Edgar Filing: CONTANGO OIL & GAS CO

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

MCF-2013.09.30-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended September 30, 2013



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

For the transition period from to

Commission file number 001-16317

CONTANGO OIL & GAS COMPANY

(Exact name of registrant as specified in its charter)




DELAWARE		95-4079863
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

717 TEXAS, SUITE 2900

HOUSTON, TEXAS 77002

(Address of principal executive offices)

(713) 236-7400

(Registrant’s telephone number, including area code)

3700 BUFFALO SPEEDWAY, SUITE 960

HOUSTON, TEXAS 77098

(Former Address of principal executive offices)

(713) 960-1901

(Registrant’s former telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2013

TABLE OF CONTENTS




		Page
	PART I—FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements
	Consolidated Balance Sheets (unaudited) as of September 30, 2013 and June 30, 2013	3
	Consolidated Statements of Operations (unaudited) for the three months ended September 30, 2013 and 2012	4
	Consolidated Statements of Cash Flows (unaudited) for the three months ended September 30, 2013 and 2012	5
	Consolidated Statement of Shareholders’ Equity (unaudited) for the three months ended September 30, 2013	6
	Notes to the Unaudited Consolidated Financial Statements (unaudited)	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27
Item 4.	Controls and Procedures	27

	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	27
Item 1A.	Risk Factors	28
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3.	Defaults upon Senior Securities	28
Item 4.	Mine Safety Disclosures	28
Item 5.	Other Information	28
Item 6.	Exhibits	28

All references in this Quarterly Report on 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 Quarterly Report on 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.

Item 1. Consolidated Financial Statements

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2013			June 30, 2013
	(thousands)
CURRENT ASSETS:
Cash and cash equivalents	$	137,508		$	101,485
Accounts receivable:
Trade receivables	29,445			26,312
Joint interest billings	5,032			4,996
Income taxes	—			4,504
Other	7,773			648
Prepaid expenses	2,330			4,146
Inventory	2,147			2,147
Total current assets	184,235			144,238
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, successful efforts method of accounting:
Proved properties	560,522			562,572
Unproved properties	39,297			24,259
Furniture and equipment	218			229
Accumulated depreciation, depletion and amortization	(228,607		)	(218,122		)
Total property, plant and equipment, net	371,430			368,938
OTHER ASSETS:
Investments in affiliates	49,334			63,123
Other	373			162
TOTAL ASSETS	$	605,372		$	576,461



CURRENT LIABILITIES:
Accounts payable	$	6,199		$	4,926
Royalties and revenue payable	23,240			21,651
Accrued liabilities	4,604			4,882
Accrued exploration and development	930			313
Income tax payable	94			—
Total current liabilities	35,067			31,772

DEFERRED TAX LIABILITY	120,396			115,923
ASSET RETIREMENT OBLIGATIONS	11,015			9,612
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50,000,000 shares authorized; 20,135,107 shares issued and 15,194,952 outstanding at September 30, 2013 and June 30, 2013	805			805
Additional paid-in capital	79,024			79,024
Treasury shares at cost (4,940,155 shares at September 30, 2013 and June 30, 2013)	(117,162		)	(117,162		)
Retained earnings	476,227			456,487
Total shareholders’ equity	438,894			419,154
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	605,372		$	576,461

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 September 30,
	2013			2012
	(thousands, except per share amounts)
REVENUES:
Natural gas, oil and liquids sales	$	34,722		$	29,765
Total revenues	34,722			29,765
EXPENSES:
Operating expenses	5,553			6,464
Exploration expenses	89			44,984
Depreciation, depletion and amortization	11,518			9,566
Impairment of natural gas and oil properties	—			8,410
General and administrative expenses	2,657			2,580
Total expenses	19,817			72,004
OTHER INCOME/(EXPENSE):
Gain from investments in affiliates, net of taxes	669			164
Gain from sale of assets	15,645			—
Other income/(expense)	40			(12		)
Total other income/(expense)	16,354			152

NET INCOME (LOSS) BEFORE INCOME TAXES	31,259			(42,087		)
Income tax benefit (provision)	(11,519		)	14,538
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	19,740		$	(27,549	)
NET INCOME (LOSS) PER SHARE:
Basic	$	1.30		$	(1.80	)
Diluted	$	1.30		$	(1.80	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic	15,195			15,292
Diluted	15,195			15,292

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended September 30,
	2013			2012
	(thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	19,740		$	(27,549	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	11,518			9,566
Impairment of natural gas and oil properties	—			8,410
Exploration expenses	—			44,832
Deferred income taxes	4,473			(7,232		)
Gain from investment in affiliates	(1,030		)	(252		)
Gain on sale of assets	(15,645		)	—
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable and other	(2,573		)	1,355
Decrease in prepaids and other receivables	1,160			200
Increase (decrease) in accounts payable and advances from joint owners	2,826			(1,913		)
Decrease in other accrued liabilities	(278		)	(1,477		)
Decrease in income taxes receivable, net	4,598			(7,817		)
Other	(117		)	(207		)
Net cash provided by operating activities	$	24,672		$	17,916
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	(11,322		)	(17,205		)
Investment in affiliates	(481		)	(733		)
Cash Proceeds from sale of assets	23,154			7,823
Net cash used in investing activities	$	11,351		$	(10,115	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net cash provided by financing activities	$	—		$	—
NET INCREASE IN CASH AND CASH EQUIVALENTS	36,023			7,801
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	101,485			129,983
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	137,508		$	137,784
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for taxes, net of cash received	$	2,808		$	600
Cash paid for interest	$	—		$	13

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(Unaudited)



	Common Stock			Additional Paid-in Capital		Treasury Stock			Retained Earnings		Total Shareholders’ Equity
	Shares	Amount		Additional Paid-in Capital		Treasury Stock			Retained Earnings		Total Shareholders’ Equity
	(thousands)
Balance at June 30, 2013	15,195	$	805	$	79,024	$	(117,162	)	$	456,487	$	419,154
Net income	—	—		—		—			19,740		19,740
Balance at September 30, 2013	15,195	$	805	$	79,024	$	(117,162	)	$	476,227	$	438,894

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

CONTANGO OIL & GAS COMPANY AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

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

On October 1, 2013, the Company completed a merger ("the Merger") with Crimson Exploration Inc ("Crimson"). As the Merger was not completed until after September 30, 2013, the accompanying unaudited consolidated financial statements have not been prepared to include balance sheet or results of operations of Crimson, and thus reflect only Contango and its subsidiaries prior to the Merger. See Note 9 - "Subsequent Events" for more information on the Merger.

2. Business

General

We are a Houston-based, independent natural gas and oil company. Our core business is to explore, develop, produce and acquire natural gas and oil properties onshore and offshore in the Gulf of Mexico in water-depths of less than 300 feet, using cash generated from our existing property base. As of September 30, 2013, we had no debt.

On April 29, 2013, we signed a merger agreement with Crimson, for an all-stock transaction pursuant to which Crimson would become a wholly owned subsidiary of the Company. This transaction was approved by shareholders and closed on October 1, 2013. Upon consummation of the Merger, each share of Crimson stock was converted into the right to receive 0.08288 shares of Company stock resulting in Crimson stockholders owning approximately 20.3% of the post-merger Company. See Note 9 - "Subsequent Events" for more information on the Merger.

Operations

On July 30, 2013, we spud a well at our South Timbalier 17 prospect with the Hercules 202 rig, and on August 22, 2013 we announced that it was successful. Estimated net costs to Contango to drill, complete and bring this well to full production status are $14.8 million. The well was completed in September 2013, and facility construction is in progress. As of September 30, 2013, we had spent $10.3 million on this field , net to Contango, including leasehold costs. Prior to payout, our working interest in the well is 75.0% and our net revenue interest is 53.3%. After payout, we will have a working interest of 59.3% and a net revenue interest of 42.1% (including our share of the Republic Exploration LLC ("REX") ownership interest).

As of September 30, 2013, the Company had invested approximately $10.3 million in leasehold costs in the Tuscaloosa Marine Shale ("TMS") for approximately 28,000 acres. Additionally, we invested $5.8 million to to drill a horizontal well with Goodrich Petroleum Company in the TMS. Our non-operated working interest in this well is 25%. This well was successfully completed and is currently producing approximately 315 barrels of oil per day, with cumulative production of 116,000 barrels of oil through September 30, 2013.

