Edgar Filing: CONTANGO OIL & GAS CO

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2010

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

For the transition period from to

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)

DELAWARE

95-4079863

(State or other jurisdiction of

incorporation or organization)

(IRS Employer

Identification No.)

3700 BUFFALO SPEEDWAY, SUITE 960

HOUSTON, TEXAS 77098

(Address of principal executive offices)

(713) 960-1901

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark 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 x

The total number of shares of common stock, par value $0.04 per share, outstanding as of April 30, 2010 was 15,777,380.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE NINE MONTHS ENDED MARCH 31, 2010

TABLE OF CONTENTS


		Page
PART I – FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements
Consolidated Balance Sheets as of March 31, 2010 and June 30, 2009		3-4
Consolidated Statements of Operations for the three and nine months ended March 31, 2010 and 2009		5
Consolidated Statements of Cash Flows for the nine months ended March 31, 2010 and 2009		6
Consolidated Statement of Shareholders’ Equity for the nine months ended March 31, 2010		7
Notes to the Consolidated Financial Statements		8
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 3. Quantitative and Qualitative Disclosures about Market Risk		38
Item 4. Controls and Procedures		39

PART II – OTHER INFORMATION

Item 1A. Risk Factors		39
Item 5. Other Information		39
Item 6. Exhibits		40

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

ASSETS


	March 31, 2010			June 30, 2009
	(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	100,430,528		$	44,371,324
Accounts receivable:
Trade receivables		17,131,031			32,809,165
Advances to affiliates		5,849,203			5,494,747
Joint interest billings		5,125,981			4,515,660
Insurance receivable		1,765,561			—
Severance taxes receivable		—			3,528,402
Income taxes		—			4,221,644
Other		2,256,144			1,534,530

Total current assets		132,558,448			96,475,472


PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		517,230,036			460,881,471
Unproved properties		5,682,136			2,911,258
Furniture and equipment		275,648			273,185
Accumulated depreciation, depletion and amortization		(69,698,244	)		(44,952,301	)

Total property, plant and equipment, net		453,489,576			419,113,613


OTHER ASSETS:
Cash and other assets held by affiliates		1,747,139			1,128,110
Other		60,069			324,712

Total other assets		1,807,208			1,452,822

TOTAL ASSETS	$	587,855,232		$	517,041,907

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY


	March 31, 2010			June 30, 2009
	(Unaudited)
CURRENT LIABILITIES:
Accounts payable	$	8,277,350		$	8,812,677
Royalties and working interests payable		23,536,349			32,781,712
Accrued liabilities		2,883,026			3,867,579
Joint interest advances		—			4,056,991
Accrued exploration and development		42,178,157			120,300
Debt of affiliates		3,837,249			3,604,609
Income tax payable		2,710,214			—

Total current liabilities		83,422,345			53,243,868


DEFERRED TAX LIABILITY		117,820,525			110,964,147
ASSET RETIREMENT OBLIGATION		3,852,605			3,469,624

SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50,000,000 shares authorized, 19,681,417 shares issued and 15,842,380 outstanding at March 31, 2010, 19,638,334 shares issued and 15,828,980 outstanding at June 30, 2009,		787,255			785,533
Additional paid-in capital		77,012,556			76,321,911
Treasury stock at cost (3,839,037 shares at March 31, 2010, 3,809,354 shares at June 30, 2009)		(60,255,717	)		(58,639,644	)
Retained earnings		365,215,663			330,896,468

Total shareholders’ equity		382,759,757			349,364,268

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	587,855,232		$	517,041,907

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,
	2010			2009			2010			2009
REVENUES:
Natural gas, oil and liquids sales	$	37,845,738		$	36,133,376		$	119,528,579		$	154,370,771

Total revenues		37,845,738			36,133,376			119,528,579			154,370,771


EXPENSES:
Operating expenses		3,523,835			4,553,421			11,066,471			14,505,666
Exploration expenses		22,756,325			12,756,737			23,334,283			20,387,619
Depreciation, depletion and amortization		6,837,887			8,919,740			25,182,258			22,167,167
Lease expirations and relinquishments		735,553			3,678,708			735,553			4,125,125
Impairment of natural gas and oil properties		—			2,709,239			—			2,709,239
General and administrative expenses		1,199,999			1,490,401			4,379,711			5,993,640

Total expenses		35,053,599			34,108,246			64,698,276			69,888,456

NET INCOME BEFORE OTHER INCOME AND INCOME TAXES		2,792,139			2,025,130			54,830,303			84,482,315

OTHER INCOME (EXPENSE):
Interest expense		(109,047	)		(147,392	)		(420,311	)		(589,812	)
Interest income		535,855			154,058			834,160			757,571
Gain on sale of assets and other		112,868			—			112,868			—


NET INCOME BEFORE INCOME TAXES		3,331,815			2,031,796			55,357,020			84,650,074
Provision for income taxes		(1,589,755	)		(1,184,182	)		(21,037,825	)		(33,965,501	)


NET INCOME ATTRIBUTABLE TO COMMON STOCK	$	1,742,060		$	847,614		$	34,319,195		$	50,684,573


NET INCOME PER SHARE:
Basic	$	0.11		$	0.05		$	2.17		$	3.06
Diluted	$	0.11		$	0.05		$	2.12		$	3.01

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		15,859,618			16,162,928			15,840,607			16,543,485

Diluted		16,162,989			16,466,988			16,160,215			16,857,136

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,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	34,319,195		$	50,684,573
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		25,182,258			22,167,167
Lease expirations and relinquishments		735,553			4,125,125
Impairment of natural gas and oil properties		—			2,709,239
Exploration expenditures		22,261,487			19,361,419
Deferred income taxes		6,856,377			2,475,780
Tax benefit from exercise/cancellation of stock options		(122,025	)		(264,187	)
Stock-based compensation		447,643			1,096,443
Gain on sale of assets and other		(112,868	)		—
Changes in operating assets and liabilities:
Decrease in accounts receivable and other		14,736,771			58,358,818
Increase in prepaid insurance		(491,322	)		(225,134	)
Decrease (increase) in interest receivable		(874,410	)		1,079,107
Decrease in accounts payable and advances from joint owners		(4,592,318	)		(29,030,422	)
Decrease in other accrued liabilities		(6,701,696	)		(57,786,616	)
Increase (decrease) in income taxes payable		7,053,887			(4,942,928	)

Net cash provided by operating activities		98,698,532			69,808,384

CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures		(40,646,487	)		(23,103,005	)
Additions to furniture and equipment		(2,463	)		(5,378	)
Investment in affiliates		(619,029	)		—

Net cash used in investing activities		(41,267,979	)		(23,108,383	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments under credit facility		—			(15,000,000	)
Tax benefit from exercise/cancellation of stock options		122,025			264,187
Purchase of common stock		(1,616,073	)		(51,795,744	)
Debt issuance costs		—			(250,000	)
Proceeds from exercised options, warrants and others		122,699			1,654,469

Net cash used in financing activities		(1,371,349	)		(65,127,088	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		56,059,204			(18,427,087	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		44,371,324			59,884,574

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	100,430,528		$	41,457,487


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	7,127,400		$	36,432,652

Cash paid for interest	$	187,671		$	335,250

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				Paid-in Capital			Treasury Stock			Retained Earnings		Total Shareholders’ Equity
	Shares		Amount		Paid-in Capital			Treasury Stock			Retained Earnings		Total Shareholders’ Equity
Balance at June 30, 2009	15,828,980		$	785,533	$	76,321,911		$	(58,639,644	)	$	330,896,468	$	349,364,268
Net income	—			—		—			—			13,465,861		13,465,861
Expense of stock options	—			—		126,333			—			—		126,333

Balance at September 30, 2009	15,828,980		$	785,533	$	76,448,244		$	(58,639,644	)	$	344,362,329	$	362,956,462

Exercise of stock options	36,500			1,459		121,240								122,699
Tax benefit of exercising stock options	—			—		21,914			—			—		21,914
Issuance of restricted common stock	—			—		72,182			—			—		72,182
Net income	—			—		—			—			19,111,274		19,111,274
Expense of stock options	—			—		124,564			—			—		124,564

Balance at December 31, 2009	15,865,480		$	786,992	$	76,788,144		$	(58,639,644	)	$	363,473,603	$	382,409,095

Cashless exercise of stock options	6,583			263		(263	)		—			—		—
Tax benefit of exercising stock options	—			—		100,111			—			—		100,111
Treasury shares at cost	(29,683	)		—		—			(1,616,073	)		—		(1,616,073	)
Net income	—			—		—			—			1,742,060		1,742,060
Expense of stock options	—			—		124,564			—			—		124,564

Balance at March 31, 2010	15,842,380		$	787,255	$	77,012,556		$	(60,255,717	)	$	365,215,663	$	382,759,757

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO 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 presentation 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 the Company’s Form 10-K for the fiscal year ended June 30, 2009. The consolidated results of operations for the three and nine months ended March 31, 2010 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2010.

2. Summary of Significant Accounting Policies

The application of GAAP involves certain assumptions, judgments, choices and estimates that affect reported amounts of assets, liabilities, revenues and expenses. 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. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, and any such impairment is charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above. Depreciation, depletion and amortization is 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.

When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future net cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. No impairment charges were incurred for the nine months ended March 31, 2010. During the nine months ended March 31, 2009, the Company’s analysis determined that Grand Isle 70 was impaired and the Company recorded an impairment charge of approximately $2.7 million related to this well.

