Edgar Filing: CONTANGO OIL & GAS CO

Form 10Q Amendment No. 1

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(AMENDMENT NO. 1)

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

For the quarterly period ended March 31, 2007

¨	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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one).

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨

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 May 4, 2007 was 15,952,807.

EXPLANATORY NOTE

Contango Oil & Gas Company (the “Company”, “Contango”, “we”, “our”, “us”) is hereby amending its previously filed Quarterly Report on Form 10-Q for the quarter ended March 31, 2007 (the “Original Filing”). This Amendment No. 1 (the “Amendment”) is being filed solely to amend the following items:

•

“Footnote No. 1 to the Consolidated Financial Statements—Summary of Significant Accounting Policies, Principles of Consolidation,” has been revised to more clearly explain the consolidation policy of our non-wholly owned subsidiaries; and

•

“Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” revised to replace the discussion in the Original Filing that was based on activity of continuing and discontinued operations combined, which was presented without differentiation and was inconsistent with the financial statement presentation. The revised discussion focuses on continuing operations apart from discontinued operations in accordance with generally accepted accounting principles (“GAAP”) and the provisions of Item 303(a) of Regulation S-K. Since we did not have any newly discontinued operations for the nine months ended March 31, 2007, the revisions restate the analysis comparing our more recent activity to that of the corresponding periods of the prior year. Additionally, we are providing expanded disclosures of Management’s Discussion and Analysis covering the first and second quarters of the fiscal year ended June 30, 2007 for the same reason, rather than amending the earlier interim reports for such periods.

Other than as specified above, this Amendment does not modify or affect the financial statements in the Original Filing. As a result of this Amendment, the certifications filed as Exhibit 31.1 and Exhibit 32.1 have been re-executed as of the date of this Amendment. This Amendment does not reflect events occurring after the filing of the Original Filing or modify or update the disclosures therein in any way other than as described above. In accordance with Rule 12b-15 promulgated under the Securities Exchange Act of 1934, the complete text of each affected item, as amended, is included herein. Unaffected items have not been repeated in this Amendment.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS


	March 31, 2007			June 30, 2006
	(Unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	2,565,459		$	10,274,950
Short-term investments		—			18,472,327
Inventory tubulars		334,797			194,825
Accounts Receivable:
Trade receivables		5,046,779			481,593
Advances to affiliates		3,884,118			256,180
Joint interest billings receivable		2,252,320			3,422,261
Prepaid capital costs		4,965,752			1,208,299
Other		491,987			202,583

Total current assets		19,541,212			34,513,018


PROPERTY AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		53,955,718			18,395,015
Unproved properties		30,397,628			23,293,300
Furniture and equipment		231,877			231,877
Accumulated depreciation, depletion and amortization		(2,022,630	)		(662,877	)

Total property and equipment, net		82,562,593			41,257,315


OTHER ASSETS:
Cash and other assets held by affiliates		2,516,241			1,054,100
Investment in Freeport LNG Project		3,243,585			3,243,585
Investment in Contango Venture Capital Corporation		6,769,246			4,453,028
Deferred income tax asset		5,625,902			4,455,190
Facility fees and other assets		593,317			408,769

Total other assets		18,748,291			13,614,672

TOTAL ASSETS	$	120,852,096		$	89,385,005

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, 2007			June 30, 2006
	(Unaudited)
CURRENT LIABILITIES:
Accounts payable	$	4,376,365		$	1,041,505
Joint interest advances		602,457			5,638,600
Accrued exploration and development		9,878,601			8,278,245
Advances from affiliates		2,357,271			194,862
Debt of affiliates		8,540,091			—
Other accrued liabilities		1,750,182			1,026,743

Total current liabilities		27,504,967			16,179,955

LONG-TERM DEBT		30,000,000			10,000,000

ASSET RETIREMENT OBLIGATION		862,344			665,458

SHAREHOLDERS’ EQUITY:
Convertible preferred stock, 6%, Series D, $0.04 par value, 4,000 shares authorized, 2,000 shares issued and outstanding at June 30, 2006, liquidation preference of $10,000,000 at $5,000 per share		—			80
Common stock, $0.04 par value, 50,000,000 shares authorized, 18,527,807 shares issued and 15,952,807 outstanding at March 31, 2007, 17,574,085 shares issued and 14,999,085 outstanding at June 30, 2006,		741,111			702,961
Additional paid-in capital		46,615,497			45,105,504
Accumulated other comprehensive income		1,105,857			—
Treasury stock at cost (2,575,000 shares)		(6,180,000	)		(6,180,000	)
Retained earnings		20,202,320			22,911,047

Total shareholders’ equity		62,484,785			62,539,592

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	120,852,096		$	89,385,005

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,
	2007			2006			2007			2006
REVENUES:
Natural gas and oil sales	$	5,416,020		$	123,199		$	7,458,733		$	315,274

Total revenues		5,416,020			123,199			7,458,733			315,274

EXPENSES:
Operating expenses (credits)		280,302			5,512			557,953			(11,216	)
Exploration expenses		253,741			152,011			1,151,211			978,682
Depreciation, depletion and amortization		1,050,200			11,909			1,554,583			99,032
Impairment of natural gas and oil properties		—			419,918			192,109			419,918
General and administrative expenses		2,371,076			1,061,518			4,900,017			3,083,492

Total expenses		3,955,319			1,650,868			8,355,873			4,569,908

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE
OTHER INCOME (EXPENSES) AND INCOME TAXES		1,460,701			(1,527,669	)		(897,140	)		(4,254,634	)

OTHER INCOME (EXPENSE):
Interest expense (net of interest capitalized)		(739,510	)		(93	)		(1,297,415	)		(285	)
Interest income		231,253			165,946			638,395			565,314
Gain (loss) on sale of assets and other		(677,580	)		(18,519	)		(1,994,265	)		223,167

INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES		274,864			(1,380,335	)		(3,550,425	)		(3,466,438	)
Benefit (provision) for income taxes		(96,152	)		524,792			1,156,420			1,326,191

INCOME (LOSS) FROM CONTINUING OPERATIONS		178,712			(855,543	)		(2,394,005	)		(2,140,247	)
DISCONTINUED OPERATIONS (Note 5)
Discontinued operations, net of income taxes		—			1,754,965			—			3,032,583

NET INCOME (LOSS)		178,712			899,422			(2,394,005	)		892,336
Preferred stock dividends		22,222			150,000			314,722			451,000

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	156,490		$	749,422		$	(2,708,727	)	$	441,336

NET INCOME (LOSS) PER SHARE:
Basic
Continuing operations	$	0.01		$	(0.07	)	$	(0.18	)	$	(0.18	)
Discontinued operations		—			0.12			—			0.21

Total	$	0.01		$	0.05		$	(0.18	)	$	0.03

Diluted
Continuing operations	$	0.01		$	(0.07	)	$	(0.18	)	$	(0.18	)
Discontinued operations		—			0.12			—			0.21

Total	$	0.01		$	0.05		$	(0.18	)	$	0.03

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		15,759,324			14,865,965			15,262,085			14,675,586

Diluted		16,068,154			14,865,965			15,262,085			14,675,586

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,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Loss from continuing operations	$	(2,394,005	)	$	(2,140,247	)
Plus income from discontinued operations, net of income taxes		—			3,032,583

Net loss		(2,394,005	)		892,336
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		1,554,583			1,065,766
Impairment of natural gas and oil properties		192,109			419,918
Exploration expenditures		665,783			1,759,438
Deferred income taxes		(1,766,174	)		538,905
Tax benefit from exercise of stock option		(157,760	)		(414,854	)
Stock-based compensation		1,158,069			599,695
Loss (gain) on sale of assets and other		2,009,165			(1,081,271	)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable and other		(4,565,186	)		240,789
Increase in notes receivable		(783,824	)		—
Increase in prepaid insurance		(290,275	)		(59,594	)
Increase in interest receivable		(114,282	)		—
Increase in inventory		(139,972	)		—
Increase (decrease) in accounts payable and advances from joint owners		(1,701,283	)		537,528
Increase in other accrued liabilities		344,088			294,698
Increase (decrease) in income taxes payable		157,760			(1,177,985	)
Other		(14,900	)		(38,474	)

Net cash provided by (used in) operating activities		(5,846,104	)		3,576,895

CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures		(40,030,977	)		(21,783,141	)
Decrease (increase) in net investment in affiliates		(14,960,566	)		26,634
Investment in Freeport LNG Project		—			(236,834	)
Sale of short-term investments, net		18,472,327			15,587,387
Additions to furniture and equipment		(23,025	)		(18,370	)
Sale of assets		7,000,000			1,744,215
Decrease in advances to operators		—			1,802,906
Investment in Contango Venture Capital Corporation		(600,000	)		(708,021	)
Acquisition of overriding royalty interests		—			(1,000,000	)
Acquisition of Republic Exploration LLC and Contango Offshore Exploration interests		—			(7,500,000	)

Net cash used in investing activities		(30,142,241	)		(12,085,224	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		20,000,000			—
Borrowings by affiliates		8,540,091			—
Proceeds from preferred equity issuances, net of issuance costs		—			9,616,438
Preferred stock dividends		(314,722	)		(451,000	)
Repurchase/cancellation of stock options		(202,521	)		—
Tax benefit from exercise/cancellation of stock option		157,760			414,854
Proceeds from exercised options, warrants and others		434,755			1,535,880
Debt issuance costs		(336,509	)		—

Net cash provided by financing activities		28,278,854			11,116,172

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(7,709,491	)		2,607,843
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		10,274,950			3,985,775

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2,565,459		$	6,593,618

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	451,993		$	945,816

Cash paid for interest	$	1,657,488		$	285

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(Unaudited)


	For the Nine Months Ended March 31, 2007
	Preferred Stock					Common Stock			Paid-in Capital			Accumulated Other Comprehensive Income		Treasury Stock			Retained Earnings			Total Shareholders’ Equity			Comprehensive Income
	Shares		Amount			Shares	Amount		Paid-in Capital			Accumulated Other Comprehensive Income		Treasury Stock			Retained Earnings			Total Shareholders’ Equity			Comprehensive Income
Balance at June 30, 2006	2,000		$	80		14,999,085	$	702,961	$	45,105,504		$	—	$	(6,180,000	)	$	22,911,047		$	62,539,592
Issuance of common stock	—			—		16,750		670		81,268			—		—			—			81,938
Expense of stock options	—			—		—		—		147,222			—		—			—			147,222
Repurchase/cancellation of stock options, net of tax benefit	—			—		—		—		(152,508	)		—		—			—			(152,508	)
Net loss	—			—		—		—		—			—		—			(255,856	)		(255,856	)
Preferred stock dividends	—			—		—		—		—			—		—			(150,000	)		(150,000	)
Comprehensive income	—			—		—		—		—			—		—			—			—		$	—


Balance at September 30, 2006	2,000			80		15,015,835		703,631		45,181,486			—		(6,180,000	)		22,505,191			62,210,388

Conversion of Series D preferred shares	(100	)		(4	)	41,666		1,667		(1,663	)		—		—			—			—
Exercise of stock options	—			—		4,000		160		50,170			—		—			—			50,330
Tax benefit from exercise of stock options	—			—		—		—		2,825			—		—			—			2,825
Issuance of common stock	—			—		8,416		337		71,704			—		—			—			72,041
Cashless exercise of stock options	—			—		726		29		(29	)		—		—			—			—
Expense of stock options	—			—		—		—		147,222			—		—			—			147,222
Net loss	—			—		—		—		—			—		—			(2,316,861	)		(2,316,861	)
Preferred stock dividends	—			—		—		—		—			—		—			(142,500	)		(142,500	)
Comprehensive income	—			—		—		—		—			—		—			—			—		$	—


Balance at December 31, 2006	1,900			76		15,070,643		705,824		45,451,715			—		(6,180,000	)		20,045,830			60,023,445

Conversion of Series D preferred shares	(1,900	)		(76	)	791,664		31,667		(31,591	)		—		—			—			—
Exercise of stock options	—			—		90,500		3,620		380,805			—		—			—			384,425
Tax benefit from exercise of stock options	—			—		—		—		121,041			—		—			—			121,041
Cancellation of options and warrants	—			—		—		—		(16,119	)		—		—			—			(16,119	)
Expense of stock options	—			—		—		—		709,646			—		—			—			709,646
Net income	—			—		—		—		—			—		—			178,712			178,712			178,712
Preferred stock dividends	—			—		—		—		—			—		—			(22,222	)		(22,222	)
Unrealized gain on available-for-sale securities	—			—		—		—		—			1,105,857		—			—			1,105,857			1,105,857
Comprehensive income	—			—		—		—		—			—		—			—			—		$	1,284,569


Balance at March 31, 2007	—		$	—		15,952,807	$	741,111	$	46,615,497		$	1,105,857	$	(6,180,000	)	$	20,202,320		$	62,484,785

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America for interim financial information, pursuant to the rules and regulations of the Securities and Exchange Commission, 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 accounting principles generally accepted in the United States of America 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. Certain prior year amounts have been reclassified to conform to the current year presentation. The financial statements should be read in conjunction with the audited financial statements and notes included in the Company’s Form 10-K for the fiscal year ended June 30, 2006. The results of operations for the three and nine months ended March 31, 2007 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2007.

1. Summary of Significant Accounting Policies

The application of generally accepted accounting principles involves certain assumptions, judgments, choices and estimates that affect reported amounts of assets, liabilities, revenues and expenses. Thus, the application of these principles can result in varying results from company to company. 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 cost center by cost center 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. Approximately $0.2 million of impairment was reported for the nine months ended March 31, 2007 which was attributable to a write-down of costs relating to the Alta-Ellis #1 well in December 2006.

