Contango Oil & Gas (MCF) 10-Q 10 May 17 2017 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 05, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Entity Registrant Name	Contango Oil & Gas Company
Entity Central Index Key	1,071,993
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		25,572,245
Entity Current Reporting Status	Yes

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net	11,825	16,727
Prepaid expenses	796	1,787
Current derivative asset	931
Inventory	540	540
Total current assets	14,092	19,054
Natural gas and oil properties, successful efforts method of accounting:
Proved properties	1,193,574	1,188,065
Unproved properties	45,735	38,338
Other property and equipment	1,279	1,265
Accumulated depreciation, depletion and amortization	(895,946)	(887,286)
Total property, plant and equipment, net	344,642	340,382
OTHER NON-CURRENT ASSETS:
Investments in affiliates	17,551	15,767
Other	1,193	1,311
Total other non-current assets	18,744	17,078
TOTAL ASSETS	377,478	376,514
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	52,958	55,135
Current derivative liability	1,103	3,446
Current asset retirement obligations	4,826	4,308
Total current liabilities	58,887	62,889
NON-CURRENT LIABILITIES:
Long-term debt	59,722	54,354
Asset retirement obligations	19,949	22,618
Other long term liabilities	248	248
Total non-current liabilities	79,919	77,220
Total liabilities	138,806	140,109
COMMITMENTS AND CONTINGENCIES (NOTE 12)
SHAREHOLDERS' EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 30,563,743 shares issued and 25,232,489 shares outstanding at March 31, 2017, 30,557,987 shares issued and 25,238,600 shares outstanding at December 31, 2016	1,211	1,211
Additional paid-in capital	297,895	296,439
Treasury shares at cost (5,331,254 shares at March 31, 2017 and 5,319,387 shares at December 31, 2016)	(128,395)	(128,321)
Retained earnings	67,961	67,076
Total shareholders' equity	238,672	236,405
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 377,478	$ 376,514

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.04	$ 0.04
Common stock, shares authorized	50,000,000	50,000,000
Common stock, shares issued	30,563,743	30,557,987
Common stock, shares outstanding	25,232,489	25,238,600
Treasury stock, shares	5,331,254	5,319,387

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
REVENUES:
Oil and condensate sales	$ 5,542	$ 5,247
Natural gas sales	11,140	9,935
Natural gas liquids sales	2,742	2,400
Total revenues	19,424	17,582
EXPENSES:
Operating expenses	6,833	7,604
Exploration expenses	91	320
Depreciation, depletion and amortization	11,771	16,545
Impairment and abandonment of oil and gas properties	30	1,851
General and administrative expenses	6,596	5,902
Total expenses	25,321	32,222
OTHER INCOME (EXPENSE):
Gain from investment in affiliates, net of income taxes	1,784	40
Gain from sale of assets	2,940
Interest expense	(759)	(878)
Gain on derivatives, net	3,096	4,204
Other expense	(88)	(40)
Total other income	6,973	3,326
NET INCOME (LOSS) BEFORE INCOME TAXES	1,076	(11,314)
Income tax provision	(191)	(90)
NET INCOME (LOSS)	$ 885	$ (11,404)
NET INCOME (LOSS) PER SHARE:
Basic (in dollars per share)	$ 0.04	$ (0.60)
Diluted (in dollars per share)	$ 0.04	$ (0.60)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic (in shares)	24,607	19,079
Diluted (in shares)	24,641	19,079

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 885	$ (11,404)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	11,771	16,545
Impairment of natural gas and oil properties		1,872
Exploration recovery	(232)	(58)
Gain on sale of assets	(2,940)
Gain from investment in affiliates	(1,784)	(40)
Stock-based compensation	1,456	1,699
Unrealized gain on derivative instruments	(3,275)	(2,696)
Changes in operating assets and liabilities:
Decrease in accounts receivable & other receivables	4,840	6,971
Decrease in prepaids	991	372
Increase (decrease) in accounts payable & advances from joint owners	3,869	(5,458)
Increase (decrease) in other accrued liabilities	(973)	175
Decrease in income taxes receivable, net	188	368
Other	61	(18)
Net cash provided by operating activities	14,857	8,328
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	(20,807)	(4,836)
Additions to furniture & equipment	(14)
Sale of oil and gas properties	670
Net cash used in investing activities	(20,151)	(4,836)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	54,963	45,167
Repayments under credit facility	(49,595)	(48,431)
Purchase of treasury stock	(74)	(228)
Net cash provided by (used in) financing activities	5,294	(3,492)
NET CHANGE IN CASH AND CASH EQUIVALENTS
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD
CASH AND CASH EQUIVALENTS, END OF PERIOD

Consolidated Statement Of Share

Consolidated Statement Of Shareholders Equity - 3 months ended Mar. 31, 2017 - USD ($) $ in Thousands	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Total
Balance at Dec. 31, 2016	$ 1,211	$ 296,439	$ (128,321)	$ 67,076	$ 236,405
Balance, shares at Dec. 31, 2016	25,238,600				25,238,600
Treasury shares at cost			(74)		$ (74)
Treasury shares at cost, shares	(11,867)
Restricted shares activity, shares	5,756
Stock-based compensation		1,456			1,456
Net income				885	885
Balance at Mar. 31, 2017	$ 1,211	$ 297,895	$ (128,395)	$ 67,961	$ 238,672
Balance, shares at Mar. 31, 2017	25,232,489				25,232,489

