Edgar Filing: CONTANGO OIL & GAS CO

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

MCF-2013.03.31-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013



¨	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)

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 ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 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 ý No ¨

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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

The total number of shares of common stock, par value $0.04 per share, outstanding as of May 8, 2013 was 15,194,952.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE NINE MONTHS ENDED MARCH 31, 2013

TABLE OF CONTENTS




		Page
	PART I—FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets (unaudited) as of March 31, 2013 and June 30, 2012	3
	Consolidated Statements of Operations (unaudited) for the three and nine months ended March 31, 2013 and 2012	4
	Consolidated Statements of Cash Flows (unaudited) for the nine months ended March 31, 2013 and 2012	5
	Consolidated Statement of Shareholders’ Equity (unaudited) for the nine months ended March 31, 2013	6
	Notes to the Unaudited Consolidated Financial Statements (unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40
Item 4.	Controls and Procedures	41

	PART II—OTHER INFORMATION
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 5.	Other Information	41
Item 6.	Exhibits	41

All references in this Form 10-Q to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and its wholly-owned subsidiaries. Unless otherwise noted, all information in this Form 10-Q 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.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2013			June 30, 2012
	(thousands)
CURRENT ASSETS:
Cash and cash equivalents	$	82,606		$	129,983
Accounts receivable:
Trade receivables	27,017			29,688
Joint interest billings	4,687			4,768
Income taxes	15,595			4,510
Other	566			242
Prepaid expenses	3,872			5,762
Inventory	2,516			260
Total current assets	136,859			175,213
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties	547,100			561,713
Unproved properties	36,732			12,485
Furniture and equipment	227			213
Accumulated depreciation, depletion and amortization	(208,066		)	(178,081		)
Total property, plant and equipment, net	375,993			396,330
OTHER ASSETS:
Investments in affiliates	59,894			52,827
Other	193			284
TOTAL ASSETS	$	572,939		$	624,654



CURRENT LIABILITIES:
Accounts payable	$	8,357		$	3,084
Royalties and revenue payable	22,206			22,098
Accrued liabilities	6,829			6,796
Accrued exploration and development	575			2,334
Total current liabilities	37,967			34,312

DEFERRED TAX LIABILITY	117,354			118,010
ASSET RETIREMENT OBLIGATIONS	9,820			7,993
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50,000,000 shares authorized; 20,135,107 shares issued and 15,194,952 outstanding at March 31, 2013; 20,135,107 shares issued and 15,292,448 outstanding at June 30, 2012	805			805
Additional paid-in capital	79,024			79,024
Treasury shares at cost (4,940,155 shares at March 31, 2013 and 4,842,659 shares at June 30, 2012)	(117,162		)	(112,207		)
Retained earnings	445,131			496,717
Total shareholders’ equity	407,798			464,339
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	572,939		$	624,654

The accompanying notes are an integral part of these consolidated financial statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended March 31,							Nine Months Ended March 31,
	2013				2012			2013			2012
				(thousands, except per share amounts)
REVENUES:
Natural gas, oil and liquids sales	$	31,787			$	41,339		$	96,493		$	139,449
Total revenues	31,787				41,339			96,493			139,449
EXPENSES:
Operating expenses	9,785				5,727			21,220			18,626
Exploration expenses	129				76			51,743			133
Depreciation, depletion and amortization	10,494				11,710			30,830			36,203
Impairment of natural gas and oil properties	—				—			14,078			—
General and administrative expenses	3,208				1,226			8,607			5,778
Total expenses	23,616				18,739			126,478			60,740

Loss from investments in affiliates, net of taxes	(1,147		)		—			(639		)	—
Other income/(expense)	141				42			(44		)	(86		)

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	7,165				22,642			(30,668		)	78,623
Income tax benefit (provision)	(3,296		)		(7,942		)	9,592			(28,748		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	3,869				14,700			(21,076		)	49,875
DISCONTINUED OPERATIONS (NOTE 8)
Discontinued operations, net of income taxes	—				(26		)	—			(821		)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	3,869			$	14,674		$	(21,076	)	$	49,054
NET INCOME (LOSS) PER SHARE:
Basic
Continuing operations	$	0.25			$	0.96		$	(1.38	)	$	3.23
Discontinued operations	—				—			—			(0.05		)
Total	$	0.25			$	0.96		$	(1.38	)	$	3.18
Diluted
Continuing operations	$	0.25			$	0.96		$	(1.38	)	$	3.23
Discontinued operations	—				—			—			(0.05		)
Total	$	0.25			$	0.96		$	(1.38	)	$	3.18
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic	15,195				15,357			15,229			15,453
Diluted	15,195				15,360			15,229			15,456

The accompanying notes are an integral part of these consolidated financial statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended March 31,
	2013			2012
	(thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) from continuing operations	$	(21,076	)	$	49,875
Loss from discontinued operations, net of income taxes	—			(821		)
Net income (loss)	(21,076		)	49,054
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	30,830			36,203
Impairment of natural gas and oil properties	14,078			1,031
Exploration expenses	51,445			—
Deferred income taxes	(2,049		)	(3,151		)
Loss from investment in affiliates	983			—
Loss on sale of assets	—			169
Tax benefit from exercise/cancellation of stock options	—			(254		)
Stock-based compensation	—			3
Changes in operating assets and liabilities:
Decrease in accounts receivable and other	2,670			10,023
Increase in prepaids and other receivables	(1,042		)	(1,750		)
Increase in inventory	(2,256		)	—
Increase (decrease) in accounts payable and advances from joint owners	5,462			(24,954		)
Increase (decrease) in other accrued liabilities	33			(3,067		)
Increase in income taxes receivable, net	(9,692		)	(6,578		)
Other	(626		)	(85		)
Net cash provided by operating activities	$	68,760		$	56,644
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	(73,249		)	(18,734		)
Advances under note receivable	—			(500		)
Repayment of note receivable	—			500
Investment in affiliates	(15,569		)	(11,234		)
Return of investments in affiliates	8,146			—
Additions to furniture and equipment	—			(35		)
Net cash used in investing activities	$	(80,672	)	$	(30,003	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid	(30,510		)	—
Purchase of common stock	(4,955		)	(17,000		)
Tax benefit from exercise/cancellation of stock options	—			254
Net cash used in financing activities	$	(35,465	)	$	(16,746	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(47,377		)	9,895
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	129,983			150,007
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	82,606		$	159,902
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes, net of cash received	$	1,800		$	38,035
Cash paid for interest	$	37		$	113

The accompanying notes are an integral part of these consolidated financial statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(Unaudited)



	Common Stock				Additional Paid-in Capital		Treasury Stock			Retained Earnings			Total Shareholders’ Equity
	Shares		Amount		Additional Paid-in Capital		Treasury Stock			Retained Earnings			Total Shareholders’ Equity
	(thousands)
Balance at June 30, 2012	15,292		$	805	$	79,024	$	(112,207	)	$	496,717		$	464,339
Net loss	—		—		—		—			(27,549		)	(27,549		)
Balance at September 30, 2012	15,292		$	805	$	79,024	$	(112,207	)	$	469,168		$	436,790

Treasury shares at cost	(97	)	—		—		(4,955		)	—			(4,955		)
Dividends	—		—		—		—			(30,510		)	(30,510		)
Net income	—		—		—		—			2,604			2,604
Balance at December 31, 2012	15,195		$	805	$	79,024	$	(117,162	)	$	441,262		$	403,929

Net income	—		—		—		—			3,869			3,869
Balance at March 31, 2013	15,195		$	805	$	79,024	$	(117,162	)	$	445,131		$	407,798

The accompanying notes are an integral part of this consolidated financial statement

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), including instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes included in Contango Oil & Gas Company’s ("Contango" or the "Company") Form 10-K for the fiscal year ended June 30, 2012. The consolidated results of operations for the three and nine months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2013.

2. Business

General

We are a Houston-based, independent natural gas and oil company. Our core business is to explore, develop, produce and acquire natural gas and oil properties onshore and offshore in the Gulf of Mexico in water-depths of less than 300 feet, using cash generated from our existing property base. We have no debt.

On April 30, 2013, we announced that we had signed a merger agreement with Crimson Exploration Inc. ("Crimson"), for an all-stock transaction pursuant to which Crimson would become a wholly owned subsidiary of the Company. Upon consummation of the merger, each share of Crimson stock will be converted into 0.08288 shares of Company stock resulting in Crimson stockholders owning 20.3% of the post-merger Company. This transaction is subject to shareholder approval and is expected to close in late-2013. See Note 12 - "Subsequent Events" for more information on the merger.

On November 29, 2012, the Board of the Company declared a special dividend of $2.00 per share of common stock which was paid on December 17, 2012 to each holder of record of the Company's common stock as of the close of business on December 10, 2012.

Operations

In late January 2013, we identified sustained casing pressure between the production tubing and the production casing at our Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a workover of the well. Well production was shut-in and the original tubing and completion assembly were successfully removed. Operations are underway to replace the tubing and restore the well to production. As of March 31, 2013, we had invested approximately $5.4 million on these workover operations which are included in operating expenses. We expect the well to resume production by the end of May 2013.

As of March 31, 2013, the Company had invested approximately $9.0 million in leasehold costs in the Tuscaloosa Marine Shale ("TMS") for approximately 24,000 acres, plus an additional $5.1 million to acquire acreage and a 25% non-operated working interest to drill a horizontal well with Goodrich Petroleum Company ("Goodrich") in the TMS. This well was successfully completed and is currently producing approximately 700 barrels of oil per day, with cumulative production of 65,000 barrels of oil through April 30, 2013.

During the nine months ended March 31, 2013, due to the decline in production and high water levels from our Ship Shoal 263 well, our reservoir engineer revised his estimated net proved natural gas and oil reserves from this well. As a result, the net book value of our Ship Shoal 263 well exceeded the future undiscounted cash flows associated with its reserves. Accordingly, the Company recognized an impairment expense of approximately $12.0 million for the nine months ended March 31, 2013. No impairment was recognized for the three months ended March 31, 2013.

In July 2012, we unsuccessfully drilled two exploration prospects at Ship Shoal 134 ("Eagle") and South Timbalier 75 ("Fang"), and found no commercial hydrocarbons. For the nine months ended March 31, 2013, we recorded exploration expenses of approximately $50.0 million, including leasehold costs, related to these two wells.

Investments

As of March 31, 2013, we had invested approximately $14.1 million in Alta Resources Investments, LLC ("Alta Energy"), whose primary area of focus is the liquids-rich Kaybob Duvernay in Alberta, Canada. We had also invested approximately $46.9 million in Exaro Energy III LLC ("Exaro"), which is primarily focused on the development of proved reserves in the Jonah Field in Wyoming.

3. Summary of Significant Accounting Policies

The application of GAAP involves certain assumptions, judgments, decisions and estimates that affect reported amounts of assets, liabilities, revenues, expenses, contingencies and reserves. Actual results could differ from these estimates. Contango’s significant accounting policies are described below.

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. 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. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above. 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 costs amortized over proved developed reserves.

