Table of Contents
Index to Financial Statements
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended June 30, 2010
| ¨ | 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 001-16317
CONTANGO OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
| Delaware | 95-4079863 | |
| (State or other jurisdiction of incorporation or organization) |
(IRS Employer Identification No.) |
3700 Buffalo Speedway, Suite 960
Houston, Texas 77098
(Address of principal executive offices)
(713) 960-1901
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Common Stock, Par Value $0.04 per share | NYSE Amex |
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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. (Check one):
| Large accelerated filer | ¨ | Accelerated filer | x | |||
| Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ | |||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
At December 31, 2009, the aggregate market value of the registrant’s common stock held by non-affiliates (based upon the closing sale price of shares of such common stock as reported on the NYSE Amex was $589,189,869. As of August 31, 2010, there were 15,664,666 shares of the registrant’s common stock outstanding.
Documents Incorporated by Reference
Items 10, 11, 12, 13 and 14 of Part III have been omitted from this report since registrant will file with the Securities and Exchange Commission, not later than 120 days after the close of its fiscal year, a definitive proxy statement, pursuant to Regulation 14A. The information required by Items 10, 11, 12, 13 and 14 of this report, which will appear in the definitive proxy statement, is incorporated by reference into this Form 10-K.
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Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
ANNUAL REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED JUNE 30, 2010
| Page | ||||
| PART I | ||||
| Item 1. | Business | |||
| 1 | ||||
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| 10 | ||||
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| 13 | ||||
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| Item 1A. | Risk Factors | 14 | ||
| Item 1B. | Unresolved Staff Comments | 22 | ||
| Item 2. | Properties | |||
| 23 | ||||
| 23 | ||||
| 24 | ||||
| 24 | ||||
| 25 | ||||
| 25 | ||||
| Item 3. | Legal Proceedings | 27 | ||
| Item 4. | Reserved | 27 | ||
| PART II | ||||
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 27 | ||
| Item 6. | Selected Financial Data | 30 | ||
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | |||
| 31 | ||||
| Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium |
31 | |||
| 32 | ||||
| 36 | ||||
| 38 | ||||
| 38 | ||||
| 38 | ||||
| 38 | ||||
| Application of Critical Accounting Policies and Management’s Estimate |
39 | |||
| 40 | ||||
| Item 7A. | Quantitative and Qualitative Disclosure about Market Risk | 41 | ||
| Item 8. | Financial Statements and Supplementary Data | 41 | ||
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 42 | ||
| Item 9A. | Controls and Procedures | 42 | ||
| Item 9B. | Other Information | 44 | ||
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| PART III | ||||
| Item 10. | Directors, Executive Officers and Corporate Governance | 44 | ||
| Item 11. | Executive Compensation | 45 | ||
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 45 | ||
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | 45 | ||
| Item 14. | Principal Accountant Fees and Services | 45 | ||
| PART IV | ||||
| Item 15. | Exhibits and Financial Statement Schedules | 45 | ||
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Some of the statements made in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. These include such matters as:
| • | Our financial position |
| • | Business strategy, including outsourcing |
| • | Meeting our forecasts and budgets |
| • | Anticipated capital expenditures |
| • | Drilling of wells |
| • | Natural gas and oil production and reserves |
| • | Timing and amount of future discoveries (if any) and production of natural gas and oil |
| • | Operating costs and other expenses |
| • | Cash flow and anticipated liquidity |
| • | Prospect development |
| • | Property acquisitions and sales |
| • | New governmental laws and regulations |
Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These factors include among others:
| • | Low and/or declining prices for natural gas and oil |
| • | Natural gas and oil price volatility |
| • | Operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and gas processing facilities |
| • | The risks associated with acting as the operator in drilling deep high pressure and temperature wells in the Gulf of Mexico |
| • | The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which the Company has made a large capital commitment relative to the size of the Company’s capitalization structure |
| • | The timing and successful drilling and completion of natural gas and oil wells |
| • | Availability of capital and the ability to repay indebtedness when due |
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| • | Availability of rigs and other operating equipment |
| • | Ability to raise capital to fund capital expenditures |
| • | Timely and full receipt of sale proceeds from the sale of our production |
| • | The ability to find, acquire, market, develop and produce new natural gas and oil properties |
| • | Interest rate volatility |
| • | Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures |
| • | Operating hazards attendant to the natural gas and oil business |
| • | Downhole drilling and completion risks that are generally not recoverable from third parties or insurance |
| • | Potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps |
| • | Weather |
| • | Availability and cost of material and equipment |
| • | Delays in anticipated start-up dates |
| • | Actions or inactions of third-party operators of our properties |
| • | Actions or inactions of third-party operators of pipelines or processing facilities |
| • | Ability to find and retain skilled personnel |
| • | Strength and financial resources of competitors |
| • | Federal and state regulatory developments and approvals |
| • | Environmental risks |
| • | Worldwide economic conditions |
| • | The ability to construct and operate offshore infrastructure, including pipeline and production facilities |
| • | The continued compliance by the Company with various pipeline and gas processing plant specifications for the gas and condensate produced by the Company |
| • | Drilling and operating costs, production rates and ultimate reserve recoveries in our Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) acreage |
| • | Restrictions on permitting activities |
| • | Expanded rigorous monitoring and testing requirements |
| • | Legislation that may regulate drilling activities and increase or remove liability caps for claims of damages from oil spills |
| • | Ability to obtain insurance coverage on commercially reasonable terms |
| • | Accidental spills, blowouts and pipeline ruptures |
| • | Impact of potential legislative and regulatory changes on Gulf of Mexico operating and safety standards due to the Deepwater Horizon incident |
You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” referred to on page 14 of this report for some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in forward-looking statements.
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All references in this Form 10-K to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and wholly-owned Subsidiaries. Unless otherwise noted, all information in this Form 10-K relating to natural gas and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates prepared by independent engineers and are net to our interest.
| Item 1. | Business |
Overview
Contango is a Houston-based, independent natural gas and oil company. The Company’s business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore prospects.
Our exploration strategy is predicated upon two core beliefs: (1) that the only competitive advantage in the commodity-based natural gas and oil business is to be among the lowest cost producers and (2) that virtually all the exploration and production industry’s value creation occurs through the drilling of successful exploratory wells. As a result, our business strategy includes the following elements:
Funding exploration prospects generated by Juneau Exploration, L.P., our alliance partner. We depend primarily upon our alliance partner, Juneau Exploration, L.P. (“JEX”), for prospect generation expertise. JEX is experienced and has a successful track record in exploration.
Using our limited capital availability to increase our reward/risk potential on selective prospects. We have concentrated our risk investment capital in our offshore Gulf of Mexico prospects. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success. COI drills and operates our offshore prospects. Should we be successful in any of our offshore prospects, we will have the opportunity to spend significantly more capital to complete development and bring the discovery to producing status.
Operating in the Gulf of Mexico. COI was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. While the Company has historically drilled turnkey wells, adverse weather conditions as well as difficulties encountered while drilling our offshore wells could cause our contracts to come off turnkey and thus lead to significantly higher drilling costs.
Sale of proved properties. From time-to-time as part of our business strategy, we have sold and in the future expect to continue to sell some or a substantial portion of our proved reserves and assets to capture current value, using the sales proceeds to further our offshore exploration activities. Since its inception, the Company has sold approximately $484 million worth of natural gas and oil properties, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for potentially higher rate of return natural gas and oil exploration opportunities.
Controlling general and administrative and geological and geophysical costs. Our goal is to be among the most efficient in the industry in revenue and profit per employee and among the lowest in general and administrative costs. We plan to continue outsourcing our geological, geophysical, and reservoir engineering and land functions, and partnering with cost efficient operators. We have eight employees.
Structuring transactions to share risk. JEX, our alliance partner, shares in the upfront costs and the risk of our exploration prospects.
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Index to Financial Statements
Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our employees and stockholders. Our directors and executive officers beneficially own or have voting control over approximately 22% of our common stock.
JEX is a private company formed for the purpose of assembling domestic natural gas and oil prospects. Under our agreement with JEX, JEX generates natural gas and oil prospects and evaluates exploration prospects generated by others. JEX focuses on the Gulf of Mexico, and generates offshore exploration prospects either individually, or via our affiliated company, Republic Exploration, LLC (“REX”) (see “Offshore Gulf of Mexico Exploration Joint Ventures” below). Prior to June 1, 2010, JEX would also generate offshore exploration prospects via a second company affiliated with us, Contango Offshore Exploration, LLC (“COE”). Effective June 1, 2010, COE was dissolved and all properties owned by COE were transferred to its respective members. We do not have a written agreement with JEX which contractually obligates them to provide us their services.
Offshore Gulf of Mexico Exploration Joint Ventures
Contango, through its wholly-owned subsidiary COI, and its partially-owned affiliate, REX, conducts exploration activities in the Gulf of Mexico. As of August 31, 2010, Contango, through COI and REX, had an interest in 28 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.
COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling and operating wells in the Gulf of Mexico. Additionally, COI expects to acquire significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out agreement, or similar agreement, with REX. COI may also acquire and operate significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.
The Company’s offshore production consists of 11 wells located on federal and State of Louisiana leases in the shallow waters of the Gulf of Mexico. These 11 wells produce via the following three platforms:
Eugene Island 11 Platform
As of August 31, 2010, the Company-owned and operated platform at Eugene Island 11 was processing approximately 54 Mmcfed, net to Contango. This platform was designed with a capacity of 500 million cubic feet per day (“Mmcfd”) and 6,000 barrels of oil per day (“bopd”). This platform services production from the Company’s four Mary Rose wells and Eloise North well, which are all located in State of Louisiana waters, as well as our Dutch #4 well and Eloise South well, which are both located in federal waters. From the Eugene Island 11 platform, the gas and condensate flow to our Eugene Island 63 auxiliary platform via our 20” pipeline, which has been designed with a capacity of 330 Mmcfd and 6,000 bopd, and then from the Eugene Island 63 auxiliary platform to third-party owned and operated on-shore processing facilities near Patterson, Louisiana.
On February 24, 2010, a dredge contracted by the Army Corps of Engineers to dredge the Atchafalaya River Channel ruptured the Company’s 20” pipeline that runs from our Eugene Island 11gathering platform to our Eugene Island 63 auxiliary platform. All wells serviced by the platform were immediately shut-in upon pipeline rupture, and we immediately implemented our spill response plan. The Company estimates that a minimal and immaterial quantity of production was lost. The pipeline was repaired and production resumed on March 31, 2010. We believe the repairs will be covered by our insurance policy subject to a deductible. We have an approximate 53% ownership interest in the pipeline.
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Index to Financial Statements
Eugene Island 24 Platform
The third-party owned and operated production platform at Eugene Island 24 was processing approximately 30 Mmcfed, net to Contango as of August 31, 2010. This platform was designed with a capacity of 100 Mmcfd and 3,000 bopd. This platform services production from the Company’s Dutch #1, #2 and #3 federal wells.
Ship Shoal 263 Platform
Ship Shoal 263 (“Nautilus”) was spud in October 2009 and announced as a discovery in January 2010. The Company-owned and operated Ship Shoal 263 platform was designed with a capacity of 40 Mmcfd and 5,000 bopd. This platform services production from our Nautilus well which began producing in June 2010 and is currently producing approximately 18 Mmcfed, net to Contango.
Other Activities
In March 2010, we obtained a farm-in and spud a well on block Eugene Island 10 to drill a well on our Eloise South prospect. This well was spud in March 2010, announced as a discovery in June 2010, and began producing in July 2010. The well tested the Rob L sands identified in our Eloise North well, and was drilled in a location so that upon depletion of our Eloise South well, our well bore may be completed up-hole and produce in the Cib-op sand as our Dutch #5 well. The Company has a 26.9% working interest (21.5% net revenue interest) in Eloise South, inclusive of our ownership interest in REX, and a 47.05% working interest (38.1% net revenue interest) in Dutch #5. As of August 31, 2010, the Company had invested approximately $12.7 million, inclusive of our ownership interest in REX, to drill, complete and bring the well to production.
In the third quarter of the fiscal year ended June 30, 2010 we drilled two dry holes in the Gulf of Mexico. The first was on a farm-in we obtained on block Vermillion 155 (“Paisano”). This well had a dry hole cost of approximately $5.3 million and the Company had a 100% working interest. The second was our Matagorda Island 617 well (“Dude”), which was drilled in mid-February 2010 and determined to be a dry hole in April 2010. This well had a dry hole cost of approximately $14.9 million and the Company had a 100% working interest.
During the fiscal year ended June 30, 2010, COI was awarded three lease blocks from the Western Gulf of Mexico Lease Sale No. 210 held on August 19, 2009, five leases from the State of Texas Lease Sale held on October 6, 2009, and three lease blocks from the Central Gulf of Mexico Lease Sale No. 213 held on March 17, 2010. COI was awarded the following leases for the following bid amounts:
| Ÿ | Matagorda Island Block 607 |
$ | 317,000 | ||
|
Ÿ |
Matagorda Island Block 616 |
$ | 317,000 | ||
|
Ÿ |
Matagorda Island Block 617 |
$ | 1,017,000 | ||
|
Ÿ |
Galveston Area 248L |
$ | 144,000 | ||
|
Ÿ |
Galveston Area 276L |
$ | 144,000 | ||
|
Ÿ |
Galveston Area 277L (N/2 of NE/4) |
$ | 291,787 | ||
|
Ÿ |
Galveston Area 277 L (S/2 of NE/4) |
$ | 144,000 | ||
|
Ÿ |
Galveston Area 338S |
$ | 64,000 | ||
|
Ÿ |
Ship Shoal 121 |
$ | 3,017,777 | ||
|
Ÿ |
Ship Shoal 122 |
$ | 277,777 | ||
|
Ÿ |
Vermillion 170 |
$ | 3,017,777 |
During the fiscal year ended June 30, 2009, the Company’s Mary Rose #1 well was successfully worked over at a cost of approximately $11.5 million ($6.1 million net to Contango), to reduce water production from a water bearing sand above our production reservoir. We also installed line heaters at the Eugene Island 11 platform which allowed us to further increase our production rate. Production had been constrained due to entrained water that attached to the paraffin in our condensate. The line heaters were installed at a cost of approximately $1.9 million ($0.9 million net to Contango).
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Index to Financial Statements
The Company’s Mary Rose #2 well was successfully worked over in May 2009 at a cost of approximately $5.6 million ($3.0 million net to Contango), to also reduce water production from a water bearing sand above our production reservoir.
In September 2008, COI purchased additional working interests in nine offshore lease blocks from existing owners for a total of $2.1 million. See “Offshore Properties” below for a detailed description of the interests owned in our offshore properties.
During the fiscal year ended June 30, 2008, the Company acquired additional working interests in the Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) discoveries in a like-kind exchange, using funds from the sale of its Arkansas Fayetteville Shale properties held by a qualified intermediary. The Company purchased an additional 12.5 % working interest and 10.0% net revenue interest in Dutch and an additional average 13.67% working interest and 10.0% net revenue interest in Mary Rose from three different companies for $300 million. The Company also purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries for $9.0 million.
Republic Exploration LLC (REX)
West Delta 36, a REX prospect, is operated by a third party. The Company depends on a third-party operator for the operation and maintenance of this production platform. As of August 31, 2010, the well was temporarily shut-in. As of August 25, 2010 however, the well was producing at an 8/8ths rate of approximately 2.9 million cubic feet equivalent per day (“Mmcfed”). REX has a 25.0% working interest (“WI”), and a 20.0% net revenue interest (“NRI”), in this well.
During the fiscal year ended June 30, 2009, COI spud Eugene Island 56 #1 (“High Country West”) and West Delta 77 (“Devil’s Elbow”), both REX prospects, which were both determined to be dry holes. COI had a 100% WI and paid 100% of the drilling costs for both wells totaling approximately $16.5 million. These costs together with associated leasehold costs and prospect fees of approximately $2.3 million are reflected as exploration expenses in the Company’s Consolidated Statements of Operations for the fiscal year ended June 30, 2009.
During the fiscal year ended June 30, 2009, the Company sold a portion of its ownership interest in REX to an existing member of REX for approximately $0.8 million. This sale decreased the Company’s equity ownership interest in REX to its present 32.3%. REX was formed for the purpose of generating exploration opportunities in the Gulf of Mexico. REX focuses on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to third parties, including Contango, subject to timed drilling obligations plus retained reversionary interests in favor of REX. See Exhibit 21.2 for an organizational chart of our subsidiaries.
During the fiscal year ended June 30, 2008, the members of REX entered into an Amended and Restated Limited Liability Company Agreement (the “REX LLC Agreement”), effective as of April 1, 2008, to, among other things, distribute REX’s interest in Dutch and Mary Rose to the individual members of REX or their designees. In connection with this distribution, REX repaid in full all amounts owed by REX to a private investment firm under a $50.0 million demand promissory note with such private investment firm (the “REX Demand Note”). All security interests and other liens granted in favor of such private investment firm as security for the obligations under the REX Demand Note have been released and terminated. The Company’s portion of such repayment was approximately $22.5 million.
Contango Offshore Exploration LLC (COE)
Prior to its dissolution on June 1, 2010, the Company owned a 65.6% equity interest in COE. As of June 1, 2010, COE had borrowed $4.3 million from the Company under a non-recourse promissory note (the “Note”) payable on demand. As of June 1, 2010, accrued and unpaid interest on the Note was approximately $1.6 million. In connection with the dissolution, the Company assumed its 65.6% share of the obligation under the Note, while the other member of COE assumed the remaining 34.4%, or approximately $2 million. This $2 million is reflected as a receivable in the Consolidated Balance Sheet of the Company as of June 30, 2010.
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Index to Financial Statements
Prior to its dissolution, COE had generated three prospects which were all drilled by COI: Ship Shoal 263, Grand Isle 70 and Grand Isle 72. In connection with its dissolution, COE distributed its ownership interest in Ship Shoal 263 to its members. As a result, Contango has a working interest of approximately 92.46% and a net revenue interest of approximately 74% in this well. As of August 31, 2010 we had invested approximately $38.2 million to drill, complete and bring Ship Shoal 263 to full production status.
Grand Isle 70 (“Red Queen”) was drilled in July 2006 and was temporarily abandoned while alternative development scenarios were being evaluated. Effective December 1, 2009 the Company and COE sold their respective interests in Grand Isle 70 to an independent third-party oil and gas company in exchange for an overriding royalty interest. The Company subsequently sold its overriding royalty interests to JEX for a gain of $112,868.
Grand Isle 72 (“Liberty”) ceased producing in October 2009 and the well was plugged and abandoned in June 2010. The Company invested approximately $500,000 to permanently abandon the site. This lease was relinquished to the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) (previously the Minerals Management Service) during the fourth quarter of our fiscal year ending June 30, 2010.
In June 2010, the Company withdrew from Ship Shoal 358, a COE prospect, and transferred all future plugging and abandonment liabilities to the third party operator responsible for operation and maintenance of the production platform.
Impact of Hurricanes Gustav and Ike
During the fiscal year ended June 2009, Hurricanes Gustav and Ike moved through the Gulf of Mexico and it was necessary for us to shut-in our Dutch and Mary Rose production at various times before, during and after the storms. Our offshore facilities sustained minor damage from Hurricane Ike. Repairs were completed on the damaged wells at an 8/8ths cost of approximately $2.4 million, which was covered by the Company’s insurance subject to a deductible. The on-shore third-party processing and pipeline facilities on which we rely, however, incurred significant damage from Hurricane Ike and necessitated approximately three months of downtime for our production while repairs were being made.
Producing Properties. The following table sets forth the interests owned by Contango through its related entities in the Gulf of Mexico which were producing natural gas or oil as of August 31, 2010:
| Area/Block |
WI | NRI | Status | |||||
| Contango Operators, Inc.: |
||||||||
| Eugene Island 10 #D-1 (Dutch #1) |
47.05 | % | 38.1 | % | Producing | |||
| Eugene Island 10 #E-1 (Dutch #2) |
47.05 | % | 38.1 | % | Producing | |||
| Eugene Island 10 #F-1 (Dutch #3) |
47.05 | % | 38.1 | % | Producing | |||
| Eugene Island 10 #G-1 (Dutch #4) |
47.05 | % | 38.1 | % | Producing | |||
| Eugene Island 10 #I-1 (Eloise South) |
23.76 | % | 19.0 | % | Producing | |||
| S-L 18640 #1 (Mary Rose #1) |
53.21 | % | 40.5 | % | Producing | |||
| S-L 19266 #1 (Mary Rose #2) |
53.21 | % | 38.7 | % | Producing | |||
| S-L 19266 #2 (Mary Rose #3) |
53.21 | % | 38.7 | % | Producing | |||
| S-L 18860 #1 (Mary Rose #4) |
34.58 | % | 25.5 | % | Producing | |||
| S-L 19266 #3 (Eloise North) |
36.90 | % | 26.9 | % | Producing | |||
| Ship Shoal 263 |
92.46 | % | 74.0 | % | Producing | |||
| Republic Exploration LLC | ||||||||
| West Delta 36 |
25.0 | % | 20.0 | % | Producing | |||
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Leases. The following table sets forth the interests owned by Contango through its related entities in leases in the Gulf of Mexico as of August 31, 2010:
| Area/Block |
WI | Lease Date | Expiration Date | ||||
| Contango Operators, Inc.: | |||||||
| Ship Shoal 14 |
50.00 | % | May-06 | May-11 | |||
| Viosca Knoll 383 (1) |
(2 | ) | Jun-06 | Jun-11 | |||
| S-L 19261 |
53.21 | % | Feb 07 | Feb 12 | |||
| S-L 19396 |
53.21 | % | Jun 07 | Jun 12 | |||
| Eugene Island 11 |
53.21 | % | Dec 07 | Dec-12 | |||
| East Breaks 369 (1)(3) |
(4 | ) | Dec-03 | Dec-13 | |||
| East Breaks 370 (1) |
65.63 | % | Dec-03 | Dec-13 | |||
| Galveston Area 248L |
100.00 | % | Oct-09 | Oct-14 | |||
| Galveston Area 276L |
100.00 | % | Oct-09 | Oct-14 | |||
| Galveston Area 277L (N/2 of NE/4) |
100.00 | % | Oct-09 | Oct-14 | |||
| Galveston Area 277L (S/2 of NE/4) |
100.00 | % | Oct-09 | Oct-14 | |||
| Galveston Area 338S |
100.00 | % | Oct-09 | Oct-14 | |||
| Matagorda Island 607 |
100.00 | % | Nov-09 | Nov-14 | |||
| Matagorda Island 616 |
100.00 | % | Nov-09 | Nov-14 | |||
| Matagorda Island 617 (3) |
100.00 | % | Nov-09 | Nov-14 | |||
| Ship Shoal 121 |
100.00 | % | Jul-10 | Jul-15 | |||
| Ship Shoal 122 |
100.00 | % | Jul-10 | Jul-15 | |||
| Vermillion 170 |
100.00 | % | Jul-10 | Jul-15 | |||
| East Breaks 366 (1) |
65.63 | % | Nov-05 | Nov-15 | |||
| East Breaks 410 (1) |
65.63 | % | Nov-05 | Nov-15 | |||
| Republic Exploration LLC |
|||||||
| Ship Shoal 14 |
50.00 | % | May-06 | May-11 | |||
| East Cameron 210 |
100.00 | % | Jun-09 | Jun-14 | |||
| South Timbalier 97 |
100.00 | % | Jun-09 | Jun-14 | |||
| (1) | Previously owned by COE |
| (2) | Farm out. COI retains a 1.75% ORRI |
| (3) | Dry Hole |
| (4) | Farm out. COI retains a 2.41% ORRI |
Onshore Exploration and Properties
Conterra Company
Effective October 1, 2009, the Company’s wholly-owned subsidiary, Conterra Company (“Conterra”), entered into a joint venture with Patara Oil & Gas LLC (“Patara”), a privately held oil and gas company, to develop proved undeveloped Cotton Valley gas reserves in Panola County, Texas. B.A. Berilgen, a member of the Company’s board of directors, is the Chief Executive Officer of Patara.
