table presents the results of operations related to natural gas production (in thousands):

 

		For the Years Ended December 31,
		2013				2012				2011
Revenues		$	90,677			$	26,284			$	5,744
Production costs			25,114				10,872				758
Impairment of gas properties			—				—				2,592
Depreciation, depletion and amortization			25,000				9,404				2,184
General and administrative expenses			3,114				1,972				—
Results of operations from producing activities		$	37,449			$	4,036			$	210

 

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Reserve quantity information for the years ended December 31, 2013, 2012 and 2011 are as follows (in thousands):

 

		2013				2012				2011
Proved developed and undeveloped reserves:
Beginning of year			256,236				116,206				—
Extensions and discoveries			39,623				196,238				117,600
Revision of previous estimates			(53,605	)			(47,616	)			—
Production			(22,886	)			(8,592	)			(1,394	)
End of year			219,368				256,236				116,206
Proved developed reserves:
End of year			104,741				70,026				28,948
Proved developed reserves:
End of year			114,627				186,210				87,258

The Partnership added 39,623 MMcf, 196,238 MMcf and 117,600 MMcf through its drilling program in the Marcellus Shale in 2013, 2012 and 2011, respectively. In 2013, the Partnership had net negative revisions of 53,605 MMcf due primarily to performance revisions. In 2012, the Partnership had net negative revisions of 47,616 MMcf due primarily to declines in natural gas pricing.

Information with respect to estimated discounted future net cash flows related to its proved natural gas reserves as of December 31, is as follows (in thousands):

 

		2013				2012				2011
Future cash inflows		$	854,334			$	728,314			$	504,768
Future production costs			(264,853	)			(254,172	)			(59,366	)
Future development costs			(92,689	)			(172,426	)			(103,764	)
Future net cash flows			496,792				301,716				341,638
10% annual discount for estimated timing of cash flows			(204,586	)			(159,562	)			(200,464	)
Standardized measure of discounted future net cash flows		$	292,206			$	142,154			$	141,174

For 2013, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013, adjusted for energy content and a regional price differential. For 2013, this adjusted gas price was $3.90 per Mcf.

For 2012, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.84 per Mcf.

For 2011, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.34 per Mcf.

 

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The following is the principal sources of changes in the standardized measure of discounted future net cash flows (in thousands):

 

		2013				2012				2011
Balance at beginning of period		$	142,154			$	141,174			$	—
Net change in prices and production costs			163,948				(53,710	)			—
Net change in future development costs			5,563				(524	)			—
Natural gas net revenues			(65,563	)			(15,414	)			(4,988	)
Extensions			37,901				76,262				146,162
Revisions of previous quantity estimates			(29,504	)			(57,846	)			—
Previously estimated development costs incurred			62,507				25,724				—
Accretion of discount			14,222				14,118				—
Changes in timing and other			(39,022	)			12,370				—
Balance at end of period		$	292,206			$	142,154			$	141,174

 

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INDEPENDENT AUDITORS’ REPORT

To the Partners of

Alpha Shale Resources, LP

Canonsburg, Pennsylvania

We have audited the accompanying balance sheet of Alpha Shale Resources, LP (Partnership) as of December 31, 2011 and for the year then ended and the related statements of operations, changes in partners’ capital and cash flows. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Alpha Shale Resources, LP as of December 31, 2011 and for the year then ended and the results of its operations and its cash flows, in conformity with accounting principles generally accepted in the United States of America.

/s/ Schneider Downs & Co., Inc.

Pittsburgh, Pennsylvania

April 20, 2012

 

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ALPHA SHALE RESOURCES, LP

BALANCE SHEET

 

(in thousands)		December 31, 2011
Assets
Current assets:
Cash and cash equivalents		$	6,111
Accounts receivable			649
Due from general partner			26
Prepaids and other current assets			163
Total current assets			6,949
Natural gas properties, net			48,222
Total assets		$	55,171
Liabilities and partners’ capital
Current liabilities:
Accounts payable		$	8,366
Accrued capital expenses			8,823
Revenues payable			348
Other accrued expenses			51
Total current liabilities			17,588
Long-term liabilities:
Asset retirement obligations			307
Total liabilities			17,895
Partners’ capital
Managing general partner			38
Limited partners			37,238
Total partners’ capital			37,276
Total liabilities and partners’ capital		$	55,171

See accompanying Notes to Financial Statements.

 

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ALPHA SHALE RESOURCES, LP

STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2011

 

(in thousands)		2011
Revenues:
Natural gas sales		$	5,744
Costs and expenses:
Natural gas production costs			757
Depreciation, depletion and amortization			2,184
Loss on impairment of oil and gas properties			2,592
General and administrative expenses			359
Total costs and expenses			5,892
Net loss		$	(148	)

See accompanying Notes to Financial Statements.

 

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ALPHA SHALE RESOURCES, LP

STATEMENT OF CASH FLOWS

FOR THE YEAR ENDED DECEMBER 31, 2011

 

(in thousands)		2011
Cash flows from operating activities:
Net loss		$	(148	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			2,184
Loss on impairment of natural gas properties			2,592
Changes in assets and liabilities:
Accounts receivable			(649	)
Prepaid and other assets			(123	)
Accounts payable			7
Accrued expenses			353
Net cash provided by operating activities			4,216
Cash flows from investing activities:
Purchase and development of natural gas properties			(29,499	)
Cash flows from financing activities:
Capital contributions			29,600
Net increase in cash and cash equivalents			4,317
Cash and cash equivalents:
Beginning of year			1,794
End of year		$	6,111
Supplemental schedule of noncash investing and financing activities
Capital expenditures for natural gas properties financed by accounts payable and accrued expenses		$	14,939
Asset retirement obligation, with a corresponding increase to natural gas properties		$	68

See accompanying Notes to Financial Statements.

 

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ALPHA SHALE RESOURCES, LP

STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

FOR THE YEAR ENDED DECEMBER 31, 2011

 

(in thousands)		Managing General Partner				Limited Partners				Total Capital
Balance as of December 31, 2010		$	8			$	7,816			$	7,824
Capital contributions			30				29,570				29,600
Net loss			—				(148	)			(148	)
Balance as of December 31, 2011		$	38			$	37,238			$	37,276

See accompanying Notes to Financial Statements.

 

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ALPHA SHALE RESOURCES, LP

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2011

 

1.	Organization and Operations

These financial statements present the activities for Alpha Shale Resources, LP (hereinafter referred to as the Partnership). The Partnership was organized as a limited partnership in accordance with the laws of the State of Delaware on February 3, 2010 (date of inception) through funding from its limited partners, Foundation PA Coal Company, LLC (Alpha Holdings), and Rice Drilling C, LLC (Rice Drilling C) and its managing general partner, Alpha Shale Holdings, LLC (Holdings). According to the terms of the limited partnership agreement, revenues, costs and cash distributions of the Partnership are allocated 49.95% each to Alpha Holdings and Rice Drilling C and 0.10% to Holdings.

Alpha is engaged primarily in the acquisition, exploration, development, production and sale of natural gas. Drilling is engaged in the tendering of natural gas wells in the Marcellus Shale region of Southwestern Pennsylvania. The Partnership sells its natural gas products solely to a natural gas marketing customer, which accounts for 100% of its accounts receivable as of December 31, 2011, and 100% of its sales for the year ended December 31, 2011. Natural gas sales included in the statement of operations consist of sales for one horizontal well, which was in production from May 2011 through December 31, 2011.

 

2.	Summary of Significant Accounting Policies

A summary of significant accounting policies consistently applied by management in the preparation of the accompanying financial statements follows:

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Natural Gas Properties. The Partnership uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells and related asset retirement costs are capitalized. Depletion is based on cost less estimated salvage value using the unit-of-production method. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of geological, geophysical, engineering and economic data. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

Partnership estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. The petroleum engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Partnership adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization expense, a change in the Partnership’s estimated reserves could have a material effect on the Partnership’s net income.

