Edgar Filing: CONTANGO OIL & GAS CO

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006

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 ¨ Non-accelerated filer x

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 11, 2006 was 14,999,085.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE NINE MONTHS ENDED MARCH 31, 2006

TABLE OF CONTENTS


		Page

	PART I – FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets as of March 31, 2006 and June 30, 2005	3
	Consolidated Statements of Operations for the three and nine months ended March 31, 2006 and 2005	5
	Consolidated Statements of Cash Flows for the nine months ended March 31, 2006 and 2005	6
	Consolidated Statement of Shareholders’ Equity for the nine months ended March 31, 2006	7
	Notes to the Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	46
Item 4.	Controls and Procedures	47

	PART II – OTHER INFORMATION

Item 1A.	Risk Factors	47
Item 6.	Exhibits and Reports on Form 8-K	48

All references in this Form 10-Q to the “Company”, “Contango”, “we”, “us” or “our” are to Contango Oil & Gas Company and its wholly-owned Subsidiaries. Unless otherwise noted, all information in this Form 10-Q relating to natural gas and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates prepared by independent engineers and are net to our interest.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2006			June 30, 2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6,593,618		$	3,985,775
Short-term investments		9,912,482			25,499,869
Accounts receivable, net		1,212,076			1,423,094
Other		483,266			302,926

Total current assets		18,201,442			31,211,664

PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties		11,781,476			1,520,530
Unproved properties		20,748,874			7,789,306
Properties held for sale		6,910,090			3,145,518
Furniture and equipment		229,822			197,949
Accumulated depreciation, depletion and amortization		(2,306,924	)		(1,328,567	)

Total property, plant and equipment, net		37,363,338			11,324,736

OTHER ASSETS:
Cash and other assets held by affiliates		1,316,306			1,067,263
Investment in Freeport LNG Project		3,243,585			3,006,751
Investment in Contango Venture Capital Corporation		2,978,158			2,274,356
Deferred income tax asset		3,923,426			4,462,329
Other assets		5,822			5,822

Total other assets		11,467,297			10,816,521

TOTAL ASSETS	$	67,032,077		$	53,352,921

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2006			June 30, 2005
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	997,910		$	435,661
Accrued exploration and development		1,841,590			85,608
Income taxes payable		65,709			1,658,548
G&A accrued liabilities		529,416			189,823
Other accrued liabilities		25			3,271

Total current liabilities		3,434,650			2,372,911

ASSET RETIREMENT OBLIGATION		10,171			957
SHAREHOLDERS’ EQUITY:
Convertible preferred stock, 6%, Series D, $0.04 par value, 4,000 shares authorized, 2,000 shares issued and outstanding at March 31, 2006, liquidation preference of $10,000,000 at $5,000 per share		80			—
Convertible preferred stock, 6%, Series C, $0.04 par value, 4,000 shares authorized, 1,400 shares issued and outstanding at June 30, 2005, liquidation preference of $7,000,000 at $5,000 per share		—			56
Common stock, $0.04 par value, 50,000,000 shares authorized, 17,574,085 shares issued and 14,999,085 outstanding at March 31, 2006, 15,997,809 shares issued and 13,422,809 outstanding at June 30, 2005		702,961			639,910
Additional paid-in capital		44,903,869			32,800,077
Treasury stock at cost (2,575,000 shares)		(6,180,000	)		(6,180,000	)
Retained earnings		24,160,346			23,719,010

Total shareholders’ equity		63,587,256			50,979,053

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	67,032,077		$	53,352,921

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,
	2006			2005			2006			2005
REVENUES:
Natural gas and oil sales	$	123,199		$	256,632		$	315,274		$	630,720

Total revenues		123,199			256,632			315,274			630,720

EXPENSES:
Operating expenses (credits)		5,512			5,890			(11,216	)		43,610
Exploration expenses		152,011			1,741,322			978,682			3,014,786
Depreciation, depletion and amortization		11,909			98,884			99,032			266,205
Impairment of natural gas and oil properties		419,918			124,537			419,918			236,537
General and administrative expense		1,061,518			620,738			3,083,492			2,520,262

Total expenses		1,650,868			2,591,371			4,569,908			6,081,400

LOSS FROM CONTINUING OPERATIONS BEFORE OTHER INCOME AND INCOME TAXES		(1,527,669	)		(2,334,739	)		(4,254,634	)		(5,450,680	)
OTHER INCOME (EXPENSE):
Interest expense		(93	)		(93	)		(285	)		(71,410	)
Interest income		165,946			168,466			565,314			201,822
Gain (loss) on sale of assets and other		(18,519	)		(12,346	)		223,167			(99,166	)

LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(1,380,335	)		(2,178,712	)		(3,466,438	)		(5,419,434	)
Benefit for income taxes		524,792			762,549			1,326,191			1,896,802

LOSS FROM CONTINUING OPERATIONS		(855,543	)		(1,416,163	)		(2,140,247	)		(3,522,632	)

DISCONTINUED OPERATIONS (Note 3 and 4)
Discontinued operations, net of income taxes		1,754,965			344,119			3,032,583			17,188,866

NET INCOME (LOSS)		899,422			(1,072,044	)		892,336			13,666,234
Preferred stock dividends		150,000			105,000			451,000			315,000

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	749,422		$	(1,177,044	)	$	441,336		$	13,351,234

NET INCOME (LOSS) PER SHARE:
Basic
Continuing operations	$	(0.07	)	$	(0.12	)	$	(0.18	)	$	(0.30	)
Discontinued operations		0.12			0.03			0.21			1.32

Total	$	0.05		$	(0.09	)	$	0.03		$	1.02

Diluted
Continuing operations	$	(0.07	)	$	(0.12	)	$	(0.18	)	$	(0.30	)
Discontinued operations		0.12			0.03			0.21			1.32

Total	$	0.05		$	(0.09	)	$	0.03		$	1.02

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic		14,865,965			13,108,196			14,675,586			13,030,251

Diluted		14,865,965			13,108,196			14,675,586			13,030,251

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,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES:
(Loss) from continuing operations	$	(2,140,247	)	$	(3,522,632	)
Plus income from discontinued operations, net of income taxes		3,032,583			17,188,866

Net income		892,336			13,666,234
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		1,065,766			2,525,530
Impairment of natural gas and oil properties		419,918			236,537
Exploration expenditures		1,759,438			2,259,019
Deferred income taxes		538,905			(3,146,741	)
Gain on sale of assets and other		(1,081,271	)		(16,188,274	)
Stock-based compensation		599,695			274,573
Tax benefit from exercise of stock options		(414,854	)		—
Changes in operating assets and liabilities:
Decrease in accounts receivable and other		240,789			3,855,874
(Increase) in prepaid insurance		(59,594	)		(70,570	)
Decrease (increase) in accounts payable		537,528			(322,730	)
Increase (decrease) in other accrued liabilities		294,698			(302,554	)
Increase (decrease) in income taxes payable		(1,177,985	)		4,026,501
Other		(38,474	)		3,968

Net cash provided by operating activities		3,576,895			6,817,367

CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures		(21,783,141	)		(4,982,088	)
Natural gas and oil exploration and development reimbursements		—			2,560,689
Increase in net investment in affiliates		26,634			(755,877	)
Investment in Freeport LNG Project		(236,834	)		(673,418	)
Sale (Purchase) of short-term investments		15,587,387			(27,555,658	)
Proceeds from the sale of assets		1,744,215			40,126,428
Sales costs		—			(168,686	)
Additions to furniture and equipment		(18,370	)		(6,614	)
Decrease in advances to operators		1,802,906			215,230
Investment in Contango Venture Capital Corporation		(708,021	)		(770,432	)
Acquisition of overriding royalty interests		(1,000,000	)		—
Acquisition of Republic Exploration LLC and Contango Offshore Exploration LLC interests		(7,500,000	)		—

Net cash (used) provided by investing activities		(12,085,224	)		7,989,574

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility		—			2,200,000
Repayments under credit facility		—			(9,289,000	)
Proceeds from exercised options, warrants and others		1,535,880			1,086,168
Tax benefit from exercise of stock options		414,854			—
Preferred stock dividends		(451,000	)		(315,000	)
Proceeds from preferred equity, net of issuance costs		9,616,438			—
Debt issue costs		—			(20,200	)

Net cash (used) provided by financing activities		11,116,172			(6,338,032	)

NET INCREASE IN CASH AND CASH EQUIVALENTS		2,607,843			8,468,909
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		3,985,775			396,753

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	6,593,618		$	8,865,662

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes	$	945,816		$	6,475,221

Cash paid for interest	$	285		$	83,061

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, 2006
	Preferred Stock					Common Stock			Paid-in Capital			Treasury Stock			Retained Earnings			Total Shareholders’ Equity
	Shares		Amount			Shares	Amount		Paid-in Capital			Treasury Stock			Retained Earnings			Total Shareholders’ Equity
Balance at June 30, 2005	1,400		$	56		13,422,809	$	639,910	$	32,800,077		$	(6,180,000	)	$	23,719,010		$	50,979,053
Exercise of stock options and warrants	—			—		125,000		5,000		377,500			—			—			382,500
Tax benefit from exercise of stock options	—			—		—		—		6,536			—			—			6,536
Expense of stock options	—			—		—		—		177,939			—			—			177,939
Cashless exercise of stock options	—			—		1,576		63		(63	)		—			—			—
Conversion of Series C preferred stock	(1,400	)		(56	)	1,166,662		46,666		(46,610	)		—			—			—
Issuance of Series D preferred stock	2,000			80		—		—		9,616,358			—			—			9,616,438
Net income	—			—		—		—		—			—			211,301			211,301
Preferred stock dividends	—			—		—		—		—			—			(151,000	)		(151,000	)

Balance at September 30, 2005	2,000		$	80		14,716,047	$	691,639	$	42,931,737		$	(6,180,000	)	$	23,779,311		$	61,222,767

Expense of stock options	—			—		—		—		192,428			—			—			192,428
Cashless exercise of stock options	—			—		1,538		62		(62	)		—			—			—
Net loss	—			—		—		—		—			—			(218,387	)		(218,387	)
Preferred stock dividends	—			—		—		—		—			—			(150,000	)		(150,000	)

Balance at December 31, 2005	2,000		$	80		14,717,585	$	691,701	$	43,124,103		$	(6,180,000	)	$	23,410,924		$	61,046,808

Exercise of stock options and warrants	—			—		281,500		11,260		1,142,120			—			—			1,153,380
Tax benefit from exercise of stock options	—			—		—		—		408,318			—			—			408,318
Expense of stock options	—			—		—		—		229,328			—			—			229,328
Net income	—			—		—		—		—			—			899,422			899,422
Preferred stock dividends	—			—		—		—		—			—			(150,000	)		(150,000	)

Balance at March 31, 2006	2,000		$	80		14,999,085	$	702,961	$	44,903,869		$	(6,180,000	)	$	24,160,346		$	63,587,256

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 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 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, 2005. The results of operations for the three and nine months ended March 31, 2006 are not necessarily indicative of the results that may be expected for the fiscal year ending June 30, 2006.