Under the terms of the joint venture agreement (the “Joint Venture Agreement”), Conterra will fund 100% of the drilling and completion costs in exchange for 90% of the net revenues. The Joint Venture Agreement contemplates drilling up to 15 wells, at an estimated 8/8ths cost of approximately $1.65 million per well. The average 8/8ths reserves per well are approximately 1.5 Bcfe (1.125 net Bcfe after a 25% royalty). In July 2010, both Conterra and Patara agreed to enter into a second joint venture agreement to drill up to an additional 15 wells, bringing the total expected number of wells to 30.
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By paying all of the drilling and completion costs, the Company will be able to benefit from the associated tax deductions which are estimated to be about 75% of total drilling costs, or approximately $1.2 million per well. Upon the Company achieving a 15% per annum cash-on-cash rate of return on the basket of 15 wells, the Company’s net revenue interest converts into a 5% overriding royalty interest.
As of August 31, 2010, we were producing at a rate of approximately 5.6 Mmcfed, net to Contango, from 12 wells. Three additional wells have been logged and are waiting to be fracture stimulated while another one well is drilling ahead. As of August 31, 2010 we have invested approximately $25.8 million in this drilling program.
South Texas
In July 2010, the Company announced a discovery at its on-shore wildcat exploration well (Rexer #1) in south Texas. The Company has a 100% working interest (72.5% net revenue interest) in this well before payout, and a 75% working interest (54.4% net revenue interest) after payout. Production is expected to begin by the end of October 2010. As of June 30, 2010, the Company had invested approximately $4.2 million to drill, complete and prepare to bring this well to production.
Contango Mining Company
During the fiscal year ended June 30, 2010, the Company created a new wholly-owned subsidiary, Contango Mining Company (“Contango Mining”), to initially invest up to $3.0 million to conduct mineral exploration activities on approximately 647,000 acres of Alaska Native and State of Alaska lands located in interior Alaska (“Mineral Exploration Lands”). Contango Mining purchased a 50% ownership from a private company for $1.0 million, together with our commitment to invest the next $2.0 million of capital expenditures to fund the expenses associated with the initial mineral exploration phase on this acreage. Contango Mining and its partner will share expenses on a 50/50 basis thereafter and each will own a 50% working interest burdened by varying amounts of a production royalty and a 1% overriding royalty interest. To date, Contango Mining has invested a total of $2.6 million.
Contango Mining has also assembled with the private company approximately 100,000 acres of State of Alaska and Federal unpatented mining claims for the purpose of conducting exploration work for rare earth minerals. Our decision to acquire the mining claims is based, in part, on the results of several surveys performed by the United States Geological Survey in the 1970’s and 1980’s.
The Company anticipates reorganizing Contango Mining in order to pursue additional exploration activities in the state of Alaska.
Contango Venture Capital Corporation
During the fiscal year ended June 30, 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, sold its direct and indirect investments in several alternative energy investments for approximately $3.4 million, recognizing a loss of approximately $2.9 million. CVCC’s only remaining investment is Moblize, Inc. (“Moblize”). As of August 31, 2010, CVCC owned 443,648 shares of Moblize convertible preferred stock, which represents an approximate 19.5% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas and other industries using open-standards based technologies.
Property Sales and Discontinued Operations
Freeport LNG Development, L.P.
During the fiscal year ended June 30, 2008, the Company sold its ten percent (10%) limited partnership interest in Freeport LNG Development L.P. (“Freeport LNG”) to Turbo LNG LLC, an affiliate of
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Osaka Gas Co., Ltd., for $68.0 million, and recognized a pre-tax gain of approximately $63.4 million on the sale. Freeport LNG is a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcfd”) liquefied natural gas (“LNG”) receiving and gasification terminal on Quintana Island, near Freeport, Texas.
Arkansas Fayetteville Shale
During the fiscal year ended June 30, 2008, the Company sold its Arkansas Fayetteville Shale properties to Petrohawk Energy Corporation and XTO Energy, Inc. for a total of approximately $327.2 million. The Company sold approximately 25,400 acres with 9.4 Mmcfd of production, net to Contango. The Company recognized a gain of approximately $262.3 million as a result of this sale.
Texas and Louisiana
During the fiscal year ended June 30, 2008, the Company sold its interest in two onshore wells to Alta Resources LLC. The Alta-Ellis#1 in Texas and the Temple-Inland in Louisiana were sold for approximately $1.1 million.
The Company currently derives its revenue principally from the sale of natural gas and oil. As a result, the Company’s revenues are determined, to a large degree, by prevailing natural gas and oil prices. The Company currently sells its natural gas and oil on the open market at prevailing market prices. Major purchasers of our natural gas, oil and natural gas liquids for the fiscal year ended June 30, 2010 were ConocoPhillips Company (37%), Shell Trading US Company (24%), Atmos Energy Marketing, LLC (16%) and Enterprise Products Operating LLC (13%). Market prices are dictated by supply and demand, and the Company cannot predict or control the price it receives for its natural gas and oil. The Company has outsourced the marketing of its offshore natural gas and oil production volume to a privately-held third party marketing firm. The Company has a policy not to hedge its natural gas and oil production.
Price decreases would adversely affect our revenues, profits and the value of our proved reserves. Historically, the prices received for natural gas and oil have fluctuated widely. Among the factors that can cause these fluctuations are:
| • | The domestic and foreign supply of natural gas and oil |
| • | Overall economic conditions |
| • | The level of consumer product demand |
| • | Adverse weather conditions and natural disasters |
| • | The price and availability of competitive fuels such as heating oil and coal |
| • | Political conditions in the Middle East and other natural gas and oil producing regions |
| • | The level of LNG imports |
| • | Domestic and foreign governmental regulations |
| • | Special taxes on production |
| • | The loss of tax credits and deductions |
The Company competes with numerous other companies in all facets of its business. Our competitors in the exploration, development, acquisition and production business include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater financial resources and in-house technical expertise.
Federal Income Tax. Federal income tax laws significantly affect the Company’s operations. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to
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deduct as incurred, rather than to capitalize and amortize, its domestic “intangible drilling and development costs” and to claim depletion on a portion of its domestic natural gas and oil properties based on 15% of its natural gas and oil gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas).
Environmental Matters. Domestic natural gas and oil operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations such as the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) also known as the “Super Fund Law”. The trend towards stricter standards in environmental legislation and regulation could increase costs to the Company and others in the industry. Natural gas and oil lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee’s operations, and may also be subject to liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area.
The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in U.S. waters. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations. Few defenses exist to the liability imposed by the OPA. In addition, to the extent the Company’s offshore lease operations affect state waters, the Company may be subject to additional state and local clean-up requirements or incur liability under state and local laws. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. However, the Company cannot predict whether these financial responsibility requirements under any OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely affect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico.
The Company’s operations are subject to numerous federal, state and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. Such laws and regulations, among other things, impose absolute liability on the lessee for the cost of clean-up of pollution resulting from a lessee’s operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the natural gas and oil industry in general. Federal, state and local initiatives to further regulate the disposal of natural gas and oil wastes are also pending in certain jurisdictions, and these initiatives could have a similar impact on the Company. The Company’s operations are also subject to additional federal, state and local laws and regulations relating to protection of human health, natural resources, and the environment pursuant to which the Company may incur compliance costs or other liabilities.
Impact of Deepwater Horizon Incident. In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon sank after an apparent blowout and fire. The accident resulted in the loss of life and a significant oil spill. In response to the Incident, the President of the United States has announced a six-month moratorium on drilling in the deepwater Gulf of Mexico and imposed new restrictions on permitting activities on the Outer Continental Shelf. Although the root cause, or causes, of the Deepwater Horizon Incident are unclear at this time, we believe there is a high likelihood of regulatory and/or legislative changes that will impact operations in the Gulf of Mexico. Various Congressional committees have already begun pursuing legislation to change existing governmental regulations. We will continue to monitor the expected regulatory and legislative response and its impact on our operations.
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Other Laws and Regulations. Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company’s properties and to limit the allowable production from the successful wells completed on the Company’s properties, thereby limiting the Company’s revenues.
The BOEMRE administers the natural gas and oil leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The BOEMRE holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the BOEMRE changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. However, the Company believes that the regulations generally do not impact the Company to any greater extent than other similarly situated producers. At the end of lease operations, oil and gas lessees must plug and abandon wells, remove platforms and other facilities, and clear the lease site sea floor. The BOEMRE requires companies operating on the Outer Continental Shelf to obtain surety bonds to ensure performance of these obligations. As an operator, the Company is required to obtain surety bonds of $200,000 per lease for exploration and $500,000 per lease for developmental activities.
The Federal Energy Regulatory Commission (the “FERC”) has embarked on wide-ranging regulatory initiatives relating to natural gas transportation rates and services, including the availability of market-based and other alternative rate mechanisms to pipelines for transmission and storage services. In addition, the FERC has announced and implemented a policy allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to affiliated and non-affiliated entities that are not subject to the FERC’s rate jurisdiction. The Company cannot predict the ultimate outcome of these developments, or the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the natural gas prices received by the Company for the sale of its production, the FERC’s actions may have an impact on the Company. However, the impact should not be substantially different for the Company than it would be for other similarly situated natural gas producers and sellers.
In accordance with industry practices, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us an economically appropriate level of financial protection from significant unfavorable losses resulting from damages to, or the loss of, physical assets or loss of human life and liability claims of third parties. We maintain insurance at levels that we believe are appropriate and consistent with industry practice.
We expect the future availability and cost of insurance to be impacted by the recent Deepwater Horizon incident. Impacts could include: tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico, including possible increases in liability caps for claims of damages from oil spills.
Recently, various Congressional committees have begun pursuing legislation to increase or remove liability caps for Gulf of Mexico drilling. The current $75 million liability limit under the Oil Pollution Act is likely to be materially increased or lifted in its entirety. Such a requirement could ultimately require a company to maintain either an insurance coverage minimum larger than Contango is able or willing to meet, or a financial size and equity position significantly larger than Contango is able to meet. The insurance market may be unable to provide coverage enhancements to address any significant increases in liability caps going forward. In all likely legislative outcomes, we anticipate that insurance coverage will be at a higher cost.
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Gulf of Mexico drilling entails significant inherent risks and increasingly, political risk as well. If an event occurs that is not covered by insurance or not fully protected by insured limits, it would likely have a material adverse impact on our financial condition, results of operations and cash flows.
We have eight employees, all of whom are full time. Effective March 1, 2010, the Company outsourced its human resources function to Administaff Companies II, LP (“Administaff”) and all of the Company’s employees became co-employees of Administaff. In addition to our employees, we use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, environmental and tax services. We are dependent on JEX for prospect generation, evaluation and prospect leasing. As a working interest owner, we rely on outside operators to drill, produce and market our natural gas and oil for our onshore prospects and certain offshore prospects where we are a non-operator. In the offshore prospects where we are the operator, we rely on a turn-key contractor to drill and rely on independent contractors to produce and market our natural gas and oil. In addition, we utilize the services of independent contractors to perform field and on-site drilling and production operation services and independent third party engineering firms to calculate our reserves.
Directors and Executive Officers
The following table sets forth the names, ages and positions of our directors and executive officers:
| Name |
Age | Position | ||
| Kenneth R. Peak | 65 | Chairman, Chief Executive Officer and Director | ||
| Marc Duncan | 57 | President and Chief Operating Officer | ||
| Sergio Castro | 41 | Chief Financial Officer | ||
| Slava Makalskaya | 41 | Vice President and Controller | ||
| Charles A. Cambron | 43 | Vice President of Operations | ||
| B.A. Berilgen | 62 | Director | ||
| Jay D. Brehmer | 45 | Director | ||
| Charles M. Reimer | 65 | Director | ||
| Steven L. Schoonover | 65 | Director |
Kenneth R. Peak. Mr. Peak is the founder of the Company and has been Chairman and Chief Executive Officer since its formation in September 1999. Mr. Peak entered the energy industry in 1973 as a commercial banker and held a variety of financial and executive positions in the oil and gas industry prior to starting Contango in 1999. Mr. Peak served as an officer in the U.S. Navy from 1968 to 1971. Mr. Peak received a BS in physics from Ohio University in 1967, and an MBA from Columbia University in 1972. He currently serves as a director of Patterson-UTI Energy, Inc., a provider of onshore contract drilling services to exploration and production companies in North America.
Marc Duncan. Mr. Duncan joined Contango in June 2005 as President and Chief Operating Officer of Contango Operators, Inc. and was appointed President and Chief Operating Officer of Contango Oil & Gas Company in October 2006. Mr. Duncan has over 26 years of experience in the energy industry and has held a variety of domestic and international engineering and senior-level operations management positions relating to natural gas and oil exploration, project development, and drilling and production operations. Prior to joining Contango, Mr. Duncan served as Chief Operating Officer of USENCO International, Inc. and its subsidiaries and affiliates in China and Ukraine from February 2000 to July 2004 and as a senior project and drilling engineer for Hunt Oil Company from July 2004 to June 2005. He holds an MBA in Engineering Management from the University of Dallas, an MEd from the University of North Texas and a BS in Science and Education from Stephen F. Austin University.
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Sergio Castro. Mr. Castro joined Contango in March 2006 as Treasurer and was appointed Vice President and Treasurer in April 2006 and Chief Financial Officer in June 2010. Prior to joining Contango, Mr. Castro spent two years (April 2004 to March 2006) as a consultant for UHY Advisors TX, LP. From January 2001 to April 2004, Mr. Castro was a lead credit analyst for Dynegy Inc. From August 1997 to January 2001, Mr. Castro worked as an auditor for Arthur Andersen LLP, where he specialized in energy companies. Mr. Castro was honorably discharged from the U.S. Navy in 1993 as an E-6, where he served onboard a nuclear powered submarine. Mr. Castro received a BBA in Accounting in 1997 from the University of Houston, graduating summa cum laude. Mr. Castro is a CPA and a Certified Fraud Examiner.
Yaroslava Makalskaya. Ms. Makalskaya joined Contango in March 2010 and was appointed Vice President and Controller in June 2010. Prior to joining Contango, Ms. Makalskaya was a director of the Transaction Services practice at PricewaterhouseCoopers, where she assisted clients with M&A transactions as well as advised clients with complex accounting and financial reporting issues. Ms.Makalskaya holds a MS degree in economics from Novosibirsk State University in Russia. Ms. Makalskaya is a CPA and has approximately 18 years of work experience in accounting and finance, including 13 years in public accounting. During her work in the audit practice of PricewaterhouseCoopers and Arthur Andersen, her clients included many US and international companies in energy, utilities and mining and other sectors.
Charles A. Cambron. Mr. Cambron joined Contango in August 2010 as Vice President of Operations. Mr. Cambron has 19 years of experience in the Gulf of Mexico oil and gas industry. Most recently he was employed by Applied Drilling Technology, Inc. (ADTI) as an Operations Manager from August 1995 until August 2010. He also held various positions in engineering and offshore supervision over a 15 year period. Prior to ADTI, Mr. Cambron began his career with Rowan Petroleum, Inc. as a Drilling Engineer working in both the Gulf of Mexico and North Sea. Mr. Cambron received a B.S. degree in Petroleum Engineering from the University of Oklahoma in 1991.
B.A. Berilgen. Mr. Berilgen was appointed a director of Contango in July 2007. Mr. Berilgen has served in a variety of senior positions during his 39 year career. Most recently, he became Chief Executive Officer of Patara Oil & Gas LLC in April 2008. Prior to that he was Chairman, Chief Executive Officer and President of Rosetta Resources Inc., a company he founded in June 2005, until his resignation in July 2007, and then he was an independent consultant from July 2007 through April 2008. Mr. Berilgen was also previously the Executive Vice President of Calpine Corp. and President of Calpine Natural Gas L.P. from October 1999 through June 2005. In June 1997, Mr. Berilgen joined Sheridan Energy, a public oil and gas company, as its President and Chief Executive Officer. Mr. Berilgen attended the University of Oklahoma, receiving a B.S. in Petroleum Engineering in 1970 and a M.S. in Industrial Engineering / Management Science.
Jay D. Brehmer. Mr. Brehmer has been a director of Contango since October 2000. Mr. Brehmer is a co-founding partner of Southplace, LLC, a provider of private-company middle-market corporate finance advisory services. Mr. Brehmer founded Southplace, LLC in November 2002. In August 2004, Mr. Brehmer became Managing Director of Houston Capital Advisors LP, a boutique financial advisory, merger and acquisition investment bank, while still retaining his membership in Southplace, LLC. Mr. Brehmer resigned from Houston Capital Advisors LP in January 2008 and is currently associated with Southplace, LLC in a full-time capacity. From May 1998 until November 2002, Mr. Brehmer was responsible for structured-finance energy related transactions at Aquila Energy Capital Corporation. Prior to joining Aquila, Mr. Brehmer founded Capital Financial Services, which provided mid-cap companies with strategic merger and acquisition advice coupled with prudent financial capitalization structures. Mr. Brehmer holds a BBA from Drake University in Des Moines, Iowa.
Charles M. Reimer. Mr. Reimer was elected a director of Contango in November 2005. Mr. Reimer is President of Freeport LNG Development, L.P., and has experience in exploration, production, liquefied natural gas (“LNG”) and business development ventures, both domestically and abroad. From 1986 until 1998, Mr. Reimer served as the senior executive responsible for the VICO joint venture that operated in Indonesia, and provided LNG technical support to P. T. Badak. Additionally, during these years he served, along with Pertamina executives, on the board of directors of the P.T. Badak LNG plant in Bontang, Indonesia. Mr. Reimer began his career with Exxon Company USA in 1967 and held various professional and management positions in Texas and Louisiana. Mr. Reimer was named President of Phoenix Resources Company in 1985
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and relocated to Cairo, Egypt, to begin eight years of international assignments in both Egypt and Indonesia. Prior to joining Freeport LNG Development, L.P. in December 2002, Mr. Reimer was President and Chief Executive Officer of Cheniere Energy, Inc.
Steven L. Schoonover. Mr. Schoonover was elected a director of Contango in November 2005. Mr. Schoonover was most recently Chief Executive Officer of Cellxion, L.L.C., a company he founded in September 1996 and sold in September 2007, which specialized in construction and installation of telecommunication buildings and towers, as well as the installation of high-tech telecommunication equipment. Since the sale in September 2007, Mr. Schoonover continues to serve as a consultant to the current management team of Cellxion, L.L.C. From 1990 until its sale in November 1997 to Telephone Data Systems, Inc., Mr. Schoonover served as President of Blue Ridge Cellular, Inc., a full-service cellular telephone company he co-founded. From 1983 to 1996, he served in various positions, including President and Chief Executive Officer, with Fibrebond Corporation, a construction firm involved in cellular telecommunications buildings, site development and tower construction. Mr. Schoonover has been awarded, on two occasions with two different companies, Entrepreneur of the Year, sponsored by Ernst & Young, Inc Magazine and USA Today.
Directors of Contango serve as members of the board of directors until the next annual stockholders meeting, until successors are elected and qualified or until their earlier resignation or removal. Officers of Contango are elected by the board of directors and hold office until their successors are chosen and qualified, until their death or until they resign or have been removed from office. All corporate officers serve at the discretion of the board of directors. In fiscal year 2010, each outside director of the Company received a quarterly retainer of $20,000 payable in cash, with no stock option or common stock grants. There were no additional payments for meetings attended or being chairman of a committee. There are no family relationships between any of our directors or executive officers.
In fiscal year 2009 and 2008, each outside director of the Company received a quarterly retainer of $8,000 payable in cash and $36,000 payable annually in Company common stock. Each outside director also received a $1,000 cash payment for each board meeting and separately scheduled Audit Committee meeting attended. The Chairman of the Audit Committee received an additional quarterly cash payment of $3,000.
We lease our corporate offices at 3700 Buffalo Speedway, Suite 960, Houston, Texas 77098. Our existing 60 month lease agreement expires on October 31, 2011.
We adopted a Code of Ethics for senior management in December 2002. A copy of our Code of Ethics is filed as an exhibit to this Form 10-K and is also available on our Website at www.contango.com.
General information about us can be found on our Website at www.contango.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our Website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission (“SEC”).
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| Item 1A. | Risk Factors |
In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating the Company. An investment in the Company is subject to risks inherent in our business. The trading price of the shares of the Company is affected by the performance of our business relative to, among other things, competition, market conditions and general economic and industry conditions. The value of an investment in the Company may decrease, resulting in a loss.
We have no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and a substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitability and growth and could have a material adverse effect on the business, the results of operations and financial condition of the Company.
Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. Prices received affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and our ability to raise additional capital. We do not expect to hedge our production to protect against price decreases. Lower prices may also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:
| • | The domestic and foreign supply of natural gas and oil. |
| • | Overall economic conditions. |
| • | The level of consumer product demand. |
| • | Adverse weather conditions and natural disasters. |
| • | The price and availability of competitive fuels such as LNG, heating oil and coal. |
| • | Political conditions in the Middle East and other natural gas and oil producing regions. |
| • | The level of LNG imports. |
| • | Domestic and foreign governmental regulations. |
| • | Special taxes on production. |
| • | Access to pipelines and gas processing plants. |
| • | The loss of tax credits and deductions. |
A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period would negatively affect us.
We depend on the services of our Chairman and Chief Executive Officer, and implementation of our business plan could be seriously harmed if we lost his services.
We depend heavily on the services of Kenneth R. Peak, our chairman and chief executive officer. We do not have an employment agreement with Mr. Peak, and the proceeds from a $10.0 million “key person” life insurance policy on Mr. Peak may not be adequate to cover our losses in the event of Mr. Peak’s death.
We are highly dependent on the technical services provided by JEX and could be seriously harmed if JEX terminated its services with us or became otherwise unavailable.
Because we employ no geoscientists or petroleum engineers, we are dependent upon JEX for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. We do not have a written agreement with JEX which contractually obligates JEX to provide us with its services in the future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss of the services of JEX could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by JEX of certain explorationists could have a material adverse effect on our operations as well.
Our ability to successfully execute our business plan is dependent on our ability to obtain adequate financing.
Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling of exploration prospects and producing property acquisitions, has required and is expected to continue to
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require substantial capital expenditures. We may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, additional financing may not be available to us on acceptable terms, if at all. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.
It is difficult to quantify the amount of financing we may need to fund our planned growth. The amount of funding we may need in the future depends on various factors such as:
| • | Our financial condition. |
| • | The prevailing market price of natural gas and oil. |
| • | The type of projects in which we are engaging. |
| • | The lead time required to bring any discoveries to production. |
We frequently obtain capital through the sale of our producing properties.
The Company, since its inception in September 1999, has raised approximately $484 million from various property sales. These sales bring forward future revenues and cash flows, but our longer term liquidity could be impaired to the extent our exploration efforts are not successful in generating new discoveries, production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of these property sales the Company’s ability to collateralize bank borrowings is reduced which increases our dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.
We assume additional risk as Operator in drilling high pressure and high temperature wells in the Gulf of Mexico.
COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. Drilling activities are subject to numerous risks, including the significant risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. Drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells. The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. This may lead to difficulty and delays in consistently obtaining certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being delayed or experiencing increased costs. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or we may not recover all or any of our investment. The risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling and completion operations may be higher due to our inexperience as an operator.
Additionally, we use turnkey contracts that may cost more than drilling contracts at daily rates. Under certain conditions, the turnkey contract can be terminated by the turnkey drilling contractor, which could lead to materially higher risks and costs for the Company.
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We rely on third-party operators to operate and maintain some of our production pipelines and processing facilities and, as a result, we have limited control over the operations of such facilities. The interests of an operator may differ from our interests.