 

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Unproved natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Management determined that no impairment allowance was necessary at December 31, 2011. Unproved natural gas properties approximated $3.8 million at December 31, 2011. Capitalized costs of producing natural gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment are depreciated over their estimated useful lives. Wells in progress approximated $27.8 million at December 31, 2011.

The Partnership assesses its proved natural gas properties for possible impairment on an annual basis, as events or changes in circumstances indicate that the carrying amount of an asset might not be recoverable. During 2011, it was decided by the Operating Committee of the Partnership not to complete two vertical wells that had previously been drilled. As such, an impairment charge of approximately $2.6 million was recorded during the period ended December 31, 2011.

On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.

Revenue Recognition. Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Partnership under contract with the Partnership’s natural gas marketer and only current customer. All of the Partnership contracts’ pricing provisions are tied to Platts Gas Daily market prices. As a result, the Partnership’s revenue from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.

Cash and Cash Equivalents. The Partnership maintains cash that might exceed federally insured amounts at times. The Partnership considers all items purchased with a maturity of three months or less and all interest-bearing money market funds to be cash and cash equivalents.

Accounts Receivable. The Partnership performs ongoing credit evaluations of its customer and does not require collateral. Provisions are made for estimated uncollectible trade accounts receivable. The Partnership’s estimate is based on historical collection experience, a review of current status of trade receivables and judgment. Decisions to charge-off receivables are based on management’s judgment after consideration of facts and circumstances surrounding potential uncollectible accounts. Management determined that no allowance was necessary at December 31, 2011.

Asset Retirement Obligations. The Partnership accounts for its asset retirement obligations, plugging costs, as required by the Asset Retirement and Environmental Obligations topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (Codification or ASC), which requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. For the Partnership, asset retirement obligations primarily relate to the abandonment of natural gas-producing facilities and are accreted over the estimated life of the related asset, for the change in present value. The initial capitalized costs are depleted over the useful lives of the related asset, through charges to depreciation, depletion and amortization expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

 

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The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted, risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulations enact new plugging and abandonment requirements. The Partnership has a $25 thousand bond deposit, legally restricted for purposes of settling asset retirement obligations in the Commonwealth of Pennsylvania. This bond deposit is included in prepaid and other assets.

A reconciliation of the Partnership’s liability for well plugging and abandonment costs as of December 31, 2011 is as follows (in thousands):

 

Asset retirement obligations, beginning of year		$	235
Additions			67
Accretion expense			5
Asset retirement obligations, end of year		$	307

The accretion expense relative to the asset retirement obligations is included on the statements of operations under the caption depreciation, depletion and amortization.

Income Taxes. The Partnership is organized as a limited partnership and is not subject to federal or state income taxes. Accordingly, no provision has been made for current or deferred income taxes in these financial statements. The taxable income of the Partnership is included in the tax return of the individual partners. In addition, the Partnership has not identified any material uncertain tax positions requiring an accrual or disclosure in the financial statements. The Partnership accrues interest and penalties related to unrecognized tax benefits in income tax expense. Additionally, the Partnership’s U.S. Federal income tax return filed for 2010 remains subject to examination by the Internal Revenue Service (IRS).

Recent Accounting Pronouncements. In January 2010, the FASB issued the Accounting Standards Update (ASU), Fair Value Measurements Disclosures, to require new disclosures for fair value measurements and to provide clarification for existing disclosure requirements. More specifically, this update will require (1) an entity to disclose separately the amounts of significant transfers in and out of Levels I and 2 fair value measurements and to describe the reasons for the transfers; and (2) information about purchases, sales, issuances and settlements to be presented separately on a gross basis rather than net, in the reconciliation for fair value measurements using significant unobservable inputs (Level 3 inputs). The ASU clarifies existing disclosure requirements for the level of disaggregation used for classes of assets and liabilities measured at fair value and requires disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements using Level 2 and Level 3 inputs. The adoption of the ASU by the Partnership did not materially impact or expand its financial statement footnote disclosures.

 

3.	Natural Gas Properties

Natural gas properties at December 31, 2011 consist of the following (in thousands):

 

		2011
Unproved properties		$	3,843
Proved and producing			18,691
Natural gas properties, successful efforts method, at cost			22,534
Less—Accumulated depreciation, depletion and amortization			2,210
			20,324
Natural gas properties in progress			27,898
Total natural gas properties		$	48,222

 

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Included in proved and producing are the estimated costs associated with the Partnership’s asset retirement obligations discussed in Note 2, which approximated $0.3 million at December 31, 2011.

 

4.	Partners’ Capital

The Partnership consists of three partners: Holdings, which is the managing general partner, and Alpha Holdings and Rice Drilling C, the limited partners. The Partnership authorized and issued 10,000 units during 2010. In February 2010, Holdings contributed $6 thousand for 10 units, or a 0.10% ownership, and Alpha Holdings and Rice Drilling C each contributed $3.0 million for 4,995 shares, or 49.95% ownership each.

In November 2010, the Partnership had an additional capital call amounting to $4.0 million, of which $4 thousand was contributed by Holdings; and Alpha Holdings and Rice Drilling C contributed $2.0 million each, in line with ownership percentages; and no additional units were issued.

During 2011, the three partners continued to make contributions into Alpha, in line with ownership percentages, and no additional units were issued as depicted on the Statement of Changes in Partners’ Capital.

 

5.	Contingencies

The Partnership is involved in various legal proceedings arising out of the normal conduct of its business. In the opinion of management, the ultimate resolution of such matters will not have a material effect on the financial position or results of operations of the Partnership.

The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.

The Partnership accounts for environmental contingencies in accordance with the Contingencies topic of the FASB Codification. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessment and/or cleanup is probable, and the costs can be reasonably estimated. The Partnership maintains insurance that may cover in whole or in part certain environmental expenditures. At December 31, 2011, the Partnership had no environmental contingencies requiring specific disclosure or accrual.

 

6.	Related-Party Activity

During 2011, management services were provided by related entities to the Partnership; however, the partners agreed to waive charging a fee to Alpha for these services for 2011.

During the year ended December 31, 2011, the Partnership incurred expenses relative to the development and production of natural gas properties with related parties amounting to approximately $0.5 million.

Amounts due to partners and related parties approximated $33 thousand at December 31, 2011.

 

7.	Fair Value Measurements

Fair value measurement requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the assumptions (i.e., inputs) used in the valuation. Level 1 provides the most reliable measure of fair value, while Level 3 generally requires significant management judgment: Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. The fair value hierarchy is defined as follows:

Level 1—Valuations are based on unadjusted quoted prices in active markets for identical assets or liabilities.

 

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Level 2—Valuations are based on quoted prices for similar assets or liabilities in active markets, or quoted prices in markets that are not active for which significant inputs are observable, either directly or indirectly.

Level 3—Valuations are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Inputs reflect management’s best estimate of what market participants would use in valuing the asset or liability at the measurement date.

At December 31, 2011, the Partnership’s financial instruments consist primarily of cash, accounts receivable and accounts payable. The carrying amount of cash, receivables and accounts payable approximate their fair value due to the short-term nature of such instruments.

The Partnership reviews long-lived assets, including natural gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets might not be recoverable. If the estimated undiscounted cash flows for a particular asset are not sufficient to cover the asset’s carrying value, it is impaired and the carrying value is reduced to the asset’s current fair value. These fair value measurements fell within Level 3 of the fair value hierarchy. During 2011, the Partnership determined that certain natural gas properties were impaired, resulting in an impairment charge of $2.6 million. The impairment charge reduced the remaining carrying value of these properties to their aggregate fair value of approximately $0 at December 31, 2011.

 

8.	Subsequent Events

Subsequent events are defined as events or transactions that occur after the balance sheet date, but before the financial statements are issued or are available to be issued. Management has evaluated subsequent events through April 20, 2012, the date on which the financial statements were available to be issued and noted that there was an additional capital contribution in February 2012 in the amount of $12.0 million.