During the nine months ended March 31, 2010 we drilled two dry holes. The first was at Vermillion 155 which was a farm-in we obtained from a third-party independent oil and gas company. This well was spud on March 25, 2010 and was determined to be a dry hole in April 2010. The Company recognized exploration expense of approximately $6.1 million in the Consolidated Statements of Operations for the three and nine months ended March 31, 2010 as a result of this well. The second dry hole was at Matagorda Island 617 which was spud in mid-February 2010 and determined to be a dry hole in April 2010. The Company recognized exploration expense of approximately $16.0 million in the Consolidated Statements of Operations for the three and nine months ended March 31, 2010 as a result of this well.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

An integral and on-going part of our business strategy is to sell our proved reserves from time to time in order to generate additional capital to reinvest in our offshore exploration programs. The Company classifies such property sales as discontinued operations.

Cash Equivalents. Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of March 31, 2010, the Company had approximately $100.4 million in cash and cash equivalents. Of this amount, approximately $65.7 million was invested in U.S. Treasury money market funds and the remaining $34.7 million was invested in overnight U.S. Treasury funds.

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 intercompany balances and transactions. Wholly-owned subsidiaries are fully consolidated. The Company has two subsidiaries that are not wholly owned: 32.3% owned Republic Exploration, LLC (“REX”) and 65.6% owned Contango Offshore Exploration LLC (“COE”). These subsidiaries are not controlled by the Company and are proportionately consolidated.

Recent Accounting Pronouncements. In February 2010, the Financial Accounting Standards Board (“FASB”) amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance for the quarter ended March 31, 2010.

In June 2009, the FASB issued new accounting guidance on the FASB Accounting Standards Codification and the hierarchy of GAAP. This new accounting guidance codifies existing GAAP and recognizes only two levels of GAAP, authoritative and nonauthoritative. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This new accounting guidance is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.

Effective July 1, 2009, the Company adopted new accounting guidance on fair value measurements which require additional disclosures about the Company’s nonfinancial assets and liabilities, which adoption had no impact on the Company’s financial position, results of operations or cash flows.

In April 2009, the FASB issued new accounting guidance which provides additional guidance for estimating fair value when the volume and level of activity for the asset or liability have significantly decreased. This guidance is effective for interim reporting periods ending after June 15, 2009. Our adoption of this new guidance did not have a material impact on our financial position, results of operations or cash flows.

In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:

•

Commodity Prices – Economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless contractual arrangements designate the price to be used.

•

Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.

•

Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

•

Reserve Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

•

Reserve Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees our reserves estimation process. We will also be required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

•

Non-Traditional Resources – The definition of oil and gas producing activities will expand and focus on the marketable product rather than the method of extraction.

The rules are effective for fiscal years ending on or after December 31, 2009, and early adoption is not permitted. We do not expect the new rules to have a material impact on our reported natural gas and oil reserves for the fiscal year ending June 30, 2010.

In June 2008, the FASB issued new accounting guidance which addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method. This new guidance is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years. All prior-period EPS data presented shall be adjusted retrospectively (including interim financial statements, summaries of earnings, and selected financial data). The Company’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.

In December 2007, the FASB issued new accounting guidance which requires that most identifiable assets, liabilities and noncontrolling interests be recorded at full fair value and require noncontrolling interests to be reported as a component of equity. This new guidance is effective for periods beginning on or after December 15, 2008, and earlier adoption is prohibited. The Company’s adoption of this new guidance did not have any impact on its financial position, results of operations or cash flows.

Stock-Based Compensation. The Company applies the fair value based method to account for stock-based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. The fair value of each award is estimated as of the date of grant using the Black-Scholes option-pricing model. The Company also classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. In March 2010, the Company issued 25,000 options to a new employee with the following assumptions: (i) risk-free interest rate of 0.25 percent; (ii) expected life of five years; (iii) expected volatility of 35.43 percent and (iv) expected dividend yield of zero percent. The following weighted-average assumptions were used for the 60,000 options granted during the nine months ended March 31, 2009: (i) risk-free interest rate of 3.01 percent; (ii) expected life of five years; (iii) expected volatility of 53 percent and (iv) expected dividend yield of zero percent.

The Company’s 1999 Stock Incentive Plan expired in August 2009. Any outstanding options issued under the plan will be converted into securities if exercised prior to their expiration date, which expiration date ranges from June 2010 to September 2013.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

On September 15, 2009, the Company’s Board of Directors adopted the Contango Oil & Gas Company Annual Incentive Plan (the “2009 Plan”), which was approved by shareholders on November 19, 2009. Under the 2009 Plan, the Company’s Board of Directors can grant restricted stock awards to officers or other employees of the Company. Restricted stock awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board. Grants of service-based restricted stock awards are valued at our common stock price at the date of grant. The Company did not grant shares of restricted stock to any officer or director for the nine months ended March 31, 2010. For the nine months ended March 31, 2009, the Company granted 3,088 shares of restricted stock to its Board of Directors as part of its annual compensation. These shares vested over a period of one year.

During the nine months ended March 31, 2010 and 2009, the Company recorded stock-based compensation charges of $0.4 million and $1.1 million, respectively, to general and administrative expense for restricted stock and option awards. These amounts do not reflect compensation actually received by the individuals, but rather represent expense recognized in the Company’s consolidated financial statements that relate to restricted stock and option awards granted in current and previous fiscal years.

3. Natural Gas and Oil Exploration and Production Risk

The Company’s future financial condition and results of operations will depend upon prices received for its natural gas and oil production and the cost of finding, acquiring, developing and producing reserves. Substantially all of its production is sold under various terms and arrangements at prevailing market prices. Prices for natural gas and oil are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control.

Other factors that have a direct bearing on the Company’s financial condition are uncertainties inherent in estimating natural gas and oil reserves and future hydrocarbon production and cash flows, particularly with respect to wells that have not been fully tested and with wells having limited production histories; the timing and costs of our future drilling; development and abandonment activities; access to additional capital; changes in the price of natural gas and oil; availability and cost of services and equipment; and the presence of competitors with greater financial resources and capacity. The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect our reported results of operations, the amount of reported assets, liabilities and contingencies, and proved natural gas and oil reserves. We use the successful efforts method of accounting for our natural gas and oil activities.

4. Customer Concentration Credit Risk

The customer base for the Company is concentrated in the natural gas and oil industry. Major purchasers of our natural gas and oil for the nine months ended March 31, 2010 were ConocoPhillips Company, Shell Trading US Company, Atmos Energy Marketing, LLC, Trans Louisiana Gas Pipeline, Inc., and Enterprise Products Operating LLC. 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 are numerous other potential purchasers of our production.

5. Insurance Receivable

On February 24, 2010, a dredge contracted by the Army Corps of Engineers to dredge the Atchafalaya River Channel ruptured the Company’s 20” pipeline that runs from our Eugene Island 11 gathering platform to the Eugene Island 63 platform where our pipeline joins a third-party pipeline that transports our production to shore. The pipeline was repaired and production resumed on March 31, 2010. We believe the repairs will be covered by our insurance policy subject to an 8/8ths deductible of $500,000 and have recorded an insurance receivable of approximately $1.8 million in the Consolidated Balance Sheet as of March 31, 2010 as a result of this incident.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

6. Net Income per Common Share

A reconciliation of the components of basic and diluted net income per share of common stock is presented in the tables below:


	Three Months Ended March 31, 2010					Three Months Ended March 31, 2009
	Income		Weighted Average Shares	Per Share		Income		Weighted Average Shares	Per Share
Basic Earnings per Share:
Net income attributable to common stock	$	1,742,060	15,859,618	$	0.11	$	847,614	16,162,928	$	0.05

Effect of potential dilutive securities:
Stock options, net of shares assumed purchased		—	303,371		—		—	302,516		—
Restricted shares		—	—		—		—	1,544		—

Diluted Earnings per Share:
Net income, attributable to common stock	$	1,742,060	16,162,989	$	0.11	$	847,614	16,466,988	$	0.05

Anti-dilutive securities:


	Nine Months Ended March 31, 2010					Nine Months Ended March 31, 2009
	Income		Weighted Average Shares	Per Share		Income		Weighted Average Shares	Per Share
Basic Earnings per Share:
Net income attributable to common stock	$	34,319,195	15,840,607	$	2.17	$	50,684,573	16,543,485	$	3.06

Effect of potential dilutive securities:
Stock options, net of shares assumed purchased		—	319,093		—		—	312,107		—
Restricted shares		—	515		—		—	1,544		—

Diluted Earnings per Share:
Net income, attributable to common stock	$	34,319,195	16,160,215	$	2.12	$	50,684,573	16,857,136	$	3.01

Anti-dilutive securities:

Options to purchase 85,000 shares of common stock were outstanding as of March 31, 2010, but were not included in the computation of diluted earnings per share for the three and nine months ended March 31, 2010. Options to purchase 45,000 shares of common stock were outstanding as of March 31, 2009, but were not included in the computation of diluted earnings per share for the three and nine months ended March 31, 2009. These options were excluded because either (i) the option’s exercise price was greater than the average market price of the common shares, or (ii) application of the treasury method to in-the-money options made some of these options anti-dilutive.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

7. Related Party Transactions

During March 2010, the Company purchased 29,683 shares of common stock from certain directors and employees at a cost of approximately $1.6 million, or $54.44 per share, which represented the closing price of the Company’s common stock on the date sold.

Effective October 1, 2009, the Company’s wholly-owned subsidiary, Conterra Company (“Conterra”), entered into a joint venture with Patara Oil & Gas LLC (“Patara”), a privately held oil and gas company, to develop proved undeveloped Cotton Valley gas reserves in Panola County, Texas. B.A. Berilgen, a member of the Company’s board of directors, is the Chief Executive Officer of Patara.

On March 31, 2006, COE executed in favor of the Company, a Promissory Note (the “Note”) in the aggregate principal amount of $2,800,550, and carried a per annum interest rate of 10%. Since that date, the aggregate principal amount of the Note has increased to $5.9 million, and the interest rate has been reduced to 5%. As of March 31, 2010, COE had borrowed $4.3 million under the Note, with accrued and unpaid interest on the Note of approximately $1.6 million.