In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company classified its $11.6 million property sale effective April 1, 2006, and its $2.0 million property sale effective February 1, 2006, as discontinued operations. An integral and on-going part of our business strategy is to sell our proved reserves from time to time in order to generate additional capital to reinvest in our onshore and offshore exploration programs. Thus, it is our intent to remain an independent natural gas and oil company engaged in the exploration, production, and acquisition of natural gas and oil.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, 2007, the Company had $2,565,459 in cash and cash equivalents, of which $665,483 was invested in highly liquid AAA-rated tax-exempt money market funds.

Short Term Investments. As of March 31, 2007, the Company had no money invested in a portfolio of periodic auction reset (“PAR”) securities, which typically have coupons that periodically reset to market interest rates at intervals ranging from 7 to 35 days. These PAR securities are ordinarily classified as short term investments and consist of AAA-rated tax-exempt municipal bonds. PAR securities are highly liquid and have minimal interest rate risk.

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. Exploration and development subsidiaries not wholly owned, such as 42.7% owned Republic Exploration LLC (“REX”), 50% owned Magnolia Offshore Exploration LLC (“MOE”), and 76.0% owned Contango Offshore Exploration LLC (“COE”) are not controlled by the Company and are proportionately consolidated.

Upon the formation of REX and MOE, Contango was the only owner that contributed cash, and under the terms of the respective limited liability company agreements, was entitled to all of the ventures’ assets and liabilities until the ventures expended all of the Company’s initial cash contribution. The Company therefore consolidated 100% of the ventures’ net assets and results of operations. During the quarter ended December 31, 2002, both REX and MOE completed exploration activities to fully expend the Company’s initial cash contribution, thereby enabling each owner to share in the net assets of the venture based on their stated ownership percentages. Commencing with the quarter ended December 31, 2002, the Company began consolidating 33.3% and 50.0% of the net assets and results of operations of REX and MOE, respectively. The reduction of our ownership in the net assets of REX and MOE resulted in a non-cash exploration expense of approximately $4.2 million and $0.2 million, respectively. The other owners of REX contributed seismic data and related geological and geophysical services, while the other owner of MOE contributed geological and geophysical services in exchange for its ownership interest.

Upon the formation of COE, Contango was the only owner that contributed cash, but by agreement, the owners in COE immediately shared in the net assets of COE, including the Company’s initial cash contribution, based on their stated ownership percentages. The Company therefore consolidated 66.6% of the venture’s net assets and results of operations. The other owner of COE contributed geological and geophysical services in exchange for its ownership interest.

On September 2, 2005, the Company purchased an additional 9.4% ownership interest in each of REX and COE. Both interests were purchased from an existing owner, which prior to the sale, owned 33.3% of each of the two subsidiaries. As a result of these two purchases, the Company’s equity ownership interest in REX has increased from 33.3% to 42.7% and in COE from 66.6% to 76.0%. On September 2, 2005, an independent third party also purchased a 9.4% interest in each of REX and COE and the selling owner’s ownership interest thus decreased from 33.3% to 14.6% in each such entity.

Contango’s 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG”) is accounted for at cost. As a 10% limited partner, the Company has no ability to direct or control the operations or management of the general partner.

Contango’s 32% ownership in Contango Capital Partnership Management, LLC (“CCPM”), Contango’s 25% limited partnership interest in Contango Capital Partners, L.P. (“CCPLP”) and Contango’s 33% ownership of Moblize Inc. (“Moblize”) are accounted for using the equity method. Under the equity method, only Contango’s investment in and amounts due to and from the equity investee are included in the consolidated balance sheet.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

CCPLP formed the Contango Capital Partners Fund, LP (the “Fund”) in January 2005. The Fund owns equity interests in a portfolio of alternative energy companies. The Fund marks these equity interests to market according to fair market values on a quarterly basis.

Contango’s investments in Gridpoint, Inc. (“Gridpoint”) is accounted for using the cost method. Under the cost method, Contango records an investment in the stock of an investee at cost, and recognizes dividends received as income. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment.

Contango’s investment in Trulite, Inc. (“Trulite”) is accounted for in accordance with SFAS No. 115 (“SFAS 115”) “Accounting for Certain Investments in Debt and Equity Securities”. SFAS 115 applies to preferred stock and common stock, if ownership is less than 20%, or if ownership exceeds 20% but effective control (significant influence) is lacking. It is not applicable to investments under the equity method. Due to the nature and objective of our investment in Trulite, these securities are classified as available-for-sale securities under SFAS 115. Any unrealized gains or losses while marking these securities to market are reflected as a component of other comprehensive income at March 31, 2007.

Recent Accounting Pronouncements. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115.” This pronouncement permits entities to use the fair value method to measure certain financial assets and liabilities by electing an irrevocable option to use the fair value method at specified election dates. After election of the option, subsequent changes in fair value would result in the recognition of unrealized gains or losses as period costs during the period the change occurred. SFAS No. 159 becomes effective as of the beginning of the first fiscal year that begins after November 15, 2007, with early adoption permitted. However, entities may not retroactively apply the provisions of SFAS No. 159 to fiscal years preceding the date of adoption. We are currently evaluating the impact that SFAS No. 159 may have on our financial position, results of operations or cash flows.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value under Generally Accepted Accounting Principles and requires enhanced disclosures about fair value measurements. It does not require any new fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We do not expect SFAS No. 157 to have a material impact on the Company.

In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are currently evaluating the provisions of FIN 48 and assessing the impact, if any, it may have on our financial position and results of operations.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Stock-Based Compensation. Effective July 1, 2001, the Company adopted the fair value based method prescribed in SFAS No. 123, “Accounting for Stock Based Compensation”. Under the fair value based method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the award vesting period. The fair value of each award is estimated as of the date of grant using the Black-Scholes options-pricing model. Effective July 1, 2005, the Company adopted SFAS No. 123 (revised 2004) (“SFAS 123(R)”), “Share-Based Payment”. Prior to the adoption of SFAS 123(R), the Company presented all benefits from the exercise of share-based compensation as operating cash flows in the statement of cash flows. SFAS 123(R) requires the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) to be classified as financing cash flows. The fair value of each option is estimated as of the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants during the quarters ended March 31, 2007 and 2006, respectively: (i) risk-free interest rates of 5.0 and 4.5 percent; (ii) expected lives of five years; (iii) expected volatility of 56 percent and 40 percent and (iv) expected dividend yield of zero percent.

Under the Company’s 1999 Stock Incentive Plan, as amended (the “1999 Plan”), the Company’s Board of Directors may also grant restricted stock awards to officers or other employees of the Company. Restricted stock awards made under the 1999 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board. Restricted stock awards generally vest over a period of three years. Grants of service based restricted stock awards are valued at our common stock price at the date of grant. During the nine months ended March 31, 2007, the Company granted 16,750 shares of restricted stock to its employees, and 8,416 shares of restricted stock to its Board of Directors as part of its annual compensation. The shares of restricted stock granted to the Board of Directors vest over a period of one year.

On February 7, 2007, the Company granted 200,000 options to the Chairman and CEO at a fair value of $11.25 per option, to be expensed over the vesting period. During the nine months ended March 31, 2007 and 2006, the Company recorded stock-based compensation charges of $1,158,069 and $599,695 to general and administrative expense, respectively.

2. Natural Gas and Oil Exploration Risk

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

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

3. Credit Risk

The majority of the Company’s revenues for the three and nine months ended March 31, 2007 resulted from oil and gas sales to a single customer, Cokinos Energy Corporation. The receivables associated with these revenues are secured with letters of credit. We believe the loss of this purchaser would not have a material effect on our financial position or results of operation since there are numerous potential purchasers of our production.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

4. Sale of Properties – Continuing Operations

In December 2006, Contango Operators, Inc. (“COI”), a wholly-owned subsidiary of the Company, completed the sale of its 25% working interest in the Grand Isle 72 well (“Liberty”) to an independent oil and gas company for $7.0 million. The sold property had reserves of approximately 1.9 billion cubic feet equivalent (“Bcfe”), net to COI. The Company recognized a loss of approximately $2.0 million for the nine months ended March 31, 2007 as a result of this sale. The Company continues to have an interest in Grand Isle 72 via its investment in COE.

5. Sale of Properties – Discontinued Operations

On March 24, 2006, the Company’s Board of Directors approved the sale of all of the Company’s onshore producing assets in Texas and Alabama for an aggregate purchase price of $11.6 million. These properties were held by Contango STEP, L.P. (“STEP”), an indirect wholly-owned subsidiary of the Company. The sale was completed in June 2006 pursuant to a purchase and sale agreement. The sold properties had net reserves of approximately 203 thousand barrels of oil and 849 million cubic feet (“MMcf”) of gas, or 2.1 Bcfe. The Company recognized a pre-tax gain of $6.2 million for the year ended June 30, 2006. This sale has been classified as discontinued operations in our financial statements for all periods presented.

In March 2006, the Company completed the sale of its interest in a producing well in Zapata County, Texas to an independent oil and gas company for approximately $2.0 million. Approximately 227 MMcf of proven reserves were sold. Pre-tax proceeds after netting adjustments were $2.0 million. The Company recognized a pre-tax gain on sale of $1.0 million for the year ended June 30, 2006. This sale has been classified as discontinued operations in our financial statements for all periods presented.

The Company did not have any discontinued operations for the three or nine months ended March 31, 2007. The summarized financial results for discontinued operations for the periods ended March 31, 2006 are as follows:

Operating Results :


	Three Months Ended March 31,					Nine Months Ended March 31,
	2007		2006			2007		2006
Revenues	$	—	$	1,555,134		$	—	$	4,377,017
Operating credits		—		466,362	*		—		1,266,320
Exploration expenses		—		—			—		(1,093,139	)
Depreciation, depletion and amortization		—		(380,000	)		—		(966,734	)
Gain on sale of discontinued operations		—		1,058,450			—		1,082,048

Gain before income taxes	$	—	$	2,699,946		$	—	$	4,665,512
Provision for income taxes		—		(944,981	)		—		(1,632,929	)

Gain from discontinued operations, net of income taxes	$	—	$	1,754,965		$	—	$	3,032,583

*	Credits due to severance tax refunds

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the three and nine months ended March 31, 2006, operating expenses from discontinued operations resulted in a net credit of $466,362 and $1,266,320, respectively. The net credits were attributable to credits issued for previously paid severance taxes. The Railroad Commission of Texas allows for a severance tax reduction on tight sand gas wells. As a result, some of our properties sold in fiscal year 2005 were eligible for severance tax reduction. By contractual agreement, revenues and expenses prior to July 1, 2004, the effective date of the sale, accrue to us.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. Net Income (Loss) Per Common Share

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


	Three Months Ended March 31, 2007								Three Months Ended March 31, 2006
	Income			Weighted Average Shares		Per Share			Income (Loss)			Weighted Average Shares		Per Share
Income (loss) from continuing operations including preferred dividends	$	156,490		15,759,324		$	0.01		$	(1,005,543	)	14,865,965		$	(0.07	)
Discontinued operations, net of income taxes	$	—		—		$	—		$	1,754,965		14,865,965		$	0.12


Basic Earnings per Share:
Net income (loss) attributable to common stock	$	156,490		15,759,324		$	0.01		$	749,422		14,865,965		$	0.05

Effect of Potential Dilutive Securities:
Stock options		—		308,830						—		(a	)
Series D preferred stock		(a	)	(a	)					(a	)	(a	)

Income (loss) from continuing operations including preferred dividends	$	156,490		16,068,154		$	0.01		$	(1,005,543	)	14,865,965		$	(0.07	)
Discontinued operations, net of income taxes	$	—		—		$	—		$	1,754,965		14,865,965		$	0.12


Diluted Earnings per Share:
Net income attributable to common stock	$	156,490		16,068,154		$	0.01		$	749,422		14,865,965		$	0.05

Anti-dilutive Securities:
Shares assumed not issued from options to purchase common shares as income from continuing operations was in a loss position for the period	$	—				$	—		$	—		952,000		$	7.87
Series D preferred stock	$	22,222		140,740		$	0.16		$	150,000		833,333		$	0.18
(a) Anti-dilutive.

	Nine Months Ended March 31, 2007								Nine Months Ended March 31, 2006
	Loss			Weighted Average Shares		Per Share			Income (Loss)			Weighted Average Shares		Per Share
Loss from continuing operations including preferred dividends	$	(2,708,727	)	15,262,085		$	(0.18	)	$	(2,591,247	)	14,675,586		$	(0.18	)
Discontinued operations, net of income taxes		—		—		$	—			3,032,583		14,675,586			0.21

Basic Earnings per Share:
Net income (loss) attributable to common stock	$	(2,708,727	)	15,262,085		$	(0.18	)	$	441,336		14,675,586		$	0.03

Effect of Potential Dilutive Securities:
Stock options		—		(a	)					—		(a	)
Series D preferred stock		(a	)	(a	)					(a	)	(a	)

Loss from continuing operations including preferred dividends	$	(2,708,727	)	15,262,085		$	(0.18	)	$	(2,591,247	)	14,675,586		$	(0.18	)
Discontinued operations, net of income taxes		—		—			—			3,032,583		14,675,586			0.21


Diluted Earnings per Share:
Net loss attributable to common stock	$	(2,708,727	)	15,262,085		$	(0.18	)	$	441,336		14,675,586		$	0.03

Anti-dilutive Securities:
Shares assumed not issued from options to purchase common shares as income from continuing operations was in a loss position for the period	$	—				$	—		$	—		952,000		$	7.87
Series C preferred stock (converted during the period)	$	—		—		$	—		$	21,000		1,166,667		$	0.02
Series D preferred stock	$	314,722		833,330		$	0.38		$	430,000		791,667		$	0.54

(a)	Anti-dilutive.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

7. Acquisition of Interest in Partially-Owned Subsidiaries and Overriding Royalties

On September 2, 2005, we purchased an additional 9.4% ownership interest in each of our two partially-owned offshore Gulf of Mexico exploration subsidiaries, REX for $5.6 million and COE for $1.9 million, for a total expenditure of $7.5 million. Both interests were purchased from Juneau Exploration, L.P. (“JEX”), which prior to the sale, owned 33.3% of each of the two subsidiaries. As a result of these two purchases, the Company’s equity ownership interest in REX has increased from 33.3% to 42.7% and in COE from 66.6% to 76.0%. The purchases were financed from the Company’s existing cash on hand. An independent third party also purchased a 9.4% interest in each of REX and COE from JEX for the same total purchase price of $7.5 million. JEX will continue in its capacity as the managing member of both REX and COE and following these two sales, now owns a 14.6% interest in each of REX and COE.