1. Summary of Critical 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 critical accounting principles, which are described below, relate to the successful efforts method for costs related to natural gas and oil activities, consolidation principles and stock based compensation, cash and cash equivalents, and short-term investments.

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 cash flows on a cost center basis to the unamortized capitalized cost of the asset. If the future undiscounted 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.

In accordance with Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company classified its property sale to Edge Petroleum Corporation (“Edge Petroleum”), effective July 1, 2004, and its property sale to an independent oil and gas company effective February 1, 2006, as discontinued operations. In addition, as of March 31, 2006, all of the Company’s onshore producing assets were also classified as discontinued operations. These properties were sold effective April 1, 2006. 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.

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, 2006, the Company had $6,593,618 in cash and cash equivalents, of which $2,161,737 was invested in highly liquid AAA-rated tax-exempt money market funds.

Short Term Investments. As of March 31, 2006, the Company had $9,912,482 invested in a portfolio of periodic auction reset (“PAR”) securities, which have coupons that periodically reset to market interest rates at intervals ranging from 7 to 35 days. These PAR securities are being 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”) (see “Offshore Gulf of Mexico Exploration Joint Ventures”) are not controlled by the Company and are proportionately consolidated. By agreement, REX, MOE and COE have disproportionate allocations of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.

By agreement, since the Company was the only owner that contributed cash to REX, MOE and COE upon formation of these three ventures, the Company consolidated 100% of the ventures’ net assets and results of operations until the ventures expended all of the Company’s initial cash contributions. Subsequent to that event, the owners’ share in the net assets of the ventures is based on their stated ownership percentages. By agreement, the owners in COE immediately share in the net assets of COE, including the Company’s initial cash contribution, based on their stated ownership percentages. The other owners of REX, MOE and COE who participated in the initial formation of these entities contributed seismic data and related geological and geophysical services to the ventures in exchange for ownership interests.

On September 2, 2005, the Company purchased an additional 9.4% ownership interest in each of REX and COE. Both ownership 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, on the same terms as the Company, 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”) and Contango’s 25% limited partnership interest in Contango Capital Partners, L.P. (“CCPLP”) 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. 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 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 Statement of Financial Accounting Standards 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 Statement of Financial Accounting Standards 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, 2006 and 2005, respectively: (i) risk-free interest rate of 4.5 percent and 4.25 percent; (ii) expected lives of five years; (iii) expected volatility of 40 percent and 26 percent, and (iv) expected dividend yield of zero percent.

During the three months ended March 31, 2006 and 2005, the Company recorded stock-based compensation charges of $229,328 and $97,529 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. Sale of Properties - Discontinued Operations

In December 2004, the Company completed the sale of the majority of its south Texas natural gas and oil interests to Edge Petroleum for $50.0 million. The sale was approved by a majority of the Company’s stockholders at a Special Meeting of Stockholders on December 29, 2004. Approximately 16 billion cubic feet per day equivalent (“Bcfe/d”) of proven reserves were sold having a pre-tax net present value when using a 10% discount rate as of June 30, 2004 of $54.3 million. Pre-tax proceeds after netting adjustments were $40.1 million. Adjustments were made for net revenues that Contango received for production occurring after July 1, 2004, the effective date of sale, up to the post-closing date of March 29, 2005. The Company recognized a gain on sale of $16.3 million for the year ended June 30, 2005. Our sale of assets to Edge Petroleum has been classified as discontinued operations in our financial statements for all periods presented.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In March 2006, the Company completed the sale of its interest in a well in Zapata County, Texas to an independent oil and gas company for approximately $2.0 million. Approximately 227 million cubic feet (“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 $1.1 million for the three and nine months ended March 31, 2006. This sale has been classified as discontinued operations in our financial statements for all periods presented.

4. Properties Held for Sale

On March 24, 2006, the Company’s Board of Directors approved the sale of all of the Company’s onshore producing assets for an aggregate purchase price of $11.5 million. These properties were held by Contango STEP, LP (“STEP”), an indirect wholly-owned subsidiary of the Company, and substantially all of such properties were sold in April 2006. These properties had a net carrying amount of approximately $5.2 million as of March 31, 2006. All STEP producing properties were classified as properties held for sale as of March 31, 2006, and were included in discontinued operations in our financial statements for all periods presented. Approximately $37,000 in depreciation expense was not recorded from March 24, 2006 through March 31, 2006.

In accordance with Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” we classified our properties held for sale as discontinued operations as of March 31, 2006.

The summarized financial results for discontinued operations for each of the periods ended March 31, are as follows:

Operating Results:


	Three Months Ended March 31,						Nine Months Ended March 31,
	2006			2005			2006			2005
Revenues	$	1,555,134		$	774,449		$	4,377,017		$	14,357,236
Operating (expenses) credits *		466,362			178,392			1,266,320			(1,226,890	)
Depreciation expense		(380,000	)		(223,666	)		(966,734	)		(2,259,325	)
Exploration expense		—			(229,119	)		(1,093,139	)		(714,906	)
Gain on sale of discontinued operations		1,058,450			29,358			1,082,048			16,288,294

Gain before income taxes		2,699,946			529,414			4,665,512			26,444,409
Provision for income taxes		(944,981	)		(185,295	)		(1,632,929	)		(9,255,543	)

Gain from discontinued operations, net of income taxes	$	1,754,965		$	344,119		$	3,032,583		$	17,188,866

*	Credits due to severance tax refunds

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 south Texas Queen City formation properties, which were included in the sale of our south Texas natural gas and oil interests to Edge Petroleum, 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

5. 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, 2006								Three Months Ended March 31, 2005
	Income (Loss)			Weighted Average Shares		Per Share			Income (Loss)			Weighted Average Shares		Per Share
Loss from continuing operations including preferred dividends	$	(1,005,543	)	14,865,965		$	(0.07	)	$	(1,521,163	)	13,108,196		$	(0.12	)
Discontinued operations, net of income taxes		1,754,965		14,865,965			0.12			344,119		13,108,196			0.03

Basic Earnings per Share:
Net income (Loss)	$	749,422		14,865,965		$	0.05		$	(1,177,044	)	13,108,196		$	(0.09	)

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

Loss from continuing operations including preferred dividends	$	(1,005,543	)	14,865,965		$	(0.07	)	$	(1,521,163	)	13,108,196		$	(0.12	)
Discontinued operations, net of income taxes		1,754,965		14,865,965			0.12			344,119		13,108,196			0.03

Diluted Earnings per Share:
Net income (Loss)	$	749,422		14,865,965		$	0.05		$	(1,177,044	)	13,108,196		$	(0.09	)

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		$	—		1,098,000		$	4.58
Series C preferred stock (converted during the period)	$	—		—		$	—		$	105,000		1,166,667		$	0.09
Series D preferred stock	$	150,000		833,333		$	0.18			—		—			—

(a) Anti-dilutive.

	Nine Months Ended March 31, 2006								Nine Months Ended March 31, 2005
	Income (Loss)			Weighted Average Shares		Per Share			Income (Loss)			Weighted Average Shares		Per Share
Loss from continuing operations including preferred dividends	$	(2,591,247	)	14,675,586		$	(0.18	)	$	(3,837,632	)	13,030,251		$	(0.30	)
Discontinued operations, net of income taxes		3,032,583		14,675,586			0.21			17,188,866		13,030,251			1.32

Basic Earnings per Share:
Net income	$	441,336		14,675,586		$	0.03		$	13,351,234		13,030,251		$	1.02

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

Loss from continuing operations including preferred dividends	$	(2,591,247	)	14,675,586		$	(0.18	)	$	(3,837,632	)	13,030,251		$	(0.30	)
Discontinued operations, net of income taxes		3,032,583		14,675,586			0.21			17,188,866		13,030,251			1.32

Diluted Earnings per Share:
Net income	$	441,336		14,675,586		$	0.03		$	13,351,234		13,030,251		$	1.02

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		$	—		1,098,000		$	4.58
Series C preferred stock (converted during the period)	$	21,000		1,166,667		$	0.02		$	315,000		1,185,180		$	0.27
Series D preferred stock	$	430,000		791,667		$	0.54			—		—			—

(a)	Anti-dilutive.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

6. 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.

During the quarter ended March 31, 2006, 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. These assets include planned drilling commitments, unevaluated exploration blocks, and proven developed producing (“PDP”) 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. Should Dutch or portions of Liberty not be successful, the Company will be required under successful efforts accounting to expense all or a portion of this allocation in addition to the drilling costs. During the quarter ended March 31, 2006, we wrote off $0.3 million of the purchase price relating to our Main Pass 221 prospect which was a dry hole, and $0.1 million relating to our East Cameron 107 prospect, as a result of the expiration of its lease.

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.

7. 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.

8. Conversion of Series C Cumulative Convertible Preferred Stock into Common Stock

On July 19, 2005, we exercised our mandatory conversion rights pursuant to the terms of our Series C preferred stock, and converted all of the remaining 1,400 shares of our Series C preferred stock issued and outstanding into 1,166,662 shares of common stock. The outstanding shares of the Series C preferred stock had a face value of $7.0 million, and paid a 6.0% per annum quarterly cash dividend.

9. Investment in Freeport LNG

As of March 31, 2006, 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 1.5 billion cubic feet per day (“Bcf/d”) liquefied natural gas (“LNG”) receiving terminal in Freeport, Texas.