8. Subsequent Events

During April 2010, the Company purchased 85,771 shares of common stock from certain directors and employees at a cost of approximately $4.7 million, or $55.25 per share, which represented the closing price of the Company’s common stock on the date sold.

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, 2009, previously filed with the SEC.

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

Although we believe the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will occur. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These factors include:

•

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 raise capital to fund capital expenditures

•

Timely and full receipt of sale proceeds from the sale of our production

•

The ability to find, acquire, market, develop and produce new natural gas and oil properties

•

Interest rate volatility

•

Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures

•

Operating hazards attendant to the natural gas and oil business

•

Downhole drilling and completion risks that are generally not recoverable from third parties or insurance

•

Potential mechanical failure or under-performance of significant wells, production facilities, processing plants or pipeline mishaps

•

Weather

•

Availability and cost of material and equipment

•

Delays in anticipated start-up dates

•

Actions or inactions of third-party operators of our properties

•

Actions or inactions of third-party operators of pipelines or processing facilities

•

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

•

Drilling and operating costs, production rates and ultimate reserve recoveries in our Eugene Island 10 (“Dutch”) and State of Louisiana (“Mary Rose”) acreage.

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.

Overview

Contango is a Houston-based, independent natural gas and oil company. The Company’s core business is to explore, develop, produce and acquire natural gas and oil properties primarily offshore in the Gulf of Mexico. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore prospects.

Our Strategy

Our exploration strategy is predicated upon two core beliefs: (1) that the only competitive advantage in the commodity-based natural gas and oil business is to be among the lowest cost producers and (2) that virtually all the exploration and production industry’s value creation occurs through the drilling of successful exploratory wells. As a result, our business strategy includes the following elements:

Funding exploration prospects generated by Juneau Exploration, L.P., our alliance partner. We depend primarily upon our alliance partner, Juneau Exploration, L.P. (“JEX”), for prospect generation expertise. JEX is experienced and has a successful track record in exploration.

Using our limited capital availability to increase our reward/risk potential on selective prospects. We have concentrated our risk investment capital in our offshore Gulf of Mexico prospects. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success. COI drills and operates our offshore prospects. Should we be successful in any of our offshore prospects, we will have the opportunity to spend significantly more capital to complete development and bring the discovery to producing status.

Sale of proved properties. From time-to-time as part of our business strategy, we have sold and in the future expect to continue to sell some or a substantial portion of our proved reserves and assets to capture current value, using the sales proceeds to further our offshore exploration activities. Since its inception, the Company has sold approximately $484 million worth of natural gas and oil properties, and views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, and as a source of funds for potentially higher rate of return natural gas and oil exploration opportunities.

Controlling general and administrative and geological and geophysical costs. Our goal is to be among the most efficient in the industry in revenue and profit per employee and among the lowest in general and administrative costs. We plan to continue outsourcing our geological, geophysical, and reservoir engineering and land functions.

Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our employees and stockholders. Our directors and executive officers beneficially own or have voting control over approximately 23% of our common stock.

Exploration Alliance with JEX

JEX is a private company formed for the purpose of assembling domestic natural gas and oil prospects. Under our agreement with JEX, JEX generates natural gas and oil prospects and evaluates exploration prospects generated by others. JEX focuses on the Gulf of Mexico, and generates offshore exploration prospects via our affiliated companies, Republic Exploration LLC (“REX”) and Contango Offshore Exploration LLC (“COE”) (see “Offshore Gulf of Mexico Exploration Joint Ventures” below). We do not have a written agreement with JEX which contractually obligates them to provide us with their services.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango, through its wholly-owned subsidiary COI, and its partially-owned subsidiaries, REX and COE, conducts exploration activities in the Gulf of Mexico. As of April 30, 2010, Contango, through COI, REX and COE, had an interest in 26 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

Contango owns a 32.3% equity interest in REX and a 65.6% equity interest in COE, both of which were formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These companies focus on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to Contango, subject to timed drilling obligations plus retained reversionary interests in favor of REX and COE.

Republic Exploration LLC

West Delta 36, a REX prospect, is operated by a third party. The Company depends on a third-party operator for the operation and maintenance of this production platform. The well is currently temporarily shut-in to build well pressure. REX has a 25.0% working interest (“WI”), and a 20.0% net revenue interest (“NRI”), in this well.

Contango Offshore Exploration LLC

Ship Shoal 263 (“Nautilus”), a COE prospect, was spud by COI in October 2009. In January 2010, the Company announced a successful well at this prospect. The Company has a working interest of approximately 94% and a net revenue interest of approximately 74% in this well, inclusive of its investment in COE. Production is expected to begin by mid-summer 2010 at an estimated rate of 20 million cubic feet equivalent per day (“Mmcfed”), net to Contango. We have invested approximately $14.7 million to drill this well and expect to invest an additional $22.9 million, net to Contango, to complete and bring the well to full production status.

Grand Isle 70, another COE prospect, was drilled by COI in July 2006 and was temporarily abandoned while alternative development scenarios were being evaluated. Effective December 31, 2009 the Company and COE sold their respective interests in Grand Isle 70 to an independent third-party oil and gas company in exchange for an overriding royalty interest. During the three months ended March 31, 2010, all overriding royalty interests were sold to JEX for a gain of $112,868.

Grand Isle 72 (“Liberty”), another COE prospect, ceased producing in October 2009. The well has been plugged and abandoned and we are in the process of removing the platform. Estimated costs to permanently abandon the site are approximately $650,000, net to Contango. The Company is in the process of relinquishing the lease to the Minerals Management Service (“MMS”).

As of March 31, 2010, COE had borrowed $4.3 million from the Company under a promissory note (the “Note”). Effective January 1, 2010, the interest rate on the Note was reduced from 10% to 5% per annum. The Note is payable upon demand. As of March 31, 2010, accrued and unpaid interest on the Note was approximately $1.6 million.

Contango Operators, Inc.

COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling and operating exploration and development wells in the Gulf of Mexico. Additionally, COI expects to acquire significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out agreement, or similar agreement, with either REX or COE. COI may also operate and acquire significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.

Nearly all of the Company’s production is from its four Dutch wells, four Mary Rose wells, and Eloise North well, all located on federal and State of Louisiana leases in the shallow water of the Gulf of Mexico. These nine wells produce via two platforms: the Company-owned and operated platform at Eugene Island 11 and a third-party owned and operated platform at Eugene Island 24.

Eugene Island 11 Platform

As of April 30, 2010, the Company’s platform at Eugene Island 11 was processing approximately 30 Mmcfed, net to Contango. This platform was designed with a capacity of 500 million cubic feet per day (“Mmcfd”) and 6,000 barrels of oil per day (“bopd”). This platform services production from the Company’s four Mary Rose wells, our Eloise North well, and our Dutch #4 well. From the Eugene Island 11 platform, the gas and condensate flow to Eugene Island 63 via our pipeline, which has been designed with a capacity of 330 Mmcfd and 6,000 bopd, and then to on-shore processing facilities near Patterson, Louisiana.

On February 24, 2010, a dredge contracted by the Army Corps of Engineers to dredge the Atchafalaya River Channel ruptured the Company’s 20” pipeline that runs from our Eugene Island 11 gathering platform to the Eugene Island 63 platform where our pipeline joins a third-party pipeline that transports our production to shore. All six wells serviced by the platform were immediately shut-in upon pipeline rupture, and we immediately implemented our spill response plan. The Company estimates that a minimal and immaterial quantity of production was lost. The pipeline was repaired and production resumed on March 31, 2010. We believe the repairs will be covered by our insurance policy subject to an 8/8ths deductible of $500,000. We have an approximate 53% ownership interest in the pipeline.

Eugene Island 24 Platform

The third-party owned and operated production platform at Eugene Island 24 was processing approximately 51 Mmcfed, net to Contango as of April 30, 2010. This platform was designed with a capacity of 100 Mmcfd and 3,000 bopd. This platform services production from the Company’s Dutch #1, #2 and #3 wells.

Other Activities

In March 2010, we spud two exploration wells in the Gulf of Mexico. The first well was a farm-in we obtained on block Eugene Island 10 to drill a well on our Eloise South prospect. This well was spud March 2, 2010 and will test the Rob L sands identified in our Eloise North well. The well is being drilled in a location so that upon depletion of our Eloise South well, our well bore may be completed up-hole and produce in the Cib-op sand as our Dutch #5 well. The Company has a 29.7% working interest (19% net revenue interest) in Eloise South, and a 47.0% working interest (37.6% net revenue interest) in Dutch #5. The Company expects to log this well prior to the end of May 2010 and has budgeted to invest approximately $8.9 million, net to our interest, to drill and complete Eloise South, and another $3.5 million to build a platform.

The second well was a farm-in we obtained on block Vermillion 155 (“Paisano”). This well was spud on March 25, 2010 and was determined to be a dry hole in April 2010. The well has an estimated dry hole cost of approximately $6.1 million and the Company has a 100% working interest.

On March 17, 2010, COI was the apparent high bidder on three lease blocks at the Central Gulf of Mexico Lease Sale No. 213. We bid $3,017,777 on Ship Shoal 121, $277,777 on Ship Shoal 122 and $3,017,777 on Vermillion 170. An apparent high bid (“AHB”) gives the bidding party priority in award of offered tracts, notwithstanding the fact that the MMS may reject all bids for a given tract. The MMS review process may take up to 90 days for some bids. Upon completion of that process, final results for all AHBs will be known.