Organization And Business

Organization And Business	3 Months Ended
	Mar. 31, 2017
Organization And Business [Abstract]
Organization And Business	1. Organization and Business Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based, independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its onshore properties in Texas and Wyoming and offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and to use that cash flow to explore, develop, exploit, produce and acquire crude oil and natural gas properties in the Texas and Rocky Mountain regions of the United States. The following table lists the Company’s primary producing areas as of March 31, 2017: Location Formation Gulf of Mexico Offshore Louisiana - water depths less than 300 feet Madison and Grimes counties, Texas Woodbine (Upper Lewisville) Zavala and Dimmit counties, Texas Buda / Austin Chalk Weston County, Wyoming Muddy Sandstone Pecos County, Texas Southern Delaware Basin (Wolfcamp) Texas Gulf Coast Conventional and unconventional formations Sublette County, Wyoming Jonah Field (1) (1) Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this investment is not included in the Company’s reported production results for the three months ended March 31, 2017. In July 2016, the Company purchased approximately 12,100 gross operated undeveloped acres (5,000 net acres) in the Southern Delaware Basin in Pecos County, Texas (the “Acquisition”), which it began drilling during the fourth quarter of 2016, and as of March 31, 2017, had increased its acreage to 13,400 gross operated acres (6,700 net). The Company’s 2017 capital expenditure program is expected to be focused on its newly acquired West Texas acreage. The Company’s 2017 capital program will focus on: (i) the development of its Southern Delaware Basin acreage; (ii) the preservation of its healthy financial position; (iii) identification of opportunities for cost efficiencies in all areas of its operations; and (iv) maintaining core leases and continuing to identify new resource potential opportunities internally and, where appropriate, through acquisition. The Company will continuously monitor the commodity price environment, stability and forecast, and, if warranted, make adjustments to its strategy as the year progresses.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2017
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	2. Summary of Significant Accounting Policies The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2016 (the “2016 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2016 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this report. 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 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 2016 Form 10-K. The consolidated results of operations for the quarter ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated. The investment in Exaro by our wholly-owned subsidiary, Contaro Company (“Contaro”) is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, reserves or production in those reported for the Company’s consolidated results. Oil and Gas Properties - Successful Efforts Our application of the successful efforts method of accounting for our natural gas and oil exploration and production 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. Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized no impairment of proved properties for the quarter ended March 31, 2017 and approximately $0.7 million impairment of proved properties for the quarter ended March 31, 2016. Substantially all of the non-cash impairment charge in the quarter ended March 31, 2016 was directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. 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. The Company recognized no impairment of unproved properties for the quarter ended March 31, 2017. The Company recognized impairment expense of approximately $1.1 million for the quarter ended March 31, 2016, related to partial impairment of certain unproved properties due primarily to the sustained low commodity price environment and expiring leases; substantially all of which was related to unproved lease cost amortization of the properties in Fayette and Gonzales counties Texas. Net Income (Loss) Per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For the quarter ended March 31, 2017, the weighted average incremental shares for restricted stock were 33,475, and the weighted average incremental shares for Performance Stock Units (“PSUs”) were 564 shares. Potential dilutive securities, including unexercised stock options, PSUs and unvested restricted stock, have not been considered when their effect would be antidilutive. For the quarter ended March 31, 2017, 97,319 stock options, 553,019 restricted shares and 267,399 PSUs were excluded from dilutive shares as they were antidilutive. For the quarter ended March 31, 2016, 116,461 stock options and 284,528 restricted shares were excluded from dilutive shares due to the loss for the period. Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly-owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly-owned subsidiary that is inactive and not a Subsidiary Guarantor. Finally, the Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. Recent Accounting Pronouncements In January 2017, the FASB issued ASU No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (ASU 201701). The amendments in this update are intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. Public business entities should apply the amendments in this update to annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations. In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishment costs; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after a business combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity method investees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the Company’s presentation of cash flows. In March 2016, the FASB issued ASU No. 2016-09: Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 is part of an initiative to reduce complexity in accounting standards. The areas of simplification in ASU 2016-09 involve several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, ASU 2016-09 is effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years; early application is permitted. The provisions of this accounting update did not have a material impact on the Company’s financial position, results of operations or cash flows. In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Several additional standards related to revenue recognition have been issued that amend the original standard, with most providing additional clarification. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company is currently determining the impact of the new revenue recognition standard on its contracts. The Company’s revenue contracts are primarily normal purchase/sale contracts and as such, the Company does not expect that the new revenue recognition standard will have a material impact on the Company’s financial statements upon adoption. The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized at the date of the adoption of the standard.

Acquisitions and Dispositions

Acquisitions and Dispositions	3 Months Ended
	Mar. 31, 2017
Business Combinations [Abstract]
Acquisitions and Dispositions	3. Acquisitions and Dispositions In the July 2016 Acquisition, the Company purchased one-half of the seller’s interest in approximately 12,100 gross undeveloped acres (approximately 5,000 net acres) in the Southern Delaware Basin of Texas for up to $25 million. The purchase price was comprised of $10 million in cash paid on July 26, 2016, plus $10 million in carried well costs expected to be paid over the period of drilling and completion of the first six wells, plus, contingent upon success, $5 million for spud bonuses to be paid ratably over the next 14 wells actually drilled, which would increase the total consideration to $25 million. As of March 31, 2017, the Company had increased its acreage to 13,400 gross operated acres (6,700 net). On December 30, 2016, all of the Company’s non-core Colorado assets were sold to an independent oil and gas company for an aggregate purchase price of $5.0 million, subject to normal post-closing adjustments. The properties consisted of the Company’s approximately 16,000 gross (11,200 net) acres primarily in Adams and Weld counties, Colorado and associated producing vertical wells. Effective February 1, 2017, the Company sold to a third party all of its assets in the Bob West North area and its operated assets in the Escobas area, both located in Southeast Texas. The Company recorded a net gain of $2.9 million after removal of the asset retirement obligations associated with the sold properties.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2017
Fair Value Measurements [Abstract]
Fair Value Measurements	4. Fair Value Measurements Pursuant to Accounting Standards Codification 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of March 31, 2017. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3. Fair value information for financial assets and liabilities was as follows as of March 31, 2017 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 931 $ — $ 931 $ — Commodity price contracts - liabilities $ (1,103) $ — $ (1,103) $ — Derivatives listed above are recorded in “Current and long-term derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gain on derivatives, net" in the Company's consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves. See Note 5 - "Derivative Instruments" for additional discussion of derivatives. As of March 31, 2017, the Company's derivative contracts were with certain members of its bank group which are major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's credit facility with the Royal Bank of Canada and other lenders (the “RBC Credit Facility”) approximates carrying value because the facility interest rate approximates current market rates and is reset at least every six months. See Note 9 - "Long-Term Debt" for further information. Impairments Contango tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure. Asset Retirement Obligations The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves.

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2017
Derivative Instruments [Abstract]
Derivative Instruments	5. Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts. As of March 31, 2017, the Company’s natural gas and oil derivative positions consisted of “swaps” and “costless collars”. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract. It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is exposed to potential margin calls, under any of these contracts as they are secured under the RBC Credit Facility. See Note 9 - "Long-Term Debt" for further information regarding the RBC Credit Facility. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in "Gain on derivatives, net" on the consolidated statements of operations. The following derivative instruments were in place at March 31, 2017 (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit (1) Fair Value Natural Gas Apr - July 2017 Collar 400,000 MMBtu $ 2.65 - 3.00 Natural Gas Aug 2017 - Oct 2017 Collar 200,000 MMBtu $ 2.65 - 3.00 Natural Gas Nov 2017 - Dec 2017 Collar 400,000 MMBtu $ 2.65 - 3.00 Natural Gas Apr - July 2017 Swap 300,000 MMBtu $ Natural Gas Aug 2017 - Oct 2017 Swap 70,000 MMBtu $ Natural Gas Nov 2017 - Dec 2017 Swap 300,000 MMBtu $ Oil Apr - July 2017 Swap 9,000 Bbls $ Oil Aug 2017 - Oct 2017 Swap 6,000 Bbls $ Oil Nov 2017 - Dec 2017 Swap 8,000 Bbls $ Oil Apr - Dec 2017 Swap 9,000 Bbls $ Total net fair value of derivative instruments $ (172) (1) Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of March 31, 2017 (in thousands): Gross Netting (1) Total Assets $ 931 $ (931) $ — Liabilities $ (1,103) $ 931 $ (172) (1) Represents counterparty netting under agreements governing such derivatives. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2016 (in thousands): Gross Netting (1) Total Assets $ — $ — $ — Liabilities $ (3,446) $ — $ (3,446) (1) Represents counterparty netting under agreements governing such derivatives. The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the quarters ended March 31, 2017 and 2016 (in thousands): Three Months Ended March 31, 2017 2016 Crude oil contracts $ 170 $ — Natural gas contracts (349) 1,508 Realized gain (loss) $ (179) $ 1,508 Crude oil contracts $ 524 $ — Natural gas contracts 2,751 2,696 Unrealized gain (loss) $ 3,275 $ 2,696 Gain on derivatives, net $ 3,096 $ 4,204