We depend upon the services of third-party operators to operate production platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil. We have limited influence over the conduct of operations by third-party operators. As a result, we have little control over how frequently and how long our production is shut-in when production problems, weather and other production shut-ins occur. Poor performance on the part of, or errors or accidents attributable to, the operator of a project in which we participate may have an adverse effect on our results of operations and financial condition. Also, the interest of an operator may differ from our interests.
Repeated production shut-ins can possibly damage our well bores.
Our well bores are required to be shut-in from time to time due to a variety of issues, including a combination of weather, mechanical problems, sand production, bottom sediment, water and paraffin associated with our condensate production at our Eugene Island 11 platform, as well as downstream third-party facility and pipeline shut-ins. In addition, shut-ins are necessary from time to time to upgrade and improve the production handling capacity at related downstream platform, gas processing and pipeline infrastructure. In addition to negatively impacting our near term revenues and cash flow, repeated production shut-ins may damage our well bores if repeated excessively or not executed properly. The loss of a well bore due to damage could require us to drill additional wells.
Concentrating our capital investment in the Gulf of Mexico increases our exposure to risk.
Our capital investments are focused in offshore Gulf of Mexico prospects. However, our exploration prospects in the Gulf of Mexico may not lead to significant revenues. Furthermore, we may not be able to drill productive wells at profitable finding and development costs.
Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows.
Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows will be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, the majority of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities of our reserves.
There are numerous uncertainties in estimating crude oil and natural gas reserves and their value, including many factors that are beyond our control. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities of reserves shown in this report.
In order to prepare these estimates, our independent third-party petroleum engineers must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
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Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves shown in a reserve report. In addition, estimates of our proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control and may prove to be incorrect over time. As a result, our estimates may require substantial upward or downward revisions if subsequent drilling, testing and production reveal different results. Furthermore, some of the producing wells included in our reserve report have produced for a relatively short period of time. Accordingly, some of our reserve estimates are not based on a multi-year production decline curve and are calculated using a reservoir simulation model together with volumetric analysis. Any downward adjustment could indicate lower future production and thus adversely affect our financial condition, future prospects and market value.
In June 2010, the Company revised its offshore reserves downward by approximately 48.5 Bcfe. This revision was attributable to newly learned bottom hole pressure data as a result of a recent field wide shut-in and a “P/Z pressure test” that indicated fewer reserves than originally estimated.
The Company’s reserves and revenues are concentrated in one field.
The proved reserves assigned to our Dutch and Mary Rose discoveries have ten producing well bores concentrated in two reservoirs on one field, and are producing via two pipelines and two production platforms. Reserve assessments based on only ten well bores in two reservoirs with relatively limited production history are subject to significantly greater risk of downward revision than multiple well bores from a variety of mature producing reservoirs.
We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside engineers.
We have no in house reservoir engineering capability, and therefore rely on the accuracy of the periodic reservoir reports provided to us by our independent third-party reservoir engineers. If those reports prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of our independent reservoir engineers in our financial planning. If the reports of the outside reservoir engineers prove to be inaccurate, we may make misjudgments in our financial planning.
Exploration is a high risk activity, and our participation in drilling activities may not be successful.
Our future success largely depends on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the significant risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
| • | Unexpected drilling conditions. |
| • | Blowouts, fires or explosions with resultant injury, death or environmental damage. |
| • | Pressure, temperature or other irregularities in formations. |
| • | Equipment failures and/or accidents caused by human error. |
| • | Tropical storms, hurricanes and other adverse weather conditions. |
| • | Compliance with governmental requirements and laws, present and future. |
| • | Shortages or delays in the availability of drilling rigs and the delivery of equipment. |
| • | Our turnkey drilling contracts reverting to a day rate contract or our turnkey contractor electing to terminate the turnkey contract would significantly increase the cost and risk to the Company. |
| • | Problems at third-party operated platforms, pipelines and gas processing facilities over which we have no control. |
Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would materially and adversely affect our future cash flows and results of operations.
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In addition, as a “successful efforts” company, we choose to account for unsuccessful exploration efforts (the drilling of “dry holes”) and seismic costs as a current expense of operations, which immediately impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and cause our earnings to be volatile from period to period.
Production activities in the Gulf of Mexico increase our susceptibility to pollution and natural resource damage.
A blowout, rupture or spill of any magnitude would present serious operational and financial challenges. Most of the Company’s operations are on the Gulf of Mexico shelf in water depths less than 200 feet and less than 50 miles from the coast. Such proximity to the shore-line increases the probability of a biological impact or damaging the fragile eco-system in the event of released condensate.
The natural gas and oil business involves many operating risks that can cause substantial losses.
The natural gas and oil business involves a variety of operating risks, including:
| • | Blowouts, fires and explosions. |
| • | Surface cratering. |
| • | Uncontrollable flows of underground natural gas, oil or formation water. |
| • | Natural disasters. |
| • | Pipe and cement failures. |
| • | Casing collapses. |
| • | Stuck drilling and service tools. |
| • | Reservoir compaction. |
| • | Abnormal pressure formations. |
| • | Environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or discharges of toxic gases. |
| • | Capacity constraints, equipment malfunctions and other problems at third-party operated platforms, pipelines and gas processing plants over which we have no control. |
| • | Repeated shut-ins of our well bores could significantly damage our well bores. |
| • | Required workovers of existing wells that may not be successful. |
If any of the above events occur, we could incur substantial losses as a result of:
| • | Injury or loss of life. |
| • | Reservoir damage. |
| • | Severe damage to and destruction of property or equipment. |
| • | Pollution and other environmental damage. |
| • | Clean-up responsibilities. |
| • | Regulatory investigations and penalties. |
| • | Suspension of our operations or repairs necessary to resume operations. |
Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and collisions. In addition, offshore operations, and in some instances, operations along the Gulf Coast, are subject to damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.
If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
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Not hedging our production may result in losses.
Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if our production should be shut-in during a period when NYMEX natural gas prices increase, our policy is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.
Our ability to market our natural gas and oil may be impaired by capacity constraints and equipment malfunctions on the platforms, gathering systems, pipelines and gas plants that transport and process our natural gas and oil.
All of our natural gas and oil is transported through gathering systems, pipelines, processing plants, and offshore platforms. Transportation capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems, processing plants, platforms or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations. Further, repeated shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could result in additional wells being required to produce our reserves.
We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceed with our exploration and development of the lease site.
Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of JEX and others to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. However, such deficiencies may not have been cured by the operator of such wells. It does happen, from time to time, that the examination made by title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.
Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than many of our competitors.
We compete with a broad range of natural gas and oil companies in our exploration and property acquisition activities. We also compete for the equipment and labor required to operate and to develop these properties. Many of our competitors have substantially greater financial resources than we do. These competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties. Further, they may be able to evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future depends on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively with these companies or in such a highly competitive environment.
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We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment. Failure to comply with such rules and regulations could result in substantial penalties and have an adverse effect on us. These laws and regulations:
| • | Require that we obtain permits before commencing drilling. |
| • | Restrict the substances that can be released into the environment in connection with drilling and production activities. |
| • | Limit or prohibit drilling activities on protected areas, such as wetlands or wilderness areas. |
| • | Require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells. |
Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain only limited insurance coverage for sudden and accidental environmental damages. Accordingly, we may be subject to liability, or we may be required to cease production from properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated developments could cause us to make environmental expenditures that are significantly different from those we currently expect. Existing laws and regulations could be changed and any such changes could have an adverse effect on our business and results of operations.
Our operations in the Gulf of Mexico could be adversely affected by changes in laws and regulations which are expected to occur as a result of the Deepwater Horizon Incident.
In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon was engaged in drilling operations for another operator and sank after an apparent blowout and fire. The accident resulted in the loss of life and a significant oil spill. On May 27, 2010, in response to the incident, the President of the United States announced a six-month moratorium on drilling in the deepwater Gulf of Mexico and imposed new restrictions on permitting activities on the Outer Continental Shelf. On July 12, 2010, the Secretary of the Interior revised the moratorium that is scheduled to end November 30, 2010. In conjunction with the moratorium, the Department of the Interior issued a directive calling for additional safety and performance standards as well as rigorous monitoring and testing requirements. More recently, various Congressional committees have begun pursuing legislation to regulate drilling activities and increase liability for oil spills.
We are monitoring legislative and regulatory developments; however, the full legislative and regulatory response to the incident is not yet known. An expansion of safety and performance regulations or an increase in liability for drilling activities may have one or more of the following impacts on our business:
| • | Increase the costs of drilling exploratory and development wells. |
| • | Cause delays in, or preclude, the development of projects in the Gulf of Mexico |
| • | Result in higher operating costs. |
| • | Increase or remove liability caps for claims of damages from oil spills. |
| • | Limit our ability to obtain additional insurance coverage on commercially reasonable terms to protect against any increase in liability. |
Any of the above factors may result in a reduction of our cash flows, profitability, and the fair value of our properties.
We do not control the activities on properties we do not operate.
Other companies may from time to time drill, complete and operate properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of
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our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:
| • | Timing and amount of capital expenditures. |
| • | The operator’s expertise and financial resources. |
| • | Approval of other participants in drilling wells. |
| • | Selection of technology. |
We are highly dependent on our management team, JEX, exploration partners and third-party consultants and any failure to retain the services of such parties could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies.
The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy is highly dependent on our management team, as well as certain key geoscientists, geologists, engineers and other professionals engaged by us. We are highly dependent on the services provided by JEX and we do not have any written agreements contractually obligating them to provide us with their services in the future. The loss of key members of our management team, JEX or other highly qualified technical professionals could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies which may have a material adverse effect on our business, financial condition and operating results.
Acquisition prospects are difficult to assess and may pose additional risks to our operations.
We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. The successful acquisition of natural gas and oil properties requires an assessment of:
| • | Recoverable reserves. |
| • | Exploration potential. |
| • | Future natural gas and oil prices. |
| • | Operating costs. |
| • | Potential environmental and other liabilities and other factors. |
| • | Permitting and other environmental authorizations required for our operations. |
In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are necessarily inexact and their accuracy inherently uncertain and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken.
Future acquisitions could pose additional risks to our operations and financial results, including:
| • | Problems integrating the purchased operations, personnel or technologies. |
| • | Unanticipated costs. |
| • | Diversion of resources and management attention from our exploration business. |
| • | Entry into regions or markets in which we have limited or no prior experience. |
| • | Potential loss of key employees of the acquired organization. |
The risks and challenges inherent in mineral exploration are quite different from our natural gas and oil exploration and we have no mineral expertise.
Our investment in Contango Mining does not represent a change in our natural gas and oil exploration business model. We recognize that the risks and challenges inherent in mineral exploration are quite different from our natural gas and oil exploration business. Our 2009 and early 2010 exploration programs found relatively few samples of commercial grade minerals but we believe our results merit continued exploration.
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At this early exploration stage our investment should be considered speculative and the probability of ultimately being successful in finding gold or other minerals in a volume sufficient to support a commercial mining operation are quite low. We have little or no experience in mining and mineral development and will be highly dependent upon the advice of consultants.
Anti-takeover provisions of our certificate of incorporation, bylaws and Delaware law could adversely effect a potential acquisition by third-parties that may ultimately be in the financial interests of our stockholders.
Our Certificate of Incorporation, Bylaws and the Delaware General Corporation Law contain provisions that may discourage unsolicited takeover proposals. These provisions could have the effect of inhibiting fluctuations in the market price of our common stock that could result from actual or rumored takeover attempts, preventing changes in our management or limiting the price that investors may be willing to pay for shares of common stock.
The Company adopted a Stockholders Rights Plan in September 2008 that is designed to ensure that all stockholders of the Company receive fair value for their shares of common stock in a proposed takeover of the Company and to guard against coercive takeover tactics to gain control of the Company. In addition, these provisions, among other things, authorize the board of directors to:
| • | Designate the terms of and issue new series of preferred stock. |
| • | Limit the personal liability of directors. |
| • | Limit the persons who may call special meetings of stockholders. |
| • | Prohibit stockholder action by written consent. |
| • | Establish advance notice requirements for nominations for election of the board of directors and for proposing matters to be acted on by stockholders at stockholder meetings. |
| • | Require us to indemnify directors and officers to the fullest extent permitted by applicable law. |
| • | Impose restrictions on business combinations with some interested parties. |
Our common stock is thinly traded.
Contango has approximately 15.7 million shares of common stock outstanding. Directors and officers own or have voting control over approximately 3.2 million shares. Since our common stock is not heavily traded, the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of our common stock.
| Item 1B. | Unresolved Staff Comments |
None
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| Item 2. | Properties |
Production, Prices and Operating Expenses
The following table presents information from continuing operations regarding the production volumes, average sales prices received and average production costs associated with our sales of natural gas, oil and natural gas liquids (“NGLs”) for the periods indicated. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGL is the energy equivalent of six thousand cubic feet (“Mcf”) of natural gas. Reported lease operating expenses include property and severance taxes.
| Year Ended June 30, | |||||||||
| 2010 | 2009 | 2008 | |||||||
| Production: |
|||||||||
| Natural gas (million cubic feet) |
21,385 | 20,535 | 9,089 | ||||||
| Oil and condensate (thousand barrels) |
505 | 515 | 185 | ||||||
| Natural gas liquids (thousand gallons) |
25,117 | 24,803 | 4,968 | ||||||
| Total (million cubic feet equivalent) |
28,003 | 27,168 | 10,909 | ||||||
| Natural gas (million cubic feet per day) |
58.6 | 56.3 | 24.8 | ||||||
| Oil and condensate (thousand barrels per day) |
1.4 | 1.4 | 0.5 | ||||||
| Natural gas liquids (thousand gallons per day) |
68.8 | 68.0 | 13.6 | ||||||
| Total (million cubic feet equivalent per day) |
76.8 | 74.4 | 29.7 | ||||||
| Average sales price: |
|||||||||
| Natural gas (per thousand cubic feet) |
$ | 4.47 | $ | 6.34 | $ | 9.77 | |||
| Oil and condensate (per barrel) |
$ | 77.18 | $ | 67.72 | $ | 108.36 | |||
| Natural gas liquids (per gallon) |
$ | 1.04 | $ | 1.03 | $ | 1.55 | |||
| Total (per thousand cubic feet equivalent) |
$ | 5.74 | $ | 7.02 | $ | 10.68 | |||
| Selected data per Mcfe: |
|||||||||
| Total lease operating expenses |
$ | 0.61 | $ | 0.87 | $ | 0.62 | |||
| General and administrative expenses |
$ | 0.16 | $ | 0.35 | $ | 1.50 | |||
| Depreciation, depletion and amortization of natural gas and oil properties |
$ | 1.25 | $ | 1.17 | $ | 1.01 | |||
Development, Exploration and Acquisition Expenditures
The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated:
| Year Ended June 30, | |||||||||
| 2010 | 2009 | 2008 | |||||||
| Property acquisition costs: |
|||||||||
| Unproved |
$ | 11,318,349 | $ | — | $ | — | |||
| Proved |
2,009,330 | 1,131,582 | 309,000,000 | ||||||
| Exploration costs |
52,805,270 | 23,284,970 | 45,243,651 | ||||||
| Developmental costs |
40,901,582 | 22,889,629 | 76,025,586 | ||||||
| Total costs |
$ | 107,034,531 | $ | 47,306,181 | $ | 430,269,237 | |||
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The following table shows our drilling activity for the periods indicated. In the table, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells.
| Year Ended June 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||
| Exploratory Wells: |
||||||||||||
| Productive (onshore) |
14 | 14.0 | — | — | 34 | 2.2 | ||||||
| Productive (offshore) |
2 | 1.3 | 2 | 0.8 | 4 | 2.0 | ||||||
| Non-productive (onshore) |
— | — | — | — | 19 | 3.9 | ||||||
| Non-productive (offshore) |
2 | 2.0 | 2 | 2.0 | 1 | 1.0 | ||||||
| Total |
18 | 17.3 | 4 | 2.8 | 58 | 9.1 | ||||||
For the fiscal year ended June 31, 2008, the onshore wells listed above relate to our investment in the Arkansas Fayetteville Shale. At the time the Company sold its interest in the Arkansas Fayetteville Shale wells, the Company had 16 wells that were being drilled. We have classified those 16 wells as non-productive.
Exploration and Development Acreage
Our principal natural gas and oil properties consist of natural gas and oil leases. The following table indicates our interests in developed and undeveloped acreage as of June 30, 2010:
| Developed Acreage (1)(2) |
Undeveloped Acreage (1)(3) | |||||||
| Gross (4) | Net (5) | Gross (4) | Net (5) | |||||
| Onshore Texas |
10,075 | 9,115 | 535 | 535 | ||||
| Offshore Gulf of Mexico |
16,897 | 8,547 | 61,272 | 46,983 | ||||
| Total |
26,972 | 17,662 | 61,807 | 47,518 | ||||
| (1) | Excludes any interest in acreage in which we have no working interest before payout or before initial production. |
| (2) | Developed acreage consists of acres spaced or assignable to productive wells. |
| (3) | Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. |
| (4) | Gross acres refer to the number of acres in which we own a working interest. |
| (5) | Net acres represent the number of acres attributable to an owner’s proportionate working interest in a lease (e.g., a 50% working interest in a lease covering 320 acres is equivalent to 160 net acres). |
Included in the Offshore Gulf of Mexico acres shown in the table above are the beneficial interests Contango has in the offshore acreage owned by REX. The above table includes our 32.3% interest in REX’s 1,163 net developed acres and 11,619 net undeveloped acres. In addition, the Company holds royalty interests in 4,538 gross undeveloped acres (79 net undeveloped acres), offshore in the Gulf of Mexico.
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The following table sets forth the number of gross and net productive natural gas and oil wells in which we owned an interest as of June 30, 2010:
| Total Productive Wells (1) | ||||
| Gross (2) | Net (3) | |||
| Natural gas (onshore) |
14 | 12.7 | ||
| Natural gas (offshore) |
12 | 5.4 | ||
| Oil |
— | — | ||
| Total |
26 | 18.1 | ||
| (1) | Productive wells are producing wells and wells capable of producing commercial quantities. Completed but marginally producing wells are not considered here as a “productive” well. |
| (2) | A gross well is a well in which we own an interest. |
| (3) | The number of net wells is the sum of our fractional working interests owned in gross wells. |
The following table presents our estimated net proved natural gas and oil reserves and the pre-tax net present value of our reserves at June 30, 2010, based on reserve reports generated by William M. Cobb & Associates, Inc. (“Cobb”) and Lonquist & Co. LLC (“Lonquist”). The Company believes that having independent and well respected third-party engineering firms prepare its reserve reports enhances the credibility of its reported reserve estimates. Management is responsible for the reserve estimate disclosures in this filing, and meets regularly with our independent third-party engineers to review these reserve estimates. The qualifications of the technical person at each of these firms primarily responsible for overseeing his firm’s preparation of the company’s reserve estimates are set forth below.
William M. Cobb & Associates, Inc.
| • | Over 30 years of practical experience in the estimation and evaluation of reserves |
| • | A registered professional engineer in the state of Texas |
| • | Bachelor of Science Degree in Petroleum Engineering |
| • | Member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. |
Lonquist & Co. LLC
| • | Over 21 years of practical experience in the estimation and evaluation of reserves |
| • | A registered professional engineer in the state of Texas |
| • | Bachelor of Science Degree in Petroleum Engineering |
| • | Member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers. |
Each of Cobb and Lonquist has informed us that the technical person primarily responsible for the reserve estimates meets or exceeds the education, training, and experience requirements set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.
We maintain adequate and effective internal controls over the underlying data upon which reserves estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is communicated to our reservoir engineers quarterly, is confirmed when our third-party reservoir engineers hold technical meetings with geologists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained
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from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Controls – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. All data such as commodity prices, lease operating expenses, production taxes, field level commodity price differentials, ownership percentages, and well production data are updated in the reserve database by our third-party reservoir engineers and then analyzed by management to ensure that they have been entered accurately and that all updates are complete. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, our independent engineering firms prepare their independent reserve estimates and final report.
| Total Proved Reserves as of June 30, 2010 | ||||||||
| Producing | Non-Producing | Total | ||||||
| Offshore |
||||||||
| Natural gas (MMcf) |
177,418 | 68,593 | 246,011 | |||||
| Oil and condensate (MBbls) |
3,675 | 923 | 4,598 | |||||
| Natural gas liquids (MBbls) |
4,657 | 2,081 | 6,738 | |||||
| Total proved reserves (MMcfe) |
227,410 | 86,617 | 314,027 | |||||
| Pre-tax net present value ($000) (discounted @ 10%) |
$ | 812,044 | $ | 158,398 | 970,442 | |||
In December 2008, the SEC released the final rule for Modernization of Oil and Gas Reporting. The new rule requires disclosure of oil and gas proved reserves using the 12-month average beginning-of-month price for the year, rather than year-end prices, and allows the use of reliable technologies to estimate proved oil and gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. In addition, companies are required to report on the independence and qualifications of its reserves preparer or auditor, and file reports when a third party is relied upon to prepare reserves estimates or conduct a reserves audit. The reserves information above is presented consistent with the requirements of the new rule. The new rule does not allow prior-year reserve information to be restated, so all information related to periods prior to June 30, 2010 is presented consistent with prior SEC rules for the estimation of proved reserves. In January 2010, the Financial Accounting Standards Board (“FASB”) adopted the SEC’s final rule for Modernization of Oil and Gas Reporting.
The line item “Pre-tax net present value, discounted at 10%” in the table above, is not intended to represent the current market value of the estimated natural gas and oil reserves we own. The pre-tax net present value of future cash flows attributable to our proved reserves as of June 30, 2010 was based on $4.09 per million British thermal units (“MMbtu”) for natural gas at the NYMEX, $76.21 per barrel of oil at the West Texas Intermediate Posting, and $44.62 per barrel of NGLs, in each case before adjusting for basis, transportation costs and British thermal unit (“BTU”) content. The pre-tax net present value is a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K. The table below reconciles our calculation of pre-tax net present value to the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. Management believes that pre-tax net present value is an important non-GAAP financial measure used by analysts, investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The reconciliation of the pre-tax net present value to the standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves at June 30, 2010 is as follows (in thousands):
| At June 30, 2010 |
|||
| Pre-tax net present value ($000) (discounted @ 10%) |
970,442 | ||
| Future income taxes, discounted at 10% |
(258,348 | ) | |
| Standardized measure of discounted future net cash flows |
712,094 |
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While we are reasonably certain of recovering our calculated reserves, the process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third party engineers must project production rates, estimate timing and amount of development expenditures, analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of all of this data may vary. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
| Item 3. | Legal Proceedings |
From time to time, we are party to litigation or other legal and administrative proceedings that we consider to be a part of the ordinary course of business. As of the date of this Form 10-K, we are not a party to any material legal proceedings and we are not aware of any material proceedings contemplated against us, that could individually or in the aggregate, reasonably be expected to have a material adverse effect on our financial condition, cash flows or results of operations.
| Item 4. | Reserved |
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. |
Our common stock was listed on the NYSE Amex (previously the American Stock Exchange) in January 2001 under the symbol “MCF”. The table below shows the high and low closing prices of our common stock for the periods indicated.
| High | Low | |||||
| Fiscal Year 2009: |
||||||
| Quarter ended September 30, 2008 |
$ | 94.40 | $ | 48.11 | ||
| Quarter ended December 31, 2008 |
$ | 56.30 | $ | 36.55 | ||
| Quarter ended March 31, 2009 |
$ | 57.15 | $ | 32.20 | ||
| Quarter ended June 30, 2009 |
$ | 49.87 | $ | 35.87 | ||
| Fiscal Year 2010: |
||||||
| Quarter ended September 30, 2009 |
$ | 51.06 | $ | 40.40 | ||
| Quarter ended December 31, 2009 |
$ | 54.09 | $ | 44.38 | ||
| Quarter ended March 31, 2010 |
$ | 55.00 | $ | 47.07 | ||
| Quarter ended June 30, 2010 |
$ | 60.03 | $ | 44.28 | ||
On August 31, 2010, the closing price of our common stock on the NYSE Amex was $43.85 per share, and there were 15,664,666 shares of Contango common stock outstanding, held by approximately 79 holders of record.
