UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2016
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from _______________ to _______________
Commission file number: 000-51719
LINN ENERGY, INC.
(Successor in interest to Linn Energy, LLC)
(Exact name of registrant as specified in its charter)
Delaware | 81-5366183 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
600 Travis Houston, Texas | 77002 | |
(Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code
(281) 840-4000
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
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.
Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company x
Indicate by check-mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yes ¨ No x
The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrant was approximately $20 million on June 30, 2016, based on $0.09 per unit, the last reported sales price of the units on the OTC Markets Group Inc.’s Pink marketplace on such date.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨
As of February 28, 2017, there were 91,708,500 shares of Class A common stock, par value $0.001 per share, outstanding.
Documents Incorporated By Reference:
Certain information called for in Items 10, 11, 12, 13 and 14 of Part III will be included in an amendment to this Annual Report on Form 10-K.
TABLE OF CONTENTS
Page | ||
i
Glossary of Terms
As commonly used in the oil and natural gas industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:
Basin. A large area with a relatively thick accumulation of sedimentary rocks.
Bbl. One stock tank barrel or 42 United States gallons liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 degrees to 59.5 degrees Fahrenheit.
Development well. A well drilled within the proved area of a reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A stratum of rock that is recognizable from adjacent strata consisting primarily of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBbls/d. MBbls per day.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcf/d. MMcf per day.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMcfe/d. MMcfe per day.
MMMBtu. One billion British thermal units.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NGL. Natural gas liquids, which are the hydrocarbon liquids contained within natural gas.
ii
Glossary of Terms - Continued
Productive well. A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved reserves. Reserves that 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, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves or PUDs. 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. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Royalty interest. An interest that entitles the owner of such interest to a share of the mineral production from a property or to a share of the proceeds there from. It does not contain the rights and obligations of operating the property and normally does not bear any of the costs of exploration, development and operation of the property.
Spacing. The number of wells which conservation laws allow to be drilled on a given area of land.
Standardized measure of discounted future net cash flows. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the regulations of the Securities and Exchange Commission, without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses or depreciation, depletion and amortization; discounted using an annual discount rate of 10%.
Tcfe. One trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
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 oil, natural gas and NGL regardless of whether such acreage contains proved reserves.
Unproved reserves. Reserves that are considered less certain to be recovered than proved reserves. Unproved reserves may be further sub-classified to denote progressively increasing uncertainty of recoverability and include probable reserves and possible reserves.
iii
Glossary of Terms - Continued
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover. Maintenance on a producing well to restore or increase production.
Zone. A stratigraphic interval containing one or more reservoirs.
iv
Part I
Item 1. Business
This Annual Report on Form 10-K contains forward-looking statements based on expectations, estimates and assumptions as of the date of this filing. These statements by their nature are subject to a number of risks and uncertainties. Actual results may differ materially from those discussed in the forward-looking statements. For more information, see “Cautionary Statement Regarding Forward-Looking Statements” included at the end of this Item 1. “Business” and see also Item 1A. “Risk Factors.”
References
When referring to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “Reorganized LINN,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of LINN Energy through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see below and Note 3). The reference to “LinnCo” herein refers to LinnCo, LLC, which is an affiliate of the Predecessor.
The reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Overview
LINN Energy is an independent oil and natural gas company that was formed on February 14, 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2, on May 11, 2016, Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017.
On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date. The results of operations of Berry are reported as discontinued operations for all periods presented.
The Company’s properties are located in the United States (“U.S.”), in the Hugoton Basin, the Rockies, the Mid-Continent, east Texas and north Louisiana (“TexLa”), Michigan/Illinois, California, the Permian Basin and south Texas.
Proved reserves at December 31, 2016, were approximately 3,520 Bcfe, of which approximately 17% were oil, 65% were natural gas and 18% were natural gas liquids (“NGL”). Approximately 92% were classified as proved developed, with a total standardized measure of discounted future net cash flows of approximately $1.9 billion. At December 31, 2016, the Company operated 13,393 or approximately 58% of its 23,158 gross productive wells and had an average proved reserve-life index of approximately 12 years, based on the December 31, 2016, reserve reports and year-end 2016 production.
1
Item 1. Business - Continued
Strategy
Prior to the Company’s emergence from voluntary reorganization under Chapter 11, the Company was an upstream master limited partnership with a strategy to acquire, develop and maximize cash flow from a growing portfolio of long-life oil and natural gas assets. Upon its emergence from bankruptcy as a corporation with an improved balance sheet and greater liquidity, the Company is transitioning to a growth-oriented exploration and production company.
The Company’s current focus is on accelerating the development of its core SCOOP/STACK/Merge acreage in western Oklahoma, along with additional emerging stacked pay horizontal opportunities in the Mid-Continent, Rockies and TexLa regions. The Company has a large inventory of drilling and optimization projects to achieve organic growth and continues to add value by efficiently operating and applying new technology to mature fields. As part of its restructuring, the Company is marketing certain non-strategic assets to focus resources on growth opportunities and continues to leverage its experienced workforce and scalable infrastructure to maximize shareholder value.
Recent Developments
Emergence from Voluntary Reorganization Under Chapter 11
On October 21, 2016, the Debtors filed the Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates (the “Original Plan”).
On December 3, 2016, the Debtors split the Original Plan and pursued separate plans of reorganization for the LINN Debtors, on the one hand, and Linn Acquisition Company, LLC (“LAC”) and Berry, on the other hand. Accordingly, on December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “LINN Plan”). The LINN Debtors subsequently filed amended versions of the LINN Plan with the Bankruptcy Court.
On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the LINN Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.
On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.
Pursuant to the LINN Plan, the Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed subsidiary of the Predecessor and the borrower under the Credit Agreement (“Exit Facility”) entered into in connection with the reorganization, in exchange for 100% of the equity of Holdco II and the issuance of interests in the Exit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred 100% of the equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash and an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor (the “Disposition”), which the Predecessor distributed to certain of its creditors in satisfaction of their claims. Contemporaneously with the reorganization transactions and pursuant to the LINN Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims.
For additional information related to the Company’s emergence from bankruptcy and the terms of the Exit Facility, see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2.
2
Item 1. Business - Continued
2017 Oil and Natural Gas Capital Budget
For 2017, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $395 million, including approximately $300 million related to its oil and natural gas capital program and approximately $84 million related to its plant and pipeline capital. This estimate is under continuous review and subject to ongoing adjustments.
Financing Activities
See Item 7. “Management’s Discuss and Analysis of Financial Condition and Results of Operations” for a description of the Exit Facility entered into in February 2017.
During the year ended December 31, 2016, the Company borrowed approximately $979 million under the LINN Credit Facility (as defined in Note 6) and made repayments of approximately $1.8 billion of a portion of the borrowings outstanding under the LINN Credit Facility and term loan. The repayments include approximately $841 million in commodity derivative settlements paid by the counterparties to the lenders under the LINN Credit Facility. As of December 31, 2016, total borrowings outstanding (including outstanding letters of credit) under the LINN Credit Facility were approximately $1.9 billion, with no remaining availability. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a description of the amendment to the LINN Credit Facility entered into in April 2016. Pursuant to the terms of the LINN Plan, on the Effective Date, all obligations under the LINN Credit Facility were canceled.
Commodity Derivatives
During the year ended December 31, 2016, LINN Energy entered into commodity derivative contracts consisting of natural gas swaps for October 2016 through December 2019, oil swaps for November 2016 through December 2017, and oil collars for January 2018 through December 2019.
In April 2016 and May 2016, in connection with the Company’s restructuring efforts, LINN Energy canceled (prior to the contract settlement dates) all of its then-outstanding derivative contracts for net proceeds of approximately $1.2 billion. The net proceeds were used to make permanent repayments of a portion of the borrowings outstanding under the LINN Credit Facility.
Offer to Exchange LINN Energy Units for LinnCo Shares
In March 2016, LinnCo filed a Registration Statement on Form S-4 related to an offer to exchange each outstanding unit representing limited liability company interests of LINN Energy for one common share representing limited liability company interests of LinnCo. The initial offer expired on April 25, 2016, and on April 26, 2016, LinnCo commenced a subsequent offering period that expired on August 1, 2016. During the exchange period, 123,100,715 LINN Energy units were exchanged for an equal number of LinnCo shares. As a result of the exchanges of LINN Energy units for LinnCo shares, LinnCo’s ownership of LINN Energy’s outstanding units increased from approximately 37% at December 31, 2015, to approximately 71% at December 31, 2016. Pursuant to the terms of the LINN Plan, on the Effective Date, all outstanding units were extinguished without recovery.
Delisting from Stock Exchange
As a result of the Company’s failure to comply with the NASDAQ Global Select Market continued listing requirements, on May 24, 2016, the Company’s units began trading over the counter on the OTC Markets Group Inc.’s Pink marketplace under the trading symbol “LINEQ.” As a result of the cancellation of the units on the Effective Date, the units ceased to trade on the OTC Markets Group Inc.’s Pink Marketplace.
Operating Regions
The Company’s properties are located in eight operating regions in the U.S.:
• | Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; |
3
Item 1. Business - Continued
• | Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin) and North Dakota (Williston Basin); |
• | Mid-Continent, which includes Oklahoma properties located in the Anadarko and Arkoma basins, as well as waterfloods in the Central Oklahoma Platform; |
• | TexLa, which includes properties located in east Texas and north Louisiana; |
• | Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; |
• | California, which includes properties located in the San Joaquin Valley and Los Angeles basins; |
• | Permian Basin, which includes properties located in west Texas and southeast New Mexico; and |
• | South Texas. |
Hugoton Basin
The Hugoton Basin is a large oil and natural gas producing area located in southwest Kansas extending through the Oklahoma Panhandle into the central portion of the Texas Panhandle. The Company’s Kansas and Oklahoma Panhandle properties primarily produce from the Council Grove and Chase formations at depths ranging from 2,200 feet to 3,100 feet and its Texas properties in the basin primarily produce from the Brown Dolomite formation at depths ranging from 2,900 feet to 3,700 feet. The Company’s properties in this region are primarily mature, low-decline natural gas wells.
To more efficiently transport its natural gas in the Texas Panhandle to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 665 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. The Company also owns and operates the Jayhawk natural gas processing plant in southwest Kansas with a capacity of approximately 450 MMcf/d, allowing it to receive maximum value from the liquids-rich natural gas produced in the area. The Company’s production in the area is delivered to the plant via a system of approximately 3,930 miles of pipeline and related facilities operated by the Company, of which approximately 2,075 miles of pipeline are owned by the Company.
Hugoton Basin proved reserves represented approximately 29% of total proved reserves at December 31, 2016, all of which were classified as proved developed. This region produced approximately 180 MMcfe/d or 21% of the Company’s 2016 average daily production. During 2016, the Company invested approximately $1 million to develop the properties in this region.
Rockies
The Rockies region consists of properties located in Wyoming (Green River, Washakie and Powder River basins), northeast Utah (Uinta Basin) and North Dakota (Bakken and Three Forks formations in the Williston Basin). Wells in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 1,000 feet to 15,000 feet. The Company’s properties in the Jonah Field located in the Green River Basin of southwest Wyoming produce from the Lance and Mesaverde formations at depths ranging from 7,500 feet to 14,500 feet. The Company’s properties in the Washakie Basin produce at depths ranging from 7,500 feet to 11,500 feet. The Company’s properties in the Powder River Basin consist of a CO2 flood operated by Fleur de Lis Energy, LLC in the Salt Creek Field. The Company’s properties in the Uinta Basin produce at depths ranging from 5,500 feet to 15,000 feet. The Company’s nonoperated properties in the Williston Basin produce at depths ranging from 9,000 feet to 12,000 feet.
To more efficiently transport its natural gas in the Uinta Basin to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 95 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area.
Rockies proved reserves represented approximately 28% of total proved reserves at December 31, 2016, of which 85% were classified as proved developed. This region produced approximately 330 MMcfe/d or 40% of the Company’s 2016 average daily production. During 2016, the Company invested approximately $41 million to develop the properties in this region.
4
Item 1. Business - Continued
Mid-Continent
The Mid-Continent region consists of properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform. In December 2014, the Company completed the sale of its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma. The Company’s properties in this diverse region produce from both oil and natural gas reservoirs at depths ranging from 1,500 feet to 11,000 feet. As of December 31, 2016, the Company’s properties in this region are primarily mature, low-decline oil and natural gas wells.
Mid-Continent proved reserves represented approximately 15% of total proved reserves at December 31, 2016, of which 81% were classified as proved developed. This region produced approximately 101 MMcfe/d or 12% of the Company’s 2016 average daily production. During 2016, the Company invested approximately $31 million to develop the properties in this region and approximately $40 million in exploration activity.
TexLa
The TexLa region consists of properties located in east Texas and north Louisiana and primarily produces natural gas from the Cotton Valley, Travis Peak and Bossier Sand formations at depths ranging from 7,000 feet to 12,500 feet. Proved reserves for these mature, low-decline producing properties represented approximately 9% of total proved reserves at December 31, 2016, of which 95% were classified as proved developed. To more efficiently transport its natural gas in east Texas to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 635 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. This region produced approximately 72 MMcfe/d or 9% of the Company’s 2016 average daily production. During 2016, the Company invested approximately $9 million to develop the properties in this region.
Michigan/Illinois
The Michigan/Illinois region consists primarily of natural gas properties in the Antrim Shale formation in north Michigan and oil properties in south Illinois. These wells produce at depths ranging from 200 feet to 4,000 feet. Michigan/Illinois proved reserves represented approximately 8% of total proved reserves at December 31, 2016, all of which were classified as proved developed. To more efficiently transport its natural gas in Michigan to market, the Company owns and operates a network of natural gas gathering systems comprised of approximately 1,480 miles of pipeline and associated compression and metering facilities that connect to numerous sales outlets in the area. This region produced approximately 30 MMcfe/d or 4% of the Company’s 2016 average daily production. During 2016, the Company invested approximately $1 million to develop the properties in this region.
California
The California region consists of properties located in the South Belridge field in the San Joaquin Valley Basin and the Brea Olinda field in the Los Angeles Basin. The properties in the South Belridge field produce from the Tulare and Diatomite formations using waterflood and thermal enhanced oil recovery methods at depths ranging from 800 feet to 2,000 feet. The Brea Olinda Field was discovered in 1880 and produces from the shallow Pliocene formation to the deeper Miocene formation at depths ranging from 1,000 feet to 7,500 feet. The Company’s properties in this region are primarily mature, low-decline oil wells.
California proved reserves represented approximately 5% of total proved reserves at December 31, 2016, all of which were classified as proved developed. This region produced approximately 32 MMcfe/d or 4% of the Company’s 2016 average daily production. During 2016, the Company made no material investments to develop the properties in this region.
Permian Basin
The Company’s properties are located in west Texas and southeast New Mexico, primarily produce at depths ranging from 2,000 feet to 12,000 feet and are primarily mature, low-decline oil and natural gas wells including several waterflood properties located across the basin.
5
Item 1. Business - Continued
Permian Basin proved reserves represented approximately 4% of total proved reserves at December 31, 2016, all of which were classified as proved developed. This region produced approximately 56 MMcfe/d or 7% of the Company’s 2016 average daily production. During 2016, the Company invested approximately $1 million to develop the properties in this region.
South Texas
The South Texas region consists of a widely diverse set of oil and natural gas properties located in a large area extending from north Houston to the border of Mexico. These wells produce at depths ranging from 2,000 feet to 17,000 feet. Proved reserves for these mature properties, the majority of which are natural gas with associated NGL, represented approximately 2% of total proved reserves at December 31, 2016, all of which were classified as proved developed. This region produced approximately 27 MMcfe/d or 3% of the Company’s 2016 average daily production. During 2016, the Company invested approximately $2 million to develop the properties in this region.
Drilling and Acreage
The following table sets forth the wells drilled during the years indicated:
Year Ended December 31, | ||||||||
2016 | 2015 | 2014 | ||||||
Gross wells: | ||||||||
Productive | 211 | 388 | 506 | |||||
Dry | 1 | 5 | 1 | |||||
212 | 393 | 507 | ||||||
Net development wells: | ||||||||
Productive | 26 | 139 | 291 | |||||
Dry | — | 1 | 1 | |||||
26 | 140 | 292 | ||||||
Net exploratory wells: | ||||||||
Productive | 7 | 1 | — | |||||
Dry | — | 1 | — | |||||
7 | 2 | — | ||||||
The total wells above exclude 20, 196 and 411 gross wells (18, 163 and 407 net wells) drilled by Berry during the period from January 1, 2016 through December 3, 2016, and the years ended December 31, 2015, and December 31, 2014, respectively. There were no lateral segments added to existing vertical wellbores during the years ended December 31, 2016, or December 31, 2014. There were two lateral segments added to existing vertical wellbores during the year ended December 31, 2015. As of December 31, 2016, the Company had 63 gross (6 net) wells in progress (51 gross and 2 net wells were temporarily suspended).
This information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and the quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of oil, natural gas or NGL, regardless of whether they generate a reasonable rate of return.
6
Item 1. Business - Continued
The following table sets forth information about the Company’s drilling locations and net acres of leasehold interests as of December 31, 2016:
Total (1) | ||
Proved undeveloped | 119 | |
Other locations | 5,096 | |
Total drilling locations | 5,215 | |
Leasehold interests – net acres (in thousands) | 2,640 | |
(1) | Does not include optimization projects. |
As shown in the table above, as of December 31, 2016, the Company had 119 proved undeveloped drilling locations (specific drilling locations as to which the independent engineering firm, DeGolyer and MacNaughton, assigned proved undeveloped reserves as of such date) and the Company had identified 5,096 additional unproved drilling locations (specific drilling locations as to which DeGolyer and MacNaughton has not assigned any proved reserves) on acreage that the Company has under existing leases. Successful development wells frequently result in the reclassification of adjacent lease acreage from unproved to proved. The number of unproved drilling locations that will be reclassified as proved drilling locations will depend on the Company’s drilling program, its commitment to capital and commodity prices.
Productive Wells
The following table sets forth information relating to the productive wells in which the Company owned a working interest as of December 31, 2016. Productive wells consist of producing wells and wells capable of production, including wells awaiting pipeline or other connections to commence deliveries. The number of wells below does not include approximately 2,858 gross productive wells in which the Company owns a royalty interest only.
Natural Gas Wells | Oil Wells | Total Wells | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Operated (1) | 9,030 | 8,012 | 4,363 | 4,039 | 13,393 | 12,051 | |||||||||||
Nonoperated (2) | 7,065 | 2,299 | 2,700 | 308 | 9,765 | 2,607 | |||||||||||
16,095 | 10,311 | 7,063 | 4,347 | 23,158 | 14,658 | ||||||||||||
(1) | The Company had 89 operated wells with multiple completions at December 31, 2016. |
(2) | The Company had 2 nonoperated wells with multiple completions at December 31, 2016. |
Developed and Undeveloped Acreage
The following table sets forth information relating to leasehold acreage as of December 31, 2016:
Developed Acreage | Undeveloped Acreage | Total Acreage | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
(in thousands) | |||||||||||||||||
Leasehold acreage | 4,532 | 2,617 | 57 | 23 | 4,589 | 2,640 | |||||||||||
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Item 1. Business - Continued
Future Acreage Expirations
If production is not established or the Company takes no other action to extend the terms of the related leases, undeveloped acreage will expire over the next three years as follows:
2017 | 2018 | 2019 | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
(in thousands) | |||||||||||||||||
Leasehold acreage | 4 | 2 | 9 | 6 | 4 | 1 | |||||||||||
The Company’s investment in developed and undeveloped acreage comprises numerous leases. The terms and conditions under which the Company maintains exploration or production rights to the acreage are property-specific, contractually defined and vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration. In some instances, the Company may elect to relinquish acreage in advance of the contractual expiration date if the evaluation process is complete and there is not a business basis for extension. In cases where additional time may be required to fully evaluate acreage, the Company has generally been successful in obtaining extensions. The Company utilizes various methods to manage the expiration of leases, including drilling the acreage prior to lease expiration or extending lease terms.
Production, Price and Cost History
The results of operations of Berry are reported as discontinued operations for all periods presented (see Note 3). Unless otherwise indicated, information presented herein relates only to LINN Energy’s continuing operations.
The Company’s natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. The Company’s natural gas production is sold to purchasers under spot price contracts, percentage-of-index contracts or percentage-of-proceeds contracts. Under percentage-of-index contracts, the Company receives a price for natural gas and NGL based on indexes published for the producing area. Under percentage-of-proceeds contracts, the Company receives a percentage of the resale price received by the purchaser for sales of residual natural gas and NGL recovered after transportation and processing of natural gas. These purchasers sell the residual natural gas and NGL based primarily on spot market prices. Although exact percentages vary daily, as of December 31, 2016, approximately 90% of the Company’s natural gas and NGL production was sold under short-term contracts at market-sensitive or spot prices. In certain circumstances, the Company has entered into natural gas processing contracts whereby the residual natural gas is sold under short-term contracts but the related NGL are sold under long-term contracts. In all such cases, the residual natural gas and NGL are sold at market-sensitive index prices. As of December 31, 2016, the Company had no natural gas or NGL delivery commitments under long-term contracts.
The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area, and as of December 31, 2016, approximately 90% of its oil production was sold under short-term contracts. As of December 31, 2016, the Company had no oil delivery commitments under long-term contracts.
The Company’s natural gas is transported through its own and third-party gathering systems and pipelines. The Company incurs processing, gathering and transportation expenses to move its natural gas from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume, distance shipped and the fee charged by the third-party processor or transporter.
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Item 1. Business - Continued
The following table sets forth information regarding total production, average daily production, average prices and average costs for each of the years indicated:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
Total production: | |||||||||||
Natural gas (MMcf) | 187,068 | 200,488 | 179,670 | ||||||||
Oil (MBbls) | 10,047 | 11,819 | 13,212 | ||||||||
NGL (MBbls) | 9,297 | 9,365 | 11,569 | ||||||||
Total (MMcfe) | 303,134 | 327,587 | 328,353 | ||||||||
Average daily production: | |||||||||||
Natural gas (MMcf/d) | 511 | 549 | 492 | ||||||||
Oil (MBbls/d) | 27.5 | 32.4 | 36.2 | ||||||||
NGL (MBbls/d) | 25.4 | 25.7 | 31.7 | ||||||||
Total (MMcfe/d) | 828 | 897 | 900 | ||||||||
Weighted average prices: (1) | |||||||||||
Natural gas (Mcf) | $ | 2.28 | $ | 2.56 | $ | 4.28 | |||||
Oil (Bbl) | $ | 39.12 | $ | 44.00 | $ | 87.00 | |||||
NGL (Bbl) | $ | 14.28 | $ | 12.68 | $ | 34.07 | |||||
Average NYMEX prices: | |||||||||||
Natural gas (MMBtu) | $ | 2.46 | $ | 2.66 | $ | 4.41 | |||||
Oil (Bbl) | $ | 43.32 | $ | 48.80 | $ | 93.00 | |||||
Costs per Mcfe of production: | |||||||||||
Lease operating expenses | $ | 1.05 | $ | 1.15 | $ | 1.35 | |||||
Transportation expenses | $ | 0.53 | $ | 0.51 | $ | 0.50 | |||||
General and administrative expenses (2) | $ | 0.78 | $ | 0.87 | $ | 0.83 | |||||
Depreciation, depletion and amortization | $ | 1.33 | $ | 1.69 | $ | 2.35 | |||||
Taxes, other than income taxes | $ | 0.25 | $ | 0.34 | $ | 0.52 | |||||
Total production – discontinued operations: (3) | |||||||||||
Total (MMcfe) | 80,588 | 105,999 | 113,331 | ||||||||
(1) | Does not include the effect of gains (losses) on derivatives. |
(2) | General and administrative expenses for the years ended December 31, 2016, December 31, 2015, and December 31, 2014, include approximately $34 million, $47 million and $45 million, respectively, of noncash unit-based compensation expenses. In addition, general and administrative expenses for the years ended December 31, 2016, December 31, 2015, and December 31, 2014, include costs incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
(3) | Total production of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. |
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Item 1. Business - Continued
The following table sets forth information regarding production volumes for fields with greater than 15% of the Company’s total proved reserves for each of the years indicated:
Year Ended December 31, | ||||||||
2016 | 2015 | 2014 | ||||||
Total production: | ||||||||
Hugoton Basin Field: | ||||||||
Natural gas (MMcf) | 38,501 | 41,294 | 29,424 | |||||
Oil (MBbls) | 27 | 21 | 16 | |||||
NGL (MBbls) | 2,983 | 3,061 | 2,348 | |||||
Total (MMcfe) | 56,566 | 59,787 | 43,608 | |||||
Green River Basin Field: | ||||||||
Natural gas (MMcf) | 44,668 | * | * | |||||
Oil (MBbls) | 477 | * | * | |||||
NGL (MBbls) | 1,349 | * | * | |||||
Total (MMcfe) | 55,625 | * | * | |||||
* | Represented less than 15% of the Company’s total proved reserves for the year indicated. |
Reserve Data
Proved Reserves
The following table sets forth estimated proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows at December 31, 2016, based on reserve reports prepared by independent engineers, DeGolyer and MacNaughton:
Estimated proved developed reserves: | |||
Natural gas (Bcf) | 2,128 | ||
Oil (MMBbls) | 93 | ||
NGL (MMBbls) | 94 | ||
Total (Bcfe) | 3,254 | ||
Estimated proved undeveloped reserves: | |||
Natural gas (Bcf) | 172 | ||
Oil (MMBbls) | 6 | ||
NGL (MMBbls) | 10 | ||
Total (Bcfe) | 266 | ||
Estimated total proved reserves: | |||
Natural gas (Bcf) | 2,300 | ||
Oil (MMBbls) | 99 | ||
NGL (MMBbls) | 104 | ||
Total (Bcfe) | 3,520 | ||
Proved developed reserves as a percentage of total proved reserves | 92 | % | |
Standardized measure of discounted future net cash flows (in millions) (1) | $ | 1,929 | |
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Item 1. Business - Continued
Representative NYMEX prices: (2) | |||
Natural gas (MMBtu) | $ | 2.48 | |
Oil (Bbl) | $ | 42.64 | |
(1) | This measure is not intended to represent the market value of estimated reserves. |
(2) | In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. |
During the year ended December 31, 2016, the Company’s PUDs increased to 266 Bcfe from zero at December 31, 2015. As a result of the uncertainty regarding the Company’s future commitment to capital, the Company reclassified all of its PUDs to unproved at December 31, 2015. Based on the December 31, 2016 reserve reports, the amounts of capital expenditures estimated to be incurred in 2017, 2018 and 2019 to develop the Company’s PUDs are approximately $65 million, $60 million and $38 million, respectively. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs and product prices. None of the 266 Bcfe of PUDs at December 31, 2016, has remained undeveloped for five years or more. All PUD properties are included in the Company’s current five-year development plan.
Reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and NGL that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and NGL that are ultimately recovered. Future prices received for production may vary, perhaps significantly, from the prices assumed for the purposes of estimating the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows should not be construed as the market value of the reserves at the dates shown. The 10% discount factor required to be used under the provisions of applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry. The standardized measure of discounted future net cash flows is materially affected by assumptions regarding the timing of future production, which may prove to be inaccurate.
The reserve estimates reported herein were prepared by independent engineers, DeGolyer and MacNaughton. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data provided by the Company. When preparing the reserve estimates, the independent engineering firm did not independently verify the accuracy and completeness of the information and data furnished by the Company with respect to ownership interests, production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention that brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years. The independent engineering firm also prepared estimates with respect to reserve categorization, using the definitions of proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
The Company’s internal control over the preparation of reserve estimates is a process designed to provide reasonable assurance regarding the reliability of the Company’s reserve estimates in accordance with SEC regulations. The preparation of reserve estimates was overseen by the Company’s Corporate Reserves Manager, who has Master of Petroleum Engineering and Master of Business Administration degrees and more than 30 years of oil and natural gas industry experience. The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer. For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data.” The Company has not filed reserve estimates with any federal authority or agency, with the exception of the SEC.
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Item 1. Business - Continued
Operational Overview
General
The Company generally seeks to be the operator of its properties so that it can develop drilling programs and optimization projects intended to not only replace production, but add value through reserve and production growth and future operational synergies. Many of the Company’s wells are completed in multiple producing zones with commingled production and long economic lives.
Principal Customers
For the year ended December 31, 2016, no individual customer exceeded 10% of the Company’s sales of oil, natural gas and NGL. If the Company were to lose any one of its major oil and natural gas purchasers, the loss could temporarily cease or delay production and sale of its oil and natural gas in that particular purchaser’s service area. If the Company were to lose a purchaser, it believes it could identify a substitute purchaser. However, if one or more of the large purchasers ceased purchasing oil and natural gas altogether, it could have a detrimental effect on the oil and natural gas market in general and on the prices and volumes of oil, natural gas and NGL that the Company is able to sell.
Competition
The oil and natural gas industry is highly competitive. The Company encounters strong competition from other independent operators and master limited partnerships in acquiring properties, contracting for drilling and other related services, and securing trained personnel. The Company is also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. The Company is unable to predict when, or if, such shortages may occur or how they would affect its drilling program.
Operating Hazards and Insurance
The oil and natural gas industry involves a variety of operating hazards and risks that could result in substantial losses from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties, and suspension of operations. The Company may be liable for environmental damages caused by previous owners of property it purchases and leases. As a result, the Company may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate funds otherwise available, or result in the loss of properties. In addition, the Company participates in wells on a nonoperated basis and therefore may be limited in its ability to control the risks associated with the operation of such wells.
In accordance with customary industry practices, the Company maintains insurance against some, but not all, potential losses. The Company cannot provide assurance that any insurance it obtains will be adequate to cover any losses or liabilities. The Company has elected to self-insure for certain items for which it has determined 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 not fully covered by insurance could have a material adverse effect on the Company’s financial position, results of operations and cash flows. For more information about potential risks that could affect the Company, see Item 1A. “Risk Factors.”
Title to Properties
Prior to the commencement of drilling operations, the Company conducts a title examination and performs curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, the Company is typically responsible for curing any title defects at its expense prior to commencing drilling operations. Prior to completing an acquisition of producing leases, the Company performs title reviews on the most significant leases and, depending on the materiality of properties, the Company may obtain a title opinion or review previously obtained title opinions. As a result, the Company has obtained title opinions on a significant portion of its properties and believes that it has satisfactory title to its producing properties in accordance with standards generally accepted in the industry.
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Item 1. Business - Continued
Seasonal Nature of Business
Seasonal weather conditions and lease stipulations can limit the drilling and producing activities and other operations in regions of the U.S. in which the Company operates. These seasonal conditions can pose challenges for meeting the well drilling objectives and increase competition for equipment, supplies and personnel, which could lead to shortages and increase costs or delay operations. For example, Company operations may be impacted by ice and snow in the winter and by electrical storms and high temperatures in the spring and summer, as well as by wild fires in the fall.
The demand for natural gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies sometimes lessen this fluctuation. In addition, certain natural gas consumers utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can also lessen seasonal demand fluctuations.
Environmental Matters and Regulation
The Company’s operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company’s operations are subject to the same environmental laws and regulations as other companies in the oil and natural gas industry. These laws and regulations may:
• | require the acquisition of various permits before drilling commences; |
• | require notice to stakeholders of proposed and ongoing operations; |
• | require the installation of expensive pollution control equipment; |
• | restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities; |
• | limit or prohibit drilling activities on lands located within wilderness, wetlands, areas inhabited by endangered species and other protected areas; |
• | require remedial measures to prevent pollution from former operations, such as pit closure, reclamation and plugging and abandonment of wells; |
• | impose substantial liabilities for pollution resulting from operations; and |
• | require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement with respect to operations affecting federal lands or leases. |
These laws, rules and regulations may also restrict the production rate of oil, natural gas and NGL below the rate that would otherwise be possible. The regulatory burden on the industry increases the cost of doing business and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on operating costs.
The environmental laws and regulations applicable to the Company and its operations include, among others, the following U.S. federal laws and regulations:
• | Clean Air Act (“CAA”), and its amendments, which governs air emissions; |
• | Clean Water Act (“CWA”), which governs discharges to and excavations within the waters of the U.S.; |
• | Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), which imposes liability where hazardous releases have occurred or are threatened to occur (commonly known as “Superfund”); |
• | The Oil Pollution Act of 1990, which amends and augments the CWA and imposes certain duties and liabilities related to the prevention of oil spills and damages resulting from such spills; |
• | Energy Independence and Security Act of 2007, which prescribes new fuel economy standards and other energy saving measures; |
• | National Environmental Policy Act (“NEPA”), which governs oil and natural gas production activities on federal lands; |
• | Resource Conservation and Recovery Act (“RCRA”), which governs the management of solid waste; |
• | Safe Drinking Water Act (“SDWA”), which governs the underground injection and disposal of wastewater; and |
• | U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages. |
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Item 1. Business - Continued
Various states regulate the drilling for, and the production, gathering and sale of, oil, natural gas and NGL, including imposing production taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of resources. States may regulate rates of production and may establish maximum daily production allowables from wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulations, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil, natural gas and NGL that may be produced from the Company’s wells and to limit the number of wells or locations it can drill. The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal opportunity employment.
The Company believes that it substantially complies with all current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its business, financial condition, results of operations or cash flows. Future regulatory issues that could impact the Company include new rules or legislation relating to the items discussed below.
Climate Change
In December 2009, the Environmental Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the CAA. The EPA has adopted three sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles, a second that regulates emissions of GHGs from certain large stationary sources under the CAA’s Prevention of Significant Deterioration and Title V permitting programs, and a third that regulates GHG emissions from fossil fuel-burning power plants. In September 2015, the EPA published a proposed rule that would update and expand the New Source Performance Standards (“NSPS”) by setting additional emissions limits for volatile organic compounds and regulating methane emissions from new and modified sources in the oil and gas industry. In May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among other things, certain onshore oil and natural gas production facilities, on an annual basis. In addition, in 2015, the U.S. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. Legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the U.S. At the state level, almost one half of the states, including California, have begun taking actions to control and/or reduce emissions of GHGs. See “California GHG Regulations” below for additional details on current GHG regulations in the state of California.
Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause the Company to incur significant costs in preparing for or responding to those effects.
California GHG Regulations
In October 2006, California adopted the Global Warming Solutions Act of 2006 (“Assembly Bill 32”), which established a statewide “cap and trade” program with an enforceable compliance obligation beginning with 2013 GHG emissions. The program is designed to reduce the state’s GHG emissions to 1990 levels by 2020. Assembly Bill 32 sets maximum limits or caps on total emissions of GHGs from industrial sectors of which the Company is a part, as its California operations emit GHGs. The cap will decline annually through 2020. The Company is required to remit compliance instruments for each metric ton of GHG that it emits, in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. Under Assembly Bill 32, the Company will be granted a certain number of
14
Item 1. Business - Continued
California carbon allowances (“CCA”) and the Company will need to purchase CCAs and/or offset credits to cover the remaining amount of its emissions. Compliance with Assembly Bill 32 could significantly increase the Company’s capital, compliance and operating costs and could also reduce demand for the oil and natural gas the Company produces. The cost to acquire compliance instruments will depend on the market price for such instruments at the time they are purchased, the distribution of cost-free allowances among various industry sectors by the California Air Resources Board and the Company’s ability to limit its GHG emissions and implement cost-containment measures. The cap and trade program is currently scheduled to be in effect through 2020, although it may be continued thereafter.
Hydraulic Fracturing
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and natural gas regulatory programs. However, on May 9, 2014, the EPA announced an advance notice of proposed rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and natural gas exploration or production. Further, in March 2015, the Department of the Interior’s Bureau of Land Management (“BLM”) adopted a rule requiring, among other things, public disclosure to the BLM of chemicals used in hydraulic fracturing operations after fracturing operations have been completed and would strengthen standards for well-bore integrity and management of fluids that return to the surface during and after fracturing operations on federal and Indian lands. In June 2016, a federal district judge in Wyoming, in litigation pursued by several states, industry associations and an Indian tribe struck down BLM’s enforcement of the new rule; the decision was appealed by BLM and the matter remains pending before the U.S. Court of Appeals for the Tenth Circuit. In addition, legislation has been introduced before Congress that would provide for federal regulation of hydraulic fracturing and would require disclosure of the chemicals used in the fracturing process. If enacted, these or similar bills could result in additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites and also increased costs to make wells productive.