 

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Independent Accountants’ Compilation Report

To the Members of

Countrywide Energy Services, LLC

We have compiled the accompanying balance sheet of Countrywide Energy Services, LLC, a Pennsylvania limited liability company (the “Company”), as of December 31, 2013, and the related statements of operations, members’ capital, and cash flows for the year then ended. We have not audited or reviewed the accompanying financial statements and, accordingly, do not express an opinion or provide any assurance about whether the financial statements are in accordance with accounting principles generally accepted in the United States of America.

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America and for designing, implementing, and maintaining internal control relevant to the preparation and fair presentation of the financial statements.

Our responsibility is to conduct the compilation in accordance with Statements on Standards for Accounting and Review Services issued by the American Institute of Certified Public Accountants. The objective of a compilation is to assist management in presenting financial information in the form of financial statements without undertaking to obtain or provide any assurance that there are no material modifications that should be made to the financial statements.

/s/ Grossman Yanak & Ford LLP

Pittsburgh, Pennsylvania

March 3, 2014

 

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Independent Auditors’ Report

To the Members of

Countrywide Energy Services, LLC

We have audited the accompanying financial statements of Countrywide Energy Services, LLC, a Pennsylvania limited liability company, (the “Company”), which comprise the balance sheet as of December 31, 2012, and the statements of operations, members’ capital, and cash flows for the year ended December 31, 2012 and the period from May 9, 2011 to December 31, 2011, and the related notes to the financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Countrywide Energy Services, LLC as of December 31, 2012, and the results of its operations and its cash flows for the year ended December 31, 2012 and the period from May 9, 2011 to December 31, 2011 in accordance with accounting principles generally accepted in the United States of America.

/s/ Grossman Yanak & Ford LLP

Pittsburgh, Pennsylvania

February 20, 2013

 

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Countrywide Energy Services, LLC

Balance Sheets

December 31, 2013 And 2012

 

		NOTES		2013				2012
(in thousands)				(Unaudited)
Assets
Current assets:
Cash		1		$	879			$	152
Accounts receivable, net (less allowance for doubtful accounts of $23 thousand and $102 thousand)		1			163				1,731
Current portion of note receivable		2			351				—
Prepaid expenses and other					79				65
Total current assets					1,472				1,948
Equipment, net		1,3			62				2,453
Note receivable		2			1,049				—
Deposits					—				112
Total assets				$	2,583			$	4,513
Liabilities and members’ capital
Current liabilities:
Current maturities of notes payable		4		$	—			$	105
Current maturities of capital lease obligations		1,5			30				665
Accounts payable					9				494
Distributions payable					148				—
Accrued interest					—				14
Accrued payroll and related expenses					—				134
Total current liabilities					187				1,412
Long-term liabilities:
Notes payable		4			—				48
Lease obligations		1			—				152
Total liabilities					187				1,612
Members’ capital		1			2,396				2,901
Total liabilities and members’ capital				$	2,583			$	4,513

See accompanying Notes to Financial Statements, Independent Accountants’ Compilation Report and Independent Auditors’ Report.

 

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Countrywide Energy Services, LLC

Statements of Operations

For the Years Ended December 31, 2013 (Unaudited) and 2012

and for the Period from May 9, 2011 to December 31, 2011

 

		Notes		2013				2012				2011
(in thousands)				(Unaudited)
Net revenue		1,6		$	4,885			$	8,560			$	9,724
Cost of revenue		5			4,274				6,535				6,721
Gross profit					611				2,025				3,003
Selling, general and administrative expenses		1			628				1,623				1,137
Income (loss) from operations					(17	)			402				1,866
Other income (expense):
Interest expense		5			(90	)			(218	)			(16	)
Gain (loss) on disposal of equipment					255				(82	)			20
Other income (expense), net					165				(300	)			4
Net income				$	148			$	102			$	1,870

See accompanying Notes to Financial Statements, Independent Accountants’ Compilation Report and Independent Auditors’ Report.

 

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Countrywide Energy Services, LLC

Statements of Cash Flows

For the Years Ended December 31, 2013 (Unaudited) and 2012

and for the Period from May 9, 2011 to December 31, 2011

 

		2013				2012				2011
(in thousands)		(Unaudited)
Cash flows from operating activities:
Net income		$	148			$	102			$	1,870
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation			754				910				276
(Gain) loss on sale of equipment			(255	)			82				(20	)
(Increase) decrease in:
Accounts receivable			1,568				1,603				(2,252	)
Prepaid expenses and other assets			99				(6	)			(65	)
Increase (decrease) in:
Accounts payable			(485	)			(1,459	)			1,088
Other accrued liabilities			(147	)			(56	)			155
Net cash provided by operating activities			1,682				1,176				1,052
Cash flows from investing activities:
Purchase of equipment			(273	)			(152	)			(1,117	)
Proceeds from sale of equipment			992				148				152
Net cash provided by (used in) investing activities			719				(4	)			(965	)
Cash flows from financing activities:
Deposit related to capital lease			—				—				(107	)
Repayment of capital lease obligations			(1,015	)			(916	)			(330	)
Repayment of debt			(154	)			(116	)			(73	)
Receipt from member			—				—				400
Distributions to members			(505	)			(10	)			(6	)
Net cash used in financing activities			(1,674	)			(1,042	)			(116	)
Net increase (decrease) in cash			727				130				(29	)
Cash, beginning of period			152				22				51
Cash, end of period		$	879			$	152			$	22
Supplemental disclosures of cash flow information:
Cash paid during the period for interest		$	104			$	213			$	7

 

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Supplemental disclosure of noncash investing and financing activities:

During the year ended December 31, 2013, the Company financed equipment acquisitions of $0.2 million with capital leases. Additionally, equipment was sold in exchange for cash of $0.4 million and a note receivable of $1.4 million (see Note 2).

Also as of December 31, 2013, distributions of $0.1 million were included in distributions payable.

During the year ended December 31, 2012, the Company financed equipment acquisitions of $0.2 million with capital leases.

During the period from May 9, 2011 to December 31, 2011, the Company financed equipment acquisitions of $2.1 million with a note payable of $0.3 million and capital leases of $1.8 million. Additionally, equipment purchases of $0.3 million were unpaid and included in accounts payable as of December 31, 2011.

See accompanying Notes to Financial Statements, Independent Accountants’ Compilation Report and Independent Auditors’ Report.

 

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Countrywide Energy Services, LLC

Statements of Members’ Capital

For the Years Ended December 31, 2013 (Unaudited) and 2012

and for the Period from May 9, 2011 to December 31, 2011

 

(in thousands)		Contributed Capital				Accumulated Income				Receivable from Member				Total
Balance as of May 9, 2011		$	359			$	586			$	(400	)		$	545
Receipt from member			—				—				400				400
Net income			—				1,870				—				1,870
Distributions			—				(6	)			—				(6	)
Balance as of December 31, 2011			359				2,450				—				2,809
Net income			—				102				—				102
Distributions			—				(10	)			—				(10	)
Balance as of December 31, 2012			359				2,542				—				2,901
Net income (Unaudited)			—				148				—				148
Distributions (Unaudited)			—				(653	)			—				(653	)
Balance as of December 31, 2013 (Unaudited)		$	359			$	2,037			$	—			$	2,396

See accompanying Notes to Financial Statements, Independent Accountants’ Compilation Report and Independent Auditors’ Report.

 

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Countrywide Energy Services, LLC

Notes To Financial Statements

 

1.	Summary of Significant Accounting Policies and Related Matters

Organization and Activity—The Company was organized as a Pennsylvania limited liability company on January 21, 2010. The Company offers a wide-range of roustabout and oil field services to enterprises that are exploring and extracting Pennsylvania’s Marcellus Shale natural gas. These services include logistics, site preparation, maintenance, water transfer, land reclamation and production services.

Prior to the Company’s amended and restated operating agreement dated May 9, 2011, the Company had a sole member. Effective May 9, 2011, a 50% membership interest in the Company was purchased by Rice Drilling B LLC (“Rice Drilling B”).

Basis of Accounting—The Company maintains its accounting records on the accrual basis of accounting. Revenues are recognized for services provided or equipment on site based upon daily rates as specified in master service agreements with customers. Expenses are recognized as incurred.