Stock-Based Compensation

Stock-Based Compensation	3 Months Ended
	Mar. 31, 2017
Stock-Based Compensation [Abstract]
Stock-Based Compensation	6. Stock-Based Compensation Stock Options Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the quarters ended March 31, 2017 and 2016, there was no excess tax benefit recognized. Compensation expense related to stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted during the quarters ended March 31, 2017 or 2016. During the quarter ended March 31, 2017, no stock options were exercised and 14,586 stock options were forfeited by former employees. During the quarter ended March 31, 2016, no stock options were exercised or forfeited. Restricted Stock During the quarter ended March 31, 2017, the Company granted 30,000 shares of restricted common stock, which vest over three years, to a newly hired employee as part of his overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2017, was $7.78 with a total fair value of approximately $0.2 million after adjustment for an estimated weighted average forfeiture rate of 5.8%. During the quarter ended March 31, 2017, 24,244 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2017 was approximately $256 thousand. Approximately 0.3 million shares remained available for grant under the Amended and Restated 2009 Incentive Compensation Plan as of March 31, 2017, excluding 297,399 PSUs outstanding. During the quarter ended March 31, 2016, the Company granted 40,688 immediately vested shares of restricted common stock. Of these, 38,943 shares were granted to employees and 1,745 shares were granted to directors, all of which were issued pursuant to the Company’s salary replacement program (the “Salary Replacement Program) which temporarily deferred 10% of 2015 employee salaries and director fees. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2016, was $6.40 with a total fair value of approximately $0.3 million after adjustment for an estimated weighted average forfeiture rate of 0.0%. During the quarter ended March 31, 2016, 40 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2016 was approximately $1 thousand. The Company recognized approximately $1.5 million and $1.7 million in stock compensation expense during the quarters ended March 31, 2017 and 2016, respectively, for restricted shares granted to its officers, employees and directors. As of March 31, 2017, an additional $5.6 million of compensation expense remained to be recognized over the remaining weighted-average vesting period of 3.9 years. Additionally, in April 2017, the Company granted 338,560 restricted stock awards to employees as part of their overall compensation package. Performance Stock Units During the quarter ended March 31, 2017, the Company issued 30,000 PSUs to a new employee, at a fair value of $8.32 per unit using the Monte Carlo simulation model. No PSUs were issued during the quarter ended March 31, 2016. PSUs represent the opportunity to receive shares of the Company's common stock at the time of settlement. The number of shares to be awarded upon settlement of these PSUs may range from 0% to 200% of the number of PSUs awarded contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PSUs vest and settlement is determined after a three year period. Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee of the Company’s board of directors intends to settle the PSUs with shares of the Company's common stock after three years, the PSU awards are accounted for as equity awards and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award. Additionally, in April 2017, the Company granted 160,908 PSUs to executives as part of their overall compensation package.

Other Financial Information

Other Financial Information	3 Months Ended
	Mar. 31, 2017
Other Financial Information [Abstract]
Other Financial Information	7. Other Financial Information The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): March 31, 2017 December 31, 2016 Accounts receivable: Trade receivables $ 6,533 $ 8,424 Receivable for Alta Resources Distribution 1,993 1,993 Joint interest billings 3,269 3,519 Income taxes receivable 91 91 Other receivables 695 3,395 Allowance for doubtful accounts (756) (695) Total accounts receivable $ 11,825 $ 16,727 Prepaid expenses and other: Prepaid insurance $ 357 $ 1,086 Other 439 701 Total prepaid expenses and other $ 796 $ 1,787 Accounts payable and accrued liabilities: Royalties and revenue payable $ 16,384 $ 16,920 Advances from partners 9,756 5,792 Accrued exploration and development 9,737 11,176 Accrued carried well costs 3,333 7,155 Trade payables 6,934 5,406 Accrued LOE & workover expense 1,390 1,867 Accrued G&A and legal expense 2,918 5,016 Other accounts payable and accrued liabilities 2,506 1,803 Total accounts payable and accrued liabilities $ 52,958 $ 55,135 Included in the table below is supplemental information about certain cash and non-cash transactions during the three months ended March 31, 2017 and 2016 (in thousands): Three Months Ended March 31, 2017 2016 Cash payments: Interest payments $ 760 $ 879 Income tax payments (refunds) $ 3 $ (351) Non-cash investing activities in the consolidated statements of cash flows: Decrease in accrued capital expenditures $ (5,261) $ (1,222)