There may be other attempts to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act and/or other regulatory mechanisms. The Interagency Working Group on Unconventional Natural Gas and Oil was created by Executive Order on April 13, 2012, and is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources. In December 2016, the EPA released its final report on a wide ranging study on the effects of hydraulic fracturing resources. While no widespread impacts from hydraulic fracturing were found, the EPA identified a number of activities and factors that may have increased risk for future impacts. Moreover, some states and local governments have adopted, and other states and local governments are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, many states in which we operate have adopted disclosure regulations requiring varying degrees of disclosure of the constituents in hydraulic fracturing fluids. In addition, the regulation or prohibition of hydraulic fracturing is the subject of significant political activity in a number of jurisdictions, some of which have resulted in tighter regulation (including, most recently, new regulations in California requiring a permit to conduct well stimulation), bans, and/or recognition of local government authority to implement such restrictions. In many instances, litigation has ensued, some of which remains pending. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for the Company to perform fracturing to stimulate production from tight formations. In addition, any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect the Company’s revenues, results of operations and net cash provided by operating activities.
The Company uses a significant amount of water in its hydraulic fracturing operations. The Company’s inability to locate sufficient amounts of water, or dispose of or recycle water used in its drilling and production operations, could adversely impact its operations. Moreover, new environmental initiatives and regulations could include restrictions on the Company’s 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 development or production of natural gas.
Finally, in some instances, the operation of underground injection wells has been alleged to cause earthquakes in some of the states where we operate. Such issues have sometimes led to orders prohibiting continued injection in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some
15
Item 1. Business - Continued
jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect the Company, either directly or indirectly, depending on the wells affected.
Solid and Hazardous Waste
Although oil and natural gas wastes generally are exempt from regulation as hazardous wastes under the federal Resource Conservation and Recovery Act (“RCRA”) and some comparable state statutes, it is possible some wastes the Company generates presently or in the future may be subject to regulation under the RCRA or other applicable statutes. The EPA and various state agencies have limited the disposal options for certain wastes, including hazardous wastes and there is no guarantee that the EPA or the states will not adopt more stringent requirements in the future. For example, in May 2016, several environmental groups filed a lawsuit in the U.S. District Court for the District of Columbia that seeks to compel the EPA to review and, if necessary, revise its regulations regarding existing exemptions for exploration and production related wastes. Furthermore, certain wastes generated by the Company’s oil and natural gas operations that are currently exempt from designation as hazardous wastes may in the future be designated as hazardous wastes under the RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements.
Endangered Species Act
The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered and threatened species or their habitats. Some of the Company’s operations may be located in areas that are designated as habitats for endangered or threatened species. In February 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, the U.S. Fish and Wildlife Service continues its six-year effort to make listing decisions and critical habitat designations where necessary for over 250 species before the end of the agency’s 2017 fiscal year, as required under a 2011 settlement approved by the U.S. District Court for the District of Columbia, and many hundreds of additional anticipated listing decisions have already been identified beyond those recognized in the 2011 settlement. The Company believes that it is currently in substantial compliance with the ESA. However, the designation of previously unprotected species as being endangered or threatened could cause the Company to incur additional costs or become subject to operating restrictions in areas where the species are known to exist.
Air Emissions
In August 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. These standards require operators to capture the gas from natural gas well completions and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and existing wells that are refractured. Further, the finalized regulations also establish specific new requirements for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. The EPA amended these rules in December 2014 to specify requirements for different flowback stages and to expand the rules to cover more storage vessels, among other changes. These rules may require changes to the Company’s operations, including the installation of new equipment to control emissions.
The Company’s costs for environmental compliance may increase in the future based on new environmental regulations. In November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands. Several states are pursuing similar measures to regulate emissions of methane from new and existing sources within the oil and natural gas source category. In addition, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. The EPA has also adopted new rules under the CAA that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-
16
Item 1. Business - Continued
related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase the Company’s costs of development, which costs could be significant.
Water Resources
The CWA and analogous state laws restrict the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the U.S., a term broadly defined to include, among other things, certain wetlands. Under the CWA, permits must be obtained for the discharge of pollutants into waters of the U.S. The CWA provides for administrative, civil and criminal penalties for unauthorized discharges, both routine and accidental, of pollutants and of oil and hazardous substances. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require permits to discharge storm water runoff, including discharges associated with construction activities. The CWA also prohibits the discharge of fill materials to regulated waters including wetlands without a permit. In addition, the EPA and the Army Corps of Engineers (“Corps”) released a rule to revise the definition of “waters of the United States” (“WOTUS”) for all CWA programs, which went into effect in August 2015. In October 2015, the U.S. Court of Appeals for the Sixth Circuit stayed the WOTUS rule nationwide pending further action of the court. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Those regulations will be implemented as they were prior to the effective date of the new WOTUS rule. The WOTUS rule could significantly expand federal control of land and water resources across the U.S., triggering substantial additional permitting and regulatory requirements.
Also, in August 2016, the EPA finalized new wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works, permitting several years until compliance will be enforced. This pending restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.
Natural Gas Sales and Transportation
Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. The Company believes that the natural gas pipelines in its 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, but the status of these lines has never been challenged before FERC. The distinction between FERC-regulated transmission services and federally unregulated gathering services is subject to change based on future determinations by FERC, the courts, or Congress, and application of existing FERC policies to individual factual circumstances. Accordingly, the classification and regulation of some of the Company’s natural gas gathering facilities may be subject to challenge before FERC or subject to change based on future determinations by FERC, the courts, or Congress. In the event the Company’s gathering facilities are reclassified to FERC-regulated transmission services, it may be required to charge lower rates and its revenues could thereby be reduced.
FERC requires certain participants in the natural gas market, including natural gas gatherers and marketers which engage in a minimum level of natural gas sales or purchases, to submit annual reports regarding those transactions to FERC. Should the Company fail to comply with this requirement or any other applicable FERC-administered statute, rule, regulation or order, it could be subject to substantial penalties and fines.
Pipeline Safety Regulations
The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates safety of oil and natural gas pipelines, including, with some specific exceptions, oil and natural gas gathering lines. From time to time, PHMSA, the courts, or Congress may make determinations that affect PHMSA’s regulations or their applicability to the Company’s pipelines. These determinations may affect the costs the Company incurs in complying with applicable safety regulations.
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Item 1. Business - Continued
Worker Safety
The Occupational Safety and Health Act (“OSHA”) and 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 the Company’s operations. Failure to comply with OSHA requirements can lead to the imposition of penalties. In December 2015, the U.S. Departments of Justice and Labor announced a plan to more frequently and effectively prosecute worker health and safety violations, including enhanced penalties.
Future Impacts and Current Expenditures
The Company cannot predict how future environmental laws and regulations may impact its properties or operations. For the year ended December 31, 2016, the Company did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of its facilities. The Company is not aware of any environmental issues or claims that will require material capital expenditures during 2017 or that will otherwise have a material impact on its financial position, results of operations or cash flows.
Employees
As of December 31, 2016, the Company employed approximately 1,500 personnel. None of the employees are represented by labor unions or covered by any collective bargaining agreement. The Company believes that its relationship with its employees is satisfactory.
Principal Executive Offices
The Company is a Delaware corporation with headquarters in Houston, Texas. The principal executive offices are located at 600 Travis, Houston, Texas 77002. The main telephone number is (281) 840-4000.
Available Information
The Company’s internet website is www.linnenergy.com. The Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to these reports are available free of charge on or through its website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. Information on the Company’s website should not be considered a part of, or incorporated by reference into, this Annual Report on Form 10‑K.
The SEC maintains an internet website that contains these reports at www.sec.gov. Any materials that the Company files with the SEC may be read or copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.
Cautionary Statement Regarding Forward-Looking Statements
This Annual Report on Form 10-K contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond the Company’s control. These statements may include discussions about the Company’s:
• | business strategy; |
• | acquisition strategy; |
• | financial strategy; |
• | new capital structure and the future adoption of fresh start accounting; |
• | uncertainty of the Company’s ability to improve its financial results and profitability following emergence from bankruptcy and other risks and uncertainties related to the Company’s emergence from bankruptcy; |
• | inability to maintain relationships with suppliers, customers, employees and other third parties following emergence from bankruptcy; |
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Item 1. Business - Continued
• | failure to satisfy the Company’s short- or long-term liquidity needs, including its inability to generate sufficient cash flow from operations or to obtain adequate financing to fund its capital expenditures and meet working capital needs following emergence from bankruptcy; |
• | large or multiple customer defaults on contractual obligations, including defaults resulting from actual or potential insolvencies; |
• | ability to comply with covenants under the Exit Facility; |
• | effects of legal proceedings; |
• | drilling locations; |
• | oil, natural gas and NGL reserves; |
• | realized oil, natural gas and NGL prices; |
• | production volumes; |
• | capital expenditures; |
• | economic and competitive advantages; |
• | credit and capital market conditions; |
• | regulatory changes; |
• | lease operating expenses, general and administrative expenses and development costs; |
• | future operating results, including results of acquired properties; |
• | plans, objectives, expectations and intentions; and |
• | taxes. |
All of these types of statements, other than statements of historical fact included in this Annual Report on Form 10-K, are forward-looking statements. These forward-looking statements may be found in Item 1. “Business;” Item 1A. “Risk Factors;” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other items within this Annual Report on Form 10-K. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.
The forward-looking statements contained in this Annual Report on Form 10-K are largely based on Company expectations, which reflect estimates and assumptions made by Company management. These estimates and assumptions reflect management’s best judgment based on currently known market conditions and other factors. Although the Company believes such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond its control. In addition, management’s assumptions may prove to be inaccurate. The Company cautions that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and it cannot assure any reader that such statements will be realized or the events will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements due to factors set forth in Item 1A. “Risk Factors” and elsewhere in this Annual Report on Form 10-K. The forward-looking statements speak only as of the date made and, other than as required by law, the Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
Item 1A. Risk Factors
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our shares are described below. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
Risks Related to Emergence from Bankruptcy
We recently emerged from bankruptcy, which could adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our recent emergence from the bankruptcy could adversely affect our business and relationships with customers, vendors, royalty and working interest owners, employees, service providers and suppliers. Due to uncertainties, many risks exist, including the following:
• | vendors or other contract counterparties could terminate their relationship or require financial assurances or enhanced performance; |
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Item 1A. Risk Factors - Continued
• | the ability to renew existing contracts and compete for new business may be adversely affected; |
• | the ability to attract, motivate and/or retain key executives and employees may be adversely affected; |
• | employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and |
• | competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted. |
The occurrence of one or more of these events could adversely affect our business, operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our actual financial results after emergence from bankruptcy may not reflect historical trends.
In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the LINN Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the LINN Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on those projections.
In addition, upon our emergence from bankruptcy, we will adopt fresh start accounting and, as a result, our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our historical consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends. The lack of comparable historical financial information may discourage investors from purchasing our common stock.
Upon our emergence from bankruptcy, the composition of the Board of Directors changed significantly.
Pursuant to the LINN Plan, the composition of the Board of Directors changed significantly. Upon emergence, our Board of Directors will consist of seven directors, none of which, except for Mark E. Ellis, our President and Chief Executive Officer, previously served on the Board of Directors of the Predecessor. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board of Directors and, thus, may have different views on the issues that will determine the future of the Company. There is no guarantee that the new Board of Directors will pursue, or will pursue in the same manner, strategic plans consistent with those of the Predecessor. As a result, the future strategy and plans of the Company may differ materially from those of the past.
The ability of the new directors to quickly expand their knowledge of our business plans, operations and strategies in a timely manner will be critical to their ability to make informed decisions about Company strategy and operations. If our Board of Directors is not sufficiently informed to make such decisions, our ability to compete effectively and profitably could be adversely affected.
The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.
The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.
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Item 1A. Risk Factors - Continued
Business Risks
Commodity prices are volatile, and prolonged depressed prices or a further decline in prices would reduce our revenues, profitability and net cash provided by operating activities and would significantly affect our financial condition and results of operations.
Our revenues, profitability, cash flow and the carrying value of our properties depend on the prices of and demand for oil, natural gas and NGL. Historically, the oil, natural gas and NGL markets have been very volatile and are expected to continue to be volatile in the future, and prolonged depressed prices or a further decline in prices will significantly affect our financial results and impede our growth. Changes in oil, natural gas and NGL prices have a significant impact on the value of our reserves and on our net cash provided by operating activities. In addition, revenues from certain wells may exceed production costs and nevertheless not generate sufficient return on capital. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for them, market uncertainty and a variety of additional factors that are beyond our control, such as:
• | the domestic and foreign supply of and demand for oil, natural gas and NGL; |
• | the price and level of foreign imports; |
• | the level of consumer product demand; |
• | weather conditions; |
• | overall domestic and global economic conditions; |
• | political and economic conditions in oil and natural gas producing countries; |
• | the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain price and production controls; |
• | the impact of the U.S. dollar exchange rates on oil, natural gas and NGL prices; |
• | technological advances affecting energy consumption; |
• | domestic and foreign governmental regulations and taxation; |
• | the impact of energy conservation efforts; |
• | the proximity and capacity of pipelines and other transportation facilities; and |
• | the price and availability of alternative fuels. |
Prolonged depressed prices or a further decline in prices would reduce our revenues, profitability and net cash provided by operating activities and would significantly affect our financial condition and results of operations.
The sustained oil, natural gas and NGL price declines have resulted in significant impairments of certain of our properties. Future declines in commodity prices, changes in expected capital development, increases in operating costs or adverse changes in well performance may result in additional write-downs of the carrying amounts of our assets, which could materially and adversely affect our results of operations in the period incurred.
We evaluate the impairment of our oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. For the year ended December 31, 2016, we recorded noncash impairment charges of approximately $165 million. Future declines in oil, natural gas and NGL prices, changes in expected capital development, increases in operating costs or adverse changes in well performance, among other things, may result in us having to make additional material write-downs of the carrying amounts of our assets, which could materially and adversely affect our results of operations in the period incurred.
Disruptions in the capital and credit markets, continued low commodity prices and other factors may restrict our ability to raise capital on favorable terms, or at all.
Disruptions in the capital and credit markets, in particular with respect to companies in the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. Continued low commodity prices, among other factors, have caused some lenders to increase interest rates, enact tighter lending standards which we may not satisfy, and in certain instances have reduced or ceased to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms or at all, it could adversely affect our business and financial condition.
21
Item 1A. Risk Factors - Continued
We may not be able to obtain funding under the Exit Facility because of a decrease in our borrowing base, or obtain new financing, which could adversely affect our operations and financial condition.
Historically, the Predecessor relied on borrowings under the Sixth Amended and Restated Credit Agreement (the “LINN Credit Facility”) to meet a portion of its capital needs. Pursuant to the LINN Plan, the LINN Credit Facility was paid down in part and replaced by the Credit Agreement (“Exit Facility”) entered into in connection with the reorganization, which consists of a new reserve-based revolving loan with up to $1.4 billion in borrowing commitments and a new term loan in an original principal amount of $300 million. The initial borrowing base is subject to redetermination on April 1, 2018, and semiannual borrowing base redeterminations thereafter and may also be subject to certain additional redeterminations triggered by certain asset sales, casualty events, acquisitions, debt issuances and hedge terminations. Any reduction in the borrowing base will reduce our available liquidity, and, if the reduction results in the outstanding amount under the Exit Facility exceeding the borrowing base, we will be required to repay the deficiency. We may not have the financial resources in the future to make any mandatory deficiency principal prepayments required under the Exit Facility, which could result in an event of default.
In the future, we may not be able to access adequate funding under the Exit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. Since the process for determining the borrowing base under the Exit Facility involves evaluating the estimated value of some of our oil and natural gas properties using pricing models determined by the lenders at that time, a decline in those prices used, or further downward reductions of our reserves, likely will result in a redetermination of our borrowing base and a decrease in the available borrowing amount at the time of the next scheduled redetermination. In such case, we would be required to repay any indebtedness in excess of the borrowing base.
Our Exit Facility also restricts our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If net cash provided by operating activities or cash available under our Exit Facility is not sufficient to meet our capital requirements, the failure to obtain such additional debt or equity financing could result in a curtailment of our development operations, which in turn could lead to a decline in our reserves.
We may be unable to maintain compliance with the financial maintenance or other covenants in the Exit Facility, which could result in an event of default under the Exit Facility that, if not cured or waived, would have a material adverse effect on our business and financial condition.
Under the Exit Facility, we are required to maintain certain financial covenants including the maintenance of (i) an asset coverage ratio of at least 1.1 to 1.0, tested on (a) the date of each scheduled borrowing base redetermination commencing with the first scheduled borrowing base redetermination and (b) the date of each additional borrowing base redetermination done in conjunction with an asset sale and (ii) a maximum total net debt to last twelve months EBITDAX ratio of 6.75 to 1.0 for March 31, 2018 through December 31, 2018, 6.5 to 1.0 for March 31, 2019 through March 31, 2020, and 4.5 to 1.0 thereafter.
If we were to violate any of the covenants under the Exit Facility and were unable to obtain a waiver or amendment, it would be considered a default after the expiration of any applicable grace period. If we were in default under the Exit Facility, then the lenders may exercise certain remedies including, among others, declaring all outstanding borrowings immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due.
Restrictive covenants in the Exit Facility could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Restrictive covenants in the Exit Facility impose significant operating and financial restrictions on us and our subsidiaries. These restrictions limit our ability to, among other things:
• | incur additional indebtedness; |
• | incur additional liens; |
• | enter into sale and lease-back transactions; |
22
Item 1A. Risk Factors - Continued
• | make certain investments; |
• | make certain capital expenditures; |
• | consolidate, merge, sell, or otherwise dispose of all or substantially all of our assets; |
• | pay dividends or make other distributions or repurchase or redeem our stock; |
• | enter into transactions with our affiliates; |
• | engage or enter into any new lines of business; |
• | enter into certain marketing activities for hydrocarbons; |
• | create additional subsidiaries; |
• | prepay, redeem, or repurchase certain of our indebtedness; and |
• | amend or modify certain provisions of our organizational documents. |
The Exit Facility also requires us to comply with certain financial maintenance covenants as discussed above. A breach of any of these covenants could result in a default under our Exit Facility. If a default occurs and remains uncured or unwaived, the administrative agent or majority lenders under the Exit Facility may elect to declare all borrowings outstanding thereunder, together with accrued interest and other fees, to be immediately due and payable. The administrative agent or majority lenders under the Exit Facility would also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay our indebtedness when due or declared due, the administrative agent will also have the right to proceed against the collateral pledged to it to secure the indebtedness under the Exit Facility. If such indebtedness were to be accelerated, our assets may not be sufficient to repay in full our secured indebtedness.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants in the Exit Facility. The restrictions contained in the Exit Facility could:
• | limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise restrict our activities or business plan; and |
• | adversely affect our ability to finance our operations, enter into acquisitions or to engage in other business activities that would be in our interest. |
Our commodity derivative activities could result in financial losses or could reduce our income, which may adversely affect our net cash provided by operating activities, financial condition and results of operations.
To achieve more predictable net cash provided by operating activities and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we have entered into commodity derivative contracts for a portion of our production. Commodity derivative arrangements expose us to the risk of financial loss in some circumstances, including situations when production is less than expected. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the sale of our underlying physical commodity, which may adversely affect our net cash provided by operating activities, financial condition and results of operations.
We may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.
While we have hedged a portion of our estimated production for 2017, 2018 and 2019, our anticipated production volumes remain mostly unhedged. Based on current expectations for future commodity prices, reduced hedging market liquidity and potential reduced counterparty willingness to enter into new hedges with us, we may be unable to hedge anticipated production volumes on attractive terms or at all, which would subject us to further potential commodity price uncertainty and could adversely affect our net cash provided by operating activities, financial condition and results of operations.
Counterparty failure may adversely affect our derivative positions.
We cannot be assured that our counterparties will be able to perform under our derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, our net cash provided by operating activities, financial condition and results of operations would be adversely affected.
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Item 1A. Risk Factors - Continued
Unless we replace our reserves, our future reserves and production will decline, which would adversely affect our net cash provided by operating activities, financial condition and results of operations.
Producing oil, natural gas and NGL reservoirs are characterized by declining production rates that vary depending on reservoir characteristics and other factors. The overall rate of decline for our production will change if production from our existing wells declines in a different manner than we have estimated and may change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future oil, natural gas and NGL reserves and production and, therefore, our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our net cash provided by operating activities, financial condition and results of operations. In addition, given restrictive covenants under our Exit Facility and general market conditions, we may be unable to finance potential acquisitions of reserves on terms that are acceptable to us or at all. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.
Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
No one can measure underground accumulations of oil, natural gas and NGL in an exact manner. Reserve engineering requires subjective estimates of underground accumulations of oil, natural gas and NGL and assumptions concerning future oil, natural gas and NGL prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. An independent petroleum engineering firm prepares estimates of our proved reserves. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future oil, natural gas and NGL prices, production levels and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual amounts could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and NGL attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. Decreases in commodity prices can result in a reduction of our estimated reserves if development of those reserves would not be economic at those lower prices. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil, natural gas and NGL we ultimately recover being different from our reserve estimates.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated oil, natural gas and NGL reserves. We base the estimated discounted future net cash flows from our proved reserves on an unweighted average of the first-day-of-the month price for each month during the 12-month calendar year and year-end costs. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:
• | actual prices we receive for oil, natural gas and NGL; |
• | the amount and timing of actual production; |
• | capital and operating expenditures; |
• | the timing and success of development activities; |
• | supply of and demand for oil, natural gas and NGL; and |
• | changes in governmental regulations or taxation. |
In addition, the 10% discount factor required to be used under the provisions of applicable accounting standards when calculating discounted future net cash flows, 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.
24
Item 1A. Risk Factors - Continued
Our development operations require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could adversely affect our ability to sustain our operations at current levels and could lead to a decline in our reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development and production of oil, natural gas and NGL reserves. These expenditures will reduce our cash available for other purposes. Our net cash provided by operating activities and access to capital are subject to a number of variables, including:
• | our proved reserves; |
• | the level of oil, natural gas and NGL we are able to produce from existing wells; |
• | the prices at which we are able to sell our oil, natural gas and NGL; |
• | the level of operating expenses; and |
• | our ability to acquire, locate and produce new reserves. |
If our net cash provided by operating activities decreases, we may have limited ability to obtain the capital or financing necessary to sustain our operations at current levels and could lead to a decline in our reserves.
We may decide not to drill some of the prospects we have identified, and locations that we decide to drill may not yield oil, natural gas and NGL in commercially viable quantities.
Our prospective drilling locations are in various stages of evaluation, ranging from a prospect that is ready to drill to a prospect that will require additional geological and engineering analysis. Based on a variety of factors, including future oil, natural gas and NGL prices, the generation of additional seismic or geological information, the current and future availability of drilling rigs and other factors, we may decide not to drill one or more of these prospects. In addition, the cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomic if we drill dry holes or wells that are productive but do not produce enough oil, natural gas and NGL to be commercially viable after drilling, operating and other costs. As a result, we may not be able to increase or sustain our reserves or production, which in turn could have an adverse effect on our business, financial condition, results of operations and cash flows.
Drilling for and producing oil, natural gas and NGL are high risk activities with many uncertainties that could adversely affect our financial position, results of operations and cash flows.
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil, natural gas and NGL can be uneconomic, not only from dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
• | the high cost, shortages or delivery delays of equipment and services; |
• | unexpected operational events; |
• | adverse weather conditions; |
• | facility or equipment malfunctions; |
• | title problems; |
• | pipeline ruptures or spills; |
• | compliance with environmental and other governmental requirements; |
• | unusual or unexpected geological formations; |
• | loss of drilling fluid circulation; |
• | formations with abnormal pressures; |
• | fires; |
• | blowouts, craterings and explosions; and |
• | uncontrollable flows of oil, natural gas and NGL or well fluids. |
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Item 1A. Risk Factors - Continued
Any of these events can cause increased costs or restrict our ability to drill the wells and conduct the operations which we currently have planned. Any delay in the drilling program or significant increase in costs could adversely affect our financial position, results of operations and cash flows.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. As of December 31, 2016, nonoperated wells represented approximately 42% of our owned gross wells, or approximately 18% of our owned net wells. We have limited ability to influence or control the operation or future development of these nonoperated properties, including timing of drilling and other scheduled operations activities, compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues, and lead to unexpected future costs.
Our business depends on gathering and transportation facilities. Any limitation in the availability of those facilities would interfere with our ability to market the oil, natural gas and NGL we produce, which could adversely affect our business, results of operations and cash flows.
The marketability of our oil, natural gas and NGL production depends in part on the availability, proximity and capacity of gathering systems and pipelines. The amount of oil, natural gas and NGL that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell the oil, natural gas and NGL production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering and transportation facilities, would interfere with our ability to market the oil, natural gas and NGL we produce, and could adversely affect our business, results of operations and cash flows.
Regulatory Risks
Because we handle oil, natural gas and NGL and other hydrocarbons, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.
The operations of our wells, gathering systems, turbines, pipelines and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. There is an inherent risk that we may incur environmental costs and liabilities due to the nature of our business, the substances we handle and the ownership or operation of our properties. Certain environmental statutes, including the RCRA, CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. In addition, an accidental release from one of our wells or gathering pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations.
Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary, and these costs may not be recoverable from insurance. For a more detailed discussion of environmental and regulatory matters impacting our business, see Item 1. “Business – Environmental Matters and Regulation.”
26
Item 1A. Risk Factors - Continued
We are subject to complex and evolving federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Our operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have resulted in delays and increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.
Part of the regulatory environment in which we operate includes, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil, natural gas and NGL we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect our financial condition and results of operations. For a description of the laws and regulations that affect us, see Item 1. “Business – Environmental Matters and Regulation.”
We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine emissions, greenhouse gases and hydraulic fracturing. Changes in environmental laws and regulations occur frequently, and any changes that result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management, or completion activities or waste handling, storage, transport, remediation or disposal, emission or discharge requirements could require significant expenditures by us or other operators of the properties to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations or financial condition. Increased scrutiny of the oil and natural gas industry may occur as a result of the EPA’s FY2017‑2019 National Enforcement Initiatives, through which the EPA will purportedly 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.
Legislation and regulation of hydraulic fracturing, including with respect to seismic activity allegedly related to hydraulic fracturing, could adversely affect our business.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. For a description of the laws and regulations that affect us, including our hydraulic fracturing operations, see Item 1. “Business – Environmental Matters and Regulation.” If adopted, certain bills could result in additional permitting and disclosure requirements for hydraulic fracturing operations as well as various restrictions on those operations. Any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect our business, financial position, results of operations and net cash provided by operating activities.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our drilling and production operations, could adversely impact our operations. Moreover, 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 development or production of natural gas.
Finally, in some instances, the operation of underground injection wells has been alleged to cause earthquakes in some of the states where we operate. Such issues have sometimes led to orders prohibiting continued injection in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Future orders or regulations addressing concerns about seismic activity from well injection could affect us, either directly or indirectly, depending on the wells affected.
27
Item 1A. Risk Factors - Continued
Legislation and regulation of greenhouse gases could adversely affect our business.
In December 2009, the Environmental Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHG”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA began adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). The EPA has adopted three sets of rules regulating GHG emissions under the CAA, one that requires a reduction in emissions of GHGs from motor vehicles, a second that regulates emissions of GHGs from certain large stationary sources under the CAA’s Prevention of Significant Deterioration and Title V permitting programs, and a third that regulates GHG emissions from fossil fuel-burning power plants. In September 2015, the EPA published a proposed rule that would update and expand the New Source Performance Standards by setting additional emissions limits for volatile organic compounds and regulating methane emissions from new and modified sources in the oil and gas industry. In May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the U.S., including, among other things, certain onshore oil and natural gas production facilities, on an annual basis. In addition, in 2015, the U.S. participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. Legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the U.S. At the state level, almost one half of the states, including California, have begun taking actions to control and/or reduce emissions of GHGs. For a description of the California “cap and trade” program, see Item 1. “Business – Environmental Matters and Regulation.” Any such added regulation could lead to operational delays, increased operating costs and additional regulatory burdens, and reduced production of oil and natural gas, which could adversely affect our business, financial position, results of operations and net cash provided by operating activities.
Uncertainty regarding derivatives legislation could have an adverse impact on our ability to hedge risks associated with our business.
Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), enacted in 2010, expands federal oversight and regulation of the derivatives markets and entities, such as us, that participate in those markets. Those markets involve derivative transactions, which include certain instruments, such as interest rate swaps, forward contracts, option contracts, financial contracts and other contracts, used in our risk management activities. The Dodd-Frank Act requires that most swaps ultimately will be cleared through a registered clearing facility and that they be traded on a designated exchange or swap execution facility, with certain exceptions for entities that use swaps to hedge or mitigate commercial risk. The Dodd-Frank Act requirements relating to derivative transactions have not been fully implemented by the SEC and the Commodities Futures Trading Commission and the current presidential administration has indicated a desire to repeal and/or replace certain provisions of the Dodd-Frank Act. Uncertainty regarding the current law and any new regulations could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of available counterparties. In addition, we may transact with counterparties based in the European Union, Canada or other jurisdictions which are in the process of implementing regulations to regulate derivatives transactions, some of which are currently in effect and impose operational and transactional costs on our derivatives activities.
Stockholder Risks
There is currently no established public trading market for shares of our Class A common stock and such shares of Class A common stock may never be publicly traded. Accordingly, the holders of our Class A common stock may have no ability to sell their shares.
Upon our emergence from bankruptcy, all units representing limited liability company interests of the Predecessor were canceled and the Reorganized LINN issued shares of Class A common stock. Our Class A common stock is not currently listed on any national or regional securities exchange or quoted on any over-the-counter market. There can be no assurance that a market for our Class A common stock will be established or that, if established, a market will be sustained. Therefore, holders of our Class A common stock may be unable to sell their shares.
28
Item 1A. Risk Factors - Continued
The market price of our Class A common stock could be subject to wide fluctuations in response to, and the level of trading that develops for our Class A common stock may be affected by numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the LINN Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our Class A common stock, the lack of comparable historical financial information, in certain material respects, given the adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flows, the nature and content of our earnings releases, announcements or events that impact our assets, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Annual Report on Form 10‑K. No assurance can be given that an active market will develop for our Class A common stock or as to the liquidity of the trading market for our Class A common stock. Our Class A common stock may be traded only infrequently in transactions arranged through brokers or otherwise, and reliable market quotations may not be available. Holders of our Class A common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our Class A common stock, or the expectation of these sales, could materially and adversely affect the market price of our Class A common stock.
There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.
Funds associated with Fir Tree Inc., York Capital Management Global Advisors, LLC and Elliott Management Corporation collectively owned approximately 49% of our outstanding Class A common stock as of March 13, 2017. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in the Company. Such transactions might adversely affect us or other holders of our Class A common stock. In addition, our significant concentration of share ownership may adversely affect the trading price of our Class A common stock because investors may perceive disadvantages in owning shares in companies with significant stockholders.
The issuance of share-based awards may dilute your holding of shares of Class A common stock.
Pursuant to the LINN Plan, we issued 91,708,500 shares of Class A common stock in the Reorganized LINN. A total of 6,444,381 shares of Class A common stock of the Reorganized LINN were reserved for issuance (of which 2,478,608 shares were issued as of the Effective Date) under the 2017 Omnibus Incentive Plan (“2017 Incentive Plan”) as equity-based awards to employees, directors and certain other persons. The exercise of equity awards, including any stock options that we may grant in the future, and warrants, and the sale of shares of our common stock underlying any such stock options could have an adverse effect on the market for our common stock, including the price that investors could obtain for their shares. Investors may experience dilution in the value of their investment upon the exercise of any stock options that may be granted or issued pursuant to the 2017 Incentive Plan in the future.
We do not expect to pay dividends in the near future.
We do not anticipate that cash dividends or other distributions will be paid with respect to our Class A common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are, or may be, a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our Class A common stock.
Certain provisions of our Certificate of Incorporation and our Bylaws may make it difficult for stockholders to change the composition of our Board of Directors and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.
Certain provisions of our Certificate of Incorporation and our Bylaws may have the effect of delaying or preventing changes in control if our Board of Directors determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Certificate of Incorporation and Bylaws include, among other things, those that:
• | authorize our Board of Directors to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval; |
• | establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and |
29
Item 1A. Risk Factors - Continued
• | limit the persons who may call special meetings of stockholders. |
These provisions could enable the Board of Directors to delay or prevent a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may discourage or prevent attempts to remove and replace incumbent directors. These provisions may also discourage or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board of Directors, which is responsible for appointing the members of our management.
We are a “smaller reporting company” and, as such, are allowed to provide less disclosure than larger public companies.
We are currently a “smaller reporting company,” as defined by Rule 12b-2 of the Securities Exchange Act of 1934. As a “smaller reporting company,” we have certain decreased disclosure obligations in our SEC filings, which may make it harder for investors to analyze our results of operations and financial prospects and may result in less investor confidence.
Item 1B. Unresolved Staff Comments
None
Item 2. Properties
Information concerning proved reserves, production, wells, acreage and related matters are contained in Item 1. “Business.”
The Company’s obligations under its Exit Facility are secured by mortgages on substantially all of the Company’s oil and natural gas properties. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional details about the Exit Facility.
Offices
The Company’s principal corporate office is located at 600 Travis, Houston, Texas 77002. The Company maintains additional offices in California, Illinois, Kansas, Louisiana, Michigan, New Mexico, Oklahoma, Texas, Utah and Wyoming.
Item 3. Legal Proceedings
On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order. Consummation of the LINN Plan was subject to certain conditions set forth in the LINN Plan. On the Effective Date, all of the conditions were satisfied or waived and the LINN Plan became effective and was implemented in accordance with its terms. The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.
The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. For certain statewide class action royalty payment disputes, the Company filed notices advising that it had filed for bankruptcy protection and seeking a stay, which was granted. However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.
The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
Item 4. Mine Safety Disclosures
Not applicable
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Part II
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
From May 24, 2016 through February 28, 2017, the Predecessor’s units were listed on the OTC Markets Group Inc.’s Pink marketplace (“OTC”) under the trading symbol “LINEQ.” Prior to May 24, 2016, the Predecessor’s units were listed on the NASDAQ Global Select Market (“NASDAQ”).
In connection with the Company’s reorganization and emergence from bankruptcy, on the Effective Date, all units in the Predecessor outstanding prior to the emergence were canceled and ceased to be listed on the OTC Markets Group Inc.’s Pink marketplace. Simultaneous with the cancellation of the units, the Successor authorized for issuance 270,000,000 shares of Class A common stock and 30,000,000 shares of preferred stock, par value $0.001 per share, and issued 91,708,500 shares of Class A common stock primarily to holders of certain classes of claims in the Chapter 11 cases.
There is currently no established public trading market for the shares of Class A common stock and there has not been an established public trading market for the shares of Class A common stock since the Company emerged from bankruptcy on February 28, 2017. At the close of business on March 15, 2017, there were approximately two stockholders of record.
The following table sets forth the range of high and low last reported sales prices per unit of the Predecessor, as reported by the OTC or NASDAQ, for the quarters indicated. In addition, distributions declared during each quarter are presented.
Unit Price Range | Cash Distributions Declared Per Unit | |||||||||||
Quarter | High | Low | ||||||||||
2016: | ||||||||||||
October 1 – December 31 | $ | 0.34 | $ | 0.05 | $ | — | ||||||
July 1 – September 30 | $ | 0.10 | $ | 0.05 | $ | — | ||||||
April 1 – June 30 | $ | 0.48 | $ | 0.08 | $ | — | ||||||
January 1 – March 31 | $ | 1.95 | $ | 0.33 | $ | — | ||||||
2015: | ||||||||||||
October 1 – December 31 | $ | 3.41 | $ | 1.12 | $ | — | ||||||
July 1 – September 30 | $ | 9.16 | $ | 2.11 | $ | 0.313 | ||||||
April 1 – June 30 | $ | 13.94 | $ | 8.91 | $ | 0.313 | ||||||
January 1 – March 31 | $ | 14.25 | $ | 9.22 | $ | 0.313 | ||||||
Distributions
Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor currently has no intention of paying cash dividends and any future payment of cash dividends would be subject to the restrictions in the Exit Facility.
Securities Authorized for Issuance Under Equity Compensation Plans
See the information incorporated by reference in Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” regarding securities authorized for issuance under the Company’s equity compensation plans, which information is incorporated by reference into this Item 5.