Effective November 1, 2009, COI was awarded three lease blocks from the Western Gulf of Mexico Lease Sale No. 210 held on August 19, 2009. COI bid approximately $1.7 million for such leases. The Company was awarded Matagorda Island Blocks 607 and 616 (collectively, “El Duderino”) and Matagorda Island Block 617 (“Dude”). Our Dude well was drilled in mid-February 2010 and determined to be a dry hole in April 2010. The well has an estimated dry hole cost of approximately $16.0 million and the Company has a 100% working interest.

Effective October 6, 2009, COI was awarded five leases from the State of Texas Lease Sale held on October 6, 2009. COI bid approximately $800,000 for such leases. The Company was awarded Galveston Area 248L, 276L, 277L (N/2 of NE/4), 277L (S/2 of NE/4) and 338S (collectively, “His Dudeness”).

Offshore Properties

Producing Properties. The following table sets forth the interests owned by Contango through its related entities in the Gulf of Mexico which were producing natural gas or oil as of April 30, 2010:


Area/Block	WI		NRI		Status
Contango Operators, Inc.:
Eugene Island 10 #D-1 (Dutch #1)	47.05	%	38.1	%	Producing
Eugene Island 10 #E-1 (Dutch #2)	47.05	%	38.1	%	Producing
Eugene Island 10 #F-1 (Dutch #3)	47.05	%	38.1	%	Producing
Eugene Island 10 #G-1 (Dutch #4)	47.05	%	38.1	%	Producing
S-L 18640 #1 (Mary Rose #1)	53.21	%	40.5	%	Producing
S-L 19266 #1 (Mary Rose #2)	53.21	%	38.7	%	Producing
S-L 19266 #2 (Mary Rose #3)	53.21	%	38.7	%	Producing
S-L 18860 #1 (Mary Rose #4)	34.58	%	25.5	%	Producing
S-L 19266 #3 (Eloise North #1)	36.90	%	26.9	%	Producing

Republic Exploration LLC
West Delta 36	25.0	%	20.0	%	Shut-in

Contango Offshore Exploration LLC:
Ship Shoal 358, A-3 well	10.0	%	7.7	%	Shut-in

Leases. The following table sets forth the working interests owned by Contango and related entities in other non-developed leases in the Gulf of Mexico as of April 30, 2010.


Area/Block	WI		Lease Date	Expiration Date
Contango Operators, Inc.:
Ship Shoal 14	50.00	%	May-06	May-11
Ship Shoal 263	25.00	%	Jun-06	Jun-11
S-L 19261	53.21	%	Feb 07	Feb 12
S-L 19396	53.21	%	Jun 07	Jun 12
Eugene Island 11	53.21	%	Dec 07	Dec-12
Eugene Island 56 (1)	100.00	%	Jul-08	Jul-13
Galveston Area 248L	100.00	%	Oct-09	Oct-14
Galveston Area 276L	100.00	%	Oct-09	Oct-14
Galveston Area 277L (N/2 of NE/4)	100.00	%	Oct-09	Oct-14
Galveston Area 277L (S/2 of NE/4)	100.00	%	Oct-09	Oct-14
Galveston Area 338S	100.00	%	Oct-09	Oct-14
Matagorda Island 607	100.00	%	Nov-09	Nov-14
Matagorda Island 616	100.00	%	Nov-09	Nov-14
Matagorda Island 617 (1)	100.00	%	Nov-09	Nov-14

Republic Exploration LLC
Ship Shoal 14	50.00	%	May-06	May-11
East Cameron 210	100.00	%	Jun-09	Jun-14
South Timbalier 97	100.00	%	Jun-09	Jun-14

Contango Offshore Exploration LLC:
Ship Shoal 263	75.00	%	Jun-06	Jun-11
Viosca Knoll 383	(2	)	Jun-06	Jun-11
East Breaks 369	(3	)	Dec-03	Dec-13
East Breaks 370	100.00	%	Dec-03	Dec-13
East Breaks 366	100.00	%	Nov-05	Nov-15
East Breaks 410	100.00	%	Nov-05	Nov-15

(1)

Dry Hole

(2)	Farm out. COE retained a 2.67% ORRI

(3)	Farm out. COE will receive a 3.67% ORRI before project payout and a 6.67% ORRI after project payout

Onshore Exploration and Properties

Conterra Company

Under the terms of the joint venture agreement (the “Joint Venture Agreement”), Conterra will fund 100% of the drilling and completion costs in exchange for 90% of the net revenues. The Joint Venture Agreement contemplates drilling up to 15 wells, at an estimated 8/8ths cost of approximately $1.5 million per well. The average 8/8ths reserves per well are expected to be approximately 1.5 Bcfe (1.125 net Bcfe after a 25% royalty).

By paying all of the drilling and completion costs, the Company will be able to benefit from the associated tax deductions which are estimated to be about 75% of total drilling costs, or approximately $1.1 million per well. Upon the Company achieving a 15% per annum cash-on-cash rate of return on a basket of 15 wells, the Company’s net revenue interest converts into a 5% overriding royalty interest.

As of April 30, 2010, we were producing at a rate of approximately 2.9 Mmcfed, net to Contango, from five wells. Three additional wells have been logged and are waiting to be fracture stimulated while another two wells are drilling ahead. To date we have invested approximately $14.2 million in this drilling program. Based on results to date, and using our current received gas price of $3.30 per thousand cubic feet equivalent, we are on track to earn our projected cash-on-cash pre-tax 15% rate of return.

Lavaca County, Texas

The Company has budgeted to drill a wildcat exploration well in south Texas prior to June 30, 2010, at an estimated cost of approximately $3 million, net to Contango.

Contango ORE Company

During the nine months ended March 31, 2010, the Company created a new wholly-owned subsidiary, Contango ORE Company (“CORE”), to initially invest up to $3.0 million to conduct mineral exploration activities on approximately 580,000 acres of Alaska Native and State of Alaska lands located in interior Alaska (“Mineral Exploration Lands”). CORE purchased a 50% ownership from a private company for $1.0 million, together with our commitment to invest the next $2.0 million of capital expenditures to fund the expenses associated with the initial mineral exploration phase on this acreage. CORE and its partner will share expenses on a ⁵⁰/50 basis thereafter and each will own a 50% working interest burdened by an approximate 5% overriding royalty interest. CORE has thus far invested a total of $1.3 million. Should this summer’s planned trenching, soil samples and mineralization studies indicate that additional exploration is warranted, CORE will have the opportunity to invest significantly more capital in this project.

Employees

Effective March 1, 2010, the Company outsourced its human resources function to Administaff Companies II, LP (“Administaff”) and all of the Company’s employees became co-employees of Administaff. The Company has eight employees.

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 2 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 to estimate the fair value of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Reserve Estimates. While we are reasonably certain of recovering our reported reserves, the Company’s estimates of natural gas and oil reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s natural gas and oil properties and/or the rate of depletion of such natural gas and oil properties. 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, 2010 of 1% would not have a material effect on depreciation, depletion and amortization expense. Holding all other factors constant, a reduction in the Company’s proved reserve estimate at March 31, 2010 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $1.3 million, $2.6 million and $4.2 million, respectively.

Impairment of Natural Gas and Oil Properties. The Company reviews its proved natural gas and oil properties for impairment on an annual basis or whenever events and circumstances indicate a potential decline in the recoverability of their carrying value. The Company compares expected undiscounted future net cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows, based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Given the complexities associated with natural gas and oil reserve estimates and the history of price volatility in the natural gas and oil markets, events may arise that will require the Company to record an impairment of its natural gas and oil properties and there can be no assurance that such impairments will not be required in the future nor that they will not be material.

Stock-Based Compensation. The Company measures and recognizes compensation expense for all stock-based payments at fair value. Management makes assumptions including stock price volatility and employee turnover that are utilized to measure compensation expense. The fair value of stock options granted is estimated at the date of grant using the Black-Scholes option-pricing model. This model requires the input of assumptions, which are set forth in Note 2 to our consolidated financial statements.

MD&A Summary Data

The table below sets forth revenue, expense and production data for the three and nine months ended March 31, 2010 and 2009.


	Three Months Ended March 31,						Nine Months Ended March 31,
	2010		2009		Change		2010		2009		Change
	($000)						($000)
Revenues:
Natural gas, oil and NGL sales	$	37,846	$	36,133	5	%	$	119,529	$	154,371	-23	%

Total revenues	$	37,846	$	36,133	5	%	$	119,529	$	154,371	-23	%


Production:
Natural gas (million cubic feet)		4,043		5,351	-24	%		15,991		14,523	10	%
Oil and condensate (thousand barrels)		102		148	-31	%		400		363	10	%
Natural gas liquids (thousand gallons)		4,881		6,009	-19	%		18,685		16,836	11	%

Total (million cubic feet equivalent)		5,352		7,097	-25	%		21,060		19,106	10	%

Natural gas (million cubic feet per day)		44.9		59.5	-24	%		58.4		53.0	10	%
Oil and condensate (thousand barrels per day)		1.1		1.6	-31	%		1.5		1.3	15	%
Natural gas liquids (thousand gallons per day)		54.2		66.8	-19	%		68.2		61.4	11	%

Total (million cubic feet equivalent per day)		59.2		78.6	-25	%		77.1		69.6	11	%

Average Sales Price:
Natural gas (per thousand cubic feet)	$	5.90	$	4.82	22	%	$	4.42	$	7.29	-39	%
Oil and condensate (per barrel)	$	78.48	$	41.60	89	%	$	73.51	$	73.05	1	%
Natural gas liquids (per gallon)	$	1.22	$	0.69	77	%	$	1.04	$	1.30	-20	%

Total (per thousand cubic feet equivalent)	$	7.07	$	5.09	39	%	$	5.68	$	8.08	-30	%

Operating expenses	$	3,524	$	4,553	-23	%	$	11,066	$	14,506	-24	%
Exploration expenses	$	22,756	$	12,757	78	%	$	23,334	$	20,388	14	%
Depreciation, depletion and amortization	$	6,838	$	8,920	-23	%	$	25,182	$	22,167	14	%
Lease expiration expenses	$	736	$	3,679	-80	%	$	736	$	4,125	-82	%
Impairment of natural gas and oil properties	$	—	$	2,709	-100	%	$	—	$	2,709	-100	%
General and administrative expenses	$	1,200	$	1,490	-19	%	$	4,380	$	5,994	-27	%
Interest expense	$	109	$	147	-26	%	$	420	$	590	-29	%
Interest income	$	536	$	154	248	%	$	834	$	758	10	%
Gain on sale of assets and other	$	113	$	—	100	%	$	113	$	—	100	%

Three Months Ended March 31, 2010 Compared to Three Months Ended March 31, 2009

Natural Gas, Oil and Natural Gas Liquids (“NGL”) Sales. We reported revenues of approximately $37.8 million for the three months ended March 31, 2010, compared to revenues of approximately $36.1 million for the three months ended March 31, 2009. This increase in sales was principally attributable to a significant increase in natural gas, oil and NGL prices received for the three months ended March 31, 2010. This increase in sales was partially offset by lower produced volumes due to our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in 2010.