The members of the Company decided that operations would be discontinued in the summer of 2013 as a result of the departure of the Company’s president. Subsequent operating activity has been limited to finishing work on outstanding contracts and selling the operating assets of the Company to an unrelated third party in exchange for cash and an installment note (see Note 2). The Company is in the process of converting the remaining assets to cash and satisfying its obligations. Remaining cash as well as the installment note will be distributed to Rice Drilling B and the other member in 2014 so that the Company can be dissolved. While the Company is in the process of liquidating, the financial statements have not been presented on the liquidation basis. However, the differences between the financial statements as presented and under the liquidation basis would not be significant.

Use of Estimates—The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Comprehensive Income—Comprehensive income consists of net income plus changes in other equity accounts. The Company had no comprehensive income beyond its net income for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011.

Cash—The Company maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed the balance sheets amounts due to outstanding checks.

Accounts Receivable—The Company regularly extended credit to customers for services provided in the normal course of business based upon management’s assessment of their creditworthiness. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. Increases in the allowance are charged to general and administrative expenses. Accounts are judged to be delinquent principally based on contractual terms. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the customer. While these estimates incorporated management’s assessment at December 31, 2013 and 2012, it is at least reasonably possible that the allowances will be further revised in the near term and actual results could differ from these estimates.

Equipment—Equipment is recorded at cost. Expenditures for major renewals and betterments that extend the useful lives of equipment are capitalized. Expenditures for maintenance and repairs are charged to expense as

 

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incurred. Provision for depreciation is computed using the straight-line method based on the estimated useful lives of the assets which range from two to ten years. Equipment under capital lease obligations is depreciated on the straight-line method over the shorter of the lease term or the estimated useful life of the equipment.

The carrying values of long-lived assets, which are limited to equipment, are evaluated periodically in relation to the operating performance of the underlying assets. Adjustments are made if the sum of expected future cash flows is less than book value and, if required, such adjustments would be measured based on discounted cash flows.

See Independent Accountants’ Compilation Report and Independent Auditors’ Report.

Income Taxes—The Company is treated as a partnership for federal and state income tax purposes. Consequently, the Company is not subject to income taxes; instead its members include the income in their tax returns.

Subsequent Events—Management has evaluated subsequent events for recognition and disclosure purposes through March 3, 2014, the date the financial statements were available to be issued.

 

2.	Note Receivable

During 2013, the Company sold equipment in exchange for $0.4 million cash and a $1.4 million note receivable. Payments on this note are due in monthly installments of $42 thousand, including interest at 5%, beginning March 1, 2014 with final payment on February 1, 2017. The note is secured by the equipment. Installments on this note subsequent to December 31, 2013 are expected to be as follows (in thousands):

 

2014		$	351
2015			462
2016			485
2017			102
Total		$	1,400

 

3.

Equipment

Equipment consists of the following as of December 31, 2013 and 2012 (in thousands):

 

		2013				2012
		(Unaudited)
Field equipment:
Machinery		$	—			$	1,916
Pipe			—				1,149
Vehicles and trailers			78				519
Leasehold improvements			—				28
Furniture and fixtures			—				8
Construction in progress			—				—
Total		$	78			$	3,620
Less accumulated depreciation			16				1,167
Equipment, net		$	62			$	2,453

Depreciation expense was $0.8 million, $0.9 million and $0.3 million for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011, respectively. The cost of equipment

 

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held under capital leases as of December 31, 2013 and 2012 was $0.1 million and $1.8 million, respectively. Accumulated depreciation of equipment held under capital leases was $16 thousand and $0.5 million as of December 31, 2013 and 2012, respectively.

See Independent Accountants’ Compilation Report and Independent Auditors’ Report.

 

4.	Long-Term Debt

Notes payable consist of the following as of December 31, 2012 (in thousands):

 

		2012
Promissory note payable due in monthly installments of $8 thousand through June 2014, including interest at 4.41%; secured by vehicles and guaranteed by both members and an individual		$	142
Vehicle loan payable in monthly installments of $1 thousand through September 2013, including interest at 9.48%; secured by vehicle			8
Unsecured promissory note payable to two individuals in monthly installments of $2 thousand, including interest at 8%, through February 2013			3
Total			153
Less current portion			105
Long-term notes payable		$	48

All notes payable were repaid during 2013.

 

5.

Leases

As of December 31, 2013, the Company has vehicles under capital leases with remaining obligations of $30 thousand. Subsequent to December 31, 2013, the Company purchased the vehicles for approximately $31 thousand and the lease agreements were terminated.

The Company also leased a garage and the surrounding land under an operating lease which was transferred to a third party in November 2013. Rent expense for this lease was $33 thousand, $31 thousand and $20 thousand for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011, respectively.

Additionally, the Company rented equipment and vehicles under various short term arrangements. Rental expense for these items was approximately $0.4 million, $0.9 million and $1.2 million for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011, respectively.

 

6.	Concentrations

The Company provided services to related companies (including Rice Drilling B, one of its investees, and one of its subcontractors) which accounted for approximately 91%, 85% and 60% of revenues for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011, respectively. Two additional customers accounted for approximately 26% of the Company’s revenues for the period from May 9, 2011 to December 31, 2011. Receivables from related companies accounted for 82%, and 98% of accounts receivable as of December 31, 2013 and 2012, respectively.

See Independent Accountants’ Compilation Report and Independent Auditors’ Report.

 

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ANNEX A:

LETTER OF TRANSMITTAL

TO TENDER

OLD 6.25% Senior Notes due 2022

OF

RICE ENERGY INC.

PURSUANT TO THE EXCHANGE OFFER AND PROSPECTUS

DATED                     , 2014

 

The Exchange Agent for the Exchange Offer is:

WELLS FARGO BANK, NATIONAL ASSOCIATION

 

By Registered or Certified Mail: Wells Fargo Bank, N.A. Corporate Trust Operations MAC-N9303-121 P.O. Box 1517 Minneapolis, MN 55480		By Overnight Delivery or Regular Mail: Wells Fargo Bank, N.A Corporate Trust Operations MAC-N9303-121 Sixth & Marquette Avenue Minneapolis, MN 55479

By Facsimile:

(877) 407-4679

Attn: Bondholder Communications

Confirm by Telephone:

(800) 344-5128

Attn: Bondholder Communications

If you wish to exchange old 6.25% Senior Notes due 2022 for an equal aggregate principal amount at maturity of new 6.25% Senior Notes due 2022 pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the exchange agent prior to the expiration date.

The undersigned hereby acknowledges receipt and review of the Prospectus, dated                     , 2014 (the “Prospectus”), of Rice Energy Inc. (the “Issuer”), and this letter of transmittal (the “Letter of Transmittal”), which together describe the Issuer’s offer (the “Exchange Offer”) to exchange its 6.25% Senior Notes due 2022 (the “new notes”) that have been registered under the Securities Act, as amended (the “Securities Act”), for a like principal amount of its issued and outstanding 6.25% Senior Notes due 2022 (the “old notes”). Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

The Issuer reserves the right, at any time or from time to time, to extend the Exchange Offer at its discretion, in which event the term “Expiration Date” shall mean the latest time date to which the Exchange Offer is extended. The Issuer shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

 

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This Letter of Transmittal is to be used by holders of the old notes. Tender of old notes is to be made according to the Automated Tender Offer Program (“ATOP”) of the Depository Trust Company (“DTC”) pursuant to the procedures set forth in the prospectus under the caption “Exchange Offer—Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer generated message known as an “agent’s message” to the exchange agent for its acceptance. For you to validly tender your old notes in the Exchange Offer the Exchange Agent must receive prior to the Expiration Date, an agent’s message under the ATOP procedures that confirms that:

 

•

DTC has received your instructions to tender your old notes; and

 

•

you agree to be bound by the terms of this Letter of Transmittal.

BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT

 

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ANNEX B: GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

“Bcf .” One billion cubic feet of natural gas.

“Btu.” One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree of Fahrenheit.

“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“DD&A.” Depreciation, depletion, amortization and accretion.

“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry gas.” A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.