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Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Continued |
Sales of Unregistered Securities
None
Issuer Purchases of Equity Securities
None
32
Item 6. | Selected Financial Data |
The selected financial data set forth below should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8. “Financial Statements and Supplementary Data.”
Because of rapid growth through acquisitions and development of properties, the Company’s historical results of operations and period-to-period comparisons of those results and certain other financial data may not be meaningful or indicative of future results. The results of operations of Berry are reported as discontinued operations for all periods presented (see Note 3).
At or for the Year Ended December 31, | |||||||||||||||||||
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||||||
Statement of operations data: | |||||||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 952,132 | $ | 1,151,240 | $ | 2,312,137 | $ | 2,022,916 | $ | 1,601,180 | |||||||||
Gains (losses) on oil and natural gas derivatives | (164,330 | ) | 1,027,014 | 1,127,395 | 182,906 | 124,762 | |||||||||||||
Depreciation, depletion and amortization | 404,237 | 554,386 | 771,549 | 818,466 | 606,150 | ||||||||||||||
Interest expense, net of amounts capitalized | 192,862 | 460,635 | 499,890 | 417,174 | 379,937 | ||||||||||||||
Loss from continuing operations | (385,697 | ) | (3,744,634 | ) | (474,405 | ) | (671,364 | ) | (386,616 | ) | |||||||||
Income (loss) from discontinued operations | (1,786,159 | ) | (1,015,177 | ) | 22,596 | (19,973 | ) | — | |||||||||||
Net loss | (2,171,856 | ) | (4,759,811 | ) | (451,809 | ) | (691,337 | ) | (386,616 | ) | |||||||||
Loss per unit – continuing operations: | |||||||||||||||||||
Basic | (1.10 | ) | (10.91 | ) | (1.47 | ) | (2.86 | ) | (1.92 | ) | |||||||||
Diluted | (1.10 | ) | (10.91 | ) | (1.47 | ) | (2.86 | ) | (1.92 | ) | |||||||||
Income (loss) per unit – discontinued operations: | |||||||||||||||||||
Basic | (5.06 | ) | (2.96 | ) | 0.07 | (0.08 | ) | — | |||||||||||
Diluted | (5.06 | ) | (2.96 | ) | 0.07 | (0.08 | ) | — | |||||||||||
Net loss per unit: | |||||||||||||||||||
Basic | (6.16 | ) | (13.87 | ) | (1.40 | ) | (2.94 | ) | (1.92 | ) | |||||||||
Diluted | (6.16 | ) | (13.87 | ) | (1.40 | ) | (2.94 | ) | (1.92 | ) | |||||||||
Distributions declared per unit | $ | — | $ | 0.938 | $ | 2.90 | $ | 2.90 | $ | 2.87 | |||||||||
Weighted average units outstanding | 352,653 | 343,323 | 328,918 | 237,544 | 203,775 | ||||||||||||||
Cash flow data: | |||||||||||||||||||
Net cash provided by (used in): | |||||||||||||||||||
Operating activities (1) | $ | 880,514 | $ | 1,249,457 | $ | 1,711,890 | $ | 1,166,212 | $ | 350,907 | |||||||||
Investing activities | (235,840 | ) | (310,417 | ) | (2,021,025 | ) | (818,317 | ) | (3,684,829 | ) | |||||||||
Financing activities | 48,015 | (938,681 | ) | 258,773 | (296,967 | ) | 3,334,051 | ||||||||||||
Balance sheet data: | |||||||||||||||||||
Total assets | $ | 4,660,591 | $ | 9,936,880 | $ | 16,632,820 | $ | 16,436,499 | $ | 11,365,653 | |||||||||
Current portion of long-term debt | 1,937,729 | 2,841,518 | — | — | — | ||||||||||||||
Long-term debt, net | — | 4,447,308 | 8,125,213 | 6,796,015 | 5,958,539 | ||||||||||||||
Liabilities subject to compromise | 4,305,005 | — | — | — | — | ||||||||||||||
Unitholders’ capital (deficit) | (2,396,988 | ) | (268,901 | ) | 4,543,605 | 5,891,427 | 4,427,180 | ||||||||||||
(1) | Net of payments made for commodity derivative premiums of approximately $583 million for the year ended December 31, 2012. |
33
Item 6. Selected Financial Data - Continued
At or for the Year Ended December 31, | ||||||||||||||
2016 | 2015 | 2014 | 2013 | 2012 | ||||||||||
Production data: | ||||||||||||||
Average daily production – continuing operations: | ||||||||||||||
Natural gas (MMcf/d) | 511 | 549 | 492 | 440 | 349 | |||||||||
Oil (MBbls/d) | 27.5 | 32.4 | 36.2 | 32.2 | 29.2 | |||||||||
NGL (MBbls/d) | 25.4 | 25.7 | 31.7 | 29.6 | 24.5 | |||||||||
Total (MMcfe/d) | 828 | 897 | 900 | 811 | 671 | |||||||||
Average daily production – discontinued operations: (1) | ||||||||||||||
Total (MMcfe/d) | 241 | 291 | 310 | 267 | — | |||||||||
Reserves data: (2) | ||||||||||||||
Estimated proved reserves – continuing operations: | ||||||||||||||
Natural gas (Bcf) | 2,300 | 2,231 | 3,568 | 2,730 | 2,571 | |||||||||
Oil (MMBbls) | 99 | 103 | 197 | 195 | 191 | |||||||||
NGL (MMBbls) | 104 | 97 | 146 | 184 | 179 | |||||||||
Total (Bcfe) | 3,520 | 3,435 | 5,631 | 4,999 | 4,796 | |||||||||
Estimated proved reserves – discontinued operations: | ||||||||||||||
Total (Bcfe) | — | 1,053 | 1,673 | 1,404 | — | |||||||||
(1) | Average daily production of discontinued operations for 2016 and 2013 is for the periods from January 1, 2016 through December 3, 2016, and December 17, 2013 through December 31, 2013, respectively. |
(2) | In accordance with Securities and Exchange Commission regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. |
34
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with the financial statements and related notes included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements based on expectations, estimates and assumptions. Actual results may differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGL, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, credit and capital market conditions, regulatory changes and other uncertainties, as well as those factors set forth in “Cautionary Statement Regarding Forward-Looking Statements” in Item 1. “Business” and in Item 1A. “Risk Factors.”
When referring to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “Reorganized LINN,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of LINN Energy through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see below and Note 3). The reference to “LinnCo” herein refers to LinnCo, LLC, which is an affiliate of the Predecessor.
The reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Executive Overview
LINN Energy is an independent oil and natural gas company that was formed on February 14, 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further below and in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017.
On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date. The results of operations of Berry are reported as discontinued operations for all periods presented.
The Company’s properties are located in eight operating regions in the United States (“U.S.”):
• | Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; |
• | Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin) and North Dakota (Williston Basin); |
• | Mid-Continent, which includes Oklahoma properties located in the Anadarko and Arkoma basins, as well as waterfloods in the Central Oklahoma Platform; |
• | TexLa, which includes properties located in east Texas and north Louisiana; |
• | Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; |
• | California, which includes properties located in the San Joaquin Valley and Los Angeles basins; |
35
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
• | Permian Basin, which includes properties located in west Texas and southeast New Mexico; and |
• | South Texas. |
For a discussion of the Company’s eight operating regions, see Item 1. “Business.”
For the year ended December 31, 2016, the Company’s results included the following:
• | oil, natural gas and NGL sales of approximately $952 million compared to $1.2 billion for 2015; |
• | average daily production of approximately 828 MMcfe/d compared to 897 MMcfe/d for 2015; |
• | net loss of approximately $2.2 billion compared to $4.8 billion for 2015; |
• | net cash provided by operating activities from continuing operations of approximately $874 million compared to $1.1 billion for 2015; |
• | capital expenditures, excluding acquisitions, of approximately $173 million compared to $366 million for 2015; and |
• | 212 wells drilled (211 successful) compared to 393 wells drilled (388 successful) for 2015. |
Chapter 11 Proceedings
On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040.
On October 21, 2016, the Debtors filed the Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates (the “Original Plan”).
On December 3, 2016, the Debtors split the Original Plan and pursued separate plans of reorganization for the LINN Debtors, on the one hand, and Linn Acquisition Company, LLC (“LAC”) and Berry, on the other hand. Accordingly, on December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “LINN Plan”). The LINN Debtors subsequently filed amended versions of the LINN Plan with the Bankruptcy Court.
On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the LINN Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.
On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.
Bankruptcy Accounting
The consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that were impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s consolidated balance sheet at December 31, 2016. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Plans of Reorganization
In accordance with the LINN Plan, on the Effective Date:
• | The Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed subsidiary of the Predecessor and the borrower under the Credit Agreement (“Exit Facility”) entered into in connection with the reorganization, in exchange for 100% of the equity of Holdco II and the issuance of interests in the Exit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred 100% of the equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash and an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor (the “Disposition”), which the Predecessor distributed to certain of its creditors in satisfaction of their claims. Contemporaneously with the reorganization transactions and pursuant to the LINN Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims. |
• | The holders of claims under the Predecessor’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the $1.7 billion Exit Facility. As a result, all outstanding obligations under the LINN Credit Facility were canceled. |
• | Holdco II, as borrower, entered into the Exit Facility with the holders of claims under the LINN Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan (the “Revolving Loan”) with up to $1.4 billion in borrowing commitments and a new term loan (the “Term Loan”) in an original principal amount of $300 million. For additional information, see “Financing Activities” below. |
• | The holders of the Company’s 12.00% senior secured second lien notes due December 2020 (the “Second Lien Notes”) received their pro rata share of (i) 17,678,889 shares of Class A common stock; (ii) certain rights to purchase shares of Class A common stock in the rights offering, as described below; and (iii) $30 million in cash. The holders of the Company’s 6.50% senior notes due May 2019, 6.25% senior notes due November 2019, 8.625% senior notes due 2020, 7.75% senior notes due February 2021 and 6.50% senior notes due September 2021 (collectively, the “Unsecured Notes”) received their pro rata share of (i) 26,724,396 shares of Class A common stock; and (ii) certain rights to purchase shares of Class A common stock in the rights offering (as described below). As a result, all outstanding obligations under the Second Lien Notes and the Unsecured Notes and the indentures governing such obligations were canceled. |
• | The holders of general unsecured claims (other than claims relating to the Second Lien Notes and the Unsecured Notes) against the LINN Debtors (the “LINN Unsecured Claims”) received their pro rata share of cash from two cash distribution pools totaling $40 million, as divided between a $2.3 million cash distribution pool for the payment in full of allowed LINN Unsecured Claims in an amount equal to $2,500 or less (and larger claims for which the holders irrevocably agreed to reduce such claims to $2,500), and a $37.7 million cash distribution pool for pro rata distributions to all remaining allowed general LINN Unsecured Claims. As a result, all outstanding LINN Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date. |
• | All units that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. On the Effective Date, the Reorganized LINN issued in the aggregate 91,708,500 shares of Class A common stock. No cash was raised from the issuance of the Class A common stock on account of claims held by the Predecessor’s creditors. |
• | The Reorganized LINN entered into a registration rights agreement with the Backstop Parties (as defined below) and other recipients of shares of Class A common stock who own at least 10% of the shares of Class A common stock or are otherwise deemed to be an affiliate of the Reorganized LINN, pursuant to which the Company agreed to, among other things, file a registration statement with the Securities and Exchange Commission within 60 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined therein). |
37
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
• | By operation of the LINN Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. The Reorganized LINN formed a new board of directors, consisting of the Chief Executive Officer of the Predecessor, one director selected by the Reorganized LINN and five directors selected by a six-person selection committee. |
In accordance with the Berry Plan, on the Effective Date:
• | LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, and Berry became a wholly owned subsidiary of Berry Petroleum Corporation. All of the equity interests in LAC that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. Subsequently, LAC commenced liquidation, which is expected to be completed following the resolution of the outstanding claims. As a result, Berry Petroleum Corporation became a stand-alone company, separate from the Company and the LINN Debtors. |
• | The holders of claims under Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the new Berry credit facility (“Berry Exit Facility”). As a result, all outstanding obligations under the Berry Credit Facility were canceled. |
• | Berry, as borrower, entered into the Berry Exit Facility with the holders of claims under the Berry Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments. |
• | The holders of Berry’s 6.75% senior notes due 2020 and 6.375% senior notes due 2022 (collectively, the “Berry Unsecured Notes”) received their pro rata share of either (i) shares of common stock in Berry Petroleum Corporation or, for those non-accredited investors holding the Berry Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Berry Cash Distribution Pool”), and (ii) certain rights to purchase shares of preferred stock in Berry Petroleum Corporation. |
• | The holders of unsecured claims against Berry (other than the Berry Unsecured Notes) (the “Berry Unsecured Claims”) received their pro rata share of either (i) shares of common stock in Berry Petroleum Corporation or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Berry Cash Distribution Pool. As a result, all outstanding obligations under the Berry Unsecured Notes and the indentures governing such obligations were canceled and all outstanding Berry Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date. |
• | Berry and LAC settled all intercompany claims against the LINN Debtors pursuant to a settlement agreement approved as part of the Berry Plan and the Confirmation Order, which settlement provided Berry and LAC with a $25 million general unsecured claim against the Company. |
Bank RSA
Prior to the Petition Date, on May 10, 2016, the Debtors entered into a restructuring support agreement (“Bank RSA”) with certain holders (“Consenting Bank Creditors”) collectively holding or controlling at least 66.67% by aggregate outstanding principal amounts under (i) the LINN Credit Facility and (ii) the Berry Credit Facility. The Bank RSA set forth, subject to certain conditions, the commitment of the Consenting Bank Creditors to support a comprehensive restructuring of the Debtors’ long-term debt. The Bank RSA provided that the Consenting Bank Creditors would support the use of the LINN Debtors’ and Berry’s cash collateral under specified terms and conditions, including adequate protection terms. The Bank RSA required the Debtors and the Consenting Bank Creditors to, among other things, support and not interfere with consummation of the restructuring transactions contemplated by the Bank RSA and, as to the Consenting Bank Creditors, vote their claims in favor of the plan of reorganization.
Restructuring Support Agreement
On October 7, 2016, the LINN Debtors entered into a restructuring support agreement (“Original LINN RSA”) with (i) certain holders of the Second Lien Notes (such holders, the “Consenting Second Lien Noteholders”) and (ii) certain holders of the Unsecured Notes (such holders of the Unsecured Notes, the “Consenting Unsecured Noteholders,” and together such Consenting Unsecured Noteholders with the Consenting Second Lien Noteholders, the “Consenting Noteholders”).
38
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
On October 21, 2016, the LINN Debtors entered into the First Amended and Restated Restructuring Support Agreement (“LINN RSA”) with (i) certain Consenting Second Lien Noteholders, (ii) certain Consenting Unsecured Noteholders and (iii) certain lenders (together with the Consenting Noteholders, the “Consenting LINN Creditors”) under the LINN Credit Facility. The LINN RSA amended and restated the Original LINN RSA and replaced the Bank RSA with respect to the terms of the restructuring of the LINN Debtors. At that time, the Bank RSA remained in full force and effect with respect to the restructuring of Berry and LAC. The LINN RSA set forth, subject to certain conditions, the commitment of the LINN Debtors and the Consenting LINN Creditors to support a comprehensive restructuring of the LINN Debtors’ long-term debt (the “Restructuring”). The LINN RSA required the LINN Debtors and the Consenting LINN Creditors to, among other things, support and not interfere with consummation of the Restructuring and, as to the Consenting LINN Creditors, vote their claims in favor of the LINN Plan. The restructuring contemplated by the LINN RSA was effectuated through the LINN Plan and the Confirmation Order and took effect on the Effective Date.
Backstop Commitment Agreement
On October 25, 2016, the Company entered into a backstop commitment agreement (“Backstop Commitment Agreement”) with the parties thereto (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties, which were also Consenting Noteholders under the LINN RSA, agreed to backstop a $530 million new money investment in the Reorganized LINN pursuant to the rights offerings to be conducted in accordance with the LINN Plan. The Backstop Commitment Agreement generally provided that the LINN Debtors would facilitate certain aspects of the rights offering and the obligations under the Backstop Commitment Agreement were assumed by the Reorganized LINN on the Effective Date.
In accordance with the LINN Plan, the Backstop Commitment Agreement and the rights offerings procedures filed in the Chapter 11 cases and approved by the Bankruptcy Court, the LINN Debtors offered eligible creditors, including the Backstop Parties, the right to purchase Class A common stock upon emergence from the Chapter 11 cases for an aggregate purchase price of $530 million. The rights offerings consisted of the following offerings:
• | Holders of Unsecured Notes as of the record date set therefor were granted rights entitling each such holder to subscribe to the rights offering in an amount up to its pro rata share of Class A common stock (the “Unsecured Rights Offering,” and such Class A common stock offered for purchase thereunder, the “Unsecured Rights Offering Shares”), which Unsecured Rights Offering Shares, collectively, reflected an aggregate purchase price of $319,004,408 at the per share price set forth in the Backstop Commitment Agreement. |
• | Holders of Second Lien Notes as of the record date set therefor were granted rights entitling each such holder to subscribe to the rights offering in an amount up to its pro rata share of Class A common stock (the “Secured Rights Offering,” and such Class A common stock offered for purchase thereunder, the “Secured Rights Offering Shares”), which Secured Rights Offering Shares, collectively, reflected an aggregate purchase price of $210,995,592 at the per share price set forth in the Backstop Commitment Agreement. |
Under the Backstop Commitment Agreement, certain Backstop Parties agreed to purchase their pro rata share of the Unsecured Rights Offering Shares and the Secured Rights Offering Shares, as applicable, that were not duly subscribed to pursuant to the Unsecured Rights Offering or the Secured Rights Offering, as applicable, at the discounted per share price set forth in the Backstop Commitment by parties other than Backstop Parties (the “Backstop Commitment”).
Pursuant to the Backstop Commitment Agreement, the LINN Debtors agreed to pay the Backstop Parties on the Effective Date a commitment premium equal to 4.0% of the $530 million committed amount (the “Backstop Commitment Premium”), of which 3.0% was paid in cash and 1.0% was paid in the form of Class A common stock at the discounted per share price set forth in the Backstop Commitment Agreement. All amounts payable to the Backstop Parties in their capacities as such for the Backstop Commitment Premium were paid pro rata based on the amount of their respective Backstop Commitments on the Effective Date (as compared to the aggregate Backstop Commitment of all Backstop Parties).
The rights to purchase new common stock in the rights offerings, all shares issued upon exercise thereof, and all shares issued to the Backstop Parties in respect of their Backstop Commitments pursuant to the Backstop Commitment Premium, were issued in reliance upon the exemption from the registration requirements of the securities laws pursuant to Section 1145 of the Bankruptcy Code. All shares issued to the Backstop Parties pursuant to the Backstop Commitment Agreement in respect of their Backstop Commitment were issued in reliance upon the exemption from registration under the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(a)(2) thereof and/or Regulation D thereunder.
39
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The LINN Plan provided that, in all circumstances, parties would receive at least 50.1% of the common stock of the Reorganized LINN on account of the rights offerings (subject to dilution in connection with the 2017 Incentive Plan).
The Backstop Parties’ commitments to backstop the rights offerings, and the other transactions contemplated by the Backstop Commitment Agreement, were conditioned upon the satisfaction of all conditions to the effectiveness of the LINN Plan and other applicable conditions precedent set forth in the Backstop Commitment Agreement. The issuances of new common stock pursuant to the rights offerings and the Backstop Commitment Agreement were conditioned upon, among other things, confirmation of the LINN Plan by the Bankruptcy Court, and the LINN Plan’s effectiveness upon the Company’s emergence from its Chapter 11 cases. On the Effective Date, all conditions to the rights offerings and the Backstop Commitment Agreement were met, and the LINN Debtors completed the rights offerings and the related issuance of the Class A common stock.
Covenant Violations
The Company’s filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under its Credit Facilities, its Second Lien Notes and its senior notes. Additionally, other events of default, including cross-defaults, have occurred, including the failure to make interest payments on the Company’s Second Lien Notes and senior notes, as well as the receipt of a going concern explanatory paragraph from the Company’s independent registered public accounting firm on the Company’s consolidated financial statements for the year ended December 31, 2015. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default. See Note 6 for additional details about the Company’s debt.
Credit Facilities
The Company’s Credit Facilities contained a requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. Consequently, the filing of the Company’s 2015 Annual Report on Form 10-K which included such explanatory paragraph resulted in a default under the LINN Credit Facility as of the filing date, March 15, 2016, subject to a 30 day grace period.
On April 12, 2016, the Company entered into amendments to both the LINN Credit Facility and the Berry Credit Facility. The amendments provided for, among other things, an agreement that (i) certain events would not become defaults or events of default until May 11, 2016, (ii) the borrowing bases would remain constant until May 11, 2016, unless reduced as a result of swap agreement terminations or collateral sales and (iii) the Company, the administrative agent and the lenders would negotiate in good faith the terms of a restructuring support agreement in furtherance of a restructuring of the capital structure of the Company and its subsidiaries. In addition, the amendment to the Berry Credit Facility provided Berry with access to previously restricted cash of $45 million in order to fund ordinary course operations.
As a condition to closing the amendments, in April 2016, (a) the Company made a $100 million permanent repayment of a portion of the borrowings outstanding under the LINN Credit Facility and (b) the Company and certain of its subsidiaries provided control agreements over certain deposit accounts. Pursuant to the terms of the amendment to the LINN Credit Facility and as a result of the execution of the Bank RSA, in May 2016, the Company made a $350 million permanent repayment of a portion of the borrowings outstanding under the LINN Credit Facility.
The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Credit Facilities. However, under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of the default.
Second Lien Notes
The indenture governing the Second Lien Notes (“Second Lien Indenture”) required the Company to deliver mortgages by February 18, 2016, subject to a 45 day grace period. The Company elected to exercise its right to the grace period, which resulted in the Company being in default under the Second Lien Indenture.
On April 4, 2016, the Company entered into a settlement agreement with certain holders of the Second Lien Notes and agreed to deliver, and make arrangements for recordation of, the mortgages. The Company has since delivered and made arrangements for recordation of the mortgages.
40
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The settlement agreement required the parties to commence good faith negotiations with each other regarding the terms of a potential comprehensive and consensual restructuring, including a potential restructuring under a Chapter 11 plan of reorganization. The settlement agreement provided that in the event the parties were unable to reach agreement on the terms of a consensual restructuring on or before the commencement of such Chapter 11 proceedings (or such later date as mutually agreed to by the parties), the parties would support entry by the Bankruptcy Court of a settlement order that, among other things, (i) approves the issuance of additional notes, in the principal amount of $1.0 billion plus certain accrued interest, on a proportionate basis to existing holders of the Second Lien Notes and (ii) releases the mortgages and other collateral upon the issuance of the additional notes (the “Settlement Order”).
The settlement agreement will terminate upon, among other events, entry by the Bankruptcy Court of a final, non-appealable order denying the Company’s motion seeking entry of the Settlement Order.
The Company also failed to make interest payments on its Second Lien Notes during 2016.
The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Second Lien Indenture. However, under the Bankruptcy Code, holders of the Second Lien Notes were stayed from taking any action against the Company as a result of the default.
Senior Notes
The Company deferred making interest payments totaling approximately $60 million due March 15, 2016, including approximately $30 million on LINN Energy’s 7.75% senior notes due February 2021, approximately $12 million on LINN Energy’s 6.50% senior notes due September 2021 and approximately $18 million on Berry’s 6.375% senior notes due September 2022, which resulted in the Company being in default under these senior notes. The indentures governing each of the applicable series of notes provided the Company a 30 day grace period to make the interest payments.
On April 14, 2016, within the 30 day interest payment grace period provided for in the indentures governing the notes, the Company and Berry made interest payments of approximately $60 million in satisfaction of their respective obligations.
The Company failed to make interest payments due on its senior notes subsequent to April 14, 2016.
The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the indentures governing the senior notes. However, under the Bankruptcy Code, holders of the senior notes were stayed from taking any action against the Company as a result of the default.
2017 Oil and Natural Gas Capital Budget
For 2017, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $395 million, including approximately $300 million related to its oil and natural gas capital program and approximately $84 million related to its plant and pipeline capital. This estimate is under continuous review and subject to ongoing adjustments.
Financing Activities
Exit Facility
On the Effective Date, pursuant to the terms of the LINN Plan, Holdco II, as borrower, entered into the Exit Facility with the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent, providing for the Revolving Loan with up to $1.4 billion in borrowing commitments and the Term Loan in an original principal amount of $300 million.
The initial borrowing base in respect of the Revolving Loan is $1.4 billion and there are no scheduled borrowing base redeterminations until April 1, 2018. After such time and until August 28, 2020, any scheduled redetermination of the borrowing base resulting in a decrease of the borrowing base will cause the borrowing base to be allocated into a conforming Revolving Loan tranche and a non-conforming Revolving Loan tranche that, in the aggregate, equal $1.4 billion. As of the Effective Date, the Company had approximately $600 million in borrowings outstanding under the Revolving Loan.
Interest on borrowings under the Exit Facility is determined by reference to the London Interbank Offered Rate (“LIBOR”) plus an applicable margin of (a) 3.50% per annum in the case of the conforming Revolving Loan tranche and (b) 5.50% per
41
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
annum in the case of the non-conforming Revolving Loan tranche. The Revolving Loan is not subject to amortization. The conforming Revolving Loan tranche matures on February 27, 2021, and the non-conforming Revolving Loan tranche matures on August 28, 2020.
The Term Loan incurs interest at a rate of LIBOR plus 7.50% per annum, amortized quarterly, and matures on February 27, 2021.
Holdco II has the right to prepay any borrowings under the Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to eurodollar loans.
The obligations under the Exit Facility are guaranteed by the Company, Linn Energy Holdco LLC and Holdco II’s subsidiaries, subject to customary exceptions, and are secured by liens on substantially all personal property of the Company. In connection with emergence from bankruptcy, the Company’s existing pre-petition mortgages were reaffirmed. Within 30 days of closing the Exit Facility, the Company is required to execute certain amended and restated mortgages and certain additional mortgages to achieve collateral coverage of no less than 95% of the total value of the proved reserves of the oil and natural gas properties of the Company, and certain equipment and facilities associated therewith, as required under the terms of the Exit Facility.
Under the Exit Facility, the Company is required to maintain certain financial covenants including the maintenance of (i) an asset coverage ratio of at least 1.1 to 1.0, tested on (a) the date of each scheduled borrowing base redetermination commencing with the first scheduled borrowing base redetermination and (b) the date of each additional borrowing base redetermination done in conjunction with an asset sale and (ii) a maximum total net debt to last twelve months EBITDAX ratio of 6.75 to 1.0 for March 31, 2018 through December 31, 2018, 6.5 to 1.0 for March 31, 2019 through March 31, 2020, and 4.5 to 1.0 thereafter.
The Exit Facility also contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and natural gas engineering reports and budgets, maintenance and operation of property (including oil and natural gas properties), restrictions on the incurrence of liens and indebtedness, mergers, consolidations and sales of assets, transactions with affiliates and other customary covenants.
The Exit Facility contains customary events of default and remedies for credit facilities of this nature. Failure to comply with the financial and other covenants in the Exit Facility would allow the lenders, subject to customary cure rights, to require immediate payment of all amounts outstanding under the Exit Facility.
LINN Credit Facility
See above for a description of the amendment to the LINN Credit Facility entered into in April 2016. During the year ended December 31, 2016, the Company borrowed approximately $979 million under the LINN Credit Facility and made repayments of approximately $1.8 billion of a portion of the borrowings outstanding under the LINN Credit Facility and term loan. The repayments include approximately $841 million in commodity derivative settlements paid by the counterparties to the lenders under the LINN Credit Facility. As of December 31, 2016, total borrowings outstanding (including outstanding letters of credit) under the LINN Credit Facility were approximately $1.9 billion, with no remaining availability. Pursuant to the terms of the LINN Plan, on the Effective Date, all obligations under the LINN Credit Facility were canceled.
Commodity Derivatives
During the year ended December 31, 2016, LINN Energy entered into commodity derivative contracts consisting of natural gas swaps for October 2016 through December 2019, oil swaps for November 2016 through December 2017, and oil collars for January 2018 through December 2019.
In April 2016 and May 2016, in connection with the Company’s restructuring efforts, LINN Energy canceled (prior to the contract settlement dates) all of its then-outstanding derivative contracts for net proceeds of approximately $1.2 billion. The net proceeds were used to make permanent repayments of a portion of the borrowings outstanding under the LINN Credit Facility.
42
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Offer to Exchange LINN Energy Units for LinnCo Shares
In March 2016, LinnCo filed a Registration Statement on Form S-4 related to an offer to exchange each outstanding unit representing limited liability company interests of LINN Energy for one common share representing limited liability company interests of LinnCo. The initial offer expired on April 25, 2016, and on April 26, 2016, LinnCo commenced a subsequent offering period that expired on August 1, 2016. During the exchange period, 123,100,715 LINN Energy units were exchanged for an equal number of LinnCo shares. As a result of the exchanges of LINN Energy units for LinnCo shares, LinnCo’s ownership of LINN Energy’s outstanding units increased from approximately 37% at December 31, 2015, to approximately 71% at December 31, 2016. Pursuant to the terms of the LINN Plan, on the Effective Date, all outstanding units were extinguished without recovery.
Delisting from Stock Exchange
As a result of the Company’s failure to comply with the NASDAQ Global Select Market continued listing requirements, on May 24, 2016, the Company’s units began trading over the counter on the OTC Markets Group Inc.’s Pink marketplace under the trading symbol “LINEQ.” As a result of cancellation of the units on the Effective Date, the units ceased to trade on the OTC Markets Group Inc.’s Pink marketplace.
43
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Results of Operations
Year Ended December 31, 2016, Compared to Year Ended December 31, 2015
Year Ended December 31, | |||||||||||
2016 | 2015 | Variance | |||||||||
(in thousands) | |||||||||||
Revenues and other: | |||||||||||
Natural gas sales | $ | 426,307 | $ | 512,538 | $ | (86,231 | ) | ||||
Oil sales | 393,021 | 519,968 | (126,947 | ) | |||||||
NGL sales | 132,804 | 118,734 | 14,070 | ||||||||
Total oil, natural gas and NGL sales | 952,132 | 1,151,240 | (199,108 | ) | |||||||
Gains (losses) on oil and natural gas derivatives | (164,330 | ) | 1,027,014 | (1,191,344 | ) | ||||||
Marketing and other revenues (1) | 129,911 | 141,759 | (11,848 | ) | |||||||
917,713 | 2,320,013 | (1,402,300 | ) | ||||||||
Expenses: | |||||||||||
Lease operating expenses | 317,046 | 375,840 | (58,794 | ) | |||||||
Transportation expenses | 161,037 | 167,561 | (6,524 | ) | |||||||
Marketing expenses | 29,736 | 35,278 | (5,542 | ) | |||||||
General and administrative expenses (2) | 237,841 | 285,996 | (48,155 | ) | |||||||
Exploration costs | 4,080 | 9,473 | (5,393 | ) | |||||||
Depreciation, depletion and amortization | 404,237 | 554,386 | (150,149 | ) | |||||||
Impairment of long-lived assets | 165,044 | 4,960,144 | (4,795,100 | ) | |||||||
Taxes, other than income taxes | 74,838 | 111,302 | (36,464 | ) | |||||||
(Gains) losses on sale of assets and other, net | 15,558 | (195,490 | ) | 211,048 | |||||||
1,409,417 | 6,304,490 | (4,895,073 | ) | ||||||||
Other income and (expenses) | (194,398 | ) | 233,450 | (427,848 | ) | ||||||
Reorganization items, net | 311,599 | — | 311,599 | ||||||||
Loss from continuing operations before income taxes | (374,503 | ) | (3,751,027 | ) | 3,376,524 | ||||||
Income tax expense (benefit) | 11,194 | (6,393 | ) | 17,587 | |||||||
Loss from continuing operations | (385,697 | ) | (3,744,634 | ) | 3,358,937 | ||||||
Loss from discontinued operations, net of income taxes | (1,786,159 | ) | (1,015,177 | ) | (770,982 | ) | |||||
Net loss | $ | (2,171,856 | ) | $ | (4,759,811 | ) | $ | 2,587,955 | |||
(1) | For the years ended December 31, 2016, and December 31, 2015, approximately $69 million and $78 million, respectively, of general and administrative expenses were incurred by Berry through a management fee charged by the Company. Management fee revenues are included in “other revenues” on the consolidated statements of operations. |
(2) | General and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include approximately $34 million and $47 million, respectively, of noncash unit-based compensation expenses. In addition, general and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include costs incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Year Ended December 31, | ||||||||||
2016 | 2015 | Variance | ||||||||
Average daily production: | ||||||||||
Natural gas (MMcf/d) | 511 | 549 | (7 | )% | ||||||
Oil (MBbls/d) | 27.5 | 32.4 | (15 | )% | ||||||
NGL (MBbls/d) | 25.4 | 25.7 | (1 | )% | ||||||
Total (MMcfe/d) | 828 | 897 | (8 | )% | ||||||
Weighted average prices: (1) | ||||||||||
Natural gas (Mcf) | $ | 2.28 | $ | 2.56 | (11 | )% | ||||
Oil (Bbl) | $ | 39.12 | $ | 44.00 | (11 | )% | ||||
NGL (Bbl) | $ | 14.28 | $ | 12.68 | 13 | % | ||||
Average NYMEX prices: | ||||||||||
Natural gas (MMBtu) | $ | 2.46 | $ | 2.66 | (8 | )% | ||||
Oil (Bbl) | $ | 43.32 | $ | 48.80 | (11 | )% | ||||
Costs per Mcfe of production: | ||||||||||
Lease operating expenses | $ | 1.05 | $ | 1.15 | (9 | )% | ||||
Transportation expenses | $ | 0.53 | $ | 0.51 | 4 | % | ||||
General and administrative expenses (2) | $ | 0.78 | $ | 0.87 | (10 | )% | ||||
Depreciation, depletion and amortization | $ | 1.33 | $ | 1.69 | (21 | )% | ||||
Taxes, other than income taxes | $ | 0.25 | $ | 0.34 | (26 | )% | ||||
Average daily production – discontinued operations: (3) | ||||||||||
Total (MMcfe/d) | 241 | 291 | (17 | )% | ||||||
(1) | Does not include the effect of gains (losses) on derivatives. |
(2) | General and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include approximately $34 million and $47 million, respectively, of noncash unit-based compensation expenses. In addition, general and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include costs incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
(3) | Average daily production of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. |
45
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales decreased by approximately $199 million or 17% to approximately $952 million for the year ended December 31, 2016, from approximately $1.2 billion for the year ended December 31, 2015, due to lower natural gas and oil prices, and lower production volumes, partially offset by higher NGL prices. Lower natural gas and oil prices resulted in a decrease in revenues of approximately $52 million and $49 million, respectively. Higher NGL prices resulted in an increase in revenues of approximately $15 million.
Average daily production volumes decreased to approximately 828 MMcfe/d for the year ended December 31, 2016, from approximately 897 MMcfe/d for the year ended December 31, 2015. Lower oil, natural gas and NGL production volumes resulted in a decrease in revenues of approximately $78 million, $34 million and $1 million, respectively.
The following table sets forth average daily production by region:
Year Ended December 31, | |||||||||||
2016 | 2015 | Variance | |||||||||
Average daily production (MMcfe/d): | |||||||||||
Rockies | 330 | 359 | (29 | ) | (8 | )% | |||||
Hugoton Basin | 180 | 193 | (13 | ) | (7 | )% | |||||
Mid-Continent | 101 | 100 | 1 | 2 | % | ||||||
TexLa | 72 | 72 | — | — | |||||||
Permian Basin | 56 | 80 | (24 | ) | (30 | )% | |||||
California | 32 | 30 | 2 | 8 | % | ||||||
Michigan/Illinois | 30 | 31 | (1 | ) | (3 | )% | |||||
South Texas | 27 | 32 | (5 | ) | (14 | )% | |||||
828 | 897 | (69 | ) | (8 | )% | ||||||
The decreases in average daily production volumes primarily reflect reduced development capital spending throughout the Company’s various operating regions, as well as marginal well shut-ins, driven by continued low commodity prices. The decrease in average daily production volumes in the Permian Basin region also reflects lower production volumes as a result of the sale of its remaining position in Howard County in the Permian Basis (“Howard County Assets Sale”) on August 31, 2015.