Average Sales Prices. For the three months ended March 31, 2010, the average price of natural gas was $5.90 per thousand cubic feet (“Mcf”) while the average price for oil and condensate was $78.48 per barrel and the average price for NGLs was $1.22 per gallon. For the three months ended March 31, 2009, the average price of natural gas was $4.82 per Mcf while the average price for oil and condensate was $41.60 per barrel and the average price for NGLs was $0.69 per gallon.

Natural Gas, Oil and NGL Production. Our net natural gas production for the three months ended March 31, 2010 was approximately 44.9 Mmcfd, down from approximately 59.5 Mmcfd for the three months ended March 31, 2009. Net oil and condensate production for the comparable periods also decreased from approximately 1,600 barrels per day to approximately 1,100 barrels per day, and our NGL production decreased from approximately 66,800 gallons per day to approximately 54,200 gallons per day. This decrease in natural gas, oil and NGL production was principally attributable to our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in 2010.

Operating Expenses. Lease operating expenses (“LOE”) for the three months ended March 31, 2010 were approximately $3.5 million, which included approximately $1.0 million in Louisiana state severance taxes. Lease operating expenses for the three months ended March 31, 2009 were approximately $4.6 million, which included a credit of approximately $2.9 million of Louisiana state severance taxes. For wells drilled to a true vertical depth of 15,000 feet or more, where production commences after July 31, 1994, the State of Louisiana exempts taxpayers from paying severance taxes on these wells for 24 months from the date production begins, or until payout of well cost, whichever comes first. The decrease in LOE was attributable to our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in 2010.

Exploration Expense. We reported $22.8 million of exploration expense for the three months ended March 31, 2010. Of this amount, approximately $6.1 million relates to dry hole costs for Vermillion 155, $16.0 million relates to dry hole costs for Matagorda Island 617, and the remaining $0.7 million is attributable to various geological and geophysical activities, seismic data, and delay rentals. For the three months ended March 31, 2009, we reported $12.8 million of exploration expense. Of this amount, approximately $12.5 million was related to dry hole costs for Eugene Island 56 while the remaining $0.3 million was attributable to various geological and geophysical activities, seismic data, and delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2010 was approximately $6.8 million. For the three months ended March 31, 2009, we recorded approximately $8.9 million of depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization was primarily attributable to reduced production as a result of our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in 2010.

Lease Expiration and Relinquishment Expense. For the three months ended March 31, 2010, the Company recorded lease expiration and relinquishment expense of $735,553 related to the relinquishment of South Marsh Island 57, South Marsh Island 59 and South Marsh Island 75. For the three months ended March 31, 2009, the Company recorded lease expiration and relinquishment expense of $3.7 million due to the expiration and relinquishment of 40 lease blocks owned by our partially-owned subsidiaries, REX and COE.

Impairment Expense. No impairment expense was recorded for the three months ended March 31, 2010. For the three months ended March 31, 2009, the Company recorded impairment expense of approximately $2.7 million related to our Grand Isle 70 well as a result of the expected future undiscounted net cash flows of this well being lower than the unamortized capitalized cost.

General and Administrative Expenses. General and administrative expenses for the three months ended March 31, 2010 and the three months ended March 31, 2009 were approximately $1.2 million and $1.5 million, respectively.

Major components of general and administrative expenses for the three months ended March 31, 2010 included approximately $0.3 million in State of Louisiana franchise taxes, $0.5 million in salaries and benefits, $0.1 million in accounting, tax, legal, engineering and other professional fees, $0.2 million in insurance costs, and $0.1 million related to the cost of expensing stock options and stock grant compensation.

Major components of general and administrative expenses for the three months ended March 31, 2009 included approximately $0.2 million in State of Louisiana franchise taxes, $0.6 million in salaries and benefits, $0.3 million in accounting, tax, legal, engineering and other professional fees, $0.1 million in insurance costs, and $0.3 million related to the cost of expensing stock options and stock grant compensation.

Interest Expense. We reported interest expense of $109,047 for the three months ended March 31, 2010, compared to interest expense of $147,392 for the three months ended March 31, 2009. This interest expense is a combination of commitment fees paid under our credit facility, as well as a portion of COE’s interest expense on the Note as a result of our proportionate consolidation of COE. The decrease is attributable to lowering the interest rate on the Note effective January 1, 2010.

Interest Income. We reported interest income of $535,855 for the three months ended March 31, 2010, compared to $154,058 of interest income reported for the three months ended March 31, 2009. Both periods include interest income as a result of the loan made by the Company to COE. The higher levels of interest income in 2010 are attributable to higher cash balances.

Gain on Sale of Assets and Other. For the three months ended March 31, 2010, the Company reported a gain on sale of assets and other of $112,868 related to the sale of its Grand Isle 70 well. The Company had no gain on sale of assets and other during the three months ended March 31, 2009.

Nine Months Ended March 31, 2010 Compared to Nine Months Ended March 31, 2009

Natural Gas, Oil and Natural Gas Liquids (“NGL”) Sales. We reported revenues of approximately $119.5 million for the nine months ended March 31, 2010, compared to revenues of approximately $154.4 million for the nine months ended March 31, 2009. This decrease was principally attributable to the significant decline in natural gas, oil and condensate and NGL prices received for the nine months ended March 31, 2010 as well as by a reduction in production resulting from our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in 2010. The decrease was partially offset by increased natural gas and oil sales from our Eloise North well which began producing in December 2008 and our Dutch #4 well which began producing in January 2009. The decrease in sales was also offset by increased production from our Dutch #1, #2 and #3 wells which resumed production after being shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike.

Average Sales Prices. For the nine months ended March 31, 2010, the average price of natural gas was $4.42 per Mcf while the average price for oil and condensate was $73.51 per barrel and the average price for NGLs was $1.04 per gallon. For the nine months ended March 31, 2009, the average price of natural gas was $7.29 per Mcf while the average price for oil and condensate was $73.05 per barrel and the average price for NGLs was $1.30 per gallon.

Natural Gas, Oil and NGL Production. Our net natural gas production for the nine months ended March 31, 2010 was approximately 58.4 Mmcfd, up from approximately 53.0 Mmcfd for the nine months ended March 31,

2009. Net oil and condensate production for the comparable periods also increased from approximately 1,300 barrels per day to approximately 1,500 barrels per day, and our NGL production increased from approximately 61,400 gallons per day to approximately 68,200 gallons per day. This increase in natural gas, oil and NGL production was principally attributable to our Eloise North well which began producing in December 2008 and our Dutch #4 well which began producing in January 2009. The increase in production was also attributable to our Dutch #1, #2 and #3 wells which were shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike. This increase in production was partially offset by our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in 2010.

Operating Expenses. LOE for the nine months ended March 31, 2010 were approximately $11.1 million, which included approximately $3.7 million of Louisiana state severance taxes. Lease operating expenses for the nine months ended March 31, 2009 were approximately $14.5 million, which included $2.1 million of Louisiana state severance taxes, which includes a credit of approximately $2.9 million. For wells drilled to a true vertical depth of 15,000 feet or more, where production commences after July 31, 1994, the State of Louisiana exempts taxpayers from paying severance taxes on these wells for 24 months from the date production begins, or until payout of well cost, whichever comes first.

Exploration Expense. We reported approximately $23.3 million of exploration expense for the nine months ended March 31, 2010. Of this amount, approximately $6.1 million related to the dry hole the Company drilled at Vermillion 155, $16.0 million related to the dry hole the Company drilled at Matagorda Island 617, and the remaining $1.2 million related to various geological and geophysical activities, seismic data, and delay rentals. For the nine months ended March 31, 2009, we reported approximately $20.4 million of exploration expense. Of this amount, approximately $7.1 million related to the dry hole the Company drilled at West Delta 77, $12.5 million related to the dry hole the Company drilled at Eugene Island 56, and the remaining $0.8 million related to various geological and geophysical activities, seismic data, and delay rentals.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the nine months ended March 31, 2010 was approximately $25.2 million. For the nine months ended March 31, 2009, we recorded approximately $22.2 million of depreciation, depletion and amortization. The increase in depreciation, depletion and amortization was primarily attributable to added production from newly added reserves from our Eloise North and Dutch #4 wells. The increase was also attributable to reduced production during all of September, October and the majority of November 2008 from our Dutch #1, #2 and #3 wells which were shut-in due to Hurricane Ike. This increase in depreciation, depletion and amortization was partially offset by our ruptured 20” pipeline which shut-in production from our four Mary Rose wells, Dutch #4 and our Eloise North wells for approximately 35 days in 2010.