Impairment of Long-Lived Assets. When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future net cash flows on a field by field 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. No impairment of proved properties was recognized during the three months ended March 31, 2013. For the nine months ended March 31, 2013, we recorded an impairment expense of approximately $14.1 million related to proved properties. Of this amount, approximately $12.0 million related to our Ship Shoal 263 well and $2.1 million related to the Eugene Island 24 platform and other properties. Despite the writedowns on Ship Shoal 263, this well reached payout during fiscal year 2012. No impairment of proved properties was recognized in continuing operations for the three or nine months ended March 31, 2012.

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. No impairment of unproved properties was recognized during the three months ended March 31, 2013. For the nine months ended March 31, 2013, the Company recognized impairment expense of approximately $1.4 million related to an unsuccessful exploration program in Jim Hogg County, Texas and $6.6 million related to leasehold costs at our dry holes at Ship Shoal 134 and South Timbalier 75. These costs are all included in exploration expenses. No impairment of unproved properties was recognized during the three or nine months ended March 31, 2012.

Cash Equivalents. Cash equivalents are considered to be highly liquid investment grade investments having an original maturity of 90 days or less. As of March 31, 2013, the Company had approximately $82.6 million in cash and cash equivalents, the vast majority of which was held in non-interest bearing accounts.

Principles of Consolidation. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries and affiliates, after elimination of all significant intercompany balances and transactions. Wholly-owned subsidiaries are consolidated. Exploration and development affiliates not wholly owned, such as 32.3% owned Republic Exploration, LLC (“REX”), are not controlled by the Company and are proportionately consolidated in the Company’s financial statements.

Other Investments. The Company's 2.0% ownership interest in Alta Energy is accounted for using the cost method. The Company also has a 37% ownership interest in Exaro. The Company has two seats on the board of directors of Exaro, and has significant influence, but not control, over Exaro. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method.

The Company originally had a 45% ownership interest in Exaro upon its formation in April 2012. In August 2012, one of the other investors in Exaro exercised its right to assume $15 million of the Company's commitment by making a cash payment to the Company of $7.5 million and agreeing to assume $7.5 million of the Company's future commitment in Exaro. This reduced the Company's ownership interest to 37%. As of March 31, 2013, the Company had invested approximately $46.9 million in Exaro.

Reclassifications. Certain reclassifications have been made to the amounts included in the consolidated financial statements as of June 30, 2012 and for the three and nine months ended March 31, 2012, in order to conform to the presentation as of and for the three and nine months ended March 31, 2013. These reclassifications were not material.

4. 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 the Company's 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.

5. 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 and oil for the three and nine months ended March 31, 2013 were ConocoPhillips Company, Shell Trading US Company, Exxon Mobil Oil Corporation, Enterprise Products Operating LLC, Crosstex Energy Services, and Trans Louisiana Gas Pipeline, Inc. 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, but there currently are numerous other potential purchasers of our production.

6. Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per share of common stock is presented below:



	Three Months Ended March 31, 2013					Three Months Ended March 31, 2012
	Income		Shares	Per Share		Income (loss)			Shares	Per Share
	(thousands, except per share amounts)
Net income from continuing operations	$	3,869	15,195	$	0.25	$	14,700		15,357	$	0.96
Discontinued operations, net of income tax	—		15,195	—		(26		)	15,357	—
Basic Earnings per Share:
Net income attributable to common stock	$	3,869	15,195	$	0.25	$	14,674		15,357	$	0.96
Effect of potential dilutive securities:
Stock options, net of shares assumed purchased	—		—			—			3
Net income from continuing operations	$	3,869	15,195	$	0.25	$	14,700		15,360	$	0.96
Discontinued operations, net of income tax	—		15,195	—		(26		)	15,360	—
Diluted Earnings per Share:
Net income attributable to common stock	$	3,869	15,195	$	0.25	$	14,674		15,360	$	0.96



	Nine Months Ended March 31, 2013							Nine Months Ended March 31, 2012
	Loss			Shares	Per Share			Income (loss)			Shares	Per Share
	(thousands, except per share amounts)
Net income (loss) from continuing operations	$	(21,076	)	15,229	$	(1.38	)	$	49,875		15,453	$	3.23
Discontinued operations, net of income tax	—			15,229	—			(821		)	15,453	(0.05		)
Basic Earnings per Share:
Net income (loss) attributable to common stock	$	(21,076	)	15,229	$	(1.38	)	$	49,054		15,453	$	3.18
Effect of potential dilutive securities:
Stock options, net of shares assumed purchased	—			—				—			3
Net income (loss) from continuing operations	$	(21,076	)	15,229	$	(1.38	)	$	49,875		15,456	$	3.23
Discontinued operations, net of income tax	—			15,229	—			(821		)	15,456	(0.05		)
Diluted Earnings per Share:
Net income (loss) attributable to common stock	$	(21,076	)	15,229	$	(1.38	)	$	49,054		15,456	$	3.18

7. Credit Facility

In October 2010, the Company obtained a $40 million secured revolving credit agreement with Amegy Bank (the “Credit Agreement”). The Credit Agreement is supported by a hydrocarbon borrowing base and is available to fund the Company’s exploration and development activities, as well as repurchase shares of common stock, pay dividends and fund working capital as needed. The Credit Agreement is secured by substantially all of the assets of the Company. Borrowings under the Credit Agreement bear interest at LIBOR plus 2.5%, subject to a LIBOR floor of 0.75%. The principal is due October 1, 2014, and may be prepaid at any time with no prepayment penalty. An arrangement fee of $300,000 was paid in connection with the facility and effective November 1, 2011, a commitment fee of 0.125% is owed on unused borrowing capacity. The Credit Agreement contains customary covenants including limitations on our current ratio of assets to liabilities and additional indebtedness. As of March 31, 2013, the Company was in compliance with all covenants and had no borrowings outstanding under the Credit Agreement.

8. Discontinued Operations

In May 2011, the Company sold its 100% working interest (72.5% net revenue interest) in Rexer #1 and its 75% working interest (54.4% net revenue interest) in Rexer-Tusa #2 to Patara Oil & Gas LLC (“Patara”). B.A. Berilgen, a member of the Company’s board of directors, was the Chief Executive Officer of Patara at the time of the sale. In October 2011, the Company sold its remaining 25% working interest (18.4% net revenue interest) in Rexer-Tusa #2 to Patara. The sale was effective October 1, 2011. The Company has accounted for the sale of Rexer #1 and Rexer-Tusa #2 as discontinued operations beginning with the three months ended December 31, 2011 and reclassified the results of operations for these two wells, along with other minor assets sold to Patara, to discontinued operations for all periods presented as follows :



	Three Months Ended March 31, 2012			Nine Months Ended March 31, 2012
	(in thousands)
Results of Operations:
Revenues	$	(40	)	$	6
Operating expenses				(43		)
Exploration expenses				(7		)
Impairment of natural gas and oil properties				(1,031		)
Loss on sale of discontinued operations				(188		)
Loss before income taxes	(40		)	(1,263		)
Income tax benefit	14			442
Loss from discontinued operations, net of income taxes	$	(26	)	$	(821	)

9. Income Taxes

The Company’s income tax provision for continuing operations consists of the following (in thousands):



	Three Months Ended March 31,						Nine Months Ended March 31,
	2013			2012			2013			2012
Current tax provision (benefit):
Federal	$	2,036		$	10,500		$	(9,612	)	$	28,638
State	540			1,040			1,725			2,841
Total	$	2,576		$	11,540		$	(7,887	)	$	31,479
Deferred tax provision (benefit):
Federal	$	319		$	(3,403	)	$	(1,580	)	$	(2,327	)
State	(216		)	(195		)	(469		)	(404		)
Total	$	103		$	(3,598	)	$	(2,049	)	$	(2,731	)
Total tax provision (benefit):
Federal	$	2,355		$	7,097		$	(11,192	)	$	26,311
State	324			845			1,256			2,437
Total	$	2,679		$	7,942		$	(9,936	)	$	28,748

Of the total tax provision for the three and nine months ended March 31, 2013, approximately $617,000 and $344,000 of deferred income tax benefit are included in the loss from affiliates line item in the Company's Consolidated Statements of Operations.

10. Related Party Transactions

Juneau Exploration L.P. In April 2012, the Company announced that Mr. Brad Juneau, the sole manager of the general partner of Juneau Exploration, L.P. ("JEX"), had joined the Company’s board of directors and that the Company had entered into an advisory agreement with JEX (the "Advisory Agreement"), whereby in addition to generating and evaluating offshore and onshore exploration prospects for the Company, JEX would direct Contango’s staff on operational matters including drilling, completions and production. Pursuant to the Advisory Agreement, JEX was paid an annual fee of $2.0 million.

Effective January 1, 2013, the Advisory Agreement was terminated, and the Company and JEX entered into a First Right of Refusal Agreement (the "First Right Agreement"). Under the First Right Agreement, JEX granted a first right of refusal to Contango to purchase any exploration prospects generated and recommended by JEX. Prospects would be presented along with terms and conditions for purchasing each prospect and Contango would have the first right of refusal to purchase the prospect from JEX for a period of 10 days, subject to mutually acceptable terms. Pursuant to the First Right Agreement, JEX would be paid an annual fee of $0.5 million, which approximated the costs incurred by JEX for their continued support to the Company in the areas of operations, engineering, and land functions. Effective as of March 31, 2013, the First Right Agreement was terminated.

Effective January 1, 2013, Contaro Company, a wholly-owned subsidiary of the Company, entered into an advisory agreement with JEX (the "Contaro Advisory Agreement"). Under the Contaro Advisory Agreement, JEX will provide advisory services to Contaro in connection with Contaro's investment in Exaro, and Mr. Juneau will serve on the board of managers of Exaro and perform such duties as described in the limited liability company operating agreement of Exaro. Pursuant to the Contaro Advisory Agreement, JEX will be paid a monthly fee of $10,000 and shall be entitled to receive a one percent (1%) fee of the cash profit earned by Contaro. Cash profit is defined as the amount of cash received by Contango as a result of its investment in Contaro, less the cash invested by the Company as a result of its investment in Contaro.

In August 2012, the Company's founder, Chairman and Chief Executive Officer, Mr. Kenneth R. Peak, took a medical leave of absence and the Board of Directors of the Company appointed Mr. Juneau as President and Acting Chief Executive Officer of the Company. In December 2012, Mr. Joseph J. Romano was elected President and Chief Executive Officer of the Company. Mr. Peak passed away on April 19, 2013 and Mr. Romano was named Chairman of the Company. Mr. Romano is also the President and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic").

JEX and JEX affiliates and Olympic have historically participated with the Company in the drilling and development of certain prospects through participation agreements and joint operating agreements, which specify each participant’s working interest ("WI"), net revenue interest ("NRI"), and describe when such interests are earned, as well as allocate an overriding

royalty interest ("ORRI") of up to 3.33% to benefit the employees of JEX, excluding Mr. Juneau, except where otherwise noted. Olympic last participated with the Company in the drilling of wells in March 2010, and does not anticipate participating in any future wells. Olympic's ownership in Company-operated wells is limited to our Dutch and Mary Rose wells.

Republic Exploration LLC. In his capacity as sole manager of the general partner of JEX, Mr. Juneau also controls the activities of REX, an entity owned 34.4% by JEX, 32.3% by Contango, and 33.3% by a third party which contributed other assets to REX. REX generates and evaluates offshore exploration prospects and has historically participated with the Company in the drilling and development of certain prospects through participation agreements and joint operating agreements, which specify each participant’s working interest, net revenue interest, and describe when such interests are earned, as well as allocate an overriding royalty interest ("ORRI") of up to 3.33% to benefit the employees of JEX. The Company proportionately consolidates the results of REX in its consolidated financial statements.