In August 2013, the Company received notice that a third party proposed to sell its interests in oil and gas assets in the Gulf of Mexico, including its interests in five Dutch wells. In September 2013, the Company exercised its preferential right to purchase its pro-rata interest in the five Dutch wells and related assets for approximately $18.8 million. The purchase is expected to close by the end of November 2013.

Investments

Alta Resources Investments, LLC. Our total investment in Alta Resources Investments, LLC ("Alta"), whose primary area of focus is the liquids-rich Kaybob Duvernay Play in Alberta, Canada, was $15.2 million. On August 1, 2013, Alta sold its interest in over 67,000 acres in the Kaybob Duvernay Play. Net proceeds to the Company from the sale are expected to be

approximately $30.8 million. Of the total expected proceeds, the Company received approximately $23.1 million in September 2013 and recognized a gain of approximately $15.6 million. We expect to receive the remaining proceeds of $7.7 million by the end of calendar year 2013. This amount is included in Other Accounts Receivable on the Consolidated Balance Sheet as of September 30, 2013.

Exaro Energy III LLC. As of September 30, 2013, we had also invested approximately $46.9 million for a 37% interest in Exaro Energy III LLC ("Exaro"), which is primarily focused on the development of proved reserves in the Jonah Field in Wyoming. For the three months ended September 30, 2013 and September 30, 2012 we recognized a gain of approximately $0.7 million and $0.2 million, (net of tax expense of $360,000 and $88,000) respectively, for our share of Exaro's earnings.

3. Summary of Significant Accounting Policies

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

Successful Efforts Method of Accounting. The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above. Depreciation, depletion and amortization is calculated on a field by field basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other costs amortized over proved developed reserves.

Impairment of Long-Lived Assets. When circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future net cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the future undiscounted net cash flows based on the Company’s estimate of future natural gas and oil prices and operating costs and anticipated production from proved and probable reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair market value. No impairment of proved properties was recognized in continuing operations for the three months ended September 30, 2013. For the three months ended September 30, 2012, we recorded an impairment expense of approximately $8.4 million related to proved properties. Of this amount, approximately $6.3 million related to our Ship Shoal 263 well and $2.1 million related to the Eugene Island 24 platform and other properties. Despite the writedowns on Ship Shoal 263, this well reached payout during fiscal year 2012.

Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. No impairment of unproved properties was recognized during the three months ended September 30, 2013. For the three months ended September 30, 2012, the Company recognized impairment expense of approximately $1.2 million related to an unsuccessful exploration program in Jim Hogg County, Texas and $6.6 million related to leasehold costs at our dry holes at Ship Shoal 134 and South Timbalier 75. These costs are all included in exploration expenses.

Cash Equivalents. Cash equivalents are considered to be highly liquid investment grade investments having an original maturity of 90 days or less. As of September 30, 2013, the Company had approximately $137.5 million in cash and cash equivalents, all of which was held in interest bearing investment accounts.

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

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

Recent Accounting Pronouncements. In February 2013, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update 2013-04 - "Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date". The objective of this update is to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability

arrangements for which the total amount of the obligations within the scope of this guidance is fixed at the reporting date, except for obligations addressed within existing guidance in U.S. GAAP. Examples of obligations within the scope of this update include debt arrangements, other contractual obligations, and settled litigation and judicial rulings. U.S. GAAP does not include specific guidance on accounting for such obligations with joint and several liability, which has resulted in diversity in practice. The accounting update is effective for interim and annual periods beginning after December 15, 2013. Management is currently evaluating the provisions of this accounting update and assessing the impact , if any, it may have on the Company's financial position and results of operations.

Further, management is closely monitoring the joint standard-setting efforts of the FASB and the International Accounting Standards Board. There are a large number of pending accounting standards that are being targeted for completion in 2013 and beyond, including, but not limited to, standards relating to revenue recognition, accounting for leases, fair value measurements, accounting for financial instruments, disclosure of loss contingencies and financial statement presentation. Because these pending standards have not yet been finalized, at this time management is not able to determine the potential future impact that these standards will have, if any, on the Company's financial position, results of operations, or cash flows.

4. Customer Concentration Credit Risk

The customer base for the Company is concentrated in the natural gas and oil industry. Major purchasers of our natural gas and oil for the three months ended September 30, 2013 were ConocoPhillips Company, Shell Trading US Company, Enterprise Products Operating LLC, Exxon Mobil Oil Corporation, and Crosstex Energy Services. Our sales to these companies are not secured with letters of credit and in the event of non-payment, we could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect on our financial position, but there currently are numerous other potential purchasers of our production.

5. Credit Facility

In October 2010, the Company obtained a $40 million secured revolving Credit Agreement with Amegy Bank (the “Amegy Credit Agreement”). The Amegy Credit Agreement was supported by a hydrocarbon borrowing base and was available to fund the Company’s exploration and development activities, as well as repurchase shares of common stock, pay dividends and fund working capital as needed. The Amegy Credit Agreement was collateralized by substantially all of the assets of the Company. Borrowings under the Amegy Credit Agreement bore interest at LIBOR plus 2.5%, subject to a LIBOR floor of 0.75%. The principal was due October 1, 2014, and could be prepaid at any time with no prepayment penalty. An arrangement fee of $300,000 was paid in connection with the facility. Effective November 1, 2011, a commitment fee of 0.125%. was owed on unused borrowing capacity. The Amegy Credit Agreement contained customary covenants including limitations on our current ratio and additional indebtedness. As of September 30, 2013, the Company was in compliance with all covenants and had no borrowings outstanding under the Amegy Credit Agreement.

The Amegy Credit Agreement was refinanced in connection with the Merger with Crimson. See Note 9 - "Subsequent Events" for more information.

6. Investment in Exaro Energy LLC

In April 2012, the Company entered into a Limited Liability Company Agreement , as amended (the “LLC Agreement”) in connection with the formation of Exaro. Pursuant to the LLC Agreement, as amended, the Company has committed to invest up to $67.5 million in cash in Exaro, together with other parties for an aggregate commitment of $182.5 million, or a 37% ownership interest in Exaro. As of September 30, 2013, the Company had invested approximately $46.9 million in Exaro. No additional contributions were made during the three months ended September 30, 2013.

Our share in Exaro's results of operations for the three months ended September 30, 2013 and September 30, 2012 was $0.7 million, net of tax expense of $360,000, and $0.2 million, net of tax expense of $88,000, respectively.

7. Income Taxes

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



	Three Months Ended September 30,
	2013		2012
Current tax provision (benefit):
Federal	$	6,536	$	(7,874	)
State	870		568
Total	$	7,406	$	(7,306	)
Deferred tax provision (benefit):
Federal	$	4,251	$	(7,108	)
State	222		(124		)
Total	$	4,473	$	(7,232	)
Total tax provision (benefit):
Federal	$	10,787	$	(14,982	)
State	1,092		444
Total	$	11,879	$	(14,538	)

Of the total tax provision for the three months ended September 30, 2013 and September 30, 2012, approximately $360,000 and $88,000 of deferred income tax expense are included in the gain from affiliates line item in the Company's Consolidated Statements of Operations.

8. Related Party Transactions

Effective January 1, 2013, Contaro Company ("Contaro"), a wholly-owned subsidiary of the Company, entered into an advisory agreement with Juneau Exploration, L.P. ("JEX") (the "Contaro Advisory Agreement"). Mr. Brad Juneau, a director of the Company is the sole manager of the general partner of JEX. Under the Contaro Advisory Agreement, JEX provides advisory services to Contaro in connection with Contaro's investment in Exaro, and Mr. Juneau serves on the Board of Managers of Exaro on behalf of Contaro and performs such duties as described in the LLC Agreement. Pursuant to the Contaro Advisory Agreement, JEX is paid a monthly fee of $10,000 by Contaro and is entitled to receive a one percent (1%) fee of the cash profit earned by Contaro. Cash profit is defined as the amount of cash received by Contaro as a result of its investment in Exaro, less the cash invested by Contaro in Exaro.

In December 2012, Mr. Joseph J. Romano was elected President and Chief Executive Officer of the Company. In April 2013, Mr. Romano was elected Chairman of the Board of Directors. Mr. Romano is also the President and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic"). In connection with the Merger, effective October 1, 2013, Mr. Romano continues to serve as Chairman of the Board of Directors, but is no longer the President and Chief Executive Officer of the Company.