Lease Expiration and Relinquishment Expense. For the nine months ended March 31, 2010, the Company recorded lease expiration and relinquishment expense of $735,553 related to the relinquishment of South Marsh Island 57, South Marsh Island 59 and South Marsh Island 75. For the nine months ended March 31, 2009, the Company recorded lease expiration and relinquishment expense of approximately $4.1 million due to the expiration and relinquishment of 43 lease blocks owned by REX and COE.

Impairment Expense. No impairment expense was recorded for the nine months ended March 31, 2010. For the nine months ended March 31, 2009, the Company recorded impairment expense of approximately $2.7 million related to our Grand Isle 70 well as a result of the expected future undiscounted net cash flows of this well being lower than the unamortized capitalized cost.

General and Administrative Expenses. General and administrative expenses for the nine months ended March 31, 2010 and the nine months ended March 31, 2009 were approximately $4.4 million and $6.0 million, respectively.

Major components of general and administrative expenses for the nine months ended March 31, 2010 included approximately $2.4 million in salaries and benefits, $0.6 million in accounting, tax, legal, engineering and other professional fees, $0.1 million in office administration expenses, $0.4 million in insurance costs, $0.5 million in State of Louisiana franchise taxes, and $0.4 million related to the cost of expensing stock options and stock grant compensation.

Major components of general and administrative expenses for the nine months ended March 31, 2009 included approximately $1.7 million in salaries and benefits, $1.3 million in accounting, tax, legal, engineering and other professional fees, $0.2 million in office administration expenses, $0.4 million in insurance costs, $1.3 million in State of Louisiana franchise taxes, and $1.1 million related to the cost of expensing stock options and stock grant compensation.

Interest Expense. We reported interest expense of $420,311 for the nine months ended March 31, 2010, compared to interest expense of $589,812 for the nine months ended March 31, 2009. A portion of this interest expense is the Company’s portion of COE’s interest expense on the Note as a result of our proportionate consolidation of COE. The remaining balance is interest expense related to credit facilities, under which we had amounts outstanding during the nine months ended March 31, 2009.

Interest Income. We reported interest income of $834,160 for the nine months ended March 31, 2010, compared to interest income of $757,571 for the nine months ended March 31, 2009. Both periods include interest income as a result of the loan made by the Company to COE. The higher levels of interest income in 2010 are attributable to higher cash balances.

Gain on Sale of Assets and Other. For the nine months ended March 31, 2010, the Company reported a gain on sale of assets and other of $112,868 related to the sale of its Grand Isle 70 well. The Company had no gain on sale of assets and other during the nine months ended March 31, 2009.

Production, Prices, Operating Expenses, and Other


	Three Months Ended March 31,				Nine Months Ended March 31,
	2010		2009		2010		2009
	(Dollar amounts in 000’s, except per Mcfe amounts)				(Dollar amounts in 000’s, except per Mcfe amounts)
Production Data:
Natural gas (million cubic feet)		4,043		5,351		15,991		14,523
Oil and condensate (thousand barrels)		102		148		400		363
Natural gas liquids (thousand gallons)		4,881		6,009		18,685		16,836

Total (million cubic feet equivalent)		5,352		7,097		21,060		19,106

Natural gas (million cubic feet per day)		44.9		59.5		58.4		53.0
Oil and condensate (thousand barrels per day)		1.1		1.6		1.5		1.3
Natural gas liquids (thousand gallons per day)		54.2		66.8		68.2		61.4

Total (million cubic feet equivalent per day)		59.2		78.6		77.1		69.6

Average Sales Price:
Natural gas (per thousand cubic feet)	$	5.90	$	4.82	$	4.42	$	7.29
Oil and condensate (per barrel)	$	78.48	$	41.60	$	73.51	$	73.05
Natural gas liquids (per gallon)	$	1.22	$	0.69	$	1.04	$	1.30

Total (per thousand cubic feet equivalent)	$	7.07	$	5.09	$	5.68	$	8.08

Selected data per Mcfe:
Lease operating expenses	$	0.66	$	0.64	$	0.53	$	0.76
General and administrative expenses	$	0.22	$	0.21	$	0.21	$	0.31
Depreciation, depletion and amortization of natural gas and oil properties	$	1.24	$	1.23	$	1.17	$	1.12

Capital Resources and Liquidity

Cash From Operating Activities. Cash flows from operating activities provided approximately $98.7 million in cash for the nine months ended March 31, 2010 compared to $69.8 million for the same period in 2009. This increase in cash provided by operating activities was attributable to increased natural gas, oil and NGL production attributable to our Eloise North and Dutch #4 well. The increase in production was also attributable to our Dutch #1, #2 and #3 wells which were shut-in during all of September, October and the majority of November 2008 due to Hurricane Ike.

Cash From Investing Activities. Cash flows used in investing activities for the nine months ended March 31, 2010 were approximately $41.3 million, compared to using $23.1 million in investing activities for the nine months ended March 31, 2009. This increase was primarily attributable to increased capital expenditures for drilling exploration and developmental wells.

Cash From Financing Activities. Cash flows used in financing activities for the nine months ended March 31, 2010 were approximately $1.4 million, compared to using $65.1 million for the same period in 2009. During the nine months ended March 31, 2009, the Company paid off its credit facility and repurchased significant amounts of common stock pursuant to our share repurchase program. There were no credit facility payments and fewer purchases of common stock during the nine months ended March 31, 2010.

Capital Budget. For the remainder of calendar year 2010, the Company has budgeted to invest approximately $72.2 million as follows:

•

We will invest approximately $17.2 million to finish completing, build a platform, lay a pipeline, build facilities and hook up our Nautilus discovery.

•

We will invest approximately $12.4 million to drill and complete, build a platform, lay a pipeline, build facilities and hook up our Eloise South prospect.

•

We will invest approximately $20.6 million to pay for our dry holes at Vermillion 155 and Matagorda Island 617.

•

We will invest approximately $11.2 million to drill and complete seven additional on-shore wells in Panola County, Texas under our joint venture with Patara Oil & Gas LLC.

•

We will invest approximately $3.0 million to drill a conventional on-shore Texas prospect that is currently under farm-in negotiations.

•

We will invest approximately $0.6 million to plug and abandon Grand Isle 72.

•

We will invest approximately $2.0 million in our Alaskan mineral exploration project.

•

We will invest approximately $5.2 million in lease payments and delay rentals should we be awarded the leases from the AHB at the Central Gulf of Mexico Lease Sale No 213 held on March 17, 2010.

Of the $72.2 million of capital expenditures planned for the remainder of this calendar year, the Company has incurred expenses of approximately $42.2 million and accrued for this amount as a current liability in the Consolidated Balance Sheet as of March 31, 2010.

The Company often reviews acquisitions and prospects presented to us by third parties and may decide to invest in one or more of these opportunities. There can be no assurance that we will invest, or that any investment entered into will be successful. These potential investments are not part of our current capital budget and would require us to invest additional capital. Natural gas and oil prices continue to be volatile and our resources may be insufficient to fund any of these opportunities. As of April 30, 2010, we had approximately $78 million in cash and cash equivalents and no debt outstanding.

The Company views periodic reserve sales as an opportunity to capture value, reduce reserve and price risk, in addition to being a source of funds for potentially higher rate of return natural gas and oil exploration investments. We believe these periodic natural gas and oil property sales are an efficient strategy to meet our cash and liquidity needs by providing us with immediate cash, which would otherwise take years to realize through the production lives of the fields sold. We have in the past and expect in the future to continue to rely heavily on the sales of assets to generate cash to fund our exploration investments and operations.

These sales bring forward future revenues and cash flows, but our longer term liquidity could be impaired to the extent our exploration efforts are not successful in generating new discoveries, production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of these property sales the Company’s ability to collateralize bank borrowings is reduced which may increase our dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.

Natural Gas and Oil Reserves

The following table presents our estimated net proved, developed producing natural gas and oil reserves at March 31, 2010. Reserves were based on a reserve report generated by William M. Cobb & Associates, Inc. and Lonquist & Co. LLC. The Company believes that having independent and well respected third-party engineering firms prepare its reserve report enhances the credibility of our reported reserve estimates. Management is responsible for the reserve estimate disclosures in this filing, and meets regularly with our independent third-party engineers to review these reserve estimates.


		Proved Reserves as of March 31, 2010
Natural Gas (MMcf)		281,403
Oil, Condensate and Natural Gas Liquids (MBbls)		12,584

Total proved reserves (Mmcfe)		356,907

While we are reasonably certain of recovering our calculated reserves, the process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third-party engineers must project production rates 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 most likely will vary from estimates. 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 Program

In September 2008, the Company’s board of directors approved a $100 million share repurchase program. Under the program, all shares are purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases will be made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. Repurchased shares of common stock become authorized but unissued shares, and may be issued in the future for general corporate and other purposes. As of April 30, 2010, we have purchased 1,339,808 shares of our common stock at an average cost per share of $43.40, for a total expenditure of approximately $58.2 million, resulting in 15,777,380 shares of common stock outstanding and 16,417,714 fully diluted shares. As of April 30, 2010, approximately $41.8 million remained available for repurchase under the share repurchase program.

Credit Facility

On October 3, 2008, the Company and its wholly-owned subsidiaries completed the arrangement of a $50 million Hydrocarbon Borrowing Base secured revolving credit facility pursuant to a credit agreement with BBVA Compass Bank (successor in interest to Guaranty Bank, as administrative agent and issuing lender) (the “Credit Agreement”). The credit facility is secured by substantially all of the Company’s assets and is available to fund the Company’s exploration and development activities, as well as the repurchase of shares of the Company’s common stock, the payment of dividends, and working capital as needed. Borrowings under the Credit Agreement bear interest at LIBOR plus 2.0% per annum. The outstanding principal amount and any accrued interest thereon is due October 3, 2010, and may be prepaid at any time in accordance with the Credit Agreement with no prepayment penalty. An arrangement fee of 0.5%, or $250,000, was paid in connection with the facility and a commitment fee of 0.5% is paid on the unused commitment amount. As of March 31, 2010, the Company had no amounts outstanding under the Credit Agreement.