We have not declared or paid any dividends on our shares of common stock. Any future decision to pay dividends on our common stock will be at the discretion of our board and will depend upon our financial condition, results of operations, capital requirements, and other factors our board may deem relevant.
During the fiscal year ended 2007, we sold $30.0 million of our Series E preferred stock to a group of private investors. During the fiscal year ended 2008, all Series E preferred stockholders converted their Series E preferred stock into 789,468 shares of our common stock.
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The following table sets forth information about our equity compensation plans at June 30, 2010:
| Plan Category |
Number of securities to be issued upon exercise of outstanding options |
Weighted-average exercise price of outstanding options |
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (b)) | ||||
| 1999 Stock Incentive Plan - |
280,334 | $ | 26.76 | — | |||
| 2009 Equity Compensation Plan - |
25,000 | $ | 49.29 | 1,475,000 | |||
| Equity compensation plans not |
— | — | — | ||||
The Company’s 1999 Stock Incentive Plan (the “1999 Plan”) expired in August 2009. The 280,334 outstanding options issued under the 1999 Plan will be converted into securities if exercised prior to their expiration dates, which range from December 2010 to September 2013.
On September 15, 2009, the Company’s Board of Directors adopted the Contango Oil & Gas Company Equity Compensation Plan (the “2009 Plan”), which was approved by shareholders on November 19, 2009. Under the 2009 Plan, the Company’s Board of Directors can grant restricted stock and option awards to officers, directors, employees or consultants of the Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board.
During the fiscal year ended June 30, 2010, the Company purchased 115,454 shares of its common stock from three officers of the Company and two members of its board of directors for approximately $6.4 million. During the fiscal year ended June 30, 2009, the Company purchased 21,754 shares of its common stock from one member of its board of directors for approximately $1.3 million. During the fiscal year ended June 30, 2008, Company purchased 10,000 shares of its common stock from one member of its board of directors and 99,333 stock options from three officers of the Company and one member of its board of directors for approximately $6.6 million. All purchases were approved by the Company’s board of directors and were completed at the closing price of the Company’s common stock on the date of purchase.
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The following graph compares the yearly percentage change from June 30, 2005 until June 30, 2010 in the cumulative total stockholder return on our common stock to the cumulative total return on the Russell 2000 Stock Index and a peer group of five independent oil and gas exploration companies selected by us. The companies in our selected peer group are ATP Oil & Gas Corp., Callon Petroleum, Energy XXI (Bermuda) Limited, McMoRan Exploration Company, and W&T Offshore, Inc. Our common stock began trading on the NYSE Amex (previously American Stock Exchange) on January 19, 2001 and before that traded on the Nasdaq over-the-counter Bulletin Board. The graph assumes that a $100 investment was made in our common stock and each index on June 30, 2005 and that all dividends were reinvested. The stock performance for our common stock is not necessarily indicative of future performance. For companies that did not exist as of June 30, 2005, we used the initial public price for all periods that an actual price did not exist.
Comparison of Fiscal Year 2010 Cumulative Total Return
| 06/30/2005 | 6/30/2006 | 6/30/2007 | 6/30/2008 | 6/30/2009 | 6/30/2010 | |||||||
| Peer Group Composite |
100 | 141 | 127 | 183 | 29 | 46 | ||||||
| Russell 2000 Stock Index |
100 | 113 | 130 | 108 | 79 | 95 | ||||||
| Contango Oil & Gas Co. |
100 | 154 | 394 | 1,010 | 462 | 486 |
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| Item 6. | Selected Financial Data |
| Year Ended June 30, | |||||||||||||||||
| 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||
| (Dollar amounts in 000s, except per share amounts) | |||||||||||||||||
| Financial Data: |
|||||||||||||||||
| Revenues: |
|||||||||||||||||
| Natural gas and oil sales |
$ | 160,681 | $ | 190,656 | $ | 116,498 | $ | 14,140 | $ | 776 | |||||||
| Total revenues |
$ | 160,681 | $ | 190,656 | $ | 116,498 | $ | 14,140 | $ | 776 | |||||||
| Income (loss) from continuing operations |
$ | 49,686 | $ | 55,861 | $ | 83,221 | $ | (1,078 | ) | $ | (6,888 | ) | |||||
| Discontinued operations, net of income taxes |
— | — | 173,685 | (1,617 | ) | 6,681 | |||||||||||
| Net income (loss) |
$ | 49,686 | $ | 55,861 | $ | 256,906 | $ | (2,695 | ) | $ | (207 | ) | |||||
| Preferred stock dividends |
— | — | 1,548 | 540 | 601 | ||||||||||||
| Net income (loss) attributable to common stock |
$ | 49,686 | $ | 55,861 | $ | 255,358 | $ | (3,235 | ) | $ | (808 | ) | |||||
| Net income (loss) per share: |
|||||||||||||||||
| Basic |
|||||||||||||||||
| Continuing operations |
$ | 3.14 | $ | 3.41 | $ | 5.05 | $ | (0.03 | ) | $ | (0.50 | ) | |||||
| Discontinued operations |
— | — | 10.73 | (0.18 | ) | 0.45 | |||||||||||
| Total |
$ | 3.14 | $ | 3.41 | $ | 15.78 | $ | (0.21 | ) | $ | (0.05 | ) | |||||
| Diluted |
|||||||||||||||||
| Continuing operations |
$ | 3.08 | $ | 3.35 | $ | 4.82 | $ | (0.03 | ) | $ | (0.50 | ) | |||||
| Discontinued operations |
— | — | 10.06 | (0.18 | ) | 0.45 | |||||||||||
| Total |
$ | 3.08 | $ | 3.35 | $ | 14.88 | $ | (0.21 | ) | $ | (0.05 | ) | |||||
| Weighted average shares outstanding: |
|||||||||||||||||
| Basic |
15,831 | 16,363 | 16,185 | 15,430 | 14,760 | ||||||||||||
| Diluted |
16,157 | 16,690 | 17,263 | 15,430 | 14,760 | ||||||||||||
| Working capital (deficit) |
$ | 41,385 | $ | 43,232 | $ | 29,913 | $ | (4,088 | ) | $ | 18,333 | ||||||
| Capital expenditures |
$ | 97,699 | $ | 45,742 | $ | 119,929 | $ | 77,688 | $ | 33,805 | |||||||
| Long term debt |
$ | — | $ | — | $ | 15,000 | $ | 20,000 | $ | 10,000 | |||||||
| Stockholders’ equity |
$ | 377,330 | $ | 349,364 | $ | 341,998 | $ | 90,804 | $ | 62,540 | |||||||
| Total assets |
$ | 592,266 | $ | 517,042 | $ | 599,974 | $ | 153,936 | $ | 89,385 | |||||||
| Proved Reserve Data: |
|||||||||||||||||
| Total proved reserves (Mmcfe) |
314,027 | 355,046 | 369,076 | 84,876 | 3,430 | ||||||||||||
| Pre-tax net present value (SEC at 10%) |
$ | 970,442 | $ | 889,865 | $ | 3,183,843 | $ | 329,179 | $ | 8,852 | |||||||
| Standardized Measure |
$ | 712,094 | $ | 638,091 | $ | 2,233,918 | $ | 252,297 | $ | 7,734 | |||||||
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| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the related notes and other information included elsewhere in this report.
Contango is a Houston-based, independent natural gas and oil company. The Company’s business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico. COI, our wholly-owned subsidiary, acts as operator on certain offshore prospects.
Revenues and Profitability. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil and on our ability to find, develop and acquire natural gas and oil reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.
Reserve Replacement. Generally, our producing properties offshore in the Gulf of Mexico have high initial production rates, followed by steep declines. As a result, we must locate and develop or acquire new natural gas and oil reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire natural gas and oil reserves.
Sale of proved properties. From time-to-time as part of our business strategy, we have sold, and in the future may continue to sell some or a substantial portion of our proved reserves to capture current value, using the sales proceeds to reduce debt and further our exploration activities.
Use of Estimates. The preparation of our financial statements requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include estimates of remaining proved natural gas and oil reserves, the timing and costs of our future drilling, development and abandonment activities, and income taxes.
Please see “Risk Factors” on page 14 for a more detailed discussion of a number of other factors that affect our business, financial condition and results of operations.
Impact of Deepwater Horizon Incident and Federal Deepwater Moratorium
In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling operations for another operator, sank after an apparent blowout and fire. On May 27, 2010, in response to the incident, the President of the United States announced a six-month moratorium on drilling in the deepwater Gulf of Mexico (the “Moratorium”), which followed a one-month suspension in activity announced in May 2010, immediately following the spill. Under the Moratorium, no new drilling, including sidetracks and bypasses of wells, is allowed in water depths greater than 500 feet for six months, or until November 27, 2010. For operators such as Contango that operate in less than 500 feet of water, there are new, more restrictive requirements, on permitting activities on the Outer Continental Shelf.
On July 12, 2010, the Secretary of the Interior announced a revised moratorium that is scheduled to extend through November 30, 2010 that focuses on drilling configurations and technologies rather than on water depth. The revised moratorium applies to all Gulf of Mexico drilling operations. Some companies may be able to resume drilling sooner under certain conditions. To qualify, operators must certify that they have adequate plans in place to quickly shut down an out-of-control well, that the blowout preventers atop the wells it drills have passed rigorous new tests, and that sufficient cleanup resources are on hand in the event of a spill.
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Business Impact
In the near-term, we do not expect a material impact on our production. It is our understanding that workover operations, operations necessary to sustain reservoir pressure, and plugging and abandonment operations are still allowed, to the extent they comply with applicable regulations and permits. Therefore, we do not expect production for the remainder of calendar year 2010 to be impacted.
Over a longer period of time, however, we believe that the Deepwater Horizon incident is likely to have a significant and lasting effect on the US offshore energy industry, and will likely result in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards, changes in equipment requirements and the availability and cost of insurance, as well as increased politicization of the industry. A significant delay of planned exploratory activities will reduce our longer term ability to replace reserves, resulting in a negative impact on production, including a reduction in operating results and cash flows as we deplete our reserves. There may be other impacts of which we are not aware at this time.
Finally, the potential for removal of the liability cap for claims of damages from oil spills, and/or the enactment of onerous rules and regulations regarding activities in the Gulf of Mexico could significantly alter our industry. Such rules could effectively limit which companies can operate in the Gulf of Mexico. Small and medium-sized oil and gas companies may not be able to obtain insurance coverage at economically appropriate levels or meet financial responsibility requirements and would be forced to exit operations in the Gulf of Mexico. Potentially less attractive economics for exploration and development programs going forward will require companies retaining operations in the Gulf of Mexico to review their business models. We have drilled, and believe we can continue to drill, safely in the Gulf of Mexico. However, exploration and production companies will be able to continue doing business in the Gulf of Mexico only to the extent it remains economically viable.
Delays and volatility are inherent in our business. We have maintained a capital structure with a strong liquidity position allowing us to manage during periods of uncertainty. We believe we are well-positioned to respond to the increasingly complex regulatory framework for the Gulf of Mexico.
The following is a discussion of the results of our continuing operations for the fiscal year ended June 30, 2010, compared to the fiscal year ended June 30, 2009, and for the fiscal year ended June 30, 2009, compared to the fiscal year ended June 30, 2008.
Revenues. All of our revenues are from the sale of our natural gas and oil production. Our revenues may vary significantly from year to year depending on changes in commodity prices, which fluctuate widely, and production volumes. Our production volumes are subject to wide swings as a result of new discoveries, weather and mechanical related problems. In addition, our production declines over time as we produce our reserves.
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The table below sets forth revenue and production data for continuing operations for the fiscal years ended June 30, 2010, 2009 and 2008.
| Year ended June 30, | Year ended June 30, | |||||||||||||||||||
| 2010 | 2009 | % | 2009 | 2008 | % | |||||||||||||||
| ($000) | ($000) | |||||||||||||||||||
| Revenues: |
||||||||||||||||||||
| Natural gas and oil sales |
$ | 160,681 | $ | 190,656 | -16 | % | $ | 190,656 | $ | 116,498 | 64 | % | ||||||||
| Total revenues |
$ | 160,681 | $ | 190,656 | $ | 190,656 | $ | 116,498 | ||||||||||||
| Production: |
||||||||||||||||||||
| Natural gas (million cubic feet) |
21,385 | 20,535 | 4 | % | 20,535 | 9,089 | 126 | % | ||||||||||||
| Oil and condensate (thousand barrels) |
505 | 515 | -2 | % | 515 | 185 | 178 | % | ||||||||||||
| Natural gas liquids (thousand gallons) |
25,117 | 24,803 | 1 | % | 24,803 | 4,968 | 399 | % | ||||||||||||
| Total (million cubic feet equivalent) |
28,003 | 27,168 | 3 | % | 27,168 | 10,909 | 149 | % | ||||||||||||
| Natural gas (million cubic feet per day) |
58.6 | 56.3 | 4 | % | 56.3 | 24.8 | 127 | % | ||||||||||||
| Oil and condensate (thousand barrels per day) |
1.4 | 1.4 | 0 | % | 1.4 | 0.5 | 179 | % | ||||||||||||
| Natural gas liquids (thousand gallons per day) |
68.8 | 68.0 | 1 | % | 68.0 | 13.6 | 401 | % | ||||||||||||
| Total (million cubic feet per day equivalent) |
76.8 | 74.4 | 3 | % | 74.4 | 29.7 | 150 | % | ||||||||||||
| Average Sales Price: |
||||||||||||||||||||
| Natural gas (per thousand cubic feet) |
$ | 4.47 | $ | 6.34 | -29 | % | $ | 6.34 | $ | 9.77 | -35 | % | ||||||||
| Oil and condensate (per barrel) |
$ | 77.18 | $ | 67.72 | 14 | % | $ | 67.72 | $ | 108.36 | -38 | % | ||||||||
| Natural gas liquids (per gallon) |
$ | 1.04 | $ | 1.03 | 1 | % | $ | 1.03 | $ | 1.55 | -34 | % | ||||||||
| Total (per thousand cubic feet equivalent) |
$ | 5.74 | 7.02 | -18 | % | 7.02 | 10.68 | -34 | % | |||||||||||
| Operating expenses |
$ | 17,040 | $ | 23,684 | -28 | % | $ | 23,684 | $ | 6,777 | 249 | % | ||||||||
| Exploration expenses |
$ | 21,939 | $ | 20,603 | 6 | % | $ | 20,603 | $ | 5,729 | 260 | % | ||||||||
| Depreciation, depletion and amortization |
$ | 35,374 | $ | 32,673 | 8 | % | $ | 32,673 | $ | 11,900 | 175 | % | ||||||||
| Lease expirations and relinquishments |
$ | 952 | $ | 5,208 | -82 | % | $ | 5,208 | $ | 642 | 711 | % | ||||||||
| Impairment of natural gas and oil properties |
$ | — | $ | 5,866 | -100 | % | $ | 5,866 | $ | — | 100 | % | ||||||||
| General and administrative expenses |
$ | 4,616 | $ | 9,467 | -51 | % | $ | 9,467 | $ | 16,929 | -44 | % | ||||||||
| Interest expense, net of interest capitalized |
$ | 518 | $ | 741 | -30 | % | $ | 741 | $ | 3,933 | -81 | % | ||||||||
| Interest income |
$ | 915 | $ | 926 | -1 | % | $ | 926 | $ | 1,969 | -53 | % | ||||||||
| Gain (loss) on sale of assets and other |
$ | 113 | $ | (530 | ) | -121 | % | $ | (530 | ) | $ | 62,314 | -101 | % | ||||||
Natural Gas, Oil and NGL Sales. We reported revenues of approximately $160.7 million for the year ended June 30, 2010, down from approximately $190.7 million reported for the year ended June 30, 2009. This decrease in sales was primarily attributable to the significant decline in natural gas prices received for the year ended June 30, 2010. Also contributing was a reduction in production as a result of our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in fiscal year 2010. This decreased production was partially offset by increased production from our Eloise North well which began producing in December 2008 and our Dutch #4 well which began producing in January 2009. The decrease in production was also offset by increased production from our Dutch #1, #2 and #3 wells which increased production in fiscal year 2010, as compared to prior year when they were shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike.
We reported revenues of approximately $190.7 million for the year ended June 30, 2009, up from approximately $116.5 million reported for the year ended June 30, 2008. This increase was attributable to increased natural gas, oil and NGL sales from our Mary Rose #4 discovery which began producing in July 2008, our Eloise North discovery which began producing in December 2008, and our Dutch #4 discovery which began producing in January 2009. This increase was partially offset by reduced sales from our Dutch
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#1, #2 and #3 wells which were shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike. The increase was also attributable to the additional interest we purchased in our Dutch and Mary Rose discoveries, effective January 1, 2008.
Natural Gas, Oil and NGL Production and Average Sales Prices. Our net natural gas production for the year ended June 30, 2010 was approximately 58.6 Mmcfd, up from approximately 56.3 Mmcfd for the year ended June 30, 2009. Net oil production and NGL production remained relatively stable for the comparable periods. Net oil production remained flat at approximately 1,400 bopd for both periods, while NGL production went from approximately 68,000 gallons per day to approximately 68,800 gallons per day. This increase in natural gas production was principally attributable to our Eloise North well which began producing in December 2008 and our Dutch #4 well which began producing in January 2009. The increase in production was also attributable to our Dutch #1, #2 and #3 wells which were shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike. This increase in production was partially offset by our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in 2010.
For the year ended June 30, 2010, the price of natural gas was $4.47 per Mcf while the price for oil and NGLs was $77.18 per barrel and $1.04 per gallon, respectively. For the year ended June 30, 2009, the price of natural gas was $6.34 per Mcf while the price for oil and NGLs was $67.72 per barrel and $1.03 per gallon, respectively.
Our net natural gas production for the year ended June 30, 2009 was approximately 56.3 Mmcfd, up from approximately 24.8 Mmcfd for the year ended June 30, 2008. Net oil production for the period was up from approximately 500 bopd to 1,400 bopd, and NGL production was up from approximately 13,600 gallons per day to 68,000 gallons per day for the same period. The increase in natural gas, oil and NGL production was principally attributable to a full year of production from our Mary Rose #4 discovery which began producing in July 2008, our Eloise North discovery which began producing in December 2008, and our Dutch #4 discovery which began producing in January 2009. This increase was partially offset by reduced production from our Dutch #1 - #3 wells which were shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike. The increase in production was also attributable to the additional interest we purchased in our Dutch and Mary Rose discoveries, effective January 1, 2008.
For the year ended June 30, 2009, the price of natural gas was $6.34 per Mcf while the price for oil and NGLs was $67.72 per barrel and $1.03 per gallon, respectively. For the year ended June 30, 2008, the price of natural gas was $9.77 per Mcf while the price for oil and NGLs was $108.36 per barrel and $1.55 per gallon, respectively.
Operating Expenses. Operating expenses for the year ended June 30, 2010 were approximately $17.0 million, which included approximately $5.3 million of Louisiana state severance taxes and $0.7 million in workover costs. The remaining $11.0 million related mainly to continuing operations from nine wells, compared to operating expenses for the year ended June 30, 2009 of approximately $23.7 million which included approximately $3.7 million in Louisiana severance taxes and $10.7 million for workover costs. The remaining $9.3 million related mainly to continuing operations from seven wells, plus an additional two wells that were only producing for a portion of the year. Operating expenses for the year ended June 30, 2008 were approximately $6.8 million which related to continuing operations from only six wells.
Exploration Expense. We reported approximately $21.9 million of exploration expenses for the year ended June 30, 2010. Of this amount, approximately $14.9 million related to the dry hole the Company drilled at Matagorda Island 617, $5.3 million related to the dry hole the Company drilled at Vermillion 155, and the remaining $1.7 million related to various geological and geophysical activities, seismic data and delay rentals.
We reported approximately $20.6 million of exploration expenses for the year ended June 30, 2009. Of this amount, approximately $7.1 million related to the dry hole the Company drilled at West Delta 77, $12.5 million related to the dry hole the Company drilled at Eugene Island 56, and the remaining $1.0 million related to various geological and geophysical activities, seismic data and delay rentals.
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We reported approximately $5.7 million of exploration expenses for the year ended June 30, 2008. Of this amount, approximately $4.2 million was related to the dry hole the Company drilled at High Island A198, approximately $0.6 million was attributable to the cost to acquire and reprocess 3-D seismic data offshore in the Gulf of Mexico, and approximately $0.9 million was attributable to the payment of delay rentals.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the year ended June 30, 2010 was approximately $35.4 million. For the year ended June 30, 2009, we recorded approximately $32.7 million of depreciation, depletion and amortization. The increase in depreciation, depletion and amortization was primarily attributable to an overall increase in production from our Eloise North and Dutch #4 wells, an increase in production from our Dutch #1, #2 and #3 wells which were shut-in during three months in fiscal year 2009 due to Hurricane Ike, and an increase in reserves due to new discoveries. This increase in production was partially offset by our ruptured 20” pipeline which shut-in production from our Mary Rose wells, Dutch #4 and Eloise North wells for approximately 35 days in fiscal year 2010, as well as by a downward revision of our reserves in June 2010.
Depreciation, depletion and amortization for the year ended June 30, 2009 was approximately $32.7 million. For the year ended June 30, 2008, we recorded approximately $11.9 million of depreciation, depletion and amortization. The increase in depreciation, depletion and amortization was primarily attributable to added production from newly added reserves from our Mary Rose #4, Eloise North and Dutch #4 discoveries, as well as from the additional interest we purchased in our Dutch and Mary Rose discoveries, effective January 1, 2008.
Lease Expiration and Relinquishment Expense. For the year ended June 30, 2010, the Company recorded lease expiration and relinquishment expense of approximately $0.9 million, related to the relinquishment of six lease blocks owned by REX and COE. For the year ended June 30, 2009, the Company recorded lease expiration and relinquishment expense of approximately $5.2 million due to the expiration and relinquishment of 44 lease blocks owned by REX and COE. For the year ended June 30, 2008, the Company recorded lease expiration and relinquishment expense of approximately $0.6 million related to the expiration of Eugene Island 209 and Viosca Knoll 161, two leases held by COE.
Impairment of Natural Gas and Oil Properties. The Company did not report an impairment charge for the year ended June 30, 2010 or 2008. For the year ended June 30, 2009, the Company recorded impairment expense of approximately $5.9 million. Of this amount, approximately $2.5 million related to the impairment of Grand Isle 70 and $3.4 million related to the impairment of Grand Isle 72, as a result of the expected future undiscounted net cash flows of these wells being lower than the unamortized capitalized cost.
General and Administrative Expenses. General and administrative expenses for the year ended June 30, 2010 were approximately $4.6 million, down from approximately $9.5 million for the year ended June 30, 2009. The decrease is principally attributable to lower bonus payments and stock and stock option expenses in the year ended June 30, 2010. Major components of general and administrative expenses for the year ended June 30, 2010 included approximately $3.0 million in salaries, benefits and board compensation (includes $0.7 million in non-cash expenses related to restricted stock and option awards), $0.5 million in office administration and other expenses, $0.5 million in insurance costs, $0.2 million in accounting and tax services, and $0.4 million in legal, consulting and other administrative expenses.
General and administrative expenses for the year ended June 30, 2009 were approximately $9.5 million, down from $16.9 million for the year ended June 30, 2008. The decrease is principally attributable to higher bonus payments in fiscal year 2008. Major components of general and administrative expenses for the year ended June 30, 2009 included approximately $5.3 million in salaries, benefits and bonuses (includes $1.4 million in non-cash expenses related to restricted stock and option awards), $1.7 million in office administration and other expenses, $0.5 million in insurance costs, $0.7 million in accounting and tax services, and $1.3 million in legal and other administrative expenses.