As of March 31, 2013, Contango, Olympic, JEX, REX and JEX employees owned the following interests in the Company's offshore wells.



	Contango				Olympic				JEX				REX				JEX Employees
	WI		NRI		WI		NRI		WI		NRI		WI		NRI		ORRI
Dutch #1 - #5	47.05	%	38.12	%	3.02	%	2.42	%	1.61	%	1.29	%	—	%	—	%	2.02%
Mary Rose #1	53.21	%	40.45	%	3.61	%	2.7	%	2.01	%	1.51	%	—	%	—	%	2.79%
Mary Rose #2 - #3	53.21	%	38.67	%	3.61	%	2.58	%	2.01	%	1.44	%	—	%	—	%	2.79%
Mary Rose #4	34.58	%	25.49	%	2.34	%	1.7	%	1.31	%	0.95	%	—	%	—	%	1.82%
Mary Rose #5	37.80	%	27.88	%	2.56	%	1.87	%	1.43	%	1.04	%	—	%	—	%	1.54%
Ship Shoal 263	100.00	%	80.00	%	—	%	—	%	—	%	—	%	—	%	—	%	3.33%
Vermilion 170	83.20	%	64.83	%	—	%	—	%	4.30	%	3.35	%	12.50	%	9.74	%	3.33%

Below is a summary of payments received from (paid to) Olympic, JEX and REX in the ordinary course of business in our capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types of payments with other well owners (in thousands):



	Three months ended March 31,
	2013									2012
	Olympic			JEX			REX			Olympic			JEX			REX
Revenue payments as well owners	$	(1,650	)	$	(1,195	)	$	(850	)	$	(2,037	)	$	(1,611	)	$	(1,455	)
Joint interest billing receipts	286			197			115			207			188			179



	Nine months ended March 31,
	2013									2012
	Olympic			JEX			REX			Olympic			JEX			REX
Revenue payments as well owners	$	(4,700	)	$	(3,418	)	$	(2,440	)	$	(6,652	)	$	(4,323	)	$	(1,903	)
Joint interest billing receipts	814			617			436			887			691			2,037

Below is a summary of payments received from (paid to) Olympic, JEX and REX as a result of specific transactions between the Company, Olympic, JEX and REX. While these payments are in the ordinary course of business, the Company did not have similar transactions with other well owners (in thousands):



	Three months ended March 31,
	2013								2012
	Olympic		JEX			REX			Olympic		JEX			REX
Reimbursement of certain costs	$	—	$	(171	)	$	(4	)	$	—	$	(36	)	$	(9	)
Payments under First Right Agreement and Contaro Advisory Agreement	—		(155		)	—			—		(30		)	—



	Nine months ended March 31,
	2013								2012
	Olympic		JEX			REX			Olympic			JEX			REX
Reimbursement of certain costs	$	—	$	(573	)	$	(4	)	$	(10	)	$	(42	)	$	(20	)
Prospect fees	—		—			—			—			(250		)	—
Payments under Advisory Agreement, First Right Agreement and Contaro Advisory Agreement	—		(1,155		)	—			—			(30		)	—
REX distribution to members	—		—			646			—			—			—

As of March 31, 2013 and June 30, 2012, the Company's consolidated balance sheets included the following balances (in thousands):



	March 31, 2013									June 30, 2012
	Olympic			JEX			REX			Olympic			JEX			REX
Accounts receivable:
Trade receivables	$	5		$	5		$	5		$	10		$	20		$	18
Joint interest billings	218			412			808			192			158			92

Accounts payable:
Royalties and revenue payable	(1,236		)	(679		)	(9		)	(1,198		)	(813		)	(682		)
Other - Prospect Fees	—			(500		)	—			—			—			—

In addition to the above, the Company paid Mr. Brad Juneau $28,000 and $112,000 during the three and nine months ended March 31, 2013 for his services as a director of the Company.

11. Share Repurchase Programs

$100 Million Share Repurchase Program

In September 2008, the Board approved a $100 million share repurchase program. All shares were purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases were 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 became authorized but unissued shares, and may be issued in the future for general corporate and other purposes.

During the nine months ended March 31, 2012, the Company purchased 271,837 shares at an average price of $55.38 per share, for a total of approximately $15.1 million. The $100 million share repurchase program concluded in October 2011.

$50 Million Share Repurchase Program

In September 2011, the Board approved a $50 million share repurchase program, effective upon completion of purchases under the Company’s $100 million share repurchase program. The purchases made under the $50 million share repurchase program are subject to the same terms and conditions as purchases made under the $100 million share repurchase program. No shares were purchased during the three months ended March 31, 2013. During the nine months ended March 31, 2013, the Company purchased 97,496 shares at an average price of $50.82 per share, for a total of approximately $5.0 million. During the three months ended March 31, 2012, the Company purchased 45,000 stock options for approximately $0.5 million. During the nine months ended March 31, 2012, the Company purchased 35,663 shares at an average price of $54.58 per share, for a total of approximately $1.9 million.

As of March 31, 2013, under both share repurchase programs combined, the Company had purchased approximately 2.4 million shares of its common stock at an average cost per share of $46.84, and 45,000 stock options, for a total of approximately $110.8 million, bringing its total share count as of March 31, 2013 to 15,194,952 shares of common stock outstanding.

12. Subsequent Events

Merger with Crimson Exploration, Inc.

On April 29, 2013, the Company and Crimson entered into an Agreement and Plan of Merger (the “Merger Agreement”), pursuant to which Crimson will become a wholly owned subsidiary of the Company (the "Merger").

Subject to the terms and conditions of the Merger Agreement, each share of Crimson common stock will be converted into 0.08288 shares of common stock of the Company. The Merger is intended to qualify as a tax-free reorganization for U.S. federal income tax purposes, so that none of the Company, Crimson, Merger Sub or Crimson's stockholders will recognize any gain or loss in the Merger, except that Crimson's stockholders may recognize gain or loss with respect to cash received in lieu of fractional shares of Company common stock.

The closing of the Merger is subject to the satisfaction or waiver of certain customary conditions, including, among others, (i) the adoption of the Merger Agreement by Crimson's stockholders; (ii) the approval by the Company's stockholders of the issuance of Company common stock in the Merger to Crimson's stockholders; (iii) the registration statement on Form S-4 used to register the Company common stock to be issued in the Merger being declared effective by the Securities and Exchange Commission (the “SEC”); (iv) the approval for listing on the New York Stock Exchange of the Company common stock to be issued in the Merger; (v) subject to specified materiality standards, the accuracy of the representations and warranties of, and the performance of all covenants by, the parties; (vi) the absence of a material adverse effect with respect to each of Crimson and the Company; and (vii) the delivery of tax opinions that the Merger will be treated as a “reorganization” within the meaning of Section 368(a) of the Internal Revenue Code.

The Company has agreed that, upon the Closing, it will cause the Board of Directors to consist of eight directors, three of whom will be appointed by the board of directors of Crimson and five of whom will be appointed by Contango's Board of Directors. Additionally, Joseph J. Romano (the current Chairman, President and Chief Executive Officer of the Company) will serve as Chairman of the Board, Allan D. Keel (the current President and Chief Executive Officer of Crimson) will serve as President and Chief Executive Officer of the Company, and E. Joseph Grady (the current Senior Vice President and Chief Financial Officer of Crimson) will serve as Senior Vice President and Chief Financial Officer of the Company. Messrs. Keel and Grady entered into employment agreements with the Company that become effective upon the consummation of the Merger. The combined company will have its headquarters and principal corporate office in Houston, Texas.

In connection with the execution of the Merger Agreement, the Company concurrently entered into a Stockholder Support and Irrevocable Proxy Agreement with each of (a) OCM Crimson Holdings, LLC and OCM GW Holdings, LLC (collectively, “Oaktree”) and (b) Allan D. Keel, E. Joseph Grady, A. Carl Isaac, Jay S. Mengle, Thomas H. Atkins and John A. Thomas, each of whom is an executive officer of Crimson, (collectively, the “Crimson Support Agreements”). The shares of Crimson common stock outstanding that are beneficially owned by Oaktree and such executive officers of Crimson and are subject to the Crimson Support Agreements represent, in the aggregate, approximately 38.8% of Crimson's outstanding common stock as of April 29, 2013. Pursuant to the Crimson Support Agreements, Oaktree and each signatory executive officer of Crimson agrees to vote the shares it beneficially owns (i) in favor of the Merger and the Merger Agreement and (ii) against (a) any other acquisition proposal, (b) any liquidation, dissolution, recapitalization, extraordinary dividend or other significant corporate reorganization of Crimson, and (c) any other action, proposal or agreement that would reasonably be expected to interfere with or delay the consummation of the Merger. The Crimson Support Agreements terminate at the earliest of the effective time of the Merger, the termination of the Merger Agreement in accordance with its terms or any reduction of the Merger Consideration.

Additionally, in connection with the execution of the Merger Agreement, Crimson concurrently entered into a Stockholder Support Agreement (collectively, the “Company Support Agreements”) with the Estate of Kenneth R. Peak, Joseph J. Romano, Brad Juneau, Sergio Castro and Yaroslava Makalskaya who, in the aggregate, beneficially own approximately 10.6% of the Company's outstanding common stock as of April 29, 2013. Pursuant to the Company Support Agreements, the Estate of Kenneth R. Peak and each signatory executive officer and director of the Company agrees to vote their shares of the Company's common stock in favor of the Merger and against any other acquisition proposal.

The foregoing descriptions of the Merger Agreement and related agreements are qualified in their entirety by reference to the full text of such agreements, which are attached as exhibits to the Company's report on Form 8-K, dated as of April 30, 2012, as filed with the SEC.

Investments

As of March 31, 2013, the Company had invested approximately $14.1 million in Alta Energy to drill in the Kaybob Duvernay shale in Alberta, Canada. From April 1, 2013 through May 8, 2013, we invested an additional $0.8 million, bringing the Company's total investment in Alta Energy to approximately $14.9 million.

Available Information

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”).

Item 2. 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 consolidated financial statements and the accompanying notes and other information included elsewhere in this Form 10-Q and in our Form 10-K for the fiscal year ended June 30, 2012, previously filed with the SEC.

Executive Overview

Contango Oil & Gas Company (“Contango” or the “Company”) is a Houston-based, independent natural gas and oil company. Our core business is to explore, develop, produce and acquire natural gas and oil properties onshore and offshore in the Gulf of Mexico in water-depths of less than 300 feet, using cash generated from our existing property base. We have no debt.

On April 19, 2013, the Company's founder and former Chairman, President and Chief Executive Officer, Mr. Kenneth R. Peak, passed away at the age of 67. Mr. Peak was diagnosed with an inoperable brain tumor in August 2012 that he was no longer able to battle. The Company holds a $10 million life insurance policy for Mr. Peak and received the proceeds of such policy in early May 2013.

On April 30, 2013, the Company announced that it had signed a merger agreement with Crimson Exploration Inc. ("Crimson"), for an all-stock transaction pursuant to which Crimson would become a wholly owned subsidiary of Contango. Upon consummation of the merger, each share of Crimson stock will be converted into 0.08288 shares of Contango stock resulting in Crimson stockholders owning 20.3% of the post-merger Contango. This transaction is subject to shareholder approval of both Contango and Crimson and is expected to close by October 2013.