Gains (Losses) on Oil and Natural Gas Derivatives
Losses on oil and natural gas derivatives were approximately $164 million for the year ended December 31, 2016, compared to gains of approximately $1.0 billion for the year ended December 31, 2015, representing a variance of approximately $1.2 billion. Losses on oil and natural gas derivatives were primarily due to changes in fair value of the derivative contracts and the impact of the declining maturity schedule from period to period of the Company’s hedges. The fair value on unsettled derivative contracts changes as future commodity price expectations change compared to the contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
See above under “Executive Overview” for details about the Company’s commodity derivatives cancellations in 2016.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” and Note 7 and Note 8 for additional details about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.
46
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Other revenues primarily include management fee revenues charged to Berry by the Company and helium sales revenue. Marketing and other revenues decreased by approximately $12 million or 8% to approximately $130 million for the year ended December 31, 2016, from approximately $142 million for the year ended December 31, 2015. The decrease was primarily due to lower management fee revenues charged to Berry by the Company, principally driven by reduced salaries and benefits related expenses at the Company, as well as lower revenues generated by the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms, partially offset by higher helium sales revenue in the Hugoton Basin.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $59 million or 16% to approximately $317 million for the year ended December 31, 2016, from approximately $376 million for the year ended December 31, 2015. The decrease was primarily due to cost savings initiatives and lower workover activities. Lease operating expenses per Mcfe also decreased to $1.05 per Mcfe for the year ended December 31, 2016, from $1.15 per Mcfe for the year ended December 31, 2015.
Transportation Expenses
Transportation expenses decreased by approximately $7 million or 4% to approximately $161 million for the year ended December 31, 2016, from approximately $168 million for the year ended December 31, 2015. The decrease was primarily due to reduced costs as a result of lower production volumes, partially offset by higher costs from nonoperated properties in the Rockies region. Transportation expenses per Mcfe increased to $0.53 per Mcfe for the year ended December 31, 2016, from $0.51 per Mcfe for the year ended December 31, 2015.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses decreased by approximately $5 million or 16% to approximately $30 million for the year ended December 31, 2016, from approximately $35 million for the year ended December 31, 2015. The decrease was primarily due to lower expenses associated with the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. In addition, general and administrative expenses for the years ended December 31, 2016, and December 31, 2015, include costs incurred by LINN Energy associated with the operations of Berry. General and administrative expenses decreased by approximately $48 million or 17% to approximately $238 million for the year ended December 31, 2016, from approximately $286 million for the year ended December 31, 2015. The decrease was primarily due to lower professional services expenses, lower acquisition expenses, lower salaries and benefits related expenses and lower various other administrative expenses including rent. General and administrative expenses for the year ended December 31, 2015, was impacted by advisory fees related to alliance agreements entered into with certain private capital investors. General and administrative expenses per Mcfe also decreased to $0.78 per Mcfe for the year ended December 31, 2016, from $0.87 per Mcfe for the year ended December 31, 2015.
For professional services expenses related to the Chapter 11 proceedings that were incurred since the Petition Date, see “Reorganization Items, Net.”
Exploration Costs
Exploration costs decreased by approximately $5 million to approximately $4 million for the year ended December 31, 2016, from approximately $9 million for the year ended December 31, 2015. The decrease was primarily due to lower dry hole costs and lower leasehold impairment expenses on unproved properties.
47
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $150 million or 27% to approximately $404 million for the year ended December 31, 2016, from approximately $554 million for the year ended December 31, 2015. The decrease was primarily due to lower rates as a result of the impairments recorded in 2015 and 2016, as well as lower total production volumes. Depreciation, depletion and amortization per Mcfe also decreased to $1.33 per Mcfe for the year ended December 31, 2016, from $1.69 per Mcfe for the year ended December 31, 2015.
Impairment of Long-Lived Assets
The Company recorded the following noncash impairment charges associated with proved and unproved oil and natural gas properties:
Year Ended December 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Mid-Continent region | $ | 141,902 | $ | 405,370 | |||
Rockies region | 23,142 | 1,592,256 | |||||
Hugoton Basin region | — | 1,667,768 | |||||
TexLa region | — | 352,422 | |||||
Permian Basin region | — | 71,990 | |||||
South Texas region | — | 42,433 | |||||
Proved oil and natural gas properties | 165,044 | 4,132,239 | |||||
TexLa region | — | 416,846 | |||||
Permian Basin region | — | 226,922 | |||||
Rockies region | — | 184,137 | |||||
Unproved oil and natural gas properties | — | 827,905 | |||||
Impairment of long-lived assets | $ | 165,044 | $ | 4,960,144 | |||
The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves.
(Gains) Losses on Sale of Assets and Other, Net
During the year ended December 31, 2016, the Company had no significant gains or losses from the sale of assets. During the year ended December 31, 2015, the Company recorded a net gain of approximately $177 million, including costs to sell of approximately $1 million, on the Howard County Assets Sale. See Note 3 for additional details of divestitures and exchanges of properties.
Taxes, Other Than Income Taxes
Year Ended December 31, | |||||||||||
2016 | 2015 | Variance | |||||||||
(in thousands) | |||||||||||
Severance taxes | $ | 38,800 | $ | 53,752 | $ | (14,952 | ) | ||||
Ad valorem taxes | 33,883 | 54,388 | (20,505 | ) | |||||||
California carbon allowances | 1,123 | 3,210 | (2,087 | ) | |||||||
Other | 1,032 | (48 | ) | 1,080 | |||||||
$ | 74,838 | $ | 111,302 | $ | (36,464 | ) | |||||
48
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Taxes, other than income taxes decreased by approximately $36 million or 33% for the year ended December 31, 2016, compared to the year ended December 31, 2015. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower natural gas and oil prices and lower production volumes. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to lower estimated valuations on certain of the Company’s properties. California carbon allowances decreased primarily due to lower anticipated emissions compliance obligations as a result of reduced capital spending levels.
Other Income and (Expenses)
Year Ended December 31, | |||||||||||
2016 | 2015 | Variance | |||||||||
(in thousands) | |||||||||||
Interest expense, net of amounts capitalized | $ | (192,862 | ) | $ | (460,635 | ) | $ | 267,773 | |||
Gain on extinguishment of debt | — | 708,050 | (708,050 | ) | |||||||
Other, net | (1,536 | ) | (13,965 | ) | 12,429 | ||||||
$ | (194,398 | ) | $ | 233,450 | $ | (427,848 | ) | ||||
Other income and (expenses) decreased by approximately $428 million for the year ended December 31, 2016, compared to the year ended December 31, 2015. Interest expense decreased primarily due to the Company’s discontinuation of interest expense recognition on the senior notes for the period from May 12, 2016 through December 31, 2016, as a result of the Chapter 11 proceedings, lower outstanding debt during the period principally as a result of the senior notes repurchased and exchanged during 2015, and lower amortization of discounts and financing fees. For the period from May 12, 2016, through December 31, 2016, contractual interest, which was not recorded, on the senior notes was approximately $143 million. For the year ended December 31, 2015, the Company recorded a gain on extinguishment of debt of approximately $708 million as a result of the repurchases of a portion of its senior notes. Other expenses decreased primarily due to lower write-offs of deferred financing fees related to the LINN Credit Facility and lower bank fees. See “Debt” under “Liquidity and Capital Resources” below for additional details.
The $1.0 billion in aggregate principal amount of Second Lien Notes issued in November 2015 were accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. For the period from May 12, 2016, through December 31, 2016, unrecorded contractual interest on the Second Lien Notes was approximately $76 million.
Reorganization Items, Net
The Company has incurred and is expected to continue to incur significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.
49
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The following table summarizes the components of reorganization items included on the consolidated statement of operations:
Year Ended December 31, 2016 | |||
(in thousands) | |||
Legal and other professional advisory fees | $ | (56,656 | ) |
Unamortized deferred financing fees, discounts and premiums | (52,045 | ) | |
Gain related to interest payable on the 12.00% senior secured second lien notes due December 2020 (1) | 551,000 | ||
Terminated contracts | (66,052 | ) | |
Other | (64,648 | ) | |
Reorganization items, net | $ | 311,599 | |
(1) | Represents a noncash gain on the write-off of postpetition contractual interest through maturity, recorded to reflect the carrying value of the liability subject to compromise at its estimated allowed claim amount. |
Income Tax Expense (Benefit)
Prior to the consummation of the LINN Plan, the Company was a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized income tax expense of approximately $11 million for the year ended December 31, 2016, compared to an income tax benefit of approximately $6 million for the year ended December 31, 2015. The increased income tax expense is primarily due to additional expense recognized related to unit-based compensation in 2016 for which there was no windfall benefit offset as in 2015.
Loss from Discontinued Operations, Net of Income Taxes
Berry was deconsolidated effective December 3, 2016, and its results of operations are reported as discontinued operations for all periods presented. Loss from discontinued operations, net of income taxes increased by approximately $771 million to approximately $1.8 billion for the year ended December 31, 2016, from approximately $1.0 billion for the year ended December 31, 2015. The increase was primarily due to the loss on deconsolidation of approximately $546 million, higher impairment charges, lower production revenues and losses compared to gains on oil and natural gas derivatives for the comparative period, partially offset by lower expenses. See Note 3 for additional information.
Net Loss
Net loss decreased by approximately $2.6 billion to approximately $2.2 billion for the year ended December 31, 2016, from approximately $4.8 billion for the year ended December 31, 2015. The decrease was primarily due to lower impairment charges and lower expenses, including interest, partially offset by losses compared to gains on oil and natural gas derivatives for the comparative period, higher loss from discontinued operations, the gain on extinguishment of debt in 2015 and lower production revenues. See discussion above for explanations of variances.
50
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Results of Operations
Year Ended December 31, 2015, Compared to Year Ended December 31, 2014
Year Ended December 31, | |||||||||||
2015 | 2014 | Variance | |||||||||
(in thousands) | |||||||||||
Revenues and other: | |||||||||||
Natural gas sales | $ | 512,538 | $ | 768,504 | $ | (255,966 | ) | ||||
Oil sales | 519,968 | 1,149,444 | (629,476 | ) | |||||||
NGL sales | 118,734 | 394,189 | (275,455 | ) | |||||||
Total oil, natural gas and NGL sales | 1,151,240 | 2,312,137 | (1,160,897 | ) | |||||||
Gains on oil and natural gas derivatives | 1,027,014 | 1,127,395 | (100,381 | ) | |||||||
Marketing and other revenues (1) | 141,759 | 198,735 | (56,976 | ) | |||||||
2,320,013 | 3,638,267 | (1,318,254 | ) | ||||||||
Expenses: | |||||||||||
Lease operating expenses | 375,840 | 443,157 | (67,317 | ) | |||||||
Transportation expenses | 167,561 | 165,489 | 2,072 | ||||||||
Marketing expenses | 35,278 | 81,210 | (45,932 | ) | |||||||
General and administrative expenses (2) | 285,996 | 274,006 | 11,990 | ||||||||
Exploration costs | 9,473 | 125,037 | (115,564 | ) | |||||||
Depreciation, depletion and amortization | 554,386 | 771,549 | (217,163 | ) | |||||||
Impairment of long-lived assets | 4,960,144 | 2,050,387 | 2,909,757 | ||||||||
Taxes, other than income taxes | 111,302 | 169,695 | (58,393 | ) | |||||||
Gains on sale of assets and other, net | (195,490 | ) | (487,286 | ) | 291,796 | ||||||
6,304,490 | 3,593,244 | 2,711,246 | |||||||||
Other income and (expenses) | 233,450 | (515,060 | ) | 748,510 | |||||||
Loss from continuing operations before income taxes | (3,751,027 | ) | (470,037 | ) | (3,280,990 | ) | |||||
Income tax expense (benefit) | (6,393 | ) | 4,368 | (10,761 | ) | ||||||
Loss from continuing operations | (3,744,634 | ) | (474,405 | ) | (3,270,229 | ) | |||||
Income (loss) from discontinued operations, net of income taxes | (1,015,177 | ) | 22,596 | (1,037,773 | ) | ||||||
Net loss | $ | (4,759,811 | ) | $ | (451,809 | ) | $ | (4,308,002 | ) | ||
(1) | For the years ended December 31, 2015, and December 31, 2014, approximately $78 million and $86 million, respectively, of general and administrative expenses were incurred by Berry through a management fee charged by the Company. Management fee revenues are included in “other revenues” on the consolidated statements of operations. |
(2) | General and administrative expenses for the years ended December 31, 2015, and December 31, 2014, include approximately $47 million and $45 million, respectively, of noncash unit-based compensation expenses. In addition, general and administrative expenses for the years ended December 31, 2015, and December 31, 2014, include costs incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
51
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Year Ended December 31, | ||||||||||
2015 | 2014 | Variance | ||||||||
Average daily production: | ||||||||||
Natural gas (MMcf/d) | 549 | 492 | 12 | % | ||||||
Oil (MBbls/d) | 32.4 | 36.2 | (10 | )% | ||||||
NGL (MBbls/d) | 25.7 | 31.7 | (19 | )% | ||||||
Total (MMcfe/d) | 897 | 900 | — | |||||||
Weighted average prices: (1) | ||||||||||
Natural gas (Mcf) | $ | 2.56 | $ | 4.28 | (40 | )% | ||||
Oil (Bbl) | $ | 44.00 | $ | 87.00 | (49 | )% | ||||
NGL (Bbl) | $ | 12.68 | $ | 34.07 | (63 | )% | ||||
Average NYMEX prices: | ||||||||||
Natural gas (MMBtu) | $ | 2.66 | $ | 4.41 | (40 | )% | ||||
Oil (Bbl) | $ | 48.80 | $ | 93.00 | (48 | )% | ||||
Costs per Mcfe of production: | ||||||||||
Lease operating expenses | $ | 1.15 | $ | 1.35 | (15 | )% | ||||
Transportation expenses | $ | 0.51 | $ | 0.50 | 2 | % | ||||
General and administrative expenses (2) | $ | 0.87 | $ | 0.83 | 5 | % | ||||
Depreciation, depletion and amortization | $ | 1.69 | $ | 2.35 | (28 | )% | ||||
Taxes, other than income taxes | $ | 0.34 | $ | 0.52 | (35 | )% | ||||
Average daily production – discontinued operations: | ||||||||||
Total (MMcfe/d) | 291 | 310 | (6 | )% | ||||||
(1) | Does not include the effect of gains (losses) on derivatives. |
(2) | General and administrative expenses for the years ended December 31, 2015, and December 31, 2014, include approximately $47 million and $45 million, respectively, of noncash unit-based compensation expenses. In addition, general and administrative expenses for the years ended December 31, 2015, and December 31, 2014, include costs incurred by LINN Energy associated with the operations of Berry. On February 28, 2017, LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities. |
52
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Revenues and Other
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales decreased by approximately $1.1 billion or 50% to approximately $1.2 billion for the year ended December 31, 2015, from approximately $2.3 billion for the year ended December 31, 2014, due to lower oil, natural gas and NGL prices and lower production volumes. Lower oil, natural gas and NGL prices resulted in a decrease in revenues of approximately $508 million, $345 million and $200 million, respectively.
Average daily production volumes decreased to approximately 897 MMcfe/d for the year ended December 31, 2015, from approximately 900 MMcfe/d for the year ended December 31, 2014. Lower oil and NGL production volumes resulted in a decrease in revenues of approximately $121 million and $75 million, respectively. Higher natural gas production volumes resulted in an increase in revenues of approximately $89 million.
The following table sets forth average daily production by region:
Year Ended December 31, | |||||||||||
2015 | 2014 | Variance | |||||||||
Average daily production (MMcfe/d): | |||||||||||
Rockies | 359 | 241 | 118 | 49 | % | ||||||
Hugoton Basin | 193 | 164 | 29 | 18 | % | ||||||
Mid-Continent | 100 | 287 | (187 | ) | (65 | )% | |||||
Permian Basin | 80 | 110 | (30 | ) | (27 | )% | |||||
TexLa | 72 | 38 | 34 | 92 | % | ||||||
South Texas | 32 | 12 | 20 | 172 | % | ||||||
Michigan/Illinois | 31 | 33 | (2 | ) | (5 | )% | |||||
California | 30 | 15 | 15 | 102 | % | ||||||
897 | 900 | (3 | ) | — | |||||||
The increase in average daily production volumes in the Rockies region primarily reflects the impact of the acquisition of properties from subsidiaries of Devon Energy Corporation (“Devon” and the acquisition, the “Devon Assets Acquisition”) on August 29, 2014, and development capital spending. The increase in average daily production volumes in the Hugoton Basin region primarily reflects the impact of the properties received in the exchange with Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc. (“Exxon XTO”) on August 15, 2014, and the acquisition of properties from Pioneer Natural Resources Company (“Pioneer”) on September 11, 2014. The decrease in average daily production volumes in the Mid-Continent region primarily reflects lower production volumes as a result of the properties sold to privately held institutional affiliates of EnerVest, Ltd. and its joint venture partner FourPoint Energy, LLC (“Granite Wash Assets Sale”) on December 15, 2014, partially offset by the impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Permian Basin region primarily reflects lower production volumes as a result of the properties relinquished in the two exchanges with Exxon XTO and ExxonMobil, as well as the Howard County Assets Sale on August 31, 2015. The increase in average daily production volumes in the TexLa region primarily reflects the impact of the Devon Assets Acquisition. The increase in average daily production volumes in the South Texas region reflects the full year impact of the Devon Assets Acquisition. The decrease in average daily production volumes in the Michigan/Illinois region primarily reflects a low-decline asset base with minimal development capital spending. The increase in average daily production volumes in the California region primarily reflects the impact of the properties received in the exchange with Exxon Mobil Corporation (“ExxonMobil”) on November 21, 2014, and development capital spending.
Gains (Losses) on Oil and Natural Gas Derivatives
Gains on oil and natural gas derivatives were approximately $1.0 billion and $1.1 billion for the years ended December 31, 2015, and December 31, 2014, respectively, representing a decrease of approximately $100 million. Gains on oil and natural gas derivatives decreased primarily due to changes in fair value of the derivative contracts. The results for 2015 also include cash settlements of approximately $5 million related to canceled derivatives contracts. In addition, the results for 2015 and 2014 include gains of approximately $4 million and $7 million, respectively, related to the recoveries of a bankruptcy claim. The fair value on unsettled derivatives contracts changes as future commodity price expectations change compared to the
53
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
contract prices on the derivatives. If the expected future commodity prices increase compared to the contract prices on the derivatives, losses are recognized; and if the expected future commodity prices decrease compared to the contract prices on the derivatives, gains are recognized.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” and Note 7 and Note 8 for additional details about the Company’s commodity derivatives. For information about the Company’s credit risk related to derivative contracts, see “Counterparty Credit Risk” under “Liquidity and Capital Resources” below.
Marketing and Other Revenues
Marketing revenues represent third-party activities associated with company-owned gathering systems, plants and facilities. Other revenues primarily include management fee revenues charged to Berry by the Company and helium sales revenue. Marketing and other revenues decreased by approximately $57 million or 29% to approximately $142 million for the year ended December 31, 2015, from approximately $199 million for the year ended December 31, 2014. The decrease was primarily due to lower management fee revenues charged to Berry by the Company, principally driven by reduced salaries and benefits related expenses at the Company, as well as lower revenues generated by the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms, partially offset by higher helium sales revenue in the Hugoton Basin.
Expenses
Lease Operating Expenses
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies, and workover expenses. Lease operating expenses decreased by approximately $67 million or 15% to approximately $376 million for the year ended December 31, 2015, from approximately $443 million for the year ended December 31, 2014. The decrease was primarily due to cost savings initiatives and lower costs as a result of the properties sold during the fourth quarter of 2014, partially offset by costs associated with properties acquired during the third quarter of 2014. Lease operating expenses per Mcfe also decreased to $1.15 per Mcfe for the year ended December 31, 2015, from $1.35 per Mcfe for the year ended December 31, 2014.
Transportation Expenses
Transportation expenses increased by approximately $3 million or 1% to approximately $168 million for the year ended December 31, 2015, from approximately $165 million for the year ended December 31, 2014. The increase was primarily due to costs associated with properties acquired during the third quarter of 2014 partially offset by lower costs as a result of the properties sold during the fourth quarter of 2014. Transportation expenses per Mcfe also increased to $0.51 per Mcfe for the year ended December 31, 2015, from $0.50 per Mcfe for the year ended December 31, 2014.
Marketing Expenses
Marketing expenses represent third-party activities associated with company-owned gathering systems, plants and facilities. Marketing expenses decreased by approximately $46 million or 57% to approximately $35 million for the year ended December 31, 2015, from approximately $81 million for the year ended December 31, 2014. The decrease was primarily due to lower expenses associated with the Jayhawk natural gas processing plant in Kansas, principally driven by a change in contract terms.
General and Administrative Expenses
General and administrative expenses are costs not directly associated with field operations and reflect the costs of employees including executive officers, related benefits, office leases and professional fees. In addition, general and administrative expenses for the years ended December 31, 2015, and December 31, 2014, include costs incurred by LINN Energy associated with the operations of Berry. General and administrative expenses increased by approximately $12 million or 4% to approximately $286 million for the year ended December 31, 2015, from approximately $274 million for the year ended December 31, 2014. The increase was primarily due to higher advisory fees related to the alliance agreements partially offset by lower acquisition expenses. General and administrative expenses per Mcfe also increased to $0.87 per Mcfe for the year ended December 31, 2015, from $0.83 per Mcfe for the year ended December 31, 2014.
54
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Exploration Costs
Exploration costs decreased by approximately $116 million to approximately $9 million for the year ended December 31, 2015, from approximately $125 million for the year ended December 31, 2014. The decrease was primarily due to lower leasehold impairment expenses on unproved properties.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased by approximately $218 million or 28% to approximately $554 million for the year ended December 31, 2015, from approximately $772 million for the year ended December 31, 2014. The decrease was primarily due to the divestitures of properties in 2014 with higher rates compared to the rates of properties acquired in 2014, lower rates as a result of the impairments recorded in 2014 and the first and third quarters of 2015. Depreciation, depletion and amortization per Mcfe also decreased to $1.69 per Mcfe for the year ended December 31, 2015, from $2.35 per Mcfe for the year ended December 31, 2014.
Impairment of Long-Lived Assets
The Company recorded the following noncash impairment charges associated with proved and unproved oil and natural gas properties:
Year Ended December 31, | |||||||
2015 | 2014 | ||||||
(in thousands) | |||||||
Hugoton Basin region | $ | 1,667,768 | $ | — | |||
Rockies region | 1,592,256 | 332,365 | |||||
Mid-Continent region | 405,370 | 244,413 | |||||
TexLa region | 352,422 | 4,836 | |||||
Permian Basin region | 71,990 | 1,337,444 | |||||
South Texas region | 42,433 | 131,329 | |||||
Proved oil and natural gas properties | 4,132,239 | 2,050,387 | |||||
TexLa region | 416,846 | — | |||||
Permian Basin region | 226,922 | — | |||||
Rockies region | 184,137 | — | |||||
Unproved oil and natural gas properties | 827,905 | — | |||||
Impairment of long-lived assets | $ | 4,960,144 | $ | 2,050,387 | |||
The impairment charges in 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The impairment charges in 2014 include approximately $1.4 billion due to a steep decline in commodity prices during the fourth quarter of 2014 and approximately $603 million due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for proved oil and natural gas properties.
(Gains) Losses on Sale of Assets and Other, Net
During the year ended December 31, 2015, the Company recorded a net gain of approximately $177 million, including costs to sell of approximately $1 million, on the Howard County Assets Sale. During the year ended December 31, 2014, the Company recorded the following net gains and losses on divestitures and exchanges of properties:
• | Net gain of approximately $294 million, including costs to sell of approximately $10 million, on the Granite Wash Assets Sale; |
• | Net gain of approximately $50 million, including costs to sell of approximately $3 million, on the noncash exchange of a portion of its Permian Basin properties to ExxonMobil for properties in California’s South Belridge Field; |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
• | Net gain of approximately $99 million, including costs to sell of approximately $3 million, on the noncash exchange of a portion of its Permian Basin properties to Exxon XTO for properties in the Hugoton Basin; and |
• | Net gain of approximately $36 million on the sale of the Company’s interests in certain non-producing oil and natural gas properties located in the Mid-Continent region. |
See Note 3 for additional details of divestitures and exchanges of properties.
Taxes, Other Than Income Taxes
Year Ended December 31, | |||||||||||
2015 | 2014 | Variance | |||||||||
(in thousands) | |||||||||||
Severance taxes | $ | 53,752 | $ | 108,820 | $ | (55,068 | ) | ||||
Ad valorem taxes | 54,388 | 60,136 | (5,748 | ) | |||||||
California carbon allowances | 3,210 | 461 | 2,749 | ||||||||
Other | (48 | ) | 278 | (326 | ) | ||||||
$ | 111,302 | $ | 169,695 | $ | (58,393 | ) | |||||
Taxes, other than income taxes decreased by approximately $58 million or 34% for the year ended December 31, 2015, compared to the year ended December 31, 2014. Severance taxes, which are a function of revenues generated from production, decreased primarily due to lower oil, natural gas and NGL prices. Ad valorem taxes, which are based on the value of reserves and production equipment and vary by location, decreased primarily due to lower estimated valuations on certain of the Company’s properties, partially offset by acquisitions completed during the third quarter of 2014. California carbon allowances increased primarily due to an increase in estimated emissions for which credits are needed and higher costs for acquired allowances.
Other Income and (Expenses)
Year Ended December 31, | |||||||||||
2015 | 2014 | Variance | |||||||||
(in thousands) | |||||||||||
Interest expense, net of amounts capitalized | $ | (460,635 | ) | $ | (499,890 | ) | $ | 39,255 | |||
Gain on extinguishment of debt | 708,050 | — | 708,050 | ||||||||
Other, net | (13,965 | ) | (15,170 | ) | 1,205 | ||||||
$ | 233,450 | $ | (515,060 | ) | $ | 748,510 | |||||
Other income and (expenses) decreased by approximately $749 million for the year ended December 31, 2015, compared to the year ended December 31, 2014. Interest expense decreased primarily due to lower outstanding debt during the period and lower amortization of financing fees and expenses primarily related to the bridge loan and term loan that were repaid during 2014 and senior notes that were repurchased during 2015, partially offset by a decrease in capitalized interest. In addition, for the year ended December 31, 2015, the Company recorded a gain on extinguishment of debt of approximately $708 million as a result of the repurchases of a portion of its senior notes and the exchange of a portion of its senior notes for the Second Lien Notes. Other expenses decreased during 2015 primarily due to lower write-offs of deferred financing fees related to the LINN Credit Facility. See “Debt” under “Liquidity and Capital Resources” below for additional details.
Income Tax Expense (Benefit)
Prior to the consummation of the LINN Plan, the Company was a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. The Company recognized an income tax benefit of approximately $6 million for the year ended December 31, 2015, compared to income tax expense of approximately $4 million for the year ended December 31, 2014. The income tax benefit was primarily due to lower income from the Company’s taxable subsidiaries in 2015 compared to 2014.
Income (Loss) from Discontinued Operations, Net of Income Taxes
Berry was deconsolidated effective December 3, 2016, and its results of operations are reported as discontinued operations for all periods presented. Loss from discontinued operations, net of income taxes increased by approximately $1.0 billion to a loss of approximately $1.0 billion for the year ended December 31, 2015, from income of approximately $23 million for the year ended December 31, 2014. The increase was primarily due to higher impairment charges, lower production revenues and lower gains on oil and natural gas derivatives, partially offset by lower expenses. See Note 3 for additional information.
Net Loss
Net loss increased by approximately $4.3 billion to approximately $4.8 billion for the year ended December 31, 2015, from approximately $452 million for the year ended December 31, 2014. The increase was primarily due to higher impairment charges, lower production revenues, the loss compared to income from discontinued operations for the comparative period and lower gains on oil and natural gas derivatives, partially offset by the gain on extinguishment of debt and lower expenses, including interest. See discussion above for explanations of variances.
Liquidity and Capital Resources
In order to decrease the Company’s level of indebtedness and maintain the Company’s liquidity at levels sufficient to meet its commitments, the Company undertook a number of actions, including minimizing capital expenditures and further reducing its recurring operating expenses. Despite taking these actions, the Company did not have sufficient liquidity to satisfy its debt service obligations, meet other financial obligations and comply with its debt covenants. As a result, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code. Based on current expectations of the reorganized Company upon its emergence from bankruptcy, the Company believes its liquidity and capital resources will be sufficient to conduct its business and operations.
Historically, the Company has utilized funds from debt and equity offerings, borrowings under its Credit Facilities and net cash provided by operating activities for capital resources and liquidity, and the primary use of capital has been for acquisitions and the development of oil and natural gas properties. For the year ended December 31, 2016, the Company’s total capital expenditures were approximately $173 million.
See below for details regarding capital expenditures for the periods presented:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Oil and natural gas | $ | 126,127 | $ | 317,957 | $ | 926,394 | |||||
Plant and pipeline | 38,384 | 2,539 | 12,851 | ||||||||
Other | 8,222 | 45,610 | 42,621 | ||||||||
Capital expenditures, excluding acquisitions | $ | 172,733 | $ | 366,106 | $ | 981,866 | |||||
Capital expenditures, excluding acquisitions – discontinued operations | $ | 22,019 | $ | 151,589 | $ | 574,068 | |||||
For 2017, the Company estimates its total capital expenditures, excluding acquisitions, will be approximately $395 million, including approximately $300 million related to its oil and natural gas capital program and approximately $84 million related to its plant and pipeline capital. This estimate is under continuous review and subject to ongoing adjustments.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Statements of Cash Flows
The following is a comparative cash flow summary:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Net cash: | |||||||||||
Provided by operating activities | $ | 880,514 | $ | 1,249,457 | $ | 1,711,890 | |||||
Used in investing activities | (235,840 | ) | (310,417 | ) | (2,021,025 | ) | |||||
Provided by (used in) financing activities | 48,015 | (938,681 | ) | 258,773 | |||||||
Net increase (decrease) in cash and cash equivalents | $ | 692,689 | $ | 359 | $ | (50,362 | ) | ||||
Operating Activities
Cash provided by operating activities for the year ended December 31, 2016, was approximately $881 million, compared to approximately $1.2 billion for the year ended December 31, 2015. The decrease was primarily due to lower cash settlements on derivatives and lower production related revenues principally due to lower commodity prices and lower production volumes, partially offset by lower expenses.
Cash provided by operating activities for the year ended December 31, 2015, was approximately $1.2 billion, compared to approximately $1.7 billion for the year ended December 31, 2014. The decrease was primarily due to lower production related revenues principally due to lower commodity prices, partially offset by higher cash settlements on derivatives.
Investing Activities
The following provides a comparative summary of cash flow from investing activities:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Cash flow from investing activities: | |||||||||||
Deconsolidation of Berry Petroleum Company, LLC | $ | (28,549 | ) | $ | — | $ | — | ||||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | — | — | (2,475,315 | ) | |||||||
Capital expenditures | (225,748 | ) | (625,223 | ) | (1,124,465 | ) | |||||
Investment in discontinued operations | — | (132,332 | ) | (100,921 | ) | ||||||
Proceeds from sale of properties and equipment and other | (4,690 | ) | 345,770 | 2,195,898 | |||||||
Net cash used in investing activities – continuing operations | (258,987 | ) | (411,785 | ) | (1,504,803 | ) | |||||
Net cash provided by (used in) investing activities – discontinued operations | 23,147 | 101,368 | (516,222 | ) | |||||||
Net cash used in investing activities | $ | (235,840 | ) | $ | (310,417 | ) | $ | (2,021,025 | ) | ||
The primary use of cash in investing activities is for capital spending, including acquisitions and the development of the Company’s oil and natural gas properties. Berry was deconsolidated effective December 3, 2016, and its cash flows are reported as discontinued operations for all periods presented. The Company made no acquisitions of properties during 2016 or 2015. During 2014, the Company made two significant cash acquisitions of properties from Pioneer and Devon. See Note 3 for additional details of acquisitions. Capital expenditures decreased during 2016 and 2015 primarily due to lower spending on development activities throughout the Company’s various operating regions as a result of continued low commodity prices.
Proceeds from the sale of properties and equipment and other for the year ended December 31, 2015, include approximately $276 million in net cash proceeds received from the Howard County Assets Sale in August 2015. Proceeds from the sale of
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
properties and equipment and other for the year ended December 31, 2014, include approximately $1.8 billion in net cash proceeds received from the Granite Wash Assets Sale. See Note 3 for additional details of divestitures.
Financing Activities
Cash provided by financing activities for the year ended December 31, 2016, was approximately $48 million compared to cash used in financing activities of approximately $939 million for the year ended December 31, 2015. During the year ended December 31, 2016, the Company borrowed approximately $979 million under the LINN Credit Facility, including approximately $919 million in February 2016 which represented the remaining undrawn amount that was available. In addition, during the year ended December 31, 2016, the Company repaid approximately $913 million under the LINN Credit Facility and term loan, primarily using the net cash proceeds from canceled derivative contracts (see Note 7). Cash provided by financing activities for the year ended December 31, 2014, was approximately $259 million. Financing cash flow needs decreased during 2015 primarily due to reduced capital expenditures and acquisition activity for the year ended December 31, 2015, as compared to the year ended December 31, 2014.
The following provides a comparative summary of proceeds from borrowings and repayments of debt:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Proceeds from borrowings: | |||||||||||
LINN Credit Facility | $ | 978,500 | $ | 1,445,000 | $ | 2,540,000 | |||||
Senior notes | — | — | 1,100,024 | ||||||||
Bridge loan and term loans | — | — | 2,300,000 | ||||||||
$ | 978,500 | $ | 1,445,000 | $ | 5,940,024 | ||||||
Repayments of debt: | |||||||||||
LINN Credit Facility | $ | (814,298 | ) | $ | (1,275,000 | ) | $ | (2,305,000 | ) | ||
Senior notes | — | (553,461 | ) | — | |||||||
Bridge loan and term loan | (98,911 | ) | — | (2,300,000 | ) | ||||||
$ | (913,209 | ) | $ | (1,828,461 | ) | $ | (4,605,000 | ) | |||
See Note 15 for details about the Company’s borrowings and repayments of debt that were reflected as noncash transactions.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Debt
The following summarizes the Company’s outstanding debt:
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands, except percentages) | |||||||
LINN credit facility | $ | 1,654,745 | $ | 2,215,000 | |||
Berry credit facility | — | 873,175 | |||||
Term loan | 284,241 | 500,000 | |||||
6.50% senior notes due May 2019 | 562,234 | 562,234 | |||||
6.25% senior notes due November 2019 | 581,402 | 581,402 | |||||
8.625% senior notes due April 2020 | 718,596 | 718,596 | |||||
6.75% Berry senior notes due November 2020 | — | 261,100 | |||||
12.00% senior secured second lien notes due December 2020 (1) | 1,000,000 | 1,000,000 | |||||
Interest payable on senior secured second lien notes due December 2020 (1) | — | 608,333 | |||||
7.75% senior notes due February 2021 | 779,474 | 779,474 | |||||
6.50% senior notes due September 2021 | 381,423 | 381,423 | |||||
6.375% Berry senior notes due September 2022 | — | 572,700 | |||||
Net unamortized discounts and premiums (2) | — | (8,694 | ) | ||||
Net unamortized deferred financing fees (2) | (1,257 | ) | (37,374 | ) | |||
Total debt, net | 5,960,858 | 9,007,369 | |||||
Less current portion, net (3) | (1,937,729 | ) | (2,841,518 | ) | |||
Less liabilities subject to compromise (4) | (4,023,129 | ) | — | ||||
Less debt and unamortized premiums of discontinued operations | — | (1,718,543 | ) | ||||
Long-term debt, net | $ | — | $ | 4,447,308 | |||
(1) | The issuance of the Second Lien Notes was accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. During the year ended December 31, 2016, $551 million was written off to reorganization items in connection with the filing of the Bankruptcy Petitions. The remaining amount of approximately $57 million was classified as liabilities subject to compromise at December 31, 2016. |
(2) | Approximately $52 million in net discounts, premiums and deferred financing fees were written off to reorganization items in connection with the filing of the Bankruptcy Petitions. |
(3) | Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2016, and December 31, 2015. The current portion as of December 31, 2015, also includes approximately $128 million of interest payable on the Second Lien Notes due within one year. |
(4) | The Company’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. |
As described in Note 3, the Company deconsolidated Berry effective December 3, 2016. Therefore, the Company reports no Berry debt as of December 31, 2016.