Investment In Exaro Energy III

Investment In Exaro Energy III LLC	3 Months Ended
	Mar. 31, 2017
Investment In Exaro Energy III LLC [Abstract]
Investment In Exaro Energy III LLC	8. Investment in Exaro Energy III LLC The Company maintains an ownership interest in Exaro of approximately 37%. The following table (in thousands) presents condensed balance sheet data for Exaro as of March 31, 2017 and December 31, 2016. The balance sheet data was derived from Exaro’s balance sheet as of March 31, 2017 and December 31, 2016 and was not adjusted to represent the Company’s percentage of ownership interest in Exaro. The Company’s share in the equity of Exaro at March 31, 2017 was approximately $17.5 million. March 31, 2017 December 31, 2016 Current assets (1) $ 22,500 $ 25,296 Non-current assets: Net property and equipment 88,545 90,621 Gas processing deposit 1,150 1,150 Other non-current assets 430 8 Total non-current assets 90,125 91,779 Total assets $ 112,625 $ 117,075 Current liabilities (2) $ 61,328 $ 65,694 Non-current liabilities: Long-term debt — — Other non-current liabilities 3,370 8,106 Total non-current liabilities 3,370 8,106 Members' equity 47,927 43,275 Total liabilities & members' equity $ 112,625 $ 117,075 (1) Approximately $18.8 million and $19.6 million of current assets as of March 31, 2017 and December 31, 2016, respectively, is cash. (1) Approximately $54.4 million and $59.3 million of current liabilities as of March 31, 2017 and December 31, 2016, respectively, are attributable to the senior loan facility maturing September 26, 2017. The following table (in thousands) presents the condensed results of operations for Exaro for the quarter ended March 31, 2017 and 2016. The results of operations for the quarter ended March 31, 2017 and 2016 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent the Company’s ownership interest but rather reflects the results of Exaro as a company. The Company’s share in Exaro’s results of operations recognized for the quarter ended March 31, 2017 and 2016 was a gain of $1.8 million, net of no tax expense, and a gain of $40 thousand, net of an insignificant tax expense, respectively. Three Months Ended March 31, 2017 2016 Production: Oil (thousand barrels) 25 36 Gas (million cubic feet) 2,308 2,774 Total (million cubic feet equivalent) 2,460 2,991 Oil and natural gas sales $ 9,171 $ 6,312 Gain on derivatives 2,562 — Other gain — 2,102 Less: Lease operating expenses 3,219 3,557 Depreciation, depletion, amortization & accretion 2,343 3,006 General & administrative expense 733 808 Income from continuing operations 5,438 1,043 Net interest expense (624) (693) Net income $ 4,814 $ 350 Exaro's results of operations do not include income taxes because Exaro is treated as a partnership for tax purposes.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2017
Long-Term Debt [Abstract]
Long-Term Debt	9. Long-Term Debt RBC Credit Facility In October 2013, the Company entered into a $500 million four-year revolving credit facility with Royal Bank of Canada and other lenders, which currently has an October 1 2019 maturity date. The borrowing base under the facility is redetermined each November 1 and May 1. As of March 31, 2017, the borrowing base under the RBC Credit Facility was $140 million. Effective May 4, 2017, as part of the regular redetermination schedule, the borrowing base under the RBC Credit Facility was redetermined at $125 million. As of March 31, 2017, the Company had approximately $59.7 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2016, the Company had approximately $54.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of March 31, 2017, borrowing availability under the RBC Credit Facility was $78.4 million. Total interest expense under the RBC Credit Facility, including commitment fees, for the quarter ended March 31, 2017 was approximately $0.8 million. Total interest expense under the RBC Credit Facility, including commitment fees, for the quarter ended March 31, 2016 was approximately $0.9 million. The RBC Credit Facility contains restrictive covenants which, among other things, restrict the declaration or payment of dividends by Contango and require a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the RBC Credit Facility Agreement. As of March 31, 2017, the Company was in compliance with all financial covenants under the RBC Credit Facility, and at current commodity prices, does not expect any covenant compliance issues over the next twelve months. The RBC Credit Facility also contains events of default that may accelerate repayment of any borrowings and/or termination of the facility. Events of default include, but are not limited to, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. The weighted average interest rate in effect at March 31, 2017 and December 31, 2016 was 4.3% and 4.2%, respectively. The RBC Credit Facility matures on October 1, 2019, at which time any outstanding balances will be due.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2017
Income Taxes [Abstract]
Income Taxes	10. Income Taxes The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended March 31, 2017 2016 Current tax provision: Federal $ — $ — State 191 90 Total $ 191 $ 90 Total tax provision: Federal $ — $ — State 191 90 Total $ 191 $ 90 Included in gain from investment in affiliates $ — $ — Total income tax provision $ 191 $ 90 In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the quarter ended March 31, 2017, the Company continues to fully value the net deferred tax asset. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	11. Related Party Transactions Olympic Energy Partners Mr. Joseph J. Romano, the Chairman of the Company’s board of directors, is also the President and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic"). Olympic participated with the Company in the drilling of wells in March 2010, and its ownership in Company-operated wells is limited to our Dutch and Mary Rose wells. During the quarters ended March 31, 2016 and 2017 Mr. Romano earned $14 thousand for his service as a director of the Company. During the quarter ended March 31, 2016, Mr. Romano received 261 shares of restricted stock, which vested immediately, pursuant to the Salary Replacement Program. The Company recognized compensation expense of approximately $19 thousand related to the shares granted to Mr. Romano for the quarter ended March 31, 2016. No restricted stock was issued during the quarter ended March 31, 2017. Below is a summary of payments received from (paid to) Olympic in the ordinary course of business in the Company’s capacity as operator of the wells and platforms for the periods indicated. The Company made and received similar types of payments with other well owners (in thousands): Three Months Ended March 31, 2017 2016 Revenue payments as well owners $ (764) $ (648) Joint interest billing receipts 113 62 As of March 31, 2017 and December 31, 2016, the Company's consolidated balance sheets reflected the following balances relating to Olympic (in thousands): March 31, 2017 December 31, 2016 Accounts receivable: Joint interest billing $ 42 $ 59 Accounts payable: Royalties and revenue payable (456) (557) Oaktree Capital Management L.P. As of March 31, 2017, Oaktree Capital Management L.P. ("Oaktree"), through various funds, owned approximately 5.1% of the Company's stock. On October 1, 2013, Mr. James Ford, then a Managing Director and Portfolio Manager within Oaktree, was elected to the Company's board of directors. Mr. Ford is currently a Senior Advisor to Oaktree. Historically, all cash and equity awards payable to Mr. Ford were instead granted to an affiliate of Oaktree. Beginning in 2016, all cash and equity awards payable to Mr. Ford were paid to him directly. During the quarter ended March 31, 2017, Mr. Ford earned $17 thousand in cash as a result of his board participation. During the quarter ended March 31, 2016, an affiliate of Oaktree earned $17 thousand in cash as a result of Mr. Ford's board participation. During the quarter ended March 31, 2016, an affiliate of Oaktree received 313 shares of restricted stock, which vested immediately, pursuant to the Salary Replacement Program. The Company recognized compensation expense of approximately $19 thousand related to the shares granted to an affiliate of Oaktree for the quarter ended March 31, 2016. No restricted stock was issued to Mr. Ford during the quarter ended March 31, 2017.