As of May 8, 2013, we had approximately $92.3 million of cash, $40.0 million of unused borrowing capacity, and no debt.

Investments Summary

As of May 8, 2013, we had invested approximately $14.9 million in Alta Resources Investments, LLC ("Alta Energy") whose primary area of focus is the liquids-rich Kaybob Duvernay in Alberta, Canada, where we have approximately a 5% ownership interest. We have also invested approximately $46.9 million in Exaro Energy III LLC ("Exaro") for a 37% ownership interest in Exaro, whose primary area of focus is the development of proved reserves in the Jonah Field in Wyoming.

Operations Summary

The Company has invested $5.1 million as a 25% working interest owner in the Crosby 12H-1, a well operated by Goodrich Petroleum Company LLC ("Goodrich") in the Tuscaloosa Marine Shale (“TMS”), an oil focused shale play in central Louisiana and Mississippi. As of May 6, 2013 the Crosby 12H-1 was producing at an 8/8ths rate of approximately 700 barrels of oil per day, with cumulative production of 65,000 barrels of oil through April 30, 2013. Additionally, we have invested approximately $9.0 million in leasehold costs for approximately 24,000 acres in the TMS. The data we obtain from the Goodrich well will help us evaluate our TMS acreage and develop a plan for drilling and operating future wells.

In late January 2013, we identified sustained casing pressure between the production tubing and the production casing at our Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a workover of the well. Well production was shut-in and the original tubing and completion assembly were successfully removed. Operations are underway to replace the tubing and restore the well to production. As of March 31, 2013 we had expended approximately $5.4 million on these workover operations. We expect the well to resume production by the end of May 2013.

Exploration Program Summary

In March 2013, the Company announced that it was the apparent high bidder on three lease blocks, representing two prospects, at the Central Gulf of Mexico Lease Sale 227 held on March 20, 2013. The Company bid a total of approximately $1.7 million on Eugene Island 23, Ship Shoal 52 and Ship Shoal 59. An apparent high bid (“AHB”) is subject to Outer Continental Shelf (“OCS”) Bid Adequacy Review, notwithstanding the fact that the Bureau of Ocean Energy Management

(“BOEM”) may reject all bids for a given tract. The BOEM review process can take up to 90 days. Upon approval from the BOEM, our plan is to promptly seek permits to drill these prospects in 2014. A deposit of $0.3 million has been paid to the BOEM for these leases and is included in prepaid expenses in the Company's Consolidated Balance Sheets. The remaining funds will be paid upon awarding of the leases.

In March 2013, the Company signed a Letter of Intent with a third-party independent oil and gas company to purchase an offshore block in state of Louisiana waters. The permitting process is underway and we expect to be able to spud this well in mid-2013 at an estimated cost of $6.5 million, net to Contango. Under the terms of the participation agreements, Contango will have a 75% working interest before payout. Once payout of all costs is reached, Republic Exploration, LLC ("REX") will have an option to back-in for a 9.4% working interest, the seller will have an option to back-in for a 9.4% working interest, and Contango will have a 56.2% working interest.

In December 2012, the Company was awarded the sixth and final lease bid on at the Central Gulf of Mexico Lease Sale 216/222 held in June 2012. The Company bid an aggregate amount of approximately $11 million on six blocks. We have submitted an exploration permit for the first of these blocks, Ship Shoal 255, and have budgeted to spud this well in late-2013 at an estimated cost of $22.5 million, net to Contango.

On July 3, 2012, we spud our Ship Shoal 134 prospect ("Eagle") with the Hercules 205 rig. On October 19, 2012, we announced that we had reached total depth on Eagle and no commercial hydrocarbons were found. The Company has plugged and abandoned this well. For the nine months ended March 31, 2013, we incurred approximately $28.9 million to drill, plug and abandon this well, including approximately $6.3 million in leasehold costs.

On July 10, 2012 we spud our South Timbalier 75 prospect ("Fang") with the Spartan 303 rig. On October 30, 2012, we announced that we had reached total depth on Fang and no commercial hydrocarbons were found. The Company has plugged and abandoned this well. For the nine months ended March 31, 2013, we incurred approximately $21.1 million to drill, plug and abandon this well, including approximately $0.3 million in leasehold costs. This prospect was a farm-in and the lease was never earned as a result of the dry hole.

Asset Impairments

Our exploration strategy is predicated upon the belief that the only competitive advantage in the commodity-based natural gas and oil business is to be among the lowest cost producers. 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 exploration of i) offshore Gulf of Mexico prospects and ii) conventional and unconventional onshore plays. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success.

Exploration Alliance with JEX

JEX is a private company formed for the purpose of generating offshore and onshore domestic natural gas and oil prospects for the Company, either directly, or via our 32.3% owned affiliated company, Republic Exploration LLC (“REX”) (see “Offshore Gulf of Mexico Exploration Joint Ventures” below). In addition to generating prospects, JEX occasionally evaluates exploration prospects generated by third-party independent companies. Once we agree to a prospect from JEX, REX or a third-party, we enter into a participation agreement and joint operating agreement specifying each participant’s working interest, net revenue interest, and description of when such interests are earned, as well as allocating an overriding royalty interest of up to 3.33% to benefit employees of JEX.

On April 10, 2012, the Company announced that Mr. Brad Juneau, the sole manager of the general partner of JEX, had joined the Company’s board of directors and that the Company had entered into an advisory agreement with JEX (the "Advisory Agreement"), whereby in addition to generating and evaluating offshore and onshore exploration prospects for the

Company, JEX would direct Contango’s staff on operational matters including drilling, completions and production. Pursuant to the Advisory Agreement, JEX was paid an annual fee of $2.0 million.

Effective January 1, 2013, the Advisory Agreement was terminated, and the Company and JEX entered into a First Right of Refusal Agreement (the "First Right Agreement"). Under the First Right Agreement, JEX granted a first right of refusal to Contango to purchase any exploration prospects generated and recommended by JEX. Prospects would be presented along with terms and conditions for purchasing each prospect and Contango would have the first right of refusal to purchase the prospect from JEX for a period of 10 days, subject to mutually acceptable terms. Pursuant to the First Right Agreement, JEX would be paid an annual fee of $0.5 million which approximated the costs incurred by JEX for their continued support to the Company in the areas of operations, engineering, and land functions. JEX and its employees would continue to be eligible to receive overriding royalty interests, carried interests and certain back-in rights. The First Right Agreement was terminated effective as of March 31, 2013.

Effective January 1, 2013, Contaro Company, a wholly-owned subsidiary of the Company, entered into an advisory agreement with JEX (the "Contaro Advisory Agreement"). Under the Contaro Advisory Agreement, JEX will provide advisory services to Contaro in connection with Contaro's investment in Exaro, and Mr. Juneau will serve on the Board of Managers of Exaro and perform such duties as described in the limited liability company operating agreement of Exaro. Pursuant to the Contaro Advisory Agreement, JEX will be paid a monthly fee of $10,000 and shall be entitled to receive a one percent (1%) fee of the cash profit earned by Contaro. Cash profit is defined as the amount of cash received by Contango as a result of its investment in Contaro, less the cash invested by the Company as a result of its investment in Contaro.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango, through its wholly-owned subsidiary Contango Operators, Inc. ("COI"), and its partially-owned subsidiary REX, conducts exploration activities in the Gulf of Mexico. As of May 8, 2013, Contango, through COI and REX, had an interest in 15 offshore leases. See “Offshore Properties” for additional information on our offshore properties.

Contango Operators, Inc.

COI acquires leasehold acreage, drills and operates our wells in the Gulf of Mexico. Additionally, COI may acquire significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, under farm-out agreements, or similar agreements, with REX, JEX and/or third parties.

As of May 7, 2013, the Company’s offshore production was approximately 58.5 Mmcfed, net to Contango, which consists of seven federal and five state of Louisiana wells in the shallow waters of the Gulf of Mexico. These 12 operated wells produce through the following three platforms:

Eugene Island 11 Platform

Our Company-owned and operated production platform at Eugene Island 11 was designed with a capacity of 500 Mmcfd and 6,000 bopd. In September 2010 the Company installed a companion platform and two pipelines adjacent to the Eugene Island 11 platform to be able to access alternate markets. These platforms service production from the Company’s five Dutch wells in federal waters and five Mary Rose wells in state of Louisiana waters. From these platforms, gas and condensate can 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 there to third-party owned and operated on-shore processing facilities near Patterson, Louisiana, via an ANR pipeline.

Alternatively, gas can flow to the American Midstream pipeline via our 8” pipeline, which has been designed with a capacity of 80 Mmcfd, and from there to a third-party owned and operated on-shore processing facility at Burns Point, Louisiana. Condensate can also flow via an ExxonMobil pipeline to on-shore markets and multiple refineries. As of May 7, 2013, we were producing approximately 57.9 Mmcfed, net to Contango, from this platform.

Based on production and decline rates, the Company has determined the need to place its Dutch and Mary Rose wells on compression in late-2013. The Company is in the process of building a large turbine type compressor for the platform at an estimated cost of $9.2 million, net to Contango. This compressor will be of sufficient capacity to service all ten of the Company's Dutch and Mary Rose wells. As of March 31, 2013, the Company had incurred approximately $6.7 million to design and build the compressor.

Ship Shoal 263 Platform

Our Company-owned and operated platform at Ship Shoal 263 was designed with a capacity of 40 Mmcfd and 5,000 bopd. This platform services natural gas and condensate production from our Ship Shoal 263 well, which both flow via the Transcontinental Gas Pipeline to onshore processing plants. As of May 7, 2013, we were producing approximately 0.6 Mmcfed, net to Contango, from this platform. We believe this well may be fully depleted in the next twelve months. The well reached payout during fiscal year 2012. We will continue producing this well as long as it is economical.

Should we have a discovery at our Ship Shoal 255 prospect, we will transport the new production to this platform. We have therefore reclassified the platform to unproved properties as of March 31, 2013.

Vermilion 170 Platform

Our Company-owned and operated platform at Vermilion 170 was designed with a capacity of 60 Mmcfd and 2,000 bopd. This platform services natural gas and condensate production from our Vermilion 170 well which began producing in September 2011. The production flows via the Sea Robin Pipeline to onshore processing plants. Based on production and decline rates, the Company has determined the need to place its Vermilion 170 well on compression, at a cost of $1.4 million, net to Contango. As of March 31, 2013, the Company had incurred all of the $1.4 million to install the compressor, which we expect to begin operating in mid-2013. Since late January 2013, the well has been temporarily shut-in for workover operations. We expect the well to resume production by the end of May 2013.

Republic Exploration LLC

In his capacity as sole manager of the general partner of JEX, Mr. Juneau also controls the activities of REX, an entity owned 34.4% by JEX, 32.3% by Contango, and 33.3% by a third party which contributed other assets to REX. REX generates and evaluates offshore exploration prospects for the Company and has historically participated with the Company in the drilling and development of certain prospects through participation agreements and joint operating agreements, which specify each participant's working interest, net revenue interest, and describe when such interests are earned, as well as allocate an overriding royalty interest ("ORRI") of up to 3.33% to benefit the employees of JEX. The Company proportionately consolidates the results of REX in its consolidated financial statements. In April 2013, REX sold its 25% working interest in West Delta 36 to another partner in that well.