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General and administrative expenses for the year ended June 30, 2008 were approximately $16.9 million. Major components of general and administrative expenses for the year ended June 30, 2008 included approximately $1.0 million in salaries, $12.1 million in benefits and bonuses (includes $1.5 million in non-cash expenses to restricted stock and option awards), $1.1 million in office administration and other expenses, $0.4 million in insurance costs, $0.9 million in accounting and tax services, and $1.4 million in legal and other administrative expenses.
Interest Expense. Interest expense for the fiscal years ended June 30, 2010, 2009 and 2008 were approximately $0.5 million, $0.7 million, and $3.9 million, respectively. The lower levels of interest expense for the fiscal years ended 2010 and 2009 relate mainly to the Company’s portion of COE’s interest expense on the Note as a result of our proportionate consolidation of COE. The higher level of interest expense for the fiscal year ended 2008 was attributable to bank debt outstanding during the period. The Company retired all of its long term debt during the fiscal year ended 2009.
Interest Income. Interest income for the fiscal years ended June 30, 2010, 2009 and 2008 were approximately $0.9 million, $0.9 million, and $1.9 million, respectively. The higher level of interest income for fiscal year 2008 was attributable to loans made to related parties and interest earned on the proceeds from our various property sales.
Gain on Sale of Assets and Other. For the year ended June 30, 2010, we reported a gain on sale of assets and other of approximately $0.1 million related to the sale of our Grand Isle 70 well. For the year ended June 30, 2009, we reported a loss on sale of assets and other of approximately $0.5 million related to a post-closing adjustment for the sale of our Arkansas Fayetteville Shale properties.
For the year ended June 30, 2008, we reported a gain on sale of assets and other of approximately $62.3 million. Of this amount, approximately $63.4 million relates to the gain on the sale of the Company’s 10% limited partnership interest in Freeport LNG, $2.1 million relates to a payment from a stockholder related to a short swing profit liability, $0.3 million relates to the gain on the sale of certain overriding royalty interests and onshore properties, offset by a $2.9 million loss recognized on the sale of certain assets held by CVCC and a $0.6 million loss attributable to the write-down of the Company’s investment in Moblize.
Discontinued Operations. The Company did not have any discontinued operations for the year ended June 30, 2010 or 2009. The table and discussions above, along with our financial statements, discuss only continuing operations for all fiscal years presented. Not reflected are the Company’s sold producing properties which generated 7.7% of combined revenues for the fiscal year ended June 30, 2008. Please see Note 6 – Sale of Properties – Discontinued Operations of Notes to Consolidated Financial Statements included as part of this Form 10-K, for a discussion of our discontinued operations.
Capital Resources and Liquidity
Cash From Operating Activities. Cash flow from operating activities provided approximately $128.2 million in cash for the year ended June 30, 2010 compared to $95.4 million for the same period in 2009. This increase in cash provided by operating activities was primarily attributable to increased natural gas, oil and NGL production attributable to our Eloise North and Dutch #4 well. The increase in production was also attributable to our Dutch #1, #2 and #3 wells which were shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike.
Cash flow from operating activities provided approximately $95.4 million in cash for the year ended June 30, 2009 compared to $112.7 million for the same period in 2008. This decrease in net cash provided by operating activities was primarily attributable to lower sales as a result of lower natural gas and oil prices during 2009, partially offset by increased production from our Mary Rose #4, Eloise North and Dutch #4 discoveries which began producing during the year ended June 30, 2009.
Cash From Investing Activities. Cash flows used in investing activities for the year ended June 30, 2010 were approximately $97.7 million, compared to $45.8 million used in investing activities for the year ended June 30, 2009. The higher level of cash flows used in investing activities in 2010 was primarily attributable to increased capital expenditures for drilling exploration and development wells.
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Cash flows used in investing activities for the year ended June 30, 2009 were approximately $45.8 million, compared to $38.9 million used in investing activities for the year ended June 30, 2008. The lower level of cash flows used in investing activities in 2008 was due primarily to the proceeds received from the sale of certain assets.
Cash From Financing Activities. Cash flows used in financing activities for the year ended June 30, 2010 were approximately $22.4 million, compared to $65.1 million used in financing activities for the same period in 2009. This $65.1 million of cash flows used in financing activities for the year ended June 30, 2009 is primarily composed of purchasing approximately $51.8 million of our common stock and the repayment of $15.0 million of debt. There were no credit facility payments and fewer purchases of common stock during the year ended June 30, 2010.
Cash flows used in financing activities for the year ended June 30, 2009 were approximately $65.1 million, compared to $20.2 million used in financing activities for the same period in 2008. This $65.1 million of cash flows used in financing activities for the year ended June 30, 2009 is primarily composed of purchasing approximately $51.8 million of our common stock and the repayment of $15.0 million of debt.
Income Taxes. During the year ended June 30, 2010, 2009 and 2008, we paid approximately $11.5 million, $45.6 million and $22.0 million, respectively, in estimated income taxes.
Capital Budget. For the remainder of fiscal year 2011, our capital expenditure budget calls for us to invest approximately $85 million from cash flow from operations and cash on hand as follows:
| • | We plan to invest approximately $60 million to drill up to four wildcat exploration wells in the Gulf of Mexico, at an estimated dry hole cost of approximately $15 million each, net to Contango. |
| • | We plan to invest approximately $22.5 million to drill and complete 15 additional on-shore wells in Panola County, Texas under our joint venture with Patara Oil & Gas LLC. |
The Company often reviews acquisitions and prospects presented to us by third parties and may decide to invest in one or more of these opportunities. There can be no assurance that we will invest, or that any investment entered into will be successful. These potential investments are not part of our current capital budget and would require us to invest additional capital. Natural gas and oil prices continue to be volatile and our resources may be insufficient to fund any of these opportunities. As of August 31, 2010, we had approximately $45.5 million in cash and cash equivalents and no debt outstanding.
Discontinued Operations. The Company, since its inception in September 1999, has raised approximately $484.0 million in proceeds from twelve separate property sales, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, in addition to being a source of funds for potentially higher rate of return natural gas and oil exploration investments. We believe these periodic natural gas and oil property sales are an efficient strategy to meet our cash and liquidity needs by providing us with immediate cash, which would otherwise take years to realize through the production lives of the fields sold. We have in the past and expect to in the future to continue to rely heavily on the sales of assets to generate cash to fund our exploration investments and operations.
These sales bring forward future revenues and cash flows, but our longer term liquidity could be impaired to the extent our exploration efforts are not successful in generating new discoveries, production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of these property sales the Company’s ability to collateralize bank borrowings is reduced which increases our dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.
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We had no discontinued operations for the fiscal year ended June 30, 2010 or 2009. The table below sets forth the proceeds received from natural gas and oil property sales for the year ended June 30, 2008, the impact of these sales on our developed reserve quantities, and a measure of our developed reserves held at the end of each such fiscal year. Please see the reserve activity reported in the Supplemental Oil and Gas Disclosures on pages F-23 through F-26 for a more detailed discussion regarding our standardized measure.
| Fiscal Year of Property Sale |
Proceeds Received |
Reserves Sold (Mmcfe) |
Reserves at end of Fiscal Year (Mmcfe) |
Standardized Measure
of Discounted Future Net Cash Flows at end of Fiscal Year | ||||||
| 2008 |
$ | 328,300,000 | 13,789 | 369,076 | $ | 2,233,918,129 | ||||
For fiscal year 2008, the Company realized approximately $8.1 million in operating cash flows from discontinued operations, approximately $319.0 million in investing cash flows from discontinued operations and zero in financing cash flows from discontinued operations.
Off Balance Sheet Arrangements
None.
The following table summarizes our known contractual obligations as of June 30, 2010:
| Payment due by period | |||||||||||||||
| Total | Less than 1 year |
1-3 years | 3-5 years | More than 5 years | |||||||||||
| Long term debt |
$ | — | $ | — | $ | — | $ | — | $ | — | |||||
| Delay rentals |
$ | 1,944,240 | $ | 542,838 | $ | 999,792 | $ | 401,610 | $ | — | |||||
| Asset retirement obligations |
$ | 5,156,642 | $ | — | $ | — | $ | — | $ | 5,156,642 | |||||
| Operating leases |
$ | 291,438 | $ | 198,114 | $ | 83,550 | 9,774 | — | |||||||
| Total |
$ | 7,392,320 | $ | 740,952 | $ | 1,083,342 | $ | 411,384 | $ | 5,156,642 | |||||
In September 2008, the Company’s board of directors approved a $100 million share repurchase program. Under the program, all shares are purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases will be made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. Repurchased shares of common stock become authorized but unissued shares, and may be issued in the future for general corporate and other purposes. As of August 31, 2010, we have purchased approximately 1.7 million shares of our common stock at an average cost per share of $43.88, for a total expenditure of approximately $75 million. As at August 31, 2010, we have 15,664,666 shares of common stock outstanding and 15,970,000 fully diluted shares.
On October 3, 2008, the Company and its wholly owned subsidiaries completed the arrangement of a $50 million Hydrocarbon Borrowing Base secured revolving credit facility pursuant to a credit agreement with BBVA Compass Bank (successor in interest to Guaranty Bank, as administrative agent and issuing lender) (the “Compass Agreement”). The credit facility is secured by substantially all of the Company’s assets and is available to fund the Company’s exploration and development activities, as well as the repurchase of shares of the Company’s common stock, the payment of dividends, and working capital as needed. Borrowings under the Compass Agreement bear interest at LIBOR plus 2.0% per annum and are due October 3, 2010. An arrangement fee of 0.5%, or $250,000, was
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paid in connection with the facility and a commitment fee of 0.5% is paid on the unused commitment amount. As of August 31, 2010 the Company was in compliance with all financial covenants, ratios and other provisions of the Compass Agreement. No amounts have been drawn on the credit facility.
On August 24, 2010, the Company signed a commitment letter with Amegy Bank National Association (“Amegy”) to arrange for a four-year $40 million hydrocarbon borrowing base senior revolving credit facility (the “Amegy Agreement”) to replace the expiring Compass Agreement. Under the terms and conditions of the term sheet with Amegy, the facility will be secured by substantially all of the Company’s assets and will be available to fund the Company’s exploration and development activities, as well as the repurchase of shares of the Company’s common stock, the payment of dividends, and working capital as needed. Borrowings under the Amegy Agreement will bear interest at LIBOR plus 2.5% per annum. An arrangement fee of 0.75%, or $300,000, will be paid in connection with the facility and a commitment fee of 0.375% will be paid on the unused commitment amount. The Amegy Agreement will contain customary covenants including limitations on additional indebtedness.
In August 2008, the Company prepaid in full the $15.0 million it had outstanding under its $30.0 million loan agreement with a private investment firm (the “Term Loan Agreement”) and terminated the Term Loan Agreement. In February 2008, using the proceeds from our $68.0 million sale of Freeport LNG, the Company prepaid in full the $20.0 million it had outstanding under its three-year $20.0 million secured term loan facility with The Royal Bank of Scotland plc (the “RBS Facility”) and terminated the RBS Facility.
Application of Critical Accounting Policies and Management’s Estimates
The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company’s significant accounting policies are described in Note 2 of Notes to Consolidated Financial Statements included as part of this Form 10-K. We have identified below the policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. The Company analyzes its estimates, including those related to natural gas and oil reserve estimates, on a periodic basis and bases its estimates on historical experience, independent third party reservoir engineers and various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of the Company’s consolidated financial statements:
Successful Efforts Method of Accounting. Our application of the successful efforts method of accounting for our natural gas and oil business activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
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Reserve Estimates. While we are reasonably certain of recovering our reported reserves, the Company’s estimates of natural gas and oil reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s natural gas and oil properties and/or the rate of depletion of such natural gas and oil properties. In June 2010, the Company revised its offshore reserves downward by approximately 48.5 Bcfe. This revision was attributable to newly obtained bottom hole pressure data as a result of a recent field wide shut-in and a “P/Z pressure test” that indicated fewer reserves than was originally estimated.
Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material. Holding all other factors constant, a reduction in the Company’s proved reserve estimate at June 30, 2010 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $1.6 million, $3.6 million, and $5.8 million, respectively.
Impairment of Natural Gas and Oil Properties. The Company reviews its proved natural gas and oil properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company compares expected undiscounted future net cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Given the complexities associated with natural gas and oil reserve estimates and the history of price volatility in the natural gas and oil markets, events may arise that will require the Company to record an impairment of its natural gas and oil properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.
Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consists of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statements and income tax reporting. Numerous judgments and assumptions are inherent in the determination of deferred income tax assets and liabilities as well as income taxes payable in the current period. We are subject to taxation in several jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions.
Recent Accounting Pronouncements
In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance for the fiscal year ended June 30, 2010.
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In January 2010, the FASB adopted the SEC’s Modernization of Oil & Gas Reporting: Final Rule requirements to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:
| • | Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless contractual arrangements designate the price to be used. |
| • | Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered. |
| • | Reserve Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees our reserves estimation process. We will also be required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate. |
The Company adopted the new rules effective June 30, 2010, and as a result, it (i) prepared its reserve estimates as of June 30, 2010 based on the new reserves definitions, (ii) has estimated its June 30, 2010 reserve quantities using the 12-month average price and (iii) included additional disclosures as required by the new rule. As a result of the change in reserve pricing from year-end oil and gas prices to now using the 12-month average prices, the Company’s total proved reserves at June 30, 2010 were 3.8 Bcfe higher than they would have otherwise been if year-end oil and gas prices were used. Oil and gas reserve quantities or their values are a significant component of the Company’s depreciation, depletion and amortization (“DD&A”), asset retirement obligation, and impairment analysis. The Company’s adoption of the SEC’s Modernization of Oil and Gas Reporting: Final Rule had an immaterial impact on the Company’s DD&A expense, asset retirement obligation, and impairment analysis.
Effective July 1, 2009, the Company adopted new accounting guidance on fair value measurements which require additional disclosures about the Company’s nonfinancial assets and liabilities, which adoption had no impact on the Company’s financial position, results of operations or cash flows.
In June 2009, the FASB issued new accounting guidance on the FASB Accounting Standards Codification and the hierarchy of GAAP. This new accounting guidance codifies existing GAAP and recognizes only two levels of GAAP, authoritative and nonauthoritative. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This new accounting guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.
| Item 7A. | Quantitative and Qualitative Disclosure about Market Risk |
Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas and oil production. Realized commodity prices received for our production are tied to the spot prices applicable to natural gas and crude oil at the applicable delivery points. Prices received for natural gas and oil are volatile and unpredictable. We do not hedge against price risk exposure. For the year ended June 30, 2010, a 10% fluctuation in the prices received for natural gas and oil production would have had an approximate $16.0 million impact on our revenues.
Interest Rate Risk. As of August 31, 2010, we have no long-term debt subject to the risk of loss associated with movements in interest rates.
| Item 8. | Financial Statements and Supplementary Data |
The financial statements and supplemental information required to be filed under Item 8 of Form 10-K are presented on pages F-1 through F-27 of this Form 10-K.
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| 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
An evaluation was performed under the supervision and with the participation of the Company’s senior management of the effectiveness of the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of June 30, 2010, the end of the period covered by this report. Based on that evaluation, the Company’s management, including the Chairman and Chief Executive Officer, Chief Financial Officer, and Controller, concluded that the Company’s disclosure controls and procedures were effective as of such date to ensure that information required to be disclosed in the reports that the Company files under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to the Company’s management, including the Chairman, Chief Executive Officer, Chief Financial Officer and Controller, as appropriate, to allow timely decisions regarding required disclosures.
Management’s Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of the Company’s management, including the Chairman, Chief Executive Officer, Chief Financial Officer and Controller, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Company’s evaluation under the framework in Internal Control—Integrated Framework, the Company’s management concluded that its internal control over financial reporting was effective as of June 30, 2010.
Grant Thornton LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has audited the effectiveness of our internal control over financial reporting as of June 30, 2010, as stated in their report which is included herein.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Contango Oil & Gas Company
We have audited Contango Oil & Gas Company (a Delaware corporation) and subsidiaries’ internal control over financial reporting as of June 30, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Contango Oil & Gas Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s report on internal control over financial reporting. Our responsibility is to express an opinion on Contango Oil & Gas Company’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of 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.
In our opinion, Contango Oil & Gas Company and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of June 30, 2010, based on criteria established in Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Contango Oil & Gas Company and subsidiaries as of June 30, 2010 and 2009, and the related consolidated statements of operations, shareholders' equity, and cash flows for each of the three years in the period ended June 30, 2010 and our report dated September 13, 2010 expressed an unqualified opinion on those financial statements.
| /s/ GRANT THORNTON LLP |
| Houston, Texas |
| September 13, 2010 |
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Changes in Internal Control Over Financial Reporting
There was no change in our internal controls over financial reporting during the period covered by this annual report on Form 10-K that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
| Item 9B. | Other Information |
On September 30, 2008, the Company adopted a Stockholder Rights Plan (the “Plan”) that is designed to ensure that all stockholders of Contango receive fair value for their shares of common stock in the event of any proposed takeover of Contango and to guard against the use of partial tender offers or other coercive tactics to gain control of Contango without offering fair value to all of Contango’s stockholders. The Plan is not intended, nor will it operate, to prevent an acquisition of Contango on terms that are favorable and fair to all stockholders.
Under the terms of the Plan, each right (a “Right”) will entitle the holder to buy 1/100 of a share of Series F Junior Preferred Stock of Contango (the “Preferred Stock”) at an exercise price of $200 per share. The Rights will be exercisable and will trade separately from the shares of common stock only if a person or group acquires beneficial ownership of 20% or more of Contango’s common stock or commences a tender or exchange offer that would result in such a person or group owning 20% or more of the common stock (the “Triggering Event”).
Under the terms of the Plan, Rights have been distributed as a dividend at the rate of one Right for each share of common stock held as of the close of business on October 1, 2008. Stockholders will not actually receive certificates for the Rights at this time, but the Rights will become part of each outstanding share of common stock. An additional Right will be issued along with each share of common stock that is issued or sold by Contango after October 1, 2008. The Rights may only be exercised during a three-year period and are scheduled to expire on September 30, 2011. Upon a Triggering Event, Contango stockholders will receive certificates for the Rights.
If any person actually acquires 20% or more of shares of common stock — other than through a tender or exchange offer for all shares of common stock that provides a fair price and other acceptable terms for such shares, as determined by the board of directors of Contango — or if a 20%-or-more stockholder engages in certain “self-dealing” transactions or engages in a merger or other business combination in which Contango survives and its shares of common stock remain outstanding, the other Contango stockholders will be able to exercise the Rights and buy shares of common stock of Contango having approximately twice the value of the exercise price of the Rights. Additionally, if Contango is involved in certain other mergers where its shares are exchanged or certain major sales of its assets occur, Contango stockholders will be able to purchase a certain number of the other party’s common stock in an amount equal to approximately twice the value of the exercise price of the Rights.
Contango will be entitled to redeem the Rights at $0.01 per Right at any time until the earlier of (i) the tenth day following public announcement that a person has acquired a 20% ownership position in shares of common stock of Contango or (ii) the final expiration date of the Rights. Contango in its discretion may extend the period during which it may redeem the Rights.
| Item 10. | Directors, Executive Officers and Corporate Governance |
The information regarding directors, executive officers, promoters and control persons required under Item 10 of Form 10-K will be contained in our Definitive Proxy Statement for our 2010 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings “Election of Directors”, “Executive Compensation”, “Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance” and is incorporated herein by reference. The Proxy Statement will be filed with the SEC pursuant to Regulation 14A of the Exchange Act, not later than 120 days after June 30, 2010.
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| Item 11. | Executive Compensation |
The information required under Item 11 of Form 10-K will be contained in the Proxy Statement under the heading “Executive Compensation” and is incorporated herein by reference.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information required under Item 12 of Form 10-K will be contained in the Proxy Statement under the heading “Security Ownership of Certain Other Beneficial Owners and Management” and is incorporated herein by reference.
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
The information required under Item 13 of Form 10-K will be contained in the Proxy Statement under the heading “Certain Relationships and Related Transactions, and Director Independence” and “Executive Compensation” and is incorporated herein by reference.
| Item 14. | Principal Accountant Fees and Services |
The information required under Item 14 of Form 10-K will be contained in the Proxy Statement under the heading “Principal Accountant Fees and Services” and is incorporated herein by reference.
| Item 15. | Exhibits and Financial Statement Schedules |
(a) Financial Statements and Schedules:
The financial statements are set forth in pages F-1 to F-22 of this Form 10-K. Financial statement schedules have been omitted since they are either not required, not applicable, or the information is otherwise included.