The purchase price paid in excess of the subsidiaries net assets acquired (“purchase price allocation”) was allocated to the various assets owned by the subsidiaries during the quarter ended September 30, 2005. These assets include planned drilling commitments, unevaluated exploration blocks, and proven developed producing properties. A significant portion of the purchase price allocation was allocated to our Eugene Island 10 (“Dutch”) and Grand Isle 63/72/73 (“Liberty”) exploration prospects.

On November 7, 2005, the Company, in a separate transaction, also acquired certain overriding royalty interests in REX, COE and MOE offshore prospects for the purchase price of $1.0 million.

8. Series D Perpetual Cumulative Convertible Preferred Stock

On July 15, 2005, we sold $10.0 million of our Series D preferred stock to a group of private investors. The Series D preferred stock is perpetual and cumulative, is senior to our common stock and is convertible at any time into shares of our common stock at a price of $12.00 per share. The dividend on the Series D preferred stock can be paid quarterly in cash at a rate of 6.0% per annum or paid-in-kind at a rate of 7.5% per annum. Our registration statement filed with the Securities and Exchange Commission, covering the 833,330 shares of common stock issuable upon conversion of the Series D preferred stock, became effective on October 26, 2005. Net proceeds associated with the private placement of the Series D preferred stock was $9,616,438, net of stock issuance costs.

In November 2006, two Series D preferred stockholders voluntarily elected to convert a total of 100 shares of Series D preferred stock to 41,666 shares of common stock, par value $0.04 per share. The converted shares of Series D preferred stock had a face value of $0.5 million.

On January 15, 2007, we exercised our mandatory conversion rights pursuant to the terms of our Series D preferred stock, and converted all of the remaining 1,900 shares of our Series D preferred stock issued and outstanding into 791,664 shares of our common stock. The outstanding shares of the Series D preferred stock had a face value of $9.5 million.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

9. Contango Venture Capital Corporation

As of March 31, 2007, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, held a direct investment in three alternative energy portfolio companies – Gridpoint, Inc., Moblize Inc. and Trulite Inc. Our investment in Gridpoint is less than 20% and we account for this investment under the cost method. Our investment in Moblize rose above 20% during the three months ended September 30, 2006 when the Company exercised its right pursuant to two warrants, to purchase additional shares of the company. We account for this investment under the equity method. Trulite is a publicly traded company. We account for this investment in accordance with SFAS No. 115 (“SFAS 115”) “Accounting for Certain Investments in Debt and Equity Securities”.

Gridpoint, Inc. As of March 31, 2007, CVCC had invested approximately $1.0 million in Gridpoint in exchange for 333,333 shares of Gridpoint preferred stock, which represents an approximate 1.8% ownership interest. Gridpoint’s intelligent energy management products ensure clean, reliable power, increase energy efficiency, and integrate renewable energy. With Gridpoint, home and business owners can automatically protect themselves from power outages, manage their energy online and reduce their carbon footprint.

Moblize Inc. As of March 31, 2007, CVCC had invested $1.2 million in Moblize in exchange for 648,648 shares of Moblize convertible preferred stock, which represents an approximate 33% ownership interest. Moblize develops real time diagnostics and field optimization solutions for the oil and gas and other industries using open-standards based technologies. Moblize has deployed its technology on our Grand Isle 72 well which allows COI to remotely monitor, control and record, in real time, daily production volumes. Moblize is continuing to deploy its technology on oil fields near Houston belonging to Chevron U.S.A. Inc. and on other COI operated wells.

Trulite, Inc. As of March 31, 2007, CVCC had invested $0.9 million in Trulite in exchange for 2,001,014 shares of Trulite common stock, which represents an approximate 17% ownership interest. Trulite develops lightweight hydrogen generators for fuel cell systems, and recently began trading publicly on over the counter bulletin boards under the stock symbol “TRUL.OB”. As a result, we mark-to-market our investment in Trulite based on public pricing. At March 31, 2007, our investment in Trulite had a mark-to-market value of approximately $2.6 million.

As of March 31, 2007, CVCC owned 25% of Contango Capital Partners Fund, L.P. (the “Fund”). The Fund currently holds a direct investment in two alternative energy companies – Protonex Technology Corporation (“Protonex”) and Jadoo Power Systems (“Jadoo”). We account for our investment in the Fund under the equity method. The Fund, however, accounts for its investment in Protonex in accordance with SFAS 115, and accounts for its investment in Jadoo at fair value in accordance with the AICPA Audit and Accounting Guide, “Investment Companies”.

Protonex Technology Corporation. As of March 31, 2007, the Fund had invested $1.5 million in Protonex in exchange for 2,400,000 shares of Protonex stock, which represents an approximate 7% ownership interest. Protonex provides long-duration portable and remote power sources with a focus on providing solutions to the U.S. military and supplies complete power solutions and application engineering services to original equipment manufacturer’s customers. Protonex trades its common shares on the AIM market of the London Stock Exchange under the stock symbol “PTX.L”. As a result, the Fund marks-to-market its investment in Protonex based on public pricing. At March 31, 2007, the Fund’s investment in Protonex had a mark-to-market value of approximately $4.4 million.

Jadoo Power Systems. As of March 31, 2007, the Fund has invested approximately $1.2 million and owns 2,200,000 shares of Jadoo stock, which represents an approximate 5% ownership interest. Jadoo develops high energy density power products for the law enforcement, military and electronic news gathering applications. As of March 31, 2007, the Fund’s investment in Jadoo had a valuation of approximately $1.2 million.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. Long-Term Debt

On January 30, 2007, the Company completed the arrangement of a new $30.0 million secured term loan agreement with a private investment firm (the “Term Loan Agreement”). The Term Loan Agreement is secured with substantially all the assets of the Company, except for the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. As of March 31, 2007, the Company had borrowed $10.0 million under the Term Loan Agreement. Borrowings under the Term Loan Agreement bear interest at 30 day LIBOR plus 5.0%. Accrued interest is due monthly. The principal is due December 31, 2008, but we may prepay at any time with no prepayment penalty. An arrangement fee of 1%, or $300,000, was paid in connection with the term loan. Additionally, we pay a non-use fee in the amount of 0.50% per annum multiplied by such non-funded amount.

The Company has $20.0 million outstanding under a three-year $20.0 million secured term loan facility with The Royal Bank of Scotland plc (the “RBS Facility”). The RBS Facility is secured with the stock of Sundance. Sundance owns a 10% limited partnership interest in Freeport LNG, which owns the Freeport LNG facility. Borrowings under the RBS Facility bear interest, at the Company’s option, at either (i) 30 day LIBOR, (ii) 60 day LIBOR, (iii) 90 day LIBOR or (iv) 6 month LIBOR, all plus 6.5%. Interest is due at the end of the LIBOR period chosen. The principal is due April 27, 2009, but we may prepay after April 27, 2008 with no prepayment penalty.

Both the Term Loan Agreement and the RBS Facility require a minimum level of working capital and contain certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required working capital or comply with certain covenants in the Term Loan Agreement and RBS Facility could result in a default and acceleration of all indebtedness under such credit facilities. As of March 31, 2007, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement and RBS Facility.

On December 14, 2006, the Company terminated its $0.1 million credit facility with Guaranty Bank, FSB. The Company had no debt outstanding under this credit facility at the time of termination and was in compliance with its financial covenants, ratios and other provisions.

11. Related Party Transactions

In the ordinary course of business, the Company contracted with Moblize to install equipment that will allow COI to remotely monitor, control and record, in real time, daily production volumes from the Grand Isle 72 well. For the nine months ended March 31, 2007, the Company paid approximately $48,000 to Moblize for such services.

On October 26, 2006, REX executed a Demand Promissory Note (the “REX Note”) with a private investment firm which is non-recourse to Contango. Under the terms of the REX Note, REX can borrow up to $50.0 million at a per annum rate of 11.5% for the first advance, and a per annum rate of LIBOR plus 6.0% for each additional advance. All advances are payable in full on the earlier of October 26, 2008 or upon demand. As of March 31, 2007, REX had borrowed $20.0 million under the REX Note. The Company is not a party to or guarantor of the REX Note, but as a result of our proportionate consolidation of REX, $8.5 million is reflected as a current liability on our balance sheet as of March 31, 2007. The REX Note is secured by substantially all the assets of REX including the production attributable to REX from our Dutch and Mary Rose exploration discovery in the Gulf of Mexico. For the nine months ended March 31, 2007, the Company’s proportionate share of such interest expense was approximately $264,000.

In August 2006, the Company loaned $125,000 to Trulite under a Promissory Note (the “First Trulite Note”). The First Trulite Note bears interest at a per annum rate of 11.25% until February 9, 2007, at which point the per annum rate will change to prime rate plus three percentage points until May 1, 2007, which is when the Trulite Note plus all accrued and unpaid interest is due. On November 21, 2006, the Company loaned an additional $400,000 to Trulite under a second Promissory Note (the “Second Trulite Note”). The Second Trulite Note bears

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

interest at a per annum rate of 11.25% until April 24, 2007, at which point the per annum rate will change to prime rate plus three percentage points until July 22, 2007, which is when the Second Trulite Note plus all accrued and unpaid interest is due. On February 12, 2007, the Company loaned an additional $240,000 to Trulite under a third Promissory Note (the “Third Trulite Note”, and together with the First Trulite Note and Second Trulite Note, collectively, the “Trulite Notes”). The Third Trulite Note bears interest at a per annum rate of 11.25% until August 5, 2007, at which point the per annum rate will change to prime rate plus three percentage points until October 31, 2007, which is when the Third Trulite Note plus all accrued and unpaid interest is due. For the nine months ended March 31, 2007, the Company earned approximately $30,000 in interest income from the Trulite Notes.

On March 31, 2006, COE executed a Promissory Note (the “COE Note”) to the Company to finance its share of development costs in Grand Isle 72, in the aggregate principal amount of up to $2.8 million. The COE Note is payable upon demand and bears interest at a per annum rate of 10%. On March 20, 2007, the aggregate principal amount was increased to $3.75 million. As of March 31, 2007, the outstanding principal balance under the COE Note was $3.0 million. For the nine months ended March 31, 2007, the amount of accrued interest thereon was approximately $94,000.

In July 2006, the Company purchased options from one of the members of the Board of Directors for $91,190. We do not have a publicly announced program to repurchase shares of our common stock.

12. Subsequent Events

On April 24, 2007, the aggregate principal amount of the COE Note was increased to $5.0 million. On the same day, COE borrowed an additional $0.8 million from the Company, bringing the outstanding principal balance under the COE Note to $3.8 million as of May 4, 2007.

On April 9, 2007, the Company borrowed an additional $5.0 million under the Term Loan Agreement. The Company’s total debt obligation under the Term Loan Agreement was $15.0 million as of May 4, 2007.

On April 5, 2007, the Company entered into a subscription agreement, as amended from time to time (the “Subscription Agreement”) with Trulite, whereby both parties agreed to convert the aggregate principal balance of $765,000 in Trulite Notes and all accrued but unpaid interest into shares of Trulite common stock. The number of shares to be issued is dependant upon the average closing sale price for the common stock as determined pursuant to Subscription Agreement, and will take place once Trulite has a specified number of shares outstanding, as detailed in the Subscription Agreement.

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.

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 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, 2006, previously filed with the Securities and Exchange Commission.

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 and budgets

•

Anticipated capital expenditures

•

Drilling of wells

•

Natural gas and oil 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

•

Development, construction and financing of our liquefied natural gas (“LNG”) receiving terminal

•

Investment in alternative energy

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 among others:

•

Low and/or declining prices for natural gas and oil

•

Natural gas and oil price volatility

•

Interest rate volatility

•

The risks associated with acting as the operator in drilling deep high pressure wells in the Gulf of Mexico

•

The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes, especially in prospects in which the Company has made a large capital commitment relative to the size of the Company’s capitalization structure

•

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

•

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

•

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 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

•

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

•

Ability of LNG to become a competitive energy supply in the United States

•

Ability to fund our LNG project, cost overruns and third party performance

•

Successful commercialization of alternative energy technologies

•

Drilling costs, production rates and ultimate reserve recoveries in our Arkansas Fayetteville Shale play.

•

Drilling costs, production rates and ultimate reserve recoveries in our Dutch and Mary Rose acreage.

•

The ability of our partially-owned REX subsidiary to fund, on a non-recourse basis, its working interest commitment in our Dutch and Mary Rose discovery.

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 and in the Arkansas Fayetteville Shale. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator on certain offshore prospects. The Company also owns a 10% interest in a limited partnership formed to develop an LNG receiving terminal in Freeport, Texas, and holds investments in companies focused on commercializing environmentally preferred energy technologies.

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 our alliance partners. We depend on our alliance partners for prospect generation expertise. Our alliance partners, Juneau Exploration, L.P. (“JEX”) and Alta Resources, LLC (“Alta”) are experienced and have successful track records in exploration.