Offshore Properties

Producing Properties. The following table sets forth the interests owned by Contango through its affiliated entities in the Gulf of Mexico which were capable of producing natural gas or oil as of May 8, 2013:



Area/Block	WI		NRI		Status
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 (Dutch #5)	47.05	%	38.1	%	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 & S-L 19261 (Mary Rose #5)	37.80	%	27.6	%	Intermittent
Ship Shoal 263 (Nautilus)	100.00	%	80.0	%	Producing
Vermilion 170 (Swimmy)	87.24	%	68.0	%	Workover

Leases. The Company has recently relinquished South Timbalier 97, and Ship Shoal 121. The following table sets forth the working interests owned by Contango and affiliated entities in non-developed leases in the Gulf of Mexico as of May 8, 2013.



Area/Block	WI		Lease Date	Expiration Date
East Breaks 369 (Dry Hole)	(1	)	Dec-03	Dec-13
Brazos Area 543	100.00	%	Mar-12	Mar-17
East Cameron 124	100.00	%	Sept-12	Sept-17
Eugene Island 31	100.00	%	Oct-12	Oct-17
Ship Shoal 83	100.00	%	Oct-12	Oct-17
South Timbalier 110	100.00	%	Oct-12	Oct-17
Eugene Island 260	100.00	%	Nov-12	Nov-17
Ship Shoal 255	100.00	%	Dec-12	Dec-17


(1)	Farm-out. COI retains a 2.41% ORRI

Onshore Exploration and Properties

Kaybob Duvernay - Alberta, Canada

In April 2011, the Company announced a commitment to invest up to $20 million in Alta Energy, a venture that will acquire, explore, develop and operate onshore unconventional oil and natural gas shale assets in North America. As of May 8, 2013, we had invested approximately $14.9 million in Alta Energy to lease approximately 68,000 acres in the Kaybob Duvernay, a liquids rich shale play in Alberta, Canada. Alta Energy has built a large acreage block in the core of the play. As of May 8, 2013, Alta Energy had drilled four vertical test wells and taken whole cores on two of those. Additionally, Alta Energy has successfully drilled and completed two horizontal wells. The Alta Energy 1-32 well is on production while the Alta Energy 14-25 is planned to begin production this summer. We own a 5.0% interest in Alta's Kaybob Duvernay project.

Jonah Field - Sublette County, Wyoming

In April 2012, the Company announced that through its wholly-owned subsidiary, Contaro Company, it had entered into a Limited Liability Company Agreement (the “LLC Agreement”) in connection with the formation of Exaro. Pursuant to the LLC Agreement, the Company had committed to invest up to $82.5 million in cash in Exaro over the next five years together with other parties for an aggregate commitment of $182.5 million, or a 45% ownership interest in Exaro.

In August 2012, one of the other investors in Exaro exercised its right to assume $15 million of the Company's commitment, which lowered the Company's commitment to $67.5 million and its ownership interest to 37%. As of March 31, 2013, the Company had invested approximately $46.9 million in Exaro.

Exaro has entered into an Earning and Development Agreement with Encana Oil & Gas (USA) Inc. (“Encana”) to provide funding of up to $380 million to continue the development drilling program in a defined area of Encana’s Jonah Field asset located in Sublette County, Wyoming. This funding will be comprised of the $182.5 million investment described above, debt, and cash flow from operations. Encana will continue to be the operator of the field and upon investing the full amount of the $380 million, Exaro will have earned 32.5% of Encana’s working interest in a defined joint venture area that comprises approximately 5,760 gross acres.

As of May 8, 2013, the Exaro-Encana venture had 43 new wells on production, producing at a rate of approximately 9.2 Mmcfed, net to Contango, plus an additional six wells that are either in the completion or fracture stimulation phase. We continue to have three drilling rigs running on this project. For the three and nine months ended March 31, 2013, the Company recognized a loss of approximately $1.1 million and $639,000, respectively, net of tax benefit of $617,000 and $344,000, as a result of its investment in Exaro.

Tuscaloosa Marine Shale

In October 2012, the Company became a 25% non-operating working interest owner in property in the TMS operated by Goodrich. The TMS is an oil-focused shale play in central Louisiana and Mississippi. We have invested $5.1 million, net to Contango, to acquire acreage and participate in our first horizontal well, the Crosby 12H-1 well in Wilkinson County, Mississippi. For evaluation purposes, we drilled a pilot well, performed an open-hole evaluation and obtained a conventional core over the TMS interval. As of May 6, 2013, the Crosby 12H-1 well was producing at a rate of approximately 700 barrels of

oil per day, with cumulative production of 65,000 barrels of oil through April 30, 2013. This well has approximately 6,700 feet of usable lateral and was fracked with 25 stages.

Additionally, as of May 8, 2013, the Company had invested approximately $9.0 million to lease approximately 24,000 acres in the TMS. We plan to participate in additional third-party operated wells with a small working interest prior to initiating an operated, high interest drilling program. The data we obtain from the Crosby 12H-1 well will help us evaluate our TMS acreage and develop a plan for drilling and operating future wells.

Employees

We have eleven employees. The Company outsources its human resources function to Insperity, Inc. and all of the Company’s employees are co-employees of Insperity, Inc.

Application of Critical Accounting Policies and Management’s Estimates

The discussion and analysis of the Company’s financial condition and results of operations are 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 3 to the consolidated financial statements included in this Quarterly Report on Form 10-Q. 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 its 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 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.

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 natural gas and oil prices, 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. 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 March 31, 2013 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense for the nine months ended March 31, 2013 by approximately $1.6 million, $3.4 million and $5.3 million, respectively.

Impairment of Natural Gas and Oil Properties. The Company reviews its proved natural gas and oil properties for impairment whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company compares expected undiscounted future net cash flows from each field 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, 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, and anticipated capital expenditures. 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 consolidated financial statements and consist 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 consolidated 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.

MD&A Summary Data

The table below sets forth our average net daily production data in Mmcfed for each of the periods indicated:



	Three Months Ended
	March 31, 2012	June 30, 2012	September 30, 2012	December 31, 2012	March 31, 2013
Dutch and Mary Rose Wells	59.3	67.5	54.2	57.2	59.5
Ship Shoal 263 Well (Nautilus)	7.8	7.6	3.5	2.6	0.9
Vermilion 170 Well (Swimmy)	15.3	15.5	10.5	12.9	3.6
Non-operated wells	0.3	0.2	—	—	0.6
	82.7	90.8	68.2	72.7	64.6

Dutch and Mary Rose Wells


•	The low production during the three months ended March 31, 2013 was due to choking back the Dutch #2 well while waiting to plug back the lowest lobe in the CibOp formation later in May 2013. As of May 7, 2013, the ten Dutch and Mary Rose wells were flowing approximately 57.9 Mmcfed, net to Contango.

Ship Shoal 263 Well

•

Since late-2011, production at this well has been slowly decreasing due to overheating, scaling problems, and water production. The well has also been shut-in several times over the past few months for production logging and chemical treatment. We believe that this well may be fully depleted in the next twelve months. The well reached payout during fiscal year 2012. We will continue producing this well as long as it is economical. As of May 7, 2013, the well was flowing at approximately 0.6 Mmcfed, net to Contango.


•	During the nine months ended March 31, 2013, due to the decline in production from this well, our reservoir engineer revised his estimated net proved natural gas and oil reserves from this well. As a result, the net book value of our Ship Shoal 263 well exceeded the future undiscounted cash flows associated with its reserves. Accordingly, the Company

recognized an impairment expense of approximately $12.0 million for the nine months ended March 31, 2013. No impairment was recognized for the three months ended March 31, 2013.

Vermilion 170 Well

•

In late January 2013, we identified sustained casing pressure between the production tubing and the production casing at our Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a workover of the well. Well production was shut-in and the original tubing and completion assembly were successfully removed. Operations are underway to replace the tubing and restore the well to production. As of March 31, 2013, we had expended approximately $5.4 million on these workover operations. We expect the well to resume production by the end of May 2013.

The table below sets forth revenue, expense and production data for the three and nine months ended March 31, 2013 and 2012:



	Three Months Ended March 31,						Nine Months Ended March 31,
	2013		2012		Change		2013		2012		Change
	(thousands, except percent change, average sales price and selected data per Mcfe)
Revenues:
Natural gas sales	$	16,013	$	14,246	12	%	$	48,060	$	58,669	(18	)%
Condensate sales	$	10,174	$	17,757	(43	)%	$	31,266	$	52,161	(40	)%
NGL sales	$	5,600	$	9,336	(40	)%	$	17,167	$	28,619	(40	)%
Total revenues	$	31,787	$	41,339	(23	)%	$	96,493	$	139,449	(31	)%

Production:
Natural gas (million cubic feet)	4,367		5,547		(21	)%	14,230		17,276		(18	)%
Oil and condensate (thousand barrels)	91		157		(42	)%	290		464		(38	)%
Natural gas liquids (thousand gallons)	6,311		7,321		(14	)%	19,655		20,725		(5	)%
Total (million cubic feet equivalent)	5,815		7,535		(23	)%	18,778		23,021		(18	)%

Natural gas (million cubic feet per day)	48.5		61.0		(21	)%	51.9		62.8		(18	)%
Oil and condensate (thousand barrels per day)	1.0		1.7		(42	)%	1.1		1.7		(38	)%
Natural gas liquids (thousand gallons per day)	70.1		80.5		(14	)%	71.7		75.4		(5	)%
Total (million cubic feet equivalent per day)	64.6		82.7		(23	)%	68.5		83.8		(18	)%

Average Sales Price:
Natural gas (per thousand cubic feet)	$	3.67	$	2.57	43	%	$	3.38	$	3.40	(1	)%
Oil and condensate (per barrel)	$	111.85	$	113.41	(1	)%	$	108.00	$	112.53	(4	)%
Natural gas liquids (per gallon)	$	0.89	$	1.28	(30	)%	$	0.87	$	1.38	(37	)%
Total (per thousand cubic feet equivalent)	$	5.47	$	5.49	*		$	5.14	$	6.06	(15	)%

Summary of Financial Information:
Operating expenses	$	9,785	$	5,727	71	%	$	21,220	$	18,626	14	%
Exploration expenses	$	129	$	76	70	%	$	51,743	$	133	**
Depreciation, depletion and amortization	$	10,494	$	11,710	(10	)%	$	30,830	$	36,203	(15	)%
Impairment of natural gas and oil properties	$	—	$	—	—	%	$	14,078	$	—	100	%
General and administrative expenses	$	3,208	$	1,226	162	%	$	8,607	$	5,778	49	%

Selected Data per Mcfe:
Lease operating expenses	$	1.68	$	0.76	121	%	$	1.13	$	0.81	40	%
General and administrative expenses	$	0.55	$	0.16	244	%	$	0.46	$	0.25	84	%
Depreciation, depletion and amortization of natural gas and oil properties	$	1.77	$	1.53	16	%	$	1.62	$	1.55	5	%

* Less than 1%
** Greater than 1000%

Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Natural Gas, Oil and Natural Gas Liquids (“NGL”) Sales and Production. We reported revenues of approximately $31.8 million for the three months ended March 31, 2013, compared to revenues of approximately $41.3 million for the three months ended March 31, 2012. This decrease in revenues of $9.5 million was principally attributable to a decrease in natural gas, condensate and NGL production.