JEX and its affiliates and Olympic have historically participated with the Company in the drilling and development of certain prospects through participation agreements and joint operating agreements, which specify each participant’s working interest ("WI"), net revenue interest ("NRI"), and describe when such interests are earned, as well as allocate an overriding royalty interest ("ORRI") of up to 3.33% to benefit the employees of JEX, excluding Mr. Juneau, except where otherwise noted. Olympic last participated with the Company in the drilling of wells in March 2010. Olympic's ownership in Company-operated wells is limited to our Dutch and Mary Rose wells.

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

As of September 30, 2013, Contango, Olympic, JEX, REX and JEX employees owned the following interests in the Company's offshore wells.



	Contango				Olympic				JEX				REX				JEX Employees
	WI		NRI		WI		NRI		WI		NRI		WI		NRI		ORRI
Dutch #1 - #5	47.05	%	38.12	%	3.02	%	2.42	%	1.61	%	1.29	%	—	%	—	%	2.02%
Mary Rose #1	53.21	%	40.44	%	3.61	%	2.7	%	2.01	%	1.51	%	—	%	—	%	2.79%
Mary Rose #2 - #3	53.21	%	38.67	%	3.61	%	2.58	%	2.01	%	1.44	%	—	%	—	%	2.79%
Mary Rose #4	34.58	%	25.49	%	2.34	%	1.7	%	1.31	%	0.95	%	—	%	—	%	1.82%
Mary Rose #5	37.80	%	27.88	%	2.56	%	1.87	%	1.43	%	1.04	%	—	%	—	%	1.54%
Ship Shoal 263	100.00	%	80.00	%	—	%	—	%	—	%	—	%	—	%	—	%	3.33%
Vermilion 170	83.20	%	64.83	%	—	%	—	%	4.30	%	3.35	%	12.50	%	9.74	%	3.33%
South Timbalier 17 (1)	75.00	%	53.25	%	—	%	—	%	—	%	—	%	—	%	—	%	—%
Crosby 12H-1 (2)	22.50	%	16.31	%	—	%	—	%	2.50	%	1.81	%	—	%	—	%	0.63%

(1) In June 2013, the Company purchased South Timbalier 17 from an independent oil and gas company. Under the terms of the applicable participation agreement, the Company will have a 75% working interest in this well, with several other owners owning the remainder, until payout of all costs is reached. Once payout of all costs has been reached, REX will have an option to back-in for up to a 9.4% working interest, (6.7% net revenue interest), resulting in the Company owning a 56.3% direct working interests (39.9% direct net revenue interest). The Company paid JEX a prospect fee of $250,000 for evaluating this prospect. There are no JEX employee ORRIs on this prospect.

(2) In October 2012, the Company purchased a 25% non-operating working interest in the Crosby 12H-1 well in Wilkinson County, Mississippi, targeting the TMS. Under the terms of the applicable participation agreement, Contango had a 25% working interest through first production. Once production began, JEX exercised its option to back-in for a 2.5% working interest and 1.81% net revenue interest, respectively. Once production began, JEX employees also received an ORRI of 0.63%.

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



	Three months ended September 30,
	2013									2012
	Olympic			JEX			REX			Olympic			JEX			REX
Revenue payments as well owners	$	(1,698	)	$	(1,254	)	$	(470	)	$	(1,540	)	$	(1,133	)	$	(849	)
Joint interest billing receipts	235			412			908			293			220			91

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



	Three months ended September 30,
	2013								2012
	Olympic		JEX			REX			Olympic		JEX			REX
Reimbursement of certain costs	$	—	$	(10	)	$	—		$	—	$	(146	)	$	—
Payments under Contaro Advisory Agreement	—		(30		)	—			—		(667		)	—
Investment in REX	—		—			(197		)	—		—			—
REX distribution to members	—		—			—			—		—			323

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



	September 30, 2013									June 30, 2013
	Olympic			JEX			REX			Olympic			JEX			REX
Accounts receivable:
Trade receivables	$	—		$	1		$	—		$	16		$	21		$	—
Joint interest billings	66			61			151			178			358			922

Accounts payable:
Royalties and revenue payable	(1,292		)	(848		)	(416		)	(1,181		)	(881		)	(285		)

In addition to the above, the Company paid Mr. Brad Juneau $28,000 during the three months ended September 30, 2013 and 2012 for his services as a director of the Company.

9. Subsequent Events

Merger with Crimson

On October 1, 2013, the Company completed a merger with Crimson Exploration Inc. In accordance with the terms of the merger agreement, Crimson merged with and into Contango Acquisition, Inc ("Merger Sub"), a wholly-owned subsidiary of the Company with Crimson surviving as a wholly-owned subsidiary of Contango. Contango issued approximately 3.9 million shares of its common stock in exchange for all of Crimson's outstanding capital stock. The Company also assumed $235.4 million in debt, including accrued interest and repayment premium, and issued 135,898 options in exchange for the outstanding options held by Crimson employees.

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

The newly constituted board of directors of the Company consists of Joseph J. Romano, Allan D. Keel, B.A. Berilgen, B. James Ford, Brad Juneau, Lon McCain, Charles M. Reimer, and Steven L. Schoonover. The board of directors has appointed Allan D. Keel as President and Chief Executive Officer of Contango and E. Joseph Grady serves as Senior Vice President and Chief Financial Officer of the Company. Joseph J. Romano remains as Chairman of the Board. Messrs. Keel, Grady and certain other employees of Crimson entered into employment agreements with the Company that became effective upon the consummation of the Merger. The combined company has its headquarters and principal corporate office in Houston, Texas.

The Merger will be accounted for using the acquisition method of accounting with Contango being considered the acquirer of Crimson for accounting purposes. Contango will allocate the purchase price to the fair value of Crimson’s tangible and intangible assets and liabilities at the acquisition date, with any excess purchase price, if any, being recorded as goodwill. Under the acquisition method of accounting, goodwill is not amortized but is tested for impairment at least annually. The Company is currently working on finalizing the fair value analysis for assets acquired and liabilities assumed and purchase price allocation.

New Credit Facility

In connection with the Merger, the Company assumed and immediately repaid Crimson’s $175.0 million debt with Barclays Bank PLC ("Barclays"), its $58.6 million debt with Wells Fargo, and $1.8 million in accrued interest and prepayment premiums. In order to finance the assumed debt, the Company entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other lenders (the “RBC Credit Facility”) with an initial hydrocarbon supported borrowing base of $275 million. The RBC Credit Facility replaced the Company's $40 million Amegy Credit Agreement. The Company incurred $2.2 million of arrangement and upfront fees in connection with the RBC Credit Facility. Proceeds of the RBC Credit Facility will be used (i) to finance working capital and for general corporate purposes (including requisitions), (ii) for permitted acquisitions, and (iii) to finance transaction expenses in connection with the RBC Credit Facility and the Merger. The RBC Credit Facility is collateralized by substantially all of the assets of the Company and its subsidiaries. Borrowings under the RBC Credit Facility bear interest at a rate that is dependent upon LIBOR or the U.S. prime rate of interest, plus a margin dependent upon the amount outstanding.

On October 1, 2013, the $235.4 million of assumed debt, accrued interest, and prepayment premium and $2.2 million of arrangement and upfront fees under the RBC Credit Facility were paid with the Company's existing cash of $127.6 million and drawings under our RBC Credit Facility of $110.0 million.

Advisory Fees

Upon completion of the Merger, the Company was also required to pay the remaining $1.7 million of a $2.8 million advisory fee to Petrie Partners Securities, LLC, and an assumed liability for an advisory fee to Barclays Capital, Inc. of $2.8 million, who acted as financial advisors to Contango and Crimson, respectively. Both fees were paid in October 2013.

Derivative Instruments

As a result of the Merger, Contango assumed all of Crimson's derivative instruments outstanding as of September 30, 2013, including those transfered to the Company via novation. As of September 30, 2013, the net fair value of Crimson's derivative instruments was approximately $0.3 million.

Exercise of Preferential Right

In August 2013, the Company received notice from a third party that it proposed to sell its interests in oil and gas assets in the Gulf of Mexico, including its interest in five Dutch wells. In September 2013, the Company exercised its preferential right to purchase its pro-rata interest in the five Dutch wells and related assets for approximately $18.8 million. The sale is expected to close by the end of November 2013.

Available Information

General information about us can be found on our website at www.contango.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file or furnish them to the Securities and Exchange Commission (“SEC”).