“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“EUR.” Estimated ultimate recovery.

“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“Drilling locations.” Total gross (net) resource play locations that we may be able to drill on our existing acreage. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.

“Gross acres” or “gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.

“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Mcf.” One thousand cubic feet of natural gas.

“MMcf.” One million cubic feet of natural gas.

“MMBtu.” One million Btu.

 

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“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“NYMEX.” The New York Mercantile Exchange.

“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Prospect.” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

“Proved reserves.” The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

“Proved undeveloped reserves (“PUD”).” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“PV-10.” When used with respect to natural gas and oil reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production, future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC.

“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.

“Total depth.” The planned end of a well, measured by the length of pipe required to reach the bottom.

“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

 

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“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

 

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Rice Energy Inc.

Offer to Exchange

Up To $900,000,000 of

6.25% Senior Notes due 2022

That Have Not Been Registered Under

The Securities Act of 1933

For

Up To $900,000,000 of

6.25% Senior Notes due 2022

That Have Been Registered Under

The Securities Act of 1933

 

 

DEALER PROSPECTUS DELIVERY OBLIGATION

Until                     , 2015, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 20.

Indemnification of Directors and Officers.

Rice Energy Inc.

Rice Energy Inc. is organized under the laws of Delaware. Our amended and restated certificate of incorporation provides that a director will not be liable to the corporation or its stockholders for monetary damages to the fullest extent permitted by the DGCL. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our certificate of incorporation, will be limited to the fullest extent permitted by the amended DGCL. Our amended and restated bylaws provides that the corporation will indemnify, and advance expenses to, any officer or director to the fullest extent authorized by the DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, stockholder vote, agreement or otherwise.

Our amended and restated certificate of incorporation also contains indemnification rights for our directors and our officers. Specifically, our amended and restated certificate of incorporation provides that we shall indemnify our officers and directors to the fullest extent authorized by the DGCL. Further, we may maintain insurance on behalf of our officers and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors.

We have obtained directors’ and officers’ insurance to cover our directors, officers and some of our employees for certain liabilities.

We have entered into written indemnification agreements with our directors and executive officers. Under these agreements, if an officer or director makes a claim of indemnification to us, either a majority of the independent directors or independent legal counsel selected by the independent directors must review the relevant facts and make a determination whether the officer or director has met the standards of conduct under Delaware law that would permit (under Delaware law) and require (under the indemnification agreement) us to indemnify the officer or director.

Delaware Limited Liability Companies

Rice Marketing LLC, Rice Energy Marketing LLC, Rice Energy Appalachia, LLC, Rice Drilling B LLC, Rice Poseidon Midstream LLC, Rice Olympus Midstream LLC, Alpha Shale Holdings, LLC (each, a “Delaware LLC Registrant”, and collectively, the “Delaware LLC Registrants”), Rice Drilling D LLC and Blue Tiger Oilfield Services LLC are organized in the State of Delaware. Section 18-108 of the Delaware Limited Liability Company Act provides that, subject to such standards and restrictions, if any, as are set forth in its limited

 

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liability company agreement, a Delaware limited liability company may, and has the power to, indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

The limited liability company agreements and operating agreements of the Delaware LLC Registrants generally provide for the indemnification of members, officers and managers of each Delaware LLC Registrant to the fullest extent authorized by the Delaware Limited Liability Company Act, provided however, that officers and managers are generally not entitled to indemnification for losses arising as a result of fraud, willful misconduct, bad faith and gross negligence. The operating agreements of Rice Drilling D LLC and Blue Tiger Oilfield Services LLC provide that the respective limited liability companies are empowered to, but are not required to, indemnify any member, manager or officer.

The general effect of the foregoing is to provide indemnification to officers and managers for liabilities that may arise by reason of their status as officers or managers, other than liabilities arising from willful or intentional misconduct, acts or omissions not in good faith, unlawful distributions of corporate assets or transactions from which the officer or manager derived an improper personal benefit.

Each Delaware limited liability company may maintain directors’ and officers’ liability insurance for itself and any subsidiaries.

Delaware Limited Partnership

Alpha Shale Resources, LP is organized in the state of Delaware. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The partnership agreement of Alpha Shale Resources, LP provides that the limited partner shall have no liability under the partnership agreement, but does not otherwise provide for indemnification.

Alpha Shale Resources, LP may maintain directors’ and officers’ liability insurance for itself and any subsidiaries.

Pennsylvania Limited Liability Company

Rice Drilling C LLC is organized in the Commonwealth of Pennsylvania. Section 8945 of the Pennsylvania Limited Liability Company Law of 1994 provides that a Pennsylvania limited liability company may and shall have the power to indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever; provided, however, that a limited liability company may not indemnify a manager, member or other person for an act that is determined by a court to constitute willful misconduct or recklessness. Further, subsection (d) provides that a limited liability company may pay expenses incurred by a member, manager or other person in advance of disposition of any claim if such person makes an undertaking to repay the company if it is determined that such person is not entitled to indemnification. Finally, under subsection (f), a limited liability company must indemnify its members and managers for payments made, and personal liabilities reasonably incurred, in the ordinary and proper conduct of its business or for the preservation of its business or property.

The operating agreement of Rice Drilling C LLC provides that the company shall indemnify its member and such other persons identified by the member as entitled to indemnification, for all costs, losses, liabilities and damages paid or accrued by the member or any such other person in connection with the business of the company, to the fullest extent provided by the laws of the Commonwealth of Pennsylvania. In addition, the company may advance costs of defense of any proceeding to its member or any such other person upon receipt by the company of an undertaking to repay such amount if it is ultimately determined that the member or such other person is not entitled to indemnification by the company.

Rice Drilling C LLC may maintain directors’ and officers’ liability insurance for itself and any subsidiaries.

 

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Item 21.

Exhibits and Financial Statement Schedules.

(a) The following documents are filed as exhibits to this Registration Statement:

 

Exhibit Number		Description
2.1		Purchase and Sale Agreement, among M3 Appalachia Gathering, LLC, as seller, Rice Poseidon Midstream LLC, as Buyer, and M3 Midstream LLC, dated as of February 12, 2014 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 14, 2014).
2.2		Purchase and Sale Agreement, dated June 11, 2014, by and among Rice Drilling B LLC, Chesapeake Appalachia, L.L.C. and Statoil USA Onshore Properties Inc. (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on August 7, 2014).
3.1		Amended and Restated Certificate of Incorporation of Rice Energy Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
3.2		Amended and Restated Bylaws of Rice Energy Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
3.3*		Certificate of Formation of Rice Marketing LLC
3.4*		Limited Liability Company Agreement of Rice Marketing LLC
3.5*		Certificate of Formation of Rice Energy Marketing LLC
3.6*		Limited Liability Company Agreement of Rice Energy Marketing LLC
3.7*		Certificate of Formation of Rice Energy Appalachia, LLC
3.8*		Second Amended and Restated Limited Liability Company Agreement of Rice Energy Appalachia, LLC
3.9*		Certificate of Formation of Rice Drilling B LLC
3.10*		Second Amended and Restated Limited Liability Company Agreement of Rice Drilling B LLC
3.11*		Certificate of Organization of Rice Drilling C LLC
3.12*		Amended and Restated Operating Agreement of Rice Drilling C LLC
3.13*		Certificate of Formation of Rice Drilling D LLC
3.14*		Amended and Restated Operating Agreement of Rice Drilling D LLC
3.15*		Certificate of Formation of Rice Poseidon Midstream LLC
3.16*		Operating Agreement of Rice Poseidon Midstream LLC
3.17*		Certificate of Formation of Rice Olympus Midstream LLC
3.18*		Operating Agreement of Rice Olympus Midstream LLC
3.19*		Certificate of Formation of Blue Tiger Oilfield Services LLC
3.20*		Operating Agreement of Blue Tiger Oilfield Services LLC
3.21*		Certificate of Formation of Alpha Shale Holdings, LLC

 