As of February 28, 2017, total borrowings outstanding under the Exit Facility were approximately $900 million, and there was approximately $793 million remaining available borrowing capacity (which includes a $7 million reduction for outstanding letters of credit). As of December 31, 2016, there was no remaining available borrowing capacity under the LINN Credit Facility. Pursuant to the terms of the LINN Plan, on the Effective Date, all obligations under the LINN Credit Facility were canceled.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
During the year ended December 31, 2015, the Company repurchased, through privately negotiated transactions and on the open market, approximately $927 million of its outstanding senior notes as follows:
• | 6.50% senior notes due May 2019 – $53 million; |
• | 6.25% senior notes due November 2019 – $395 million; |
• | 8.625% senior notes due April 2020 – $295 million; |
• | 7.75% senior notes due February 2021 – $36 million; and |
• | 6.50% senior notes due September 2021 – $148 million. |
In connection, with the repurchases, the Company paid approximately $553 million in cash.
For additional information related to the Company’s outstanding debt, see Note 6.
Contingencies
See Item 3. “Legal Proceedings” for information regarding legal proceedings that the Company is party to and any contingencies related to these legal proceedings.
Commitments and Contractual Obligations
For information related to the Company’s emergence from bankruptcy and the terms of the Exit Facility, see “Executive Overview” above. The following is a summary of the Company’s commitments and contractual obligations as of December 31, 2016:
Payments Due | ||||||||||||||||||||
Contractual Obligations | Total | 2017 | 2018 – 2019 | 2020 – 2021 | 2022 and Beyond | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Debt obligations: | ||||||||||||||||||||
Credit facility (1) | $ | 1,654,745 | $ | 1,654,745 | $ | — | $ | — | $ | — | ||||||||||
Term loan (1) | 284,241 | 284,241 | — | — | — | |||||||||||||||
Second lien notes (2) | 1,000,000 | — | — | 1,000,000 | — | |||||||||||||||
Senior notes | 3,023,129 | — | 1,143,636 | 1,879,493 | — | |||||||||||||||
Interest (3) | 1,507,337 | 446,708 | 776,991 | 283,638 | — | |||||||||||||||
Operating lease obligations: | ||||||||||||||||||||
Office, property and equipment leases | 9,019 | 3,627 | 4,860 | 472 | 60 | |||||||||||||||
Other: | ||||||||||||||||||||
Commodity derivatives | 93,857 | 82,508 | 11,349 | — | — | |||||||||||||||
Asset retirement obligations | 402,162 | 9,686 | 12,704 | 14,791 | 364,981 | |||||||||||||||
Other | 961 | 61 | 122 | 122 | 656 | |||||||||||||||
$ | 7,975,451 | $ | 2,481,576 | $ | 1,949,662 | $ | 3,178,516 | $ | 365,697 | |||||||||||
(1) | The contractual maturity date for the LINN Credit Facility and term loan was April 2019; however, the LINN Credit Facility and term loan were subject to springing maturities based on the maturity of any outstanding LINN Energy junior lien debt. Due to covenant violations, the LINN Credit Facility and term loan were classified as current at December 31, 2016. |
(2) | The contractual maturity date for the Second Lien Notes is December 2020; however, these notes were subject to a springing maturity based on the maturity of any outstanding LINN Energy unsecured debt. |
(3) | Represents interest on the LINN Credit Facility and term loan computed at 5.50% through contractual maturity in April 2019. Interest on the December 2020 Second Lien Notes computed at a fixed rate of 12.00%. Interest on the May 2019 senior notes, November 2019 senior notes, April 2020 senior notes, February 2021 senior notes and September 2021 senior notes computed at fixed rates of 6.50%, 6.25%, 8.625%, 7.75% and 6.50%, respectively. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Counterparty Credit Risk
The Company accounts for its commodity derivatives at fair value. The Company’s counterparties are current participants or affiliates of participants in the LINN Credit Facility and the Exit Facility. The LINN Credit Facility was secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company was not required to post any collateral. The Company does not receive collateral from its counterparties. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
At-the-Market Offering Program
The Company’s Board of Directors had authorized the sale of up to $500 million of units under an at-the-market offering program, with sales of units, if any, to be made under an equity distribution agreement. No sales were made under the equity distribution agreement during the year ended December 31, 2016. During the year ended December 31, 2015, the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average price of $12.37 per unit for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional services expenses of approximately $459,000. The Company used the net proceeds for general corporate purposes, including the open market repurchases of a portion of its senior notes (see Note 6).
Public Offering of Units
In May 2015, the Company sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ($11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the LINN Credit Facility.
Distributions
Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor currently has no intention of paying cash dividends and any future payment of cash dividends would be subject to the restrictions in the Exit Facility.
Critical Accounting Policies and Estimates
The discussion and analysis of the Company’s financial condition and results of operations is based on the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these financial statements requires management of the Company to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors that are believed to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. Actual results may differ from these estimates and assumptions used in the preparation of the financial statements.
Below are expanded discussions of the Company’s more significant accounting policies, estimates and judgments, i.e., those that reflect more significant estimates and assumptions used in the preparation of its financial statements. See Note 1 for details about additional accounting policies and estimates made by Company management.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
Recently Issued Accounting Standards
For a discussion of recently issued accounting standards, see Note 1.
Oil and Natural Gas Reserves
Proved reserves are based on the quantities of oil, natural gas and NGL that 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, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The independent engineering firm, DeGolyer and MacNaughton, prepared a reserve and economic evaluation of all of the Company properties on a well-by-well basis as of December 31, 2016, and the reserve estimates reported herein were prepared by DeGolyer and MacNaughton. The reserve estimates were reviewed and approved by the Company’s senior engineering staff and management, with final approval by its Executive Vice President and Chief Operating Officer.
Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The process performed by the independent engineers to prepare reserve amounts included their estimation of reserve quantities, future production rates, future net revenue and the present value of such future net revenue, based in part on data provided by the Company. The estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years.
The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. In addition, reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, natural gas and NGL eventually recovered. For additional information regarding estimates of reserves, including the standardized measure of discounted future net cash flows, see “Supplemental Oil and Natural Gas Data (Unaudited)” in Item 8. “Financial Statements and Supplementary Data” and see also Item 1. “Business.”
Oil and Natural Gas Properties
Proved Properties
The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use.
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the
63
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
product of a process that begins with New York Mercantile Exchange forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.
Based on the analysis described above, for the years ended December 31, 2016, December 31, 2015, and December 31, 2014, the Company recorded noncash impairment charges of approximately $165 million, $4.1 billion and $2.1 billion, respectively, associated with proved oil and natural gas properties. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Unproved Properties
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past.
Based on the analysis described above, for the year ended December 31, 2015, the Company recorded noncash impairment charges of approximately $828 million associated with unproved oil and natural gas properties. The Company recorded no impairment charges associated with unproved properties for the years ended December 31, 2016, or December 31, 2014. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Exploration Costs
Exploratory geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded no leasehold impairment expenses related to unproved properties during the year ended December 31, 2016. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million and $125 million for the years ended December 31, 2015, and December 31, 2014, respectively, which are included in “exploration costs” on the consolidated statements of operations.
Revenue Recognition
Sales of oil, natural gas and NGL are recognized when the product 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. In addition, the Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses.
Derivative Instruments
Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials.
64
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Continued
The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes.
A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date.
Derivative instruments are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments. See Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” for sensitivity analysis regarding the Company’s derivative financial instruments.
Acquisition Accounting
The Company accounts for business combinations under the acquisition method of accounting (see Note 3). Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred. Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill while any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. In addition, when appropriate, the Company reviews comparable purchases and sales of oil and natural gas properties within the same regions, and uses that data as a proxy for fair market value; i.e., the amount a willing buyer and seller would enter into in exchange for such properties.
While the estimated fair values of the assets acquired and liabilities assumed have no effect on cash flow, they can have an effect on future results of operations. Generally, higher fair values assigned to oil and natural gas properties result in higher future depreciation, depletion and amortization expense, which results in decreased future net income. Also, a higher fair value assigned to oil and natural gas properties, based on higher future estimates of commodity prices, could increase the likelihood of impairment in the event of lower commodity prices or higher operating costs than those originally used to determine fair value. The recording of impairment expense has no effect on cash flow but results in a decrease in net income for the period in which the impairment is recorded.
65
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Company’s primary market risks are attributable to fluctuations in commodity prices and interest rates. These risks can affect the Company’s business, financial condition, operating results and cash flows. See below for quantitative and qualitative information about these risks.
The following should be read in conjunction with the financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The reference to a “Note” herein refers to the accompanying Notes to Consolidated Financial Statements contained in Item 8. “Financial Statements and Supplementary Data.”
Commodity Price Risk
The Company’s most significant market risk relates to prices of oil, natural gas and NGL. The Company expects commodity prices to remain volatile and unpredictable. As commodity prices decline or rise significantly, revenues and cash flows are likewise affected. In addition, future declines in commodity prices may result in noncash write-downs of the Company’s carrying amounts of its assets.
Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The Company does not enter into derivative contracts for trading purposes. The appropriate level of production to be hedged is an ongoing consideration based on a variety of factors, including among other things, current and future expected commodity market prices, the Company’s overall risk profile, including leverage and size and scale considerations, as well as any requirements for or restrictions on levels of hedging contained in any credit facility or other debt instrument applicable at the time. In addition, when commodity prices are depressed and forward commodity price curves are flat or in backwardation, the Company may determine that the benefit of hedging its anticipated production at these levels is outweighed by its resultant inability to obtain higher revenues for its production if commodity prices recover during the duration of the contracts. As a result, the appropriate percentage of production volumes to be hedged may change over time.
In April 2016 and May 2016, in connection with the Company’s restructuring efforts, LINN Energy canceled (prior to the contract settlement dates) all of its then-outstanding derivative contracts for net proceeds of approximately $1.2 billion. The net proceeds were used to make permanent repayments of a portion of the borrowings outstanding under the LINN Credit Facility.
At December 31, 2016, the fair value of fixed price swaps and collars was a net liability of approximately $85 million. A 10% increase in the index oil and natural gas prices above the December 31, 2016, prices would result in a net liability of approximately $183 million, which represents a decrease in the fair value of approximately $98 million; conversely, a 10% decrease in the index oil and natural gas prices below the December 31, 2016, prices would result in a net asset of approximately $13 million, which represents an increase in the fair value of approximately $98 million.
At December 31, 2015, the fair value of fixed price swaps and put option contracts was a net asset of approximately $1.7 billion. A 10% increase in the index oil and natural gas prices above the December 31, 2015, prices would result in a net asset of approximately $1.5 billion, which represents a decrease in the fair value of approximately $190 million; conversely, a 10% decrease in the index oil and natural gas prices below the December 31, 2015, prices would result in a net asset of approximately $1.9 billion, which represents an increase in the fair value of approximately $190 million.
The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets.
The prices of oil, natural gas and NGL have been extremely volatile, and the Company expects this volatility to continue. Prices for these commodities may fluctuate widely in response to relatively minor changes in the supply of and demand for such commodities, market uncertainty and a variety of additional factors that are beyond its control. Actual gains or losses recognized related to the Company’s derivative contracts depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts. Additionally, the Company cannot be assured that its counterparties will be able to perform under its derivative contracts. If a counterparty fails to perform and the derivative arrangement is terminated, the Company’s cash flows could be impacted.
66
Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Continued
Interest Rate Risk
At December 31, 2016, the Company had debt outstanding under its credit facility and term loan of approximately $1.9 billion which incurred interest at floating rates. A 1% increase in the respective market rates would result in an estimated $19 million increase in annual interest expense.
At December 31, 2015, the Company had debt outstanding under its credit facility and term loan of approximately $2.7 billion which incurred interest at floating rates. A 1% increase in the respective market rates would result in an estimated $27 million increase in annual interest expense.
67
Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page | |
68
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate.
As of December 31, 2016, our management assessed the effectiveness of the Company’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in Internal Control – Integrated Framework (2013) by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2016, based on those criteria.
/s/ Linn Energy, Inc.
69
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Linn Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Linn Energy, Inc. (formerly known as Linn Energy, LLC) and subsidiaries (Debtor-in-Possession) (the “Company”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, unitholders’ capital (deficit), and cash flows for each of the years in the three-year period ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated 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. 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 audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Linn Energy, Inc. and subsidiaries (Debtor-in-Possession) as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, the United States Bankruptcy Court for the Southern District of Texas confirmed the Company’s Plan of Reorganization (the “Plan”) on January 27, 2017. Confirmation of the Plan resulted in the discharge of debt of the Company and substantially altered rights and interests of debt and equity security holders as provided for in the Plan. The Plan was substantially consummated on February 28, 2017 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh-start accounting as of February 28, 2017.
/s/ KPMG LLP
Houston, Texas
March 23, 2017
70
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
CONSOLIDATED BALANCE SHEETS
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands, except unit amounts) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 694,857 | $ | 1,145 | |||
Accounts receivable – trade, net | 198,064 | 179,124 | |||||
Derivative instruments | — | 1,207,012 | |||||
Other current assets | 107,613 | 74,696 | |||||
Current assets of discontinued operations | — | 81,191 | |||||
Total current assets | 1,000,534 | 1,543,168 | |||||
Noncurrent assets: | |||||||
Oil and natural gas properties (successful efforts method) | 13,232,959 | 13,110,094 | |||||
Less accumulated depletion and amortization | (9,999,560 | ) | (9,501,327 | ) | |||
3,233,399 | 3,608,767 | ||||||
Other property and equipment | 636,487 | 597,216 | |||||
Less accumulated depreciation | (224,547 | ) | (183,139 | ) | |||
411,940 | 414,077 | ||||||
Derivative instruments | — | 566,401 | |||||
Other noncurrent assets | 14,718 | 24,182 | |||||
Noncurrent assets of discontinued operations | — | 3,780,285 | |||||
14,718 | 4,370,868 | ||||||
Total noncurrent assets | 3,660,057 | 8,393,712 | |||||
Total assets | $ | 4,660,591 | $ | 9,936,880 | |||
LIABILITIES AND UNITHOLDERS’ DEFICIT | |||||||
Current liabilities: | |||||||
Accounts payable and accrued expenses | $ | 295,077 | $ | 338,247 | |||
Derivative instruments | 82,508 | — | |||||
Current portion of long-term debt, net | 1,937,729 | 2,841,518 | |||||
Other accrued liabilities | 26,304 | 102,858 | |||||
Current liabilities of discontinued operations | — | 1,017,899 | |||||
Total current liabilities | 2,341,618 | 4,300,522 | |||||
Derivative instruments | 11,349 | 857 | |||||
Long-term debt, net | — | 4,447,308 | |||||
Other noncurrent liabilities | 399,607 | 399,676 | |||||
Liabilities subject to compromise | 4,305,005 | — | |||||
Noncurrent liabilities of discontinued operations | — | 1,057,418 | |||||
Commitments and contingencies (Note 11) | |||||||
Unitholders’ deficit: | |||||||
352,792,474 units and 355,017,428 units issued and outstanding at December 31, 2016, and December 31, 2015, respectively | 5,386,885 | 5,343,116 | |||||
Accumulated deficit | (7,783,873 | ) | (5,612,017 | ) | |||
(2,396,988 | ) | (268,901 | ) | ||||
Total liabilities and unitholders’ deficit | $ | 4,660,591 | $ | 9,936,880 | |||
The accompanying notes are an integral part of these consolidated financial statements.
71
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands, except per unit amounts) | |||||||||||
Revenues and other: | |||||||||||
Oil, natural gas and natural gas liquids sales | $ | 952,132 | $ | 1,151,240 | $ | 2,312,137 | |||||
Gains (losses) on oil and natural gas derivatives | (164,330 | ) | 1,027,014 | 1,127,395 | |||||||
Marketing revenues | 36,505 | 43,876 | 84,349 | ||||||||
Other revenues | 93,406 | 97,883 | 114,386 | ||||||||
917,713 | 2,320,013 | 3,638,267 | |||||||||
Expenses: | |||||||||||
Lease operating expenses | 317,046 | 375,840 | 443,157 | ||||||||
Transportation expenses | 161,037 | 167,561 | 165,489 | ||||||||
Marketing expenses | 29,736 | 35,278 | 81,210 | ||||||||
General and administrative expenses | 237,841 | 285,996 | 274,006 | ||||||||
Exploration costs | 4,080 | 9,473 | 125,037 | ||||||||
Depreciation, depletion and amortization | 404,237 | 554,386 | 771,549 | ||||||||
Impairment of long-lived assets | 165,044 | 4,960,144 | 2,050,387 | ||||||||
Taxes, other than income taxes | 74,838 | 111,302 | 169,695 | ||||||||
(Gains) losses on sale of assets and other, net | 15,558 | (195,490 | ) | (487,286 | ) | ||||||
1,409,417 | 6,304,490 | 3,593,244 | |||||||||
Other income and (expenses): | |||||||||||
Interest expense, net of amounts capitalized | (192,862 | ) | (460,635 | ) | (499,890 | ) | |||||
Gain on extinguishment of debt | — | 708,050 | — | ||||||||
Other, net | (1,536 | ) | (13,965 | ) | (15,170 | ) | |||||
(194,398 | ) | 233,450 | (515,060 | ) | |||||||
Reorganization items, net | 311,599 | — | — | ||||||||
Loss from continuing operations before income taxes | (374,503 | ) | (3,751,027 | ) | (470,037 | ) | |||||
Income tax expense (benefit) | 11,194 | (6,393 | ) | 4,368 | |||||||
Loss from continuing operations | (385,697 | ) | (3,744,634 | ) | (474,405 | ) | |||||
Income (loss) from discontinued operations, net of income taxes | (1,786,159 | ) | (1,015,177 | ) | 22,596 | ||||||
Net loss | $ | (2,171,856 | ) | $ | (4,759,811 | ) | $ | (451,809 | ) | ||
Loss per unit – continuing operations: | |||||||||||
Basic | $ | (1.10 | ) | $ | (10.91 | ) | $ | (1.47 | ) | ||
Diluted | $ | (1.10 | ) | $ | (10.91 | ) | $ | (1.47 | ) | ||
Income (loss) per unit – discontinued operations: | |||||||||||
Basic | $ | (5.06 | ) | $ | (2.96 | ) | $ | 0.07 | |||
Diluted | $ | (5.06 | ) | $ | (2.96 | ) | $ | 0.07 | |||
Net loss per unit: | |||||||||||
Basic | $ | (6.16 | ) | $ | (13.87 | ) | $ | (1.40 | ) | ||
Diluted | $ | (6.16 | ) | $ | (13.87 | ) | $ | (1.40 | ) | ||
Weighted average units outstanding: | |||||||||||
Basic | 352,653 | 343,323 | 328,918 | ||||||||
Diluted | 352,653 | 343,323 | 328,918 | ||||||||
Distributions declared per unit | $ | — | $ | 0.938 | $ | 2.90 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
72
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF UNITHOLDERS’ CAPITAL (DEFICIT)
Units | Unitholders’ Capital | Accumulated Deficit | Treasury Units (at Cost) | Total Unitholders’ Capital (Deficit) | ||||||||||||||
(in thousands) | ||||||||||||||||||
December 31, 2013 | 329,661 | $ | 6,291,824 | $ | (400,397 | ) | $ | — | $ | 5,891,427 | ||||||||
Issuance of units | 2,314 | 13,354 | — | — | 13,354 | |||||||||||||
Distributions to unitholders | (962,048 | ) | — | — | (962,048 | ) | ||||||||||||
Unit-based compensation expenses | 53,284 | — | — | 53,284 | ||||||||||||||
Reclassification of distributions paid on forfeited restricted units | 602 | — | — | 602 | ||||||||||||||
Excess tax benefit from unit-based compensation and other | 347 | — | — | 347 | ||||||||||||||
Deferred tax on capital contribution | (1,552 | ) | — | — | (1,552 | ) | ||||||||||||
Net loss | — | (451,809 | ) | — | (451,809 | ) | ||||||||||||
December 31, 2014 | 331,975 | 5,395,811 | (852,206 | ) | — | 4,543,605 | ||||||||||||
Sale of units, net of offering costs of $8,762 | 19,622 | 224,665 | — | — | 224,665 | |||||||||||||
Issuance of units | 3,611 | — | — | — | — | |||||||||||||
Cancellation of units | (191 | ) | (672 | ) | — | 672 | — | |||||||||||
Purchase of units | — | — | (672 | ) | (672 | ) | ||||||||||||
Distributions to unitholders | (323,878 | ) | — | — | (323,878 | ) | ||||||||||||
Unit-based compensation expenses | 56,136 | — | — | 56,136 | ||||||||||||||
Reclassification of distributions paid on forfeited restricted units | 865 | — | — | 865 | ||||||||||||||
Excess tax benefit from unit-based compensation and other | (9,811 | ) | — | — | (9,811 | ) | ||||||||||||
Net loss | — | (4,759,811 | ) | — | (4,759,811 | ) | ||||||||||||
December 31, 2015 | 355,017 | 5,343,116 | (5,612,017 | ) | — | (268,901 | ) | |||||||||||
Issuance of units | 5 | — | — | — | — | |||||||||||||
Cancellation of units | (2,230 | ) | — | — | — | — | ||||||||||||
Unit-based compensation expenses | 44,218 | — | — | 44,218 | ||||||||||||||
Other | (449 | ) | — | — | (449 | ) | ||||||||||||
Net loss | — | (2,171,856 | ) | — | (2,171,856 | ) | ||||||||||||
December 31, 2016 | 352,792 | $ | 5,386,885 | $ | (7,783,873 | ) | $ | — | $ | (2,396,988 | ) | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
73
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Cash flow from operating activities: | |||||||||||
Net loss | $ | (2,171,856 | ) | $ | (4,759,811 | ) | $ | (451,809 | ) | ||
Adjustments to reconcile net loss to net cash provided by operating activities – continuing operations: | |||||||||||
(Income) loss from discontinued operations | 1,786,159 | 1,015,177 | (22,596 | ) | |||||||
Depreciation, depletion and amortization | 404,237 | 554,386 | 771,549 | ||||||||
Impairment of long-lived assets | 165,044 | 4,960,144 | 2,050,387 | ||||||||
Unit-based compensation expenses | 44,218 | 56,136 | 53,284 | ||||||||
Gain on extinguishment of debt | — | (708,050 | ) | — | |||||||
Amortization and write-off of deferred financing fees | 13,356 | 30,993 | 55,839 | ||||||||
(Gains) losses on sale of assets and other, net | 13,007 | (188,200 | ) | (372,945 | ) | ||||||
Deferred income taxes | 11,367 | 4,606 | 3,874 | ||||||||
Reorganization items, net | (365,367 | ) | — | — | |||||||
Derivatives activities: | |||||||||||
Total (gains) losses | 164,330 | (1,027,014 | ) | (1,127,395 | ) | ||||||
Cash settlements | 503,943 | 1,130,640 | 88,776 | ||||||||
Cash settlements on canceled derivatives | 356,835 | 4,679 | — | ||||||||
Changes in assets and liabilities: | |||||||||||
(Increase) decrease in accounts receivable – trade, net | (71,059 | ) | 211,884 | (7,674 | ) | ||||||
Increase in other assets | (17,733 | ) | (9,142 | ) | (1,875 | ) | |||||
Increase (decrease) in accounts payable and accrued expenses | 38,468 | (98,223 | ) | 99,003 | |||||||
Decrease in other liabilities | (515 | ) | (51,266 | ) | (10,008 | ) | |||||
Net cash provided by operating activities – continuing operations | 874,434 | 1,126,939 | 1,128,410 | ||||||||
Net cash provided by operating activities – discontinued operations | 6,080 | 122,518 | 583,480 | ||||||||
Net cash provided by operating activities | 880,514 | 1,249,457 | 1,711,890 | ||||||||
Cash flow from investing activities: | |||||||||||
Deconsolidation of Berry Petroleum Company, LLC cash | (28,549 | ) | — | — | |||||||
Acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired | — | — | (2,475,315 | ) | |||||||
Development of oil and natural gas properties | (180,313 | ) | (576,256 | ) | (1,061,395 | ) | |||||
Purchases of other property and equipment | (45,435 | ) | (48,967 | ) | (63,070 | ) | |||||
Investment in discontinued operations | — | (132,332 | ) | (100,921 | ) | ||||||
Proceeds from sale of properties and equipment and other | (4,690 | ) | 345,770 | 2,195,898 | |||||||
Net cash used in investing activities – continuing operations | (258,987 | ) | (411,785 | ) | (1,504,803 | ) | |||||
Net cash provided by (used in) investing activities – discontinued operations | 23,147 | 101,368 | (516,222 | ) | |||||||
Net cash used in investing activities | (235,840 | ) | (310,417 | ) | (2,021,025 | ) | |||||
74
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
CONSOLIDATED STATEMENTS OF CASH FLOWS - Continued
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Cash flow from financing activities: | |||||||||||
Proceeds from sale of units | — | 233,427 | — | ||||||||
Proceeds from borrowings | 978,500 | 1,445,000 | 5,940,024 | ||||||||
Repayments of debt | (913,209 | ) | (1,828,461 | ) | (4,605,000 | ) | |||||
Distributions to unitholders | — | (323,878 | ) | (962,048 | ) | ||||||
Financing fees and offering costs | (752 | ) | (26,678 | ) | (59,048 | ) | |||||
Settlement of advance from discontinued operations | — | (129,217 | ) | — | |||||||
Excess tax benefit from unit-based compensation | — | (9,467 | ) | 766 | |||||||
Other | (14,823 | ) | (74,958 | ) | 60,792 | ||||||
Net cash provided by (used in) financing activities – continuing operations | 49,716 | (714,232 | ) | 375,486 | |||||||
Net cash used in financing activities – discontinued operations | (1,701 | ) | (224,449 | ) | (116,713 | ) | |||||
Net cash provided by (used in) financing activities | 48,015 | (938,681 | ) | 258,773 | |||||||
Net increase (decrease) in cash and cash equivalents | 692,689 | 359 | (50,362 | ) | |||||||
Cash and cash equivalents: | |||||||||||
Beginning | 2,168 | 1,809 | 52,171 | ||||||||
Ending | 694,857 | 2,168 | 1,809 | ||||||||
Less cash and cash equivalents of discontinued operations at end of year | — | (1,023 | ) | (1,586 | ) | ||||||
Ending – continuing operations | $ | 694,857 | $ | 1,145 | $ | 223 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
75
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Basis of Presentation and Significant Accounting Policies
When referring to Linn Energy, Inc. (formerly known as Linn Energy, LLC) (“Successor,” “Reorganized LINN,” “LINN Energy” or the “Company”), the intent is to refer to LINN Energy, a newly formed Delaware corporation, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Linn Energy, Inc. is a successor issuer of Linn Energy, LLC pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). When referring to the “Predecessor” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to Linn Energy, LLC, the predecessor that will be dissolved following the effective date of the Plan (as defined below) and resolution of all outstanding claims, and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.
The reference to “Berry” herein refers to Berry Petroleum Company, LLC, which was an indirect 100% wholly owned subsidiary of LINN Energy through February 28, 2017. Berry was deconsolidated effective December 3, 2016 (see Note 3). The reference to “LinnCo” herein refers to LinnCo, LLC, which is an affiliate of the Predecessor.
Nature of Business
LINN Energy is an independent oil and natural gas company that was formed on February 14, 2017, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from January 2006 to February 2017. As discussed further in Note 2, on May 11, 2016 (the “Petition Date”), Linn Energy, LLC, certain of its direct and indirect subsidiaries, and LinnCo (collectively, the “LINN Debtors”) and Berry (collectively with the LINN Debtors, the “Debtors”), filed voluntary petitions (“Bankruptcy Petitions”) for relief under Chapter 11 of the U.S. Bankruptcy Code (“Bankruptcy Code”) in the U.S. Bankruptcy Court for the Southern District of Texas (“Bankruptcy Court”). The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. During the pendency of the Chapter 11 proceedings, the Debtors operated their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The Company emerged from bankruptcy effective February 28, 2017.
On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date. The results of operations of Berry are reported as discontinued operations for all periods presented.
The Company’s properties are located in eight operating regions in the United States (“U.S.”): Hugoton Basin, which includes properties located in Kansas, the Oklahoma Panhandle and the Shallow Texas Panhandle; Rockies, which includes properties located in Wyoming (Green River, Washakie and Powder River basins), Utah (Uinta Basin) and North Dakota (Williston Basin); Mid-Continent, which includes properties located in the Anadarko and Arkoma basins in Oklahoma, as well as waterfloods in the Central Oklahoma Platform; TexLa, which includes properties located in east Texas and north Louisiana; Michigan/Illinois, which includes properties located in the Antrim Shale formation in north Michigan and oil properties in south Illinois; California, which includes properties located in the San Joaquin Valley and Los Angeles basins; Permian Basin, which includes properties located in west Texas and southeast New Mexico; and South Texas.
Principles of Consolidation and Reporting
The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All significant intercompany transactions and balances have been eliminated upon consolidation. Investments in noncontrolled entities over which the Company exercises significant influence are accounted for under the equity method.
The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. In addition, the Company has classified the assets and liabilities, results of operations and cash flows of
76
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Berry as discontinued operations in its consolidated financial statements for all periods presented. Such reclassifications have no impact on previously reported net income (loss), unitholders’ capital (deficit) or cash flows.
Bankruptcy Accounting
The consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 “Reorganizations” (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that are realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s consolidated statements of operations. In addition, prepetition unsecured and under-secured obligations that may be impacted by the bankruptcy reorganization process have been classified as “liabilities subject to compromise” on the Company’s consolidated balance sheet at December 31, 2016. These liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, although they may be settled for less.
The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of the Chapter 11 proceedings. In particular, the consolidated financial statements do not purport to show: (i) the realizable value of assets on a liquidation basis or their availability to satisfy liabilities; (ii) the amount of prepetition liabilities that may be allowed for claims or contingencies, or the status and priority thereof; (iii) the effect on unitholders’ deficit accounts of any changes that may be made to the Company’s capitalization; or (iv) the effect on operations of any changes that may be made to the Company’s business.
Use of Estimates
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management of the Company to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the amount of assets and liabilities reported, disclosures about contingent assets and liabilities, and reported amounts of revenues and expenses. The estimates that are particularly significant to the financial statements include estimates of the Company’s reserves of oil, natural gas and natural gas liquids (“NGL”), future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations, certain revenues and operating expenses, fair values of commodity derivatives and fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from these estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Recently Issued Accounting Standards
In November 2016, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) that is intended to address diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The adoption of this ASU is expected to result in the inclusion of restricted cash in the beginning and ending balances of cash on the statements of cash flows and disclosure reconciling cash and cash equivalents presented on the consolidated balance sheets to cash, cash equivalents and restricted cash on the consolidated statements of cash flows.
In March 2016, the FASB issued an ASU that is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and
77
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
classification on the statement of cash flows. Components of this ASU will be applied either prospectively, retrospectively or under a modified retrospective basis (as applicable for the respective provision) as of the date of adoption and is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company is currently evaluating the impact of the adoption of this ASU. For periods following adoption, the Company will recognize excess tax benefits as income tax expense in the consolidated statements of operations and as operating activities in the consolidated statements of cash flows. The Company does not expect this standard to have a material impact on its consolidated financial statements or related disclosures.
In February 2016, the FASB issued an ASU that is intended to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet. This ASU will be applied retrospectively as of the date of adoption and is effective for fiscal years beginning after December 15, 2018, and interim periods within those years (early adoption permitted). The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The Company expects the adoption of this ASU to impact its consolidated balance sheets resulting from an increase in both assets and liabilities related to the Company’s leasing activities.
In November 2015, the FASB issued an ASU that is intended to simplify the presentation of deferred taxes by requiring that all deferred taxes be classified as noncurrent, presented as a single noncurrent amount for each tax-paying component of an entity. The ASU is effective for fiscal years beginning after December 15, 2016; however, the Company early adopted it on January 1, 2016, on a retrospective basis. The adoption of this ASU resulted in the reclassification of previously-classified net current deferred taxes of approximately $22 million from “other current assets,” as well as previously-classified net noncurrent deferred tax liabilities of approximately $11 million from “other noncurrent liabilities,” to “other noncurrent assets” resulting in net noncurrent deferred taxes of approximately $11 million on the Company’s consolidated balance sheet at December 31, 2015. There was no impact to the consolidated statements of operations.
In April 2015, the FASB issued an ASU that is intended to simplify the presentation of debt issuance costs by requiring that debt issuance costs related to a recognized debt liability be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The Company adopted this ASU on January 1, 2016, on a retrospective basis. The adoption of this ASU resulted in the reclassification of approximately $37 million of unamortized deferred financing fees (which excludes deferred financing fees associated with the Company’s Credit Facilities, as defined in Note 6, which were not reclassified) from an asset to a direct deduction from the carrying amount of the associated debt liability on the consolidated balance sheet at December 31, 2015. There was no impact to the consolidated statements of operations.
In August 2014, the FASB issued an ASU that provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This ASU is effective for the annual period ending after December 15, 2016, and for the annual periods and interim periods thereafter, and the Company adopted this ASU on December 31, 2016. The adoption of this ASU had no impact on the Company’s consolidated financial statements or related disclosures.
In May 2014, the FASB issued an ASU that is intended to improve and converge the financial reporting requirements for revenue from contracts with customers. This ASU is effective for fiscal years beginning after December 15, 2017, and interim periods within those years (early adoption permitted for fiscal years beginning after December 15, 2016, including interim periods within that year). The Company does not plan on early adopting this ASU. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements and related disclosures. The Company expects to use the cumulative-effect transition method, has completed an initial review of its contracts and is developing accounting policies to address the provisions of the ASU, but has not finalized any estimates of the potential impacts.
Cash Equivalents
For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Outstanding checks in excess of funds on deposit are
78
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
included in “accounts payable and accrued expenses” on the consolidated balance sheets and are classified as financing activities on the consolidated statements of cash flows.
Accounts Receivable – Trade, Net
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and national economic data. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential recovery is remote. The balance in the Company’s allowance for doubtful accounts related to trade accounts receivable was approximately $8 million and $1 million at December 31, 2016, and December 31, 2015, respectively.
Inventories
Materials, supplies and commodity inventories are valued at the lower of average cost or market. Inventories also include California carbon allowance instruments.
Oil and Natural Gas Properties
Proved Properties
The Company accounts for oil and natural gas properties in accordance with the successful efforts method. In accordance with this method, all leasehold and development costs of proved properties are capitalized and amortized on a unit-of-production basis over the remaining life of the proved reserves and proved developed reserves, respectively. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance and repairs necessary to maintain properties in operating condition are expensed as incurred. Estimated dismantlement and abandonment costs are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves. The Company capitalizes interest on borrowed funds related to its share of costs associated with the drilling and completion of new oil and natural gas wells. Interest is capitalized only during the periods in which these assets are brought to their intended use. The Company capitalized interest costs of approximately $257,000, $3 million and $4 million for the years ended December 31, 2016, December 31, 2015, and December 31, 2014, respectively.
The Company evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Company management believes will impact realizable prices.
79
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Based on the analysis described above, the Company recorded the following noncash impairment charges associated with proved oil and natural gas properties:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Mid-Continent region | $ | 141,902 | $ | 405,370 | $ | 244,413 | |||||
Rockies region | 23,142 | 1,592,256 | 332,365 | ||||||||
Hugoton Basin region | — | 1,667,768 | — | ||||||||
TexLa region | — | 352,422 | 4,836 | ||||||||
Permian Basin region | — | 71,990 | 1,337,444 | ||||||||
South Texas region | — | 42,433 | 131,329 | ||||||||
$ | 165,044 | $ | 4,132,239 | $ | 2,050,387 | ||||||
The impairment charges in 2016 and 2015 were due to a decline in commodity prices, changes in expected capital development and a decline in the Company’s estimates of proved reserves. The impairment charges in 2014 include approximately $1.4 billion due to a steep decline in commodity prices during the fourth quarter of 2014 and approximately $603 million due to the divestiture of certain high valued unproved properties in the Midland Basin in which the expected cash flows were previously included in the impairment assessment for proved oil and natural gas properties. The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Unproved Properties
Costs related to unproved properties include costs incurred to acquire unproved reserves. Because these reserves do not meet the definition of proved reserves, the related costs are not classified as proved properties. Unproved leasehold costs are capitalized and amortized on a composite basis if individually insignificant, based on past success, experience and average lease-term lives. Individually significant leases are reclassified to proved properties if successful and expensed on a lease by lease basis if unsuccessful or the lease term expires. Unamortized leasehold costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company evaluates the impairment of its unproved oil and natural gas properties whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of unproved properties are reduced to fair value based on management’s experience in similar situations and other factors such as the lease terms of the properties and the relative proportion of such properties on which proved reserves have been found in the past.