Cautionary Statement about Forward-Looking Statements

Some of the statements made in this report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. The words and phrases “should be”, “will be”, “believe”, “expect”, “anticipate”, “estimate”, “forecast”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. These include such matters as:


•	Our financial position


•	Business strategy, including outsourcing


•	Meeting our forecasts and budgets


•	Anticipated capital expenditures


•	Drilling of wells


•	Natural gas and oil production and reserves


•	Timing and amount of future discoveries (if any) and production of natural gas and oil


•	Operating costs and other expenses


•	Cash flow and anticipated liquidity


•	Prospect development


•	Property acquisitions and sales


•	New governmental laws and regulations


•	Expectations regarding oil and gas markets in the United States

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


•	Low and/or declining prices for natural gas and oil


•	Natural gas and oil price volatility


•	Operational constraints, start-up delays and production shut-ins at both operated and non-operated production platforms, pipelines and gas processing facilities


•	The risks associated with acting as the operator in drilling deep high pressure and temperature wells in the Gulf of Mexico, including well blowouts and explosions


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


•	The timing and successful drilling and completion of natural gas and oil wells


•	Availability of capital and the ability to repay indebtedness when due


•	Availability of rigs and other operating equipment


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


•	Ability to raise capital to fund capital expenditures


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


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


•	Interest rate volatility


•	Zero or near zero interest rates


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


•	Operating hazards attendant to the natural gas and oil business


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


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


•	Weather


•	Availability and cost of material and equipment


•	Delays in anticipated start-up dates


•	Actions or inactions of third-party operators of our properties


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


•	The ability to find and retain skilled personnel


•	Strength and financial resources of competitors


•	Federal and state regulatory developments and approvals


•	Environmental risks


•	Worldwide economic conditions


•	The ability to construct and operate offshore infrastructure, including pipeline and production facilities


•	The continued compliance by the Company with various pipeline and gas processing plant specifications for the gas and condensate produced by the Company


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


•	Restrictions on permitting activities


•	Expanded rigorous monitoring and testing requirements


•	Legislation that may regulate drilling activities and increase or remove liability caps for claims of damages from oil spills


•	Ability to obtain insurance coverage on commercially reasonable terms


•	Accidental spills, blowouts and pipeline ruptures


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

You should not unduly rely on these forward-looking statements in this report, as they speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances occurring after the date of this report or to reflect the occurrence of unanticipated events. See the information under the heading “Risk Factors” in this Quarterly Report on 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.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the accompanying notes and other information included elsewhere in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K for the fiscal year ended June 30, 2013, previously filed with the SEC.

Merger with Crimson Exploration

On October 1, 2013, the Company completed a merger with Crimson Exploration Inc. ("Crimson"), under an all-stock transaction pursuant to which Crimson became a wholly-owned subsidiary of Contango (the "Merger"). Upon consummation of the Merger, each share of Crimson stock was converted into the right to receive 0.08288 shares of Contango stock resulting in Crimson stockholders owning approximately 20.3% of the post-merger Contango. In connection with the acquisition, the Company assumed $235.4 million of debt, including accrued interest and early prepayment premium and issued 135,898 options in exchange for the outstanding options held by Crimson employees.

Crimson is a Houston, Texas-based independent energy company engaged in the exploitation, exploration, development and acquisition of crude oil and natural gas, primarily in the onshore Gulf Coast regions of the United States. Crimson currently owns and operates onshore properties in Texas, Colorado and Mississippi. Crimson refers to its four corporate areas as (i) Southeast Texas, focusing on the Woodbine, Eagle Ford and Georgetown horizontal plays as well as conventional properties, (ii) South Texas, focusing on the Eagle Ford and Buda horizontal plays as well as conventional properties, (iii) East Texas, focusing on the Haynesville, Mid-Bossier and James Lime formations, and (iv) Rockies and Other, focusing on the Niobrara and D&J Sand formations. Crimson’s strategy is to continue to increase crude oil and liquids-rich reserves and production from an extensive inventory of drilling prospects, de-risk unproved prospects in core operating areas, and opportunistically grow reserves through acquisitions complementary to its existing asset base.

The information contained in this Quarterly Report on Form 10-Q is for the three months ended September 30, 2013 and describes the operations of Contango prior to the Merger. The Company's board of directors recently voted to change our fiscal year-end to December 31. Accordingly, the first report describing the combined operations of Contango and Crimson will be our Transition Report on Form 10-K for the six-month transition period ended December 31, 2013.

Executive Overview

Contango is a Houston, Texas based, independent natural gas and oil company. The Company's core business is to explore, develop, produce and acquire natural gas and oil properties offshore in the shallow waters of the Gulf of Mexico. Contango Operators, Inc. (“COI”), our wholly-owned subsidiary, acts as operator of our offshore properties. Contango has additional onshore investments in (i) Exaro Energy III LLC ("Exaro"), which is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; and (ii) the Tuscaloosa Marine Shale ("TMS") where we own approximately 28,000 acres.

Sale of Alta Assets

On August 1, 2013, Alta Resources Investments, LLC ("Alta") sold its interest in the liquids-rich Kaybob Duvernay Play in Alberta, Canada, where we had invested approximately $15.2 million through our investments in Alta. The Company will receive approximately $30.8 million from the sales proceeds subject to certain closing conditions. Of this amount, $23.1 million was received in September 2013. We expect to receive the remaining $7.7 million by the end of calendar year 2013.

Exploration Program Summary

On July 30, 2013, we spud our South Timbalier 17 prospect in state of Louisiana offshore waters with the Hercules 202 rig, and on August 22, 2013 we announced a successful well. The well was drilled to a total measured depth of approximately 11,400 feet and the wireline logs of the well indicate the presence of hydrocarbons. Estimated reserves and production rates will be dependent upon the liquids content of the formation, which will be better defined once production begins. We are proceeding with development, including securing production facilities. Estimated costs net to Contango to drill, complete and bring this well to full production status are $14.8 million, $10.3 million of which has been spent as of September 30, 2013. Contango has a 75% working interest (53.3% net revenue interest) before payout of all costs, and a 59.3% working interest (42.1% net revenue interest) after payout (including our share of the Republic Exploration LLC ("REX") ownership interest).

Our Strategy

Our exploration strategy is predicated upon the belief that the only competitive advantage in the commodity-based natural gas and oil business is to be among the lowest cost producers.

We historically have depended upon our alliance partner, Juneau Exploration, L.P. (“JEX”), for prospect generation expertise and to review certain prospects submitted by third parties. JEX is experienced and has a successful track record in generating exploration prospects.

We have concentrated our risk investment capital in exploration of (i) offshore Gulf of Mexico prospects and (ii) conventional and unconventional onshore plays. Subsequent to the Merger, we will focus on oil and liquids rich onshore prospects complimented by the selected offshore Gulf of Mexico prospects. Exploration prospects are inherently risky as they require large amounts of capital with no guarantee of success.

Exploration Alliance with JEX

JEX is a private company formed for the purpose of generating offshore and onshore domestic natural gas and oil prospects for the Company, either directly, or via our 32.3% owned affiliated company, REX. In addition to generating prospects, JEX occasionally evaluates exploration prospects generated by third-party independent companies for us to purchase. Once we have purchased a prospect from JEX, REX or a third-party, we have historically entered into participation agreements and joint operating agreements, which specify each participant’s working interest, net revenue interest, and describe when such interests are earned, as well as allocate an overriding royalty interest of up to 3.33% to benefit employees of JEX.

In April 2012, Mr. Brad Juneau, the sole manager of the general partner of JEX, joined the Company’s board of directors. Effective January 1, 2013, Contaro Company ("Contaro"), a wholly-owned subsidiary of the Company, entered into an advisory agreement with JEX (the "Contaro Advisory Agreement"). Under the Contaro Advisory Agreement, JEX provides advisory services to Contaro in connection with Contaro's investment in Exaro, and Mr. Juneau serves on the Board of Managers of Exaro on behalf of Contaro and performs such duties as described in the LLC Agreement. Pursuant to the Contaro Advisory Agreement, JEX is paid a monthly fee of $10,000 by Contaro and is entitled to receive a one percent (1%) fee of the cash profit earned by Contaro. Cash profit is defined as the amount of cash received by Contaro as a result of its investment in Exaro, less the cash invested by Contaro in Exaro.

Contango Operators, Inc.