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Exhibit Number		Description
3.22*		Amended and Restated Limited Liability Company Agreement of Alpha Shale Holdings, LLC
3.23*		Certificate of Limited Partnership of Alpha Shale Resources, LP
3.24*		Amended and Restated Agreement of Limited Partnership of Alpha Shale Resources, LP
4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1 (File No. 133-192894) filed with the Commission on January 13, 2014).
4.2		Registration Rights Agreement, dated as of January 29, 2014, by and among Rice Energy Inc., Rice Energy Holdings LLC, Rice Energy Family Holdings, LP, NGP Rice Holdings LLC and Foundation PA Coal Company, LLC (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
4.3		Stockholders’ Agreement, dated as of January 29, 2014, by and among Rice Energy Inc., Rice Energy Holdings LLC, Rice Energy Family Holdings, LP, NGP Rice Holdings LLC and Alpha Natural Resources, Inc. (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
4.4		First Amendment to Stockholders’ Agreement, dated as of August 8, 2014, by and among Rice Energy Inc., Rice Energy Holdings LLC, Rice Energy Family Holdings, LP, NGP Rice Holdings LLC and Alpha Natural Resources, Inc. (incorporated by reference to Exhibit 4.5 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36273) filed with the Commission on August 11, 2014).
4.5		Indenture, dated as of April 25, 2014, by and among Rice Energy Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee. (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on April 29, 2014).
4.6*		Supplemental Indenture, dated as of November 10, 2014, by and among Rice Energy Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee.
4.7		Form of 6.250% Senior Note due 2022 (included as Exhibit A to Exhibit 4.4) (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on April 29, 2014).
4.8		Registration Rights Agreement, dated as of April 25, 2014, by and among Rice Energy Inc., the several guarantors named therein and Barclays Capital Inc. as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on April 29, 2014).
5.1*		Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered.
10.1		Second Amended and Restated Credit Agreement, dated as of April 25, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on October 3, 2013).
10.2		First Amendment to Second Amended and Restated Credit Agreement, dated as of August 7, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.2 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on October 3, 2013).

 

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Exhibit Number		Description
10.3		Second Amendment to Second Amended and Restated Credit Agreement, dated as of August 20, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.3 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on October 3, 2013).
10.4		Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 15, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.4 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.5		Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of November 5, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.5 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.6		Limited Consent and Waiver and Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.6 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on January 6, 2014).
10.7		Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of January 29, 2014, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.8		Senior Secured Term Loan Credit Agreement, dated as of April 25, 2013, among Rice Drilling B LLC, as borrower, Barclays Bank PLC, as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.10 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on October 3, 2013).
10.9		Master Reorganization Agreement, dated as of January 23, 2014, by and among Rice Energy Family Holdings, LP, NGP RE Holdings, L.L.C., NGP RE Holdings II, L.L.C., Daniel J. Rice III, Rice Drilling B LLC, Rice Merger LLC, Rice Energy Appalachia, LLC, each of the persons holding incentive units representing interests in Rice Energy Appalachia, LLC, Rice Energy Inc., Rice Energy Holdings LLC, and NGP Rice Holdings LLC (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on January 29, 2014).
10.10		Agreement and Plan of Merger of Rice Merger LLC with and into Rice Drilling B LLC (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on January 29, 2014).
10.11		Transaction Agreement by and among Rice Energy Inc., Rice Drilling C LLC and Foundation PA Coal Company, LLC, dated as of December 6, 2013 (incorporated by reference to Exhibit 10.8 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.12†		Amended and Restated Liability Company Agreement of Rice Energy Appalachia, LLC (incorporated by reference to Exhibit 10.11 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on January 8, 2014).

 

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Exhibit Number		Description
10.13†		Amended and Restated Liability Company Agreement of Rice Energy Holdings LLC (incorporated by reference to Exhibit 10.23 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.14†		Amended and Restated Liability Company Agreement of NGP Rice Holdings LLC (incorporated by reference to Exhibit 10.24 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.15†		Employment Agreement (Daniel J. Rice IV) (incorporated by reference to Exhibit 10.17 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.16†		Employment Agreement (Toby Z. Rice) (incorporated by reference to Exhibit 10.18 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.17†		Employment Agreement (Derek A. Rice) (incorporated by reference to Exhibit 10.19 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.18†		Employment Agreement (Grayson T. Lisenby) (incorporated by reference to Exhibit 10.20 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.19†		Employment Agreement (James W. Rogers) (incorporated by reference to Exhibit 10.21 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.20†		Employment Agreement (William E. Jordan) (incorporated by reference to Exhibit 10.22 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.21†		Indemnification Agreement (Daniel J. Rice IV) (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.22†		Indemnification Agreement (Toby Z. Rice) (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.23†		Indemnification Agreement (Derek A. Rice) (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.24†		Indemnification Agreement (Grayson T. Lisenby) (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.25†		Indemnification Agreement (James W. Rogers) (incorporated by reference to Exhibit 10.6 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.26†		Indemnification Agreement (William E. Jordan) (incorporated by reference to Exhibit 10.7 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).

 

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Exhibit Number		Description
10.27†		Indemnification Agreement (Daniel J. Rice III) (incorporated by reference to Exhibit 10.8 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.28†		Indemnification Agreement (Scott A. Gieselman) (incorporated by reference to Exhibit 10.9 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.29†		Indemnification Agreement, dated as of August 8, 2014, by and among the Company, Alpha Natural Resources, Inc. and Kevin S. Crutchfield (incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36273) filed with the Commission on August 8, 2014).
10.30†		Indemnification Agreement (James W. Christmas) (incorporated by reference to Exhibit 10.11 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.31†		Indemnification Agreement (Chris G. Carter) (incorporated by reference to Exhibit 10.12 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.32†		Indemnification Agreement (Robert F. Vagt) (incorporated by reference to Exhibit 10.13 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.33		Indemnification Agreement, dated as of August 8, 2014, by and among the Company, Alpha Natural Resources, Inc. and Kevin S. Crutchfield (incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36273) filed with the Commission on August 11, 2014).
10.34†		Amended and Restated Rice Energy Inc. 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36273) filed with the Commission on August 11, 2014).
10.35†		Rice Energy Management Bonus Plan (incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on November 12, 2013).
10.36†		Form of Restricted Stock Unit Agreement (Employees) (incorporated by reference to Exhibit 10.13 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.37†		Form of Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.19 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on January 8, 2014).
10.38		Form of Senior Subordinated Convertible Debentures due 2014 (incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.39		Amendment, Consent and Parent Guaranty to Senior Subordinated Convertible Debentures due 2014 (incorporated by reference to Exhibit 10.21 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on January 8, 2014).
10.40		Form of Warrant Agreement (incorporated by reference to Exhibit 10.16 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).

 

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Exhibit Number		Description
10.41		Form of Bonus Warrant Agreement (incorporated by reference to Exhibit 10.17 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.42		Form of Amended and Restated Warrant to Purchase Shares of Common Stock (incorporated by reference to Exhibit 10.41(a) of the Company’s Annual Report on Form 10-K (File No. 001-36273) filed with the Commission on March 21, 2014).
10.43		Form of Amended and Restated Bonus Warrant to Purchase Shares of Common Stock (incorporated by reference to Exhibit 10.42(a) of the Company’s Annual Report on Form 10-K (File No. 001-36273) filed with the Commission on March 21, 2014).
10.44		Third Amended and Restated Credit Agreement, dated as of April 10, 2014, among Rice Energy Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on April 11, 2014).
10.45†		Form of Performance Stock Unit (PSU) Agreement (incorporated by reference to Exhibit 10.44 of the Company’s Registration Statement on Form S-1 (File No. 333-197266) filed with the Commission on July 7, 2014).
12.1*		Computation of Ratio of Earnings to Fixed Charges
21.1*		List of Subsidiaries of Rice Energy Inc.
23.1*		Consent of Ernst & Young LLP (Rice Energy Inc.)
23.2*		Consent of Grossman Yanak & Ford LLP (Countrywide Energy Services, LLC)
23.3*		Consent of Ernst & Young LLP (Alpha Shale Resources, LP)
23.4*		Consent of Schneider Downs & Co., Inc. (Alpha Shale Resources, LP)
23.5*		Consent of Netherland, Sewell and Associates, Inc.
23.6*		Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto)
24.1*		Power of Attorney (included in the signature page of this Registration Statement)
25.1*		Statement of Eligibility on Form T-1 of Wells Fargo Bank, National Association
99.1*		Netherland, Sewell and Associates, Inc., Summary of Reserves at December 31, 2013 (Rice Energy Inc.)
99.2*		Netherland, Sewell and Associates, Inc., Summary of Reserves at December 31, 2013 (Alpha Shale Resources, LP)
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

 

*	Filed herewith.