Commitments And Contingencies

Commitments And Contingencies	3 Months Ended
	Mar. 31, 2017
Commitments And Contingencies [Abstract]
Commitments And Contingencies	12. Commitments and Contingencies Legal Proceedings From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below. In July 2010, several parties associated with a limited partnership, formed to invest in oil and gas properties, that was dissolved in 1995 filed suit against a subsidiary of the Company and several co-defendants in district court for Madison County in Texas. The plaintiffs claim to own or have rights in certain oil and gas properties situated in Madison County, Texas by virtue of the partnership having interests in addition to those it held of record at the time of its dissolution, which were distributed to the partners in connection with such dissolution. A predecessor of the subsidiary of the Company involved in this case acquired a portion of the interests now claimed by the plaintiffs from a successor to the general partner of the aforementioned partnership in 2000. The plaintiffs’ expert has provided a range of estimated monetary damages of up to approximately $9.4 million as to the Company’s subsidiary. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses. In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decade-old poorly documented transactions. Based on prior summary judgments, the trial court has entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company is vigorously defending this lawsuit, believes that it has meritorious defenses and is appealing the trial court’s decision to the applicable state Court of Appeals. In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by the Company in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds. The plaintiff is appealing the trial court’s decision to the applicable state Court of Appeals. The Company is vigorously defending this lawsuit and believes that it has meritorious defenses. The Company believes if this matter were to be determined adversely, amounts owed to the plaintiff could be partially offset by recoupment rights the Company may have against other working interest and/or royalty interest owners in the unit. While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely. Throughput Contract Commitment The Company signed a throughput agreement with a third party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. The Company currently forecasts that monthly gas volume deliveries through this line in its Southeast Texas area will not meet minimum throughput requirements under the agreement. Without further development in that area, the volume deficiency will continue through the expiration of the throughput commitment in March 2020. The throughput deficiency fee is paid in April of each calendar year. As of March 31, 2017, the Company estimates that the net deficiency fee will be in the range of $1.5 to $1.6 million annually for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. Based upon the current commodity price market and our short term strategic drilling plans, the Company recorded a loss contingency of $1.5 million as of March 31, 2017. The Company will continue to assess this commitment in light of its development plans for this area.

Summary Of Significant Accoun19

Summary Of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2017
Summary Of Significant Accounting Policies [Abstract]
Basis Of Presentation	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 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 2016 Form 10-K. The consolidated results of operations for the quarter ended March 31, 2017 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.
Principles Of Consolidation	The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated. The investment in Exaro by our wholly-owned subsidiary, Contaro Company (“Contaro”) is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results, reserves or production in those reported for the Company’s consolidated results.
Oil and Gas Properties - Successful Efforts	Oil and Gas Properties - Successful Efforts Our application of the successful efforts method of accounting for our natural gas and oil exploration and production 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.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. The Company recognized no impairment of proved properties for the quarter ended March 31, 2017 and approximately $0.7 million impairment of proved properties for the quarter ended March 31, 2016. Substantially all of the non-cash impairment charge in the quarter ended March 31, 2016 was directly related to the decline in commodity prices and the resulting impact on estimated future net cash flows from associated reserves. 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. The Company recognized no impairment of unproved properties for the quarter ended March 31, 2017. The Company recognized impairment expense of approximately $1.1 million for the quarter ended March 31, 2016, related to partial impairment of certain unproved properties due primarily to the sustained low commodity price environment and expiring leases; substantially all of which was related to unproved lease cost amortization of the properties in Fayette and Gonzales counties Texas.
Net Income (Loss) Per Common Share	Net Income (Loss) Per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For the quarter ended March 31, 2017, the weighted average incremental shares for restricted stock were 33,475, and the weighted average incremental shares for Performance Stock Units (“PSUs”) were 564 shares. Potential dilutive securities, including unexercised stock options, PSUs and unvested restricted stock, have not been considered when their effect would be antidilutive. For the quarter ended March 31, 2017, 97,319 stock options, 553,019 restricted shares and 267,399 PSUs were excluded from dilutive shares as they were antidilutive. For the quarter ended March 31, 2016, 116,461 stock options and 284,528 restricted shares were excluded from dilutive shares due to the loss for the period.
Subsidiary Guarantees	Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly-owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly-owned subsidiary that is inactive and not a Subsidiary Guarantor. Finally, the Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In January 2017, the FASB issued ASU No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (ASU 201701). The amendments in this update are intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. Public business entities should apply the amendments in this update to annual periods beginning after December 15, 2017, including interim periods within those periods. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations. In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishment costs; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after a business combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity method investees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The provisions of this accounting update are not expected to have a material impact on the Company’s presentation of cash flows. In March 2016, the FASB issued ASU No. 2016-09: Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (ASU 2016-09). ASU 2016-09 is part of an initiative to reduce complexity in accounting standards. The areas of simplification in ASU 2016-09 involve several aspects of accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. For public entities, ASU 2016-09 is effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years; early application is permitted. The provisions of this accounting update did not have a material impact on the Company’s financial position, results of operations or cash flows. In February 2016, the FASB issued ASU No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company will continue to assess the impact this may have on its financial position, results of operations, and cash flows. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. Several additional standards related to revenue recognition have been issued that amend the original standard, with most providing additional clarification. The provisions of this accounting update are not expected to have a material impact on the Company’s financial position or results of operations. In August 2015, the FASB issued ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” which deferred the effective date of ASU 2014-09 by one year. That new standard is now effective for annual reporting periods beginning after December 15, 2017. The Company is currently determining the impact of the new revenue recognition standard on its contracts. The Company’s revenue contracts are primarily normal purchase/sale contracts and as such, the Company does not expect that the new revenue recognition standard will have a material impact on the Company’s financial statements upon adoption. The Company expects to use the modified retrospective method to adopt the standard, meaning the cumulative effect of initially applying the standard will be recognized at the date of the adoption of the standard.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Measurements [Abstract]
Schedule Of Fair Value Of Financial Assets And (Liabilities)	Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 931 $ — $ 931 $ — Commodity price contracts - liabilities $ (1,103) $ — $ (1,103) $ —

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2017
Derivative Instruments [Abstract]
Schedule Of Derivative Contracts	The following derivative instruments were in place at March 31, 2017 (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit (1) Fair Value Natural Gas Apr - July 2017 Collar 400,000 MMBtu $ 2.65 - 3.00 Natural Gas Aug 2017 - Oct 2017 Collar 200,000 MMBtu $ 2.65 - 3.00 Natural Gas Nov 2017 - Dec 2017 Collar 400,000 MMBtu $ 2.65 - 3.00 Natural Gas Apr - July 2017 Swap 300,000 MMBtu $ Natural Gas Aug 2017 - Oct 2017 Swap 70,000 MMBtu $ Natural Gas Nov 2017 - Dec 2017 Swap 300,000 MMBtu $ Oil Apr - July 2017 Swap 9,000 Bbls $ Oil Aug 2017 - Oct 2017 Swap 6,000 Bbls $ Oil Nov 2017 - Dec 2017 Swap 8,000 Bbls $ Oil Apr - Dec 2017 Swap 9,000 Bbls $ Total net fair value of derivative instruments $ (172) (1) Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable.
Schedule Of Fair Value Of Commodity Derivatives	The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of March 31, 2017 (in thousands): Gross Netting (1) Total Assets $ 931 $ (931) $ — Liabilities $ (1,103) $ 931 $ (172) (1) Represents counterparty netting under agreements governing such derivatives. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2016 (in thousands): Gross Netting (1) Total Assets $ — $ — $ — Liabilities $ (3,446) $ — $ (3,446) (1) Represents counterparty netting under agreements governing such derivatives.
Schedule Of Derivative Contracts On Operations	The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the quarters ended March 31, 2017 and 2016 (in thousands): Three Months Ended March 31, 2017 2016 Crude oil contracts $ 170 $ — Natural gas contracts (349) 1,508 Realized gain (loss) $ (179) $ 1,508 Crude oil contracts $ 524 $ — Natural gas contracts 2,751 2,696 Unrealized gain (loss) $ 3,275 $ 2,696 Gain on derivatives, net $ 3,096 $ 4,204