On August 21, 2009, Guaranty Bank was closed by the Office of Thrift Supervision, and the Federal Deposit Insurance Corporation (FDIC) was named Receiver. No advance notice is given to the public when a financial institution is closed. All of our deposit accounts at Guaranty Bank were transferred to BBVA Compass Bank and were available immediately. The terms of our Credit Agreement remain unchanged and have been assumed by BBVA Compass Bank.

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 prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and a substantial or extended decline in natural gas and oil prices would adversely affect our revenues, profitability and growth and could have a material adverse effect on the business, the results of operations and financial condition of the Company.

Our revenues, profitability and future growth depend significantly on natural gas and crude oil prices. Prices received affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and our ability to raise additional capital. We do not expect to hedge our production to protect against price decreases. Lower prices may also affect the amount of natural gas and oil that we can economically produce. Factors that can cause price fluctuations include:

•

The domestic and foreign supply of natural gas and oil.

•

Overall economic conditions.

•

The level of consumer product demand.

•

Adverse weather conditions and natural disasters.

•

The price and availability of competitive fuels such as LNG, heating oil and coal.

•

Political conditions in the Middle East and other natural gas and oil producing regions.

•

The level of LNG imports.

•

Domestic and foreign governmental regulations.

•

Potential price controls and increased taxes.

•

Access to pipelines and gas processing plants.

A substantial or extended decline in natural gas and oil prices could have a material adverse effect on our access to capital and the quantities of natural gas and oil that may be economically produced by us. A significant decrease in price levels for an extended period would negatively affect us.

We depend on the services of our chairman, chief executive officer and chief financial officer, and implementation of our business plan could be seriously harmed if we lost his services.

We depend heavily on the services of Kenneth R. Peak, our chairman, chief executive officer, and chief financial officer. We do not have an employment agreement with Mr. Peak, and the proceeds from a $10.0 million “key person” life insurance policy on Mr. Peak may not be adequate to cover our losses in the event of Mr. Peak’s death.

We are highly dependent on the technical services provided by JEX and could be seriously harmed if JEX terminated its services with us or became otherwise unavailable.

Because we employ no geoscientists or petroleum engineers, we are dependent upon JEX for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. We do not have a written agreement with JEX which contractually obligates them to provide us with their services in the future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss of the services of JEX could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by JEX of certain explorationists could have a material adverse effect on our operations as well.

Our ability to successfully execute our business plan is dependent on our ability to obtain adequate financing.

Our business plan, which includes participation in 3-D seismic shoots, lease acquisitions, the drilling of exploration prospects and producing property acquisitions, has required and is expected to continue to require substantial capital expenditures. We may require additional financing to fund our planned growth. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, additional financing may not be available to us on acceptable terms, if at all. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

It is difficult to quantify the amount of financing we may need to fund our planned growth. The amount of funding we may need in the future depends on various factors such as:

•

Our financial condition.

•

The prevailing market price of natural gas and oil.

•

The type of projects in which we are engaging.

•

The lead time required to bring any discoveries to production.

We frequently obtain capital through the sale of our producing properties.

The Company, since its inception in September 1999, has raised approximately $484.0 million from various property sales. These sales bring forward future revenues and cash flows, but our longer term liquidity could be impaired to the extent our exploration efforts are not successful in generating new discoveries, production, revenues and cash flows. Additionally, our longer term liquidity could be impaired due to the decrease in our inventory of producing properties that could be sold in future periods. Further, as a result of these property sales the Company’s ability to collateralize bank borrowings is reduced which increases our dependence on more expensive mezzanine debt and potential equity sales. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.

We assume additional risk as Operator in drilling high pressure and high temperature wells in the Gulf of Mexico.

COI, a wholly-owned subsidiary of the Company, was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. Drilling activities are subject to numerous risks, including the significant risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. Drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells. The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. In periods of increased drilling activity resulting from high commodity prices, demand exceeds availability for drilling rigs, drilling vessels, supply boats and personnel experienced in the oil and gas industry in general, and the offshore oil and gas industry in particular. This may lead to difficulty and delays in consistently obtaining certain services and equipment from vendors, obtaining drilling rigs and other equipment at favorable rates and scheduling equipment fabrication at factories and fabrication yards. This, in turn, may lead to projects being delayed or experiencing increased costs. The cost of drilling, completing, and operating wells is often uncertain, and new wells may not be productive or we may not recover all or any of our investment. The risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling and completion operations may be higher due to our inexperience as an operator.

Additionally, we use turnkey contracts that may cost more than drilling contracts at daily rates. Under certain conditions, the turnkey contract can be terminated by the turnkey drilling contractor, which could lead to materially higher risks and costs for the Company.

We rely on third-party operators to operate and maintain some of our production pipelines and processing facilities and, as a result, we have limited control over the operations of such facilities. The interests of an operator may differ from our interests.

We depend upon the services of third-party operators to operate production platforms, pipelines, gas processing facilities and the infrastructure required to produce and market our natural gas, condensate and oil. We have limited influence over the conduct of operations by third-party operators. As a result, we have little control over how frequently and how long our production is shut-in when production problems, weather and other production shut-ins occur. Poor performance on the part of, or errors or accidents attributable to, the operator of a project in which we participate may have an adverse effect on our results of operations and financial condition. Also, the interest of an operator may differ from our interests.

Repeated production shut-ins can possibly damage our well bores.

Our well bores are required to be shut-in from time to time due to a variety of issues, including a combination of weather, mechanical problems, sand production, bottom sediment, water and paraffin associated with our condensate production at our Eugene Island 11 platform, as well as downstream third-party facility and pipeline shut-ins. In addition, shut-ins are necessary from time to time to upgrade and improve the production handling capacity at related downstream platform, gas processing and pipeline infrastructure. In addition to negatively impacting our near term revenues and cash flow, repeated production shut-ins may damage our well bores if repeated excessively or not executed properly. The loss of a well bore due to damage could require us to drill additional wells.

Concentrating our capital investment in the Gulf of Mexico increases our exposure to risk.

Our capital investments are focused in offshore Gulf of Mexico prospects. However, our exploration prospects in the Gulf of Mexico may not lead to significant revenues. Furthermore, we may not be able to drill productive wells at profitable finding and development costs.

Natural gas and oil reserves are depleting assets and the failure to replace our reserves would adversely affect our production and cash flows.

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows will be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Further, the majority of our reserves are proved developed producing. Accordingly, we do not have significant opportunities to increase our production from our existing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.

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

There are numerous uncertainties in estimating crude oil and natural gas reserves and their value, including many factors that are beyond our control. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities of reserves shown in this report.

In order to prepare these estimates, our independent third-party petroleum engineers must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

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 this 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 revenue activities are significantly concentrated in one field.

The proved reserves assigned to our Dutch and Mary Rose discoveries have nine producing well bores concentrated in one reservoir and are producing via two pipelines and two production platforms. Reserve assessments based on only nine well bores in one reservoir with relatively limited production history are subject to significantly greater risk of downward revision than multiple well bores from a variety of mature producing reservoirs.

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

We have no in house reservoir engineering capability, and therefore rely on the accuracy of the periodic reservoir reports provided to us by our independent third-party reservoir engineers. If those reports prove to be inaccurate, our financial reports could have material misstatements. Further, we use the reports of our independent reservoir engineers in our financial planning. If the reports of the outside reservoir engineers prove to be inaccurate, we may make misjudgments in our financial planning.

Exploration is a high risk activity, and our participation in drilling activities may not be successful.

Our future success largely depends on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the significant risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

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Unexpected drilling conditions.

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Blowouts, fires or explosions with resultant injury, death or environmental damage.

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Pressure or irregularities in formations.

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Equipment failures or accidents.

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Tropical storms, hurricanes and other adverse weather conditions.

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Compliance with governmental requirements and laws, present and future.

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Shortages or delays in the availability of drilling rigs and the delivery of equipment.

•

Our turnkey drilling contracts reverting to a day rate contract which would significantly increase the cost and risk to the Company.

•

Problems at third-party operated platforms, pipelines and gas processing facilities over which we have no control.

Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would materially and adversely affect our future cash flows and results of operations.

In addition, as a “successful efforts” company, we choose to account for unsuccessful exploration efforts (the drilling of “dry holes”) and seismic costs as a current expense of operations, which immediately impacts our earnings. Significant expensed exploration charges in any period would materially adversely affect our earnings for that period and cause our earnings to be volatile from period to period.

Production activities in the Gulf of Mexico increase our susceptibility to pollution and natural resource damage.

A blowout, rupture or spill of any magnitude would present serious operational and financial challenges. Most of the Company’s operations are on the Gulf of Mexico shelf in water depths less than 200 feet and less than 50 miles from the coast. Such proximity to the shore-line increases the probability of a biological impact or damaging the fragile eco-system in the event of released condensate.

The natural gas and oil business involves many operating risks that can cause substantial losses.

The natural gas and oil business involves a variety of operating risks, including:

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Blowouts, fires and explosions.

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Surface cratering.

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Uncontrollable flows of underground natural gas, oil or formation water.

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Natural disasters.

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Pipe and cement failures.

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Casing collapses.

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Stuck drilling and service tools.

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Reservoir compaction.

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Abnormal pressure formations.