**	Incorporated by reference to the filing indicated

†	Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.

 

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(b) Financial Data Schedule.

Schedules are omitted because they either are not required or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.

 

Item 22.

Undertakings.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrants, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of a registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, such registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

Each registrant hereby undertakes:

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(a) to include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(b) to reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

(c) to include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if such registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

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That, for the purpose of determining liability of such registrant under the Securities Act of 1933 to any purchaser in the initial distribution of the securities, in a primary offering of securities of such registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(a) any preliminary prospectus or prospectus of the undersigned registrants relating to the offering required to be filed pursuant to Rule 424;

(b) any free writing prospectus relating to the offering prepared by or on behalf of such registrant or used or referred to by the undersigned registrants;

(c) the portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrants or their securities provided by or on behalf of such registrant; and

(d) any other communication that is an offer in the offering made by such registrant to the purchaser.

That, for purposes of determining any liability under the Securities Act of 1933, each filing of a registrant annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 (and, where applicable, each filing of an employee benefit plan’s annual report pursuant to section 15(d) of the Securities Exchange Act of 1934) that is incorporated by reference in the registration statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

To deliver or cause to be delivered with the prospectus, to each person to whom the prospectus is sent or given, the latest annual report to security holders that is incorporated by reference in the prospectus and furnished pursuant to and meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act of 1934; and, where interim financial information required to be presented by Article 3 of Regulation S-X are not set forth in the prospectus, to deliver, or cause to be delivered to each person to whom the prospectus is sent or given, the latest quarterly report that is specifically incorporated by reference in the prospectus to provide such interim financial information.

To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Canonsburg, State of Pennsylvania, on December 2, 2014.

 

Each person whose signature appears below appoints Daniel J. Rice IV, Grayson T. Lisenby and James W. Rogers, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Name		Title		Date
/s/ Daniel J. Rice IV Daniel J. Rice IV		Director, Chief Executive Officer (Principal Executive Officer)		December 2, 2014
/s/ Toby Z. Rice Toby Z. Rice		Director, President and Chief Operating Officer		December 2, 2014
/s/ Grayson T. Lisenby Grayson T. Lisenby		Vice President and Chief Financial Officer (Principal Financial Officer)		December 2, 2014
/s/ James W. Rogers James W. Rogers		Vice President, Chief Accounting & Administrative Officer, Treasurer (Principal Accounting Officer)		December 2, 2014
/s/ Robert F. Vagt Robert F. Vagt		Director		December 2, 2014
/s/ James W. Christmas James W. Christmas		Director		December 2, 2014
/s/ Scott A. Gieselman Scott A. Gieselman		Director		December 2, 2014
/s/ Daniel J. Rice III Daniel J. Rice III		Director		December 2, 2014

 

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Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Canonsburg, State of Pennsylvania, on December 2, 2014.

 

Each person whose signature appears below appoints Daniel J. Rice IV, Grayson T. Lisenby and James W. Rogers, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Name		Title		Date
/s/ Daniel J. Rice IV Daniel J. Rice IV		Chief Executive Officer (Principal Executive Officer)		December 2, 2014
/s/ Grayson T. Lisenby Grayson T. Lisenby		Vice President and Chief Financial Officer (Principal Financial Officer)		December 2, 2014
/s/ James W. Rogers James W. Rogers		Vice President, Chief Accounting & Administrative Officer, Treasurer (Principal Accounting Officer)		December 2, 2014

 

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Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Canonsburg, State of Pennsylvania, on December 2, 2014.

 

Each person whose signature appears below appoints Daniel J. Rice IV, Grayson T. Lisenby and James W. Rogers, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Name		Title		Date
/s/ Daniel J. Rice IV Daniel J. Rice IV		Chief Executive Officer (Principal Executive Officer)		December 2, 2014
/s/ Grayson T. Lisenby Grayson T. Lisenby		Vice President and Chief Financial Officer (Principal Financial Officer)		December 2, 2014
/s/ James W. Rogers James W. Rogers		Vice President, Chief Accounting & Administrative Officer, Treasurer (Principal Accounting Officer)		December 2, 2014

 

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INDEX TO EXHIBITS

 

Exhibit Number		Description
2.1		Purchase and Sale Agreement, among M3 Appalachia Gathering, LLC, as seller, Rice Poseidon Midstream LLC, as Buyer, and M3 Midstream LLC, dated as of February 12, 2014 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 14, 2014).
2.2		Purchase and Sale Agreement, dated June 11, 2014, by and among Rice Drilling B LLC, Chesapeake Appalachia, L.L.C. and Statoil USA Onshore Properties Inc. (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on August 7, 2014).
3.1		Amended and Restated Certificate of Incorporation of Rice Energy Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
3.2		Amended and Restated Bylaws of Rice Energy Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
3.3*		Certificate of Formation of Rice Marketing LLC
3.4*		Limited Liability Company Agreement of Rice Marketing LLC
3.5*		Certificate of Formation of Rice Energy Marketing LLC
3.6*		Limited Liability Company Agreement of Rice Energy Marketing LLC
3.7*		Certificate of Formation of Rice Energy Appalachia, LLC
3.8*		Second Amended and Restated Limited Liability Company Agreement of Rice Energy Appalachia, LLC
3.9*		Certificate of Formation of Rice Drilling B LLC
3.10*		Second Amended and Restated Limited Liability Company Agreement of Rice Drilling B LLC
3.11*		Certificate of Organization of Rice Drilling C LLC
3.12*		Amended and Restated Operating Agreement of Rice Drilling C LLC
3.13*		Certificate of Formation of Rice Drilling D LLC
3.14*		Amended and Restated Operating Agreement of Rice Drilling D LLC
3.15*		Certificate of Formation of Rice Poseidon Midstream LLC
3.16*		Operating Agreement of Rice Poseidon Midstream LLC
3.17*		Certificate of Formation of Rice Olympus Midstream LLC
3.18*		Operating Agreement of Rice Olympus Midstream LLC
3.19*		Certificate of Formation of Blue Tiger Oilfield Services LLC
3.20*		Operating Agreement of Blue Tiger Oilfield Services LLC
3.21*		Certificate of Formation of Alpha Shale Holdings, LLC
3.22*		Amended and Restated Limited Liability Company Agreement of Alpha Shale Holdings, LLC
3.23*		Certificate of Limited Partnership of Alpha Shale Resources, LP

 

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Exhibit Number		Description
3.24*		Amended and Restated Agreement of Limited Partnership of Alpha Shale Resources, LP
4.1		Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1 (File No. 133-192894) filed with the Commission on January 13, 2014).
4.2		Registration Rights Agreement, dated as of January 29, 2014, by and among Rice Energy Inc., Rice Energy Holdings LLC, Rice Energy Family Holdings, LP, NGP Rice Holdings LLC and Foundation PA Coal Company, LLC (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
4.3		Stockholders’ Agreement, dated as of January 29, 2014, by and among Rice Energy Inc., Rice Energy Holdings LLC, Rice Energy Family Holdings, LP, NGP Rice Holdings LLC and Alpha Natural Resources, Inc. (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
4.4		First Amendment to Stockholders’ Agreement, dated as of August 8, 2014, by and among Rice Energy Inc., Rice Energy Holdings LLC, Rice Energy Family Holdings, LP, NGP Rice Holdings LLC and Alpha Natural Resources, Inc. (incorporated by reference to Exhibit 4.5 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36273) filed with the Commission on August 11, 2014).
4.5		Indenture, dated as of April 25, 2014, by and among Rice Energy Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee.(incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on April 29, 2014).
4.6*		Supplemental Indenture, dated as of November 10, 2014, by and among Rice Energy Inc., the several guarantors named therein and Wells Fargo Bank, National Association, as trustee.
4.7		Form of 6.250% Senior Note due 2022 (included as Exhibit A to Exhibit 4.4) (incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on April 29, 2014).
4.8		Registration Rights Agreement, dated as of April 25, 2014, by and among Rice Energy Inc., the several guarantors named therein and Barclays Capital Inc. as representative of the initial purchasers named therein (incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on April 29, 2014).
5.1*		Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered.
10.1		Second Amended and Restated Credit Agreement, dated as of April 25, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on October 3, 2013).
10.2		First Amendment to Second Amended and Restated Credit Agreement, dated as of August 7, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.2 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on October 3, 2013).
10.3		Second Amendment to Second Amended and Restated Credit Agreement, dated as of August 20, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.3 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on October 3, 2013).