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. Contango Venture Capital Corporation

Contango Venture Capital Corporation (“CVCC”), a wholly-owned subsidiary of Contango Oil & Gas Company, owns a 32% membership interest in Contango Capital Partnership Management, LLC (“CCPM”). CCPM was formed by us and other investors to invest in the energy venture capital market with a focus on domestically sourced, environmentally preferred energy technologies and to expose us to opportunities in alternative energy markets.

In January 2005, CCPM formed a venture capital fund, the Contango Capital Partners, L.P. (the “Fund”), for the purpose of investing in alternative energy companies. As of March 31, 2006, the Fund held investments in five portfolio alternative energy companies, Trulite, Inc. Synexus Energy, Inc., Protonex Technology Corp., Jadoo Power Systems, and Moblize. CCPM is the general partner and manager of the Fund. As of March 31, 2006, CVCC, a 25% limited partner of the Fund, has contributed $1.6 million in cash to the Fund.

In July 2005, the Fund invested $0.3 million in its fifth portfolio company, Moblize, along with CTTV Investments LLC, a subsidiary of Chevron Corporation. Moblize develops real time diagnostics and field optimization solutions for the oil and gas industry using open-standards based technologies. Moblize is currently deploying its technology in oil fields near Houston belonging to Chevron U.S.A. Inc.

During the quarter ended March 31, 2006, the Fund invested an additional $0.2 million in Trulite, Inc. Our limited partnership’s cumulative cash investment in the Fund is approximately $2.2 million, bringing our total investment in alternative energy investments, including cumulative mark-to-market adjustments, to approximately $2.9 million. In the future, the Fund may make additional investments in these same alternative energy companies or in other alternative energy companies.

11. Long-Term Debt

The Company’s credit facility with Guaranty Bank, FSB is an unsecured revolving line of credit. Although the Company has no debt outstanding under this credit facility as of March 31, 2006, the revolving line of credit is being maintained and provides for a borrowing capacity of $0.1 million and matures on June 29, 2006. Borrowings will bear interest, at the Company’s option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, the Company pays a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability.

The hydrocarbon borrowing base is subject to semi-annual redetermination based primarily on the value of our proved reserves. The credit facility requires the maintenance of certain ratios, including those related to working capital, funded debt to EBITDAX, and debt service coverage, as defined in the credit agreement. Additionally, the credit agreement contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell assets, pay dividends and reacquire or otherwise acquire or redeem capital stock. Failure to maintain required financial ratios or comply with the credit facility’s covenants can result in a default and acceleration of all indebtedness under the credit facility.

As of March 31, 2006, the Company was in compliance with its financial covenants, ratios and other provisions of its credit facility.

12. Subsequent Events

Term Loan Facility. On April 27, 2006, the Company completed the arrangement of a new three-year $20.0 million secured term loan agreement with The Royal Bank of Scotland (“RBS”). The term loan agreement 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. The

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Company has borrowed the first $10.0 million under the term loan agreement and may borrow the remaining $10.0 million at anytime prior to October 27, 2006. Borrowings under the term loan agreement 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. The term loan agreement requires an arrangement fee of 2%, or $400,000, which was paid upon closing.

The term loan agreement requires the maintenance of certain ratios, including those related to working capital, as defined in the term loan agreement. Additionally, the term loan agreement contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required financial ratios or comply with the term loan agreement’s covenants could result in a default and acceleration of all indebtedness under the term loan agreement. As of May 11, 2006, the Company was in compliance with its financial covenants, ratios and other provisions of the term loan agreement.

Sale of Properties. On April 28, 2006, the Company completed the sale of substantially all of its onshore producing Texas and Alabama natural gas and oil interests for $11.1 million pursuant to a purchase and sale agreement. The sold properties had net reserves of approximately 203 Mbbl of oil and 656 MMcf of gas, or 1.9 Bcfe. The sale of an additional two wells under the same purchase and sale agreement for an aggregate purchase price of approximately $0.4 million remains contingent upon the receipt of third party consents to the transfer of such wells.

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, 2005, 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

•

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

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. As a recent addition to our business, we now operate certain offshore prospects through our wholly-owned subsidiary, Contango Operators, Inc. (“COI”). 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:

Using our capital availability to increase our reward/risk potential on selective prospects. 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 offshore Gulf of Mexico prospects. This represents 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. COI, our wholly-owned subsidiary, will drill and operate 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 and is a new element of our business strategy. Our Liberty prospect was COI’s first exploration well in the Gulf of Mexico and COI plans to drill at least three additional exploration wells in the Gulf of Mexico in 2006. This represents a significant increase in the risk profile of the Company since the Company has never before operated. Our estimated drilling costs could be significantly higher if we encounter difficultly in drilling offshore exploration wells.

Sale of proved properties. From time-to-time as an integral part of our business strategy, we have sold and in the future may sell some or a substantial portion of our proved reserves to capture current value, using the sales proceeds to further our exploration, development, LNG and alternative energy investment activities. Since its inception, the Company has sold over $80.5 million worth of oil and natural gas properties.

In December 2004, we sold producing properties consisting of 39 wells in south Texas, a majority of our natural gas and oil interests, for $50.0 million to Edge Petroleum Corporation. The sale was approved by a majority of the Company’s stockholders at a Special Meeting of Stockholders on December 29, 2004. Approximately 16 Bcfe of proven reserves were sold having a pre-tax net present value when using a 10% discount rate as of June 30, 2004 of $54.3 million. Pre-tax proceeds after netting adjustments were $40.1 million.

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 million cubic feet (“MMcf”) of proven reserves were sold. Pre-tax proceeds after netting adjustments were $2.0 million.

In April 2006, the Company completed the sale of all of its onshore producing Texas and Alabama natural gas and oil interests for $11.1 million pursuant to a purchase and sale agreement. The sold properties had net reserves of approximately 203 Mbbl of oil and 656 MMcf of gas, or 1.9 Bcfe. The sale of an additional two wells under the same purchase and sale agreement for an aggregate purchase price of approximately $0.4 million remains contingent upon the receipt of third party consents to the transfer of such wells.

In accordance with Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” we classified all our property sales as discontinued operations.

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 currently have six employees.

Diversified energy investments. While our core focus is the domestic exploration and production business, we will continue to seek opportunities that may include foreign exploration prospects or investments related to new and developing energy sources such as LNG and alternative energy.

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. In addition, our alliance partners co-invest in prospects that they recommend to us.

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.

As a result of the Company’s intent to focus on developing our Fayetteville Shale play in Arkansas and our offshore Gulf of Mexico prospects, we have elected to discontinue our south Texas drilling program with Ameritex Minerals and Exploration, Ltd. (“Ameritex”) and Coastline Exploration, Inc. (“Coastline”).

Onshore Exploration and Properties

Alta Activities

Escambia County, Alabama

In January 2005, Contango and Alta elected to participate in three exploratory wells in Escambia County, Alabama: the Alta-Blackstone 10-4, the Alta-Blackstone 31-14 and the Alta-Blackstone 10-2.

During the quarter ended September 30, 2005, we drilled our first exploratory well, the Alta-Blackstone 10-4, which has been completed and began producing in February 2006 at a rate of approximately 300 barrels of oil per day. Our net revenue interest in the well is 42.9%.

During the quarter ended December 31, 2005, we successfully drilled a second exploratory well, the Alta-Blackstone 31-14, for which our 75% share of the dry hole costs was approximately $1.1 million. This well has been completed with our share of completion costs estimated at $0.5 million and is currently waiting on a pipeline hook-up.

Also during the quarter ended December 31, 2005, we drilled a third exploratory well, the Alta Blackstone 10-2, which was determined to be a dry hole and is in the process of being converted into a salt water disposal well for future use. Our 75% share of dry hole costs was $1.1 million.

These three wells were sold in April 2006, as part of the $11.1 million south Texas and Alabama property sale.

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 11, 2006, we and our partners have acquired or received commitments on approximately 42,000 net mineral acres at a cost of approximately $10.4 million. Our 70% share of the acquisition costs is approximately $7.3 million.

The Arkansas Oil & Gas Commission has now approved eleven 640-acre drilling units in Conway County, Arkansas that we estimate will allow our partnership to drill and operate approximately 100 horizontal wells. The horizontal wells are estimated to cost approximately $1.0 million each, net to the Company. We estimate our net revenue interest in these wells will average approximately 45%.

In March, we spudded the first of three wells to be operated by our alliance partner, Alta: the Alta-Beck #1-32H, the Alta-Briggler #1-31H and the Alta-Thines #1-30H, with working interests of 38.65%, 63.60%, and 34.87%, respectively. We logged 240 feet of Fayetteville Shale in the Alta-Beck #1-32H and are currently drilling horizontally. Depending on our continuing drilling results, we will attempt to move a second rig to this play by this fall, and a third by the end of the year.

In addition, as of May 11, 2006, we have been integrated into 35 wells located in the Arkansas Fayetteville Shale that are being operated by a third party independent oil and gas exploration company. Three of these wells are vertical natural gas wells that are currently producing. Four more are producing horizontal wells. The remaining 28 horizontal wells are either being drilled or are expected to be drilled over the next three months with our net share of the total drilling costs estimated at $3.1 million. Our average working interest in these integrated wells thus far is 6.3%.

Offshore Gulf of Mexico Exploration Joint Ventures

Contango directly and through affiliated companies conducts exploration activities in the Gulf of Mexico. As of May 11, 2006, Contango and its affiliates have interests in 61 offshore leases. On March 15, 2006, REX and COE were the apparent high bidders on 12 and 4 lease blocks, respectively, at the Central Gulf of Mexico Lease Sale # 198. To date, REX has been awarded 6 of the 12 lease blocks and COE has been awarded all 4 lease blocks. The sale covered areas in the central part of the Outer Continental Shelf, offshore from the Louisiana coastline. If the remaining 6 lease blocks are awarded, Contango and its affiliates will have interests in 67 offshore leases. See “Offshore Properties” below for additional information on our offshore properties.