Using our capital availability to increase our reward/risk potential on selective prospects. We have concentrated our risk investment capital in two prospect areas; our onshore Arkansas Fayetteville Shale play and our

offshore Gulf of Mexico prospects. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success. COI, our wholly-owned subsidiary, drills and operates our offshore prospects. Should we be successful in any of our offshore prospects, we will have the opportunity to spend significantly more capital to complete development and bring the discovery to producing status.

Operating in the Gulf of Mexico. COI was formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico. Assuming the role of an operator represents a significant increase in the risk profile of the Company since the Company has limited operating experience. While COI has historically drilled turnkey wells, adverse weather conditions as well as difficulties encountered while drilling our offshore wells could cause our contracts to come off turnkey and thus lead to significantly higher drilling costs.

Arkansas Fayetteville Shale. We have made a major commitment to our Arkansas Fayetteville Shale program and this commitment is expected to continue to grow as we participate in the drilling of hundreds of gross exploration/development wells over the next five to ten years.

Sale of proved properties. From time-to-time as part of our business strategy, we have sold and in the future may continue to sell some or a substantial portion of our proved reserves to capture current value, using the sales proceeds to further our exploration, LNG and alternative energy investment activities. Since its inception, the Company has sold over $87.0 million worth of oil and natural gas 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.

In December 2006, COI completed the sale of its 25% working interest (“WI”) in the Grand Isle 72 well (“Liberty”) to an independent oil and gas company for $7.0 million. The sold property had reserves of approximately 1.9 billion cubic feet equivalent (“Bcfe”), net to COI. The Company recognized a loss of approximately $2.0 million for the nine months ended March 31, 2007 as a result of this sale.

On March 24, 2006, the Company’s Board of Directors approved the sale of all of the Company’s onshore producing assets in Texas and Alabama for an aggregate purchase price of $11.6 million. These properties were held by Contango STEP, L.P. (“STEP”), an indirect wholly-owned subsidiary of the Company. The sale was completed in June 2006. The sold properties had net reserves of approximately 203 thousand barrels of oil and 849 million cubic feet (“MMcf”) of gas, or 2.1 Bcfe. The Company recognized a pre-tax gain of $6.2 million for the year ended June 30, 2006. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” we classified this property sale as discontinued operations for all periods presented.

In March 2006, we sold a producing well in south Texas for approximately $2.0 million to an independent oil and gas company. Approximately 227 MMcf of proven reserves were sold. Pre-tax proceeds after netting adjustments were $2.0 million. In accordance with SFAS 144, we classified this property sale as discontinued operations for all periods presented.

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. With respect to our onshore prospects, we plan to continue outsourcing our geological, geophysical, and reservoir engineering and land functions, and partnering with cost efficient operators. We have six employees.

Structuring transactions to share risk. Our alliance partners share in the upfront costs and the risk of our exploration prospects.

Structuring incentives to drive behavior. We believe that equity ownership aligns the interests of our partners, employees, and stockholders. Our directors and executive officers beneficially own or have voting control over approximately 24% of our common stock.

Exploration Alliances with JEX and Alta

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, REX, COE and MOE (see “Offshore Gulf of Mexico Exploration Joint Ventures” below).

Alliance with Alta. Alta Resources, LLC (“Alta”) is a private company formed for the purpose of assembling domestic, onshore natural gas and oil prospects. Our arrangement with Alta generally provides for us to pay our share of seismic and lease costs, with Alta generally receiving a negotiated overriding royalty interest and a carried or back-in working interest.

Onshore Exploration and Properties

Alta Activities

Arkansas Fayetteville Shale

In March 2005, Contango and Alta entered into an agreement to acquire natural gas, oil, and mineral leases in the Arkansas Fayetteville Shale play area located in Pope, Van Buren, Conway, Faulkner, Cleburne, and White Counties, Arkansas. As of May 4, 2007, we and our partners have acquired or received commitments on approximately 45,000 net mineral acres at a cost of approximately $13.3 million. Our 70% share of the acquisition costs is approximately $9.3 million.

Of these 45,000 acres, approximately 7,000 acres, or 15%, are located in an area containing the statistically highest expected ultimate recovery per well in the Fayetteville Shale (“Tier One”). An additional 21,000 acres, or 47%, contain proven producing wells and include our Pigeon Roost and Buck Ridge exploration areas as well as acreage contiguous to our Tier One area (“Tier Two). Another 11,500 acres, or 26%, are located within Alta’s target area, but generally east of proven production and shallower than our Pigeon Roost and Buck Ridge areas (“Tier Three”). We also have 5,500 acres, or 12%, which are located south of Alta’s target area, and are considered more speculative (“Tier Four”).

The Arkansas Oil & Gas Commission has approved 20 separate 640-acre drilling units in Conway County, Arkansas that we estimate will allow Alta to potentially drill and operate up to approximately 180 horizontal wells. Horizontal wells are estimated to cost from $2.5 to $2.7 million in Tier One and from $2.7 to $3.7 million in Tier Two. We estimate our working interest in these Alta operated wells will average between 40% to 50%, with a net revenue interest of 32% to 40%. Alta intends to continue to seek approval from the Arkansas Oil & Gas Commission for additional 640-acre units.

Alta’s first seven wells have been drilled in Tier Two. These wells took considerably longer than expected to drill and incurred significant cost overruns. Of these seven wells, only the Alta-Thines #1-30H is currently producing. Production began in January 2007 and as of May 4, 2007, the Alta-Thines #1-30H was producing approximately 0.7 million cubic feet per day (“MMcf/d”). Of the remaining six wells, two are awaiting pipeline hookup (Alta-Briggler #1-31H and Alta-Ledbetter #1-33H)), two are ready for fracture stimulation (Alta-Clark #1-26H and Alta-Wooten #1-34H), one has been temporarily abandoned due to mechanical problems and one has been temporarily suspended prior to drilling into the Fayetteville. The 8/8ths cost for drilling and completing these seven Tier Two wells is estimated at $30.5 million (approximately $16.0 million net to Contango). Of this $16.0 million, we have already invested $13.5 million as of May 4, 2007. Contango’s net average working interest and net revenue interest in these seven Tier Two wells are approximately 54% and 43%, respectively.

Alta has recently entered into a five well rig contract to exploit our Tier One and Tier Two acreage. The first of these five wells, the Alta-Huff #1-29H, was spud in March 2007 and fracture stimulation is expected in May 2007. The second of these five wells, the Alta-Jones #1-29H, was spud in April 2007. These two wells are in and

around the Gravel Hill Field area in Van Buren County, Arkansas. In addition, Alta has arranged for an independent third party operator to drill two additional wells on Alta’s behalf. The first of these, the Chwalinski #1-29H was spud in March 2007 and is now awaiting fracture stimulation. The 8/8ths cost for drilling and completing these seven wells is estimated to be $18.4 million (approximately $8.8 million net to Contango). Of this $8.8 million, we have already invested $1.6 million as of May 4, 2007. Contango’s net average working interest and net revenue interest in these seven wells are approximately 47.5% and 37.0%, respectively.

In addition, we have been integrated by a third party independent oil and gas exploration company into 101 wells as of May 4, 2007 (the “Integrated Wells”). Of these 101 Integrated Wells, 46 are in Tier One, 52 are in Tier Two, two are in Tier Three and one is in Tier Four. Of these 101 Integrated Wells, 53 are producing. The 8/8ths production rate for 46 of these 53 producing wells was 42 MMcf/d as of March 31, 2007. Production data for the remaining seven producing wells was not available. The remaining 48 wells are either currently being drilled or are expected to be drilled over the next several months. Our net share of the drilling costs for these 48 wells is approximately $7.9 million. Our average working and net revenue interest in our 101 Integrated Wells thus far is approximately 6.5% and 5.5%, respectively.

Texas, Alabama and Louisiana

Outside of Arkansas, we have spud two onshore wells with Alta, the Alta-Ellis #1 in Texas, in which we have a 50% working interest and the Temple Inland #1 in Louisiana, in which we have a 77% working interest. The Alta-Ellis #1 began producing in December 2006, and as of May 1, 2007, was producing at a rate of 1.3 million cubic feet equivalent per day (“MMcfe/d”). We recorded an impairment charge of $0.2 million for this well in December 2006. The Temple Inland #1 began producing in April 2007, and as of April 30, 2007, was producing at a rate of 0.9 MMcfe/d. We expect to spud a third well, the Alta-Coley #1 in Alabama, in which we have a 67.5% working interest, by the end of June 2007, at an 8/8ths dry hole cost of approximately $1.2 million.

We have also invested with Alta in the developing West Texas Barnett Shale Play in Jeff Davis and Reeves Counties, Texas. The Alta group has leased approximately 5,800 net mineral acres (4,000 net mineral acres to Contango before a basket payout). A third party operator has drilled several wells near our acreage. Our plans are to monitor activity in this play.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. As of May 4, 2007, Contango and its affiliates have interests in 70 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

As of March 31, 2007, Contango owned a 42.7% equity interest in REX, a 76.0% equity interest in COE, and a 50.0% equity interest in MOE, all of which were formed for the purpose of generating exploration opportunities in the Gulf of Mexico. These companies have collectively licensed approximately 4,300 blocks of 3-D seismic data and have focused on identifying prospects, acquiring leases at federal and state lease sales and then selling the prospects to third parties, including Contango, subject to timed drilling obligations plus retained reversionary interests in favor of REX, COE and MOE.

Republic Exploration LLC. On September 2, 2005, Contango purchased an additional 9.4% ownership interest in REX for $5.625 million from JEX. As a result of this purchase, our equity ownership interest in REX increased from 33.3% to 42.7% and as of December 31, 2006, Contango had approximately $5.9 million invested in REX. The three other members of REX are JEX, its managing member, a privately held investment company, and a privately held seismic company. REX holds a non-exclusive license to approximately 2,485 blocks of 3-D seismic data in the shallow waters of the Gulf of Mexico. This data is used to identify, acquire and exploit natural gas and oil prospects. All leases owned by REX are subject to a 3.3% overriding royalty interest (“ORRI”) in favor of the JEX prospect generation team. See “Offshore Properties” below for more information on REX’s offshore properties.

Contango Offshore Exploration LLC. On September 2, 2005, Contango purchased an additional 9.4% ownership interest in COE for $1.875 million from JEX. As a result of this purchase, our equity ownership interest in COE increased from 66.6% to 76.0%. As of March 31, 2007, Contango had approximately $19.4 million invested in COE, which COE has used to acquire and reprocess 1,855 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. The two other members of COE are JEX, its managing member, and a privately held investment company. All leases are subject to a 3.3% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on COE’s offshore properties.

Grand Isle 72 (“Liberty”), a COE prospect, was successfully tested in March 2006. As of May 4, 2007, the Company has invested approximately $4.7 million in drilling, completion, pipeline and production facility costs. The well commenced production in March 2007, and as of May 7, 2007, was producing at a rate of approximately 1.6 MMcfe/d. The net revenue interest to COE after well completion is 40%.

Magnolia Offshore Exploration LLC. As of March 31, 2007, Contango had approximately $1.0 million invested in MOE. JEX is the only other member of MOE and acts as the managing member, deciding which prospects MOE may acquire, develop, and exploit. MOE’s license rights to 3-D seismic data have been assigned to COE. All leases are subject to a 3.3% ORRI in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on MOE’s offshore properties.

Current Activities. In February 2007, REX was awarded the following two lease tracts at the State of Louisiana Mineral Lease Sale for an aggregate purchase price of approximately $4.6 million ($1.8 million net to Contango): State Lease 19261 and 19266 (collectively with existing State Leases 18640 and 18860, the “Mary Rose” prospect).

In November 2006, REX acquired 75% of High Island A243 from a private company in exchange for REX paying all future delay rentals. In November 2006, COE acquired 75% of East Breaks 167, High Island A311, East Breaks 166 and High Island A342 from a private company in exchange for COE paying all future delay rentals.

In October 2006, REX was awarded the following three lease blocks from the Western Gulf of Mexico Lease Sale #200 for an aggregate purchase price of approximately $1.0 million: High Island A196, High Island A197 and High Island A198. The blocks are complimentary to our existing High Island prospects.

REX and COE have farmed out East Breaks 369/370 and Vermillion 154. East Breaks 369 was spud in March 2007 and determined to be a dry hole. The well has been plugged and abandoned. The farmee has until September 1, 2008 to decide if they will drill East Breaks 370. Vermillion 154 has been farmed out, and the operator expects to drill an exploratory well prior to July 2008. During fiscal year 2006, the agreement to farm out and drill an exploratory well on West Cameron 133 was cancelled and two lease blocks, Viosca Knoll 116 and 119, were relinquished to the MMS. Also during fiscal year 2006, West Delta 36 was farmed out and was completed in September 2006. Production began in December 2006 and as of May 4, 2007, West Delta 36 was producing at a rate of 12.1 MMcfe/d. REX has a 3.67% ORRI before payout and, at its option, may elect either a 5.0% ORRI or 25% WI after payout. High Island A279 was relinquished to the MMS in December 2006.

Record title interests in the Vermilion 73 and South Marsh Island 247 leases have been assigned to a common third party. Vermillion 73 was drilled and determined to be a dry hole. REX is in negotiations with the farmee to lower REX’s ORRI from 5% to 1.5% on Vermillion 73 so that another well may be drilled in the same block. Under the proposed terms, REX would receive $35,000 in exchange for the lower ORRI, and would also receive a 5% WI at payout. A timetable for drilling South Marsh Island 247 has not yet been established. REX has reserved a 5.0% ORRI before payout on South Marsh Island 247.

The MMS has implemented a rule on royalty relief for shallow water, deep shelf natural gas production from certain Gulf of Mexico leases. “Deep shelf gas” refers to natural gas produced from depths greater than 15,000 feet in waters of 200 meters or less. Royalty relief is available on the first 15 billion cubic feet (“Bcf”) of natural gas production if produced from an interval between 15,000 to less than 18,000 feet. Royalty relief is available on the first 25 Bcf of natural gas production if produced from an interval between 18,000 to less than 20,000 feet. Royalty relief is available on the first 35 Bcf of natural gas production if produced from well depths at or greater than 20,000 feet. This royalty relief is expected to have a positive impact on the economics of deep gas wells drilled on the shelf of the Gulf of Mexico.

Non-Operated Offshore Wells. The Company has non-operating working interests in three offshore blocks: Ship Shoal 358, Eugene Island 113-B and Eugene Island 76. Contango’s net revenue interest in these three wells is 5.8%, 3.1% and 2.14%, respectively. The Company depends on third-party operators for the operation and maintenance of these production platforms. As of May 4, 2007, the Ship Shoal 358 well was producing at a rate of approximately 1.3 MMcfe/d, the Eugene Island 113B well was producing at a rate of 7.0 MMcfe/d and the Eugene Island 76 well, a REX prospect, was depleted in November 2006.

Contango Operators, Inc.

COI is a wholly-owned subsidiary of Contango formed for the purpose of drilling exploration and development wells in the Gulf of Mexico. As part of our strategy, COI operates and acquires significant working interests in offshore exploration and development opportunities in the Gulf of Mexico, usually under a farm-out agreement with either REX or COE. COI takes working interests in these prospects under the same arms-length terms offered to third party industry participants. COI also operates and acquires significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.

Current Activities. In July 2006, we spud our Eugene Island 10 (“Dutch”) prospect, located offshore Louisiana in the Gulf of Mexico. In October 2006, we announced an exploration discovery at Dutch #1, and the well came on-stream on January 28, 2007. As of May 4, 2007, the well was flowing at an 8/8ths production rate of approximately 38.4 MMcfe/d. COI has invested approximately $7.4 million to drill and complete Dutch #1. COI has an 18.3% WI and REX has a 65% WI in Dutch # 1. The net revenue interests to COI and REX are approximately 16.2% and 57.4%, respectively, with MMS deep gas royalty relief on the first 15 Bcf of gas produced from the entire field. Once the royalty relief has expired, COI and REX have a net revenue interest of 13% and 47%, respectively. The lease was farmed in on a produce-to-earn basis. The lease has now been assigned, and REX has earned the lease.

In February 2007, we spud our Dutch #2 exploratory well at Eugene Island 10, and announced a discovery in April 2007. The Company expects the Dutch #2 well to begin production during July 2007 and is currently awaiting pipeline hookup. As of May 4, 2007, COI has invested approximately $2.5 million to drill and complete this well. COI has a 16.0% WI and REX has a 56.9% WI in Dutch #2. The working interest to Contango, as a whole, is approximately 40.3%. The net revenue interests to COI and REX are approximately 14.7% and 52.1%, respectively, with MMS deep gas royalty relief on the first 15 Bcf of gas produced from the entire field. Once the royalty relief has expired, COI and REX have a net revenue interest of 12.1% and 42.8%, respectively. Contango’s independent third party engineer estimates the Dutch (Eugene Island #10) and Mary Rose (offshore State of Louisiana) discovery to have total proved reserves of 152 billion cubic feet equivalent (“Bcfe”) (43.5 Bcfe net to Contango).

In April 2007, we spud our Dutch #3 exploratory well at Eugene Island 10. We expect to spud our fourth well, the Mary Rose #1, on Louisiana state acreage, upon completion of our Dutch #3 well later this summer. The Dutch #3 and the Mary Rose #1 are planned to flow into a platform currently under construction. The platform will have a capacity of 160 MMcfe/d, and is expected to be delivered in fall 2007, at an anticipated 8/8ths cost of $25.0 million. We anticipate it will take between 7 to 9 wells to fully develop our Dutch and Mary Rose discovery.

Our Dutch #3 well is expected to cost approximately $25.0 million to drill, complete and hookup. COI has a 16.0% WI and REX has a 56.9% WI in Dutch #3. The working interest to Contango, as a whole, is approximately 40.3%. The net revenue interests to COI and REX are approximately 14.7% and 52.1%, respectively, with MMS deep gas royalty relief on the first 15 Bcf of gas produced from the entire field. Once the royalty relief has expired, COI and REX have a net revenue interest of 12.1% and 42.8%, respectively. Our Mary Rose #1 well is expected to cost approximately $30.0 million, to drill, complete and hookup. COI has a 15.7% WI and REX has a 55.7% WI in Mary Rose #1. The working interest to Contango, as a whole, is approximately 39.6%. The net revenue interests to COI and REX are approximately 11.3% and 39.9%, respectively.

Offshore Properties

Producing Properties. The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico which are producing natural gas or oil as of May 4, 2007:


Area/Block	WI		NRI		Status
Contango Operators, Inc:
Eugene Island 113B	0	%	1.7	%	Producing
Eugene Island 10 #1	18.3	%	16.2	%	Producing

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

Republic Exploration LLC:

Eugene Island 113B	0	%	3.3	%	Producing
West Delta 36		(1)		(1)	Producing
Eugene Island 10 #1	65.0	%	57.4	%	Producing

(1)	REX has a 3.67% ORRI before payout and, at its option, may elect either a 5.0% ORRI or 25% WI after payout.

Farmed-Out Properties. The following table sets forth the working interests and net revenue interests owned by Contango and related entities in the Gulf of Mexico which have been farmed out as of May 4, 2007:


Area/Block	WI		NRI		Status
Republic Exploration LLC:
Vermilion 154		(2)		(2)	Drilling expected by summer 2008
Vermillion 73		(3)		(3)	Determined to be a dry hole
South Marsh Island 247		(4)		(4)	No drilling date has been determined yet

Contango Offshore Exploration LLC:
Main Pass 221	—		—		Determined to be a dry hole
East Breaks 369	—		—		Determined to be a dry hole
East Breaks 370		(5)		(5)	No drilling date has been determined yet
Vermilion 154		(2)		(2)	Drilling expected by summer 2008

(2)	REX and COE will split a 25% back-in WI after payout.

(3)	Record title interest in lease has been assigned to a third party. REX is in negotiations to change terms to a 1.5% ORRI plus a 5% WI after payout.

(4)	Record title interest in lease has been assigned to a third party. REX has reserved a 5% of 8/8ths ORRI before payout.

(5)	Farmee has until September 1, 2008 to decide if East Breaks 370 will be drilled. COE will receive a 3.67% ORRI before project payout and a 6.67% ORRI after project payout.

Leases. The following table sets forth the working interests owned by Contango and related entities in the Gulf of Mexico as of May 4, 2007:


Area/Block	WI		Lease Date
Contango Operators, Inc.:
West Cameron 174	10.0	%	Jul-03
Grand Isle 63	25.0	%	May-04
Grand Isle 73	25.0	%	May-04
West Delta 43	35.0	%	May-04
S-L 18640 (LA)	15.7	%	Jul-05
S-L 18860 (LA)	15.7	%	Jan-06
Ship Shoal 14	37.5	%	May-06
Ship Shoal 25	37.5	%	May-06
South Marsh Island 57	37.5	%	May-06
South Marsh Island 59	37.5	%	May-06
South Marsh Island 75	37.5	%	May-06
South Marsh Island 282	37.5	%	May-06
Grand Isle 70	3.65	%	Jun-06
West Delta 77	25.0	%	Jun-06
Vermilion 194 Eugene Island 10 S-L 19261 (LA) S-L 19266 (LA)	37.5 18.3 15.7 15.7	% % % %	Jul-06 Nov-06 Feb-07 Feb-07

Area/Block	WI		Lease Date
Republic Exploration LLC:
West Cameron 174	90.0	%	Jul-03
High Island 113	100.0	%	Oct-03
South Timbalier 191	50.0	%	May-04
Vermilion 36	100.0	%	May-04
Vermilion 109	100.0	%	May-04
Vermilion 134	100.0	%	May-04
West Cameron 179	100.0	%	May-04
West Cameron 185	100.0	%	May-04
West Cameron 200	100.0	%	May-04
West Delta 18	100.0	%	May-04
West Delta 33	100.0	%	May-04
West Delta 34	100.0	%	May-04
West Delta 43	30.0	%	May-04
Ship Shoal 220	50.0	%	Jun-04
South Timbalier 240	50.0	%	Jun-04
West Cameron 133	100.0	%	Jun-04
West Cameron 80	100.0	%	Jun-04
West Cameron 167	100.0	%	Jun-04
Eugene Island 76	0	%	Jul-04
Vermilion 130	100.0	%	Jul-04
West Cameron 107	100.0	%	May-05
Eugene Island 168	50.0	%	Jun-05
S-L 18640 (LA)	55.7	%	Jul-05
S-L 18860 (LA)	55.7	%	Jan-06
High Island A243	75.0	%	Jan-06
South Marsh Island 57	50.0	%	May-06
South Marsh Island 59	50.0	%	May-06
South Marsh Island 75	50.0	%	May-06
South Marsh Island 282	50.0	%	May-06
Ship Shoal 14	50.0	%	May-06
Ship Shoal 25	50.0	%	May-06
West Delta 77	50.0	%	Jun-06
Vermilion 194	50.0	%	Jul-06
High Island A196	100.0	%	Oct-06
High Island A197 High Island A198	100.0 100.0	% %	Oct-06 Oct-06
Eugene Island 10 S-L 19261 (LA) S-L 19266 (LA)	65.0 55.7 55.7	% % %	Nov-06 Feb-07 Feb-07


Area/Block	WI		Lease Date
Contango Offshore Exploration LLC:
Viosca Knoll 167	100.0	%	May-03
Vermilion 231	100.0	%	May-03
Viosca Knoll 161	33.3	%	Jul-03
Eugene Island 209	100.0	%	Jul-03
High Island A16	100.0	%	Dec-03
East Breaks 283	100.0	%	Dec-03
South Timbalier 191	50.0	%	May-04
Grand Isle 63	50.0	%	May-04
Grand Isle 72	50.0	%	May-04
Grand Isle 73	50.0	%	May-04
Ship Shoal 220	50.0	%	Jun-04
South Timbalier 240	50.0	%	Jun-04
Viosca Knoll 118	33.3	%	Jun-04
Viosca Knoll 475	100.0	%	May-05
Eugene Island 168	50.0	%	Jun-05
East Breaks 366	100.0	%	Nov-05
East Breaks 410	100.0	%	Nov-05
East Breaks 167	75.0	%	Dec-05
High Island A311	75.0	%	Dec-05
East Breaks 166	75.0	%	Jan-06
High Island A342	75.0	%	Jan-06
Ship Shoal 263	75.0	%	Jun-06
Grand Isle 70	52.6	%	Jun-06
Viosca Knoll 119	50.0	%	Jun-06
Viosca Knoll 383	100.0	%	Jun-06

Area/Block	WI		Lease Date
Magnolia Offshore Exploration LLC:
Viosca Knoll 161	16.7	%	Jul-03
Viosca Knoll 118	16.7	%	Jun-04
Viosca Knoll 211	100.0	%	Jul-04

Freeport LNG Development, L.P.

As of March 31, 2007, the Company has invested $3.2 million and owns a 10% limited partnership interest in Freeport LNG Development, L.P. (“Freeport LNG”), a limited partnership formed to develop, construct and operate a 1.75 billion cubic feet per day (“Bcf/d”) liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas. Startup is expected to occur in the first quarter of calendar year 2008.

Although we anticipate that we may, from time-to-time, be required to provide funds to the Freeport LNG project, and intend to provide our pro rata 10% of any required equity participation, we believe the project will continue through Phase I construction and Phase II pre-development with no further significant funds likely being required from Contango.

Contango Venture Capital Corporation

As of March 31, 2007, Contango Venture Capital Corporation (“CVCC”), our wholly-owned subsidiary, held a direct investment in three alternative energy portfolio companies – Gridpoint, Inc. (“Gridpoint”), Moblize Inc. (“Moblize”) and Trulite Inc. (“Trulite”). Our investment in Gridpoint is less than a 20% ownership interest and we account for this investment under the cost method. Our investment in Moblize rose above a 20% ownership interest during the three months ended September 30, 2006 when the Company exercised its right pursuant to two warrants, to purchase additional shares of the company. We account for this investment under the equity method. Trulite is a publicly traded company. We account for this investment in accordance with SFAS No. 115 (“SFAS 115”) “Accounting for Certain Investments in Debt and Equity Securities”.

Protonex Technology Corporation. As of March 31, 2007, the Fund had invested $1.5 million in Protonex in exchange for 2,400,000 shares of Protonex stock, which represents an approximate 7% ownership interest. Protonex provides long-duration portable and remote power sources with a focus on providing solutions to the U.S. military and supplies complete power solutions and application engineering services to original equipment manufacturers customers. Protonex trades its common shares on the AIM market of the London Stock Exchange under the stock symbol “PTX.L”. As a result, the Fund marks-to-market its investment in Protonex based on public pricing. At March 31, 2007, the Fund’s investment in Protonex had a mark-to-market value of approximately $4.4 million.

Application of Critical Accounting Policies and Management’s Estimates

The discussion and analysis of the Company’s financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these 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 1 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 oil and gas 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 financial statements:

Successful Efforts Method of Accounting. Our application of the successful efforts method of accounting for our oil and gas 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 oil and gas 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 oil and gas 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 oil and gas 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. The Company’s estimates of oil and gas 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 oil and gas 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 oil and gas 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 oil and gas 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 oil and gas 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 oil and gas properties and/or the rate of depletion of such oil and gas 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, 2007 of 1% would not have a material effect on DD&A expense.

Impairment of Oil and Gas Properties. The Company reviews its proved oil and gas 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 oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require the Company to record an impairment of its oil and gas 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. Effective July 1, 2006, we adopted Statement No. 123R which requires companies to measure and recognize compensation expense for all stock-based payments at fair value. SFAS No. 123R requires that management make 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 highly subjective assumptions, which are set forth in Note 1 to our consolidated financial statements.

MD&A Summary Data – Current Period

The table below sets forth revenue, expense and production data for continuing operations for the three and nine months ended March 31, 2007 and 2006. As stated in the Explanatory Note above, the tabular information below as well as the following narratives have been revised to focus only on continuing operations, rather than combining continuing operations with the results of our discontinued operations. We have also added a discontinued operations subsection to briefly discuss the activity in our financial statements that is associated with the discontinued operations.


	Three Months Ended March 31,								Nine Months Ended March 31,
	2007			2006			Change		2007			2006			Change
Revenues:	($000)								($000)
Natural gas and oil sales	$	5,416		$	123		4303	%	$	7,459		$	315		2268	%

Total revenues	$	5,416		$	123		4303	%	$	7,459		$	315		2268	%

Production:
Natural gas (million cubic feet)		648			11		5682	%		896			30		2866	%
Oil and condensate (thousand barrels)		12			0.5		2322	%		17			2		801	%
Total (million cubic feet equivalent)		720			14		5019	%		998			42		2275	%
Natural gas (million cubic feet per day)		7.2			0.1		5682	%		3.3			0.1		2866	%
Oil and condensate (thousand barrels per day)		0.1			0.1		*			0.1			0.1		*
Total (million cubic feet equivalent per day)		7.8			0.7		981	%		3.9			0.7		449	%

Average Sales Price:
Natural gas (per thousand cubic feet)	$	7.36		$	8.19		-10	%	$	7.19		$	7.16		0	%
Oil and condensate (per barrel)	$	56.20		$	65.60		-14	%	$	59.81		$	52.59		14	%

Operating (income) expenses	$	280		$	6		4567	%	$	558		$	(11	)	-5173	%
Exploration expenses	$	254		$	152		67	%	$	1,151		$	979		18	%
Depreciation, depletion and amortization	$	1,050		$	12		8650	%	$	1,555		$	99		1471	%
Impairment of natural gas and oil properties	$	—		$	420		-100	%	$	192		$	420		-54	%
General and administrative expenses	$	2,371		$	1,062		123	%	$	4,900		$	3,083		59	%
Interest expense (net of interest capitalized)	$	740		$	—		100	%	$	1,297		$	—		100	%
Interest income	$	231		$	166		39	%	$	638		$	565		13	%
Gain (loss) on sale of assets and other	$	(678	)	$	(19	)	3468	%	$	(1,994	)	$	223		-994	%

*	not meaningful

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006

Natural Gas and Oil Sales. We reported revenues of approximately $5.4 million for the three months ended March 31, 2007, compared to revenues of approximately $0.1 million for the three months ended March 31, 2006. This increase is mainly attributable to Dutch #1 which began producing in January 2007 and increased production from our Arkansas Fayetteville Shale play.

For the three months ended March 31, 2007, prices for natural gas and oil were $7.36 per thousand cubic feet (“Mcf”) and $56.20 per barrel, compared to $8.19 per Mcf and $65.60 per barrel for the three months ended March 31, 2006.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the three months ended March 31, 2007 was approximately 648 MMcf of natural gas, up from approximately 11 MMcf of natural gas for the three months ended March 31, 2006. Net oil production for the comparable periods also increased from approximately 500 barrels of oil to approximately 12,000 barrels of oil. This increase in natural gas and oil production is principally attributable to Dutch #1 which began producing in January 2007.

Operating Expenses. Lease operating expenses for the three months ended March 31, 2007 and the three months ended March 31, 2006 were $280,302 and $5,512, respectively. These expenses are related to our continuing operations from our onshore activities in the Arkansas Fayetteville Shale and our offshore activities in the Gulf of Mexico. The increase is attributable to increased activities in both areas.

Exploration Expense. We reported approximately $0.3 million of exploration expenses for the three months ended March 31, 2007, attributable to the cost of various geological and geophysical activities, seismic data, and delay rentals. We reported approximately $0.2 million of exploration expenses for the three months ended March 31, 2006. Of this amount, approximately $0.1 million was related to additional costs incurred while drilling onshore during the period and approximately $0.1 million was attributable to the cost of various geological and geophysical activities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2007 was approximately $1.1 million. For the three months ended March 31, 2006, we recorded $11,909 of depreciation, depletion and amortization. The increase is primarily the result of production from our Dutch #1 well which began producing in January 2007 and the Arkansas Fayetteville Shale play.

Impairment of Natural Gas and Oil Properties. No impairment of natural gas and oil properties was incurred during the three months ended March 31, 2007. For the three months ended March 31, 2006, impairment expenses were approximately $0.4 million. These related to impairment of offshore properties held by REX and COE, primarily to Main Pass 221 which was determined to be a dry hole during the period, and the East Cameron 107 lease, which expired. When Contango acquired an additional interest in COE, approximately $0.3 million of the purchase price was allocated to Main Pass 221 and was written off during the three months ended March 31, 2006.

General and Administrative Expenses. General and administrative expenses for the three months ended March 31, 2007 and the three months ended March 31, 2006 were approximately $2.4 million and $1.1 million, respectively.

Major components of general and administrative expenses for the three months ended March 31, 2007 included approximately $1.2 million in salaries and benefits, approximately $0.1 million in legal, accounting, engineering and other professional fees, approximately $0.5 million in office administration expenses, and approximately $0.6 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, 2006 included approximately $0.3 million in salaries and benefits, approximately $0.3 million in legal, accounting, engineering and other professional fees, approximately $0.2 million in office administration expenses, approximately $0.1 million in insurance costs, and approximately $0.2 million related to the cost of expensing stock options.

Interest Expense. We reported interest expense of $739,510, net of approximately $0.3 million of interest capitalized, for the three months ended March 31, 2007. This relates to amounts outstanding under our secured term loan agreement with a private investment firm (the “Term Loan Agreement”) and with The Royal Bank of Scotland plc (“RBS”, the “RBS Facility”). The Company did not have any debt outstanding or any interest expense for the three months ended March 31, 2006.

Interest Income. We reported interest income of $231,253 for the three months ended March 31, 2007. This compares to the $165,946 of interest income reported for the three months ended March 31, 2006. The increase is due to additional interest income from loans made to affiliates.

Gain (loss) on sale of assets and other. For the three months ended March 31, 2007, we reported a loss on sale of assets and other of approximately $0.7 million. This relates mainly to the Company’s December 2006 sale of COI’s 25% WI in the Grand Isle 72 well (“Liberty”). For the three months ended March 31, 2006, we reported a loss on sale of assets and other of $18,519 related to our alternative energy investments.

Nine Months Ended March 31, 2007 Compared to Nine Months Ended March 31, 2006

Natural Gas and Oil Sales. We reported revenues of approximately $7.5 million for the nine months ended March 31, 2007, compared to revenues of approximately $0.3 million for the nine months ended March 31, 2006. This increase is mainly attributable to Dutch #1 which began producing in January 2007 and increased production from our Arkansas Fayetteville Shale play.

For the nine months ended March 31, 2007, prices for natural gas and oil were $7.19 per Mcf and $59.81 per barrel, compared to $7.16 per Mcf and $52.59 per barrel for the nine months ended March 31, 2006.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the nine months ended March 31, 2007 was approximately 896 MMcf of natural gas, up from approximately 30 MMcf of natural gas for the nine months ended March 31, 2006. Net oil production for the comparable periods increased from approximately 2,000 barrels of oil to approximately 17,000 barrels of oil. The increase in natural gas and oil production is principally attributable to Dutch #1 which began producing in January 2007 and increased production from our Arkansas Fayetteville Shale play.

Operating Expenses. Lease operating expenses for the nine months ended March 31, 2007 were approximately $0.6 million. Lease operating expenses for the three months ended March 31, 2006 were a net credit of $11,216. This credit balance is attributable to the reversal of previous accruals.

Exploration Expense. We reported approximately $1.2 million of exploration expenses for the nine months ended March 31, 2007. Of this amount, approximately $1.5 million was attributable to the cost of various geological and geophysical activities, seismic data, and delay rentals, offset by a credit of approximately $0.3 million. We reported approximately $1.0 million of exploration expenses for the nine months ended March 31, 2006. Of this amount, approximately $0.7 million was related to unsuccessful wells drilled during the period and $0.3 million was attributable to the cost to acquire and reprocess 3-D seismic data, delay rentals and various other geological and geophysical activities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the nine months ended March 31, 2007 was approximately $1.6 million. For the nine months ended March 31, 2006, we recorded approximately $0.1 million of depreciation, depletion and amortization. The increase is primarily the result of production from our Dutch #1 well which began producing in January 2007, and the Arkansas Fayetteville Shale play.

Impairment of Natural Gas and Oil Properties. Approximately $0.2 million of impairment was reported for the nine months ended March 31, 2007. This was attributable to a write-down of costs of the Alta-Ellis #1 well in December 2006. For the three months ended March 31, 2006, impairment expenses were approximately $0.4 million. These related to impairment of offshore properties held by REX and COE, primarily to Main Pass 221 which was determined to be a dry hole during the period, and the East Cameron 107 lease, which expired. When Contango acquired an additional interest in COE, approximately $0.3 million of the purchase price was allocated to Main Pass 221 and was written off during the nine months ended March 31, 2006.

General and Administrative Expenses. General and administrative expenses for the nine months ended March 31, 2007 and the nine months ended March 31, 2006 were approximately $4.9 million and $3.1 million, respectively.

Major components of general and administrative expenses for the nine months ended March 31, 2007 included approximately $2.1 million in salaries and benefits, $0.4 million in legal, accounting, engineering and other professional fees, $1.1 million in office administration expenses, $0.2 million in insurance costs, and $1.1 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, 2006 included approximately $0.9 million in salaries and benefits, $0.5 million in legal, accounting, engineering and other professional fees, $0.8 million in office administration expenses, $0.2 million in insurance, and $0.7 million related to the cost of expensing stock options.

Interest Expense. We reported interest expense of $1.3 million, net of $0.8 million of interest capitalized, for the nine months ended March 31, 2007. This relates to amounts outstanding under our Term Loan Agreement and the RBS Facility. The Company did not have any debt outstanding or any interest expense for the nine months ended March 31, 2006.

Interest Income. We reported interest income of $638,395 for the nine months ended March 31, 2007. This compares to the $565,314 of interest income reported for the nine months ended March 31, 2006. The slight increase is due to additional interest income from loans made to affiliates.

Gain (loss) on sale of assets and other. For the nine months ended March 31, 2007, we reported a loss on sale of assets and other of approximately $2.0 million. This mainly relates to the Company’s December 2006 sale of COI’s 25% WI in the Grand Isle 72 well. For the nine months ended March 31, 2006, we reported a gain on sale of assets and other of approximately $0.2 million, representing other income recognized by our partially-owned subsidiary, COE.

Discontinued Operations. The Company had no discontinued operations for the nine months ended March 31, 2007. The table and discussions above, along with our financial statements, discuss only continuing operations. Not reflected are the revenues generated by the Company’s sold producing properties for the nine months ended March 31, 2006. Please see Note 5 – Sale of Properties – Discontinued Operations, for a discussion of our discontinued operations for the nine months ended March 31, 2006.

Production, Prices, Operating Expenses, and Other


	Three Months Ended March 31,				Nine Months Ended March 31,
	2007		2006		2007		2006
	(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)		648		11		896		30
Oil and condensate (thousand barrels)		12		0.5		17		2
Total (million cubic feet equivalent)		720		14		998		42

Natural gas (million cubic feet per day)		7.2		0.1		3.3		0.1
Oil and condensate (thousand barrels per day)		0.1		0.1		0.1		0.1
Total (million cubic feet equivalent per day)		7.8		0.7		3.9		0.7

Average sales price:
Natural gas (per thousand cubic feet)	$	7.36	$	8.19	$	7.19	$	7.16
Oil and condensate (per barrel)	$	56.20	$	65.60	$	59.81	$	52.59

Selected data per Mcfe:
Total lease operating expenses	$	0.39	$	0.39	$	0.56	$	(0.27	)
General and administrative expenses	$	3.31	$	75.86	$	4.91	$	73.40
Depreciation, depletion and amortization of natural gas and oil properties	$	1.30	$	0.85	$	1.34	$	2.39

MD&A Summary Data – Prior Periods

The table below sets forth revenue, expense and production data for continuing operations for the three months ended December 31, 2006 and 2005 and the three months ended September 30, 2006 and 2005. As stated in the Explanatory Note above, we are providing revised MD&A disclosures, covering the first and second quarters of our fiscal year ended June 30, 2007, to focus only on continuing operations, rather than combining continuing operations with the results of our discontinued operations.


	Three Months Ended December 31,							Three Months Ended September 30,
	2006			2005		Change		2006		2005		Change
Revenues:	($000)							($000)
Natural gas and oil sales	$	850		$	44	1832	%	$	1,192	$	148	705	%

Total revenues	$	850		$	44	1832	%	$	1,192	$	148	705	%

Production:
Natural gas (million cubic feet)		105			8	1143	%		144		10	1373	%
Oil and condensate (thousand barrels)		1			1	*			4		0.4	837	%
Total (million cubic feet equivalent)		111			14	676	%		168		12	1262	%
Natural gas (million cubic feet per day)		1.1			0.1	1143	%		1.6		0.1	1406	%
Oil and condensate (thousand barrels per day)		0.1			0.1	*			0.1		0.1	*
Total (million cubic feet equivalent per day)		1.7			0.7	152	%		2.2		0.7	211	%

Average Sales Price:
Natural gas (per thousand cubic feet)	$	7.45		$	10.30	-28	%	$	6.25	$	8.86	-29	%
Oil and condensate (per barrel)	$	58.33		$	50.18	16	%	$	70.21	$	63.61	10	%

Operating (income) expenses	$	145		$	126	15	%	$	133	$	6	2117	%
Exploration expenses	$	496		$	378	31	%	$	401	$	339	18	%
Depreciation, depletion and amortization	$	292		$	32	813	%	$	212	$	55	285	%
Impairment of natural gas and oil production	$	192		$	—	100	%	$	—	$	—	0	%
General and administrative expenses	$	1,426		$	1,100	30	%	$	1,103	$	922	20	%
Interest expense (net of interest capitalized)	$	390		$	—	100	%	$	167	$	—	100	%
Interest income	$	155		$	190	-18	%	$	252	$	209	21	%
Gain (loss) on sale of assets and other	$	(1,401	)	$	32	-4478	%	$	84	$	210	-60	%

*	not meaningful

Three Months Ended December 31, 2006 Compared to Three Months Ended December 31, 2005

Natural Gas and Oil Sales. We reported revenues of approximately $0.9 million for the three months ended December 31, 2006, compared to revenues of $44,298 for the three months ended December 31, 2005. This increase is mainly attributable to increased production from our Arkansas Fayetteville Shale play.

For the three months ended December 31, 2006, prices for natural gas and oil were $7.45 per thousand cubic feet (“Mcf”) and $58.33 per barrel, compared to $10.30 per Mcf and $50.18 per barrel for the three months ended December 31, 2005.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the three months ended December 31, 2006 was approximately 105 MMcf of natural gas, up from approximately 8 MMcf of natural gas for the three months ended December 31, 2005. Net oil production for the comparable periods remained relatively unchanged. The increase in natural gas production is principally attributable to increased production from our Arkansas Fayetteville Shale play, which is mostly natural gas.

Operating Expenses. Lease operating expenses for the three months ended December 31, 2006 and the three months ended December 31, 2005 were $144,702 and $125,896, respectively. These expenses are related to our continuing operations from our onshore activities in the Arkansas Fayetteville Shale and our offshore activities in the Gulf of Mexico. The increase is attributable to increased activities in both areas.

Exploration Expense. We reported approximately $0.5 million of exploration expenses for the three months ended December 31, 2006. Of this amount, approximately $2.5 million was attributable to the cost of various geological and geophysical activities, seismic data, and delay rentals, offset by a credit of approximately $2.0 million. We reported approximately $0.4 million of exploration expenses for the three months ended December 31, 2005. Of this amount, approximately $0.2 million was related to unsuccessful wells drilled during the period and approximately $0.2 million was attributable to the cost to acquire and reprocess 3-D seismic data, delay rentals and various other geological and geophysical activities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended December 31, 2006 was $292,192. For the three months ended December 31, 2005, we recorded $31,763 of depreciation, depletion and amortization. The increase is primarily the result of increased production from our Arkansas Fayetteville Shale play.

Impairment of Natural Gas and Oil Properties. Approximately $0.2 million of impairment was reported for the three months ended December 31, 2006. This was attributable to a write-down of costs of the Alta-Ellis #1 well in December 2006. No impairment of natural gas and oil properties was incurred during the three months ended December 31, 2005.

General and Administrative Expenses. General and administrative expenses for the three months ended December 31, 2006 and the three months ended December 31, 2005 were approximately $1.4 million and $1.1 million, respectively.

Major components of general and administrative expenses for the three months ended December 31, 2006 included approximately $0.4 million in salaries and benefits, $0.3 million in legal, accounting, engineering and other professional fees, $0.3 million in office administration expenses, 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 three months ended December 31, 2005 included approximately $0.3 million in salaries and benefits, $0.2 million in legal, accounting, engineering and other professional fees, $0.2 million in office administration expenses, $0.1 million in insurance, and $0.3 million related to the cost of expensing stock options.

Interest Expense. We reported interest expense, net of interest capitalized, of $390,434 for the three months ended December 31, 2006. This relates to amounts outstanding under our secured term loan agreement with RBS. The Company did not have any debt outstanding or any interest expense for the three months ended December 31, 2005.

Interest Income. We reported interest income of $155,483 for the three months ended December 31, 2006. This compares to the $190,315 of interest income reported for the three months ended December 31, 2005. The slight decrease is due to the lower average levels of cash and cash equivalents and short term investments.

Gain (loss) on sale of assets and other. For the three months ended December 31, 2006, we reported a loss on sale of asset and other of approximately $1.4 million. This relates mainly to the December 2006 sale of COI’s 25% WI in the Grand Isle 72 well (“Liberty”). For the three months ended December 31, 2005, we reported other income of $32,164 representing a gain related to our alternative energy investments.

Three Months Ended September 30, 2006 Compared to Three Months Ended September 30, 2005

Natural Gas and Oil Sales. We reported revenues of approximately $1.2 million for the three months ended September 30, 2006, compared to revenues of approximately $0.1 million for the three months ended September 30, 2005. This increase is mainly attributable to increased production from our Arkansas Fayetteville Shale play.

For the three months ended September 30, 2006, prices for natural gas and oil were $6.25 per Mcf and $70.21 per barrel, compared to $8.86 per Mcf and $63.61 per barrel for the three months ended September 30, 2005.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the three months ended September 30, 2006 was approximately 144 MMcf of natural gas, up from approximately 10 MMcf of natural gas for the three months ended September 30, 2005. Net oil production for the comparable periods increased from 427 barrels of oil to approximately 4,000 barrels of oil. The increase in natural gas and oil production is principally attributable to increased production from our offshore properties and our Arkansas Fayetteville Shale play.

Operating Expenses. Lease operating expenses for the three months ended September 30, 2006 and the three months ended September 30, 2005 were $132,949 and $5,749, respectively. These expenses are related to our continuing operations from our onshore activities in the Arkansas Fayetteville Shale and our offshore activities in the Gulf of Mexico. The increase is attributable to increased activities in both areas.

Exploration Expense. We reported $401,347 of exploration expenses for the three months ended September 30, 2006. Of this amount, approximately $758,777 was attributable to the cost of various geological and geophysical activities, seismic data, and delay rentals, offset by a credit of $357,430. We reported $339,438 of exploration expenses for the three months ended September 30, 2005. Of this amount, approximately $256,119 was related to unsuccessful wells drilled during the period and $83,319 was attributable to the cost to acquire and reprocess 3-D seismic data.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended September 30, 2006 was approximately $212,191. For the three months ended September 30, 2005, we recorded $55,360 of depreciation, depletion and amortization. The increase is primarily the result of increased production from our Arkansas Fayetteville Shale play.

General and Administrative Expenses. General and administrative expenses for the three months ended September 30, 2006 and the three months ended September 30, 2005 were approximately $1.1 million and $0.9 million, respectively.

Major components of general and administrative expenses for the three months ended September 30, 2006 included approximately $0.5 million in salaries and benefits, $0.1 million in legal, accounting, engineering and other professional fees, $0.2 million in office administration expenses, $0.1 million in insurance costs, and $0.2 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 September 30, 2005 included approximately $0.3 million in salaries and benefits, $0.1 million in legal, accounting, engineering and other professional fees, $0.2 million in office administration expenses, $0.1 million in insurance, and $0.2 million related to the cost of expensing stock options.

Interest Expense. We reported interest expense, net of interest capitalized, of $167,471 for the three months ended September 30, 2006. This relates to amounts outstanding under our secured term loan agreement with RBS. The Company did not have any debt outstanding or any interest expense for the three months ended September 30, 2005.

Interest Income. We reported interest income of $251,659 for the three months ended September 30, 2006. This compares to the $209,053 of interest income reported for the three months ended September 30, 2005. The slight increase is due to the higher average levels of cash and cash equivalents and short term investments, further enhanced by higher interest rates.

Other Income. For the three months ended September 30, 2006, we reported other income of $84,391 resulting from changes in the market value of Protonex and equity earnings from Moblize. For the three months ended September 30, 2005, we reported other income from partially owned subsidiaries of $209,522.

Production, Prices, Operating Expenses, and Other


	Three Months Ended December 31,				Three Months Ended September 30,
	2006		2005		2006		2005
	(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)		105		8		144		10
Oil and condensate (thousand barrels)		1		1		4		0.4
Total (million cubic feet equivalent)		111		14		168		12

Natural gas (million cubic feet per day)		1.1		0.1		1.6		0.1
Oil and condensate (thousand barrels per day)		0.1		0.1		0.1		0.1
Total (million cubic feet equivalent per day)		1.7		0.7		2.2		0.7

Average sales price:
Natural gas (per thousand cubic feet)	$	7.45	$	10.30	$	6.25	$	8.86
Oil and condensate (per barrel)	$	58.33	$	50.18	$	70.21	$	63.61

Selected data per Mcfe:
Lease operating expenses	$	1.29	$	8.80	$	0.79	$	0.47
General and administrative expenses	$	12.74	$	78.55	$	6.54	$	76.86
Depreciation, depletion and amortization of natural gas and oil properties	$	2.15	$	2.22	$	1.00	$	4.49

Capital Resources and Liquidity

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 to in the future to continue to rely heavily on the sales of assets to generate cash to fund our exploration investments and operations.

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

Operating Activities. Cash flows used in operating activities for the nine months ended March 31, 2007 was approximately $5.8 million, compared to cash flows provided by operating activities of $3.6 million for the nine months ended March 31, 2006. This decrease in cash flows from operating activities is primarily attributable to decreased production and revenues.

Investing Activities. Cash flows used in investing activities for the nine months ended March 31, 2007 was approximately $30.1 million, compared to $12.1 million for the same period in 2006. This $18.0 million increase in capital expenditures is primarily attributable to investing approximately $18.2 million more on natural gas and oil properties. Natural gas and oil exploration and development expenditures were approximately $40.0 million for the nine months ended March 31, 2007, compared to $21.8 million for the nine months ended March 31, 2006.

Financing Activities. Our financing activities provided approximately $28.3 million in cash flow for the nine months ended March 31, 2007 compared to $11.1 million for the same period in 2006. This increase is primarily attributable to borrowing $20.0 million in long term debt to finance our capital expenditures and borrowing approximately $8.5 million of long term debt by our affiliates.

Capital Budget. Over the next twelve months, our capital expenditure budget calls for us to invest approximately $49.0 million, as we continue to invest in our Arkansas Fayetteville Shale play and further develop our Dutch and Mary Rose discovery. We anticipate we will need a total of 7 to 9 wells to fully develop this discovery. The following capital expenditure projections are for the Company and its wholly-owned subsidiaries only, and do not include the capital expenditure projections for our partially-owned REX subsidiary. REX’s capital needs are provided by a private investment company under a $50.0 million demand note which is non-recourse to the Company, $20.0 million of which is currently outstanding. We believe this REX note facility together with anticipated cash flows available to REX will provide REX with sufficient liquidity to meet its obligations.

Of the $49.0 million in capital expenditures budgeted for the next twelve months, $17.8 million is anticipated to be invested in offshore activities. Specifically, our budget calls for us to invest approximately $2.7 million for production and pipeline facilities for developing Dutch #2 ($1.6 million of this was invested in April 2007), approximately $11.1 million in drilling, completion and hookup costs for three more Dutch and Mary Rose wells and approximately $4.0 million for a platform that is currently under construction.

Of the $49.0 million in capital expenditures budgeted for the next twelve months, $30.4 million is expected to be invested in the Arkansas Fayetteville Shale. We have budgeted to drill a total of 59 wells over the next twelve months. Of these, 14 are to be operated by Alta and 45 are budgeted to be Integrated Wells.

Of the 14 Alta budgeted wells, we have drilled the first three of seven wells with identified locations in our Tier One and Tier Two acreage. We estimate $7.3 million will be required during the remainder of fiscal year 2007 ($2.2 million was invested in April 2007) and $3.1 million in fiscal year 2008 to fully drill, complete, fracture stimulate and hookup these seven wells. Beyond this, our capital budget calls for us to drill one Alta operated well per month, at an estimated cost of $1.2 million per well, for a total cost of $8.2 million over the next twelve months. Additionally, we estimate $2.5 million will be required to complete, fracture stimulate and hookup four of the seven wells previously drilled in Tier Two.

Of the 45 budgeted Integrated Wells, our capital budget assumes we will invest $9.3 million for the next twelve months ($1.3 million of this was invested in April 2007). We estimate we will have an average working interest of 6.5% and a net revenue interest of 5.5% in these 45 Integrated Wells.

Our capital budget also calls for us to invest approximately $0.8 million with Alta in an onshore prospect in Alabama.

As of May 4, 2007, we have approximately $2.5 million in cash and cash equivalents, $35.0 million in long-term debt outstanding and $15.0 million of borrowing availability. The Company had estimated production as of May 4, 2007 of approximately 20.0 MMcfe/d.

We may need to raise additional debt and/or equity capital to supplement our internally generated cash flow to fund our offshore exploration and development and Arkansas Fayetteville Shale development programs. There can be no assurance we will be able to raise such additional capital.

Natural Gas and Oil Reserves

The following table presents our estimated net proved, developed producing natural gas and oil reserves and the pre-tax net present value of our reserves at March 31, 2007. Our onshore reserves were based on a reserve report generated by W.D. Von Gonten & Co. The offshore reserves were based on a reserve report generated by William M. Cobb & Associates, Inc. The pre-tax net present value is not intended to represent the current market value of the estimated natural gas and oil reserves we own.

The pre-tax net present value of future cash flows attributable to our proved reserves as of March 31, 2007 was determined by the March 31, 2007 prices of $7.34 per MMbtu for natural gas at Henry Hub and $65.87 per barrel of oil at West Texas Intermediate Posting, in each case before adjustments.


	Proved Reserves as of March 31, 2007
Natural Gas (MMcf)		50,214
Oil and Condensate (MBbls)		960.7
Total proved reserves (Mmcfe)		55,978

Pre-tax net present value, SEC guidelines ($000)	$	238,326

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. Therefore, estimates of natural gas and oil reserves are inherently imprecise. 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. Because most of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a lengthy production history.

It should not be assumed that the pre-tax net present value is the current market value of our estimated natural gas and oil reserves. In accordance with requirements of the Securities and Exchange Commission, we base the estimated discounted future net cash flows from proved reserves on prices and costs available on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Credit Facility

On January 30, 2007, the Company completed the arrangement of a $30.0 million secured term loan agreement with a private investment firm (the “Term Loan Agreement”). The Term Loan Agreement is secured with substantially all the assets of the Company, except for the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary, which is pledged to RBS under our term loan with RBS. As of May 4, 2007, the Company has borrowed $15.0 million under the Term Loan Agreement. Borrowings bear interest at 30 day LIBOR plus 5.0%. Accrued interest is due monthly. The principal is due December 31, 2008, but we may prepay at any time with no prepayment penalty. An arrangement fee of 1%, or $300,000, was paid in connection with the term loan. Additionally, we pay a non-use fee in the amount of 0.50% per annum multiplied by such non-funded amount.

On April 27, 2006 the Company completed the arrangement of a three-year $20.0 million secured term loan facility with RBS (the “RBS Facility”). The RBS Facility is secured with the stock of Sundance. Sundance owns a 10% limited partnership interest in Freeport LNG Development, LP, which owns the Freeport LNG facility. As of November 3, 2006, the Company had borrowed the entire $20.0 million under the RBS Facility. Borrowings bear interest, at the Company’s option, at either (i) 30 day LIBOR, (ii) 60 day LIBOR or (iii) 90 day LIBOR, all plus 6.5%. Interest is due at the end of the LIBOR period chosen. The principal is due April 27, 2009, but we may prepay after April 27, 2008 with no prepayment penalty.

Both the Term Loan Agreement and the RBS Facility require the maintenance of certain ratios, including those related to working capital, as set forth in the agreements relating to such facilities. Additionally, the Term Loan Agreement and RBS Facility contain certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required financial ratios or comply with the covenants in the Term Loan Agreement and RBS Facility could result in a default and acceleration of all indebtedness under such credit facilities. As of May 4, 2007, the Company was in compliance with its financial covenants, ratios and other provisions of the Term Loan Agreement and the RBS Facility.

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. The risk factors listed below are not all inclusive.

We have outsourced the marketing of our production and have no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and low prices would have a material adverse effect on our revenues, profitability and growth.

Our revenues, profitability and future growth will depend significantly on natural gas and crude oil prices. Prices received also will affect the amount of future cash flow available for capital expenditures and repayment of indebtedness and will affect our ability to raise additional capital. 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 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 special taxes.

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 our alliance partners and could be seriously harmed if our alliance agreements were terminated.

Because we have only six employees, none of whom are geoscientists or petroleum engineers, we are dependent upon alliance partners for the success of our natural gas and oil exploration projects and expect to remain so for the foreseeable future. Highly qualified explorationists and engineers are difficult to attract and retain. As a result, the loss of the services of one or more of our alliance partners could have a material adverse effect on us and could prevent us from pursuing our business plan. Additionally, the loss by our alliance partners 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 will 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, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, our credit facility imposes limits on our ability to borrow under the facility based on adjustments to the value of our hydrocarbon reserves, and our credit facility limits our ability to incur additional indebtedness. 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.

We lack experience as Operator in drilling high pressure wells in the Gulf of Mexico.

Contango Operators, Inc. (“COI”) is a wholly-owned subsidiary of the Company, formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico and is a recent addition to our business strategy. COI is currently the operator for our Dutch and Mary Rose discovery. Although as a company we have previously taken working interests in offshore prospects, our recent exploration prospects are the first wells in which we have assumed the role of operator. Estimated drilling costs could be significantly higher if we encounter difficulty in drilling offshore exploration wells.

Drilling activities are subject to numerous risks, including the 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. The Company’s drilling operations may be curtailed, delayed, canceled or negatively impacted as a result of numerous factors, including inexperience as an operator, 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 we cannot assure that new wells will be productive or that we will recover all or any portion of our investment. The risk of significant cost overruns, curtailments, delays, inability to reach our target reservoir and other factors detrimental to drilling and completion operations may be higher due to our inexperience as an operator.

We may have excessive resources committed to our Arkansas Fayetteville Shale Play.

Our Arkansas Fayetteville Shale play proven reserves at March 31, 2007 were approximately 8.0 Bcf. Since inception, we have invested approximately $31.7 million in our Fayetteville Shale play ($9.3 million in lease acquisitions and $22.4 million in drilling and completion activities), while our revenues from the play from inception through the production month of February 2007 have totaled only $1.6 million. There can be no assurance that our drilling activity in this area will produce economically feasible wells. Our capital budget for the next twelve months calls for us to invest an additional $30.4 million in the Arkansas Fayetteville Shale. This represents approximately 62% of our total CAPEX budget for the next twelve months. We intend to continue to borrow significant capital against anticipated revenues and production, and should the wells not perform as expected, we could encounter difficulty repaying this debt. It is early in the exploration and development of this play, there is a lack of oil field service infrastructure in the area, and we are still learning how to most efficiently drill, complete, fracture stimulate and produce these wells. Some of our wells have taken considerably longer than expected to drill, and we have had significant cost overruns. All of our wells are operated by others and as a result, we have a limited ability to exercise influence over operations or their associated costs.

We are highly dependant on the lending availability of a single company.

Our $30.0 million Term Loan Agreement and REX’s $50.0 million demand note are with the same private investment firm. Collectively, Contango and REX have borrowed $35.0 million as of May 4, 2007. Should the private investment firm encounter difficulties funding future requested advances, some portion or all of the $45.0 million of capital that remains unfunded may no longer be available. In that case, we would have to seek alternative and possibly more expensive financing, which may or may not be available.

Increasing capital investment in certain prospects increases our dry hole risk exposure.

Beginning in the spring of 2005, we decided to increase our capital investment in certain exploration prospects, including our onshore Arkansas Fayetteville Shale prospect and our offshore Gulf of Mexico prospects. Both of these investments represent a major increase in the risk profile of the Company which in the past has limited its dry hole risk exposure on any one well to approximately $1.0 million.

The construction of our LNG receiving terminal in Freeport, Texas is subject to various development and completion risks.

We own a 10% limited partnership interest in the Freeport LNG receiving facility that is being constructed in Freeport, Texas. The LNG project received approval from the Federal Energy Regulatory Commission (the “FERC”) in June 2004. On January 11, 2005, Freeport LNG received its authorization to commence construction of the first phase of its terminal from the FERC. Construction of the 1.75 Bcf/d facility commenced on January 17, 2005. Freeport LNG is seeking an additional order from the FERC that would authorize the construction of an expansion that would increase the permitted capacity from its current level of 1.75 Bcf/d up to as much as 4.0 Bcf/d. The LNG receiving facility is subject to development risk such as permitting, cost overruns and delays. Key factors that may affect the completion of the LNG receiving terminal include, but are not limited to: timely issuance of necessary additional permits, licenses and approvals by governmental agencies and third parties; sufficient financing; unanticipated changes in market demand or supply; competition with similar projects; labor disputes; site difficulties; environmental conditions; unforeseen events, such as hurricanes, explosions, fires and product spills; delays in manufacturing and delivery schedules of critical equipment and materials; resistance in the local community; local and general economic conditions; and commercial arrangements for pipelines and related equipment to transport and market LNG.

If completion of the LNG receiving facility is delayed beyond the estimated development period, the actual cost of completion may increase beyond the amounts currently estimated in our capital budget. A delay in completion of the LNG receiving facility would also cause a delay in the receipt of revenues projected from operation of the facility, which may cause our business, results of operations and financial condition to be substantially harmed.

If we are not able to fund or finance our 10% ownership in the LNG receiving facility in Freeport, Texas, including any expansion of the facility, we may lose our 10% investment in the project.

A majority of the Freeport LNG construction costs is being provided by The ConocoPhillips Company. Upon any significant increase in construction costs to complete construction of the receiving facility or upon a call to fund construction of the proposed expansion, we may not have the financial resources to fund our 10% ownership share of construction costs. If we are unable to fund our share of the project costs or if the project is unable to secure third-party project financing, we could lose our investment in the project or be forced to sell our interest in an untimely fashion or on less than favorable terms.

If we default on our Royal Bank of Scotland loan we could lose our 10% investment in the LNG receiving facility in Freeport, Texas.

Our three-year $20.0 million term loan agreement dated April 27, 2006 with The Royal Bank of Scotland plc is secured with the stock of Contango Sundance, Inc. (“Sundance”), our wholly-owned subsidiary. Sundance owns a 10% limited partnership interest in Freeport LNG Development, LP, which owns the Freeport LNG facility. If an event of default occurs under the RBS Facility, we could lose our investment in the Freeport LNG facility.

If REX cannot promptly repay the REX Note upon demand by the lender, REX could lose all of its assets.

The REX Note is payable upon the earlier of a demand by the lender or October 26, 2007 and is secured by substantially all of the assets of REX. If the lender were to demand repayment and REX were unable to access funds for repayment, REX could lose all the collateral securing the REX Note.

Should the Company default on its $30.0 million term loan agreement, we could lose substantially all of our assets.

Our $30.0 million Term Loan Agreement dated January 30, 2007 is due December 31, 2008 and is secured with all of the Company’s assets other than LNG. If an event of default occurs under the Term Loan Agreement, we could lose all the collateral securing the term loan.

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 would 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 and present values of our reserves.

The process of estimating natural gas and oil reserves is complex. 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 and present value of reserves shown in this report.

In order to prepare these estimates, our independent third party petroleum engineer 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. Therefore, estimates of natural gas and oil reserves are inherently imprecise.

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. Some of the producing wells included in our reserve report have produced for a relatively short period of time. Because some of our reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a more lengthy production history.

You should not assume that the pre-tax net present value of our proved reserves prepared in accordance with SEC guidelines referred to in this report is the current market value of our estimated natural gas and oil reserves. We base the pre-tax net present value of future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices, costs, taxes and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.

The proven reserves assigned to our Dutch and Mary Rose discovery in particular have only one producing well bore that as of March 31, 2007, had only 2 months of production history. Reserve assessments based on only one well bore with limited production history are subject to greater risk of downward revision than multiple well bores from a mature producing reservoir.

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

•

Unexpected drilling conditions.

•

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

•

Pressure or irregularities in formations.

•

Equipment failures or accidents.

•

Tropical storms, hurricanes and other adverse weather conditions.

•

Compliance with governmental requirements and laws, present and future.

•

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

•

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

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.

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

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

•

Blowouts, fires and explosions.

•

Surface cratering.

•

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

•

Natural disasters.

•

Pipe and cement failures.

•

Casing collapses.

•

Stuck drilling and service tools.

•

Abnormal pressure formations.

•

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

If any of these events occur, we could incur substantial losses as a result of:

•

Injury or loss of life.

•

Severe damage to and destruction of property, natural resources or equipment.

•

Pollution and other environmental damage.

•

Clean-up responsibilities.

•

Regulatory investigations and penalties.

•

Suspension of our operations or repairs necessary to resume operations.

Offshore operations are subject to a variety of operating risks peculiar to the marine environment, such as capsizing and collisions. In addition, offshore operations, and in some instances, operations along the Gulf Coast, are subject to damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce the funds available for exploration, development or leasehold acquisitions, or result in loss of properties.

If we were to experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, any one of which could adversely affect our ability to conduct operations. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks. Losses could occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, and particular types of coverage may not be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Not hedging our production may result in losses.

Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if our production should be shut-in during a period when NYMEX natural gas prices increase, our policy is to hedge only through the purchase of puts. By not hedging our production, we may be more adversely affected by declines in natural gas and oil prices than our competitors who engage in hedging arrangements.

Our ability to market our natural gas and oil may be impaired by capacity constraints on the gathering systems, pipelines and processing plants that transport and process our natural gas and oil.

All of our natural gas and oil is transported through gathering systems, pipelines and processing plants, and in some cases offshore platforms, which we do not own. 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.

We have no assurance of title to our leased interests.

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 our alliance partners 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. We have no assurance, however, that any such deficiencies have been cured by the operator of any 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 most 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. Most 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 will depend on our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most 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 currently 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.

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:

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Problems integrating the purchased operations, personnel or technologies.

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Unanticipated costs.

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Diversion of resources and management attention from our exploration business.

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

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Potential loss of key employees, particularly those of the acquired organization.

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. These provisions, among other things, authorize the board of directors to:

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

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Limit the personal liability of directors.

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Limit the persons who may call special meetings of stockholders.

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Prohibit stockholder action by written consent.

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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.

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

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Impose restrictions on business combinations with some interested parties.

Our common stock is thinly traded.

Contango has approximately 16 million shares of common stock outstanding, held by approximately 120 holders of record. Directors and officers own or have voting control over approximately 3.4 million shares. Since our common stock is thinly 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.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has duly caused this Amendment No. 1 to be signed on its behalf by the undersigned, thereunto duly authorized.


CONTANGO OIL & GAS COMPANY

/s/ KENNETH R. PEAK				/s/ LESIA BAUTINA
Kenneth R. Peak				Lesia Bautina
Chairman, Chief Executive Officer and Chief Financial Officer (principal executive officer and principal financial officer)				Senior Vice President and Controller (principal accounting officer)

EXHIBIT INDEX


EXHIBIT NO.		DESCRIPTION
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 Sarbanes-Oxley Act of 2002.