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

As of September 30, 2013, the Company’s offshore production was approximately 69.3 Mmcfed, net to Contango, which consists of seven federal and five state of Louisiana wells in the shallow waters of the Gulf of Mexico. These 12 operated wells produce through the following three platforms:

Eugene Island 11 Platform

Our Company-owned and operated production platform at Eugene Island 11 was designed with a capacity of 500 million cubic feet per day ("Mmcfd") and 6,000 barrels of oil per day ("bopd"). In September 2010, the Company installed a companion platform and two pipelines adjacent to the Eugene Island 11 platform to be able to access alternate markets. These platforms service production from the Company’s five Dutch wells in federal waters and five Mary Rose wells in state of Louisiana waters. From these platforms, gas and condensate can flow to our Eugene Island 63 auxiliary platform via our 20” pipeline, which has been designed with a capacity of 330 Mmcfd and 6,000 bopd, and then from there to third-party owned and operated on-shore processing facilities near Patterson, Louisiana, via an ANR pipeline.

Alternatively, gas can flow to the American Midstream (Seacrest), LP pipeline via our 8” pipeline, which has been designed with a capacity of 80 Mmcfd, and from there to a third-party owned and operated on-shore processing facility at Burns Point, Louisiana. Condensate can also flow via an ExxonMobil Pipeline Company pipeline to on-shore markets and multiple refineries. As of September 30, 2013, we were producing approximately 59.3 Mmcfed, net to Contango, from this platform.

Based on production and decline rates, the Company has determined the need to place its Dutch and Mary Rose wells on compression in the next 12 to 24 months, depending on performance of the wells. The Company built a large turbine type compressor for the platform that will be installed an estimated cost of $9.2 million, net to Contango which is currently stored onshore. This compressor will be of sufficient capacity to service all ten of the Company's Dutch and Mary Rose wells. As of September 30, 2013, the Company had incurred approximately $8.7 million to design and build the compressor.

Ship Shoal 263 Platform

Our Company-owned and operated platform at Ship Shoal 263 was designed with a capacity of 40 Mmcfd and 5,000 bopd. This platform services natural gas and condensate production from our Ship Shoal 263 well, which both flow via the Transcontinental Gas Pipeline to onshore processing plants. As of September 30, 2013, we were producing approximately 0.6 Mmcfed, net to Contango, from the platform at Ship Shoal 263. The well reached payout during fiscal year 2012. We will continue producing this well as long as it is economical.

The drilling of our Ship Shoal 255 prospect is expected to commence in late 2013. Should we have a discovery at this prospect, we expect to transport the production to this platform. We currently classify the platform as unproved properties, as its cost is expected to be recovered through future cash flow from Ship Shoal 255.

Vermilion 170 Platform

Our Company-owned and operated platform at Vermilion 170 was designed with a capacity of 60 Mmcfd and 2,000 bopd. This platform services natural gas and condensate production from our Vermilion 170 well. The production flows via the Sea Robin Pipeline to onshore processing plants. Based on production and decline rates, the Company has determined the need to place its Vermilion 170 well on compression in the next 12 months depending on well performance, at a cost of approximately $1.4 million, net to Contango. As of September 30, 2013, the Company had incurred all of the $1.4 million to install the compressor. As of September 30, 2013, we were producing approximately 9.4 Mmcfed, net to Contango, from this platform.

Republic Exploration LLC

In his capacity as sole manager of the general partner of JEX, Mr. Juneau also controls the activities of Republic Exploration LLC ("REX"), an entity owned 34.4% by JEX, 32.3% by Contango, and 33.3% by a third party which contributed other assets to REX. REX generates and evaluates offshore exploration prospects for the Company and has historically participated with the Company in the drilling and development of certain prospects through participation agreements and joint

operating agreements, which specify each participant's working interest, net revenue interest, and describe when such interests are earned, as well as allocate an overriding royalty interest ("ORRI") of up to 3.33% to benefit the employees of JEX. The Company proportionately consolidates the results of REX in its consolidated financial statements.

Offshore Properties

Contango, through its wholly-owned subsidiary COI, and its partially-owned subsidiary REX, conducts exploration activities in the Gulf of Mexico. As of September 30, 2013, Contango, through COI and REX, had an interest in 18 offshore leases.

Producing Properties. The following table sets forth the interests owned by Contango through its affiliated entities in the Gulf of Mexico which were capable of producing natural gas or oil as of September 30, 2013:



Area/Block	WI		NRI		Status
Eugene Island 10 #D-1 (Dutch #1)	47.05	%	38.1	%	Producing
Eugene Island 10 #E-1 (Dutch #2)	47.05	%	38.1	%	Producing
Eugene Island 10 #F-1 (Dutch #3)	47.05	%	38.1	%	Producing
Eugene Island 10 #G-1 (Dutch #4)	47.05	%	38.1	%	Producing
Eugene Island 10 #I-1 (Dutch #5)	47.05	%	38.1	%	Producing
S-L 18640 #1 (Mary Rose #1)	53.21	%	40.5	%	Producing
S-L 19266 #1 (Mary Rose #2)	53.21	%	38.7	%	Producing
S-L 19266 #2 (Mary Rose #3)	53.21	%	38.7	%	Producing
S-L 18860 #1, S-L 19261 and S-L 19266 (Mary Rose #4)	34.58	%	25.5	%	Producing
S-L 19266 #3 and S-L 18640 (Mary Rose #5)	37.80	%	27.6	%	Intermittent
Ship Shoal 263	100.00	%	80.0	%	Producing
Vermilion 170	87.24	%	68.0	%	Producing

Leases. The Company released Ship Shoal 83 in August 2013. The following table sets forth the working interests owned by Contango through its related entities in the Gulf of Mexico as of September 30, 2013:



Area/Block	WI		Lease Date	Expiration Date
East Breaks 369 (Dry Hole)	(1	)	Dec-03	Dec-13
South Timbalier 17	75.00	%	(2)	(2)
Brazos Area 543	100.00	%	Mar-12	Mar-17
East Cameron 124	100.00	%	Sept-12	Sept-17
Eugene Island 31	100.00	%	Oct-12	Oct-17
South Timbalier 110	100.00	%	Oct-12	Oct-17
Eugene Island 260	100.00	%	Nov-12	Nov-17
Ship Shoal 255	100.00	%	Dec-12	Dec-17
Eugene Island 23	100.00	%	Jun-13	Jun-18
Ship Shoal 52	100.00	%	Jul-13	Jul-18
Ship Shoal 59	100.00	%	Jul-13	Jul-18


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


(2)	Successful exploration well. Lease will be held by production.

Onshore Exploration and Properties

Jonah Field - Sublette County, Wyoming

In April 2012, the Company, through its wholly-owned subsidiary, Contaro Company, entered into a Limited Liability Company Agreement (as amended, the “LLC Agreement”) in connection with the formation of Exaro. Pursuant to the LLC Agreement, the Company has committed to invest up to $67.5 million in cash in Exaro, together with other parties for an aggregate commitment of $182.5 million, or a 37% ownership interest in Exaro. As of September 30, 2013, the Company had invested approximately $46.9 million in Exaro.

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

As of September 30, 2013, the Exaro-Encana venture had 70 new wells on production, producing at a rate of approximately 12.6 Mmcfed, net to Contango, plus an additional 10 wells that are either in the completion or fracture stimulation phase. We continue to have three drilling rigs running on this project. For the three months ended September 30, 2013, the Company recognized a gain of approximately $0.7 million, net of tax expense of $360,000, as a result of its investment in Exaro.

Tuscaloosa Marine Shale

In October 2012, the Company purchased a 25% non-operated working interest in the Crosby 12H-1 well in Wilkinson County, Mississippi, targeting the TMS, an oil-focused shale play in central Louisiana and Mississippi. As of September 30, 2013, we had invested approximately $5.9 million in this well, including leasehold costs. This well is operated by Goodrich Petroleum Company LLC ("Goodrich"). For evaluation purposes, we drilled a pilot well, performed an open-hole evaluation and obtained a conventional core over the TMS interval. This well has approximately 6,700 feet of usable lateral and was fracked with 25 stages. As of September 30, 2013, the Crosby 12H-1 well was producing at an 8/8ths rate of approximately 315 barrels of oil per day, with cumulative production of approximately 116,000 barrels of oil through September 30, 2013.

Additionally, as of September 30, 2013, the Company had invested approximately $10.3 million to lease approximately 28,000 acres in the TMS of which $1.1 million was invested in the quarter ended September 30, 2013. To date, we have elected to participate in three wells, where our acreage has been pooled into a unit; (i) the Goodrich-operated CMR/Foster Creek 20-7H #1 well, where we own less than a 1% working interest, (ii) the Goodrich-operated Huff 18-7H #1 well, where we own approximately a 3% working interest, and (iii) the Goodrich-operated Horseshoe Hill #1 well, where our working interest is still being determined. We plan to continue to participate in third-party operated wells with a small working interest. The data we obtain from these wells will assist us in evaluating our TMS acreage and developing a plan for drilling and operating future wells.