Our net natural gas production for the three months ended March 31, 2013 was approximately 48.5 Mmcfd, down from approximately 61.0 Mmcfd for the three months ended March 31, 2012. Net oil and condensate production for the comparable

periods also decreased from approximately 1,700 barrels per day to approximately 1,000 barrels per day, and our NGL production decreased from approximately 80,500 gallons per day to approximately 70,100 gallons per day. In total, equivalent production decreased from 82.7 Mmcfed to 64.6 Mmcfed.

For the three months ended March 31, 2013, natural gas accounted for approximately 75% of our production, while condensate and NGLs accounted for 9% and 16%, respectively. From a revenue perspective however, natural gas generated 50% of our revenues, while condensate and NGLs generated 32% and 18%, respectively. For the three months ended March 31, 2012, natural gas accounted for 74% of our production, while condensate and NGLs each accounted for 13%. From a revenue perspective however, natural gas generated 34% of our revenues, while condensate and NGLs generated 43% and 23%, respectively.

Average Sales Prices. For the three months ended March 31, 2013, the average price of natural gas was $3.67 per thousand cubic feet (“Mcf”), the average price for oil and condensate was $111.85 per barrel and the average price for NGLs was $0.89 per gallon. For the three months ended March 31, 2012, the average price of natural gas was $2.57 per Mcf, the average price for oil and condensate was $113.41 per barrel and the average price for NGLs was $1.28 per gallon.

Operating Expenses. Lease operating expenses (“LOE”) for the three months ended March 31, 2013 were approximately $9.8 million, as compared to $5.7 million for the three months ended March 31, 2012. This increase in LOE is mainly attributable to $6.4 million in workover expenses on our Vermilion 170 well and other projects, offset by lower operating expenses due to reduced production during the period.

Exploration Expense. We reported approximately $129,000 of exploration expense for the three months ended March 31, 2013 and approximately $76,000 of exploration expense for the three months ended March 31, 2012. These expenditures consist of expenses for geological and geophysical activities, seismic data and delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2013 was approximately $10.5 million. For the three months ended March 31, 2012, we recorded approximately $11.7 million of depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization was primarily attributable to a decrease in overall production.

General and Administrative Expenses. General and administrative expenses for the three months ended March 31, 2013 and the three months ended March 31, 2012 were approximately $3.2 million and $1.2 million, respectively. This increase is principally attributable to increased bonus expense as a result of credits taken in previous years, increased legal and professional fees as a result of the proposed merger and increased salaries expense as a result of hiring Mr. Romano.

Major components of general and administrative expenses for the three months ended March 31, 2013 included approximately $0.3 million in State of Louisiana franchise taxes, $1.5 million in salaries and benefits, $1.0 million in accounting, tax, legal, engineering and other professional fees, $0.2 million in administrative costs, $0.1 million in insurance costs and $0.1 million related to board of director compensation.

Major components of general and administrative expenses for the three months ended March 31, 2012 included approximately $0.3 million in State of Louisiana franchise taxes, $0.3 million in salaries and benefits, $0.4 million in accounting, tax, legal, engineering and other professional fees, $0.1 million in insurance costs, and $0.1 million related to board of director compensation.

Nine Months Ended March 31, 2013 Compared to Nine Months Ended March 31, 2012

Natural Gas, Oil and Natural Gas Liquids (“NGL”) Sales and Production. We reported revenues of approximately $96.5 million for the nine months ended March 31, 2013, compared to revenues of approximately $139.4 million for the nine months ended March 31, 2012. This decrease in revenues of $42.9 million was principally attributable to a decrease in natural gas, condensate and NGL production, further compounded by lower sales prices for all of our products.

Our net natural gas production for the nine months ended March 31, 2013 was approximately 51.9 Mmcfd, down from approximately 62.8 Mmcfd for the nine months ended March 31, 2012. Net oil and condensate production for the comparable periods also decreased from approximately 1,700 barrels per day to approximately 1,100 barrels per day, and our NGL production decreased from approximately 75,400 gallons per day to approximately 71,700 gallons per day. In total, equivalent production decreased from 83.8 Mmcfed to 68.5 Mmcfed.

For the nine months ended March 31, 2013, natural gas accounted for approximately 76% of our production, while condensate and NGLs accounted for 9% and 15%, respectively. From a revenue perspective however, natural gas generated 50% of our revenues, while condensate and NGLs generated 32% and 18%, respectively. For the nine months ended March 31, 2012, natural gas accounted for 75% of our production, while condensate and NGLs accounted for 12% and 13%, respectively.

From a revenue perspective however, natural gas generated 42% of our revenues, while condensate and NGLs generated 37% and 21%, respectively.

Average Sales Prices. For the nine months ended March 31, 2013, the average price of natural gas was $3.38 per thousand cubic feet (“Mcf”), the average price for oil and condensate was $108.00 per barrel and the average price for NGLs was $0.87 per gallon. For the nine months ended March 31, 2012, the average price of natural gas was $3.40 per Mcf, the average price for oil and condensate was $112.53 per barrel and the average price for NGLs was $1.38 per gallon.

Operating Expenses. Lease operating expenses (“LOE”) for the nine months ended March 31, 2013 were approximately $21.2 million, as compared to approximately $18.6 million for the nine months ended March 31, 2012. This increase in LOE is mainly attributable to $6.4 million in workover expenses on our Vermilion 170 well and other projects, offset by lower operating expenses due to reduced production during the period.

Exploration Expense. We reported approximately $51.7 million of exploration expense for the nine months ended March 31, 2013, which consists of $50.0 million for Eagle and Fang, $1.4 million related to an unsuccessful drilling program in Jim Hogg County, Texas and $0.3 million for geological and geophysical activities, seismic data and delay rentals. For the nine months ended March 31, 2012, we reported approximately $0.1 million of exploration expense, which consists mainly of expenses for geological and geophysical activities, seismic data and delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the nine months ended March 31, 2013 was approximately $30.8 million. For the nine months ended March 31, 2012, we recorded approximately $36.2 million of depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization was primarily attributable to a decrease in overall production.

Impairment of Natural Gas and Oil Properties. For the nine months ended March 31, 2013, the Company recorded impairment expense of approximately $14.1 million on our properties. Of this amount, approximately $12.0 million related to our Ship Shoal 263 well and $2.1 million related to the Eugene Island 24 platform and other properties. For the nine months ended March 31, 2012, the Company did not record any impairment expenses.

General and Administrative Expenses. General and administrative expenses for the nine months ended March 31, 2013 and the nine months ended March 31, 2012 were approximately $8.6 million and $5.8 million, respectively. This increase is principally attributable to increased legal and professional fees as a result of the proposed merger and increased salaries expense as a result of hiring Mr. Romano.

Major components of general and administrative expenses for the nine months ended March 31, 2013 included approximately $0.7 million in State of Louisiana franchise taxes, $4.0 million in salaries and benefits (of which $1.4 million is accrued bonuses), $2.7 million in accounting, tax, legal, engineering and other professional fees, $0.3 million in insurance costs, $0.5 million in other administrative costs, and $0.4 million related to board of director compensation.

Major components of general and administrative expenses for the nine months ended March 31, 2012 included approximately $0.6 million in State of Louisiana franchise taxes, $3.4 million in salaries and benefits (of which $1.5 million is accrued bonuses), $1.2 million in accounting, tax, legal, engineering and other professional fees, $0.3 million in insurance costs, and $0.3 million related to board of director compensation.

Capital Resources and Liquidity

Cash From Operating Activities. Cash flows from operating activities provided approximately $68.8 million in cash for the nine months ended March 31, 2013 compared to $56.6 million for the same period in 2012. This increase in cash provided by operating activities was mainly attributable to the timing of payments of the Company’s obligations.

Cash From Investing Activities. Cash flows used in investing activities for the nine months ended March 31, 2013 were approximately $80.7 million, which consisted mainly of $73.2 million in capital expenditures for drilling and developing wells ($50.0 million of this was Eagle and Fang), investing $2.4 million in Alta Energy and investing $13.1 million in Exaro, partially offset by receiving $7.5 million as a return of capital related to our Exaro investment and $0.6 million as a distribution from REX to its partners. Cash flows used in investing activities for the nine months ended March 31, 2012 were approximately $30.0 million, which consisted mainly of $18.7 million in capital expenditures for developing our wells and facilities and $11.2 million in equity investments in Exaro and Alta Energy.

Cash From Financing Activities. Cash flows used in financing activities for the nine months ended March 31, 2013 were $35.5 million, compared to approximately $16.7 million of cash used for the nine months ended March 31, 2012. This increase in cash used is attributable to paying a $30.5 million dividend to shareholders in 2012 and purchasing shares of common stock under our publicly announced share repurchase programs.

Capital Budget. Our capital expenditure budget through December 31, 2013 calls for us to invest approximately $38.5 million from cash on hand and operating cash flows, as follows:


•	$29.0 million to drill two wildcat exploration wells in the Gulf of Mexico.


•	$5.0 million to complete our workover of Vermilion 170.


•	$1.5 million to workover our Dutch #2 well.


•	$3.0 million to complete installing compression on our Eugene Island 11 platform.

Should the Company have exploration success with its two exploration wells, our capital expenditure budget will be significantly increased.

The Company often reviews acquisitions and prospects presented to us by third parties and we 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. On April 30, 2013, the Company announced that it had signed a merger agreement with Crimson for an all-stock transaction pursuant to which Crimson would become a wholly-owned subsidiary of the Company. See Note 12 - "Subsequent Events" above for more information on the merger.

Natural Gas and Oil Reserves

The following table presents our estimated net proved natural gas and oil reserves at March 31, 2013 and June 30, 2012, based on reserve reports generated by William M. Cobb & Associates, Inc. (“Cobb”) and W.D. Von Gonten and Company ("Von Gonten"). 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 engineer to review these reserve estimates. The qualifications of the technical person at each of these firms is responsible for overseeing the 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.

W.D. Von Gonten and Company


•	Over 13 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

Each of Cobb and Von Gonten 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 engineer quarterly, is confirmed when our third-party reservoir engineer holds 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 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 engineer 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 firm prepares the independent reserve estimates and final report.



	Proved Reserves as of
	March 31, 2013	June 30, 2012
Natural Gas (MMcf) (1)	154,210	201,379
Oil, Condensate and Natural Gas Liquids (MBbls) (1)	6,948	9,198
Subtotal (Mmcfe)	195,898	256,567

Reserves attributable to our investment in Exaro Energy III LLC (Mmcfe) (2)	19,597	—
Total proved reserves (Mmcfe)	215,495	256,567

(1) Reserves Prepared by William M. Cobb & Associates, Inc.

(2) Reserves Prepared by W.D. Von Gonten and Company

Our total proved reserves as of March 31, 2013 were approximately 41.1 billion cubic feet equivalent (“Bcfe”) less than our reserves as of June 30, 2012. The major contributors to this decrease include production of 18.8 Bcfe during the nine months ended March 31, 2013; a 19.2 Bcfe decrease in our Dutch and Mary Rose reserve estimates based upon additional pressure data; a 9.2 Bcfe decrease in our Ship Shoal 263 reserves estimates due to the well unexpectedly beginning to water out; and a 14.0 Bcfe decrease in our Vermilion 170 reserves due to additional pressure data; offset by a 19.6 Bcfe increase in our reserve estimate for the Exaro-Encana venture and a 0.5 Bcfe increase from our Crosby 12H-1 well in the TMS.