(b) Exhibits:
The following is a list of exhibits filed as part of this Form 10-K. Where so indicated by a footnote, exhibits, which were previously filed, are incorporated herein by reference.
| Exhibit |
Description | |
| 2.1 | Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and REX Offshore Corporation, dated as of September 1, 2005. (11) | |
| 2.2 | Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and COE Offshore, LLC dated as of September 1, 2005. (11) | |
| 2.3 | Asset Purchase Agreement by and among Petrohawk Energy Corporation and Contango Operators Inc. (successor-in-interest to Contango Gas Solutions, L.P.), Alta Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and Tepee Petroleum Company, Inc., dated as of November 26, 2007. (17) | |
| 2.4 | Asset Purchase Agreement by and among XTO Energy Inc. and Contango Operators, Inc., Alta Resources, L.L.C., GPM Energy, LLC, MND Partners, L.P. and Tepee Petroleum Company, Inc., dated as of January 4, 2008. (18) | |
| 2.5 | Partnership Interest Purchase Agreement by and among Turbo LNG LLC, Contango Sundance, Inc. and Osaka Gas Co., Ltd., as Guarantor, dated January 7, 2008. (19) | |
| 3.1 | Certificate of Incorporation of Contango Oil & Gas Company. (5) | |
| 3.2 | Bylaws of Contango Oil & Gas Company. (5) | |
| 3.3 | Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (5) | |
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Index to Financial Statements
| 3.4 | Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (8) | |
| 4.1 | Facsimile of common stock certificate of Contango Oil & Gas Company. (1) | |
| 4.2 | Certificate of Designations, Preferences and Relative Rights and Limitations for Series E Perpetual Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (14) | |
| 4.3 | Securities Purchase Agreement, dated as of May 11, 2007, among Contango Oil & Gas Company and the Purchasers Named Therein, relating to the Series E Perpetual Cumulative Convertible Preferred Stock. (14) | |
| 4.4 | Certificate of Designation of Series F Junior Preferred Stock of Contango Oil & Gas Company dated September 30, 2008. (25) | |
| 4.5 | Rights Agreement, dated as of September 30, 2008, between Contango Oil & Gas Company and Computershare Trust Company, N.A., as Rights Agent. (25) | |
| 10.1 | Agreement, dated effective as of September 1, 1999, between Contango Oil & Gas Company and Juneau Exploration, L.L.C. (2) | |
| 10.2 | Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Trust Company of the West. (3) | |
| 10.3 | Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Fairfield Industries Incorporated. (3) | |
| 10.4 | Securities Purchase Agreement dated August 24, 2000 by and between Contango Oil & Gas Company and Juneau Exploration Company, L.L.C. (3) | |
| 10.5 | Amendment dated August 14, 2000 to agreement between Contango Oil & Gas Company and Juneau Exploration Company, LLC. dated effective as of September 1, 1999. (4) | |
| 10.6 | Asset Purchase Agreement by and among Juneau Exploration, L.P. and Contango Oil & Gas Company dated January 4, 2002. (6) | |
| 10.7 | Asset Purchase Agreement by and among Mark A. Stephens, John Miller, The Hunter Revocable Trust, Linda G. Ferszt, Scott Archer and the Archer Revocable Trust and Contango Oil & Gas Company dated January 9, 2002. (7) | |
| 10.8 | Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (10) | |
| 10.9 | Partnership Purchase Agreement among Contango Sundance, Inc., Contango Oil & Gas, Cheniere LNG, Inc. and Cheniere Energy, Inc. dated March 1, 2003. (10) | |
| 10.10 | First Amendment, dated December 19, 2003, to Freeport LNG Development, L.P. Amended and Restated Limited Partnership Agreement dated February 27, 2003. (10) | |
| 10.11 | Limited Liability Company Agreement of Republic Exploration LLC dated August 24, 2000. (11) | |
| 10.12 | Amendment to Limited Liability Company Agreement and Additional Agreements of Republic Exploration LLC dated as of September 1, 2005. (11) | |
| 10.13 | Limited Liability Company Agreement of Contango Offshore Exploration LLC dated November 1, 2000. (11) | |
| 10.14 | First Amendment to Limited Liability Company Agreement and Additional Agreements of Contango Offshore Exploration LLC dated as of September 1, 2005. (11) | |
| 10.15* | Contango Oil & Gas Company 1999 Stock Incentive Plan. (12) | |
| 10.16* | Amendment No. 1 to Contango Oil & Gas Company 1999 Stock Incentive Plan dated as of March 1, 2001. (12) | |
| 10.17 | Term Loan Agreement between Contango Oil & Gas Company and The Royal Bank of Scotland plc, dated April 27, 2006. (13) | |
| 10.18 | Demand Promissory Note dated October 26, 2006 with Schedules I, II and III. (15) | |
| 10.19 | Term Loan Agreement between Contango Oil & Gas Company and Centaurus Capital LLC, dated January 30, 2007. (16) | |
| 10.20 | Form of Pledge Agreement. (16) | |
| 10.21 | Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (20) | |
| 10.22 | Partial Assignment of Oil and Gas Leases between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (20) | |
| 10.23 | Assignment of Operating Rights Interest between CGM, LP and Contango Operators, Inc., dated as of January 3, 2008. (20) | |
| 10.24 | Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008. (20) | |
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| 10.25 | Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of January 3, 2008. (20) | |
| 10.26 | Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of January 3, 2008. (20) | |
| 10.27 | Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (20) | |
| 10.28 | Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (20) | |
| 10.29 | Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of January 3, 2008. (20) | |
| 10.30 | Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (22) | |
| 10.31 | Partial Assignment of Oil and Gas Leases between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (22) | |
| 10.32 | Assignment of Operating Rights Interest between Juneau Exploration, LP and Contango Operators, Inc., dated as of April 3, 2008. (22) | |
| 10.33 | Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008. (22) | |
| 10.34 | Partial Assignment of Oil and Gas Leases between Olympic Energy Partners, LLC and Contango Operators, Inc. dated as of April 3, 2008. (22) | |
| 10.35 | Assignment of Operating Rights Interest between Olympic Energy Partners, LLC and Contango Operators, Inc., dated as of April 3, 2008. (22) | |
| 10.36 | Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (24) | |
| 10.37 | Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (24) | |
| 10.38 | Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (24) | |
| 10.39 | Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (24) | |
| 10.40 | Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (24) | |
| 10.41 | Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (24) | |
| 10.42 | Assignment of Overriding Royalty Interest between Dutch Royalty Investments, Land and Leasing, LP and Contango Operators, Inc., dated as of February 8, 2008. (24) | |
| 10.43 | Amended and Restated Limited Liability Company Agreement of Republic Exploration LLC, dated April 1, 2008. (22) | |
| 10.44 | Amended and Restated Limited Liability Company Agreement of Contango Offshore Exploration LLC, dated April 1, 2008. (24) | |
| 10.45 | Third Amendment to Term Loan Agreement, dated as of January 17, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. (21) | |
| 10.46 | Fourth Amendment to Term Loan Agreement, dated as of February 13, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. (23) | |
| 10.47 | Amended and Restated Term Loan Agreement, dated June 5, 2008, between Contango Oil & Gas Company, as Borrower, and Centaurus Capital LLC, as Lender. (24) | |
| 10.48 | $50,000,000 Amended and Restated Credit Agreement dated as of March 31, 2009 among Contango Oil & Gas Company, Contango Energy Company and Contango Operators Inc. as Borrowers, Guaranty Bank, as administrative agent and issuing lender, and the lenders party thereto from time to time. (26) | |
| 10.49* | Contango Oil & Gas Company Annual Incentive Plan. † | |
| 10.50* | Contango Oil & Gas Company 2009 Equity Compensation Plan. † | |
| 10.51 | Conterra Joint Venture Development Agreement effective October 1, 2009 between Conterra Company and Patara Oil & Gas LLC. (27) | |
| 14.1 | Code of Ethics. (12) | |
| 21.1 | List of Subsidiaries. † | |
47
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Index to Financial Statements
| 21.2 | Organizational Chart. † | |
| 23.1 | Consent of William M. Cobb & Associates, Inc. † | |
| 23.2 | Consent of Grant Thornton LLP. † | |
| 23.3 | Consent of Lonquist & Co. LLC. † | |
| 31.1 | Certification of Chief Executive Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. † | |
| 31.2 | Certification of Chief Financial Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. † | |
| 32.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. † | |
| 32.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. † | |
| 99.1 | Report of William M. Cobb & Associates, Inc. † | |
| 99.2 | Report of Lonquist & Co. LLC. † | |
| † | Filed herewith. |
| * | Indicates a management contract or compensatory plan or arrangement. |
| 1. | Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998. |
| 2. | Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 1999, as filed with the Securities and Exchange Commission on November 11, 1999. |
| 3. | Filed as an exhibit to the Company’s report on Form 8-K, dated August 24, 2000, as filed with the Securities and Exchange Commission of September 8, 2000. |
| 4. | Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2000, as filed with the Securities and Exchange Commission on September 27, 2000. |
| 5. | Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000. |
| 6. | Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2002, as filed with the Securities and Exchange Commission on January 8, 2002. |
| 7. | Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended March 31, 2002, as filed with the Securities and Exchange Commission on February 14, 2002. |
| 8. | Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission. |
| 9. | Filed as an exhibit to the Company’s annual report on Form 10-KSB for the fiscal year ended June 30, 2003, as filed with the Securities and Exchange Commission on September 22, 2003. |
| 10. | Filed as an exhibit to the Company’s report on Form 8-K, dated December 19, 2003, as filed with the Securities and Exchange Commission on December 23, 2003. |
| 11. | Filed as an exhibit to the Company’s report on Form 8-K, dated September 2, 2005, as filed with the Securities and Exchange Commission on September 8, 2005. |
| 12. | Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2005, as filed with the Securities and Exchange Commission on September 13, 2005. |
| 13. | Filed as Exhibit 10.1 to the Company’s report on Form 10-Q for the quarter ended March 31, 2006, dated May 15, 2006, as filed with the Securities and Exchange Commission. |
| 14. | Filed as an exhibit to the Company’s report on Form 8-K, dated May 11, 2007, as filed with the Securities and Exchange Commission on May 17, 2007. |
| 15. | Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2006, dated November 8, 2006, as filed with the Securities and Exchange Commission. |
| 16. | Filed as an exhibit to the Company’s report on Form 8-K, dated January 30, 2007, as filed with the Securities and Exchange Commission on February 5, 2007. |
| 17. | Filed as an exhibit to the Company’s report on Form 8-K, dated November 26, 2007, as filed with the Securities and Exchange Commission on November 29, 2007. |
| 18. | Filed as an exhibit to the Company’s report on Form 8-K, dated January 4, 2008, as filed with the Securities and Exchange Commission on January 10, 2008. |
| 19. | Filed as an exhibit to the Company’s report on Form 8-K, dated February 5, 2008, as filed with the Securities and Exchange Commission on February 8, 2008. |
| 20. | Filed as an exhibit to the Company’s report on Form 8-K, dated January 3, 2008, as filed with the Securities and Exchange Commission on January 9, 2008. |
| 21. | Filed as an exhibit to the Company’s report on Form 8-K, dated January 17, 2008, as filed with the Securities and Exchange Commission on January 24, 2008. |
| 22. | Filed as an exhibit to the Company’s report on Form 8-K, dated April 3, 2008, as filed with the Securities and Exchange Commission on April 9, 2008. |
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Index to Financial Statements
| 23. | Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2008, as filed with the Securities and Exchange Commission on May 12, 2008. |
| 24. | Filed as an exhibit to the Company’s report on Form 10-K for the fiscal year ended June 30, 2008, as filed with the Securities and Exchange Commission on August 29, 2008. |
| 25. | Filed as an exhibit to the Company’s report on Form 8-K, dated September 30, 2008, as filed with the Securities and Exchange Commission on October 1, 2008. |
| 26. | Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended March 31, 2009, as filed with the Securities and Exchange Commission on May 11, 2009. |
| 27. | Filed as an exhibit to the Company’s report on Form 8-K, dated October 22, 2009, as filed with the Securities and Exchange Commission on October 28, 2009. |
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CONTANGO OIL & GAS COMPANY
| /S/ KENNETH R. PEAK |
/S/ SERGIO CASTRO |
/S/ YAROSLAVA MAKALSKAYA | ||
| Kenneth R. Peak | Sergio Castro | Yaroslava Makalskaya | ||
| Chief Executive Officer | Chief Financial Officer | Vice President and Controller | ||
| (principal executive officer) | (principal financial officer) | (principal accounting officer) |
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Name |
Title |
Date | ||
| /S/ KENNETH R. PEAK |
Chairman of the Board | September 13, 2010 | ||
| Kenneth R. Peak | ||||
| /S/ B.A. BERILGEN |
Director | September 13, 2010 | ||
| B.A. Berilgen | ||||
| /S/ JAY D. BREHMER |
Director | September 13, 2010 | ||
| Jay D. Brehmer | ||||
| /S/ CHARLES M. REIMER |
Director | September 13, 2010 | ||
| Charles M. Reimer | ||||
| /S/ STEVEN L. SCHOONOVER |
Director | September 13, 2010 | ||
| Steven L. Schoonover | ||||
49
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
F-1
Table of Contents
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Shareholders
Contango Oil & Gas Company
We have audited the accompanying consolidated balance sheets of Contango Oil & Gas Company (a Delaware corporation) and subsidiaries as of June 30, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended June 30, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 financial statements referred to above present fairly, in all material respects, the financial position of Contango Oil & Gas Company and subsidiaries as of June 30, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2010 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Contango Oil & Gas Company and subsidiaries’ internal control over financial reporting as of June 30, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 13, 2010 expressed an unqualified opinion on the internal control over financial reporting.
As discussed in Note 2 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil & gas reserve estimation and disclosure requirements as of June 30, 2010.
| /s/ GRANT THORNTON LLP |
| Houston, Texas |
| September 13, 2010 |
F-2
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| ASSETS
|
| |||||||
| June 30, | ||||||||
| 2010 | 2009 | |||||||
| CURRENT ASSETS: |
||||||||
| Cash and cash equivalents |
$ | 52,469,144 | $ | 44,371,324 | ||||
| Accounts receivable: |
||||||||
| Trade receivable |
41,938,567 | 32,809,165 | ||||||
| Advances to affiliates |
— | 5,494,747 | ||||||
| Joint interest billings |
11,758,980 | 4,515,660 | ||||||
| Severance taxes receivable |
— | 3,528,402 | ||||||
| Income taxes |
5,410,577 | 4,221,644 | ||||||
| Other receivable |
3,164,604 | 824,197 | ||||||
| Notes receivable |
2,027,590 | — | ||||||
| Other |
3,103,927 | 710,333 | ||||||
| Total current assets |
119,873,389 | 96,475,472 | ||||||
| PROPERTY, PLANT AND EQUIPMENT: |
||||||||
| Natural gas and oil properties, successful efforts method of accounting: |
||||||||
| Proved properties |
540,215,841 | 460,881,471 | ||||||
| Unproved properties |
10,825,074 | 2,911,258 | ||||||
| Furniture and equipment |
276,817 | 273,185 | ||||||
| Accumulated depreciation, depletion and amortization |
(78,998,049 | ) | (44,952,301 | ) | ||||
| Total property, plant and equipment, net |
472,319,683 | 419,113,613 | ||||||
| OTHER ASSETS: |
||||||||
| Cash and other assets held by affiliates |
39,731 | 1,128,110 | ||||||
| Other |
32,944 | 324,712 | ||||||
| Total other assets |
72,675 | 1,452,822 | ||||||
| TOTAL ASSETS |
$ | 592,265,747 | $ | 517,041,907 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-3
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| LIABILITIES AND SHAREHOLDERS’ EQUITY
|
| |||||||
| June 30, | ||||||||
| 2010 | 2009 | |||||||
| CURRENT LIABILITIES: |
||||||||
| Accounts payable |
$ | 34,219,769 | $ | 8,812,677 | ||||
| Royalties and working interests payable |
30,774,444 | 32,781,712 | ||||||
| Accrued liabilities |
2,647,435 | 3,867,579 | ||||||
| Joint interest advances |
739,464 | 4,056,991 | ||||||
| Accrued exploration and development |
9,263,438 | 120,300 | ||||||
| Debt of affiliates |
— | 3,604,609 | ||||||
| Income tax payable |
843,755 | — | ||||||
| Total current liabilities |
78,488,305 | 53,243,868 | ||||||
| DEFERRED TAX LIABILITY |
131,290,992 | 110,964,147 | ||||||
| ASSET RETIREMENT OBLIGATION |
5,156,642 | 3,469,624 | ||||||
| COMMITMENTS AND CONTINGENCIES (NOTE 14) |
— | — | ||||||
| SHAREHOLDERS’ EQUITY: |
||||||||
| Common stock, $0.04 par value, 50,000,000 shares authorized, |
799,300 | 785,533 | ||||||
| Additional paid-in capital |
77,967,702 | 76,321,911 | ||||||
| Treasury stock at cost (4,297,897 and 3,809,354 shares, respectively) |
(82,019,429 | ) | (58,639,644 | ) | ||||
| Retained earnings |
380,582,235 | 330,896,468 | ||||||
| Total shareholders’ equity |
377,329,808 | 349,364,268 | ||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY |
$ | 592,265,747 | $ | 517,041,907 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended June 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| REVENUES: |
||||||||||||
| Natural gas and oil sales |
$ | 160,680,691 | $ | 190,655,605 | $ | 116,497,713 | ||||||
| Total revenues |
160,680,691 | 190,655,605 | 116,497,713 | |||||||||
| EXPENSES: |
||||||||||||
| Operating expenses |
17,039,599 | 23,684,159 | 6,776,757 | |||||||||
| Exploration expenses |
21,938,539 | 20,602,915 | 5,728,600 | |||||||||
| Depreciation, depletion and amortization |
35,373,873 | 32,673,191 | 11,899,620 | |||||||||
| Lease expirations and relinquishments |
951,582 | 5,208,491 | 642,374 | |||||||||
| Impairment of natural gas and oil properties |
— | 5,866,287 | — | |||||||||
| General and administrative expense |
4,615,512 | 9,467,113 | 16,928,760 | |||||||||
| Total expenses |
79,919,105 | 97,502,156 | 41,976,111 | |||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE OTHER INCOME AND INCOME TAXES |
80,761,586 | 93,153,449 | 74,521,602 | |||||||||
| OTHER INCOME (EXPENSE): |
||||||||||||
| Interest expense, net of interest capitalized |
(517,550 | ) | (741,011 | ) | (3,933,309 | ) | ||||||
| Interest income |
915,445 | 925,505 | 1,969,145 | |||||||||
| Gain (loss) on sale of assets and other |
112,868 | (530,260 | ) | 62,314,188 | ||||||||
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
81,272,349 | 92,807,683 | 134,871,626 | |||||||||
| Provision for income taxes |
(31,586,582 | ) | (36,946,481 | ) | (51,650,422 | ) | ||||||
| INCOME FROM CONTINUING OPERATIONS |
49,685,767 | 55,861,202 | 83,221,204 | |||||||||
| DISCONTINUED OPERATIONS (Note 6) |
||||||||||||
| Discontinued operations, net of income taxes |
— | — | 173,685,065 | |||||||||
| NET INCOME |
49,685,767 | 55,861,202 | 256,906,269 | |||||||||
| Preferred stock dividends |
— | — | 1,547,777 | |||||||||
| NET INCOME ATTRIBUTABLE TO COMMON STOCK |
$ | 49,685,767 | $ | 55,861,202 | $ | 255,358,492 | ||||||
| NET INCOME PER SHARE: |
||||||||||||
| Basic |
||||||||||||
| Continuing operations |
$ | 3.14 | $ | 3.41 | $ | 5.05 | ||||||
| Discontinued operations |
— | — | 10.73 | |||||||||
| Total |
$ | 3.14 | $ | 3.41 | $ | 15.78 | ||||||
| Diluted |
||||||||||||
| Continuing operations |
$ | 3.08 | $ | 3.35 | $ | 4.82 | ||||||
| Discontinued operations |
— | — | 10.06 | |||||||||
| Total |
$ | 3.08 | $ | 3.35 | $ | 14.88 | ||||||
| WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: |
||||||||||||
| Basic |
15,830,529 | 16,362,719 | 16,184,517 | |||||||||
| Diluted |
16,157,030 | 16,690,426 | 17,262,715 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended June 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||||||
| Income from continuing operations |
$ | 49,685,767 | $ | 55,861,202 | $ | 83,221,204 | ||||||
| Plus income from discontinued operations, net of income taxes |
— | — | 173,685,065 | |||||||||
| Net income |
49,685,767 | 55,861,202 | 256,906,269 | |||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation, depletion and amortization |
35,373,873 | 32,673,191 | 15,173,285 | |||||||||
| Impairment / expiration of natural gas and oil properties |
951,582 | 11,074,778 | 1,234,111 | |||||||||
| Exploration expenditures |
20,502,517 | 19,038,463 | 4,747,798 | |||||||||
| Deferred income taxes |
19,398,868 | (1,225,537 | ) | 115,952,055 | ||||||||
| Gain on sale of assets |
(112,868 | ) | — | (326,337,749 | ) | |||||||
| Stock-based compensation |
667,077 | 1,381,797 | 1,476,988 | |||||||||
| Tax benefit from exercise of stock options |
(79,283 | ) | (264,187 | ) | (1,080,562 | ) | ||||||
| Changes in operating assets and liabilities: |
||||||||||||
| Decrease (increase) in accounts receivable and other |
(9,129,402 | ) | 39,688,876 | (67,279,024 | ) | |||||||
| Increase in notes receivable |
— | — | (250,000 | ) | ||||||||
| Increase in prepaid insurance and other receivable |
(3,233,931 | ) | (19,366 | ) | (447,202 | ) | ||||||
| Increase in inventory |
(470,318 | ) | — | — | ||||||||
| Increase (decrease) in accounts payable and advances from joint owners |
14,846,244 | (11,597,588 | ) | 26,152,482 | ||||||||
| Increase (decrease) in other accrued liabilities |
300,990 | (43,819,351 | ) | 75,997,351 | ||||||||
| Increase (decrease) in income taxes receivable, net |
662,072 | (7,420,632 | ) | 7,210,622 | ||||||||
| Other |
(1,175,512 | ) | — | 3,286,631 | ||||||||
| Net cash provided by operating activities |
128,187,676 | 95,371,646 | 112,743,055 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
| Natural gas and oil exploration and development expenditures |
(97,698,930 | ) | (45,741,659 | ) | (119,928,546 | ) | ||||||
| Sale of short-term investments, net |
— | — | 2,200,576 | |||||||||
| Additions to furniture and equipment |
(3,632 | ) | (16,025 | ) | (43,225 | ) | ||||||
| Investment in Contango Venture Capital Corporation |
— | — | (1,166,624 | ) | ||||||||
| Acquisition of natural gas and oil producing properties |
— | — | (309,000,000 | ) | ||||||||
| Sale/Acquisition costs |
— | — | (7,847,613 | ) | ||||||||
| Proceeds from the sale of assets |
— | — | 396,925,821 | |||||||||
| Net cash used in investing activities |
(97,702,562 | ) | (45,757,684 | ) | (38,859,611 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
| Borrowings under credit facility |
— | — | 35,000,000 | |||||||||
| Repayments under credit facility |
— | (15,000,000 | ) | (40,000,000 | ) | |||||||
| Borrowings (repayments) by affiliates |
— | — | (8,540,091 | ) | ||||||||
| Preferred stock dividends |
— | — | (1,547,777 | ) | ||||||||
| Repurchase/cancellation of stock options |
— | — | (5,922,532 | ) | ||||||||
| Purchase of common stock |
(23,379,775 | ) | (51,795,744 | ) | (663,900 | ) | ||||||
| Proceeds from exercised options |
913,198 | 1,654,345 | 580,760 | |||||||||
| Tax benefit from exercise/cancellation of stock options |
79,283 | 264,187 | 1,080,562 | |||||||||
| Debt issuance costs |
— | (250,000 | ) | (163,510 | ) | |||||||
| Net cash used in financing activities |
(22,387,294 | ) | (65,127,212 | ) | (20,176,488 | ) | ||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
8,097,820 | (15,513,250 | ) | 53,706,956 | ||||||||
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD |
44,371,324 | 59,884,574 | 6,177,618 | |||||||||
| CASH AND CASH EQUIVALENTS, END OF PERIOD |
$ | 52,469,144 | $ | 44,371,324 | $ | 59,884,574 | ||||||
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: |
||||||||||||
| Cash paid for taxes, net of cash received |
$ | 11,535,121 | $ | 45,592,652 | $ | 21,974,825 | ||||||
| Cash paid for interest |
$ | 250,000 | $ | 397,579 | $ | 4,305,336 | ||||||
| SUPPLEMENTAL NON-CASH ACTIVITY: |
||||||||||||
| Increase in non-recourse demand promissory note |
$ | 2,027,590 | $ | — | $ | — | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY
| Accumulated |
|||||||||||||||||||||||||||||||||||||
| Preferred Stock | Common Stock | Paid-in | Other Comprehensive |
Treasury | Retained | Total Shareholders’ |
Comprehensive | ||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Capital | Income | Stock | Earnings | Equity | Income | ||||||||||||||||||||||||||||
| Balance at June 30, 2007 |
6,000 | $ | 240 | 15,964,807 | $ | 741,591 | $ | 75,849,506 | $ | 715,659 | $ | (6,180,000 | ) | $ | 19,676,774 | $ | 90,803,770 | ||||||||||||||||||||
| Exercise of stock options |
— | — | 71,000 | 2,840 | 577,920 | — | — | — | 580,760 | ||||||||||||||||||||||||||||
| Tax benefit from exercise of stock options |
— | — | — | — | 611,726 | — | — | — | 611,726 | ||||||||||||||||||||||||||||
| Cancellation of stock options, net of tax benefit of $468,836 |
— | — | — | — | (5,453,696 | ) | — | — | — | (5,453,696 | ) | ||||||||||||||||||||||||||
| Treasury shares at cost |
— | — | (10,000 | ) | — | — | — | (663,900 | ) | — | (663,900 | ) | |||||||||||||||||||||||||
| Amortization of restricted stock |
— | — | 4,471 | 179 | 252,257 | — | — | — | 252,436 | ||||||||||||||||||||||||||||
| Conversion of Series E preferred stock to common stock |
(6,000 | ) | (240 | ) | 789,468 | 31,579 | (31,339 | ) | — | — | — | — | |||||||||||||||||||||||||
| Expense of stock options |
— | — | — | — | 1,224,552 | — | — | — | 1,224,552 | ||||||||||||||||||||||||||||
| Net income |
— | — | — | — | — | — | — | 256,906,269 | 256,906,269 | 256,906,269 | |||||||||||||||||||||||||||
| Preferred stock dividends |
— | — | — | — | — | — | — | (1,547,777 | ) | (1,547,777 | ) | ||||||||||||||||||||||||||
| Unrealized gain on available for sale securities, net of tax |
— | — | — | — | — | (715,659 | ) | — | — | (715,659 | ) | (715,659 | ) | ||||||||||||||||||||||||
| Comprehensive income |
— | — | — | — | — | — | — | — | — | $ | 256,190,610 | ||||||||||||||||||||||||||
| Balance at June 30, 2008 |
— | $ | — | 16,819,746 | $ | 776,189 | $ | 73,030,926 | $ | — | $ | (6,843,900 | ) | $ | 275,035,266 | $ | 341,998,481 | ||||||||||||||||||||
| Exercise of stock options |
— | — | 230,500 | 9,220 | 1,645,125 | — | — | — | 1,654,345 | ||||||||||||||||||||||||||||
| Tax benefit from exercise of stock options |
— | — | — | — | 264,187 | — | — | — | 264,187 | ||||||||||||||||||||||||||||
| Amortization of restricted stock |
— | — | 3,088 | 124 | 240,457 | — | — | — | 240,581 | ||||||||||||||||||||||||||||
| Treasury shares at cost |
— | — | (1,224,354 | ) | — | — | — | (51,795,744 | ) | — | (51,795,744 | ) | |||||||||||||||||||||||||
| Expense of stock options |
— | — | — | — | 1,141,216 | — | — | — | 1,141,216 | ||||||||||||||||||||||||||||
| Net income |
— | — | — | — | — | — | — | 55,861,202 | 55,861,202 | ||||||||||||||||||||||||||||
| Balance at June 30, 2009 |
— | $ | — | 15,828,980 | $ | 785,533 | $ | 76,321,911 | $ | — | $ | (58,639,644 | ) | $ | 330,896,468 | $ | 349,364,268 | ||||||||||||||||||||
| Exercise of stock options |
— | — | 344,229 | 13,767 | 899,431 | — | — | — | 913,198 | ||||||||||||||||||||||||||||
| Tax benefit from exercise of stock options |
— | — | — | — | 79,283 | — | — | — | 79,283 | ||||||||||||||||||||||||||||
| Amortization of restricted stock |
— | — | — | — | 72,182 | — | — | — | 72,182 | ||||||||||||||||||||||||||||
| Treasury shares at cost |
— | — | (488,543 | ) | — | — | — | (23,379,785 | ) | — | (23,379,785 | ) | |||||||||||||||||||||||||
| Expense of stock options |
— | — | — | — | 594,895 | — | — | — | 594,895 | ||||||||||||||||||||||||||||
| Net income |
— | — | — | — | — | — | — | 49,685,767 | 49,685,767 | ||||||||||||||||||||||||||||
| Balance at June 30, 2010 |
— | $ | — | 15,684,666 | $ | 799,300 | $ | 77,967,702 | $ | — | $ | (82,019,429 | ) | $ | 380,582,235 | $ | 377,329,808 | ||||||||||||||||||||
The accompanying notes are an integral part of this consolidated financial statement.
F-7
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Business
Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston-based, independent natural gas and oil company. The Company’s business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico.
2. Summary of Significant Accounting Policies
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates include income taxes, stock-based compensation, reserve estimates and impairment of natural gas and oil properties. Actual results could differ from those estimates.
Revenue Recognition. Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share, an overproduced imbalance occurs. To the extent the overproduced imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. At June 30, 2010 and 2009, the Company had no significant imbalances.
Cash Equivalents. Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of June 30, 2010, the Company had $52.5 million in cash and cash equivalents. Of this amount, approximately $31.7 million was invested in U.S. Treasury money market funds and the remaining $20.8 million was invested in overnight U.S. Treasury funds.
Accounts Receivable. The Company sells natural gas and crude oil to a limited number of customers. In addition, the Company participates with other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accounts receivables are due from either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells for which the Company serves as the operator. Generally, operators of natural gas and crude oil properties have the right to offset future revenues against unpaid charges related to operated wells.
The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors. Amounts deemed uncollectible are charged to the allowance.
Accounts receivable allowance for bad debt was $0 at June 30, 2010 and 2009. At June 30, 2010 and 2009, the carrying value of the Company’s accounts receivable approximated fair value.
Net Income (Loss) per Common Share. Basic net income (loss) per common share is computed by dividing income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. See Note 8 – Net Income Per Common Share for the calculations of basic and diluted net income per common share.
Income Taxes. The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax
F-8
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of June 30, 2010. The amount of unrecognized tax benefits did not materially change as of June 30, 2010. The amount of unrecognized tax benefits may change in the next twelve months; however, we do not expect the change to have a significant impact on our results of operations or our financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its statement of operations.
The Company files income tax returns in the United States and various state jurisdictions. The Company’s tax returns for 2007, 2008, and 2009 remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.
Concentration of Credit Risk. Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.
Consolidated Statements of Cash Flows. For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less when purchased to be cash equivalents. Significant transactions may occur that do not directly affect cash balances and, as such, are not disclosed in the Consolidated Statements of Cash Flows. Certain such non-cash transactions are disclosed in the Consolidated Statements of Shareholders’ Equity, including shares issued as compensation and issuance of stock options.
Fair Value of Financial Instruments. The carrying amounts of the Company’s short-term financial instruments, including cash equivalents, short-term investments, trade accounts receivable and accounts payable, approximate their fair values based on the short maturities of those instruments.
Successful Efforts Method of Accounting. The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, and any such impairment is charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. Depreciation, depletion and amortization is calculated on a field by field basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other capitalized costs amortized over proved developed reserves.
When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimate of future reserves, natural gas and oil prices and operating costs and anticipated production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to its fair value.
Impairment of Long-Lived Assets. The Company did not report an impairment charge for the year ended June 30, 2010 or 2008. For the fiscal year ended June 30, 2009, the Company’s analysis determined that Grand Isle 70 and Grand Isle 72 were impaired. The Company recorded an impairment charge of approximately $2.5 million and $3.4 million, respectively, related to these wells. Additionally, the Company recorded $5.2 million in lease expiration and relinquishment expense related to the expiration and relinquishment of 44 lease blocks owned by our partially-owned affiliate, Republic Exploration LLC (“REX”), and Contango Offshore Exploration LLC (“COE”).
For the fiscal year ended June 30, 2008, the Company classified the following asset sales as discontinued operations: its $128.0 million Western core Arkansas Fayetteville Shale sale effective October 1, 2007, its $199.2 million Eastern core Arkansas Fayetteville Shale sale effective December 1, 2007, and its $1.1 million Alta-Ellis #1 and Temple Inland sale effective February 1, 2008. An integral and on-going part of our business strategy is to sell our proved reserves from time to time in order to generate additional capital to reinvest in our onshore and offshore exploration programs.
F-9
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its wholly and partially-owned subsidiaries, after elimination of all intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. Exploration and development affiliates not wholly owned, such as REX, are not controlled by the Company and are proportionately consolidated.
For the periods ending June 30, 2008 and June 30, 2009, the company also proportionately consolidated the results of COE. Effective June 1, 2010 COE was dissolved, and all assets and liabilities owned by COE were distributed to its members.
Contango’s 19.5% ownership of Moblize Inc. (“Moblize”) is accounted for using the cost method. Under the cost method, Contango records an investment in the stock of an investee at cost, and recognizes dividends received as income. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment. In fiscal year 2010, the Company recognized a $190,000 impairment of its investment in Moblize.
Reclassifications. Certain reclassifications have been made to the fiscal year 2009 and 2008 amounts in order to conform with the 2010 presentation. These reclassifications were not material.
Recent Accounting Pronouncements In February 2010, the Financial Accounting Standards Board (“FASB”) amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance for the fiscal year ended June 30, 2010.
In January 2010, the FASB adopted the SECs changes to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:
| • | Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless contractual arrangements designate the price to be used. |
| • | Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered. |
| • | Reserve Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees our reserves estimation process. We will also be required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate. |
The Company adopted the new rules effective June 30, 2010, and as a result, it (i) prepared its reserve estimates as of June 30, 2010 based on the new reserves definitions, (ii) has estimated its June 30, 2010 reserve quantities using the 12-month average price and (iii) included additional disclosures as required by the new rule. As a result of the change in reserve pricing from year-end oil and gas prices to now using the 12-month average prices, the Company’s total proved reserves at June 30, 2010 were 3.8 Bcfe higher than they would have otherwise been if year-end oil and gas prices were used. Oil and gas reserve quantities or their values are a significant component of the Company’s depreciation, depletion and amortization (“DD&A”), asset retirement obligation, and impairment analysis. The Company’s adoption of the SEC’s Modernization of Oil and Gas Reporting: Final Rule had an immaterial impact on the Company’s DD&A expense, asset retirement obligation, and impairment analysis.
Effective July 1, 2009, the Company adopted new accounting guidance on fair value measurements which require additional disclosures about the Company’s nonfinancial assets and liabilities, which adoption had no impact on the Company’s financial position, results of operations or cash flows.
In June 2009, the FASB issued new accounting guidance on the FASB Accounting Standards Codification and the hierarchy of GAAP. This new accounting guidance codifies existing GAAP and recognizes only two levels
F-10
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
of GAAP, authoritative and nonauthoritative. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This new accounting guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.
Stock-Based Compensation. The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. The fair value of each award is estimated as of the date of grant using the Black-Scholes options-pricing model. The Company also classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model. The following weighted-average assumptions were used for the 25,000 options granted during the fiscal year ended June 30, 2010 and the 60,000 options granted during the fiscal year ended June 30, 2009: (i) risk-free interest rate of 0.25 percent and 3.01 percent, respectively; (ii) expected life of five years; (iii) expected volatility of 35 percent and 53 percent, respectively and (iv) expected dividend yield of zero percent. No options were granted for the fiscal year ended June 30, 2008.
The Company did not grant any shares of restricted stock for the fiscal year ended June 30, 2010. During the fiscal year ended June 30, 2009 and 2008, the Company granted 3,088 shares and 4,140 shares of restricted stock, respectively, to its Board of Directors as part of its annual compensation. Grants of service-based restricted stock awards are valued at our common stock price at the date of grant. The shares of restricted stock granted to the board of directors vested over a period of one year.
During the fiscal years ended June 30, 2010, 2009 and 2008, the Company recorded stock-based compensation charges of $0.7 million, $1.4 million, and $1.5 million, respectively, to general and administrative expense for restricted stock and option awards. These amounts do not reflect compensation actually received by the individuals, but rather represent expense recognized in the Company’s consolidated financial statements that relate to restricted stock and option awards granted in current and previous fiscal years.
Derivative Instruments and Hedging Activities. The Company did not enter into any derivative instruments or hedging activities for the fiscal years ended June 30, 2010, 2009 or 2008, nor did we have any open commodity derivative contracts at June 30, 2010.
Asset Retirement Obligation. The Company accounts for its retirement obligation of long lived assets by recording the net present value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Activities related to the Company’s ARO during the year ended June 30, 2010 and 2009 were as follows:
| Year Ended June 30, | |||||||
| 2010 | 2009 | ||||||
| Balance as of July 1 |
$ | 3,469,624 | $ | 1,949,881 | |||
| Liabilities incurred during period |
1,665,178 | 853,940 | |||||
| Liabilities settled during period |
(399,954 | ) | — | ||||
| Accretion |
176,737 | 159,470 | |||||
| Change in estimate |
245,057 | 506,333 | |||||
| Balance as of June 30 |
$ | 5,156,642 | $ | 3,469,624 | |||
F-11
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
3. Natural Gas and Oil Exploration and Production Risk
The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves. Substantially all of its production is sold under various terms and arrangements at prevailing market prices. Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control.
Other factors that have a direct bearing on the Company’s financial condition are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; the timing and costs of our future drilling; development and abandonment activities; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations, the amount of reported assets, liabilities and contingencies, and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.
4. Customer Concentration Credit Risk
The customer base for the Company is concentrated in the natural gas and oil industry. Major purchasers of our natural gas, oil and natural gas liquids for the fiscal year ended June 30, 2010 were ConocoPhillips Company (37%), Shell Trading US Company (24%), Atmos Energy Marketing, LLC (16%) and Enterprise Products Operating LLC (13%). Our sales to these companies are not secured with letters of credit and in the event of non-payment, we could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect on our financial position. There are numerous other potential purchasers of our production.
5. Other Receivable
On February 24, 2010, a dredge contracted by the Army Corps of Engineers to dredge the Atchafalaya River Channel ruptured the Company’s 20” pipeline that runs from our Eugene Island 11 gathering platform to our Eugene Island 63 auxiliary platform where our pipeline joins a third-party pipeline that transports our production to shore. The pipeline was repaired and production resumed on March 31, 2010. We believe the repairs will be covered by our insurance policy, subject to a deductible, and have recorded a receivable of approximately $3.2 million related to this incident in the Consolidated Balance Sheet as of June 30, 2010.
F-12
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
6. Sale of Properties - Discontinued Operations
The Company did not have any discontinued operations for the fiscal year ended June 30, 2010 or 2009.
During the fiscal year ended June 30, 2008, the Company sold its Arkansas Fayetteville Shale properties, an on-shore well in Texas and an on-shore well in Louisiana for approximately $328.3 million, in the aggregate, recognizing a gain of approximately $262.3 million. We classify our property sales as discontinued operations in our financial statements for all periods presented. The summarized financial results for discontinued operations for the period ended June 30, 2008 are as follows:
Operating Results:
| June 30, | ||||
| 2008 | ||||
| Revenues |
$ | 9,679,330 | ||
| Operating expenses |
(1,144,786 | ) | ||
| Depletion expenses |
(3,273,655 | ) | ||
| Exploration expenses |
(359,888 | ) | ||
| Impairment |
(591,737 | ) | ||
| Gain on sale of discontinued operations |
262,898,530 | |||
| Gain before income taxes |
$ | 267,207,794 | ||
| Provision for income taxes |
(93,522,729 | ) | ||
| Gain from discontinued operations, net of income taxes |
$ | 173,685,065 | ||
7. Sale of Properties – Other
Freeport LNG Development, L.P.
During the fiscal year ended June 30, 2008, the Company sold its ten percent (10%) limited partnership interest in Freeport LNG Development L.P. (“Freeport LNG”) to Turbo LNG LLC, an affiliate of Osaka Gas Co., Ltd., for $68.0 million, and recognized a pre-tax gain of approximately $63.4 million on the sale. Freeport LNG is a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcfd”) liquefied natural gas (“LNG”) receiving and gasification terminal on Quintana Island, near Freeport, Texas.
Contango Venture Capital Corporation
During the fiscal year ended June 30, 2008, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, sold its direct and indirect investments in several alternative energy investments for approximately $3.4 million, recognizing a loss of approximately $2.9 million. CVCC’s only remaining investment is Moblize, Inc. (“Moblize”). As of June 30, 2010, CVCC owned 443,648 shares of Moblize convertible preferred stock, which represents an approximate 19.5% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas and other industries using open-standards based technologies. During the fiscal year ended June 30, 2010, the Company recognized an impairment of $190,000 related to its investment in Moblize, reducing its investment to $0 as of June 30, 2010.
F-13
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
8. Net Income Per Common Share
A reconciliation of the components of basic and diluted net income per common share for the fiscal years ended June 30, 2010, 2009 and 2008 is presented below:
| Year Ended June 30, 2010 | |||||||||
| Net Income |
Shares | Per Share | |||||||
| Income from continuing operations |
$ | 49,685,767 | 15,830,529 | $ | 3.14 | ||||
| Basic Earnings per Share: |
|||||||||
| Net income attributable to common stock |
$ | 49,685,767 | 15,830,529 | $ | 3.14 | ||||
| Effect of Potential Dilutive Securities: |
|||||||||
| Stock options |
— | 586,318 | |||||||
| Shares assumed purchased |
— | (260,203 | ) | ||||||
| Restricted shares |
— | 386 | |||||||
| Income from continuing operations |
$ | 49,685,767 | 16,157,030 | $ | 3.08 | ||||
| Diluted Earnings per Share: |
|||||||||
| Net income attributable to common stock |
$ | 49,685,767 | 16,157,030 | $ | 3.08 | ||||
| Year Ended June 30, 2009 | |||||||||
| Net Income |
Shares | Per Share | |||||||
| Income from continuing operations |
$ | 55,861,202 | 16,362,719 | $ | 3.41 | ||||
| Basic Earnings per Share: |
|||||||||
| Net income attributable to common stock |
$ | 55,861,202 | 16,362,719 | $ | 3.41 | ||||
| Effect of Potential Dilutive Securities: |
|||||||||
| Stock options |
— | 640,167 | |||||||
| Shares assumed purchased |
— | (314,004 | ) | ||||||
| Restricted shares |
— | 1,544 | |||||||
| Income from continuing operations |
$ | 55,861,202 | 16,690,426 | $ | 3.35 | ||||
| Diluted Earnings per Share: |
|||||||||
| Net income attributable to common stock |
$ | 55,861,202 | 16,690,426 | $ | 3.35 | ||||
F-14
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
8. Net Income Per Common Share - continued
| Year Ended June 30, 2008 | ||||||||
| Net Income | Shares | Per Share | ||||||
| Income from continuing operations, including preferred dividends |
$ | 81,673,427 | 16,184,517 | $ | 5.05 | |||
| Discontinued operations, net of income taxes |
$ | 173,685,065 | 16,184,517 | $ | 10.73 | |||
| Basic Earnings per Share: |
||||||||
| Net income attributable to common stock |
$ | 255,358,492 | 16,184,517 | $ | 15.78 | |||
| Effect of Potential Dilutive Securities: |
||||||||
| Stock options |
— | 448,264 | ||||||
| Restricted shares |
— | 7,570 | ||||||
| Series E preferred stock |
1,547,777 | 622,364 | — | |||||
| Income from continuing operations |
$ | 83,221,204 | 17,262,715 | $ | 4.82 | |||
| Discontinued operations, net of income taxes |
$ | 173,685,065 | 17,262,715 | $ | 10.06 | |||
| Diluted Earnings per Share: |
||||||||
| Net income attributable to common stock |
$ | 256,906,269 | 17,262,715 | $ | 14.88 | |||
Options to purchase 70,000 and 45,000 shares of common stock were outstanding as of June 30, 2010 and 2009, respectively, but were not included in the computation of diluted earnings per share for the fiscal year ended June 30, 2010 or 2009. These options were excluded because either (i) the options’ exercise price was greater than the average market price of the common shares, or (ii) application of the treasury method to in-the-money options made some of the options anti-dilutive. All outstanding options as of June 30, 2008 were included in the computation of diluted earnings per share for the fiscal year ended June 30, 2008.
9. Change in Ownership of Partially-Owned Subsidiaries and Overriding Royalties
Effective June 1, 2010, COE was dissolved and all assets and liabilities owned by COE were transferred to its respective members. Contango had a 65.6% equity interest in COE. In connection with its dissolution, COE distributed its ownership interest in Ship Shoal 263 and all of its unevaluated leases to its members. As a result, Contango has a working interest of approximately 92.46% and a net revenue interest of approximately 74% in this well. Additionally, beginning in 2006, COE had borrowed $4.3 million in principal from the Company plus accrued and unpaid interest of approximately $1.6 million. In connection with the dissolution, the Company assumed its 65.6% of the obligation of COE, while the other member of COE assumed the remaining 34.4%, or approximately $2 million. This $2 million is reflected as a receivable in the Consolidated Balance Sheet of the Company as of June 30, 2010.
During the fiscal year ended June 30, 2008, the members of REX entered into an Amended and Restated Limited Liability Company Agreement (the “REX LLC Agreement”), effective as of April 1, 2008, to, among other things, distribute REX’s interest in Dutch and Mary Rose to the individual members of REX or their designees. In connection with this distribution, REX repaid in full all amounts owing by REX to a private investment firm under a $50.0 million demand promissory note with such private investment firm (the “REX Demand Note”), and all security interests and other liens granted in favor of such private investment firm as security for the obligations under the REX Demand Note have been released and terminated. The Company’s portion of such repayment was approximately $22.5 million.
Effective April 1, 2008, in connection with the REX LLC Agreement, the Company sold a portion of its membership interest in REX to an existing member of REX for approximately $0.8 million. As a result of the sale, the Company’s equity ownership interest in REX has decreased from 42.7% to 32.3%. Also effective April 1, 2008, the Company sold a portion of its membership interest in COE to an existing member of COE for approximately $0.9 million. As a result of the sale, the Company’s equity ownership interest in COE has decreased from 76.0% to 65.6%.
F-15
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
10. Acquisitions
During the fiscal year ended June 30, 2008, the Company acquired additional working interests in the Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) discoveries in a like-kind exchange, using funds from the sale of its Arkansas Fayetteville Shale properties held by a qualified intermediary. The Company purchased an additional 12.5 % working interest and 10.0% net revenue interest in Dutch and an additional average 13.67% working interest and 10.0% net revenue interest in Mary Rose from three different companies for $300 million. Of these three companies, one of them was the managing member of REX, who exchanged an ownership interest in REX for a direct working interest in Dutch and Mary Rose. The Company purchased a 2.45% working interest in Dutch and a 2.68% working interest in Mary Rose from this company for approximately $58.9 million. The Company also purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries for $9.0 million.
11. Series E Perpetual Cumulative Convertible Preferred Stock
During the fiscal year ended June 30, 2007, we sold $30.0 million of our Series E preferred stock to a group of private investors. Dividends on the Series E preferred stock were paid quarterly in cash at a rate of 6.0% per annum. During the fiscal year ended June 30, 2008, all Series E preferred stockholders converted their Series E preferred stock into 789,486 shares of our common stock.
12. Income Taxes
Actual income tax expense from continuing operations differs from income tax expense from continuing operations computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income as follows:
| Year Ended June 30, | |||||||||||||||||||
| 2010 | 2009 | 2008 | |||||||||||||||||
| Provision at statutory tax rate |
$ | 28,445,322 | 35.0 | % | $ | 32,482,689 | 35.0 | % | $ | 47,205,069 | 35.0 | % | |||||||
| State income tax provision, net of federal benefit |
1,414,744 | 1.74 | % | 4,120,324 | 4.44 | % | 1,526,658 | 1.13 | % | ||||||||||
| Permanent differences |
(465,232 | ) | -0.57 | % | 343,468 | 0.37 | % | 2,393,765 | 1.78 | % | |||||||||
| Other |
2,191,748 | 2.70 | % | — | — | 524,930 | 0.39 | % | |||||||||||
| Income tax provision |
$ | 31,586,582 | 38.87 | % | $ | 36,946,481 | 39.81 | % | $ | 51,650,422 | 38.30 | % | |||||||
F-16
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
The provision for income taxes for the periods indicated are comprised of the following:
| Year Ended June 30, | ||||||||||
| 2010 | 2009 | 2008 | ||||||||
| Current: |
||||||||||
| Federal |
$ | 11,590,121 | $ | 31,224,546 | $ | 25,364,147 | ||||
| State |
597,593 | 6,947,472 | — | |||||||
| Total |
$ | 12,187,714 | $ | 38,172,018 | $ | 25,364,147 | ||||
| Deferred: |
||||||||||
| Federal |
$ | 18,323,227 | $ | (617,027 | ) | $ | 23,937,570 | |||
| State |
1,075,641 | (608,510 | ) | 2,348,705 | ||||||
| Total |
$ | 19,398,868 | $ | (1,225,537 | ) | $ | 26,286,275 | |||
| Total: |
||||||||||
| Federal |
$ | 29,913,348 | $ | 30,607,519 | $ | 49,301,717 | ||||
| State |
1,673,234 | 6,338,962 | 2,348,705 | |||||||
| Total |
$ | 31,586,582 | $ | 36,946,481 | $ | 51,650,422 | ||||
The net deferred tax liability is comprised of the following:
| Year Ended June 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Deferred tax liability: |
||||||||||||
| Net operating loss carryover |
$ | — | $ | — | $ | — | ||||||
| Temporary basis differences in natural gas and oil properties and other |
(131,290,992 | ) | (110,964,147 | ) | (112,189,684 | ) | ||||||
| Net deferred tax liability |
$ | (131,290,992 | ) | $ | (110,964,147 | ) | $ | (112,189,684 | ) | |||
13. Long-Term Debt
On October 3, 2008, the Company and its wholly-owned subsidiaries completed the arrangement of a $50 million hydrocarbon borrowing base secured revolving credit facility pursuant to a credit agreement with BBVA Compass (successor in interest to Guaranty Bank, as administrative agent and issuing lender) (the “Compass Agreement”). The credit facility is secured by substantially all of the Company’s assets and is available to fund the Company’s exploration and development activities, as well as the repurchase of shares of the Company’s common stock, the payment of dividends, and working capital as needed. Borrowings under the Compass Agreement bear interest at LIBOR plus 2.0% per annum. The outstanding principal amount and any accrued interest thereon is due October 3, 2010, and may be prepaid at any time in accordance with the Compass Agreement with no prepayment penalty. An arrangement fee of 0.5%, or $250,000, was paid in connection with the facility and a commitment fee of 0.5% is paid on the unused commitment amount. As of June 30, 2010 the Company was in compliance with all financial covenants, ratios and other provisions of the Compass Agreement. As of June 30, 2010 and 2009, no amounts had been drawn on the credit facility.
The Compass Agreement contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or comply with certain covenants in the Compass Agreement could result in a default and funds not being available for borrowing. As of June 30, 2010, the Company was in compliance with its financial covenants, ratios and other provisions of the Compass Agreement.
F-17
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
In August 2008, the Company prepaid the $15.0 million it had outstanding under its $30.0 million loan agreement with a private investment firm (the “Term Loan Agreement”) and terminated the Term Loan Agreement. In February 2008, using the proceeds from our $68.0 million sale of Freeport LNG, the Company prepaid in full the $20.0 million it had outstanding under its three-year $20.0 million secured term loan facility with The Royal Bank of Scotland plc (the “RBS Facility”) and terminated the RBS Facility.
14. Commitments and Contingencies
Operating Leases. Contango leases its office space and certain other equipment and pays delay rentals on certain oil and gas leases. As of June 30, 2010, minimum future lease payments are as follows:
| Fiscal years Ending June 30, |
|||
| 2011 |
740,952 | ||
| 2012 |
573,252 | ||
| 2013 |
510,090 | ||
| 2014 |
339,560 | ||
| 2015 and thereafter |
71,824 | ||
| Total |
$ | 2,235,678 | |
The amount incurred under operating leases during the years ended June 30, 2010, 2009 and 2008 was $160,717, $160,405 and $149,782, respectively. Additionally, the amount incurred for delay rentals during the years ended June 30, 2010, 2009 and 2008 was approximately $0.5 million, $1.1 million and $0.9 million, respectively.
15. Stock Based Compensation
The Company’s 1999 Stock Incentive Plan (the “1999 Plan”) expired in August 2009. All 280,334 outstanding options issued under the 1999 Plan will be converted into common shares of the Company if the options are exercised prior to their expiration dates, which range from December 2010 to September 2013.
On September 15, 2009, the Company’s Board of Directors adopted the Contango Oil & Gas Company Equity Compensation Plan (the “2009 Plan”), which was approved by shareholders on November 19, 2009. Under the 2009 Plan, the Company’s Board of Directors can grant restricted stock and option awards to officers, directors, employees or consultants of the Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board.
Under the 2009 Plan, the Company may issue up to 2,500,000 shares of common stock with an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant, but in no event less than $2.00 per share. The Company may grant key employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options generally expire after five or ten years. The vesting schedule varies, and can vest over a two, three or four-year period. As of June 30, 2010, options under the 2009 Plan to acquire 25,000 shares of common stock at $49.29 were outstanding.
F-18
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
A summary of the status of stock options granted under the 1999 Plan and 2009 Plan as of June 30, 2010, 2009 and 2008, and changes during the fiscal years then ended, is presented in the table below:
| Year Ended June 30, | |||||||||||||||||||||
| 2010 | 2009 | 2008 | |||||||||||||||||||
| Shares Under Options |
Weighted Average Exercise Price |
Shares Under Options |
Weighted Average Exercise Price |
Shares Under Options |
Weighted Average Exercise Price | ||||||||||||||||
| Outstanding, beginning of year |
685,167 | $ | 16.49 | 855,667 | $ | 11.57 | 1,026,000 | $ | 10.87 | ||||||||||||
| Granted |
25,000 | $ | 49.29 | 60,000 | $ | 50.91 | — | $ | — | ||||||||||||
| Exercised |
(344,229 | ) | $ | 9.24 | (230,500 | ) | $ | 7.18 | (71,000 | ) | $ | 8.18 | |||||||||
| Forfeited |
(60,604 | ) | $ | 10.20 | — | $ | — | — | $ | — | |||||||||||
| Cancelled |
— | $ | — | — | $ | — | (99,333 | ) | $ | 6.77 | |||||||||||
| Outstanding, end of year |
305,334 | $ | 28.61 | 685,167 | $ | 16.49 | 855,667 | $ | 11.57 | ||||||||||||
| Aggregate intrinsic value |
$ | 4,928,091 | $ | 17,814,342 | $ | 69,608,510 | |||||||||||||||
| Exercisable, end of year |
240,334 | $ | 22.74 | 625,167 | $ | 13.19 | 686,167 | $ | 10.87 | ||||||||||||
| Aggregate intrinsic value |
$ | 5,289,751 | $ | 18,317,393 | $ | 56,300,002 | |||||||||||||||
| Available for grant, end of year |
2,475,000 | 508,666 | 568,666 | ||||||||||||||||||
| Weighted average fair value of options granted during the year (1) |
$ | 15.39 | $ | 24.91 | $ | — | |||||||||||||||
| (1) | The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the years ended June 30, 2010 and 2009, respectively: (i) risk-free interest rate of 0.25 percent and 3.01 percent; (ii) expected lives of five years; (iii) expected volatility of 35 percent and 53 percent; and (iv) expected dividend yield of zero percent. |
The following table summarizes information regarding stock options that were outstanding at June 30, 2010:
| Options Outstanding | Options Exercisable | |||||||||||
| Range of Exercise Price |
Number of Shares Under Outstanding Options |
Weighted Average Remaining Contractual Life |
Weighted Average Exercise Price |
Number of Shares Under Outstanding Options |
Weighted Average Exercise Price | |||||||
| $11.00 - $11.99 |
14,334 | 0.8 | $ | 11.58 | 14,334 | $ | 11.58 | |||||
| $12.00 - $12.99 |
3,000 | 0.7 | $ | 12.95 | 3,000 | $ | 12.95 | |||||
| $14.00 - $14.99 |
3,000 | 1.0 | $ | 14.14 | 3,000 | $ | 14.14 | |||||
| $21.00 - $21.99 |
200,000 | 1.6 | $ | 21.00 | 200,000 | $ | 21.00 | |||||
| $41.00 - $41.99 |
15,000 | 3.2 | $ | 41.01 | 5,000 | $ | 41.01 | |||||
| $49.00 - $49.99 |
25,000 | 4.7 | $ | 49.29 | — | $ | — | |||||
| $54.00 - $54.99 |
45,000 | 3.2 | $ | 54.21 | 15,000 | $ | 54.21 | |||||
| 305,334 | 2.1 | $ | 28.61 | 240,334 | $ | 22.74 | ||||||
F-19
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
The Company applies the fair value method to account for stock based compensation. Under this method, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the fiscal years ended June 30, 2010, 2009 and 2008, approximately $0.1 million, $0.3 million and $1.1 million, respectively, of such excess tax benefits were classified as financing cash flows. See Note 2 – Summary of Significant Accounting Policies.
All employee stock option grants are expensed over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. During the fiscal year-ended June 30, 2010, 2009 and 2008, the Company recorded stock option expense of $0.6 million, $1.1 million and $1.2 million, respectively.
As of June 30, 2010, we have approximately $1.3 million of total unrecognized compensation cost related to non-vested awards granted under our various share-based plans, which we expect to recognize over a two-year period.
The aggregate intrinsic values of the options exercised during fiscal years 2010, 2009 and 2008 were approximately $15.3 million, $12.2 million and $1.9 million, respectively.
The Company did not grant any shares of restricted stock for the fiscal year ended June 30, 2010. For the fiscal year ended June 30, 2009, the Company awarded a total of 3,088 shares of restricted stock under the 1999 Plan to its board of directors. Of these 3,088 shares of restricted stock, 1,544 shares vested on the date of grant, and the remaining 1,544 shares vested one year thereafter. The fair value of restricted stock was approximately $144,000. For the fiscal year ended June 30, 2008, the Company awarded a total of 4,140 shares of restricted stock under the 1999 Plan to its board of directors. Of these 4,140 shares of restricted stock, 2,070 shares vested on the date of grant, and the remaining 2,070 shares vested one year thereafter. The fair value of restricted stock was approximately $180,000.
For the year ended June 30, 2010, 2009 and 2008, the Company recognized $72,182, $240,581 and $252,435, respectively, in compensation expense relating to restricted stock awards. A summary of the Company’s restricted stock as of June 30, 2010, is as follows:
| Number of Shares |
Weighted Average Fair Value Per Share | |||||
| Nonvested balance at June 30, 2008 |
7,654 | $ | 22.16 | |||
| Granted |
3,088 | 46.75 | ||||
| Vested |
(9,198 | ) | 26.29 | |||
| Forfeited |
— | — | ||||
| Nonvested balance at June 30, 2009 |
1,544 | $ | 46.75 | |||
| Granted |
— | — | ||||
| Vested |
(1,544 | ) | 46.75 | |||
| Forfeited |
— | — | ||||
| Nonvested balance at June 30, 2010 |
— | $ | — | |||
F-20
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
16. Related Party Transactions
Effective October 1, 2009, the Company’s wholly-owned subsidiary, Conterra Company (“Conterra”), entered into a joint venture with Patara Oil & Gas LLC (“Patara”), a privately held oil and gas company, to develop proved undeveloped Cotton Valley gas reserves in Panola County, Texas. B.A. Berilgen, a member of the Company’s board of directors, is the Chief Executive Officer of Patara.
During the fiscal year ended June 30, 2010, the Company purchased 115,454 shares of its common stock from three officers of the Company and two members of its board of directors for approximately $6.4 million. During the fiscal year ended June 30, 2009, the Company purchased 21,754 shares of its common stock from one member of its board of directors for approximately $1.3 million. During the fiscal year ended June 30, 2008, Company purchased 10,000 shares of its common stock from one member of its board of directors and 99,333 stock options from three officers of the Company and one member of its board of directors for approximately $6.6 million. All purchases were approved by the Company’s board of directors and were completed at the closing price of the Company’s common stock on the date of purchase.
During the fiscal year June 30, 2008, the members of REX entered into the REX LLC Agreement, effective as of April 1, 2008, to, among other things, distribute REX’s interest in Dutch and Mary Rose to the individual members of REX or their designees. In connection with this distribution, REX repaid in full all amounts owing by REX under the REX Demand Note, and all security interests and other liens granted in favor of such private investment firm as security for the obligations under the REX Demand Note were released and terminated. As a result of our proportionate consolidation of REX, the Company’s portion of such repayment was approximately $22.5 million. For the fiscal year ended June 30, 2008, the Company’s proportionate share of such interest expense was approximately $1.3 million.
In March 2006, COE executed a Promissory Note (the “COE Note”) to the Company to finance its share of development costs in Grand Isle 72. The COE Note was payable upon demand and carried an annual interest rate of 10%. As of May 31, 2010, COE owed COI $4.3 million under the COE Note, and owed an additional $1.6 million in accrued and unpaid interest. Effective June 1, 2010, COE was dissolved and the Company assumed its 65.6% of the obligation of COE, while the other member of COE assumed the remaining 34.4%, or approximately $2 million. This $2 million is reflected as a note receivable in the Consolidated Balance Sheet of the Company as of June 30, 2010. The new note receivable is payable on demand and bears no interest.
17. Share Repurchase Program
In September 2008, the Company’s board of directors approved a $100 million share repurchase program. All shares are purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases will be made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. Repurchased shares of common stock become authorized but unissued shares, and may be issued in the future for general corporate and other purposes. As of June 30, 2010, we have purchased approximately 1.7 million shares of our common stock at an average cost per share of $43.89, for a total expenditure of approximately $75 million. As at June 30, 2010, we have 15,684,666 shares of common stock outstanding and 15,990,000 fully diluted shares.
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Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (continued)
18. Subsequent Events
On August 24, 2010, the Company signed a commitment letter with Amegy Bank National Association (“Amegy”) to arrange for a four-year $40 million hydrocarbon borrowing base senior revolving credit facility (the “Amegy Agreement”) to replace the expiring Compass Agreement. Under the terms and conditions of the term sheet with Amegy, the facility will be secured by substantially all of the Company’s assets and will be available to fund the Company’s exploration and development activities, as well as the repurchase of shares of the Company’s common stock, the payment of dividends, and working capital as needed. Borrowings under the Amegy Agreement will bear interest at LIBOR plus 2.5% per annum. An arrangement fee of 0.75%, or $300,000, will be paid in connection with the facility and a commitment fee of 0.375% will be paid on the unused commitment amount. The Amegy Agreement will contain customary covenants including limitations on additional indebtedness.
In July 2010, both Conterra and Patara agreed to enter into a second joint venture agreement to drill up to an additional 15 wells, bringing the total expected number of wells to 30.
During July 2010, we purchased an additional 20,000 shares of our common stock under our $100 million share repurchase program for approximately $0.9 million, bringing the total number of shares outstanding to 15,664,666 and our fully diluted shares to 15,970,000 as of August 31, 2010.
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Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
The following disclosures provide required unaudited information.
Costs Incurred. The following table presents information regarding our net costs incurred in the purchase of proved and unproved properties and in exploration and development activities for the periods indicated:
| Year Ended June 30, | |||||||||
| 2010 | 2009 | 2008 | |||||||
| Property acquisition costs: |
|||||||||
| Unproved |
$ | 11,318,349 | $ | — | $ | — | |||
| Proved |
2,009,330 | 1,131,582 | 309,000,000 | ||||||
| Exploration costs |
52,805,270 | 23,284,970 | 45,243,651 | ||||||
| Developmental costs |
40,901,582 | 22,889,629 | 76,025,586 | ||||||
| Total costs |
$ | 107,034,531 | $ | 47,306,181 | $ | 430,269,237 | |||
Natural Gas and Oil Reserves. Proved reserves are estimated quantities of natural gas and oil that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that reasonably can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved natural gas and oil reserve quantities at June 30, 2010, 2009 and 2008, and the related discounted future net cash flows before income taxes are based on estimates prepared by William M. Cobb & Associates, Inc. and Lonquist & Co. LLC. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.
F-23
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
The Company’s net ownership interests in estimated quantities of proved natural gas and oil reserves and changes in net proved reserves as of June 30, 2010, 2009 and 2008, all of which are located in the continental United States, are summarized below:
| Oil and Condensate |
NGL's | Natural Gas |
|||||||
| (MBbls) | (MBbls) | (MMcf) | |||||||
| Proved Developed and Undeveloped Reserves as of: |
|||||||||
| June 30, 2007 |
1,164 | — | 77,892 | ||||||
| Sale of reserves |
— | — | (13,789 | ) | |||||
| Extensions and discoveries |
2,200 | 3,186 | 117,999 | ||||||
| Purchases |
1,496 | 2,015 | 78,745 | ||||||
| Recoveries and revisions |
806 | 2,350 | 41,309 | ||||||
| Production |
(187 | ) | (112 | ) | (10,588 | ) | |||
| June 30, 2008 |
5,479 | 7,439 | 291,568 | ||||||
| Sale of reserves |
— | — | — | ||||||
| Extensions and discoveries |
104 | 69 | 2,148 | ||||||
| Purchases |
— | — | — | ||||||
| Recoveries and revisions |
(64 | ) | 483 | 7,437 | |||||
| Production |
(515 | ) | (590 | ) | (20,537 | ) | |||
| June 30, 2009 |
5,004 | 7,401 | 280,616 | ||||||
| Sale of reserves |
— | — | — | ||||||
| Extensions and discoveries |
1,276 | 1,081 | 40,635 | ||||||
| Purchases |
— | — | — | ||||||
| Recoveries and revisions |
(1,177 | ) | (1,146 | ) | (53,855 | ) | |||
| Production |
(505 | ) | (598 | ) | (21,385 | ) | |||
| June 30, 2010 |
4,598 | 6,738 | 246,011 | ||||||
| Proved Developed Reserves as of: |
|||||||||
| June 30, 2007 |
827 | — | 57,721 | ||||||
| June 30, 2008 |
5,479 | 7,439 | 291,568 | ||||||
| June 30, 2009 |
5,004 | 7,401 | 280,616 | ||||||
| June 30, 2010 |
4,598 | 6,738 | 246,011 | ||||||
During the fiscal year ended June 30, 2010, included in the recoveries and revisions line item is a revision of approximately 48.5 Bcfe related to our Dutch and Mary Rose field reserves. As a result of newly learned bottom hole pressure data determined during a recent field wide shut-in and a “P/Z pressure test”, our independent third-party engineer concluded that we had less reserves than originally estimated.
During the fiscal year ended June 30, 2008, the large adjustment related to discoveries is due to the exploration discoveries at Mary Rose #1, #2, #3 and #4 on our State of Louisiana State leases. The large adjustment related to purchases is due to the additional working interest the Company purchased in the Eugene Island 10 and State of Louisiana. The Company purchased an additional 12.5% working interest and 10% net revenue interest in Dutch and an additional average 13.67% working interest and 10% net revenue interest in Mary Rose for $300 million. The Company also purchased an additional 0.3% overriding royalty interest in the Dutch and Mary Rose discoveries for $9.0 million.
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Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
Standardized Measure. The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved natural gas and oil reserves as of June 30, 2010, 2009 and 2008 are shown below:
| As of June 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Future cash flows |
$ | 1,720,888,280 | $ | 1,750,118,803 | $ | 5,635,443,766 | ||||||
| Future operating expenses |
(232,641,231 | ) | (248,468,246 | ) | (211,104,075 | ) | ||||||
| Future development costs |
(66,236,936 | ) | (16,225,612 | ) | (20,712,845 | ) | ||||||
| Future income tax expenses |
(399,755,146 | ) | (447,934,853 | ) | (1,733,031,168 | ) | ||||||
| Future net cash flows |
1,022,254,967 | 1,037,490,092 | 3,670,595,678 | |||||||||
| 10% annual discount for estimated timing of cash flows |
(310,160,823 | ) | (399,398,648 | ) | (1,436,677,549 | ) | ||||||
| Standardized measure of discounted future net cash flows |
$ | 712,094,144 | $ | 638,091,444 | $ | 2,233,918,129 | ||||||
Future cash flows represent expected revenues from production and are computed by applying certain prices of natural gas and oil to fiscal year-end quantities of proved natural gas and oil reserves. For the fiscal year ended June 30, 2010, future cash flows were based on the first-day-of-the-month prices for the previous 12 months of $4.09 per MMBtu of natural gas, $76.21 per barrel of oil, and $44.62 per barrel of natural gas liquids. For the fiscal years ended June 30, 2009 and 2008, future cash flows were based on fiscal year-end prices of $3.89 and $13.095 per MMBtu for natural gas, respectively; $69.89 and $140.00 per barrel of oil, respectively; and $35.66 and $98.00 per barrel of natural gas liquids, respectively, in each case before adjusting for basis, transportation costs and BTU content.
Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future development costs relate to compression charges at our EI-11H platform, abandonment costs, and recompletion costs.
Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s natural gas and oil properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations.
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Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
Change in Standardized Measure. Changes in the standardized measure of future net cash flows relating to proved natural gas and oil reserves are summarized below:
| Year Ended June 30, | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| Changes due to current year operation: |
||||||||||||
| Sales of natural gas and oil, net of natural gas and oil operating expenses |
$ | (143,641,092 | ) | $ | (166,971,446 | ) | $ | (118,255,500 | ) | |||
| Extensions and discoveries |
151,760,465 | 9,053,412 | 1,320,872,171 | |||||||||
| Net change in prices and production costs |
|
108,882,767 |
|
(2,246,528,398 | ) | 393,348,968 | ||||||
| Change in future development costs |
7,968,517 | 5,274,099 | 50,366,258 | |||||||||
| Revisions of quantity estimates |
(190,840,383 | ) | 24,805,146 | 641,122,998 | ||||||||
| Purchase of reserves |
— | — | 868,101,751 | |||||||||
| Sale of reserves |
— | — | (26,923,252 | ) | ||||||||
| Accretion of discount |
88,986,475 | 318,384,235 | 32,917,957 | |||||||||
| Change in the timing of production rates and other |
57,460,335 | (237,994,644 | ) | (306,888,418 | ) | |||||||
| Changes in income taxes |
(6,574,384 | ) | 698,150,911 | (873,042,079 | ) | |||||||
| Net change |
74,002,700 | (1,595,826,685 | ) | 1,981,620,854 | ||||||||
| Beginning of year |
638,091,444 | 2,233,918,129 | 252,297,275 | |||||||||
| End of year |
$ | 712,094,144 | $ | 638,091,444 | $ | 2,233,918,129 | ||||||
For the fiscal year ended June 30, 2009 and 2008, the standardized measure decreased by approximately $238.0 million, and $307 million, respectively, due to a change in the timing of production rates and other. This is mainly attributable to production profile differences and other imprecise assumptions. We had six wells producing in 2008, nine wells producing in 2009 and nine wells producing in 2010.
F-26
Table of Contents
Index to Financial Statements
CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES
QUARTERLY RESULTS OF OPERATIONS (Unaudited)
Quarterly Results of Operations. The following table sets forth the results of operations by quarter for the years ended June 30, 2010 and 2009:
| Quarter Ended | ||||||||||||
| Sept. 30, | Dec. 31, | Mar. 31, | June 30, | |||||||||
| ($000, except per share amounts) | ||||||||||||
| Fiscal Year 2010: |
||||||||||||
| Revenues from continuing operations |
$ | 35,602 | $ | 46,080 | $ | 37,846 | $ | 41,153 | ||||
| Income from continuing operations (1) |
$ | 21,377 | $ | 30,661 | $ | 2,792 | $ | 26,442 | ||||
| Net income attributable to common stock |
$ | 13,466 | $ | 19,111 | $ | 1,742 | $ | 15,367 | ||||
| Net income per share (2): |
||||||||||||
| Basic: |
$ | 0.85 | $ | 1.21 | $ | 0.11 | $ | 0.97 | ||||
| Diluted: |
$ | 0.83 | $ | 1.18 | $ | 0.11 | $ | 0.95 | ||||
| Fiscal Year 2009: |
||||||||||||
| Revenues from continuing operations |
$ | 72,721 | $ | 45,517 | $ | 36,133 | $ | 36,285 | ||||
| Income from continuing operations (1) |
$ | 51,326 | $ | 31,292 | $ | 2,032 | $ | 8,158 | ||||
| Net income attributable to common stock |
$ | 30,920 | $ | 18,917 | $ | 848 | $ | 5,176 | ||||
| Net income per share (2): |
||||||||||||
| Basic: |
$ | 1.83 | $ | 1.14 | $ | 0.05 | $ | 0.33 | ||||
| Diluted: |
$ | 1.80 | $ | 1.12 | $ | 0.05 | $ | 0.32 | ||||
| (1) | Represents natural gas and oil sales, less operating expenses, exploration expenses, depreciation, depletion and amortization, lease expirations and relinquishments, impairment of natural gas and oil properties, general and administrative expense, and other income and expense before income taxes. |
| (2) | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share as each quarterly computation is based on the income for that quarter and the weighted average number of common shares outstanding during that quarter. |
F-27