Application of Critical Accounting Policies and Management’s Estimates

The discussion and analysis of the Company’s financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. The Company’s significant accounting policies are described in Note 3 to the consolidated financial statements included in this Quarterly Report on Form 10-Q. We have identified below the policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. The Company analyzes its estimates, including those related to its natural gas and oil reserve estimates, on a periodic basis and bases its estimates on historical experience, independent third party reservoir engineers and various other assumptions that management believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of the Company’s consolidated financial statements:

Successful Efforts Method of Accounting. Our application of the successful efforts method of accounting for our natural gas and oil business activities requires judgments as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas and therefore management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties

requires management’s judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

Reserve Estimates. While we are reasonably certain of recovering our reported reserves, the Company’s estimates of natural gas and oil reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing natural gas and oil prices, operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Company’s natural gas and oil properties and/or the rate of depletion of such natural gas and oil properties. Actual production, revenues and expenditures with respect to the Company’s reserves will likely vary from estimates, and such variances may be material. Holding all other factors constant, a reduction in the Company’s proved reserve estimate at September 30, 2013 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense for the three months ended September 30, 2013 by approximately $0.6 million, $1.3 million and $2.0 million, respectively.

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

Income Taxes. Income taxes are provided for the tax effects of transactions reported in the consolidated financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between consolidated financial statements and income tax reporting. Numerous judgments and assumptions are inherent in the determination of deferred income tax assets and liabilities as well as income taxes payable in the current period. We are subject to taxation in several jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions.

MD&A Summary Data

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



	September 30, 2012	December 31, 2012	March 31, 2013	June 30, 2013	September 30, 2013
Dutch and Mary Rose Wells	54.2	57.2	59.5	57.2	61.7
Ship Shoal 263 Well (Nautilus)	3.5	2.6	0.9	0.6	0.4
Vermilion 170 Well (Swimmy)	10.5	12.9	3.6	4.0	9.6
Non-operated wells	—	—	0.6	0.4	0.3
	68.2	72.7	64.6	62.2	72.0

Dutch and Mary Rose Wells


•	Production at our Dutch and Mary Rose wells has been fairly consistent over the past year. As of September 30, 2013, the ten Dutch and Mary Rose wells were producing approximately 59.3 Mmcfed, net to Contango.

Ship Shoal 263 Well

•

Production at this well has been slowly decreasing since 2011 due to overheating, scaling problems, and water production. The well has also been shut-in several times for production logging and chemical treatment. We believe that this well may be fully depleted in the next twelve months. The well reached payout during fiscal year 2012. We will continue producing this well as long as it is economical. As of September 30, 2013, the well was flowing at approximately 0.6 Mmcfed, net to Contango.

Vermilion 170 Well

•

In January 2013, we identified sustained casing pressure between the production tubing and the production casing at our Vermilion 170 well. Diagnostic tests revealed that the production tubing had parted downhole requiring a shut-in and workover. Operations were conducted to replace the tubing and restore the well, which resumed production in June 2013. As of September 30, 2013, this well was producing at approximately 9.4 Mmcfed, net to Contango.

The table below shows revenue, production data, average sales prices and average production costs associated with our sales of natural gas, oil and natural gas liquids ("NGLs") from continuing operations for the indicated periods. Oil, condensate and NGLs are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil, condensate or NGLs is the energy equivalent of six thousand cubic feet (“Mcf”) of natural gas. Reported lease operating expenses include property and severance taxes.



	Three Months Ended September 30,
	2013		2012		%
Revenues (thousands):
Natural gas sales	$	18,914	$	14,076	34	%
Condensate sales	10,044		10,681		(6	)%
NGLs sales	5,764		5,008		15	%
Total revenues	$	34,722	$	29,765	17	%

Production:
Natural gas (million cubic feet)
Dutch and Mary Rose field	4,495		3,855		17	%
Vermilion 170 field	669		704		(5	)%
Other fields	26		208		(88	)%
Total natural gas	5,190		4,767		9	%
Oil and condensate (thousand barrels)
Dutch and Mary Rose field	72		68		6	%
Vermilion 170 field	13		17		(24	)%
Other fields	6		16		(63	)%
Total oil and condensate	91		101		(10	)%
Natural gas liquids (thousand gallons)
Dutch and Mary Rose field	5,242		5,052		4	%
Vermilion 170 field	943		1,115		(15	)%
Other fields	20		120		(83	)%
Total natural gas liquids	6,205		6,287		(1	)%
Total (million cubic feet equivalent)
Dutch and Mary Rose field	5,676		4,985		14	%
Vermilion 170 field	882		965		(9	)%
Other fields	65		321		(80	)%
Total production	6,623		6,271		6	%

Daily Production:
Natural gas (million cubic feet per day)
Dutch and Mary Rose field	48.8		41.9		17	%
Vermilion 170 field	7.3		7.6		(5	)%
Other fields	0.3		2.3		(88	)%
Total natural gas	56.4		51.8		9	%
Oil and condensate (thousand barrels per day)
Dutch and Mary Rose field	0.8		0.7		6	%
Vermilion 170 field	0.1		0.2		(24	)%
Other fields	0.1		0.2		(63	)%
Total oil and condensate	1.0		1.1		(10	)%



	Three Months Ended September 30,
	2013		2012		%
Daily Production (continued):
Natural gas liquids (thousand gallons per day)
Dutch and Mary Rose field	57.0		54.9		4	%
Vermilion 170 field	10.2		12.1		(15	)%
Other fields	0.2		1.3		(83	)%
Total natural gas liquids	67.4		68.3		(1	)%
Total (million cubic feet equivalent per day)
Dutch and Mary Rose field	61.7		54.2		14	%
Vermilion 170 field	9.6		10.5		(9	)%
Other fields	0.7		3.5		(80	)%
Total production	72.0		68.2		6	%

Average Sales Price:
Natural gas (per thousand cubic feet)	$	3.64	$	2.95	23	%
Oil and condensate (per barrel)	$	110.37	$	105.75	4	%
Natural gas liquids (per gallon)	$	0.93	$	0.80	16	%
Total (per thousand cubic feet equivalent)	$	5.24	$	4.75	10	%

Expenses (thousands):
Operating expenses	$	5,553	$	6,464	(14	)%
Exploration expenses	$	89	$	44,984	(100	)%
Depreciation, depletion and amortization	$	11,518	$	9,566	20	%
Impairment of natural gas and oil properties	$	—	$	8,410	(100	)%
General and administrative expenses	$	2,657	$	2,580	3	%
Gain from sale of assets	$	15,645	$	—	100	%
Gain (loss) from affiliates (net of taxes)	$	669	$	164	308	%

Selected data per Mcfe:
Operating expenses	$	0.84	$	1.03	(18	)%
General and administrative expenses	$	0.40	$	0.41	(2	)%
Depreciation, depletion and amortization of natural gas and oil properties	$	1.71	$	1.50	14	%

Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

Natural Gas, Oil and NGLs Sales and Production. We reported revenues of approximately $34.7 million for the three months ended September 30, 2013, compared to revenues of approximately $29.8 million for the three months ended September 30, 2012. This increase in revenues of $4.9 million was primarily attributable to an increase in natural gas, oil and condensate, and NGLs prices as well as an increase in gas production.

In total, equivalent production increased from 68,200 Mmcfed to 72,000 Mmcfed. Our net natural gas production for the three months ended September 30, 2013 was approximately 56.4 Mmcfd, up from approximately 51.8 Mmcfd for the three months ended September 30, 2012; this increase is a result of a negative impact to the prior year quarter for production downtime due to Hurricane Isaac and planned production enhancement work. Net oil and condensate production for the comparable periods decreased from approximately 1,100 barrels per day to approximately 1,000 barrels per day, and our NGLs production decreased from approximately 68,300 gallons per day to approximately 67,400 gallons per day.

Average Sales Prices. For the three months ended September 30, 2013, the average price of natural gas was $3.64 per Mcf, the average price for oil and condensate was $110.37 per barrel and the average price for NGLs was $0.93 per gallon. For

the three months ended September 30, 2012, the average price of natural gas was $2.95 per Mcf, the average price for oil and condensate was $105.75 per barrel and the average price for NGLs was $0.80 per gallon.