Other Financial Information (Ta

Other Financial Information (Tables)	3 Months Ended
	Mar. 31, 2017
Other Financial Information [Abstract]
Schedule Of Additional Financial Details	The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): March 31, 2017 December 31, 2016 Accounts receivable: Trade receivables $ 6,533 $ 8,424 Receivable for Alta Resources Distribution 1,993 1,993 Joint interest billings 3,269 3,519 Income taxes receivable 91 91 Other receivables 695 3,395 Allowance for doubtful accounts (756) (695) Total accounts receivable $ 11,825 $ 16,727 Prepaid expenses and other: Prepaid insurance $ 357 $ 1,086 Other 439 701 Total prepaid expenses and other $ 796 $ 1,787 Accounts payable and accrued liabilities: Royalties and revenue payable $ 16,384 $ 16,920 Advances from partners 9,756 5,792 Accrued exploration and development 9,737 11,176 Accrued carried well costs 3,333 7,155 Trade payables 6,934 5,406 Accrued LOE & workover expense 1,390 1,867 Accrued G&A and legal expense 2,918 5,016 Other accounts payable and accrued liabilities 2,506 1,803 Total accounts payable and accrued liabilities $ 52,958 $ 55,135
Schedule Of Supplemental Disclosures	Included in the table below is supplemental information about certain cash and non-cash transactions during the three months ended March 31, 2017 and 2016 (in thousands): Three Months Ended March 31, 2017 2016 Cash payments: Interest payments $ 760 $ 879 Income tax payments (refunds) $ 3 $ (351) Non-cash investing activities in the consolidated statements of cash flows: Decrease in accrued capital expenditures $ (5,261) $ (1,222)

Investment In Exaro Energy II23

Investment In Exaro Energy III LLC (Tables)	3 Months Ended
	Mar. 31, 2017
Investment In Exaro Energy III LLC [Abstract]
Schedule Of Condensed Balance Sheet Data	March 31, 2017 December 31, 2016 Current assets (1) $ 22,500 $ 25,296 Non-current assets: Net property and equipment 88,545 90,621 Gas processing deposit 1,150 1,150 Other non-current assets 430 8 Total non-current assets 90,125 91,779 Total assets $ 112,625 $ 117,075 Current liabilities (2) $ 61,328 $ 65,694 Non-current liabilities: Long-term debt — — Other non-current liabilities 3,370 8,106 Total non-current liabilities 3,370 8,106 Members' equity 47,927 43,275 Total liabilities & members' equity $ 112,625 $ 117,075 (1) Approximately $18.8 million and $19.6 million of current assets as of March 31, 2017 and December 31, 2016, respectively, is cash. (1) Approximately $54.4 million and $59.3 million of current liabilities as of March 31, 2017 and December 31, 2016, respectively, are attributable to the senior loan facility maturing September 26, 2017.
Schedule Of Condensed Income Statement Data	Three Months Ended March 31, 2017 2016 Production: Oil (thousand barrels) 25 36 Gas (million cubic feet) 2,308 2,774 Total (million cubic feet equivalent) 2,460 2,991 Oil and natural gas sales $ 9,171 $ 6,312 Gain on derivatives 2,562 — Other gain — 2,102 Less: Lease operating expenses 3,219 3,557 Depreciation, depletion, amortization & accretion 2,343 3,006 General & administrative expense 733 808 Income from continuing operations 5,438 1,043 Net interest expense (624) (693) Net income $ 4,814 $ 350

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2017
Income Taxes [Abstract]
Components Of Income Tax Expense (Benefit)	The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended March 31, 2017 2016 Current tax provision: Federal $ — $ — State 191 90 Total $ 191 $ 90 Total tax provision: Federal $ — $ — State 191 90 Total $ 191 $ 90 Included in gain from investment in affiliates $ — $ — Total income tax provision $ 191 $ 90

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2017
Related Party Transactions [Abstract]
Schedule Of Payments Received From (Made To) Related Parties	The Company made and received similar types of payments with other well owners (in thousands): Three Months Ended March 31, 2017 2016 Revenue payments as well owners $ (764) $ (648) Joint interest billing receipts 113 62
Schedule Of Related Party Balances	As of March 31, 2017 and December 31, 2016, the Company's consolidated balance sheets reflected the following balances relating to Olympic (in thousands): March 31, 2017 December 31, 2016 Accounts receivable: Joint interest billing $ 42 $ 59 Accounts payable: Royalties and revenue payable (456) (557)

Organization And Business (Deta

Organization And Business (Details)	3 Months Ended
	Mar. 31, 2017aft	Jul. 31, 2016a
Southern Delaware Basin Of Texas [Member]
Gas and Oil Acreage [Line Items]
Gross acres | a	13,400	12,100
Net acres | a	6,700	5,000
Exaro Energy III LLC [Member]
Gas and Oil Acreage [Line Items]
Equity method investment, ownership percentage	37.00%
Maximum [Member]
Gas and Oil Acreage [Line Items]
Water depth of operations | ft	300

Summary Of Significant Accoun27

Summary Of Significant Accounting Policies (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Significant Accounting Policies [Line Items]
Impairment of proved properties	$ 0	$ 0.7
Impairment charges, unproved properties		$ 1.1
Restricted assets, percent of net assets	25.00%
Employee Stock Options [Member]
Significant Accounting Policies [Line Items]
Antidilutive (in shares)	97,319	116,461
Performance Stock Units [Member]
Significant Accounting Policies [Line Items]
Weighted average incremental shares	564
Antidilutive (in shares)	267,399
Restricted Stock [Member]
Significant Accounting Policies [Line Items]
Weighted average incremental shares	33,475
Antidilutive (in shares)	553,019	284,528

Acquisitions and Dispositions (

Acquisitions and Dispositions (Details) $ in Thousands	Feb. 01, 2017USD ($)	Jul. 31, 2016USD ($)aitem	Mar. 31, 2017USD ($)a	Dec. 31, 2016USD ($)	Dec. 30, 2016USD ($)a
Acquisition
Carried well cost			$ 3,333	$ 7,155
Southern Delaware Basin Of Texas [Member]
Acquisition
Percentage of working interest acquired		50.00%
Gross acres - Undeveloped | a		12,100	13,400
Net acres - Undeveloped | a		5,000	6,700
Cash consideration for acquisition		$ 10,000
Gas and Oil Area, Developed, Gross | a			13,400
Gas and Oil Area, Developed, Net | a			6,700
Southern Delaware Basin Of Texas [Member] | Maximum [Member]
Acquisition
Estimated consideration		25,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Colorado Properties [Member]
Acquisition
Aggregate sales price of assets sold					$ 5,000
Gas and Oil Area, Developed, Gross | a					16,000
Gas and Oil Area, Developed, Net | a					11,200
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Southeast Texas Assets [Member]
Acquisition
Gain on sale of oil and gas property	$ 2,900
Phase One [Member] | Southern Delaware Basin Of Texas [Member]
Acquisition
Carried well cost		$ 10,000
Number of wells | item		6
Phase Two [Member] | Southern Delaware Basin Of Texas [Member]
Acquisition
Spud bonus		$ 5,000
Number of wells | item		14

Fair Value Measurements (Detail

Fair Value Measurements (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - assets	$ 931
Commodity price contracts - liabilities	(1,103)
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - liabilities
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - assets	931
Commodity price contracts - liabilities	(1,103)
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - liabilities
RBC Credit Facility [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Maximum period of interest rate on floating-rate debt	6 months

Derivative Instruments (Derivat

Derivative Instruments (Derivative Contracts) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017USD ($)item$ / Mcf
Derivative [Line Items]
Fair Value | $	$ (172)
Derivative Contract Period April To July 2017 [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Fair Value | $	$ (442)
Commodity Derivative Flow Rate | item	400,000
Derivative Contract Period April To July 2017 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Fair Value | $	$ 326
Commodity Derivative Flow Rate | item	300,000
Price/Unit-Swap	3.51
Derivative Contract Period April To July 2017 [Member] | Swap [Member] | Oil [Member]
Derivative [Line Items]
Fair Value | $	$ 96
Commodity Derivative Flow Rate | item	9,000
Price/Unit-Swap	53.95
Derivative Contract Period April To July 2017 [Member] | Minimum [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Price/Unit-Swap	2.65
Derivative Contract Period April To July 2017 [Member] | Maximum [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Price/Unit-Swap	3
Derivative Contract Period, August to October 2017 [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Fair Value | $	$ (246)
Commodity Derivative Flow Rate | item	200,000
Derivative Contract Period, August to October 2017 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Fair Value | $	$ 37
Commodity Derivative Flow Rate | item	70,000
Price/Unit-Swap	3.51
Derivative Contract Period, August to October 2017 [Member] | Swap [Member] | Oil [Member]
Derivative [Line Items]
Fair Value | $	$ 35
Commodity Derivative Flow Rate | item	6,000
Price/Unit-Swap	53.95
Derivative Contract Period, August to October 2017 [Member] | Minimum [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Price/Unit-Swap	2.65
Derivative Contract Period, August to October 2017 [Member] | Maximum [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Price/Unit-Swap	3
Derivative Contract Period, November to December 2017 [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Fair Value | $	$ (415)
Commodity Derivative Flow Rate | item	400,000
Derivative Contract Period, November to December 2017 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Fair Value | $	$ 45
Commodity Derivative Flow Rate | item	300,000
Price/Unit-Swap	3.51
Derivative Contract Period, November to December 2017 [Member] | Swap [Member] | Oil [Member]
Derivative [Line Items]
Fair Value | $	$ 29
Commodity Derivative Flow Rate | item	8,000
Price/Unit-Swap	53.95
Derivative Contract Period, November to December 2017 [Member] | Minimum [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Price/Unit-Swap	2.65
Derivative Contract Period, November to December 2017 [Member] | Maximum [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Price/Unit-Swap	3
Derivative Contract Period April To December 2017 [Member] | Swap [Member] | Oil [Member]
Derivative [Line Items]
Fair Value | $	$ 363
Commodity Derivative Flow Rate | item	9,000
Price/Unit-Swap	56.20

Derivative Instruments (Fair Va

Derivative Instruments (Fair Value) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Assets
Total	$ 931
Liabilities:
Total	(1,103)
Commodity Derivatives [Member]
Assets
Gross	931
Netting	(931)
Liabilities:
Gross	(1,103)	$ (3,446)
Netting	931
Total	$ (172)	$ (3,446)

Derivative Instruments (Operati

Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	$ (179)	$ 1,508
Unrealized gain (loss)	3,275	2,696
Gain on derivatives, net	3,096	4,204
Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	170
Unrealized gain (loss)	524
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	(349)	1,508
Unrealized gain (loss)	$ 2,751	$ 2,696

Stock Based Compensation (Narra

Stock Based Compensation (Narrative) (Details) - USD ($)	1 Months Ended	3 Months Ended
	Apr. 30, 2017	Mar. 31, 2017	Mar. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant		300,000
Share-based Compensation		$ 1,456,000	$ 1,699,000
Employee Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Excess tax benefit from exercise/cancellation of stock options		$ 0	$ 0
Options exercised in period (in shares)		0	0
Stock options granted in period (in shares)		0	0
Options forfeitures during the period (in shares)		14,586	0
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years
Granted non-option (in shares)	338,560	30,000	40,688
Value of forfeitures during the period		$ 256,000	$ 1,000
Restricted stock expense		$ 1,500,000	$ 1,700,000
Compensation expense, remaining weighted average vesting period		3 years 10 months 24 days
Restricted Stock [Member] | Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted non-option (in shares)			1,745
Restricted Stock [Member] | New And Existing Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted non-option (in shares)			38,943
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares not available for issuance (in shares)		297,399
Granted non-option (in shares)	160,908
Performance Stock Units [Member] | New Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years
Granted non-option (in shares)		30,000	0

Stock Based Compensation (NonOp

Stock Based Compensation (NonOption) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	3 Months Ended		12 Months Ended
	Apr. 30, 2017	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Salary deferred (as a percent)				10.00%
Share-based Compensation		$ 1,456	$ 1,699
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years
Value of issued stock after adjustment for estimated forfeiture rate		$ 200	$ 300
Weighted average forfeiture rate		5.80%	0.00%
Compensation expense not yet recognized		$ 5,600
Activity, shares
Granted non-option (in shares)	338,560	30,000	40,688
Canceled/Forfeited (in shares)		24,244	40
Activity, weighted average fair value
Granted (in dollars per share)		$ 7.78	$ 6.40
Performance Stock Units [Member]
Activity, shares
Granted non-option (in shares)	160,908
New And Existing Employees [Member] | Restricted Stock [Member]
Activity, shares
Granted non-option (in shares)			38,943
Board of Directors [Member] | Restricted Stock [Member]
Activity, shares
Granted non-option (in shares)			1,745
New Employees [Member] | Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years
Activity, shares
Granted non-option (in shares)		30,000	0
Activity, weighted average fair value
Granted (in dollars per share)		$ 8.32
Minimum [Member] | New Employees [Member] | Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target (as a percent)		0.00%
Maximum [Member] | New Employees [Member] | Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target (as a percent)		200.00%

Other Financial Information (Ba

Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Accounts Receivable:
Trade receivables	$ 6,533	$ 8,424
Receivable for Alta Resources Distribution	1,993	1,993
Joint interest billings	3,269	3,519
Income taxes receivable	91	91
Other receivables	695	3,395
Allowance for doubtful accounts	(756)	(695)
Total Accounts Receivable	11,825	16,727
Prepaid expenses and other:
Prepaid insurance	357	1,086
Other	439	701
Total prepaid expenses and other	796	1,787
Accounts payable and accrued liabilities:
Royalties and revenue payable	16,384	16,920
Advances from partners	9,756	5,792
Accrued exploration and development	9,737	11,176
Accrued carried well cost	3,333	7,155
Trade payables	6,934	5,406
Accrued LOE & workover expense	1,390	1,867
Accrued G&A and legal expense	2,918	5,016
Other accounts payable and accrued liabilities	2,506	1,803
Total Accounts Payable and Accrued Liabilities	$ 52,958	$ 55,135

Other Financial Information (No

Other Financial Information (Non-Cash) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash payments:
Interest payments	$ 760	$ 879
Income tax payments (refunds)	3	(351)
Non-cash investing activities in the consolidated statements of cash flows:
Decrease in accrued capital expenditures	$ (5,261)	$ (1,222)

Investment in Exaro Energy II37

Investment in Exaro Energy III LLC (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Schedule of Equity Method Investments Financials
Gain from investment in affiliates, net of income taxes	$ 1,784	$ 40
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Equity method investment, ownership percentage	37.00%
Share of equity in investment	$ 17,500
Gain from investment in affiliates, net of income taxes	1,800	$ 40
Tax (expense) benefit from equity investment	$ 0

Investment in Exaro Energy II38

Investment in Exaro Energy III LLC (Balance Sheet) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Non-current assets:
Net property and equipment	$ 344,642	$ 340,382
Other non-current assets	18,744	17,078
Non-current liabilities:
Other non-current liabilities	248	248
Cash and cash equivalents
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Current assets	22,500	25,296
Non-current assets:
Net property and equipment	88,545	90,621
Gas processing deposit	1,150	1,150
Other non-current assets	430	8
Total non-current assets	90,125	91,779
Total assets	112,625	117,075
Current liabilities	61,328	65,694
Non-current liabilities:
Other non-current liabilities	3,370	8,106
Total non-current liabilities	3,370	8,106
Member's equity	47,927	43,275
Total liabilities & member's equity	112,625	117,075
Cash and cash equivalents	18,800	19,600
Current liabilities	$ 54,400	$ 59,300

Investment in Exaro Energy II39

Investment in Exaro Energy III LLC (Income Statement) (Details) MMcfe in Thousands, MMcf in Thousands, MBbls in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017MMcf	Mar. 31, 2017MBbls	Mar. 31, 2017MMcfe	Mar. 31, 2017USD ($)	Mar. 31, 2016MMcf	Mar. 31, 2016MBbls	Mar. 31, 2016MMcfe	Mar. 31, 2016USD ($)
Schedule of Equity Method Investments Financials
Gain on derivatives, net				$ 3,096				$ 4,204
General & administrative expense				6,596				5,902
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Production	2,308	25			2,774	36
Total Production (Mcfe) | MMcfe			2,460				2,991
Oil and natural gas sales				9,171				6,312
Gain on derivatives, net				2,562
Other gain								2,102
Lease operating expenses				3,219				3,557
Depreciation, depletion, amortization & accretion				2,343				3,006
General & administrative expense				733				808
Income from continuing operations				5,438				1,043
Net interest expense				(624)				(693)
Net income				$ 4,814				$ 350

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Oct. 31, 2013USD ($)	Mar. 31, 2017USD ($)	Mar. 31, 2016USD ($)	May 04, 2017USD ($)	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Letters of credit amount outstanding		$ 1,900			$ 1,900
Interest expense		$ 759	$ 878
Weighted average interest rate (as a percent)		4.30%			4.20%
RBC Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, maximum borrowing capacity	$ 500,000
Original term of credit line	4 years
Revolving credit facility, borrowing base		$ 140,000
Credit facility amount outstanding		59,700			$ 54,400
Line of credit, available		78,400
Interest expense		$ 800	$ 900
RBC Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Revolving credit facility, borrowing base				$ 125,000
RBC Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Current ratio	1
RBC Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Leverage ratio	3.50

Income Taxes (Expense Benefit)

Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Current:
State	$ 191	$ 90
Total	191	90
Total:
State	191	90
Total	191	90
Income tax provision	$ 191	$ 90

Related Party Transactions (Oly

Related Party Transactions (Olympic) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Accounts receivable:
Joint interest billing	$ 3,269		$ 3,519
Olympic [Member]
Related Party Transaction [Line Items]
Revenue payments as well owners	(764)	$ (648)
Joint interest billing receipts	113	62
Accounts receivable:
Joint interest billing	42		59
Accounts payable:
Royalties and revenue payable	(456)		$ (557)
Mr. Romano [Member]
Related Party Transaction [Line Items]
Director compensation for related party	$ 14	$ 14
Restricted stock granted in period (in shares)		261
Stock-based compensation expense		$ 19
Restricted stock issued	0

Related Party Transactions (Oak

Related Party Transactions (Oaktree) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended
	Apr. 30, 2017	Mar. 31, 2017	Mar. 31, 2016
Oaktree or Mr. Ford [Member]
Related Party Transaction [Line Items]
Ownership Percentage in Company's Stock		5.10%
Restricted stock granted in period (in shares)			313
Director compensation for related party		$ 17	$ 17
Stock-based compensation expense			$ 19
Restricted stock issued		0
Restricted Stock [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)	338,560	30,000	40,688
Vesting period (in years)		3 years

Commitments And Contingencies (

Commitments And Contingencies (Narrative) (Details) $ in Millions	1 Months Ended			3 Months Ended
	Sep. 30, 2012USD ($)	Nov. 30, 2010USD ($)site	Jul. 31, 2010USD ($)	Mar. 31, 2017USD ($)
Throughput commitment
Loss Contingency
Loss contingency expense				$ 1.5
Madison County Case [Member]
Legal Proceedings
Damages sought by plaintiffs			$ 9.4
Lavaca County Case [Member]
Legal Proceedings
Number of wells involved in litigation | site		2
Damages sought by plaintiffs		$ 5.3
Litigation Case Filed by Mineral Interest Owner Harris County [Member]
Legal Proceedings
Damages sought by plaintiffs	$ 10.7
Minimum [Member] | Throughput commitment
Loss Contingency
Estimated deficiency				1.5
Maximum [Member] | Throughput commitment
Loss Contingency
Estimated deficiency				$ 1.6