As of March 31, 2006, 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 4,400 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 March 31, 2006, Contango had approximately $11.4 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 2,030 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 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, 2006, Contango had approximately $15.7 million invested in COE. The two other members of COE are JEX, its managing member, and a privately held investment company and as of March 31, 2006, COE had invested approximately $13.8 million to acquire and reprocess 1,775 blocks of 3-D seismic data and to acquire leases in the Gulf of Mexico. All leases are subject to a 3.3% overriding royalty interest 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. We believe the well will be on-stream by September 2006, with an estimated initial 8/8ths equivalent production rate of 7-10 Mmcfe/d.

Magnolia Offshore Exploration LLC. As of March 31, 2006, Contango had approximately $0.9 million invested in MOE. Contango purchased a 50.0% working interest in MOE in October 2001. JEX is the only other member of MOE and acts as the managing member, deciding which prospects MOE may acquire, develop, and exploit. MOE owns license rights to 3-D seismic data covering 600 blocks of the Gulf of Mexico continental shelf. All leases are subject to a 3.3% overriding royalty interest in favor of the JEX prospect generation team. See “Offshore Properties” below for additional information on MOE’s offshore properties.

Current Activities. In August 2005, Hurricane Katrina struck the Gulf of Mexico and the Gulf Coast of the United States, and in September 2005, Hurricane Rita struck the same region. The Company does not at present operate or own any production platforms or pipeline facilities in the Gulf of Mexico. However, the Company does have non-operating working interests in three offshore blocks: Ship Shoal 358, Eugene Island 113-B and Eugene Island 76 and depends on third-party operators for the operation and maintenance of these production platforms. In the aftermath of the hurricanes, the Ship Shoal 358 and the Eugene Island 113-B platforms sustained damage and have now been repaired. Eugene Island-113B resumed production in April 2006 at a rate of 16 MMcfe/d, while the Ship Shoal 358 well resumed production in April 2006 at a rate of 5 MMcfe/d. Contango’s net revenue interest in these wells is 3.1% and 5.8%, respectively. The Company was not responsible for any of the capital costs required to repair the damaged platforms, pipelines, or other damaged facilities related to these wells. The Company was not materially impacted by the temporary loss of production from these two wells. Eugene Island 76, a REX prospect, was successfully tested in 2005 and began producing in January 2006. The well is currently producing at approximately 12 MMcfe/d. REX owns an overriding royalty interest of 5% until payout, after which REX has the option to elect an 8.33% overriding royalty interest or a 25% working interest upon payout.

Throughout the remainder of the year, we will continue to focus on developing our three offshore prospects, Eugene Island 10, High Island A-279 and West Delta 43, which we will operate through our wholly owned subsidiary, Contango Operators, Inc. Our capital expenditure budget calls for us to invest approximately $4.0 million in estimated dry hole costs in the drilling of Eugene Island 10, approximately $3.0 million in estimated dry hole costs in the drilling of High Island A-279, approximately $3.5 million in estimated dry hole costs in the drilling of West Delta 43. In the event we have exploration success at any of our offshore prospects, our capital budget will be significantly increased as we will incur additional costs to complete these wells and pay for production facilities.

In July 2005, REX acquired State Lease No. 18640, a 474.5 acre tract located off the coast of Louisiana covering a portion of offshore blocks Eugene Island 10 and 11 and is located approximately three miles offshore. The purchase price for the acreage was approximately $0.7 million. In January 2006, REX acquired for a purchase price of approximately $0.1 million, State Lease No. 18860, a 335.91 acre tract located in proximity to State Lease No. 18640.

In March 2006, REX was awarded the following six lease blocks from the Central Gulf of Mexico Lease Sale # 198 for an aggregate purchase price of approximately $0.9 million: South Marsh Island 57, South Marsh Island 59, South Marsh Island 75, South Marsh Island 282, Ship Shoal 14 and Ship Shoal 25. The blocks are complimentary to our existing Ship Shoal and South Marsh Island prospects.

In April 2006, COE was awarded the following two lease blocks from the Central Gulf of Mexico Lease Sale # 198 for an aggregate purchase price of approximately $1.4 million: Grand Isle Block 70 and Ship Shoal Block 263. In May 2006, COE was awarded the Viosca Knoll 119 and 383 lease blocks for an aggregate purchase price of approximately $0.4 million.

REX and COE have farmed out the following lease blocks: Main Pass 221, East Breaks 369/370, and Vermillion 154. Main Pass 221 was drilled and was determined to be a dry hole. East Breaks 369 and East Breaks 370 are expected to spud in 2007. COE will receive a 4.3% overriding royalty interest before project payout and a 7.2% overriding royalty interest after project payout on the East Breaks 369/370 prospects. Vermillion 154 has been farmed out, and the operator expects to drill an exploratory well prior to July 2008. During the last quarter, 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. West Delta 36 was farmed out during the quarter, and is expected to be drilled in August 2006.

Record title interests in the Vermilion 73 and South Marsh Island 247 leases have been assigned to a common third party. A timetable for drilling the two prospects has not yet been established. Under the farm-out agreement, REX reserves a 5.0% overriding royalty interest before payout in both prospects. In the Vermilion 73 prospect, REX also has the option after payout to maintain its 5.0% overriding royalty interest or receive a 25.0% working interest in the prospect.

The Minerals Management Service (“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 well depths greater than 18,000 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.

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 will operate and acquire 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 expects to take working interests in these prospects under the same arms-length terms offered to third party industry participants. COI may also operate and acquire significant working interests in offshore exploration and development opportunities under farm-in agreements with third parties.

Current Activities. The Company had an offshore exploration discovery at its Grand Isle 72 (“Liberty”) prospect on March 2, 2006. To date, the Company has invested approximately $7.2 million to drill and complete this well. We estimate an additional $3.8 million, net to our interest, will be required to build production and pipeline facilities to commence production. We believe the well will be on-stream by September 2006, with an estimated initial 8/8ths equivalent production rate of 7-10 MMcfe/d. The net revenue interests to COI and COE after well completion is estimated to be 20% and 40%, respectively.

COI expects to begin drilling its Eugene Island 10 (“Dutch”) prospect in July 2006. COI will pay a 35% working interest through completion of the well and will pay a 18.3% working interest thereafter. After a back-in by the farmor of the block, this working interest will be reduced to 13.75%. REX will pay a 15% working interest through completion and will have a 65% working interest thereafter, reduced to 48.75% after the farmor’s back-in. COI’s share of the dry hole costs is estimated to be $4.0 million. The prospect is being drilled under a fixed turn-key drilling contract. The net revenue interests to COI and REX, should the well be successful, and after the farmor’s back-in working interest is estimated to be 11% and 39%, respectively.

In the event Dutch is successful the Company will have the opportunity to drill additional wells but may be required to pay higher costs for rigs and related marine services as a result of the demand for such equipment related to generally strong commodity prices and the demand for offshore services.

COI plans to drill and operate two additional offshore prospects: a REX-generated prospect in West Delta 43 (“Skip Jack”) and a farm-in at High Island A-279 (“Juice”). Our share of dry hole costs for Skip Jack and Juice are estimated at $3.5 million and $3.0 million, respectively.

In High Island A-279, COI will pay a 46.7% working interest before casing point and a 37.5% working interest at casing point and thereafter. COI expects to begin drilling High Island A-279 in June 2006. In West Delta 43, COI will pay a 50% working interest before first production and will have a 35% working interest thereafter. REX will be fully carried in the costs of drilling and completing the well and will also be carried in the costs of constructing production and pipeline facilities. REX will assume a 30% working interest thereafter. COI expects to begin drilling West Delta 43 in June 2006.

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 11, 200


Area/Block	WI		NRI		Status
Contango Operators, Inc:
Eugene Island 113B	0	%	1.7	%	Producing

Republic Exploration LLC:
Eugene Island 113B	0	%	3.3	%	Producing
Eugene Island 76	(1	)	5.0	%	Producing

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

(1)	REX has a 5% of 8/8 overriding royalty interest (“ORRI”) in the lease before payout. At payout, REX may elect to either (i) escalate its ORRI in the lease from 5% to 8-1/3% of 8/8 or (ii) convert the 5% ORRI to a 25% working interest (“WI”).

Farmed-Out Properties. The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico which have been farmed out as of May 11, 2006:


Area/Block	WI		NRI		Status
Republic Exploration LLC:
Vermilion 154	(2	)	(2	)	Drilling expected by summer 2008
West Delta 36	(3	)	(3	)	Drilling expected by August 2006

Contango Offshore Exploration LLC:
Main Pass 221	(4	)	(4	)	Determined to be dry
East Breaks 369	(5	)	(5	)	Drilling expected by Sept 2007
East Breaks 370	(5	)	(5	)	Drilling expected by Sept 2008
Vermilion 154	(2	)	(2	)	Drilling expected by summer 2008

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

(3)	REX will retain a 3.67% ORRI BPO. Upon payout REX will either increase to either 5% ORRI or convert to a 25% WI APO.

(4)	COE has a 5% of 8/8 ORRI before payout. Upon payout, COE’s ORRI will escalate to 7.2% of 8/8.

(5)	COE will receive a 4.27% ORRI before project payout and a 7.27% ORRI after project payout.

Farmed-In Properties. The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico which have been farmed in as of May 11, 2006:


Area/Block	WI		NRI		Status
Contango Operators, Inc:
Eugene Island 10	(6	)	(6	)	Drilling expected by July 2006
High Island A-279	(7	)	(7	)	Drilling expected by June 2006

Republic Exploration LLC:
Eugene Island 10	(6	)	(6	)	Drilling expected by June 2006

(6)	COI has a 35% WI through completion, an 18.3% WI after completion, and a 13.75% WI following a farmor back-in of 25%. COI will be awarded the lease on a produce-to-earn basis. REX has a 15% WI through completion, a 65.0% WI after completion, and a 48.75% WI following a farmor back-in of 25%.

(7)	COI has a 46.7% WI before casing point and a 37.5% WI at casing point and thereafter.