Based on the analysis described above, the Company recorded the following noncash impairment charges associated with unproved oil and natural gas properties:
Year Ended December 31, 2015 | |||
(in thousands) | |||
TexLa region | $ | 416,846 | |
Permian Basin region | 226,922 | ||
Rockies region | 184,137 | ||
$ | 827,905 | ||
80
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The Company recorded no impairment charges associated with unproved properties for the years ended December 31, 2016, or December 31, 2014.
The impairment charges in 2015 were based primarily on no future plans to develop properties in certain operating areas as a result of declines in commodity prices. The carrying values of the impaired unproved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. The impairment charges are included in “impairment of long-lived assets” on the consolidated statements of operations.
Exploration Costs
Exploratory geological and geophysical costs, delay rentals, amortization and impairment of unproved leasehold costs and costs to drill exploratory wells that do not find proved reserves are expensed as exploration costs. The costs of any exploratory wells are carried as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as the Company is making sufficient progress towards assessing the reserves and the economic and operating viability of the project. The Company recorded no leasehold impairment expenses related to unproved properties during the year ended December 31, 2016. The Company recorded noncash leasehold impairment expenses related to unproved properties of approximately $2 million and $125 million for the years ended December 31, 2015, and December 31, 2014, respectively, which are included in “exploration costs” on the consolidated statements of operations.
Other Property and Equipment
Other property and equipment includes natural gas gathering systems, pipelines, furniture and office equipment, buildings, vehicles, information technology equipment, software and other fixed assets. These assets are recorded at cost and are depreciated using the straight-line method based on expected lives ranging from three to 39 years for the individual asset or group of assets.
Restricted Cash
Restricted cash of approximately $8 million and $7 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2016, and December 31, 2015, respectively, and represents cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements.
Derivative Instruments
Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials.
The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes.
A swap contract specifies a fixed price that the Company will receive from the counterparty as compared to floating market prices, and on the settlement date the Company will receive or pay the difference between the swap price and the market price. Collar contracts specify floor and ceiling prices to be received as compared to floating market prices. A put option requires the Company to pay the counterparty a premium equal to the fair value of the option at the purchase date and receive from the counterparty the excess, if any, of the fixed price floor over the market price at the settlement date.
81
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Derivative instruments are recorded at fair value and included on the consolidated balance sheets as assets or liabilities. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives. See Note 7 and Note 8 for additional details about the Company’s derivative financial instruments.
Revenue Recognition
Revenues representative of the Company’s ownership interest in its properties are presented on a gross basis on the consolidated statements of operations. Sales of oil, natural gas and NGL are recognized when the product 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.
The Company has elected the entitlements method to account for natural gas production imbalances. Imbalances occur when the Company sells more or less than its entitled ownership percentage of total natural gas production. In accordance with the entitlements method, any amount received in excess of the Company’s share is treated as a liability. If the Company receives less than its entitled share, the underproduction is recorded as a receivable. Imbalance receivables and payables are valued at the lower of the price in effect at the time of production, the current market value or, if a contract is in hand, the contract price. At December 31, 2016, and December 31, 2015, the Company had natural gas production imbalance receivables of approximately $8 million and $13 million, respectively, which are included in “accounts receivable – trade, net” on the consolidated balance sheets. At December 31, 2016, and December 31, 2015, the Company had natural gas production imbalance payables of approximately $6 million and $11 million, respectively, which are included in “accounts payable and accrued expenses” on the consolidated balance sheets.
The Company engages in the purchase, gathering and transportation of third-party natural gas and subsequently markets such natural gas to independent purchasers under separate arrangements. As such, the Company separately reports third-party marketing revenues and marketing expenses.
Unit-Based Compensation
The Company recognizes expense for unit-based compensation over the requisite service period in an amount equal to the fair value of unit-based awards granted to employees and nonemployee directors. The fair value of unit-based awards, excluding liability awards, is computed at the date of grant and is not remeasured. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period.
The Company has made a policy decision to recognize compensation expense for service-based awards on a straight-line basis over the requisite service period for the entire award. See Note 5 for additional details about the Company’s accounting for unit-based compensation.
Deferred Financing Fees
The Company incurred legal and bank fees related to the issuance of debt. At December 31, 2016, net deferred financing fees of approximately $17 million are included in “other current assets” and approximately $1 million are included in “current portion of long-term debt, net” on the consolidated balance sheet. At December 31, 2015, net deferred financing fees of approximately $25 million are included in “other current assets,” approximately $2 million are included in “current portion of
82
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
long-term debt, net” and approximately $35 million are included in “long-term debt, net” on the consolidated balance sheet. These debt issuance costs are amortized over the life of the debt agreement. Upon early retirement or amendment to the debt agreement, certain fees are written off to expense.
For the years ended December 31, 2016, December 31, 2015, and December 31, 2014, amortization expense of approximately $10 million, $20 million and $43 million, respectively, is included in “interest expense, net of amounts capitalized” on the consolidated statements of operations. For the year ended December 31, 2016, approximately $33 million were written off to expense and included in “reorganization items, net” on the consolidated statement of operations in connection with the filing of the Bankruptcy Petitions. For the years ended December 31, 2016, and December 31, 2015, approximately $1 million and $7 million, respectively, were written off to expense and included in “other, net” on the consolidated statements of operations related to amendments of the Credit Facilities. For the year ended December 31, 2014, approximately $8 million were written off to expense and included in “other, net” on the consolidated statement of operations related to the term loan that was repaid and the Credit Facilities that were amended in 2014.
Fair Value of Financial Instruments
The carrying values of the Company’s receivables, payables and Credit Facilities are estimated to be substantially the same as their fair values at December 31, 2016, and December 31, 2015. See Note 6 for fair value disclosures related to the Company’s other outstanding debt. As noted above, the Company carries its derivative financial instruments at fair value. See Note 8 for details about the fair value of the Company’s derivative financial instruments.
Income Taxes
Prior to the consummation of the LINN Plan, as defined below, the Company was a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes, which are accounted for using the asset and liability method. As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor is not a taxable entity. The Predecessor does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Predecessor.
Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and tax carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. See Note 14 for details of amounts recorded in the consolidated financial statements.
Note 2 – Chapter 11 Proceedings and Covenant Violations
Chapter 11 Proceedings
On the Petition Date, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040.
On October 21, 2016, the Debtors filed the Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates (the “Original Plan”).
On December 3, 2016, the Debtors split the Original Plan and pursued separate plans of reorganization for the LINN Debtors, on the one hand, and Linn Acquisition Company, LLC (“LAC”) and Berry, on the other hand. Accordingly, on December 3, 2016, the LINN Debtors filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor
83
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “LINN Plan”). The LINN Debtors subsequently filed amended versions of the LINN Plan with the Bankruptcy Court.
On December 13, 2016, LAC and Berry filed the Amended Joint Chapter 11 Plan of Reorganization of Linn Acquisition Company, LLC and Berry Petroleum Company, LLC (the “Berry Plan” and together with the LINN Plan, the “Plans”). LAC and Berry subsequently filed amended versions of the Berry Plan with the Bankruptcy Court.
On January 27, 2017, the Bankruptcy Court entered an order approving and confirming the Plans (the “Confirmation Order”). On February 28, 2017 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the respective Plans, the Plans became effective in accordance with their respective terms and LINN Energy and Berry emerged from bankruptcy as stand-alone, unaffiliated entities.
Plans of Reorganization
In accordance with the LINN Plan, on the Effective Date:
• | The Predecessor transferred all of its assets, including equity interests in its subsidiaries, other than LAC and Berry, to Linn Energy Holdco II LLC (“Holdco II”), a newly formed subsidiary of the Predecessor and the borrower under the Credit Agreement (“Exit Facility”) entered into in connection with the reorganization, in exchange for 100% of the equity of Holdco II and the issuance of interests in the Exit Facility to certain of the Predecessor’s creditors in partial satisfaction of their claims (the “Contribution”). Immediately following the Contribution, the Predecessor transferred 100% of the equity interests in Holdco II to the Successor in exchange for approximately $530 million in cash and an amount of equity securities in the Successor not to exceed 49.90% of the outstanding equity interests of the Successor (the “Disposition”), which the Predecessor distributed to certain of its creditors in satisfaction of their claims. Contemporaneously with the reorganization transactions and pursuant to the LINN Plan, (i) LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, (ii) all of the equity interests in LAC and the Predecessor were canceled and (iii) LAC and the Predecessor commenced liquidation, which is expected to be completed following the resolution of the respective companies’ outstanding claims. |
• | The holders of claims under the Predecessor’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the $1.7 billion Exit Facility. As a result, all outstanding obligations under the LINN Credit Facility were canceled. |
• | Holdco II, as borrower, entered into the Exit Facility with the holders of claims under the LINN Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan (the “Revolving Loan”) with up to $1.4 billion in borrowing commitments and a new term loan (the “Term Loan”) in an original principal amount of $300 million. For additional information about the Exit Facility, see “Financing Activities” in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” |
• | The holders of the Company’s 12.00% senior secured second lien notes due December 2020 (the “Second Lien Notes”) received their pro rata share of (i) 17,678,889 shares of Class A common stock; (ii) certain rights to purchase shares of Class A common stock in the rights offering, as described below; and (iii) $30 million in cash. The holders of the Company’s 6.50% senior notes due May 2019, 6.25% senior notes due November 2019, 8.625% senior notes due 2020, 7.75% senior notes due February 2021 and 6.50% senior notes due September 2021 (collectively, the “Unsecured Notes”) received their pro rata share of (i) 26,724,396 shares of Class A common stock; and (ii) certain rights to purchase shares of Class A common stock in the rights offering (as described below). As a result, all outstanding obligations under the Second Lien Notes and the Unsecured Notes and the indentures governing such obligations were canceled. |
• | The holders of general unsecured claims (other than claims relating to the Second Lien Notes and the Unsecured Notes) against the LINN Debtors (the “LINN Unsecured Claims”) received their pro rata share of cash from two cash distribution pools totaling $40 million, as divided between a $2.3 million cash distribution pool for the payment |
84
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
in full of allowed LINN Unsecured Claims in an amount equal to $2,500 or less (and larger claims for which the holders irrevocably agreed to reduce such claims to $2,500), and a $37.7 million cash distribution pool for pro rata distributions to all remaining allowed general LINN Unsecured Claims. As a result, all outstanding LINN Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date.
• | All units that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. On the Effective Date, the Reorganized LINN issued in the aggregate 91,708,500 shares of Class A common stock. No cash was raised from the issuance of the Class A common stock on account of claims held by the Predecessor’s creditors. |
• | The Reorganized LINN entered into a registration rights agreement with certain parties to the Backstop Commitment Agreement and other recipients of shares of Class A common stock who own at least 10% of the shares of Class A common stock or are otherwise deemed to be an affiliate of the Reorganized LINN, pursuant to which the Company agreed to, among other things, file a registration statement with the Securities and Exchange Commission within 60 days of the Effective Date covering the offer and resale of “Registrable Securities” (as defined therein). |
• | By operation of the LINN Plan and the Confirmation Order, the terms of the Predecessor’s board of directors expired as of the Effective Date. The Reorganized LINN formed a new board of directors, consisting of the Chief Executive Officer of the Predecessor, one director selected by the Reorganized LINN and five directors selected by a six-person selection committee. |
In accordance with the Berry Plan, on the Effective Date:
• | LAC assigned all of its rights, title and interest in the membership interests of Berry to Berry Petroleum Corporation, and Berry became a wholly owned subsidiary of Berry Petroleum Corporation. All of the equity interests in LAC that were issued and outstanding immediately prior to the Effective Date were extinguished without recovery. Subsequently, LAC commenced liquidation, which is expected to be completed following the resolution of the outstanding claims. As a result, Berry Petroleum Corporation became a stand-alone company, separate from the Company and the LINN Debtors. |
• | The holders of claims under Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) received a full recovery, consisting of a cash paydown and their pro rata share of the new Berry credit facility (“Berry Exit Facility”). As a result, all outstanding obligations under the Berry Credit Facility were canceled. |
• | Berry, as borrower, entered into the Berry Exit Facility with the holders of claims under the Berry Credit Facility, as lenders, and Wells Fargo Bank, National Association, as administrative agent, providing for a new reserve-based revolving loan with up to $550 million in borrowing commitments. |
• | The holders of Berry’s 6.75% senior notes due 2020 and 6.375% senior notes due 2022 (collectively, the “Berry Unsecured Notes”) received their pro rata share of either (i) shares of common stock in Berry Petroleum Corporation or, for those non-accredited investors holding the Berry Unsecured Notes that irrevocably elected to receive a cash recovery, cash distributions from a $35 million cash distribution pool (the “Berry Cash Distribution Pool”), and (ii) certain rights to purchase shares of preferred stock in Berry Petroleum Corporation. |
• | The holders of unsecured claims against Berry (other than the Berry Unsecured Notes) (the “Berry Unsecured Claims”) received their pro rata share of either (i) shares of common stock in Berry Petroleum Corporation or (ii) in the event that such holder irrevocably elected to receive a cash recovery, cash distributions from the Berry Cash Distribution Pool. As a result, all outstanding obligations under the Berry Unsecured Notes and the indentures governing such obligations were canceled and all outstanding Berry Unsecured Claims were fully satisfied, settled, released and discharged as of the Effective Date. |
• | Berry and LAC settled all intercompany claims against the LINN Debtors pursuant to a settlement agreement approved as part of the Berry Plan and the Confirmation Order, which settlement provided Berry and LAC with a $25 million general unsecured claim against the Company. |
85
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Bank RSA
Prior to the Petition Date, on May 10, 2016, the Debtors entered into a restructuring support agreement (“Bank RSA”) with certain holders (“Consenting Bank Creditors”) collectively holding or controlling at least 66.67% by aggregate outstanding principal amounts under (i) the LINN Credit Facility and (ii) the Berry Credit Facility. The Bank RSA set forth, subject to certain conditions, the commitment of the Consenting Bank Creditors to support a comprehensive restructuring of the Debtors’ long-term debt. The Bank RSA provided that the Consenting Bank Creditors would support the use of the LINN Debtors’ and Berry’s cash collateral under specified terms and conditions, including adequate protection terms. The Bank RSA required the Debtors and the Consenting Bank Creditors to, among other things, support and not interfere with consummation of the restructuring transactions contemplated by the Bank RSA and, as to the Consenting Bank Creditors, vote their claims in favor of the plan of reorganization.
Restructuring Support Agreement
On October 7, 2016, the LINN Debtors entered into a restructuring support agreement (“Original LINN RSA”) with (i) certain holders of the Second Lien Notes (such holders, the “Consenting Second Lien Noteholders”) and (ii) certain holders of the Unsecured Notes (such holders of the Unsecured Notes, the “Consenting Unsecured Noteholders,” and together such Consenting Unsecured Noteholders with the Consenting Second Lien Noteholders, the “Consenting Noteholders”).
On October 21, 2016, the LINN Debtors entered into the First Amended and Restated Restructuring Support Agreement (“LINN RSA”) with (i) certain Consenting Second Lien Noteholders, (ii) certain Consenting Unsecured Noteholders and (iii) certain lenders (together with the Consenting Noteholders, the “Consenting LINN Creditors”) under the LINN Credit Facility. The LINN RSA amended and restated the Original LINN RSA and replaced the Bank RSA with respect to the terms of the restructuring of the LINN Debtors. At that time, the Bank RSA remained in full force and effect with respect to the restructuring of Berry and LAC. The LINN RSA set forth, subject to certain conditions, the commitment of the LINN Debtors and the Consenting LINN Creditors to support a comprehensive restructuring of the LINN Debtors’ long-term debt (the “Restructuring”). The LINN RSA required the LINN Debtors and the Consenting LINN Creditors to, among other things, support and not interfere with consummation of the Restructuring and, as to the Consenting LINN Creditors, vote their claims in favor of the LINN Plan. The restructuring contemplated by the LINN RSA was effectuated through the LINN Plan and the Confirmation Order and took effect on the Effective Date.
Liabilities Subject to Compromise
The Company’s consolidated balance sheet includes amounts classified as “liabilities subject to compromise,” which represent prepetition liabilities that have been allowed, or that the Company anticipates will be allowed, as claims in its Chapter 11 cases. The amounts represent the Company’s current estimate of known or potential obligations to be resolved in connection with the Chapter 11 proceedings. The differences between the liabilities the Company has estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. The Company will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts as necessary. Such adjustments may be material.
The following table summarizes the components of liabilities subject to compromise included on the consolidated balance sheet:
December 31, 2016 | |||
(in thousands) | |||
Accounts payable and accrued expenses | $ | 137,692 | |
Accrued interest payable | 144,184 | ||
Debt | 4,023,129 | ||
Liabilities subject to compromise | $ | 4,305,005 | |
86
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Reorganization Items, Net
The Company has incurred and is expected to continue to incur significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items represent costs and income directly associated with the Chapter 11 proceedings since the Petition Date, and also include adjustments to reflect the carrying value of certain liabilities subject to compromise at their estimated allowed claim amounts, as such adjustments are determined.
The following table summarizes the components of reorganization items included on the consolidated statement of operations:
Year Ended December 31, 2016 | |||
(in thousands) | |||
Legal and other professional advisory fees | $ | (56,656 | ) |
Unamortized deferred financing fees, discounts and premiums | (52,045 | ) | |
Gain related to interest payable on the 12.00% senior secured second lien notes due December 2020 (1) | 551,000 | ||
Terminated contracts | (66,052 | ) | |
Other | (64,648 | ) | |
Reorganization items, net | $ | 311,599 | |
(1) | Represents a noncash gain on the write-off of postpetition contractual interest through maturity, recorded to reflect the carrying value of the liability subject to compromise at its estimated allowed claim amount. |
Effect of Filing on Creditors and Unitholders
Subject to certain exceptions, under the Bankruptcy Code, the filing of Bankruptcy Petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order of the Bankruptcy Court, substantially all of the Debtors’ prepetition liabilities are subject to settlement under the Bankruptcy Code. Although the filing of Bankruptcy Petitions triggered defaults on the Debtors’ debt obligations, creditors were stayed from taking any actions against the Debtors as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. The Company did not record interest expense on its Second Lien Notes or senior notes for the period from May 12, 2016, through December 31, 2016. For that period, unrecorded contractual interest was approximately $219 million.
Under the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and postpetition liabilities must be satisfied in full before the holders of the Company’s existing common units are entitled to receive any settlement or retain any property under a plan of reorganization. Pursuant to the terms of the LINN Plan, all of the equity interests in the Predecessor were canceled and the Predecessor commenced liquidation, which is expected to be completed following the resolution of all outstanding claims.
Covenant Violations
The Company’s filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under its Credit Facilities, its Second Lien Notes and its senior notes. Additionally, other events of default, including cross-defaults, have occurred, including the failure to make interest payments on the Company’s Second Lien Notes and senior notes, as well as the receipt of a going concern explanatory paragraph from the Company’s independent registered public accounting firm on the Company’s consolidated financial statements for the year ended December 31, 2015. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default. See Note 6 for additional details about the Company’s debt.
87
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Credit Facilities
The Company’s Credit Facilities contained a requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. Consequently, the filing of the Company’s 2015 Annual Report on Form 10-K which included such explanatory paragraph resulted in a default under the LINN Credit Facility as of the filing date, March 15, 2016, subject to a 30 day grace period.
On April 12, 2016, the Company entered into amendments to both the LINN Credit Facility and the Berry Credit Facility. The amendments provided for, among other things, an agreement that (i) certain events would not become defaults or events of default until May 11, 2016, (ii) the borrowing bases would remain constant until May 11, 2016, unless reduced as a result of swap agreement terminations or collateral sales and (iii) the Company, the administrative agent and the lenders would negotiate in good faith the terms of a restructuring support agreement in furtherance of a restructuring of the capital structure of the Company and its subsidiaries. In addition, the amendment to the Berry Credit Facility provided Berry with access to previously restricted cash of $45 million in order to fund ordinary course operations.
As a condition to closing the amendments, in April 2016, (a) the Company made a $100 million permanent repayment of a portion of the borrowings outstanding under the LINN Credit Facility and (b) the Company and certain of its subsidiaries provided control agreements over certain deposit accounts. Pursuant to the terms of the amendment to the LINN Credit Facility and as a result of the execution of the Bank RSA, in May 2016, the Company made a $350 million permanent repayment of a portion of the borrowings outstanding under the LINN Credit Facility.
The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Credit Facilities. However, under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of the default.
Second Lien Notes
The indenture governing the Second Lien Notes (“Second Lien Indenture”) required the Company to deliver mortgages by February 18, 2016, subject to a 45 day grace period. The Company elected to exercise its right to the grace period, which resulted in the Company being in default under the Second Lien Indenture.
On April 4, 2016, the Company entered into a settlement agreement with certain holders of the Second Lien Notes and agreed to deliver, and make arrangements for recordation of, the mortgages. The Company has since delivered and made arrangements for recordation of the mortgages.
The settlement agreement required the parties to commence good faith negotiations with each other regarding the terms of a potential comprehensive and consensual restructuring, including a potential restructuring under a Chapter 11 plan of reorganization. The settlement agreement provided that in the event the parties were unable to reach agreement on the terms of a consensual restructuring on or before the commencement of such Chapter 11 proceedings (or such later date as mutually agreed to by the parties), the parties would support entry by the Bankruptcy Court of a settlement order that, among other things, (i) approves the issuance of additional notes, in the principal amount of $1.0 billion plus certain accrued interest, on a proportionate basis to existing holders of the Second Lien Notes and (ii) releases the mortgages and other collateral upon the issuance of the additional notes (the “Settlement Order”).
The settlement agreement will terminate upon, among other events, entry by the Bankruptcy Court of a final, non-appealable order denying the Company’s motion seeking entry of the Settlement Order.
The Company also failed to make interest payments on its Second Lien Notes during 2016.
The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Second Lien Indenture. However, under the Bankruptcy Code, holders of the Second Lien Notes were stayed from taking any action against the Company as a result of the default.
88
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Senior Notes
The Company deferred making interest payments totaling approximately $60 million due March 15, 2016, including approximately $30 million on LINN Energy’s 7.75% senior notes due February 2021, approximately $12 million on LINN Energy’s 6.50% senior notes due September 2021 and approximately $18 million on Berry’s 6.375% senior notes due September 2022, which resulted in the Company being in default under these senior notes. The indentures governing each of the applicable series of notes provided the Company a 30 day grace period to make the interest payments.
On April 14, 2016, within the 30 day interest payment grace period provided for in the indentures governing the notes, the Company and Berry made interest payments of approximately $60 million in satisfaction of their respective obligations.
The Company failed to make interest payments due on its senior notes subsequent to April 14, 2016.
The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the indentures governing the senior notes. However, under the Bankruptcy Code, holders of the senior notes were stayed from taking any action against the Company as a result of the default.
Note 3 – Discontinued Operations, Divestitures, Exchanges of Properties, Acquisitions and Joint-Venture Funding
Discontinued Operations – 2016
On December 3, 2016, LINN Energy filed an amended plan of reorganization that excluded Berry. As a result of its loss of control of Berry, LINN Energy concluded that it was appropriate to deconsolidate Berry effective on the aforementioned date. The Company has classified the assets and liabilities, results of operations and cash flows of Berry as discontinued operations in its consolidated financial statements for all periods presented.
The following table presents summarized financial results of the Company’s discontinued operations on the consolidated statements of operations:
Year Ended December 31, | |||||||||||
2016 (1) | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Revenues and other | $ | 387,706 | $ | 641,654 | $ | 1,431,289 | |||||
Expenses | 1,524,296 | 1,579,029 | 1,319,633 | ||||||||
Other income and (expenses) | (57,030 | ) | (77,870 | ) | (88,991 | ) | |||||
Reorganization items, net | (46,127 | ) | — | — | |||||||
Income (loss) from discontinued operations before income taxes | (1,239,747 | ) | (1,015,245 | ) | 22,665 | ||||||
Income tax expense (benefit) | 196 | (68 | ) | 69 | |||||||
Income (loss) from discontinued operations, net of income taxes | $ | (1,239,943 | ) | $ | (1,015,177 | ) | $ | 22,596 | |||
(1) | Results of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. |
In addition, for the year ended December 31, 2016, the Company recognized a noncash loss on the deconsolidation of Berry of approximately $546 million. The loss is included in “income (loss) from discontinued operations, net of income taxes” on the consolidated statement of operations.
89
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents carrying amounts of the assets and liabilities of the Company’s discontinued operations on the consolidated balance sheet:
December 31, 2015 | |||
(in thousands) | |||
ASSETS | |||
Current assets: | |||
Cash and cash equivalents | $ | 1,023 | |
Accounts receivable – trade, net | 46,053 | ||
Other | 34,115 | ||
Current assets of discontinued operations | $ | 81,191 | |
Noncurrent assets: | |||
Oil and natural gas properties (successful efforts method), net | $ | 3,414,896 | |
Restricted cash | 250,359 | ||
Other | 115,030 | ||
Noncurrent assets of discontinued operations | $ | 3,780,285 | |
LIABILITIES | |||
Current liabilities: | |||
Accounts payable and accrued expenses | $ | 125,748 | |
Current portion of long-term debt | 873,175 | ||
Other | 18,976 | ||
Current liabilities of discontinued operations | $ | 1,017,899 | |
Noncurrent liabilities: | |||
Long-term debt, net | $ | 845,368 | |
Other | 212,050 | ||
Noncurrent liabilities of discontinued operations | $ | 1,057,418 | |
Divestiture – 2015
On August 31, 2015, the Company completed the sale of its remaining position in Howard County in the Permian Basin (“Howard County Assets Sale”). Cash proceeds received from the sale of these properties were approximately $276 million, net of costs to sell of approximately $1 million, and the Company recognized a net gain of approximately $177 million. The gain is included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations. The Company used the net proceeds from the sale to repay a portion of the outstanding indebtedness under the LINN Credit Facility.
Divestitures – 2014
On December 15, 2014, the Company completed the sale of its entire position in the Granite Wash and Cleveland plays located in the Texas Panhandle and western Oklahoma to privately held institutional affiliates of EnerVest, Ltd. and its joint venture partner FourPoint Energy, LLC. Cash proceeds received from the sale of these properties were approximately $1.8 billion, net of costs to sell of approximately $10 million, and the Company recognized a net gain of approximately $294 million.
On October 30, 2014, the Company completed the sale of its interests in certain non-producing oil and natural gas properties located in the Mid-Continent region. Cash proceeds received from the sale of these properties were approximately $44 million, and the Company recognized a net gain of approximately $36 million.
90
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The gains on divestitures in 2014 are included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations.
The Company used the net cash proceeds received from these sales to repay a short-period term loan in full as well as repay a portion of the borrowings outstanding under the LINN Credit Facility.
Exchanges of Properties – 2014
On November 21, 2014, the Company completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation (“ExxonMobil”) in exchange for properties in California’s South Belridge Field. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $50 million, including costs to sell of approximately $3 million.
On August 15, 2014, the Company completed the trade of a portion of its Permian Basin properties to Exxon Mobil Corporation and its affiliates, including its wholly owned subsidiary XTO Energy Inc. (“Exxon XTO”), in exchange for properties in the Hugoton Basin. The noncash exchange was accounted for at fair value and the Company recognized a net gain of approximately $99 million, including costs to sell of approximately $3 million.
The gains on the exchanges are equal to the difference between the carrying value and the fair value of the assets exchanged less costs to sell, and are included in “(gains) losses on sale of assets and other, net” on the consolidated statement of operations in 2014. The fair value measurements were based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy.
Acquisitions – 2014
On September 11, 2014, the Company completed the acquisition of certain oil and natural gas properties located in the Hugoton Basin from Pioneer Natural Resources Company for total consideration of approximately $328 million, which was initially financed with borrowings under the LINN Credit Facility.
On August 29, 2014, the Company completed the acquisition of certain oil and natural gas properties located in five operating regions in the U.S. from subsidiaries of Devon Energy Corporation for total consideration of approximately $2.1 billion, which was initially financed with proceeds from a bridge loan and borrowings under a short-period term loan.
During the third quarter of 2014, the Company used the net proceeds from the issuance of its 6.50% senior notes due May 2019 and 6.50% senior notes due September 2021 to repay the bridge loan in full. During the fourth quarter of 2014, the Company used the net proceeds from the sales of its Granite Wash properties as well as certain of its Wolfberry properties to repay the short-period term loan in full.
These acquisitions were accounted for under the acquisition method of accounting. Accordingly, the Company conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were expensed as incurred. The results of operations of all acquisitions have been included in the consolidated financial statements since the acquisition dates.
Joint-Venture Funding – 2014
For the year ended December 31, 2014, the Company paid approximately $25 million, including interest, to fund the commitment related to the joint-venture agreement it entered into with an affiliate of Anadarko Petroleum Company in April 2012. As of February 2014, the Company had fully funded the total commitment of $400 million.
91
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 4 – Unitholders’ Capital (Deficit)
Cancellation of Awards
In December 2016, the Company canceled all of its then-outstanding nonvested restricted units without consideration given to the employees, decreasing the Company’s units issued and outstanding by 2,230,182.
Delisting from Stock Exchange
As a result of the Company’s failure to comply with the NASDAQ Global Select Market (“NASDAQ”) continued listing requirements, on May 24, 2016, the Company’s units began trading over the counter on the OTC Markets Group Inc.’s Pink marketplace under the trading symbol “LINEQ.”
At-the-Market Offering Program
The Company’s Board of Directors had authorized the sale of up to $500 million of units under an at-the-market offering program, with sales of units, if any, to be made under an equity distribution agreement. No sales were made under the equity distribution agreement during the year ended December 31, 2016. During the year ended December 31, 2015, the Company, under its equity distribution agreement, sold 3,621,983 units representing limited liability company interests at an average price of $12.37 per unit for net proceeds of approximately $44 million (net of approximately $448,000 in commissions). In connection with the issuance and sale of these units, the Company also incurred professional services expenses of approximately $459,000. The Company used the net proceeds for general corporate purposes, including the open market repurchases of a portion of its senior notes (see Note 6).
Public Offering of Units
In May 2015, the Company sold 16,000,000 units representing limited liability company interests in an underwritten public offering at $11.79 per unit ($11.32 per unit, net of underwriting discount) for net proceeds of approximately $181 million (after underwriting discount and offering costs of approximately $8 million). The Company used the net proceeds from the sale of these units to repay a portion of the outstanding indebtedness under the LINN Credit Facility.
Forfeiture of Units in Exchange for Cash
In August 2015, in accordance with terms of the separation agreement between the Company and Kolja Rockov, former Chief Financial Officer, dated August 31, 2015, Mr. Rockov agreed to forfeit 191,446 units issued to him under the Company’s equity compensation plan (see Note 5) in exchange for a cash payment of approximately $672,000.
Distributions
Under the Predecessor’s limited liability company agreement, unitholders were entitled to receive a distribution of available cash, which included cash on hand plus borrowings less any reserves established by the Predecessor’s Board of Directors to provide for the proper conduct of the Predecessor’s business (including reserves for future capital expenditures, including drilling, acquisitions and anticipated future credit needs) or to fund distributions, if any, over the next four quarters. Monthly distributions were paid by the Company through September 2015. Distributions paid by the Company during 2015 and 2014 are presented on the consolidated statements of unitholders’ capital (deficit) and the consolidated statements of cash flows. In October 2015, the Predecessor’s Board of Directors determined to suspend payment of the Predecessor’s distribution. The Successor currently has no intention of paying cash dividends and any future payment of cash dividends would be subject to the restrictions in the Exit Facility.
92
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Unit Repurchase Plan
The Company’s Board of Directors had authorized the repurchase of up to $250 million of the Company’s outstanding units from time to time on the open market or in negotiated purchases. The Company did not repurchase any units during the years ended December 31, 2016, December 31, 2015, or December 31, 2014.
Note 5 – Unit-Based Compensation and Other Benefit Plans
Incentive Plan Summary
The Linn Energy, LLC Amended and Restated Long-Term Incentive Plan, as amended (the “LTIP”), was effective from December 2005 through February 28, 2017. The LTIP limits the number of units that may be delivered pursuant to awards to 21 million. The LTIP, which was administered by the Compensation Committee of the Board of Directors (“Compensation Committee”), permits granting unrestricted units, restricted units, phantom units, unit options, performance units and unit appreciation rights to employees, consultants and nonemployee directors under the terms of the LTIP. The restricted units, phantom units and unit options generally vest ratably over three years. The contractual life of unit options is 10 years. Performance units were granted for the first time in January 2014 to certain executive officers.
Units to be delivered as restricted units, upon the vesting of phantom units or performance units, or upon exercise of a unit option or unit appreciation right may be new units issued by the Company, units acquired by the Company in the open market, units acquired by the Company from any other person, units already owned by the Company, or any combination of the foregoing. If the Company issues new units upon the grant of restricted units, vesting of phantom units or performance units, or exercise of a unit option or unit appreciation right, the total number of units outstanding will increase. To date, the Company has issued awards of unrestricted units, restricted units, phantom units, performance units and unit options. The LTIP provides for all of the following types of awards:
Unit Grants – A unit grant is the grant of an unrestricted unit that vests immediately upon issuance.
Restricted Units – A restricted unit is a unit that vests over a period of time and that during such time is subject to forfeiture. The Company intends the restricted units under the LTIP to serve as a means of incentive compensation for performance. Therefore, LTIP participants do not pay any consideration for the units they receive.
Phantom Units – A phantom unit entitles the grantee to receive a unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a unit. The Compensation Committee may grant tandem distribution equivalent rights with respect to phantom units that entitle the holder to receive cash equal to any cash distributions made on units while the phantom units are outstanding. The Compensation Committee determines the period over which phantom units will vest, subject to applicable minimum vesting periods except with respect to phantom unit grants to nonemployee directors. The Company intends the phantom units under the LTIP to serve as a means of incentive compensation for performance. Therefore, LTIP participants do not pay any consideration for the units they receive.
Unit Options – A unit option is a right to purchase a unit at a specified price. Unit options have an exercise price that is equal to the fair market value of the units on the date of grant.
Performance Units – A performance unit is a unit that vests over a period of time in an amount based on certain comparative performance criteria. The Company intends the performance units under the LTIP to serve as a means of incentive compensation for performance. Therefore, LTIP participants do not pay any consideration for the units they receive.
Unit Appreciation Rights – A unit appreciation right is an award that, upon exercise, entitles the participant to receive the excess of the fair market value of a unit on the exercise date over the exercise price established for the unit appreciation right. The excess may be paid in the Company’s units, cash or a combination thereof, as
93
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
determined by the Compensation Committee in its discretion. To date, the Company has not granted any unit appreciation rights.
Cancellation of Awards
In December 2016, the Company canceled all of its then-outstanding nonvested restricted units, phantom units and performance unit awards, as well as its then-outstanding unit options, without consideration given to the employees. As a result, the Company recognized unit-based compensation expenses of approximately $14 million for the year ended December 31, 2016, associated with previously unrecognized compensation costs for awards that were canceled before the completion of the requisite service period. There were no awards outstanding under the LTIP as of December 31, 2016.
Accounting for Unit-Based Compensation
The Company recognizes as expense, beginning at the grant date, the fair value of equity-based compensation issued to employees and nonemployee directors. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period using the straight-line method in the Company’s consolidated statements of operations. A summary of unit-based compensation expenses included on the consolidated statements of operations is presented below:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
General and administrative expenses | $ | 34,268 | $ | 47,312 | $ | 45,195 | |||||
Lease operating expenses | 9,950 | 8,824 | 8,089 | ||||||||
Total unit-based compensation expenses | $ | 44,218 | $ | 56,136 | $ | 53,284 | |||||
Income tax benefit | $ | 16,339 | $ | 20,742 | $ | 19,688 | |||||
Restricted Units/Phantom Units/Unrestricted Units
The fair value of restricted units, phantom units and unrestricted unit grants issued is determined based on the fair market value of the Company units on the date of grant. As of December 31, 2016, a summary of the status of the nonvested units is presented below:
Number of Nonvested Units | Weighted Average Grant-Date Fair Value Per Unit | |||||
Nonvested units at December 31, 2015 | 4,926,572 | $ | 16.22 | |||
Vested | (2,069,004 | ) | $ | 19.66 | ||
Forfeited | (349,243 | ) | $ | 14.29 | ||
Canceled | (2,508,325 | ) | $ | 13.95 | ||
Nonvested units at December 31, 2016 | — | $ | — | |||
No restricted units, phantom units or unrestricted units were granted during the year ended December 31, 2016. The weighted average grant-date fair value of restricted units, phantom units and unrestricted units granted was $10.21 per unit and $33.10 per unit during the years ended December 31, 2015, and December 31, 2014, respectively. The total fair value of units that vested was approximately $41 million, $49 million and $42 million for the years ended December 31, 2016, December 31, 2015, and December 31, 2014, respectively. There were no unrecognized compensation costs as of December 31, 2016.