 

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Exhibit Number		Description
10.4		Third Amendment to Second Amended and Restated Credit Agreement, dated as of October 15, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.4 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.5		Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of November 5, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.5 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.6		Limited Consent and Waiver and Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of December 27, 2013, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.6 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on January 6, 2014).
10.7		Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of January 29, 2014, among Rice Drilling B LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.8		Senior Secured Term Loan Credit Agreement, dated as of April 25, 2013, among Rice Drilling B LLC, as borrower, Barclays Bank PLC, as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.10 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on October 3, 2013).
10.9		Master Reorganization Agreement, dated as of January 23, 2014, by and among Rice Energy Family Holdings, LP, NGP RE Holdings, L.L.C., NGP RE Holdings II, L.L.C., Daniel J. Rice III, Rice Drilling B LLC, Rice Merger LLC, Rice Energy Appalachia, LLC, each of the persons holding incentive units representing interests in Rice Energy Appalachia, LLC, Rice Energy Inc., Rice Energy Holdings LLC, and NGP Rice Holdings LLC (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on January 29, 2014).
10.10		Agreement and Plan of Merger of Rice Merger LLC with and into Rice Drilling B LLC (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on January 29, 2014).
10.11		Transaction Agreement by and among Rice Energy Inc., Rice Drilling C LLC and Foundation PA Coal Company, LLC, dated as of December 6, 2013 (incorporated by reference to Exhibit 10.8 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.12†		Amended and Restated Liability Company Agreement of Rice Energy Appalachia, LLC (incorporated by reference to Exhibit 10.11 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on January 8, 2014).
10.13†		Amended and Restated Liability Company Agreement of Rice Energy Holdings LLC (incorporated by reference to Exhibit 10.23 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.14†		Amended and Restated Liability Company Agreement of NGP Rice Holdings LLC (incorporated by reference to Exhibit 10.24 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).

 

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Exhibit Number		Description
10.15†		Employment Agreement (Daniel J. Rice IV) (incorporated by reference to Exhibit 10.17 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.16†		Employment Agreement (Toby Z. Rice) (incorporated by reference to Exhibit 10.18 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.17†		Employment Agreement (Derek A. Rice) (incorporated by reference to Exhibit 10.19 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.18†		Employment Agreement (Grayson T. Lisenby) (incorporated by reference to Exhibit 10.20 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.19†		Employment Agreement (James W. Rogers) (incorporated by reference to Exhibit 10.21 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.20†		Employment Agreement (William E. Jordan) (incorporated by reference to Exhibit 10.22 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.21†		Indemnification Agreement (Daniel J. Rice IV) (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.22†		Indemnification Agreement (Toby Z. Rice) (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.23†		Indemnification Agreement (Derek A. Rice) (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.24†		Indemnification Agreement (Grayson T. Lisenby) (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.25†		Indemnification Agreement (James W. Rogers) (incorporated by reference to Exhibit 10.6 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.26†		Indemnification Agreement (William E. Jordan) (incorporated by reference to Exhibit 10.7 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.27†		Indemnification Agreement (Daniel J. Rice III) (incorporated by reference to Exhibit 10.8 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.28†		Indemnification Agreement (Scott A. Gieselman) (incorporated by reference to Exhibit 10.9 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).

 

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Exhibit Number		Description
10.29†		Indemnification Agreement, dated as of August 8, 2014, by and among the Company, Alpha Natural Resources, Inc. and Kevin S. Crutchfield (incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36273) filed with the Commission on August 8, 2014).
10.30†		Indemnification Agreement (James W. Christmas) (incorporated by reference to Exhibit 10.11 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.31†		Indemnification Agreement (Chris G. Carter) (incorporated by reference to Exhibit 10.12 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.32†		Indemnification Agreement (Robert F. Vagt) (incorporated by reference to Exhibit 10.13 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on February 4, 2014).
10.33		Indemnification Agreement, dated as of August 8, 2014, by and among the Company, Alpha Natural Resources, Inc. and Kevin S. Crutchfield (incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36273) filed with the Commission on August 11, 2014).
10.34†		Amended and Restated Rice Energy Inc. 2014 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q (File No. 001-36273) filed with the Commission on August 11, 2014).
10.35†		Rice Energy Management Bonus Plan (incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on November 12, 2013).
10.36†		Form of Restricted Stock Unit Agreement (Employees) (incorporated by reference to Exhibit 10.13 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.37†		Form of Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.19 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on January 8, 2014).
10.38		Form of Senior Subordinated Convertible Debentures due 2014 (incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.39		Amendment, Consent and Parent Guaranty to Senior Subordinated Convertible Debentures due 2014 (incorporated by reference to Exhibit 10.21 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on January 8, 2014).
10.40		Form of Warrant Agreement (incorporated by reference to Exhibit 10.16 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.41		Form of Bonus Warrant Agreement (incorporated by reference to Exhibit 10.17 of the Company’s Registration Statement on Form S-1 (File No. 333-192894) filed with the Commission on December 16, 2013).
10.42		Form of Amended and Restated Warrant to Purchase Shares of Common Stock (incorporated by reference to Exhibit 10.41(a) of the Company’s Annual Report on Form 10-K (File No. 001-36273) filed with the Commission on March 21, 2014).

 

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Exhibit Number		Description
10.43		Form of Amended and Restated Bonus Warrant to Purchase Shares of Common Stock (incorporated by reference to Exhibit 10.42(a) of the Company’s Annual Report on Form 10-K (File No. 001-36273) filed with the Commission on March 21, 2014).
10.44		Third Amended and Restated Credit Agreement, dated as of April 10, 2014, among Rice Energy Inc., as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-36273) filed with the Commission on April 11, 2014).
10.45†		Form of Performance Stock Unit (PSU) Agreement (incorporated by reference to Exhibit 10.44 of the Company’s Registration Statement on Form S-1 (File No. 333-197266) filed with the Commission on July 7, 2014).
12.1*		Computation of Ratio of Earnings to Fixed Charges
21.1*		List of Subsidiaries of Rice Energy Inc.
23.1*		Consent of Ernst & Young LLP (Rice Energy Inc.)
23.2*		Consent of Grossman Yanak & Ford LLP (Countrywide Energy Services, LLC)
23.3*		Consent of Ernst & Young LLP (Alpha Shale Resources, LP)
23.4*		Consent of Schneider Downs & Co., Inc. (Alpha Shale Resources, LP)
23.5*		Consent of Netherland, Sewell and Associates, Inc.
23.6*		Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1 hereto)
24.1*		Power of Attorney (included in the signature page of this Registration Statement)
25.1*		Statement of Eligibility on Form T-1 of Wells Fargo Bank, National Association.
99.1*		Netherland, Sewell and Associates, Inc., Summary of Reserves at December 31, 2013 (Rice Energy Inc.)
99.2*		Netherland, Sewell and Associates, Inc., Summary of Reserves at December 31, 2013 (Alpha Shale Resources, LP)
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

 

*	Filed herewith.

**	Incorporated by reference to the filing indicated

†	Identifies an Exhibit that consists of or includes a management contract or compensatory plan or arrangement.

 

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