Leases. The following table sets forth the interests owned by Contango and related entities in the Gulf of Mexico as of May 11, 2006:


Area/Block	WI		Lease Date
Contango Operators, Inc.:
Vermilion 190	37.5	%	(10)
Vermilion 193	37.5	%	(10)
Vermilion 194	37.5	%	(10)
West Delta 77	37.5	%	(10)
Ship Shoal 14	37.5	%	(11)
Ship Shoal 25	37.5	%	(11)
South Marsh Island 9	37.5	%	(10)
South Marsh Island 57	37.5	%	(11)
South Marsh Island 59	37.5	%	(11)
South Marsh Island 75	37.5	%	(11)
South Marsh Island 282	37.5	%	(11)
South Marsh Island 287	37.5	%	(10)

Area/Block	WI		Lease Date
Republic Exploration LLC:
West Delta 36	100.0	%	May-02
Vermilion 73	(8	)	Jul-02
West Cameron 174	100.0	%	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
Vermilion 190	50.0	%	(10)
Vermilion 193	50.0	%	(10)
Vermilion 194	50.0	%	(10)
West Cameron 133	100.0	%	Jun-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	100.0	%	May-04
West Delta 77	50.0	%	(10)
Ship Shoal 14	50.0	%	(11)
Ship Shoal 25	50.0	%	(11)


Ship Shoal 220	50.0	%	Jun-04
South Timbalier 240	50.0	%	Jun-04
South Marsh Island 9	50.0	%	(10)
South Marsh Island 57	50.0	%	(11)
South Marsh Island 59	50.0	%	(11)
South Marsh Island 75	50.0	%	(11)
South Marsh Island 247	(9	)	Jul-04
South Marsh Island 282	50.0	%	(11)
South Marsh Island 287	50.0	%	(10)
Vermilion 130	100.0	%	Jul-04
West Cameron 80	100.0	%	Jun-04
West Cameron 167	100.0	%	Jun-04
Eugene Island 168	50.0	%	Jun-05
West Cameron 107	100.0	%	May-05
S-L 18640 (LA)	100.0	%	Jul-05
S-L 18860 (LA)	100.0	%	Jan-06

Area/Block	WI		Lease Date
Contango Offshore Exploration LLC:
Vermilion 231	100.0	%	May-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 70	75.0	%	(11)
Grand Isle 72	50.0	%	May-04
Grand Isle 73	50.0	%	May-04
Ship Shoal 220	50.0	%	Jun-04
Ship Shoal 263	75.0	%	(11)
South Timbalier 240	50.0	%	Jun-04
Viosca Knoll 75	33.3	%	May-02
Viosca Knoll 167	100.0	%	May-03
Viosca Knoll 161	33.3	%	Jul-03
Viosca Knoll 118	33.3	%	Jun-04
Viosca Knoll 119	50.0	%	(11)
Viosca Knoll 383	100.0	%	(11)
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

Area/Block	WI		Lease Date
Magnolia Offshore Exploration LLC:
Ship Shoal 155	100.0	%	May-02
Viosca Knoll 75	16.7	%	May-02
Viosca Knoll 161	16.7	%	Jul-03
Viosca Knoll 118	16.7	%	Jun-04
Viosca Knoll 211	100.0	%	Jul-04

(8)	Record title interest in lease has been assigned to a third party. REX has a 5% of 8/8 ORRI in the lease before payout. At payout, REX may elect to either (i) maintain its 5% ORRI in the lease or (ii) convert the 5% ORRI to a 25% WI.

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

(10)	Company was apparent high bidder. Lease block has not yet been awarded.

(11)	Lease block has been awarded but not yet received, therefore lease date has not been determined.

Freeport LNG Development, L.P.

In July 2004, Freeport LNG finalized its transaction with ConocoPhillips for the financing, construction and use of the LNG receiving terminal in Freeport, Texas. ConocoPhillips executed a terminal use agreement for 1.0 Bcf/d of regasification capacity, purchased a 50% interest in the general partner managing the Freeport LNG project and agreed to provide construction funding to the venture. This construction funding will be non-recourse to Contango. Dow Chemical has also executed a terminal use agreement for regasification capacity of 500 million cubic feet per day (“MMcf/d”) and, in an unrelated transaction with another limited partner, has purchased a 15% limited partnership interest in Freeport LNG. Freeport LNG is responsible for the commercial activities of the partnership, while the general partners, Freeport LNG and ConocoPhillips manage the entire project and ConocoPhillips, under a construction advisory and management agreement, is managing the construction of the facility.

In January 2005, Freeport LNG received its authorization to commence construction of the first phase (“Phase I”) of its terminal from the Federal Energy Regulatory Commission (the “FERC”) and construction of the 1.5 Bcf/d facility commenced on January 17, 2005. The terminal’s Phase I capacity has been sold to ConocoPhillips (1.0 Bcf/d) and Dow Chemical Company (0.5 Bcf/d) and construction is expected to be completed by January 2008. The engineering, procurement and construction contractor is a consortium of Technip USA, Zachry Construction of San Antonio, and Saipem SpA of Italy.

A majority of the Freeport LNG financing for Phase I is being provided by ConocoPhillips through a construction loan, with debt service being provided by the terminal use agreement with ConocoPhillips. Additional financing has been obtained through a $383.0 million private placement note issuance by Freeport LNG which closed on December 19, 2005. The funds from the notes will be used to fund the balance of the Phase I construction of Freeport LNG’s liquefied natural gas regasification terminal, which will have a send-out capacity of 1.75Bcf/d. The funds will also be used to fund the development of an integrated natural gas storage salt cavern and a portion of the cost of an expansion of the LNG terminal (“Phase II”). The notes are being secured primarily by payments obligated under the terminal use agreement with Dow Chemical.

Phase II expansion of the LNG terminal may include a second LNG unloading dock, additional send-out and additional storage capacity. Part of the Phase II capacity has been sold to MC Global Gas Corporation, a wholly-owned subsidiary of Mitsubishi Corporation and ConocoPhillips under long-term contracts. Expansion applications have been submitted to the FERC and other government agencies and assuming approval of these applications in mid-2006, Phase II capacity is expected to be available in 2009. Future expansions of the terminal which were included in the current applications are planned and will be constructed as additional capacity is sold.

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

In June 2004, our wholly-owned subsidiary, Contango Venture Capital Corporation (“CVCC”), acquired a 32% membership interest in Contango Capital Partnership Management, LLC (“CCPM”). CCPM was formed by us and other investors to invest in the energy venture capital market with a focus on domestically sourced, environmentally preferred energy technologies and to expose us to opportunities in alternative energy markets. Our initial cash contribution of $0.5 million was used to fund the initial overhead for the sourcing and management of an energy venture capital fund to be managed by CCPM. We hold two of seven seats on the board of directors of CCPM.

In July 2004, CVCC invested $0.1 million in exchange for a limited partnership interest in Trulite Energy Partners, L.P. Trulite Energy Partners, L.P. was an investor and principal shareholder of Trulite Inc (“Trulite”). Trulite develops lightweight hydrogen generators for fuel cell systems. In addition, in return for management services rendered by CCPM, Trulite common stock was issued to CCPM members, including CVCC, according to their membership interests in CCPM. Synexus Energy, Inc. (“Synexus”) also paid CCPM members, including CVCC, in Synexus common stock in return for management services rendered by CCPM.

In January 2005, Contango Capital Partners, L.P. was formed for the purpose of investing in the energy venture capital market and formed the Contango Capital Partners Fund, L.P. (the “Fund”). Trulite Energy Partners, L.P. was dissolved and its limited partnership interests were converted into preferred equity shares of Trulite.

In January 2005, CVCC and CCPM members contributed common shares of Trulite and Synexus to the Fund. CVCC also committed to contribute an additional $1.5 million in cash to the Fund. In exchange for these contributions of stock and cash, CVCC received a 25% limited partnership interest in the Fund. The limited partners of Trulite Energy Partners, L.P., including CVCC, contributed preferred equity shares of Trulite and Synexus and also made cash commitments to the Fund in exchange for limited partnership interests in the Fund.

On January 31, 2005, the Fund was closed to new investment with a total capitalization of $8.2 million in the form of contributed stock, cash, and future cash commitments. CCPM is the general partner and manager of the Fund.

CVCC’s 25% limited partnership interest in the Fund, as well other limited partners’ interests, were determined by CCPM based on fair market valuations of the portfolio companies’ shares of stock and cash commitments contributed to the Fund and made available at the time of the Fund’s close. The mark-to-market adjustments made by CCPM of each portfolio company were based on an analysis of comparable public and private companies, third party cash contributions, and intervening value enhancement. These mark-to-market adjustments were made to take into consideration value enhancements that had occurred during the period leading up to the Fund’s close, and were warranted based on the portfolio companies’ enhanced commercial viability.

As of January 31, 2005, the date the Fund was closed to new investment, the Fund owned equity interests in four portfolio alternative energy companies, including Trulite, Synexus, Protonex Technology Corporation, and Jadoo Power Systems. Synexus is a portable and stationary fuel cell integrator developing technology with a lightweight fuel cell stack that will create both portable and stationary power solutions for customers. In April 2006, Trulite and Synexus merged. Protonex Technology Corp. 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. Jadoo Power Systems develops high energy density power products for the law enforcement, military and electronic news gathering applications.

During the fiscal year ended June 30, 2005, the Company recorded an approximate $0.75 million increase to our investment resulting primarily from unrealized gains of the Fund as a result of a mark-to-market adjustment that was made due to the increase in the value of our alternative energy investments, bringing our total investment, which includes the mark-to-market adjustment, to $2.3 million.

During the quarter ended December 31, 2005, the Fund invested an additional $0.5 million in Synexus and an additional $0.3 million in Moblize.

During the quarter ended March 31, 2006, the Fund invested an additional $0.2 million Trulite. Our limited partnership’s cumulative cash investment in the Fund is approximately $2.2 million, bringing our total investment in alternative energy investments, including cumulative mark-to-market adjustments, as of March 31, 2006, to approximately $2.9 million. In April 2006, the Fund invested an additional $0.6 million in Trulite.

Summary of Critical Accounting Policies

In accordance with Statement of Financial Accounting Standards No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” the Company classified its property sale to Edge Petroleum, effective July 1, 2004, and its property sale to an independent oil and gas company effective February 1, 2006, as discontinued operations. Also, as of March 31, 2006, the Company held some producing south Texas and Alabama assets which were also classified as discontinued operations. An integral 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.