94
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Cash-Based Performance Unit Awards
In January 2015, the Company granted 567,320 performance units (the maximum number of units available to be earned) to certain executive officers. The 2015 performance unit awards were to vest three years from the award date, with vesting determined based on the Company’s performance compared to the performance of a predetermined group of peer companies over a specified performance period, and the value of vested units was to be paid in cash. To date, no performance units have vested and no amounts have been paid to settle any such awards. In December 2016, the Company canceled all of its then-outstanding nonvested performance unit awards. There were no awards outstanding under the LTIP as of December 31, 2016.
Unit Options
The following provides information related to unit option activity for the year ended December 31, 2016:
Number of Units Underlying Options | Weighted Average Exercise Price Per Unit | Weighted Average Remaining Contractual Life in Years | Aggregate Intrinsic Value | ||||||||||
Outstanding at December 31, 2015 | 824,711 | $ | 22.72 | 2.27 | $ | — | |||||||
Forfeited or expired | (184,498 | ) | $ | 25.80 | |||||||||
Canceled | (640,213 | ) | $ | 21.83 | |||||||||
Outstanding at December 31, 2016 | — | $ | — | — | $ | — | |||||||
Exercisable at December 31, 2016 | — | $ | — | — | $ | — | |||||||
No unit options were granted during the years ended December 31, 2016, December 31, 2015 or December 31, 2014. There were no unit options exercised during the years ended December 31, 2016, or December 31, 2015. During the year ended December 31, 2014, the total intrinsic value of unit options exercised was approximately $11 million. There were no unrecognized compensation costs as of December 31, 2016.
Defined Contribution Plan
The Company sponsors a 401(k) defined contribution plan for eligible employees. For the years 2014 through 2016, Company contributions to the 401(k) plan consisted of a discretionary matching contribution equal to 100% of the first 6% of eligible compensation contributed by the employee on a before-tax basis. The Company contributed approximately $9 million, $11 million and $10 million during the years ended December 31, 2016, December 31, 2015, and December 31, 2014, respectively, to the 401(k) plan’s trustee account. The 401(k) plan funds are held in a trustee account on behalf of the plan participants.
95
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 6 – Debt
The following summarizes the Company’s outstanding debt:
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands, except percentages) | |||||||
LINN credit facility (1) | $ | 1,654,745 | $ | 2,215,000 | |||
Berry credit facility (2) | — | 873,175 | |||||
Term loan (2) | 284,241 | 500,000 | |||||
6.50% senior notes due May 2019 | 562,234 | 562,234 | |||||
6.25% senior notes due November 2019 | 581,402 | 581,402 | |||||
8.625% senior notes due April 2020 | 718,596 | 718,596 | |||||
6.75% Berry senior notes due November 2020 | — | 261,100 | |||||
12.00% senior secured second lien notes due December 2020 (3) | 1,000,000 | 1,000,000 | |||||
Interest payable on senior secured second lien notes due December 2020 (3) | — | 608,333 | |||||
7.75% senior notes due February 2021 | 779,474 | 779,474 | |||||
6.50% senior notes due September 2021 | 381,423 | 381,423 | |||||
6.375% Berry senior notes due September 2022 | — | 572,700 | |||||
Net unamortized discounts and premiums (4) | — | (8,694 | ) | ||||
Net unamortized deferred financing fees (4) | (1,257 | ) | (37,374 | ) | |||
Total debt, net | 5,960,858 | 9,007,369 | |||||
Less current portion, net (5) | (1,937,729 | ) | (2,841,518 | ) | |||
Less liabilities subject to compromise (6) | (4,023,129 | ) | — | ||||
Less debt and unamortized premiums of discontinued operations | — | (1,718,543 | ) | ||||
Long-term debt, net | $ | — | $ | 4,447,308 | |||
(1) | Variable interest rates of 5.50% and 2.66% at December 31, 2016, and December 31, 2015, respectively. |
(2) | Variable interest rates of 5.50% and 3.17% at December 31, 2016, and December 31, 2015, respectively. |
(3) | The issuance of the Second Lien Notes was accounted for as a troubled debt restructuring which requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized. During the year ended December 31, 2016, $551 million was written off to reorganization items in connection with the filing of the Bankruptcy Petitions. The remaining amount of approximately $57 million was classified as liabilities subject to compromise at December 31, 2016. |
(4) | Approximately $52 million in net discounts, premiums and deferred financing fees were written off to reorganization items in connection with the filing of the Bankruptcy Petitions. |
(5) | Due to existing and anticipated covenant violations, the Company’s Credit Facilities and term loan were classified as current at December 31, 2016, and December 31, 2015. The current portion as of December 31, 2015, also includes approximately $128 million of interest payable on the Second Lien Notes that was due within one year. |
(6) | The Company’s senior notes and Second Lien Notes were classified as liabilities subject to compromise at December 31, 2016. |
As described in Note 3, the Company deconsolidated Berry effective December 3, 2016. Therefore, the Company reports no debt for Berry as of December 31, 2016.
Fair Value
The Company’s debt is recorded at the carrying amount on the consolidated balance sheets. The carrying amounts of the Company’s credit facilities and term loan approximate fair value because the interest rates are variable and reflective of market rates. The Company uses a market approach to determine the fair value of its senior secured second lien notes and
96
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
senior notes using estimates based on prices quoted from third-party financial institutions, which is a Level 2 fair value measurement.
December 31, 2016 | December 31, 2015 | ||||||||||||||
Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||
(in thousands) | |||||||||||||||
Senior secured second lien notes | $ | 1,000,000 | $ | 863,750 | $ | 1,000,000 | $ | 501,250 | |||||||
Senior notes, net | 3,023,129 | 1,179,224 | 2,967,308 | 461,930 | |||||||||||
Credit Facilities
LINN Credit Facility
The Predecessor’s Sixth Amended and Restated Credit Agreement (“LINN Credit Facility”) provides for (1) a senior secured revolving credit facility and (2) a senior secured term loan, in aggregate subject to the then-effective borrowing base. The maturity date is April 2019, subject to a “springing maturity” based on the maturity of any outstanding LINN Energy junior lien debt. At December 31, 2016, the Company had approximately $1.7 billion in total borrowings outstanding (including outstanding letters of credit) under the revolving credit facility and approximately $284 million under the term loan, and there was no remaining availability.
See Note 2 for details of the amendment to the LINN Credit Facility entered into on April 12, 2016.
Redetermination of the borrowing base under the LINN Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually. The Company’s obligations under the LINN Credit Facility are secured by mortgages on certain of its material subsidiaries’ oil and natural gas properties and other personal property as well as a pledge of all ownership interests in the Company’s direct and indirect material subsidiaries. The Company is required to maintain: 1) mortgages on properties representing at least 90% of the total value of oil and natural gas properties included on its most recent reserve report; 2) a minimum liquidity requirement equal to the greater of $500 million and 15% of the then effective available borrowing base after giving effect to certain redemptions or repurchases of certain debt; and 3) an EBITDA to Interest Expense ratio of at least 2.0 to 1.0 currently, 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and 2.5 to 1.0 thereafter. Additionally, the obligations under the LINN Credit Facility are guaranteed by all of the Company’s material subsidiaries, other than Berry, and are required to be guaranteed by any future material subsidiaries.
At the Company’s election, interest on borrowings under the LINN Credit Facility is determined by reference to either the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the LINN Credit Facility) or the alternate base rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the LINN Credit Facility). Interest is generally payable monthly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The Company is required to pay a commitment fee to the lenders under the LINN Credit Facility, which accrues at a rate per annum of 0.50% on the average daily unused amount of the maximum commitment amount of the lenders.
The term loan has a maturity date of April 2019, subject to a “springing maturity” based on the maturity of any outstanding LINN Energy junior lien debt, and incurs interest based on either the LIBOR plus a margin of 2.75% per annum or the ABR plus a margin of 1.75% per annum, at the Company’s election. Interest is generally payable monthly for loans bearing interest based on the ABR and at the end of the applicable interest period for loans bearing interest at the LIBOR. The term loan may be repaid at the option of the Company without premium or penalty, subject to breakage costs. While the term loan is outstanding, the Company is required to maintain either: 1) mortgages on properties representing at least 80% of the total value of oil and natural gas properties included on its most recent reserve report, or 2) a Term Loan Collateral Coverage Ratio of at least 2.5 to 1.0. The Term Loan Collateral Coverage Ratio is defined as the ratio of the present value of future cash flows from proved reserves from the currently mortgaged properties to the lesser of: (i) the then-effective borrowing base and (ii) the maximum commitment amount and the aggregate amount of the term loan outstanding. The other terms and
97
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
conditions of the LINN Credit Facility, including the financial and other restrictive covenants set forth therein, are applicable to the term loan.
Berry Credit Facility
Berry’s Second Amended and Restated Credit Agreement (“Berry Credit Facility”) provides for a senior secured revolving credit facility, subject to the then-effective borrowing base. The maturity date is April 2019.
Redetermination of the borrowing base under the Berry Credit Facility, based primarily on reserve reports using lender commodity price expectations at such time, occurs semi-annually. Berry’s obligations under the Berry Credit Facility are secured by mortgages on its oil and natural gas properties and other personal property. Berry is required to maintain: 1) mortgages on properties representing at least 90% of the present value of oil and natural gas properties included on its most recent reserve report, and 2) an EBITDAX to Interest Expense ratio of at least 2.0 to 1.0 currently, 2.25 to 1.0 from March 31, 2017 through June 30, 2017 and 2.5 to 1.0 thereafter. In accordance with the amendment described in Note 2, the lenders had agreed that the failure to maintain the EBITDAX to Interest Expense ratio would not result in a default or event of default until May 11, 2016.
At Berry’s election, interest on borrowings under the Berry Credit Facility is determined by reference to either the LIBOR plus an applicable margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowings under the Berry Credit Facility) or a Base Rate (as defined in the Berry Credit Facility) plus an applicable margin between 0.75% and 1.75% per annum (depending on the then-current level of borrowings under the Berry Credit Facility). Interest is generally payable monthly for loans bearing interest based on the Base Rate and at the end of the applicable interest period for loans bearing interest at the LIBOR. Berry is required to pay a commitment fee to the lenders under the Berry Credit Facility, which accrues at a rate per annum of 0.50% on the average daily unused amount of the maximum commitment amount of the lenders.
The Company refers to the LINN Credit Facility and the Berry Credit Facility, collectively, as the “Credit Facilities.”
The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Credit Facilities. However, under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of the default.
Senior Secured Second Lien Notes Due December 2020
On November 20, 2015, the Company issued $1.0 billion in aggregate principal amount of 12.00% senior secured second lien notes due December 2020 (“Second Lien Notes”) in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes as follows:
Par Value of Senior Notes Exchanged | |||
(in thousands) | |||
6.50% senior notes due May 2019 | $ | 584,422 | |
6.25% senior notes due November 2019 | 824,348 | ||
8.625% senior notes due April 2020 | 286,344 | ||
7.75% senior notes due February 2021 | 184,300 | ||
6.50% senior notes due September 2021 | 120,586 | ||
$ | 2,000,000 | ||
The exchanges were accounted for as a troubled debt restructuring (“TDR”). Since the total future cash payments of the new debt were less than the carrying amount of the previous debt, a gain of approximately $352 million, or $1.03 per unit, was recognized for the year ended December 31, 2015, and included in “gain on extinguishment of debt” on the consolidated
98
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
statement of operations. TDR accounting requires that interest payments on the Second Lien Notes reduce the carrying value of the debt with no interest expense recognized.
Repurchases of Senior Notes
The Company made no repurchases of its senior notes during the year ended December 31, 2016. During the year ended December 31, 2015, the Company repurchased, through privately negotiated transactions and on the open market, approximately $927 million of its outstanding senior notes as follows:
• | 6.50% senior notes due May 2019 – $53 million; |
• | 6.25% senior notes due November 2019 – $395 million; |
• | 8.625% senior notes due April 2020 – $295 million; |
• | 7.75% senior notes due February 2021 – $36 million; and |
• | 6.50% senior notes due September 2021 – $148 million. |
In connection with the repurchases, the Company paid approximately $553 million in cash and recorded a gain on extinguishment of debt of approximately $356 million for the year ended December 31, 2015.
Notes Covenants
The Second Lien Indenture contains covenants that, among other things, may limit the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) declare or pay distributions on, purchase or redeem the Company’s units or purchase or redeem the Company’s or its restricted subsidiaries’ indebtedness secured by liens junior in priority to liens securing the Second Lien Notes, unsecured indebtedness or subordinated indebtedness; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
The Company’s senior notes contain covenants that, among other things, may limit its ability to: (i) pay distributions on, purchase or redeem the Company’s units or redeem its subordinated debt; (ii) make investments; (iii) incur or guarantee additional indebtedness or issue certain types of equity securities; (iv) create certain liens; (v) sell assets; (vi) consolidate, merge or transfer all or substantially all of the Company’s assets; (vii) enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries.
Berry’s senior notes contain covenants that, among other things, may limit its ability to: (i) incur or guarantee additional indebtedness; (ii) pay distributions or dividends on Berry’s equity or redeem its subordinated debt; (iii) create certain liens; (iv) enter into agreements that restrict distributions or other payments from Berry’s restricted subsidiaries to Berry; (v) sell assets; (vi) engage in transactions with affiliates; and (vii) consolidate, merge or transfer all or substantially all of Berry’s assets.
In addition, any cash generated by Berry is currently being used by Berry to fund its activities. Historically, to the extent that Berry generated cash in excess of its needs and determined to distribute such amounts to LINN Energy, the indentures governing Berry’s senior notes limited the amount it could distribute to LINN Energy to the amount available under a “restricted payments basket,” and Berry could not distribute any such amounts unless it is permitted by the indentures to incur additional debt pursuant to the consolidated coverage ratio test set forth in the Berry indentures. During the pendency of the bankruptcy proceedings, Berry did not distribute cash to LINN Energy using the restricted payments basket.
The filing of the Bankruptcy Petitions constituted an event of default that accelerated the Company’s obligations under the Second Lien Indenture and the senior notes. However, under the Bankruptcy Code, holders of the Second Lien Notes and the senior notes were stayed from taking any action against the Company as a result of the default.
99
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Covenant Violations
The Company’s filing of the Bankruptcy Petitions described in Note 2 constituted an event of default that accelerated the Company’s obligations under its Credit Facilities, its Second Lien Notes and its senior notes. Additionally, other events of default, including cross-defaults, have occurred, including the failure to make interest payments on the Company’s Second Lien Notes and senior notes, as well as the receipt of a going concern explanatory paragraph from the Company’s independent registered public accounting firm on the Company’s consolidated financial statements for the year ended December 31, 2015. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against the Company as a result of an event of default.
Note 7 – Derivatives
Commodity Derivatives
Historically, the Company has hedged a portion of its forecasted production to reduce exposure to fluctuations in oil and natural gas prices and provide long-term cash flow predictability to manage its business. The current direct NGL hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits the Company’s ability to effectively hedge its NGL production. The Company has also hedged its exposure to differentials in certain operating areas but does not currently hedge exposure to oil or natural gas differentials.
The Company has historically entered into commodity hedging transactions primarily in the form of swap contracts that are designed to provide a fixed price, collars and, from time to time, put options that are designed to provide a fixed price floor with the opportunity for upside. The Company enters into these transactions with respect to a portion of its projected production or consumption to provide an economic hedge of the risk related to the future commodity prices received or paid. The Company does not enter into derivative contracts for trading purposes. The Company did not designate any of its contracts as cash flow hedges; therefore, the changes in fair value of these instruments are recorded in current earnings. See Note 8 for fair value disclosures about oil and natural gas commodity derivatives.
The following table presents derivative positions for the periods indicated as of December 31, 2016:
2017 | 2018 | 2019 | |||||||||
Natural gas positions: | |||||||||||
Fixed price swaps (NYMEX Henry Hub): | |||||||||||
Hedged volume (MMMBtu) | 135,050 | 40,150 | 3,650 | ||||||||
Average price ($/MMBtu) | $ | 3.17 | $ | 3.02 | $ | 3.08 | |||||
Oil positions: | |||||||||||
Fixed price swaps (NYMEX WTI): | |||||||||||
Hedged volume (MBbls) | 4,380 | — | — | ||||||||
Average price ($/Bbl) | $ | 52.13 | $ | — | $ | — | |||||
Collars (NYMEX WTI): | |||||||||||
Hedged volume (MBbls) | — | 1,825 | 1,825 | ||||||||
Average floor price ($/Bbl) | $ | — | $ | 50.00 | $ | 50.00 | |||||
Average ceiling price ($/Bbl) | $ | — | $ | 55.50 | $ | 55.50 | |||||
In accordance with a Bankruptcy Court order dated August 16, 2016, the Company was authorized to enter into postpetition hedging arrangements. During the year ended December 31, 2016, LINN Energy entered into commodity derivative contracts consisting of natural gas swaps for October 2016 through December 2019, oil swaps for November 2016 through December 2017, and oil collars for January 2018 through December 2019.
100
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In April 2016 and May 2016, in connection with the Company’s restructuring efforts, LINN Energy canceled (prior to the contract settlement dates) all of its then-outstanding derivative contracts for net proceeds of approximately $1.2 billion. The net proceeds were used to make permanent repayments of a portion of the borrowings outstanding under the LINN Credit Facility.
During the fourth quarter of 2015, the Company canceled certain of its commodity derivative contracts, consisting of Permian basis swaps for 2016 and 2017, trade month roll swaps for 2016 and 2017, and positions representing oil swaps which could have been extended at counterparty election for 2017. The Company received net cash settlements of approximately $5 million from the cancellations.
The natural gas derivatives are settled based on the closing price of NYMEX Henry Hub natural gas on the last trading day for the delivery month, which occurs on the third business day preceding the delivery month, or the relevant index prices of natural gas published in Inside FERC’s Gas Market Report on the first business day of the delivery month. The oil derivatives are settled based on the average closing price of NYMEX WTI crude oil for each day of the delivery month.
Balance Sheet Presentation
The Company’s commodity derivatives are presented on a net basis in “derivative instruments” on the consolidated balance sheets. The following table summarizes the fair value of derivatives outstanding on a gross basis:
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Assets: | |||||||
Commodity derivatives | $ | 19,369 | $ | 1,798,568 | |||
Liabilities: | |||||||
Commodity derivatives | $ | 113,226 | $ | 26,012 | |||
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the 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 owes the Company, which creates credit risk. The Company’s counterparties are current participants or affiliates of participants in the LINN Credit Facility and the Exit Facility. The LINN Credit Facility was secured by the Company’s oil, natural gas and NGL reserves; therefore, the Company was not required to post any collateral. The Company does not receive collateral from its counterparties.
The maximum amount of loss due to credit risk that the Company would incur if its counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $19 million at December 31, 2016. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; (ii) entering into derivative instruments only with counterparties that meet the Company’s minimum credit quality standard, or have a guarantee from an affiliate that meets the Company’s minimum credit quality standard; and (iii) monitoring the creditworthiness of the Company’s counterparties on an ongoing basis. In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss due to counterparty nonperformance is somewhat mitigated.
Gains (Losses) on Derivatives
Gains and losses on derivatives were net losses of approximately $164 million for the year ended December 31, 2016, and net gains of approximately $1.0 billion and $1.1 billion for the years ended December 31, 2015, and December 31, 2014, respectively, and are reported on the consolidated statements of operations in “gains (losses) on oil and natural gas derivatives.”
101
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
For the years ended December 31, 2016, December 31, 2015, and December 31, 2014, the Company received net cash settlements of approximately $861 million, $1.1 billion and $89 million, respectively. In addition, during the year ended December 31, 2016, approximately $841 million in settlements (primarily in connection with the April 2016 and May 2016 commodity derivative cancellations) were paid directly by the counterparties to the lenders under the LINN Credit Facility as repayments of a portion of the borrowings outstanding.
Note 8 – Fair Value Measurements on a Recurring Basis
The Company accounts for its commodity derivatives at fair value (see Note 7) on a recurring basis. The Company determines the fair value of its oil and natural gas derivatives utilizing pricing models that use a variety of techniques, including market quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those instruments trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives.
Fair Value Hierarchy
In accordance with applicable accounting standards, the Company has categorized its financial instruments, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Financial assets and liabilities recorded in the consolidated balance sheets are categorized based on the inputs to the valuation techniques as follows:
Level 1 | Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. |
Level 2 | Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability (commodity derivatives). |
Level 3 | Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. |
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on a quarterly basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities.
The following presents the fair value hierarchy for assets and liabilities measured at fair value on a recurring basis:
December 31, 2016 | |||||||||||
Level 2 | Netting (1) | Total | |||||||||
(in thousands) | |||||||||||
Assets: | |||||||||||
Commodity derivatives | $ | 19,369 | $ | (19,369 | ) | $ | — | ||||
Liabilities: | |||||||||||
Commodity derivatives | $ | 113,226 | $ | (19,369 | ) | $ | 93,857 | ||||
102
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
December 31, 2015 | |||||||||||
Level 2 | Netting (1) | Total | |||||||||
(in thousands) | |||||||||||
Assets: | |||||||||||
Commodity derivatives | $ | 1,798,568 | $ | (25,155 | ) | $ | 1,773,413 | ||||
Liabilities: | |||||||||||
Commodity derivatives | $ | 26,012 | $ | (25,155 | ) | $ | 857 | ||||
(1) | Represents counterparty netting under agreements governing such derivatives. |
Note 9 – Other Property and Equipment
Other property and equipment consists of the following:
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Natural gas plant and pipeline | $ | 421,806 | $ | 480,161 | |||
Furniture and office equipment | 105,353 | 106,462 | |||||
Buildings and leasehold improvements | 66,014 | 72,976 | |||||
Vehicles | 31,496 | 37,641 | |||||
Drilling and other equipment | 8,082 | 7,934 | |||||
Land | 3,736 | 3,537 | |||||
636,487 | 708,711 | ||||||
Less accumulated depreciation | (224,547 | ) | (195,661 | ) | |||
Less other property and equipment, net – discontinued operations | — | (98,973 | ) | ||||
$ | 411,940 | $ | 414,077 | ||||
Note 10 – Asset Retirement Obligations
The Company has the obligation to plug and abandon oil and natural gas wells and related equipment at the end of production operations. Estimated asset retirement costs are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets when the obligation is incurred. The liabilities are included in “other accrued liabilities” and “other noncurrent liabilities” on the consolidated balance sheets. Accretion expense is included in “depreciation, depletion and amortization” on the consolidated statements of operations. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; ); and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
103
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The following table presents a reconciliation of the Company’s asset retirement obligations:
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Asset retirement obligations at beginning of year | $ | 523,541 | $ | 497,570 | |||
Liabilities added from drilling | 546 | 3,574 | |||||
Liabilities added from acquisitions | 1,416 | — | |||||
Liabilities associated with assets divested | — | (3,306 | ) | ||||
Deconsolidation of Berry Petroleum Company, LLC asset retirement obligations | (141,612 | ) | — | ||||
Current year accretion expense | 30,498 | 30,016 | |||||
Settlements | (12,823 | ) | (6,336 | ) | |||
Revision of estimates | 596 | 2,023 | |||||
402,162 | 523,541 | ||||||
Less asset retirement obligations of discontinued operations | — | (137,563 | ) | ||||
Asset retirement obligations at end of year | $ | 402,162 | $ | 385,978 | |||
Note 11 – Commitments and Contingencies
On May 11, 2016, the Debtors filed Bankruptcy Petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors’ Chapter 11 cases are being administered jointly under the caption In re Linn Energy, LLC., et al., Case No. 16‑60040. On January 27, 2017, the Bankruptcy Court entered the Confirmation Order. Consummation of the LINN Plan was subject to certain conditions set forth in the LINN Plan. On the Effective Date, all of the conditions were satisfied or waived and the LINN Plan became effective and was implemented in accordance with its terms. The LINN Debtors Chapter 11 cases will remain pending until the final resolution of all outstanding claims.
The commencement of the Chapter 11 proceedings automatically stayed certain actions against the Company, including actions to collect prepetition liabilities or to exercise control over the property of the Company’s bankruptcy estates. For certain statewide class action royalty payment disputes, the Company filed notices advising that it had filed for bankruptcy protection and seeking a stay, which was granted. However, the Company is, and will continue to be until the final resolution of all claims, subject to certain contested matters and adversary proceedings stemming from the Chapter 11 proceedings.
The Company is not currently a party to any litigation or pending claims that it believes would have a material adverse effect on its overall business, financial position, results of operations or liquidity; however, cash flow could be significantly impacted in the reporting periods in which such matters are resolved.
During the years ended December 31, 2016, December 31, 2015, and December 31, 2014, the Company made no significant payments to settle any legal, environmental or tax proceedings. The Company regularly analyzes current information and accrues for probable liabilities on the disposition of certain matters as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Note 12 – Operating Leases
The Company leases office space and other property and equipment under lease agreements expiring on various dates through 2034. The Company recognized expense under operating leases of approximately $9 million, $15 million and $7 million for the years ended December 31, 2016, December 31, 2015, and December 31, 2014, respectively.
104
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
As of December 31, 2016, future minimum lease payments were as follows (in thousands):
2017 | $ | 3,627 | |
2018 | 2,852 | ||
2019 | 2,008 | ||
2020 | 468 | ||
2021 | 4 | ||
Thereafter | 60 | ||
$ | 9,019 | ||
Note 13 – Earnings Per Unit
Basic earnings per unit is computed by dividing net earnings attributable to unitholders by the weighted average number of units outstanding during each period. Diluted earnings per unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. The Company uses the treasury stock method to determine the dilutive effect.
The following table provides a reconciliation of the numerators and denominators of the basic and diluted per unit computations for net income (loss):
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands, except per unit data) | |||||||||||
Loss from continuing operations | $ | (385,697 | ) | $ | (3,744,634 | ) | $ | (474,405 | ) | ||
Allocated to participating securities | — | (3,039 | ) | (7,117 | ) | ||||||
$ | (385,697 | ) | $ | (3,747,673 | ) | $ | (481,522 | ) | |||
Income (loss) from discontinued operations, net of income taxes | $ | (1,786,159 | ) | $ | (1,015,177 | ) | $ | 22,596 | |||
Net loss | $ | (2,171,856 | ) | $ | (4,759,811 | ) | $ | (451,809 | ) | ||
Allocated to participating securities | — | (3,039 | ) | (7,117 | ) | ||||||
$ | (2,171,856 | ) | $ | (4,762,850 | ) | $ | (458,926 | ) | |||
Basic loss per unit – continuing operations | $ | (1.10 | ) | $ | (10.91 | ) | $ | (1.47 | ) | ||
Diluted loss per unit – continuing operations | $ | (1.10 | ) | $ | (10.91 | ) | $ | (1.47 | ) | ||
Basic income (loss) per unit – discontinued operations | $ | (5.06 | ) | $ | (2.96 | ) | $ | 0.07 | |||
Diluted income (loss) per unit – discontinued operations | $ | (5.06 | ) | $ | (2.96 | ) | $ | 0.07 | |||
Basic net loss per unit | $ | (6.16 | ) | $ | (13.87 | ) | $ | (1.40 | ) | ||
Diluted net loss per unit | $ | (6.16 | ) | $ | (13.87 | ) | $ | (1.40 | ) | ||
Basic weighted average units outstanding | 352,653 | 343,323 | 328,918 | ||||||||
Dilutive effect of unit equivalents | — | — | — | ||||||||
Diluted weighted average units outstanding | 352,653 | 343,323 | 328,918 | ||||||||
105
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Basic units outstanding excludes the effect of weighted average anti-dilutive unit equivalents related to approximately 1 million, 4 million and 6 million unit options and warrants for the years ended December 31, 2016, December 31, 2015, and December 31, 2014, respectively. All equivalent units were antidilutive for each of the years ended December 31, 2016, December 31, 2015, and December 31, 2014.
Note 14 – Income Taxes
Prior to the consummation of the LINN Plan, the Company was a limited liability company treated as a partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Company are passed through to its unitholders. Limited liability companies are subject to Texas margin tax. In addition, certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. As such, with the exception of the state of Texas and certain subsidiaries, the Predecessor is not a taxable entity. The Predecessor does not directly pay federal and state income taxes and recognition has not been given to federal and state income taxes for the operations of the Predecessor, except as set forth in the tables below. Amounts recognized for income taxes are reported in “income tax expense (benefit)” on the consolidated statements of operations.
The Company’s taxable income or loss, which may vary substantially from the net income or net loss reported on the consolidated statements of operations, is includable in the federal and state income tax returns of each unitholder. The aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Company does not have access to information about each unitholder’s tax attributes.
Certain of the Company’s subsidiaries are Subchapter C-corporations subject to federal and state income taxes. Income tax expense (benefit) consisted of the following:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Current taxes: | |||||||||||
Federal | $ | (494 | ) | $ | (12,021 | ) | $ | 473 | |||
State | 321 | 1,022 | 21 | ||||||||
Deferred taxes: | |||||||||||
Federal | 11,582 | 8,237 | (104 | ) | |||||||
State | (215 | ) | (3,631 | ) | 3,978 | ||||||
$ | 11,194 | $ | (6,393 | ) | $ | 4,368 | |||||
As of December 31, 2016, the Company’s taxable entities had approximately $5 million of net operating loss carryforwards for federal income tax purposes which will begin expiring in 2036.
A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
Year Ended December 31, | ||||||||
2016 | 2015 | 2014 | ||||||
Federal statutory rate | 35.0 | % | 35.0 | % | 35.0 | % | ||
State, net of federal tax benefit | 0.7 | 0.1 | (0.9 | ) | ||||
Loss excluded from nontaxable entities | (24.7 | ) | (34.7 | ) | (34.5 | ) | ||
Other | (14.0 | ) | (0.2 | ) | (0.5 | ) | ||
Effective rate | (3.0 | )% | 0.2 | % | (0.9 | )% | ||
106
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Significant components of the deferred tax assets and liabilities were as follows:
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Deferred tax assets: | |||||||
Net operating loss carryforwards | $ | 1,730 | $ | 370 | |||
Reorganization items | 14,932 | — | |||||
Unit-based compensation | — | 18,214 | |||||
Valuation allowance | (19,558 | ) | (2,159 | ) | |||
Other | 10,030 | 7,300 | |||||
Total deferred tax assets | 7,134 | 23,725 | |||||
Deferred tax liabilities: | |||||||
Property and equipment principally due to differences in depreciation | (7,021 | ) | (12,534 | ) | |||
Other | (279 | ) | 10 | ||||
Total deferred tax liabilities | (7,300 | ) | (12,524 | ) | |||
Net deferred tax assets (liabilities) | $ | (166 | ) | $ | 11,201 | ||
The net deferred tax liabilities are recorded in “other noncurrent liabilities” and the net deferred tax assets are recorded in “other noncurrent assets” on the consolidated balance sheets at December 31, 2016, and December 31, 2015, respectively.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. At December 31, 2016, based on projections of future taxable income for the periods in which the deferred tax assets are deductible, valuation allowances of approximately $20 million were recorded for tax carryforwards and attributes to reduce the net deferred tax assets to an amount that is more likely than not to be realized.
In accordance with the applicable accounting standards, the Company recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Company developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Company’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Company had no material uncertain tax positions at December 31, 2016, or December 31, 2015. The tax years 2013 through 2016 remain open to examination for federal income tax purposes.
107
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 15 – Supplemental Disclosures to the Consolidated Balance Sheets and Consolidated Statements of Cash Flows
“Other current assets” reported on the balance sheets include the following:
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Prepaid expenses | $ | 70,116 | $ | 29,237 | |||
Inventories | 15,798 | 19,184 | |||||
Deferred financing fees | 16,809 | 25,090 | |||||
Other | 4,890 | 1,185 | |||||
Other current assets | $ | 107,613 | $ | 74,696 | |||
Supplemental disclosures to the consolidated statements of cash flows are presented below:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Cash payments for interest, net of amounts capitalized | $ | 143,305 | $ | 476,077 | $ | 446,860 | |||||
Cash payments for income taxes | $ | 4,427 | $ | 643 | $ | — | |||||
Cash payments for reorganization items, net | $ | 37,748 | $ | — | $ | — | |||||
Noncash investing activities: | |||||||||||
In connection with the acquisition of oil and natural gas properties and joint-venture funding, assets were acquired and liabilities were assumed as follow: | |||||||||||
Fair value of assets acquired | $ | — | $ | — | $ | 2,733,814 | |||||
Cash paid, net of cash acquired | — | — | (2,398,763 | ) | |||||||
Noncash gains on exchanges of properties | — | — | (149,195 | ) | |||||||
Receivables from sellers | — | — | 10,369 | ||||||||
Liabilities assumed | $ | — | $ | — | $ | 196,225 | |||||
Accrued capital expenditures | $ | 31,128 | $ | 71,105 | $ | 180,447 | |||||
For purposes of the consolidated statements of cash flows, the Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. Restricted cash of approximately $8 million and $7 million is included in “other noncurrent assets” on the consolidated balance sheets at December 31, 2016, and December 31, 2015, respectively, and represents cash deposited by the Company into a separate account designated for asset retirement obligations in accordance with contractual agreements.
During the year ended December 31, 2016, approximately $841 million in commodity derivative settlements (primarily in connection with the April 2016 and May 2016 commodity derivative cancellations) were paid directly by the counterparties to the lenders under the LINN Credit Facility as repayments of a portion of the borrowings outstanding, and are reflected as noncash transactions by the Company.
At December 31, 2016, and December 31, 2015, net outstanding checks of approximately $6 million and $21 million, respectively, were reclassified and included in “accounts payable and accrued expenses” on the consolidated balance sheets.
108
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Net outstanding checks are presented as cash flows from financing activities and included in “other” on the consolidated statements of cash flows.
Included in “acquisition of oil and natural gas properties and joint-venture funding, net of cash acquired” on the consolidated statement of cash flows for the year ended December 31, 2014, is approximately $25 million paid by the Company towards the future funding commitment related to the joint-venture agreement entered into with Anadarko (see Note 3).
In November 2015, the Company issued $1.0 billion in aggregate principal amount of Second Lien Notes in exchange for approximately $2.0 billion in aggregate principal amount of certain of its outstanding senior notes (see Note 6).
On November 21, 2014, the Company completed a noncash exchange of a portion of its Permian Basin properties to ExxonMobil in exchange for properties in California’s South Belridge Field. On August 15, 2014, the Company completed a noncash exchange of a portion of its Permian Basin properties to Exxon XTO for properties in the Hugoton Basin.
Note 16 – Significant Customers
The Company has a concentration of customers who are engaged in oil and natural gas purchasing, transportation and/or refining within the U.S. This concentration of customers may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. The Company’s customers consist primarily of major oil and natural gas purchasers and the Company generally does not require collateral since it has not experienced significant credit losses on such sales. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectibility (see Note 1).
For the years ended December 31, 2016, December 31, 2015, and December 31, 2014, no individual customer exceeded 10% of the Company’s sales.
At December 31, 2016, no individual customer exceeded 10% of the Company’s receivables. At December 31, 2015, trade accounts receivable from one customer represented approximately 12% of the Company’s receivables.
Note 17 – Related Party Transactions
Berry Petroleum Company, LLC
Berry, a former subsidiary of LINN Energy, was deconsolidated effective December 3, 2016 (see Note 3). The employees of Linn Operating, Inc. (“LOI”), a subsidiary of LINN Energy, provided services and support to Berry in accordance with an agency agreement and power of attorney between Berry and LOI. Upon deconsolidation, transactions between the Company and Berry are no longer eliminated in consolidation and are treated as related party transactions. These transactions include, but are not limited to, management fees paid to the Company by Berry.
For the years ended December 31, 2016, December 31, 2015, and December 31, 2014, Berry incurred management fees to the Company of approximately $69 million, $78 million and $86 million, respectively, for services provided by LOI. The Company also had accounts payable due to Berry of approximately $3 million included in “accounts payable and accrued expenses” and accounts receivable due from Berry of approximately $9 million included in “accounts receivable – trade, net” on the consolidated balance sheets at December 31, 2016, and December 31, 2015, respectively. In addition, $25 million due to Berry was included in “liabilities subject to compromise” on the Company’s consolidated balance sheet at December 31, 2016.
The Company made no capital contributions to Berry during the year ended December 31, 2016. During the year ended December 31, 2015, the Company made capital contributions of approximately $471 million to Berry, including $250 million which was deposited on Berry’s behalf and posted as restricted cash with Berry’s lenders in connection with the reduction of its borrowing base in May 2015. During the second quarter of 2014, the Company made a cash capital contribution of
109
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
approximately $220 million to Berry which was used to pay in full the remaining outstanding principal amount of Berry’s approximate $205 million 10.25% senior notes due June 2014 plus accrued interest.
The Company received no cash distributions from Berry during the year ended December 31, 2016. During the years ended December 31, 2015, and December 31, 2014, the Company received cash distributions of approximately $89 million and $119 million, respectively, from Berry. In addition, in 2014, Berry advanced approximately $352 million to the Company. The Company was required to use the cash from the advance on capital expenditures in respect of Berry’s operations, to repay Berry’s indebtedness or as otherwise permitted under the terms of Berry’s indentures and credit facility. During the twelve months ended September 30, 2015, the Company spent approximately $223 million, including approximately $58 million in 2014, on capital expenditures in respect of Berry’s operations. On September 30, 2015, the Company repaid in full the remaining advance of approximately $129 million to Berry.
LinnCo, LLC
LinnCo, an affiliate of the Predecessor, was formed on April 30, 2012. LinnCo’s initial sole purpose was to own units in LINN Energy. In connection with the 2013 acquisition of Berry, LinnCo amended its limited liability company agreement to permit, among other things, the acquisition and subsequent contribution of assets to LINN Energy. All of LinnCo’s common shares were held by the public. As of December 31, 2016, LinnCo had no significant assets or operations other than those related to its interest in LINN Energy and owned approximately 71% of LINN Energy’s outstanding units.
In March 2016, LinnCo filed a Registration Statement on Form S‑4 related to an offer to exchange each outstanding unit representing limited liability company interests of LINN Energy for one common share representing limited liability company interests of LinnCo. The initial offer expired on April 25, 2016, and on April 26, 2016, LinnCo commenced a subsequent offering period that expired on August 1, 2016. During the exchange period, 123,100,715 LINN Energy units were exchanged for an equal number of LinnCo shares. As a result of the exchanges of LINN Energy units for LinnCo shares, LinnCo’s ownership of LINN Energy’s outstanding units increased from approximately 37% at December 31, 2015, to approximately 71% at December 31, 2016.
LINN Energy has agreed to provide to LinnCo, or to pay on LinnCo’s behalf, any financial, legal, accounting, tax advisory, financial advisory and engineering fees, and other administrative and out-of-pocket expenses incurred by LinnCo, along with any other expenses incurred in connection with any public offering of shares in LinnCo or incurred as a result of being a publicly traded entity. These expenses include costs associated with annual, quarterly and other reports to holders of LinnCo shares, tax return and Form 1099 preparation and distribution, NASDAQ listing fees, printing costs, independent auditor fees and expenses, legal counsel fees and expenses, limited liability company governance and compliance expenses and registrar and transfer agent fees. In addition, the Company has agreed to indemnify LinnCo and its officers and directors for damages suffered or costs incurred (other than income taxes payable by LinnCo) in connection with carrying out LinnCo’s activities. All expenses and costs paid by LINN Energy on LinnCo’s behalf are expensed by LINN Energy.
For the year ended December 31, 2016, LinnCo incurred total general and administrative expenses, reorganization expenses and offering costs of approximately $6.1 million, including approximately $2.4 million related to services provided by LINN Energy. Of the expenses and costs incurred during 2016, approximately $5.9 million had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2016.
For the year ended December 31, 2015, LinnCo incurred total general and administrative expenses and certain offering costs of approximately $3.4 million, including approximately $2.0 million related to services provided by LINN Energy. All of the expenses and costs incurred during 2015 had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2015.
For the year ended December 31, 2014, LinnCo incurred total general and administrative expenses and offering costs of approximately $2.9 million, including approximately $1.9 million related to services provided by LINN Energy. All of the expenses and costs incurred during 2014 had been paid by LINN Energy on LinnCo’s behalf as of December 31, 2014. In addition, during the year ended December 31, 2014, LINN Energy paid approximately $11 million on LinnCo’s behalf for general and administrative expenses incurred by LinnCo in 2013.
110
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The Company did not pay any distributions to LinnCo during the year ended December 31, 2016. During the years ended December 31, 2015, and December 31, 2014, the Company paid approximately $121 million and $373 million, respectively, in distributions to LinnCo attributable to LinnCo’s interest in LINN Energy.
Other
One of the Company’s former directors is the President and Chief Executive Officer of Superior Energy Services, Inc. (“Superior”), which provides oilfield services to the Company. For the years ended December 31, 2016, December 31, 2015, and December 31, 2014, the Company incurred expenditures of approximately $5 million, $8 million and $21 million, respectively, related to services rendered by Superior and its subsidiaries.
Note 18 – Subsidiary Guarantors
Linn Energy, LLC’s senior notes due May 2019, senior notes due November 2019, senior notes due April 2020, Second Lien Notes, senior notes due February 2021 and senior notes due September 2021 are guaranteed by all of the Company’s material subsidiaries, other than Berry, which was an indirect 100% wholly owned subsidiary of the Company. As a result of the Chapter 11 proceedings, LINN Energy deconsolidated Berry effective December 3, 2016.
The Company is a holding company and has no independent assets or operations of its own, the guarantees under each series of notes are full and unconditional and joint and several, and any consolidated subsidiaries of the Company other than the subsidiary guarantors are minor. There are no restrictions on the Company’s ability to obtain cash dividends or other distributions of funds from the guarantor subsidiaries.
111
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited)
The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Property acquisition costs: (1) | |||||||||||
Proved | $ | — | $ | — | $ | 2,306,541 | |||||
Unproved | — | — | 793,742 | ||||||||
Exploration costs | 40,074 | 19,929 | 644 | ||||||||
Development costs | 86,053 | 298,028 | 925,750 | ||||||||
Asset retirement costs | 419 | 4,152 | 14,855 | ||||||||
Total costs incurred – continuing operations | $ | 126,546 | $ | 322,109 | $ | 4,041,532 | |||||
Total costs incurred – discontinued operations | $ | 11,147 | $ | 132,427 | $ | 1,040,152 | |||||
(1) | See Note 3 for details about the Company’s acquisitions. |
Oil and Natural Gas Capitalized Costs
Aggregate capitalized costs related to oil, natural gas and NGL production activities with applicable accumulated depletion and amortization are presented below:
December 31, | |||||||
2016 | 2015 | ||||||
(in thousands) | |||||||
Proved properties | $ | 12,234,099 | $ | 16,337,814 | |||
Unproved properties | 998,860 | 1,783,341 | |||||
13,232,959 | 18,121,155 | ||||||
Less accumulated depletion and amortization | (9,999,560 | ) | (11,097,492 | ) | |||
3,233,399 | 7,023,663 | ||||||
Less oil and natural gas capitalized costs, net – discontinued operations | — | (3,414,896 | ) | ||||
$ | 3,233,399 | $ | 3,608,767 | ||||
112
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued
Results of Oil and Natural Gas Producing Activities
The results of operations for oil, natural gas and NGL producing activities (excluding corporate overhead and interest costs) are presented below:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Revenues and other: | |||||||||||
Oil, natural gas and natural gas liquids sales | $ | 952,132 | $ | 1,151,240 | $ | 2,312,137 | |||||
Gains (losses) on oil and natural gas derivatives | (164,330 | ) | 1,027,014 | 1,127,395 | |||||||
787,802 | 2,178,254 | 3,439,532 | |||||||||
Production costs: | |||||||||||
Lease operating expenses | 317,046 | 375,840 | 443,157 | ||||||||
Transportation expenses | 161,037 | 167,561 | 165,489 | ||||||||
Severance taxes, ad valorem taxes and California carbon allowances | 73,806 | 111,350 | 169,417 | ||||||||
551,889 | 654,751 | 778,063 | |||||||||
Other costs: | |||||||||||
Exploration costs | 4,080 | 9,473 | 125,037 | ||||||||
Depletion and amortization | 356,825 | 504,493 | 726,567 | ||||||||
Impairment of long-lived assets | 165,044 | 4,960,144 | 2,050,387 | ||||||||
(Gains) losses on sale of assets and other, net | 417 | (199,296 | ) | (501,036 | ) | ||||||
Texas margin tax expense (benefit) | (649 | ) | (2,721 | ) | 3,984 | ||||||
525,717 | 5,272,093 | 2,404,939 | |||||||||
Results of operations – continuing operations | $ | (289,804 | ) | $ | (3,748,590 | ) | $ | 256,530 | |||
Results of operations – discontinued operations (1) | $ | (1,066,634 | ) | $ | (858,833 | ) | $ | 213,280 | |||
(1) | The results of discontinued operations for 2016 is for the period from January 1, 2016 through December 3, 2016. |
There is no federal tax provision included in the results above because the Company’s subsidiaries subject to federal tax do not own any of the Company’s oil and natural gas interests. Limited liability companies are subject to Texas margin tax. See Note 14 for additional information about income taxes.
113
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued
Proved Oil, Natural Gas and NGL Reserves
The proved reserves of oil, natural gas and NGL of the Company have been prepared by the independent engineering firm, DeGolyer and MacNaughton. In accordance with Securities and Exchange Commission (“SEC”) regulations, reserves at December 31, 2016, December 31, 2015, and December 31, 2014, were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. An analysis of the change in estimated quantities of oil, natural gas and NGL reserves, all of which are located within the U.S., is shown below:
Year Ended December 31, 2016 | |||||||||||||||||
Natural Gas (Bcf) | Oil (MMBbls) | NGL (MMBbls) | Total Continuing Operations (Bcfe) | Total Discontinued Operations (Bcfe) | Total (Bcfe) | ||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 2,231 | 103.4 | 97.3 | 3,435 | 1,053 | 4,488 | |||||||||||
Revisions of previous estimates | (9 | ) | (4.3 | ) | 0.9 | (29 | ) | (179 | ) | (208 | ) | ||||||
Extensions, discoveries and other additions | 265 | 10.1 | 15.2 | 417 | 11 | 428 | |||||||||||
Production | (187 | ) | (10.0 | ) | (9.3 | ) | (303 | ) | (81 | ) | (384 | ) | |||||
Deconsolidation of Berry Petroleum Company, LLC proved reserves | — | — | — | — | (804 | ) | (804 | ) | |||||||||
End of year | 2,300 | 99.2 | 104.1 | 3,520 | — | 3,520 | |||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 2,231 | 103.4 | 97.3 | 3,435 | 1,053 | 4,488 | |||||||||||
End of year | 2,128 | 93.3 | 94.4 | 3,254 | — | 3,254 | |||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | — | — | — | — | — | — | |||||||||||
End of year | 172 | 5.9 | 9.7 | 266 | — | 266 | |||||||||||
Year Ended December 31, 2015 | |||||||||||||||||
Natural Gas (Bcf) | Oil (MMBbls) | NGL (MMBbls) | Total Continuing Operations (Bcfe) | Total Discontinued Operations (Bcfe) | Total (Bcfe) | ||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 3,568 | 197.4 | 146.3 | 5,631 | 1,673 | 7,304 | |||||||||||
Revisions of previous estimates | (1,134 | ) | (81.9 | ) | (38.4 | ) | (1,855 | ) | (524 | ) | (2,379 | ) | |||||
Sales of minerals in place | (13 | ) | (4.1 | ) | (2.0 | ) | (50 | ) | — | (50 | ) | ||||||
Extensions, discoveries and other additions | 10 | 3.8 | 0.8 | 37 | 10 | 47 | |||||||||||
Production | (200 | ) | (11.8 | ) | (9.4 | ) | (328 | ) | (106 | ) | (434 | ) | |||||
End of year | 2,231 | 103.4 | 97.3 | 3,435 | 1,053 | 4,488 | |||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 2,997 | 141.7 | 117.5 | 4,552 | 1,266 | 5,818 | |||||||||||
End of year | 2,231 | 103.4 | 97.3 | 3,435 | 1,053 | 4,488 | |||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 571 | 55.7 | 28.8 | 1,079 | 407 | 1,486 | |||||||||||
End of year | — | — | — | — | — | — | |||||||||||
114
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued
Year Ended December 31, 2014 | |||||||||||||||||
Natural Gas (Bcf) | Oil (MMBbls) | NGL (MMBbls) | Total Continuing Operations (Bcfe) | Total Discontinued Operations (Bcfe) | Total (Bcfe) | ||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||
Beginning of year | 2,730 | 194.7 | 183.5 | 4,999 | 1,404 | 6,403 | |||||||||||
Revisions of previous estimates | 54 | (13.0 | ) | (45.3 | ) | (297 | ) | (21 | ) | (318 | ) | ||||||
Purchases of minerals in place | 1,354 | 45.0 | 54.4 | 1,951 | 544 | 2,495 | |||||||||||
Sales of minerals in place | (426 | ) | (22.8 | ) | (37.2 | ) | (786 | ) | (298 | ) | (1,084 | ) | |||||
Extensions, discoveries and other additions | 36 | 6.7 | 2.5 | 92 | 158 | 250 | |||||||||||
Production | (180 | ) | (13.2 | ) | (11.6 | ) | (328 | ) | (114 | ) | (442 | ) | |||||
End of year | 3,568 | 197.4 | 146.3 | 5,631 | 1,673 | 7,304 | |||||||||||
Proved developed reserves: | |||||||||||||||||
Beginning of year | 1,824 | 138.7 | 125.2 | 3,407 | 933 | 4,340 | |||||||||||
End of year | 2,997 | 141.7 | 117.5 | 4,552 | 1,266 | 5,818 | |||||||||||
Proved undeveloped reserves: | |||||||||||||||||
Beginning of year | 906 | 56.0 | 58.3 | 1,592 | 471 | 2,063 | |||||||||||
End of year | 571 | 55.7 | 28.8 | 1,079 | 407 | 1,486 | |||||||||||
The tables above include changes in estimated quantities of oil and NGL reserves shown in Mcf equivalents using the ratio of one barrel to six Mcf. Berry was deconsolidated effective December 3, 2016, and its reserves are reported as discontinued operations for all periods presented.
Proved reserves from continuing operations increased by approximately 85 Bcfe to approximately 3,520 Bcfe for the year ended December 31, 2016, from 3,435 Bcfe for the year ended December 31, 2015. The year ended December 31, 2016, includes approximately 29 Bcfe of negative revisions of previous estimates (107 Bcfe due to lower commodity prices partially offset by 78 Bcfe of positive revisions due to asset performance). In addition, extensions and discoveries, primarily from 211 productive wells drilled during the year, contributed approximately 417 Bcfe to the increase in proved reserves.
Proved reserves from continuing operations decreased by approximately 2,196 Bcfe to approximately 3,435 Bcfe for the year ended December 31, 2015, from 5,631 Bcfe for the year ended December 31, 2014. The year ended December 31, 2015, includes approximately 1,855 Bcfe of negative revisions of previous estimates (1,348 Bcfe due to lower commodity prices, 258 Bcfe due to uncertainty regarding the Company’s future commitment to capital, 237 Bcfe due to the SEC five-year development limitation on PUDs and 12 Bcfe of negative revisions due to asset performance). During the year ended December 31, 2015, divestitures including the Howard County Assets Sale decreased proved reserves by approximately 50 Bcfe. In addition, extensions and discoveries, primarily from 388 productive wells drilled during the year, contributed approximately 37 Bcfe to the increase in proved reserves. As a result of the uncertainty regarding the Company’s future commitment to capital, the Company reclassified all of its PUDs to unproved at December 31, 2015.
Proved reserves from continuing operations increased by approximately 632 Bcfe to approximately 5,631 Bcfe for the year ended December 31, 2014, from 4,999 Bcfe for the year ended December 31, 2013. The year ended December 31, 2014, includes approximately 297 Bcfe of negative revisions of previous estimates, due primarily to 174 Bcfe of negative revisions due to ethane rejection in the Hugoton and Green River basins, 129 Bcfe of negative revisions due to the SEC five-year development limitation on PUDs and 22 Bcfe of negative revisions due to asset performance, partially offset by 28 Bcfe of positive revisions primarily due to higher natural gas prices. During the year ended December 31, 2014, acquisitions and properties acquired in the two exchanges with Exxon XTO and ExxonMobil increased proved reserves by approximately 1,951 Bcfe and the 2014 divestitures and properties relinquished in the two exchanges with Exxon XTO and ExxonMobil
115
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued
decreased proved reserves by approximately 786 Bcfe. In addition, extensions and discoveries, primarily from 506 productive wells drilled during the year, contributed approximately 92 Bcfe to the increase in proved reserves.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves
Information with respect to the standardized measure of discounted future net cash flows relating to proved reserves is summarized below. Future cash inflows are computed by applying applicable prices relating to the Company’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses because the Predecessor was not subject to federal income taxes. Limited liability companies are subject to Texas margin tax; however, these amounts are not material. See Note 14 for additional information about income taxes.
December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Future estimated revenues | $ | 10,876,241 | $ | 11,810,044 | $ | 38,350,590 | |||||
Future estimated production costs | (6,286,264 | ) | (7,276,564 | ) | (16,358,433 | ) | |||||
Future estimated development costs | (971,055 | ) | (775,328 | ) | (2,899,781 | ) | |||||
Future net cash flows | 3,618,922 | 3,758,152 | 19,092,376 | ||||||||
10% annual discount for estimated timing of cash flows | (1,690,224 | ) | (1,719,979 | ) | (10,910,462 | ) | |||||
Standardized measure of discounted future net cash flows – continuing operations | $ | 1,928,698 | $ | 2,038,173 | $ | 8,181,914 | |||||
Standardized measure of discounted future net cash flows – discontinued operations | $ | — | $ | 995,372 | $ | 4,330,377 | |||||
Representative NYMEX prices: (1) | |||||||||||
Natural gas (MMBtu) | $ | 2.48 | $ | 2.59 | $ | 4.35 | |||||
Oil (Bbl) | $ | 42.64 | $ | 50.16 | $ | 95.27 | |||||
(1) | In accordance with SEC regulations, reserves were estimated using the average price during the 12-month period, determined as an unweighted average of the first-day-of-the-month price for each month, excluding escalations based upon future conditions. The average price used to estimate reserves is held constant over the life of the reserves. |
116
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL OIL AND NATURAL GAS DATA (Unaudited) - Continued
The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows:
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(in thousands) | |||||||||||
Sales and transfers of oil, natural gas and NGL produced during the period | $ | (400,243 | ) | $ | (496,489 | ) | $ | (1,534,074 | ) | ||
Changes in estimated future development costs | 18,843 | 1,069,971 | 88,324 | ||||||||
Net change in sales and transfer prices and production costs related to future production | (162,460 | ) | (6,105,531 | ) | 421,484 | ||||||
Purchases of minerals in place | — | — | 2,473,512 | ||||||||
Sales of minerals in place | — | (97,785 | ) | (1,194,601 | ) | ||||||
Extensions, discoveries and improved recovery | 221,765 | 69,745 | 236,395 | ||||||||
Previously estimated development costs incurred during the period | — | 91,719 | 550,514 | ||||||||
Net change due to revisions in quantity estimates | (9,291 | ) | (1,089,624 | ) | (606,104 | ) | |||||
Accretion of discount | 203,817 | 818,191 | 726,400 | ||||||||
Changes in production rates and other | 18,094 | (403,938 | ) | (243,933 | ) | ||||||
Change – continuing operations | $ | (109,475 | ) | $ | (6,143,741 | ) | $ | 917,917 | |||
Change – discontinued operations | $ | (995,372 | ) | $ | (3,335,005 | ) | $ | (304,955 | ) | ||
The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
117
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL QUARTERLY DATA (Unaudited)
The following discussion and analysis should be read in conjunction with the “Consolidated Financial Statements” and “Notes to Consolidated Financial Statements,” which are included in this Annual Report on Form 10-K in Item 8. “Financial Statements and Supplementary Data.”
Quarterly Financial Data
Quarters Ended | |||||||||||||||
March 31 | June 30 | September 30 | December 31 | ||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||
2016: | |||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 199,849 | $ | 216,426 | $ | 257,902 | $ | 277,955 | |||||||
Gains (losses) on oil and natural gas derivatives | 109,453 | (183,794 | ) | 166 | (90,155 | ) | |||||||||
Total revenues and other | 346,699 | 64,851 | 286,913 | 219,250 | |||||||||||
Total expenses (1) | 472,912 | 296,824 | 331,929 | 292,194 | |||||||||||
Losses on sale of assets and other, net | 1,269 | 2,517 | 2,310 | 9,462 | |||||||||||
Reorganization items, net | — | 485,798 | (28,361 | ) | (145,838 | ) | |||||||||
Income (loss) from continuing operations | (222,927 | ) | 201,652 | (99,927 | ) | (264,495 | ) | ||||||||
Income (loss) from discontinued operations, net of income taxes | (1,124,819 | ) | 6,840 | (98,438 | ) | (569,742 | ) | ||||||||
Net income (loss) | (1,347,746 | ) | 208,492 | (198,365 | ) | (834,237 | ) | ||||||||
Income (loss) per unit – continuing operations: | |||||||||||||||
Basic | $ | (0.64 | ) | $ | 0.57 | $ | (0.28 | ) | $ | (0.75 | ) | ||||
Diluted | $ | (0.64 | ) | $ | 0.57 | $ | (0.28 | ) | $ | (0.75 | ) | ||||
Income (loss) per unit – discontinued operations: | |||||||||||||||
Basic | $ | (3.19 | ) | $ | 0.02 | $ | (0.28 | ) | $ | (1.61 | ) | ||||
Diluted | $ | (3.19 | ) | $ | 0.02 | $ | (0.28 | ) | $ | (1.61 | ) | ||||
Net income (loss) per unit: | |||||||||||||||
Basic | $ | (3.83 | ) | $ | 0.59 | $ | (0.56 | ) | $ | (2.36 | ) | ||||
Diluted | $ | (3.83 | ) | $ | 0.59 | $ | (0.56 | ) | $ | (2.36 | ) | ||||
(1) | Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. |
118
LINN ENERGY, INC. (FORMERLY KNOWN AS LINN ENERGY, LLC)
(DEBTOR-IN-POSSESSION)
SUPPLEMENTAL QUARTERLY DATA (Unaudited) - Continued
Quarters Ended | |||||||||||||||
March 31 | June 30 | September 30 | December 31 | ||||||||||||
(in thousands, except per unit amounts) | |||||||||||||||
2015: | |||||||||||||||
Oil, natural gas and natural gas liquids sales | $ | 293,983 | $ | 323,038 | $ | 286,993 | $ | 247,226 | |||||||
Gains (losses) on oil and natural gas derivatives | 421,514 | (186,714 | ) | 521,365 | 270,849 | ||||||||||
Total revenues and other | 766,984 | 177,068 | 839,441 | 536,520 | |||||||||||
Total expenses (1) | 681,222 | 420,494 | 2,113,892 | 3,284,372 | |||||||||||
Gains on sale of assets and other, net | (7,814 | ) | (17,185 | ) | (169,613 | ) | (878 | ) | |||||||
Loss from continuing operations | (16,435 | ) | (350,295 | ) | (1,032,159 | ) | (2,345,745 | ) | |||||||
Loss from discontinued operations, net of income taxes | (322,725 | ) | (28,832 | ) | (537,158 | ) | (126,462 | ) | |||||||
Net loss | (339,160 | ) | (379,127 | ) | (1,569,317 | ) | (2,472,207 | ) | |||||||
Loss per unit – continuing operations: | |||||||||||||||
Basic | $ | (0.05 | ) | $ | (1.04 | ) | $ | (2.94 | ) | $ | (6.69 | ) | |||
Diluted | $ | (0.05 | ) | $ | (1.04 | ) | $ | (2.94 | ) | $ | (6.69 | ) | |||
Loss per unit – discontinued operations: | |||||||||||||||
Basic | $ | (0.98 | ) | $ | (0.08 | ) | $ | (1.53 | ) | $ | (0.36 | ) | |||
Diluted | $ | (0.98 | ) | $ | (0.08 | ) | $ | (1.53 | ) | $ | (0.36 | ) | |||
Net loss per unit: | |||||||||||||||
Basic | $ | (1.03 | ) | $ | (1.12 | ) | $ | (4.47 | ) | $ | (7.05 | ) | |||
Diluted | $ | (1.03 | ) | $ | (1.12 | ) | $ | (4.47 | ) | $ | (7.05 | ) | |||
(1) | Includes the following expenses: lease operating, transportation, marketing, general and administrative, exploration, depreciation, depletion and amortization, impairment of long-lived assets and taxes, other than income taxes. |
119
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed in the Company’s reports under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, and the Company’s Audit Committee of the Board of Directors, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
The Company carried out an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of its disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2016.
Management’s Annual Report on Internal Control Over Financial Reporting
See “Management’s Report on Internal Control Over Financial Reporting” in Item 8. “Financial Statements and Supplementary Data.”
Changes in the Company’s Internal Control Over Financial Reporting
The Company’s management is also responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. The Company’s internal controls were designed to provide reasonable assurance as to the reliability of its financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States.
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
There were no changes in the Company’s internal control over financial reporting during the fourth quarter of 2016 that materially affected, or were reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. Other Information
None
120
Part III
Item 10. Directors, Executive Officers and Corporate Governance
A list of the Company’s executive officers and biographical information appears below under the caption “Executive Officers of the Company.” Additional information required by this item will be included in an amendment to this Annual Report on Form 10-K.
Executive Officers of the Company
Name | Age | Position with the Company | ||
Mark E. Ellis | 60 | President and Chief Executive Officer | ||
David B. Rottino | 50 | Executive Vice President and Chief Financial Officer | ||
Arden L. Walker, Jr. | 57 | Executive Vice President and Chief Operating Officer | ||
Thomas E. Emmons | 48 | Senior Vice President – Corporate Services | ||
Jamin B. McNeil | 51 | Senior Vice President – Houston Division Operations | ||
Candice J. Wells | 42 | Senior Vice President, General Counsel and Corporate Secretary | ||
Mark E. Ellis is the President and Chief Executive Officer in addition to serving on the Company’s board of directors and has served in such capacity since February 2017. He previously served as Chairman, President and Chief Executive Officer from December 2011 to February 2017, as President, Chief Executive Officer and Director from January 2010 to December 2011 and as President and Chief Operating Officer from December 2007 to January 2010. Mr. Ellis serves on the boards of the Independent Petroleum Association of America, American Exploration & Production Council and the Houston Museum of Natural Science. Mr. Ellis is a member of the Society of Petroleum Engineers.
David B. Rottino is the Executive Vice President and Chief Financial Officer in addition to serving on the Company’s board of directors and has served in such capacity since February 2017. He previously served as Executive Vice President and Chief Financial Officer from August 2015 to February 2017 and as Executive Vice President, Business Development and Chief Accounting Officer from January 2014 to August 2015. From July 2010 to January 2014, he served as Senior Vice President of Finance, Business Development and Chief Accounting Officer and from June 2008 to July 2010, Mr. Rottino served as Senior Vice President and Chief Accounting Officer.
Arden L. Walker, Jr. is the Executive Vice President and Chief Operating Officer and has served in such capacity since January 2011. From January 2010 to January 2011, he served as Senior Vice President and Chief Operating Officer. Mr. Walker joined the Company in February 2007 as Senior Vice President, Operations and Chief Engineer. Mr. Walker is a member of the Society of Petroleum Engineers and Independent Petroleum Association of America. He also serves on the board of the Sam Houston Area Council of the Boy Scouts of America.
Thomas E. Emmons is the Senior Vice President – Corporate Services and has served in such capacity since January 2014. He previously served as Vice President – Corporate Services from September 2012 to January 2014 and from August 2008 to September 2012, Mr. Emmons served as Vice President, Human Resources and Environmental, Health and Safety.
Jamin B. McNeil is the Senior Vice President – Houston Division Operations and has served in such capacity since January 2014. From June 2007 to January 2014, Mr. McNeil served as Vice President – Houston Division Operations. Mr. McNeil is a member of the Society of Petroleum Engineers.
Candice J. Wells is the Senior Vice President, General Counsel and Corporate Secretary and has served in such capacity since January 2016. From October 2013 to January 2016, Ms. Wells served as Vice President, General Counsel and Corporate Secretary. From March 2013 to October 2013, Ms. Wells served as Vice President, acting General Counsel and Corporate Secretary and from September 2011 to March 2013, she served as Vice President, Assistant General Counsel and Corporate Secretary.
Item 11. Executive Compensation
Information required by this item will be included in an amendment to this Annual Report on Form 10-K.
121
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this item will be included in an amendment to this Annual Report on Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this item will be included in an amendment to this Annual Report on Form 10-K.
Item 14. Principal Accounting Fees and Services
Information required by this item will be included in an amendment to this Annual Report on Form 10-K.
122
Part IV
Item 15. Exhibits and Financial Statement Schedules
(a) - 1. Financial Statements:
All financial statements are omitted for the reason that they are not required or the information is otherwise supplied in Item 8. “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
(a) - 2. Financial Statement Schedules:
All schedules are omitted for the reason that they are not required or the information is otherwise supplied in Item 8. “Financial Statements and Supplementary Data” in this Annual Report on Form 10-K.
(a) - 3. Exhibits:
The exhibits required to be filed by this Item 15 are set forth in the “Index to Exhibits” accompanying this report.
123
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
LINN ENERGY, INC. | ||
Date: March 23, 2017 | By: | /s/ Mark E. Ellis |
Mark E. Ellis President and Chief Executive Officer | ||
Date: March 23, 2017 | By: | /s/ David B. Rottino |
David B. Rottino Executive Vice President and Chief Financial Officer | ||
Date: March 23, 2017 | By: | /s/ Darren R. Schluter |
Darren R. Schluter Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer) | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ Mark E. Ellis | President, Chief Executive Officer and Director (Principal Executive Officer) | March 23, 2017 | ||
Mark E. Ellis | ||||
/s/ David B. Rottino | Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer) | March 23, 2017 | ||
David B. Rottino | ||||
/s/ Darren R. Schluter | Vice President and Controller (Principal Accounting Officer) | March 23, 2017 | ||
Darren R. Schluter | ||||
/s/ Matthew Bonanno | Director | March 23, 2017 | ||
Matthew Bonanno | ||||
/s/ Philip Brown | Director | March 23, 2017 | ||
Philip Brown | ||||
/s/ Evan Lederman | Chairman and Director | March 23, 2017 | ||
Evan Lederman | ||||
/s/ Kevin Mahony | Director | March 23, 2017 | ||
Kevin Mahony | ||||
/s/ Andrew Taylor | Director | March 23, 2017 | ||
Andrew Taylor | ||||
124
Index to Exhibits
Exhibit Number | Description | |
2.1 | — | Amended Joint Chapter 11 Plan of Reorganization of Linn Energy, LLC and Its Debtor Affiliates Other Than Linn Acquisition Company, LLC and Berry Petroleum Company, LLC, dated January 25, 2017 (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed on January 31, 2017 (Case No. 16-60040)) |
3.1 | — | Amended and Restated Certificate of Incorporation of Linn Energy, Inc. (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-8 filed on February 28, 2017) |
3.2 | — | Bylaws of Linn Energy, Inc. (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-8 filed on February 28, 2017) |
4.1 | — | Form of specimen New Common Stock certificate of Linn Energy, Inc. (incorporated herein by reference to Exhibit 4.1 to Current Report on Form 8-K filed on March 3, 2017) |
10.1 | — | Credit Agreement dated as of February 28, 2017, among Linn Energy Holdco II LLC, as borrower, Linn Energy Holdco LLC, as parent, Linn Energy, Inc. as holdings, subsidiary guarantors party thereto, Wells Fargo Bank, National Association, as administrative agent and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on March 3, 2017) |
10.2 | — | Registration Rights Agreement dated as of February 28, 2017, among Linn Energy, Inc. and the holders party thereto (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on March 3, 2017) |
10.3* | — | Linn Energy, Inc. 2017 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.1 to Registration Statement on Form S-8 filed on February 28, 2017) |
10.4* | — | Form of Restricted Stock Unit Agreement (for executive officers with employment agreements) (incorporated by reference to Exhibit 10.2 to Registration Statement on Form S-8 filed on February 28, 2017) |
10.5* | — | Form of Restricted Stock Unit Agreement (for employees) (incorporated by reference to Exhibit 10.3 to Registration Statement on Form S-8 filed on February 28, 2017) |
10.6* ** | — | Linn Energy Holdco LLC Incentive Interest Plan |
10.7* ** | — | Form of Award Agreement (base interests) |
10.8* ** | — | Form of Award Agreement (appreciation interests) |
10.9 | — | Membership Interest Purchase Agreement, dated as of February 28, 2017, by and between Linn Energy, LLC and Linn Energy, Inc. (incorporated by reference to Exhibit 10.6 to Current Report on Form 8-K filed on March 3, 2017) |
10.10 | — | Transition Services and Separation Agreement, dated as of February 28, 2017, by and between Linn Energy, LLC, LinnCo, LLC, and certain subsidiaries of Linn Energy, Inc. party thereto and Berry Petroleum Company, LLC (incorporated by reference to Exhibit 10.7 to Current Report on Form 8-K filed on March 3, 2017) |
10.11 | — | Joint Operating Agreement, dated February 28, 2017, between Linn Operating, Inc., as operator, and Berry Petroleum Company, LLC, as non-operator (Hugoton) (incorporated by reference to Exhibit 10.8 to Current Report on Form 8-K filed on March 3, 2017) |
10.12 | — | Joint Operating Agreement, dated February 28, 2017, between Berry Petroleum Company, LLC, as operator, and Linn Energy Holdings, LLC, as non-operator (Hill) (incorporated by reference to Exhibit 10.9 to Current Report on Form 8-K filed on March 3, 2017) |
10.13* | — | Form of Indemnity Agreement between Linn Energy, Inc. and the directors and officers of Linn Energy, Inc. (incorporated by reference to Exhibit 10.4 to Registration Statement on Form S-8 filed on February 28, 2017) |
10.14* | — | Second Amended and Restated Employment Agreement of Mark E. Ellis, dated February 28, 2017 (incorporated by reference to Exhibit 10.11 to Current Report on Form 8-K filed on March 3, 2017) |
10.15* | — | Third Amended and Restated Employment Agreement of David B. Rottino, dated February 28, 2017 (incorporated by reference to Exhibit 10.12 to Current Report on Form 8-K filed on March 3, 2017) |
10.16* | — | Second Amended and Restated Employment Agreement of Arden L. Walker, Jr., dated February 28, 2017 (incorporated by reference to Exhibit 10.13 to Current Report on Form 8-K filed on March 3, 2017) |
10.17* | — | Employment Agreement of Jamin B. McNeil, dated February 28, 2017 (incorporated by reference to Exhibit 10.14 to Current Report on Form 8-K filed on March 3, 2017) |
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Index to Exhibits - Continued
Exhibit Number | Description | |
10.18* | — | Employment Agreement of Thomas E. Emmons, dated February 28, 2017 (incorporated by reference to Exhibit 10.15 to Current Report on Form 8-K filed on March 3, 2017) |
10.19* | — | Employment Agreement of Candice J. Wells, dated February 28, 2017 (incorporated by reference to Exhibit 10.16 to Current Report on Form 8-K filed on March 3, 2017) |
12.1** | — | Computation of Ratio of Earnings to Fixed Charges |
21.1** | — | List of Significant Subsidiaries |
23.1** | — | Consent of KPMG LLP |
23.2** | — | Consent of DeGolyer and MacNaughton |
31.1** | — | Section 302 Certification of Chief Executive Officer |
31.2** | — | Section 302 Certification of Chief Financial Officer |
32.1** | — | Section 906 Certification of Chief Executive Officer |
32.2** | — | Section 906 Certification of Chief Financial Officer |
99.1** | — | 2016 Report of DeGolyer and MacNaughton |
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 |
* | Management Contract or Compensatory Plan or Arrangement required to be filed as an Exhibit hereto pursuant to Item 601 of Regulation S-K. |
** | Filed herewith. |
† | Furnished herewith. |
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