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Environmental hazards such as natural gas leaks, oil spills, pipeline ruptures or discharges of toxic gases.

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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.

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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:

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Injury or loss of life.

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Reservoir damage.

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Severe damage to and destruction of property or equipment.

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Pollution and other environmental damage.

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Clean-up responsibilities.

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Regulatory investigations and penalties.

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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, processing plants, and offshore platforms. Transportation capacity on gathering system pipelines and platforms is occasionally limited and at times unavailable due to repairs or improvements being made to these facilities or due to capacity being utilized by other natural gas or oil shippers that may have priority transportation agreements. If the gathering systems, processing plants, platforms or our transportation capacity is materially restricted or is unavailable in the future, our ability to market our natural gas or oil could be impaired and cash flow from the affected properties could be reduced, which could have a material adverse effect on our financial condition and results of operations. Further, repeated shut-ins of our wells could result in damage to our well bores that would impair our ability to produce from these wells and could result in additional wells being required to produce our reserves.

We may not have title to our leased interests and if any lease is later rendered invalid, we may not be able to proceed with our exploration and development of the lease site.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is to not incur the expense of retaining title lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of JEX and others to perform the field work in examining records in the appropriate governmental, county or parish clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to the drilling of an exploration well the operator of the well will typically obtain a preliminary title review of the drillsite lease and/or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. However, such deficiencies may not have been cured by the operator of such wells. It does happen, from time to time, that the examination made by title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect. It may also happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion.

Competition in the natural gas and oil industry is intense, and we are smaller and have a more limited operating history than many of our competitors.

We compete with a broad range of natural gas and oil companies in our exploration and property acquisition activities. We also compete for the equipment and labor required to operate and to develop these properties. Many of our competitors have substantially greater financial resources than we do. These competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties. Further, they may be able to evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil and to acquire additional properties in the future depends on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, many of our competitors have been operating for a much longer time than we have and have substantially larger staffs. We may not be able to compete effectively with these companies or in such a highly competitive environment.

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 may:

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Require that we obtain permits before commencing drilling.

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Restrict the substances that can be released into the environment in connection with drilling and production activities.

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Limit or prohibit drilling activities on protected areas, such as wetlands or wilderness areas.

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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 factual 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.

We cannot 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:

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Timing and amount of capital expenditures.

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The operator’s expertise and financial resources.

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Approval of other participants in drilling wells.

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Selection of technology.

We are highly dependent on our management team, JEX, exploration partners and third-party consultants and any failure to retain the services of such parties could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies.

The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy is highly dependent on our management team, as well as certain key geoscientists, geologists, engineers and other professionals engaged by us. We are highly dependent on the services provided by JEX and we do not have any written agreements contractually obligating them to provide us with their services in the future. The loss of key members of our management team, JEX or other highly qualified technical professionals could adversely affect our ability to effectively manage our overall operations or successfully execute current or future business strategies which may have a material adverse effect on our business, financial condition and operating results.

Acquisition prospects are difficult to assess and may pose additional risks to our operations.

We expect to evaluate and, where appropriate, pursue acquisition opportunities on terms our management considers favorable. The successful acquisition of natural gas and oil properties requires an assessment of:

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Recoverable reserves.

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Exploration potential.

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Future natural gas and oil prices.

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Operating costs.

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Potential environmental and other liabilities and other factors.

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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.

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Unanticipated costs.

•

Diversion of resources and management attention from our exploration business.

•

Entry into regions or markets in which we have limited or no prior experience.

•

Potential loss of key employees of the acquired organization.

The risks and challenges inherent in mineral exploration are quite different from our natural gas and oil exploration and we have no mineral expertise.

Our investment in the Mineral Exploration Lands does not represent a change in our natural gas and oil exploration business model. We recognize that the risks and challenges inherent in mineral exploration are quite different from our natural gas and oil exploration business and we were attracted to invest in this project solely by what we perceive to be its reward/risk ratio, where a relatively small amount of initial exploration risk capital ($3 to $5 million is envisioned) could potentially lead to a more extensive mineral exploration/development project. Our 2009 exploration program found relatively few samples of commercial grade gold ore – generally considered to be 0.5 grams per tonne or more – but we believe our results merit an expanded exploration program for the summer of 2010.

At this early exploration stage our investment should be considered speculative and our odds of ultimately being successful in finding gold or other minerals in a volume sufficient to support a commercial mining operation are quite low. We have little or no experience in mining and mineral development and will be highly dependent upon the advice of consultants.

Anti-takeover provisions of our certificate of incorporation, bylaws and Delaware law could adversely effect a potential acquisition by third-parties that may ultimately be in the financial interests of our stockholders.

Our certificate of incorporation, bylaws and the Delaware General Corporation Law contain provisions that may discourage unsolicited takeover proposals. These provisions could have the effect of inhibiting fluctuations in the market price of our common stock that could result from actual or rumored takeover attempts, preventing changes in our management or limiting the price that investors may be willing to pay for shares of common stock.

Pursuant to these provisions, the Company adopted a Stockholders Rights Plan in September 2008 that is designed to ensure that all stockholders of the Company receive fair value for their shares of common stock in a proposed takeover of the Company and to guard against coercive takeover tactics to gain control of the Company. In addition, these provisions, among other things, authorize the board of directors to:

•

Designate the terms of and issue new series of preferred stock.

•

Limit the personal liability of directors.

•

Limit the persons who may call special meetings of stockholders.

•

Prohibit stockholder action by written consent.

•

Establish advance notice requirements for nominations for election of the board of directors and for proposing matters to be acted on by stockholders at stockholder meetings.

•

Require us to indemnify directors and officers to the fullest extent permitted by applicable law.

•

Impose restrictions on business combinations with some interested parties.

Our common stock is thinly traded.

Contango has approximately 15.8 million shares of common stock outstanding. Directors and officers own or have voting control over approximately 3.2 million shares. Since our common stock is not heavily traded, the purchase or sale of relatively small common stock positions may result in disproportionately large increases or decreases in the price of our common stock.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate and Credit Rating Risk. As of April 30, 2010, we had no long-term debt subject to the risk of loss associated with movements in interest rates.

As of March 31, 2010, we had approximately $100.4 million in cash and cash equivalents. Of this amount, approximately $65.7 million was invested in U.S. Treasury money market funds and the remaining $34.7 million was invested in overnight U.S. Treasury funds. 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, 2010, 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 nine months ended March 31, 2010, a 10% fluctuation in the prices received for natural gas and oil production would impact our revenues by approximately $12 million. It could also lead to impairment of our natural gas and oil properties.

Item 4.

Controls and Procedures

Kenneth R. Peak, our Chairman, Chief Executive Officer and Chief Financial Officer, together with our Controller and Treasurer, 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, 2010. Based upon that evaluation, the Company’s management concluded that, as of March 31, 2010, 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 Chairman, Chief Executive Officer, Chief Financial Officer, Controller and Treasurer, 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, 2010 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 are incorporated into this Item 1A by reference and supersede 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 5.

Other Information

On September 30, 2008, the Company adopted a Stockholder Rights Plan (the “Plan”) that is designed to ensure that all stockholders of Contango receive fair value for their shares of common stock in the event of any proposed takeover of Contango and to guard against the use of partial tender offers or other coercive tactics to gain control of Contango without offering fair value to all of Contango’s stockholders. The Plan is not intended, nor will it operate, to prevent an acquisition of Contango on terms that are favorable and fair to all stockholders.

Under the terms of the Plan, each right (a “Right”) will entitle the holder to buy 1/100 of a share of Series F Junior Preferred Stock of Contango (the “Preferred Stock”) at an exercise price of $200 per share. The Rights will be exercisable and will trade separately from the shares of common stock only if a person or group acquires beneficial ownership of 20% or more of Contango’s common stock or commences a tender or exchange offer that would result in such a person or group owning 20% or more of the common stock (the “Triggering Event”).

Under the terms of the Plan, Rights have been distributed as a dividend at the rate of one Right for each share of common stock held as of the close of business on October 1, 2008. Stockholders will not actually receive certificates for the Rights at this time, but the Rights will become part of each outstanding share of common stock. An additional Right will be issued along with each share of common stock that is issued or sold by Contango after October 1, 2008. The Rights may only be exercised during a three-year period and are scheduled to expire on September 30, 2011. Upon a Triggering Event, Contango stockholders will receive certificates for the Rights.

If any person actually acquires 20% or more of shares of common stock — other than through a tender or exchange offer for all shares of common stock that provides a fair price and other acceptable terms for such shares, as determined by the board of directors of Contango — or if a 20%-or-more stockholder engages in certain “self-dealing” transactions or engages in a merger or other business combination in which Contango survives and its shares of common stock remain outstanding, the other Contango stockholders will be able to exercise the Rights and

buy shares of common stock of Contango having approximately twice the value of the exercise price of the Rights. Additionally, if Contango is involved in certain other mergers where its shares are exchanged or certain major sales of its assets occur, Contango stockholders will be able to purchase a certain number of the other party’s common stock in an amount equal to approximately twice the value of the exercise price of the Rights.

Contango will be entitled to redeem the Rights at $0.01 per Right at any time until the earlier of (i) the tenth day following public announcement that a person has acquired a 20% ownership position in shares of common stock of Contango or (ii) the final expiration date of the Rights. Contango in its discretion may extend the period during which it may redeem the Rights.

Item 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

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)

23.1		Consent of William M. Cobb & Associates, Inc. †

23.2		Consent of Lonquist & Co. LLC. †

31.1		Certification required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. †

32.1		Certification pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. †

†	Filed herewith.

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.

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 7, 2010	By:	/S/ KENNETH R. PEAK
		Kenneth R. Peak
		Chairman, Chief Executive Officer and Chief Financial Officer
		(Principal Executive and Financial Officer)