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”) (see “Offshore Gulf of Mexico Exploration Joint Ventures”), each as of March 31, 2006, are not controlled by the Company and are proportionately consolidated. By agreement, REX, MOE and COE have disproportionate allocations of their profits and losses among the owners. Accordingly, the Company determines its income or losses from the ventures based on a hypothetical liquidation determination of how increases or decreases in the book value of the ventures’ net assets will ultimately affect the cash payments to the Company in the event of dissolution.

By agreement, since the Company was the only owner that contributed cash to REX, MOE and COE upon formation of these three ventures, the Company consolidated 100% of the ventures’ net assets and results of operations until the ventures expended all of the Company’s initial cash contributions. Subsequent to that event, the owners’ share in the net assets of the ventures is based on their stated ownership percentages. By agreement, the owners in COE immediately share in the net assets of COE, including the Company’s initial cash contribution, based on their stated ownership percentages. The other owners of REX, MOE and COE who participated in the initial formation contributed seismic data and related geological and geophysical services to the ventures.

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.

Stock-Based Compensation. Effective July 1, 2001, the Company adopted the fair value based method prescribed in Statement of Financial Accounting Standards 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 Statement of Financial Accounting Standards 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 deduction 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, 2006 and 2005, respectively: (i) risk-free interest rate of 4.5 percent and 4.25 percent; (ii) expected lives of five years; (iii) expected volatility of 40 percent and 26 percent, and (iv) expected dividend yield of zero percent.

During the three months ended March 31, 2006 and 2005, the Company recorded stock-based compensation charges of $229,328 and $97,529, respectively, to general and administrative expense.

MD&A Summary Data

The table below sets forth revenue, expense and production data for both continuing and discontinued operations for the three and nine months ended March 31, 2006 and 2005.


	Three Months Ended March 31,								Nine Months Ended March 31,
	2006			2005			Change		2006			2005		Change
Revenues:		($000)								($000)
Natural gas and oil sales	$	1,678		$	1,031		63	%	$	4,692		$	14,988	-69	%

Total revenues	$	1,678		$	1,031		63	%	$	4,692		$	14,988	-69	%

Production:
Natural gas (million cubic feet)		116			120		-3	%		342			2,030	-83	%
Oil and condensate (thousand barrels)		13			5		160	%		28			44	-36	%
Total (million cubic feet equivalent)		194			150		29	%		510			2,294	-78	%
Natural gas (thousand cubic feet per day)		1,289			1,333		-3	%		1,248			7,409	-83	%
Oil and condensate (barrels per day)		144			56		157	%		102			161	-37	%
Total (thousand cubic feet per day equivalent)		2,153			1,669		29	%		1,860			8,375	-78	%
Average Sales Price:
Natural gas (per thousand cubic feet)	$	8.00		$	6.32		27	%	$	9.14		$	6.40	43	%
Oil and condensate (per barrel)	$	58.17		$	50.68		15	%	$	56.89		$	45.35	25	%
Operating (income) expenses	$	(461	)	$	(173	)	166	%	$	(1,278	)	$	1,270	-201	%
Exploration expenses	$	152		$	1,970		-92	%	$	2,071		$	3,703	-44	%
Depreciation, depletion and amortization	$	392		$	323		21	%	$	1,065		$	2,526	-58	%
Impairment of natural gas and oil properties	$	420		$	125		236	%	$	420		$	237	77	%
General and administrative expenses	$	1,062		$	621		71	%	$	3,083		$	2,520	22	%
Interest expense	$	—		$	—		*		$	—		$	71	*
Interest income	$	166		$	168		-1	%	$	565		$	202	180	%
Gain on sale of assets and other	$	1,040		$	17		*		$	1,305		$	16,189	*

*	not meaningful

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

Natural Gas and Oil Sales. We reported revenues of approximately $1.7 million for the three months ended March 31, 2006, up from approximately $1.0 million reported for the three months ended March 31, 2005. The increase in revenue was primarily the result of an increase in crude oil & natural gas prices and an increase in our oil production from an Alabama well that began producing during the period.

For the three months ended March 31, 2006, prices for natural gas and oil were $8.00 per Mcf and $58.17 per barrel, compared to $6.32 per Mcf and $50.68 per barrel for the three months ended March 31, 2005.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the three months ended March 31, 2006 was approximately 1,289 Mcf/d of natural gas, down from approximately 1,333 Mcf/d of natural gas for the three months ended March 31, 2005. Net oil production for the comparable periods increased from 56 barrels of oil per day to 144 barrels of oil per day. The decrease in natural gas and increase in oil

production was principally attributable to normal production declines in our existing south Texas properties and added oil production from new reserves and production from Alabama properties.

Operating Expenses. Lease operating expenses for the three months ended March 31, 2006 were $194,878. We received a $655,729 credit for severance taxes for the three months ended March 31, 2006. Total operating expenses for the three months ended March 31, 2005 were $23,050. We received a $195,537 credit for severance taxes for the three months ended March 31, 2005. The Railroad Commission of Texas has extended a natural gas incentive allowing for severance tax reduction on tight sand and gas wells. As a result, some of our south Texas Queen City formation properties are eligible for severance tax reduction. The $655,729 and $195,537 credit for severance taxes for three months ended March 31, 2006 and 2005, respectively, were attributable to previously paid severance taxes from our south Texas properties which we sold in December 2004 to Edge Petroleum.

Exploration Expense. We reported $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 to drill our Alta-Blackstone 10-2 well in Alabama during the period and $0.1 million was attributable to the cost of various geological and geophysical activities. We reported approximately $2.0 million of exploration expenses for the three months ended March 31, 2005. Of this amount, approximately $0.4 million was attributable to the cost to acquire and reprocess 3-D seismic data both onshore and offshore in the Gulf of Mexico, $0.2 million was attributable to the costs of delay rentals, and $1.4 million was related to unsuccessful wells drilled in south Texas during the period.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended March 31, 2006 was approximately $0.4 million. For the three months ended March 31, 2005, we recorded approximately $0.3 million of depreciation, depletion and amortization. The approximately $0.1 million increase is primarily the result of increased oil production from an Alabama well.

Impairment of Natural Gas and Oil Properties. Impairment expenses for the three months ended March 31, 2006 was approximately $0.4 million. These related to impairment of offshore properties held by REX and COE, and 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. We reported an impairment of natural gas and oil properties of approximately $0.1 million for the three months ended March 31, 2005. This was attributable to a write-down of costs associated with offshore lease properties owned by our subsidiary, MOE, of which Contango owns 50%.

General and Administrative Expenses. General and administrative expenses for the three months ended March 31, 2006 and the three months ended March 31, 2005 were approximately $1.0 million and $0.6 million respectively.

Major components of general and administrative expenses for the three months ended March 31, 2006 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 costs, and $0.2 million related to the cost of expensing stock options.

Major components of general and administrative expenses for the three months ended March 31, 2005 included approximately $0.1 million in salaries and benefits, $0.2 million of office administration and other. Also included in total general and administrative expenses for the three months ended March 31, 2005 was approximately $0.1 million related to the cost of expensing stock options.

Interest Income. We reported interest income of $165,946 for the three months ended March 31, 2006. This compares to the $168,466 of interest income reported for the three months ended March 31, 2005. The slight decrease is due to the lower average level of cash and cash equivalents and short term investments, each offset by higher interest rates.

Gain (Loss) on Sale of Assets and Other. We reported a pre-tax gain on sale of assets and other of $1.0 million for the three months ended March 31, 2006, representing a gain related to the sale of our interest in a well in Zapata County, Texas for approximately $2.0 million. We reported gain on sale of assets and other of approximately $17,012 for the three months ended March 31, 2005.

Nine Months Ended March 31, 2006 Compared to Nine Months Ended March 31, 2005

Natural Gas and Oil Sales. We reported natural gas and oil sales of approximately $4.7 million for the nine months ended March 31, 2006, down from approximately $15.0 million reported for the nine months ended March 31, 2005. The decrease in revenue was primarily the result of the sale of our south Texas natural gas and oil interests to Edge Petroleum, completed in December 2004. The $4.7 million of revenue for the nine months ended March 31, 2006 reflects production added from new reserves and production from properties that were not included in the sale to Edge Petroleum, but were subsequently sold in March and April 2006.

Natural Gas and Oil Production and Average Sales Prices. Our net natural gas production for the nine months ended March 31, 2006 was approximately 1,248 Mcf/d of natural gas, down from approximately 7,409 Mcf/d of natural gas for the nine months ended March 31, 2005. Net oil production for the comparable periods decreased from 161 barrels of oil per day to 102 barrels of oil per day. The decrease in natural gas and oil production was primarily the result of the sale of our south Texas natural gas and oil interests to Edge Petroleum. For the nine months ended March 31, 2006, prices for natural gas and oil were $9.14 per Mcf and $56.89 per barrel, compared to $6.40 per Mcf and $45.35 per barrel for the nine months ended March 31, 2005.

Operating Expenses. Lease operating expenses for the nine months ended March 31, 2006 were $0.5 million. We received a $1.8 million credit for severance taxes for such period. Total operating expenses for the nine months ended March 31, 2005 were $1.3 million. The Railroad Commission of Texas has extended a natural gas incentive allowing for severance tax reduction on tight sand and gas wells. As a result, some of our south Texas Queen City formation properties are eligible for severance tax reduction. The $1.8 million credit for severance taxes for the nine months ended March 31, 2006 was attributable to previously paid severance taxes from our south Texas properties which we sold in December 2004 to Edge Petroleum.

Exploration Expense. We reported $2.0 million of exploration expenses for the nine months ended March 31, 2006. Of this amount, approximately $1.8 million was related to unsuccessful wells drilled in south Texas and Alabama during the period and $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.

We reported approximately $3.7 million of exploration expenses for the nine months ended March 31, 2005. Of this amount, approximately $1.4 million was attributable to the cost to acquire and reprocess 3-D seismic data both onshore and offshore in the Gulf of Mexico, $0.2 million was spent on various other geological and geophysical activities, and $2.1 million was related to unsuccessful wells drilled in south Texas during the period.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the nine months ended March 31, 2006 was approximately $1.1 million. For the nine months ended March 31, 2005, we recorded approximately $2.5 million of depreciation, depletion and amortization. The decrease in depreciation, depletion and amortization was primarily the result of the sale of our south Texas properties to Edge Petroleum.

Impairment of Natural Gas and Oil Properties. Impairment expenses for the nine months ended March 31, 2006 were approximately $0.4 million. These related to impairment of offshore properties held by REX and COE, and 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. We reported an impairment of natural gas and oil properties of approximately $0.2 million for the nine months ended March 31, 2005. This was attributable in part to a $0.1 million write-down of costs associated with offshore lease properties owned by our partially owned subsidiary MOE, of which Contango owns 50%. The remaining $0.1 million was attributable to a write-down of costs associated with a small Barnett Shale exploratory play undertaken during the summer of 2003 that had only marginal success.

General and Administrative Expenses. General and administrative expenses for the nine months ended March 31, 2006 were approximately $3.1 million, up from $2.5 million for the nine months ended March 31, 2005.

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, $0.7 million in office administration expenses, $0.2 million in insurance costs, and $0.6 million related to the cost of expensing stock options.

Major components of general and administrative expenses for the nine months ended March 31, 2005 included approximately $1.0 million in salaries and benefits (including approximately $0.5 million of bonus accrual), $0.3 million in legal and professional fees, $0.7 million in office administration expenses, $0.2 million in insurance costs and $0.3 million related to the cost of expensing stock options.

Interest Income. We reported interest income of $0.6 million for the nine months ended March 31, 2006. This compares to the $0.2 million of interest income reported for the nine months ended March 31, 2005. The increase is due to the higher average level of cash and cash equivalents, and short term investments.

Gain (Loss) on Sale of Assets and Other. We reported a gain on sale of assets and other of $1.3 million for the nine months ended March 31, 2006, representing $0.2 million in other income recognized by our partially-owned subsidiary, COE, and a $1.1 million gain from the sale of our interest in a well in Zapata County, Texas for approximately $2.0 million.

We reported other income of approximately $16.2 million for the nine months ended March 31, 2005 which represented a $16.3 million gain on the sale of our south Texas natural gas and oil interests, offset by approximately $0.1 million in operating losses related to our alternative energy investments.

Production, Prices, Operating Expenses, and Other


	Three Months Ended March 31,						Nine Months Ended March 31,
	2006			2005			2006			2005
	(Dollar amounts in 000s, except average sales price and per Mcfe amounts)						(Dollar amounts in 000s, except average sales price and per Mcfe amounts)
Production Data:
Natural gas (million cubic feet)		116			120			342			2,030
Oil and condensate (thousand barrels)		13			5			28			44
Total (million cubic feet equivalent)		194			150			510			2,294
Natural gas (thousand cubic feet per day)		1,289			1,333			1,248			7,409
Oil and condensate (barrels per day)		144			56			102			161
Total (thousand cubic feet equivalent per day)		2,153			1,669			1,860			8,375
Average sales price:
Natural gas (per thousand cubic feet)	$	8.00		$	6.32		$	9.14		$	6.40
Oil and condensate (per barrel)	$	58.17		$	50.68		$	56.89		$	45.35
Selected data per Mcfe:
Severance taxes	$	(2.89	)	$	(1.28	)	$	(2.89	)	$	(0.18	)
Lease operating expenses	$	0.51		$	0.15		$	0.37		$	0.74
General and administrative expenses	$	5.49		$	4.08		$	6.08		$	1.10
Depreciation, depletion and amortization of natural gas and oil properties	$	1.96		$	2.06		$	1.99		$	1.07
EBITDAX (1)	$	2,117		$	600		$	4,192		$	27,386

(1)

EBITDAX represents earnings before interest, income taxes, depreciation, depletion and amortization, impairment expenses, exploration expenses, including gain (loss) from hedging activities, and sale of assets and other. We have reported EBITDAX because we believe EBITDAX is a measure commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. We believe EBITDAX assists investors in comparing a company’s performance on a consistent basis without regard to depreciation, depletion and amortization, impairment of natural gas and oil properties and exploration expenses, which can vary significantly depending upon accounting methods. EBITDAX is not a calculation based on U.S. generally accepted accounting principles and should not be considered an alternative to net income (loss) in measuring our performance or used as an exclusive measure of cash flow because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions and other sources and uses of cash, which are disclosed in our statements of cash flows. Investors should carefully consider the specific items included in our computation of EBITDAX. While we have disclosed our EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, investors should be cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service, preferred stock dividends and other commitments.

A reconciliation of EBITDAX to loss from continuing operations and operating results for discontinued operations for the periods indicated is presented below.


	Three Months Ended March 31,						Nine Months Ended March 31,
	2006			2005			2006			2005
	(Dollar amounts in 000s)						(Dollar amounts in 000s)
Reconciliation of EBITDAX:
(Loss) from continuing operations before other income and income taxes	$	(1,528	)	$	(2,335	)	$	(4,255	)	$	(5,451	)
Exploration expenses		152			1,741			979			3,015
Depreciation, depletion and amortization		12			99			99			266
Impairment of natural gas and oil properties		420			125			420			237
Gain (loss) on sale of assets and other		(19	)		(12	)		223			(99	)

EBITDAX from continuing operations		(963	)		(382	)		(2,534	)		(2,032	)
Gain from discontinued operations before taxes		2,700			529			4,666			26,444
Exploration expenses		—			229			1,093			715
Depreciation, depletion and amortization		380			224			967			2,259

EBITDAX	$	2,117		$	600		$	4,192		$	27,386

Capital Resources and Liquidity

During the nine months ended March 31, 2006, we invested $31.2 million as follows: $21.8 million in exploration and development activities; a total of $7.5 million to acquire an additional 9.4% ownership interest in each of REX and COE; $1.0 million to acquire certain overriding royalty interests in REX, COE and MOE offshore prospects; approximately $0.2 million in our 10% owned Freeport LNG project; and approximately $0.7 million in the Contango Capital Partners Fund, L.P. (“the Fund”).

Capital Budget. For the remainder of calendar year 2006, we expect to invest a total of approximately $30 million in capital expenditures as we will continue to focus on developing our Arkansas Fayetteville Shale play, as well as our three offshore prospects, Eugene Island 10, High Island A-279 and West Delta 43, which we will operate through our wholly owned subsidiary, Contango Operators, Inc.

Our capital expenditure budget calls for us to invest approximately $3.8 million for production and pipeline facilities for the Grand Isle 72, approximately $4.0 million in estimated dry hole costs in the drilling of Eugene Island 10, approximately $3.0 million in estimated dry hole costs in the drilling of High Island A-279, approximately $3.5 million in estimated dry hole costs in the drilling of West Delta 43 and approximately $1.6 million in the acquisition of offshore lease blocks. In the event we have exploration success at any of our offshore prospects, our capital budget will be significantly increased as we will incur additional costs to complete these wells and pay for production facilities.

In the Arkansas Fayetteville Shale, our partners and we have acquired or received commitments on approximately 42,000 net mineral acres and have identified a number of drillable prospects. Our capital budget calls for us to invest approximately $9.5 million in the drilling of 11 horizontal wells during the remainder of calendar year 2006. In addition, we have been integrated as a working interest owner into 35 additional wells with an average working interest per well of 6.3%. Our share of the drilling costs for these wells is estimated at $3.0 million. In the event we have exploration success in our Arkansas Fayetteville Shale play, our capital budget will be significantly increased as we will have the opportunity to drill many additional wells.

Freeport LNG closed its $383.0 million private placement note issuance in December 2005, and we believe the project will be able to continue through Phase I construction and Phase II pre-development with no further significant funds likely being required from Contango. We also expect to invest an additional $1.0 million in Contango Venture Capital Corporation.

Offshore, the production platform at Ship Shoal 358 and the pipeline to shore at Eugene Island-113B sustained damage during Hurricane Rita. Repairs at both Ship Shoal 358 and Eugene Island-113B are complete and production resumed in April 2006. We were not responsible for the capital costs required to repair the platforms, pipelines, or other facilities related to these wells and were not materially impacted by the temporary loss of production from these two wells.

As of May 11, 2006, we have approximately $33 million in cash, cash equivalents, and short term investments. In addition, the Company has $10.0 million of unutilized borrowing capacity with The Royal Bank of Scotland plc.

We believe that our cash on hand, our cash equivalents, our short term investments and our anticipated cash flow from operations together with our currently unutilized $10.0 million of borrowing capacity will be adequate to provide working capital for on-going operations, to fund our exploration and development programs, to maintain our 10% limited partnership interest in Freeport LNG, including any potential expansion in terminal capacity, to fund our remaining commitment to the Fund, and to satisfy general corporate needs. We may seek additional equity, sell assets or seek other financing to fund our exploration program and to take advantage of other opportunities that may become available. The availability of such funds will depend upon prevailing market conditions and other factors over which we have no control, as well as our financial condition and results of operations.

Natural Gas and Oil Reserves

The following table presents our estimated net proved, developed producing natural gas and oil reserves and the pre-tax net present value of our reserves at March 31, 2006, based on a reserve report generated by W.D. Von Gonten & Co. 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, 2006 was determined by the March 31, 2006 prices of $6.93 per MMbtu for natural gas at the Houston Ship Channel and $66.63 per barrel of oil at West Texas Intermediate Posting, in each case before adjusting for basis and transportation costs.


	Proved Reserves as of March 31, 2006
Natural Gas (MMcf)		1,940
Oil and Condensate (MBbls)		220
Total proved reserves (MMcfe)		3,260
Pre-tax net present value, SEC guidelines ($000)	$	16,784

On April 28, 2006, we sold 203 MBbls and 656 MMcf of the above listed reserves, leaving approximately 17 MBbls and 1,284 MMcf, or 1,386 MMcfe total proved reserves with a pre-tax net present value (as determined in accordance with SEC guidelines) of approximately $4.6 million.

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

The Company’s credit facility with Guaranty Bank, FSB is an unsecured $100,000 revolving line of credit . Although the Company has no borrowings against this line as of March 31, 2006, the revolving line of credit is being maintained and matures on June 29, 2006. The Company expects to be able to extend this credit facility until 2008. Borrowings under the credit facility bear interest, at the Company’s option, at either (i) LIBOR plus two percent (2%) or (ii) the bank’s base rate plus one-fourth percent (1/4%) per annum. Additionally, the Company pays a quarterly commitment fee of three-eighths percent (3/8%) per annum on the average availability.

The hydrocarbon borrowing base is subject to semi-annual redetermination based primarily on the value of our proved reserves. The credit facility requires the maintenance of certain ratios, including those related to working capital, funded debt to EBITDAX, and debt service coverage, as defined in the credit agreements. Additionally, the credit agreements contain certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell assets, pay dividends and reacquire or otherwise acquire or redeem capital stock. Failure to maintain required financial ratios or comply with the credit facility’s covenants can result in a default and acceleration of all indebtedness under the credit facility. As of March 31, 2006, the Company was in compliance with its financial covenants, ratios and other provisions of its credit facility

On April 27, 2006 the Company completed the arrangement of a new three-year $20.0 million secured term loan agreement with The Royal Bank of Scotland plc (“RBS”). The term loan agreement 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. As of May 11, 2006, the Company has borrowed the first $10.0 million under the term loan agreement and may borrow the remaining $10.0 million at anytime prior to October 27, 2006. Borrowings under the Agreement 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. The term loan agreement requires an arrangement fee of 2%, or $400,000, which was paid upon closing.

The term loan agreement requires the maintenance of certain ratios, including those related to working capital, as defined in the term loan agreement. Additionally, the term loan agreement contains certain negative covenants that, among other things, restrict or limit our ability to incur indebtedness, sell certain assets, and pay dividends. Failure to maintain required financial ratios or comply with the term loan agreement’s covenants could result in a default and acceleration of all indebtedness under the credit facility. As of May 11, 2006, the Company was in compliance with its financial covenants, ratios and other provisions of the term loan agreement.

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 no ability to control the prices that we receive for natural gas and oil. Natural gas and oil prices fluctuate widely, and low prices could 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.

•

Weather conditions.

•

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.

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 Contango formed for the purpose of drilling and operating exploration wells in the Gulf of Mexico and is a new element of our business strategy. COI is operating for the first time and drilled one exploration well in the Gulf of Mexico. COI plans to drill at least three additional exploration wells in the Gulf of Mexico in 2006. This represents an increase in the risk profile of the Company since the Company has never before operated. COI will be the entity under which Contango will drill and operate selective offshore prospects. Estimated drilling costs could be significantly higher if we encounter difficultly 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.

Using our capital availability to increase our reward/risk potential on selective prospects.

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. Our anticipated capital investment in our offshore prospects is estimated in excess of $10.0 million. COI will drill and operate these wells. This represents 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 1.5 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 capacity at its currently permitted 1.5 Bcf/d Freeport LNG terminal to 2.6 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, we may lose our 10% investment in the project.

A majority of the Freeport LNG financing is being provided by ConocoPhillips through a $620.0 million construction loan, with debt service being provided by the terminal use agreement with ConocoPhillips. Additional financing has been obtained through a $383.0 million private placement note issuance by Freeport LNG which closed on December 19, 2005. The notes are being secured primarily by payments obligated under the terminal use agreement with Dow Chemical. Without such financing or upon any significant shortfall in project funding, 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.

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

Our three-year $20.0 million term loan agreement 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 term loan agreement, we could lose our investment in the Freeport LNG facility.

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 as of March 31, 2006. 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.

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.

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

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Pressure or irregularities in formations.

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Equipment failures or accidents.

•

Adverse weather conditions.

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Compliance with governmental requirements and laws, present and future.

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

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:

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Blowouts, fires and explosions.

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Surface cratering.

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

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Natural disasters.

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Pipe and cement failures.

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Casing collapses.

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Stuck drilling and service tools.

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Abnormal pressure formations.

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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:

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Injury or loss of life.

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

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Pollution and other environmental damage.

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Clean-up responsibilities.

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Regulatory investigations and penalties.

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Suspension of our operations or repairs necessary to resume operations.

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

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

Not hedging our production may result in losses.

Due to the significant volatility in natural gas prices and the potential risk of significant hedging losses if NYMEX natural gas prices spike on the date options settle, 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 and pipelines that transport our natural gas and oil.

All of our natural gas and oil is transported through gathering systems and pipelines, which we do not own. Transportation capacity on gathering systems and pipelines 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 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 not to incur the expense of retaining 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 the 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. In particular, we expect to pursue acquisitions that have the potential to increase our domestic natural gas and oil reserves. 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.

We do not currently intend to pay dividends on our common stock.

We have never declared or paid a dividend on our common stock and do not expect to do so in the foreseeable future. Our current plan is to retain any future earnings for funding growth, and, therefore, holders of our common stock will not be able to receive a return on their investment unless they sell their shares.

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.

•

Impose restrictions on business combinations with some interested parties.

Our common stock is thinly traded.

Contango has approximately 15 million shares of common stock outstanding, held by approximately 115 holders of record. Directors and officers own or have voting control over approximately 3.7 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.

Item 3.

Quantitative and Qualitative Disclosure About Market Risk

Interest Rate and Credit Rating Risks. As of March 31, 2006, we had approximately $16.5 million in cash and cash equivalents, and short term investments. At March 31, 2006, approximately $4.4 million was held in our operating accounts to be used for general corporate purposes, and approximately $2.2 million was invested in highly liquid AAA-rated tax-exempt money market funds. The remaining $9.9 million was invested in a portfolio of periodic auction reset (“PAR”) securities that have coupons periodically reset to market interest rates. These PAR

securities are being 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.

Our money market funds are highly liquid AAA-rated tax-exempt securities with maturities of 90 days or less. We consider all highly liquid debt instruments having an original maturity of 90 days or less to be cash equivalents.

Investments in fixed-rate, interest-earning instruments carry a degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impacted because of changes in interest rates and credit ratings. Additionally, the value of our investments may be impaired temporarily or permanently. Due in part to these factors, our investment income may decline and we may suffer losses in principal. Currently, we do not use any derivative or other financial instruments or derivative commodity instruments to hedge any market risks, including changes in interest rates or credit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of the securities that we invest in, we do not believe that we have any cash flow exposure arising from changes in credit ratings. Based on a sensitivity analysis performed on the financial instruments held as of March 31, 2006, an immediate 10% change in interest rates is not expected to have a material effect on our near-term financial condition or results of operations.

Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas and oil production. Realized commodity prices received for our production are the spot prices applicable to natural gas and crude oil. Prices received for natural gas and oil are volatile and unpredictable and are beyond our control. For the quarter ended March 31, 2006, a 10% fluctuation in the prices received for natural gas and oil production would not have a material impact on our revenues.

Hedging Activities. Due to the significant volatility in natural gas and crude oil prices and the potential risk of significant hedging losses if NYMEX natural gas prices spike on the date options settle, our policy is to hedge only through the purchase of puts. During the nine month period ended March 31, 2006, we had no commodity hedge activity and no commodity hedges in place as of March 31, 2006.

Item 4.

Controls and Procedures

Kenneth R. Peak, our Chief Executive Officer and Chief Financial Officer, carried out an evaluation of the effectiveness of the Company’s “disclosure controls and procedures” as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of March 31, 2006. Based upon that evaluation, Mr. Peak concluded that, as of March 31, 2006, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting that occurred during the fiscal quarter ended March 31, 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1A.

Risk Factors

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

Item 6.

Exhibits

(a)

Exhibits:

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


Exhibit Number		Description

2.1		Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and REX Offshore Corporation, dated as of September 1, 2005. (1)

2.2		Purchase and Sale Agreement, by and between Juneau Exploration, L.P. and COE Offshore, LLC dated as of September 1, 2005. (1)

2.3		Purchase and Sale Agreement between Contango STEP, LP and Rosetta Resources Operating LP, dated April 28, 2006 †

3.1		Certificate of Incorporation of Contango Oil & Gas Company. (2)

3.2		Bylaws of Contango Oil & Gas Company. (2)

3.3		Agreement of Plan of Merger of Contango Oil & Gas Company, a Delaware corporation, and Contango Oil & Gas Company, a Nevada corporation. (2)

3.4		Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (3)

4.1		Facsimile of common stock certificate of Contango Oil & Gas Company. (4)

4.2		Certificate of Designations, Preferences and Relative Rights and Limitations for Series C Senior Convertible Cumulative Preferred Stock of Contango Oil & Gas Company. (5)

4.3		Certificate of Designations, Preferences and Relative Rights and Limitations for Series D Perpetual Cumulative Convertible Preferred Stock of Contango Oil & Gas Company. (6)

4.4		Securities Purchase Agreement, dated as of July 15, 2005, among Contango Oil & Gas Company and the Purchasers Named Therein. (6)

10.1		Term Loan Agreement between Contango Oil & Gas Company and The Royal Bank of Scotland plc, dated April 27, 2006. †

23.1		Consent of W.D. Von Gonten & Co. †

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

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

†	Filed herewith.

1.	Filed as an exhibit to the Company’s report on Form 8-K, dated September 2, 2005, as filed with the Securities and Exchange Commission on September 8, 2005.

2.	Filed as an exhibit to the Company’s report on Form 8-K, dated December 1, 2000, as filed with the Securities and Exchange Commission on December 15, 2000.

3.	Filed as an exhibit to the Company’s report on Form 10-QSB for the quarter ended December 31, 2002, dated November 14, 2002, as filed with the Securities and Exchange Commission.

4.	Filed as an exhibit to the Company’s Form 10-SB Registration Statement, as filed with the Securities and Exchange Commission on October 16, 1998.

5.	Filed as an exhibit to the Company’s report on Form 8-K, dated December 12, 2003, as filed with the Securities and Exchange Commission on December 17, 2003.

6.	Filed as an exhibit to the Company’s Registration Statement filed on Form S-3 as filed with the Securities and Exchange Commission on August 2, 2005.

SIGNATURES

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


	CONTANGO OIL & GAS COMPANY

Date: May 15, 2006	By:	/s/ KENNETH R. PEAK
		Kenneth R. Peak Chairman, Chief Executive Officer and Chief Financial Officer (Principal Executive and Financial Officer)

Date: May 15, 2006	By:	/s/ LESIA BAUTINA
		Lesia Bautina Senior Vice President and Controller (Principal Accounting Officer)