The Exaro-Encana venture achieved first production during mid-June 2012 and as of June 30, 2012 had no material natural gas or oil reserves. Under the terms of the Earning and Development Agreement between Exaro and Encana, for each well that Exaro participates, Exaro will earn 32.5% of Encana's interest in such well, plus an additional portion of Encana's working interest in a defined joint venture area with producing wells that comprises approximately 5,760 gross acres.

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 engineer must project production rates and timing of development expenditures, as well as analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves has in the past varied from estimates and will most likely continue to vary in the future. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, our third party engineers may adjust estimates of proved reserves 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.

Share Repurchase Programs

$100 Million Share Repurchase Program

In September 2008, the Company’s board of directors approved a $100 million share repurchase program which concluded in October 2011. Under this program, the Company purchased approximately 2.2 million shares, at an average price of $46.35 per share. All shares were purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases were 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.

$50 Million Share Repurchase Program

In September 2011, the Company’s Board of Directors approved a $50 million share repurchase program, effective upon completion of purchases under the Company’s $100 million share repurchase program. The repurchases are subject to the same terms and conditions as repurchases made under the $100 million share repurchase program. No shares were purchased during the three months ended March 31, 2013. During the nine months ended March 31, 2013, the Company purchased 97,496 shares at an average price of $50.82 per share, for a total of approximately $5.0 million. During the three months ended March 31, 2012, the Company purchased 45,000 stock options for approximately $0.5 million. During the nine months ended March 31, 2012, the Company purchased 35,663 shares at an average price of $54.58 per share, for a total of approximately $1.9 million. In total, as of May 8, 2013, the Company had purchased 197,877 shares under the $50 million share repurchase program at an average price of $52.16 per share, plus 45,000 stock options, all for approximately $10.8 million.

As of May 8, 2013, under both share repurchase programs combined, the Company had purchased approximately 2.4 million shares of its common stock at an average cost per share of $46.84 and 45,000 stock options, for a total of approximately $110.8 million, bringing its total share count to 15,194,952 shares of common stock outstanding.

Credit Facility

In October 2010, the Company completed the arrangement of a $40 million secured revolving credit agreement with Amegy Bank (the “Credit Agreement”). The Credit Agreement is supported by a hydrocarbon borrowing base and is available to fund the Company’s exploration and development activities, as well as repurchase shares of common stock and to fund working capital as needed. The Credit Agreement is secured by substantially all of the assets of the Company. Borrowings under the Credit Agreement bear interest at LIBOR plus 2.5%, subject to a LIBOR floor of 0.75%. Any principal borrowed is due October 1, 2014, and may be prepaid at any time with no prepayment penalty. An arrangement fee of $300,000 was paid in connection with the facility and effective November 1, 2011, a commitment fee of 0.125% is owed on unused borrowing capacity. The Credit Agreement contains customary covenants including limitations on our current ratio of assets to liabilities and additional indebtedness. As of May 8, 2013, the Company was in compliance with all covenants and had no borrowings outstanding under the Credit Agreement.

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


•	Expectations regarding oil and gas markets in the United States

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 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, including well blowouts and explosions


•	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


•	Availability of rigs and other operating equipment


•	Ability to receive Bureau of Ocean Energy Management, Regulation and Enforcement permits on a time schedule that permits the Company to operate efficiently


•	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


•	Zero or near zero interest rates


•	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


•	The 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


•	Operating costs, production rates and ultimate reserve recoveries of our offshore discoveries


•	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 new and potential legislative and regulatory changes on Gulf of Mexico operating and safety standards

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” in this Form 10-Q 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.

Risk Factors

In addition to the other information set forth elsewhere in this Form 10-Q and in our annual report on 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 market price 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:


•	Overall economic conditions.


•	The domestic and foreign supply of natural gas and oil.


•	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 and any LNG exports.


•	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 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. 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. We have historically entered into agreements with JEX and its affiliates when we purchase prospects from JEX and its affiliates that specify the terms and conditions of purchase.

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 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 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.

We rely on third-party operators to operate and maintain some of our production platforms, 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.

The majority of our capital investments is focused in offshore Gulf of Mexico exploration prospects, which may result in a total loss of our investment. Furthermore, even our productive wells may not result in profitable operations. Gulf of Mexico exploration efforts have been undertaken for over 60 years and remaining prospects are at deeper horizons that are more expensive to drill and often in much deeper water depths. Accordingly, as a result, a number of companies have shifted their focus to onshore “shale plays.” The Company’s continuing focus on the Gulf of Mexico will result in significant dry hole costs, potentially in excess of $30 million for one well, which significantly concentrates and increases our risk profile.

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.

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.

The Company’s reserves and revenues are primarily concentrated in one field.

Approximately 89% of our Cobb-generated reserves are assigned to our Dutch and Mary Rose discoveries which have ten producing well bores concentrated in one reservoir and are producing through two production platforms. Reserve assessments based on only ten well bores in one reservoir are subject to significantly greater risk of being shut-in for a variety of weather, platform and pipeline difficulties. In addition, the risk of a downward revision in our reserve estimates is also greater.

We rely on the accuracy of the estimates in the reservoir engineering reports provided to us by our outside engineer.

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 engineer. If those reports prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of our independent reservoir engineer in our financial planning. If the reports of the outside reservoir engineer 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.


•	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. 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.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions in the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. Internationally, the United Nations Framework Convention on Climate Change, and the Kyoto Protocol

address greenhouse gas emissions, and several countries including countries in the European Union have established greenhouse gas regulatory systems. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs.

The Environmental Protection Agency (the “EPA”) has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. In November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding serves as a first step to issuing regulations that would require permits for and reductions in greenhouse gas emissions for certain facilities. EPA has proposed such greenhouse gas regulations and may issue final rules at a subsequent date.

Several decisions have been issued by courts that may increase the risk of claims being filed by governments and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs, and could have an adverse effect on demand for the natural gas and condensate that we produce.

The natural gas and oil business involves many operating risks that can cause substantial losses and our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.

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.

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 and processing plants. 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.

Proposed United States federal budgets and pending legislation contain certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.

The federal administration has released repeated budget proposals over the past few years which include numerous proposed tax changes. The proposed budgets and legislation would repeal many tax incentives and deductions that are currently used by oil and gas companies in the United States and impose new taxes. Among others, the provisions include: elimination of

the ability to fully deduct intangible drilling costs in the year incurred; repeal of the percentage depletion deduction for oil and gas properties; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. Should some or all of these provisions become law, taxes on the E&P industry would increase, which could have a negative impact on our results of operations and cash flows. Although these proposals initially were made in 2009, none have become law. It is still, however, the federal administration’s stated intention to enact legislation to repeal tax incentives and deductions and impose new taxes on oil and gas companies.

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 have been and may continue to be adversely affected by changes in laws and regulations which have occurred and are expected to continue to occur as a result of the Deepwater Horizon Incident.

As a result of the Deepwater Horizon Incident of 2010, the Department of the Interior issued additional safety and performance standards as well as rigorous monitoring and testing requirements for offshore drilling. In addition, various Congressional committees began pursuing legislation to regulate drilling activities, establish safety requirements and increase liability for oil spills.

We continue to monitor legislative and regulatory developments, including the Drilling Safety Rule and the Workforce Safety Rule issued by the Department of the Interior. However, the full legislative and regulatory response to the incident is not fully known. An expansion of safety and performance regulations or an increase in liability for drilling activities will 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 longer time periods to obtain permits.


•	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.

Current regulatory requirements and permitting procedures have significantly delayed our ability to obtain permits to drill new wells in offshore waters.

Subsequent to the Deepwater Horizon Incident in the Gulf of Mexico, a series of Notices to Lessees (“NTLs”) were issued which imposed new regulatory requirements and permitting procedures for new wells to be drilled in federal waters of the OCS. These new regulatory requirements include the following:


•	The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.


•	The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.


•	The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.


•	The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system (“SEMS”) in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

Since the adoption of these new regulatory requirements, BOEM has been taking much longer periods of time to review and approve permits for new wells. Due to the extremely slow pace of permit review and approval, the BOEM may now take four months or longer to approve applications for drilling permits that were previously approved in less than 30 days. The new rules also increase the cost of preparing each permit application and will increase the cost of each new well.

The Bureau of Safety and Environmental Enforcement ("BSEE") has implemented much more stringent controls and reporting requirements that if not followed, could result in significant monetary penalties or a shut-in of all or a portion of our Gulf of Mexico operations.

The BSEE is the federal agency responsible for overseeing the safe and environmentally responsible development of energy and mineral resources on the OCS. They are responsible for leading the most aggressive and comprehensive reforms to offshore oil and gas regulation and oversight in U.S. history. Their reforms have tightened requirements for everything from well design and workplace safety to corporate accountability. One of the many reforms includes implementing a SEMS program. This program requires operators to identify, address, and manage safety and environmental hazards during the design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities. Facilities must be designed, constructed, maintained, monitored, and operated in a manner compatible with industry codes, consensus standards, and all applicable governmental regulations. Failure to comply with the SEMS program may force us to cease operations in the Gulf of Mexico.

Additionally, the OCS Lands Act authorizes and requires the BSEE to provide for both an annual scheduled inspection and a periodic unscheduled (unannounced) inspection of all oil and gas operations on the OCS. In addition to examining all safety equipment designed to prevent blowouts, fires, spills, or other major accidents, the inspections focus on pollution, drilling operations, completions, workovers, production, and pipeline safety. Upon detecting a violation, the inspector issues an Incident of Noncompliance (INC) to the operator and uses one of two main enforcement actions (warning or shut-in), depending on the severity of the violation. If the violation is not severe or threatening, a warning INC is issued. The warning INC must be corrected within a reasonable amount of time specified on the INC. The shut-in INC may be for a single component (a portion of the facility) or the entire facility. The violation must be corrected before the operator is allowed to resume the activity in question.

In addition to the enforcement actions specified above, the BSEE can assess a civil penalty of up to $40,000 per violation per day if: 1) the operator fails to correct the violation in the reasonable amount of time specified on the INC; or 2) the violation resulted in a threat of serious harm or damage to human life or the environment. Operators with excessive INCs may be required to cease operations in the Gulf of Mexico.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

It is customary in our industry to recover natural gas and oil from shale and other formations through the use of horizontal drilling combined with hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations using water, sand and other additives pumped under high pressure into the formation. We intend to use hydraulic fracturing as a means to increase the productivity of the onshore wells that we drill and complete.

The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states, including Pennsylvania, Texas, Colorado, Montana, New Mexico and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

Additionally, the EPA has asserted federal regulatory authority over hydraulic fracturing activities involving diesel fuel (specifically, when diesel fuel is utilized in the stimulation fluid) under the Safe Drinking Water Act and is completing the process of drafting guidance documents related to this newly asserted regulatory authority. There are also certain governmental reviews either underway or being proposed that focus on shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate such activities. The EPA has published proposed New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) that, if adopted as proposed, would amend existing NSPS and NESHAP standards for oil and gas facilities as well as create new NSPS standards for oil and gas production, transmission and distribution facilities. The EPA has also proposed regulations focused on reducing emissions of certain air pollutants by the oil and gas industry, including volatile organic compounds, sulfur dioxide and certain air toxics.