Operating Expenses. Lease operating expenses (“LOE”) for the three months ended September 30, 2013 were approximately $5.6 million, as compared to $6.5 million for the three months ended September 30, 2012. This decrease in LOE is mainly attributable to workover expenses of $1.0 million incurred in the quarter ended September 30, 2012.

Exploration Expense. We reported approximately $89,000 of exploration expense for the three months ended September 30, 2013. For the three months ended September 30, 2012, we reported approximately $45.0 million of exploration expense, which consists mainly of $43.7 million related to the drilling of two dry holes at Ship Shoal 134 and South Timbalier 75, and $1.2 million for our exploration in Jim Hogg County, Texas.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization for the three months ended September 30, 2013 and 2012 was approximately $11.5 million and $9.6 million, respectively. The increase in depreciation, depletion and amortization in the current quarter was primarily attributable to an increase in overall production.

General and Administrative Expenses. General and administrative expenses ("G&A expenses") for the three months ended September 30, 2013 and the three months ended September 30, 2012 were approximately $2.7 million and $2.6 million, respectively. G&A expenses remained flat as a result of an increase of $0.7 million due to Merger-related costs during the three months ended September 30, 2013, offset by a $0.5 million decrease related to lower bonus expense combined with a $0.1 million decrease related to other miscellaneous G&A expenses.

Capital Resources and Liquidity

Cash From Operating Activities. Cash flows from operating activities provided approximately $24.7 million in cash for the three months ended September 30, 2013 compared to $17.9 million for the same period in 2012. This increase in cash provided by operating activities was mainly attributable to positive net income for the current period, as well as the timing of payments of the Company’s obligations.

Cash From Investing Activities. Cash flows provided by investing activities for the three months ended September 30, 2013 were approximately $11.4 million, which consisted mainly of $23.2 million proceeds from the sale of our investment in Alta, offset by $11.3 million in capital expenditures for drilling and developing wells and a $0.5 million investment in REX. Cash flows used in investing activities for the three months ended September 30, 2012 were approximately $10.1 million, which consisted mainly of $17.2 million in capital expenditures for drilling and developing wells and an investment of $0.7 million in Alta, partially offset by receiving $7.5 million as a return of capital related to our Exaro investment and $0.3 million as a distribution from REX to its partners.

Cash From Financing Activities. The Company did not have any cash flows from financing activities for the three months ended September 30, 2013 or 2012.

Capital Budget. For the remainder of calendar year 2013, our previously approved capital expenditure budget includes the following:


•	approximately $4.5 million which is the remainder of the total $14.8 million estimate to drill, complete and begin production on our South Timbalier 17 well;


•	approximately $22.5 million to drill our Ship Shoal 255 prospect. Should we be successful, we will have the opportunity to spend significantly more capital to complete development and bring the discovery to producing status; and


•	approximately $18.8 million to purchase our pro-rata interest in the five Dutch wells from a third party, consistent with our preferential right. The sale is expected to close by the end of November 2013.

The total capital program for the fourth calendar quarter will be adjusted to reflect new capital commitments for capital expenditures related to Crimson properties.

As a result of the Merger, we expect to spend significantly more capital to develop Crimson's assets complimented by the selected offshore Gulf of Mexico prospects. Additionally, the Company often reviews acquisitions and prospects presented to us by third parties and we may decide to invest in one or more of these opportunities. There can be no assurance that we will invest, or that any investment we enter into will be successful. These potential investments are not part of our current capital

budget and would require us to invest additional capital. Natural gas and oil prices continue to be volatile and our resources may be insufficient to fund any of these opportunities.

New Credit Facility. In connection with the Merger, the Company assumed and immediately repaid Crimson’s $175.0 million debt with Barclays Bank PLC, $58.6 million debt with Wells Fargo, and $1.8 million in fees and prepayment premiums. In order to pay the assumed debt, the Company entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other lenders (the “RBC Credit Facility”) with an initial hydrocarbon supported borrowing base of $275 million. This facility replaced the Company's $40 million secured revolving Credit Agreement with Amegy Bank ("Amegy Credit Agreement"). The Company incurred $2.2 million of arrangement and upfront fees for the new RBC Credit Facility. Proceeds of the RBC Credit Facility will also be used to (i) finance working capital and for general corporate purposes (including requisitions), (ii) for permitted acquisitions, and (iii) to finance transaction expenses in connection with the RBC Credit Facility and the merger. The RBC Credit Facility is collateralized by substantially all of the assets of the Company and its subsidiaries. Borrowings under the RBC Credit Facility bear interest at a rate that is dependent upon LIBOR or the U.S. prime rate of interest, plus a margin dependent upon the amount outstanding under the facility.

On October 1, 2013, the $235.4 million of assumed debt, accrued interest, and prepayment premium and $2.2 million of arrangement and upfront fees under the RBC Credit Facility were paid off with existing cash of $127.6 million and drawing under our RBC Credit Facility for $110.0 million.

As of November 8, 2013, the Company had borrowed $110.0 million under the RBC Credit Facility, and had cash on hand of $6.2 million.

Natural Gas and Oil Reserves

The following table presents our estimated net proved natural gas and oil reserves at September 30, 2013 and June 30, 2013, based on reserve reports generated by William M. Cobb & Associates, Inc. (“Cobb”) and W.D. Von Gonten and Company ("Von Gonten"). The Company believes that having independent and well respected third-party engineering firms prepare its reserve reports enhances the credibility of its reported reserve estimates.



	Proved Reserves as of
	September 30, 2013	June 30, 2013
Contango Oil & Gas Reserves (1)
Natural Gas (MMcf)	146,701	149,007
Oil, Condensate and Natural Gas Liquids (MBbls)	6,227	6,472
Subtotal (Mmcfe)	184,063	187,839

Reserves Attributable to our 37% Investment in Exaro (2)
Natural Gas (MMcf)	31,910	28,320
Oil, Condensate and Natural Gas Liquids (MBbls)	367	309
Subtotal (Mmcfe)	34,112	30,174

Total (Mmcfe)	218,175	218,013

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

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

Management is responsible for the reserve estimate disclosures in this filing, and members of the Company’s management meet regularly with our independent third-party engineers to review these reserve estimates. Mr. Joseph J. Romano, the Company’s Chief Executive Officer as of September 30, 2013, had primary responsibility for the preparation of the reserve report. Mr. Romano has been in the energy industry for over 35 years, but also relies on others with technical backgrounds in a collaborative effort, all of who provide input to the independent third-party engineers. Mr. Brad Juneau, one of the Company’s directors, monitors production and pressure data daily and provides the majority of the input. Mr. Juneau holds a BS degree in petroleum engineering from Louisiana State University. Mr. Juneau has over 30 years of experience in the oil and gas industry and was a former registered petroleum engineer in the State of Texas. Other executives in accounting and production have advanced degrees and specialty licenses and also provide input to the independent third-party engineers and assist in reviewing the reports.

The qualifications of the technical individuals at Cobb and Von Gonten responsible for overseeing the preparation of our reserve estimates are set forth below.

William M. Cobb & Associates, Inc.


•	Over 30 years of practical experience in the estimation and evaluation of reserves


•	A registered professional engineer in the State of Texas


•	Bachelor of Science Degree in Petroleum Engineering


•	Member in good standing of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

W.D. Von Gonten and Company


•	Over 13 years of practical experience in the estimation and evaluation of reserves


•	A registered professional engineer in the State of Texas


•	Bachelor of Science Degree in Petroleum Engineering


•	Member in good standing of the Society of Petroleum Engineers

Each of Cobb and Von Gonten has informed us that the technical person primarily responsible for the reserve estimates meets or exceeds the education, training, and experience requirements set forth in the standards pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in the application of industry standard practices to engineering evaluations as well as the application of SEC and other industry definitions and guidelines.

We maintain adequate and effective internal controls over the underlying data upon which reserves estimates are based. The primary inputs to the reserve estimation process are comprised of technical information, financial data, ownership interests and production data. All field and reservoir technical information, which is communicated to our reservoir engineer quarterly, is confirmed when our third-party reservoir engineer holds technical meetings with geologists, operations and land personnel to discuss field performance and to validate future development plans. Current revenue and expense information is obtained from our accounting records, which are subject to external quarterly reviews, annual audits and our own set of internal controls over financial reporting. Internal controls over financial reporting are assessed for effectiveness annually using criteria set forth in Internal Controls—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. All data such as commodity prices, lease operating expenses, production taxes, field level commodity price differentials, ownership percentages, and well production data are updated in the reserve database by our third-party reservoir engineer and then analyzed by management to ensure that they have been entered accurately and that all updates are complete. Once the reserve database has been entirely updated with current information, and all relevant technical support material has been assembled, our independent engineering firm prepares the independent reserve estimates and final report.

While we are reasonably certain of recovering our calculated reserves, the process of estimating natural gas and oil reserves is complex. It requires various assumptions, including natural gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our third-party engineer must project production rates and timing of development expenditures, as well as analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves has in the past varied from estimates and will most likely continue to vary in the future. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, our third party engineers may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing natural gas and oil prices and other factors, many of which are beyond our control.

Share Repurchase Program

In September 2011, the Company’s Board of Directors approved a $50 million share repurchase program. All shares are to be purchased in the open market from time to time by the Company or through privately negotiated transactions. The purchases are subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market. No shares were purchased during the three months ended September 30, 2013 or 2012. As of September 30, 2013, the Company had purchased 197,877 shares under the $50 million share repurchase program at an average price of $52.16 per share, plus 45,000 stock options, all for approximately $10.8 million.

Credit Facility

In October 2010, the Company completed the arrangement of a $40 million secured revolving Credit Agreement with Amegy Bank (the “Amegy Credit Agreement”). The Amegy Credit Agreement was supported by a hydrocarbon borrowing base

and was available to fund the Company’s exploration and development activities, as well as repurchase shares of common stock and to fund working capital as needed. The Amegy Credit Agreement was collateralized by substantially all of the assets of the Company. Borrowings under the Amegy Credit Agreement bore interest at LIBOR plus 2.5%, subject to a LIBOR floor of 0.75%. Any principal borrowed was due October 1, 2014, and may be prepaid at any time with no prepayment penalty. An arrangement fee of $300,000 was paid in connection with the facility and effective November 1, 2011, a commitment fee of 0.125% was owed on unused borrowing capacity. The Amegy Credit Agreement contained customary covenants including limitations on our current ratio and additional indebtedness. As of September 30, 2013, the Company was in compliance with all financial covenants and had no borrowings outstanding under the Amegy Credit Agreement.

The credit facility was refinanced in connection with the Merger with Crimson. See Note 9 - "Subsequent Events" for more information.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate and Credit Rating Risk. As of September 30, 2013, we had no long-term debt subject to the risk of loss associated with movements in interest rates.

As of September 30, 2013, we had approximately $137.5 million in cash and cash equivalents, all of which was held in interest bearing investment accounts. Investments in fixed-rate, interest-earning instruments carry a degree of interest rate and credit rating risk. Fixed-rate securities may have their fair market value adversely impacted because of changes in interest rates and credit ratings. Additionally, the value of our investments may be impaired temporarily or permanently. Due in part to these factors, our investment income may decline and we may suffer losses in principal. Currently, we do not use any derivative or other financial instruments or derivative commodity instruments to hedge any market risks, including changes in interest rates or credit ratings, and we do not plan to employ these instruments in the future. Because of the nature of the issuers of the securities that we invest in, we do not believe that we have any cash flow exposure arising from changes in credit ratings. Based on a sensitivity analysis performed on the financial instruments held as of September 30, 2013, an immediate 10% change in interest rates is not expected to have a material effect on our near-term financial condition or results of operations.

Commodity Risk. Our major commodity price risk exposure is to the prices received for our natural gas and oil production. Realized commodity prices received for our production are the spot prices applicable to natural gas and crude oil. Prices received for natural gas and oil are volatile and unpredictable and are beyond our control. For the three months ended September 30, 2013, a 10% fluctuation in the prices received for natural gas and oil production would impact our revenues by approximately $3.5 million.

As a result of the Merger, Contango assumed all Crimson's derivative instruments outstanding as of September 30, 2013, including those transfered to the Company via novation. As of September 30, 2013, the net fair value of Crimson's derivative instruments was approximately $0.3 million.

Item 4. Controls and Procedures

Allan D. Keel, our Chairman, President and Chief Executive Officer, together with our Chief Financial Officer and Chief Accounting Officer, carried out an evaluation of the effectiveness of the Company’s “disclosure controls and procedures” as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of September 30, 2013. Based upon that evaluation, the Company’s management concluded that, as of September 30, 2013, the Company’s disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and to ensure that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our President and Chief Executive Officer, Chief Financial Officer, and Chief Accounting Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in the Company’s internal control over financial reporting that occurred during the fiscal quarter ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Several class action lawsuits have been brought by Crimson stockholders in Delaware Chancery Court challenging the proposed Merger and seeking, among other things, injunctive relief to enjoin the defendants from completing the Merger on the agreed-upon terms, compensatory damages, and costs and disbursements relating to the lawsuits. Various combinations of Crimson, Contango, members of Crimson’s board of directors, members of Crimson management, and Oaktree Capital

Management L.P. have been named as defendants in these lawsuits. These lawsuits have been consolidated into a single action for all purposes referred to as In Re: Crimson Exploration Inc. Stockholder Litigation; C.A. 8541-VCP.

Additionally, on July 13, 2013, a separate and similar complaint was filed in the District Court of Harris County Texas, in the matter of Fisichella Family Trust v. Crimson Exploration Inc.

The known plaintiffs in these lawsuits, based on the most current information provided by Crimson, collectively own a very small percentage of the total outstanding shares of Crimson common stock. The lawsuits allege, among other things, that Crimson’s board of directors failed to take steps to obtain a fair price, failed to properly value Crimson, failed to protect against alleged conflicts of interest, failed to conduct a reasonably informed evaluation of whether the transaction was in the best interests of stockholders, failed to fully disclose all material information to stockholders, acted in bad faith and for improper motives, engaged in self-dealing, discouraged other strategic alternatives, took steps to avoid competitive bidding, and agreed to allegedly unreasonable deal protection mechanisms, including the no-shop and fiduciary-out provisions and termination fee. The lawsuits also allege that Contango aided and abetted the other defendants in violating duties to the Crimson stockholders. The lawsuits seek damages and injunctive relief.

Contango and Crimson believe that these lawsuits are without merit and intend to contest them vigorously.

Item 1A. Risk Factors

For discussion regarding our risk factors, see Item 1 of Part 1 of our Annual Report on Form 10-K for the fiscal year ended June 30, 2013, and the Risk Factors included in the Registration Statement on Form S-4 as filed with the SEC on June 13, 2013. Those risk and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks and uncertainties could adversely affect our business, financial condition, and/or results of operations

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

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

Item 3. Defaults upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

(a) Exhibits:

The exhibits listed on the accompanying Exhibit Index are filed, furnished, or incorporated by reference as part of this report, and such Exhibit Index is incorporated herein by reference.

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: November 12, 2013	By:	/S/ ALLAN D. KEEL
		Allan D. Keel President and Chief Executive Officer (Principal Executive Officer)

Date: November 12, 2013	By:	/S/ E. JOSEPH GRADY
		E. Joseph Grady Senior Vice President and Chief Financial Officer (Principal Financial Officer)

Date: November 12, 2013	By:	/S/ YAROSLAVA MAKALSKAYA
		Yaroslava Makalskaya Vice President, Chief Accounting Officer and Controller (Principal Accounting Officer)




Exhibit Number			Description

2.1*			Agreement and Plan of Merger, dated as of April 29, 2013, by and among Contango Oil & Gas Company, Contango Acquisition, Inc. and Crimson Exploration Inc. (3)
3.1			Certificate of Incorporation of Contango Oil & Gas Company. (1)
3.2			Bylaws of Contango Oil & Gas Company. (1)
3.4			Amendment to the Certificate of Incorporation of Contango Oil & Gas Company. (2)
10.1			Credit Agreement among Contango Oil & Gas Company, as Borrower, Royal Bank of Canada, as Administrative Agent, and The Lenders Signatory Hereto dated October 1, 2013. (4)
23.1			Consent of William M. Cobb & Associates, Inc. †
23.2			Consent of W.D. Von Gonten & Company †
31.1			Certification of Chief Executive Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. †
31.2			Certification of Chief Financial Officer required by Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934. †
32.1			Certification of Chief Executive Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ††
32.2			Certification of Chief Financial Officer pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. ††
101			Interactive Data Files †



†	Filed herewith.

††	Furnished herewith.

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



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



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



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



4.	Filed as an exhibit to the Company’s Current Report on Form 8-K dated as of October 1, 2013, as filed with the Securities and Exchange Commission on October 2, 2013.