Certain environmental and other groups have suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. We cannot predict whether additional federal, state or local laws or regulations will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our business and operations could be subject to delays, increased operating and compliance costs and process prohibitions.

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 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, our exploration partners and third-party consultants and engineers, 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. 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 transactions contemplated by the Merger Agreement are subject to conditions, including certain conditions that may not be satisfied, or completed on a timely basis, if at all.

The Merger is subject to a number of conditions beyond Contango's and Crimson's control that may prevent, delay or otherwise materially adversely affect its completion. We cannot predict whether and when these other conditions will be satisfied. Any delay in completing the Merger could cause us not to realize some or all of the synergies that we expect to achieve if the Merger is successfully completed within its expected time frame.

Failure to complete the Merger could negatively impact our future business and financial results.

We cannot make any assurances that we will be able to satisfy all of the conditions to the Merger or succeed in any litigation brought in connection with the Merger. If the Merger is not completed, our financial results may be adversely affected and we will be subject to several risks, including but not limited to:

•Being required to pay a termination fee of $28 million under certain circumstances provided in the Merger Agreement;

•Payment of costs relating to the Merger, such as legal, accounting, financial advisor and printing fees, whether or not

the Merger is completed;

•Having had the focus of our management on the Merger instead of on pursuing other opportunities that could have

been beneficial to the Company; and

•Being subject to litigation related to any failure to complete the Merger.

If the Merger is not completed, we cannot assure our stockholders that these risks will not materialize and will not materially and adversely affect our business, financial results and stock prices.

Uncertainties associated with the Merger may cause a loss of management personnel and other key employees.

We are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plans. The combined company's success after the merger will depend in part upon the ability of Contango and Crimson to retain key management personnel and other key employees. Current and prospective employees of Contango and Crimson may experience uncertainty about their roles within the combined company following the Merger, which may have an adverse effect on the ability of each of Contango and Crimson to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees of Contango and Crimson to the same extent that Contango and Crimson have previously been able to attract or retain their own employees.

The failure to integrate successfully the businesses of Contango and Crimson in the expected time frame would adversely affect the combined company's future results following the Merger.

The Merger involves the integration of two companies that have previously operated independently. The success of the Merger will depend, in large part, on the ability of the combined company following the Merger to realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from combining the businesses of Contango and Crimson. To realize these anticipated benefits, the businesses of Contango and Crimson must be successfully integrated. This integration will be complex and time-consuming. The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in the combined company not achieving the anticipated benefits of the Merger.

Our stockholders will have a reduced ownership and voting interest in the combined company after the Merger.

If the Merger occurs, each Contango stockholder will remain a stockholder of Contango with a percentage ownership of the combined company that will be smaller than the stockholder's percentage of Contango prior to the Merger. As a result of these reduced ownership percentages, Contango stockholders will have less voting power in the combined company than they now have with respect to Contango.

The future results of the combined company could suffer if the combined company does not effectively manage its expanded operations following the merger.

Following the merger, the size of the business of the combined company will increase significantly beyond the current size of either Contango's or Crimson's business. The combined company's future success depends, in part, upon its ability to manage this expanded business, which could pose challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings, revenue enhancements and other benefits currently anticipated from the merger.

The combined company's debt may limit its financial flexibility.

Contango currently has no amounts outstanding under its credit facility and traditionally has carried minimal balances of long-term debt. Following the merger, it is expected that the combined company will have more long-term debt. In addition, the combined company may incur additional debt from time to time in connection with the financing of operations, acquisitions, recapitalizations and refinancings. The level of the combined company's debt could have several important effects on future operations, including, among others:


•	If a portion of the combined company's cash is applied to the payment of principal or interest on the debt, less will be available for other purposes;


•	Credit-rating agencies may change in the future with respect to the combined company, their ratings of that entity's debt and other obligations, which in turn impacts the costs, terms and conditions and availability of financing;


•	Covenants contained in the combined company's existing and future debt arrangements will require the combined company to meet financial tests that may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;


•	The combined company's ability to obtain additional financing for capital expenditures, acquisitions, general corporate and other purposes may be limited or burdened by increased costs or more restrictive covenants;


•	The combined company may be at a competitive disadvantage to similar companies that have less debt;


•	The combined company's vulnerability to adverse economic and industry conditions may increase; and


•	The combined company may face limitations on its flexibility to plan for and react to changes in its business and the industries in which it operates.

Anti-takeover provisions of our certificate of incorporation, bylaws and Delaware law could adversely affect 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.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate and Credit Rating Risk. As of May 8, 2013, we had no long-term debt subject to the risk of loss associated with movements in interest rates.

As of March 31, 2013, we had approximately $82.6 million in cash and cash equivalents, all of which was held in non-interest bearing accounts. Investments in fixed-rate, interest-earning instruments carry a degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impacted because of changes in interest rates and credit ratings. Additionally, the value of our investments may be impaired temporarily or permanently. Due in part to these factors, our investment income may decline and we may suffer losses in principal. Currently, we do not use any derivative or other financial instruments or derivative commodity instruments to hedge any market risks, including changes in interest rates or credit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of the securities that we invest in, we do not believe that we have any cash flow exposure arising from changes in credit ratings. Based on a sensitivity analysis performed on the financial instruments held as of March 31, 2013, an immediate 10% change in interest rates is not expected to have a material effect on our near-term financial condition or results of operations.

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 the spot prices applicable to natural gas and crude oil. Prices received for natural gas and oil are volatile and unpredictable and are beyond our control. For the three and nine months ended March 31, 2013, a 10% fluctuation in the prices received for natural gas and oil production would impact our revenues by approximately $3.2 million and $9.6 million, respectively.

Item 4. Controls and Procedures

Joseph J. Romano, our Chairman, President and Chief Executive Officer, together with our Chief Financial Officer and Chief Accounting Officer, carried out an evaluation 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, as amended (the “Exchange Act”), as of March 31, 2013. Based upon that evaluation, the Company’s management concluded that, as of March 31, 2013, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1A. Risk Factors

The description of the risk factors associated with the Company set forth under the heading “Risk Factors” in Item 2 of Part I, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this Form 10-Q is incorporated into this Item 1A by reference and supersedes the description of risk factors set forth under the heading “Risk Factors” in Item 1 of Part I of our annual report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The description of repurchases made by the Company set forth under the heading “Share Repurchase Program” in Item 2 of Part I, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this Form 10-Q is incorporated into this Item 2 by reference.

Item 5. Other Information

Item 6. Exhibits

(a) Exhibits:

The following is a list of exhibits filed as part of this Form 10-Q. Where so indicated by a footnote, exhibits, which were previously filed, are incorporated herein by reference.




Exhibit Number			Description

2.1*			Agreement and Plan of Merger, dated as of April 29, 2013, by and among Contango Oil & Gas Company, Contango Acquisition, Inc. and Crimson Exploration Inc. (8)
3.1			Certificate of Incorporation of Contango Oil & Gas Company. (1)
3.2			Bylaws of Contango Oil & Gas Company. (1)
3.3			Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (1)
3.4			Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (2)
4.1			Facsimile of common stock certificate of Contango Oil & Gas Company. (3)



10.1			Second Amended and Restated Credit Agreement dated as of October 1, 2010 among Contango Oil & Gas Company, Contango Operators, Inc. and Amegy Bank National Association, as Administrative Agent and Letter of Credit Issuer, together with First Amendment to Second Amended and Restated Credit Agreement dated October 20, 2010 among Contango Oil & Gas Company, Contango Operators, Inc. and Amegy Bank National Association. (4)
10.2			Purchase and Sale Agreement between Juneau Exploration, L.P. and Contango Operators, Inc. dated October 1, 2010. (5)
10.3			First Amended and Restated Limited Liability Company Agreement of Exaro Energy III LLC dated as of March 31, 2012. (6)
10.4			Advisory Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., dated as of April 1, 2012. (7)
10.5			Termination of Advisory Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., dated as of April 1, 2012. (9)
10.6			First Right of Refusal Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., entered into as of January 1, 2013. (9)
10.7			Termination of First Right of Refusal Agreement between Contango Oil & Gas Company and Juneau Exploration, L.P., entered into as of January 1, 2013. †
10.8			Advisory Agreement between Contaro Company and Juneau Exploration, L.P., entered into as of January 1, 2013. (9)
10.9			Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and OCM Crimson Holdings, LLC. (8)
10.10			Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and OCM GW Holdings, LLC. (8)
10.11			Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Allan D. Keel. (8)
10.12			Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and E. Joseph Grady. (8)
10.13			Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and A. Carl Isaac. (8)
10.14			Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Jay S. Mengle. (8)
10.15			Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and Thomas H. Atkins. (8)
10.16			Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, Contango Acquisition, Inc. and John A. Thomas. (8)
10.17			Registration Rights Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company, OCM Crimson Holdings, LLC and OCM GW Holdings, LLC. (8)
10.18			Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and Allan D. Keel. (8)
10.19			Employment Agreement, dated as of April 29, 2013, among Contango Oil & Gas Company and E. Joseph Grady. (8)
23.1			Consent of William M. Cobb & Associates, Inc. †
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			Form of Support and Irrevocable Proxy Agreement, dated as of April 29, 2013, among Crimson Exploration Inc., and the following directors and executive officers of Contango Oil & Gas Company: the Estate of Kenneth R. Peak, Joseph J. Romano, Brad Juneau, Sergio Castro and Yaroslava Makalskaya. (8)
101			Interactive Data Files †



†	Filed herewith.
*	Schedules to the agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company undertakes to furnish supplementally copies of any of the omitted schedules upon request by the SEC.



1.	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.



2.	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.



3.	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.



4.	Filed as an exhibit to the Company’s report on Form 8-K, dated October 20, 2010, as filed with the Securities and Exchange Commission on October 25, 2010.



5.	Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended September 30, 2010, dated November 9, 2010, as filed with the Securities and Exchange Commission.



6.	Filed as an exhibit to the Company’s report on Form 8-K, dated as of March 31, 2012, as filed with the Securities and Exchange Commission on April 5, 2012.



7.	Filed as an exhibit to the Company’s report on Form 8-K, dated as of April 10, 2012, as filed with the Securities and Exchange Commission on April 11, 2012.



8.	Filed as an exhibit to the Company’s report on Form 8-K, dated as of April 29, 2013, as filed with the Securities and Exchange Commission on May 1, 2013.



9.	Filed as an exhibit to the Company’s report on Form 10-Q for the quarter ended December 31, 2012, as filed with the Securities and Exchange Commission on February 11, 2013.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereto duly authorized.




	CONTANGO OIL & GAS COMPANY

Date: May 10, 2013	By:	/S/ JOSEPH J. ROMANO
		Joseph J. Romano Chairman, President and Chief Executive Officer (Principal Executive Officer)

Date: May 10, 2013	By:	/S/ SERGIO CASTRO
		Sergio Castro Vice President, Chief Financial Officer, Treasurer and Secretary (Principal Financial Officer)

Date: May 10, 2013	By:	/S/ YAROSLAVA MAKALSKAYA
		Yaroslava Makalskaya Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer)