Contango Oil & Gas (MCF) 10-K 9 Mar 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 05, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
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 Public Float			$ 129.5
Entity Common Stock, Shares Outstanding		25,479,438
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
CURRENT ASSETS:
Cash and cash equivalents	$ 0	$ 0
Accounts receivable, net	13,059	16,727
Prepaid expenses	1,892	1,787
Current derivative asset	822
Inventory		540
Total current assets	15,773	19,054
Natural gas and oil properties, successful efforts method of accounting:
Proved properties	1,239,662	1,188,065
Unproved properties	35,243	38,338
Other property and equipment	1,272	1,265
Accumulated depreciation, depletion and amortization	(930,220)	(887,286)
Total property, plant and equipment, net	345,957	340,382
OTHER NON-CURRENT ASSETS:
Investments in affiliates	18,464	15,767
Deferred tax asset	424
Other	835	1,311
Total other non-current assets	19,723	17,078
TOTAL ASSETS	381,453	376,514
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	46,755	55,135
Current derivative liability	1,765	3,446
Current asset retirement obligations	2,017	4,308
Total current liabilities	50,537	62,889
NON-CURRENT LIABILITIES:
Long-term debt	85,380	54,354
Long-term derivative liability	300
Asset retirement obligations	20,388	22,618
Other long term liabilities	248	248
Total non-current liabilities	106,316	77,220
Total liabilities	156,853	140,109
COMMITMENTS AND CONTINGENCIES (NOTE 13)
SHAREHOLDERS' EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 30,873,470 shares issued and 25,505,715 shares outstanding at December 31, 2017, 30,557,987 shares issued and 25,238,600 shares outstanding at December 31, 2016	1,223	1,211
Additional paid-in capital	302,527	296,439
Treasury shares at cost (5,367,755 shares at December 31, 2017 and 5,319,387 shares at December 31, 2016)	(128,583)	(128,321)
Retained earnings	49,433	67,076
Total shareholders' equity	224,600	236,405
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 381,453	$ 376,514

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 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	30,873,470	30,557,987
Common stock, shares outstanding	25,505,715	25,238,600
Treasury stock, shares	5,367,755	5,319,387

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
REVENUES:
Oil and condensate sales	$ 25,347	$ 23,006	$ 43,230
Natural gas sales	41,317	43,847	59,058
Natural gas liquids sales	11,881	11,330	14,217
Total revenues	78,545	78,183	116,505
EXPENSES:
Operating expenses	27,183	29,111	37,840
Exploration expenses	1,106	1,816	11,979
Depreciation, depletion and amortization	47,215	63,323	133,380
Impairment and abandonment of oil and gas properties	2,395	10,572	285,877
General and administrative expenses	24,161	26,802	26,402
Total expenses	102,060	131,624	495,478
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates (net of income taxes)	2,697	1,545	(30,582)
Interest expense	(4,100)	(3,802)	(3,164)
Gain (loss) on derivatives, net	3,325	(1,632)	2,348
Other income (expense)	3,555	(357)	97
Total other income (expense)	5,477	(4,246)	(31,301)
NET LOSS BEFORE INCOME TAXES	(18,038)	(57,687)	(410,274)
Income tax benefit (provision)	395	(342)	75,226
NET LOSS ATTRIBUTABLE TO COMMON STOCK	$ (17,643)	$ (58,029)	$ (335,048)
NET LOSS PER SHARE:
Basic (in dollars per share)	$ (0.71)	$ (2.71)	$ (17.67)
Diluted (in dollars per share)	$ (0.71)	$ (2.71)	$ (17.67)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic (in shares)	24,686	21,424	18,965
Diluted (in shares)	24,686	21,424	18,965

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (17,643)	$ (58,029)	$ (335,048)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	47,215	63,323	133,380
Impairment of natural gas and oil properties	1,785	10,438	285,870
Exploration expenses (recovery)	(232)	(1)	6,494
Deferred income taxes	(424)		(92,329)
Loss (gain) on sale of assets	(2,321)	92	231
Loss (gain) from investment in affiliates	(2,697)	(1,545)	47,049
Stock-based compensation	6,100	6,457	6,516
Unrealized loss (gain) on derivative instruments	(2,204)	3,446
Changes in operating assets and liabilities:
Decrease in accounts receivable & other	3,914	1,006	4,261
Decrease (increase) in prepaid expenses	(105)	(560)	714
Increase (decrease) in accounts payable & advances from joint owners	450	2,116	(28,672)
Increase (decrease) in other accrued liabilities	1,353	2,436	(5,711)
Decrease (increase) in income taxes receivable, net	(332)	2,777	405
Increase (decrease) in income taxes payable, net	(252)	(187)	481
Other	79	242	1,314
Net cash provided by operating activities	34,686	32,011	24,955
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	(66,613)	(24,929)	(77,820)
Sale of oil and gas properties	1,151	5,120
Sale of furniture and equipment	12	11
Return of investment in affiliates			1,014
Net cash used in investing activities	(65,450)	(19,798)	(76,806)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under credit facility	239,514	148,881	356,102
Repayments under credit facility	(208,488)	(209,972)	(304,016)
Net proceeds from equity offering		50,435
Purchase of treasury stock	(262)	(561)	(235)
Debt issuance costs		(996)
Net cash provided by (used in) financing activities	30,764	(12,213)	51,851
NET DECREASE IN CASH AND CASH EQUIVALENTS	0	0	0
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	0	0
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 0	$ 0	$ 0

CONSOLIDATED STATEMENT OF SHARE

CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Total
Balance at Dec. 31, 2014	$ 963	$ 233,278	$ (127,525)	$ 460,750	$ 567,466
Balance, shares at Dec. 31, 2014	19,148,000
Treasury shares at cost			(235)		(235)
Treasury shares at cost, shares	(31,252)
Restricted shares activity	$ 11	(10)			1
Restricted shares activity, shares	264,398
Stock-based compensation		6,256			6,256
Dissolution of REX				(597)	(597)
Net loss				(335,048)	(335,048)
Balance at Dec. 31, 2015	$ 974	239,524	(127,760)	125,105	237,843
Balance, shares at Dec. 31, 2015	19,381,146
Equity Offering	$ 214	50,221			50,435
Equity Offering, shares	5,360,000
Treasury shares at cost			(561)		(561)
Treasury shares at cost, shares	(63,597)
Restricted shares activity	$ 23	(22)			1
Restricted shares activity, shares	561,051
Stock-based compensation		6,716			6,716
Net loss				(58,029)	(58,029)
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			(262)		$ (262)
Treasury shares at cost, shares	(48,368)
Restricted shares activity	$ 12	(12)
Restricted shares activity, shares	315,483
Stock-based compensation		6,100			6,100
Net loss				(17,643)	(17,643)
Balance at Dec. 31, 2017	$ 1,223	$ 302,527	$ (128,583)	$ 49,433	$ 224,600
Balance, shares at Dec. 31, 2017	25,505,715				25,505,715

Organization and Business

Organization and Business	12 Months Ended
	Dec. 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 offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore properties in Texas and Wyoming and to use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties in onshore West Texas, the Texas Gulf Coast and the Rocky Mountain regions of the United States. On October 1, 2013, the Company completed a merger with Crimson Exploration Inc. ("Crimson") (the “Merger”). The Company historically focused operations in the GOM, but the Merger has given the Company access to high rate of return onshore prospects in known, prolific producing areas as well as long-life resource plays. Beginning in the second half of 2015, the Company reduced its drilling program in response to the challenging commodity price environment, and instead focused on : (i) the preservation of its strong and flexible financial position, including limiting its overall capital expenditure budget to internally generated cash flow; (ii) the identification of opportunities for cost and production efficiencies in all areas of its operations; and (iii) maintaining core leases and continuing to identify new resource potential opportunities internally and, where appropriate, through acquisition. As a result , until the latter half of 2016, the Company’s only drilling activity was in Weston County, Wyoming, where it completed its third well targeting the Muddy Sandstone formation. During the third quarter of 2016, the Company acquired acreage in the Southern Delaware Basin in Pecos County, Texas (the “Acquisition”), and as of December 31, 2017, had increased its acreage in the Southern Delaware Basin to 16,500 gross acres (6,800 net). Since the Acquisition, the Company has begun production from seven wells in the Southern Delaware Basin and is waiting on completion of an eighth well. The Company currently expects that the Southern Delaware Basin position will continue to be the primary focus of its drilling program for 2018. Additionally, the Company has (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”) that is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) operated properties producing from various conventional formations in various counties along the Texas Gulf Coast; and (iii) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas. On December 30, 2016, the Company completed the sale of all of its Colorado assets, primarily located in the Adams and Weld counties.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Summary Of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies Basis of Presentation The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and 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. Oil and gas exploration and development affiliates which are not controlled by the Company, such as Republic Exploration LLC (“REX”), are proportionately consolidated. REX was dissolved as of December 31, 2015. Other Investments The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company's proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statement of operations, the Company’s proportionate share of Exaro's net income or loss is reported as a single line-item in Gain (loss) from investment in affiliates (net of income taxes). Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates include oil and gas revenues, income taxes, stock-based compensation, reserve estimates, impairment of natural gas and oil properties, valuation of derivatives and accrued liabilities. Actual results could differ from those estimates. Revenue Recognition Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share, production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. As of December 31, 2017 , 2016 and 2015, the Company had no significant imbalances. Cash Equivalents Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2017 , the Company had no cash and cash equivalents, as cash balances at the end of each day are transferred to reduce outstanding debt under the Company’s revolving credit facility to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2017, accounts payable included $2.3 million in outstanding checks that had not been presented for payment. At December 31, 2016, accounts payable included $3.5 million in outstanding checks that had not been presented for payment. Accounts Receivable The Company sells natural gas and crude oil to a limited number of customers. In addition, the Company participates with other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accounts receivables are due from either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells for which the Company serves as the operator. Generally, operators of natural gas and crude oil properties have the right to offset future revenues against unpaid charges related to operated wells. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance. Accounts receivable allowance for bad debt was $0.8 and $0.7 million as of December 31, 2017 and 2016, respectively . At December 31, 2017 and 2016, the carrying value of the Company’s accounts receivable approximated fair value. Oil and Gas Properties - Successful Efforts The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. Depreciation, depletion and amortization is calculated on a field by field basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other capitalized costs amortized over proved developed reserves. Depreciation, depletion and amortization ("DD&A") of capitalized drilling and development costs of producing natural gas and crude oil properties, including related support equipment and facilities net of salvage value, are computed using the unit of production method on a field basis based on total estimated proved developed natural gas and crude oil reserves. Amortization of producing leaseholds is based on the unit of production method using total estimated proved reserves. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates. Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 13 years. Impairment of Oil and Gas Properties 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 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. For the year ended December 31, 2017, the Company recorded an impairment expense of approximately $0.3 million related to proved properties. For the year ended December 31, 2016, the Company recorded an impairment expense of approximately $0.7 million related to proved properties. For the year ended December 31, 2015, the Company recorded an impairment expense of approximately $269.6 million related to proved properties. Approximately $235.8 million of this amount was attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes counties properties. Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, and any such impairment is charged to expense in the period. During the year ended December 31, 2017, the Company recognized impairment expense of approximately $1.5 million related to the partial impairment of two unused offshore platforms in onshore storage. During the year ended December 31, 2016, the Company recognized impairment expense of approximately $6.8 million related to unproved properties in Fayette and Gonzales counties, Texas and $2.9 million related to unproved acreage in Natrona County, Wyoming. During the year ended December 31, 2015, the Company recognized impairment expense of approximately $16.3 million related to impairment and partial impairment of certain unproved properties and onshore prospects due primarily to the sustained low commodity price environment and expiring leases. Approximately $9.3 million of this amount related to unproved lease cost amortization of properties in Fayette and Gonzales counties, Texas. Asset Retirement Obligations ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records an asset retirement obligation (“ARO”) to reflect the Company's legal obligation related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in depreciation, depletion and amortization expense. The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and gas properties expense. See Note 11 - "Asset Retirement Obligation" for additional information. Income Taxes The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2017 . The amount of unrecognized tax benefits did not materially change from December 31, 2016 . The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its statement of operations. The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal tax returns for 1998 – 2016 , and state tax returns for 2010 – 2016 , remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed. Concentration of Credit Risk Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 - "Concentration of Credit Risk" for additional information. Debt Issuance Costs Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. During the year ended December 31, 2013, the Company initially incurred $2.2 million of debt issuance costs relating to the new RBC credit facility entered into in conjunction with the Merger with Crimson. The debt issuance costs were to be amortized over the original four year term of the credit line. In connection with RBC Credit Facility amendment in May 2016, the Company incurred an additional $1.0 million of debt issuance costs. As of December 31, 2017, the remaining balance of these debt issuance costs was $0.8 million, which will be amortized through October 1, 2019, with amortization expense included in the DD&A line item in the Company's income statement for the years ended December 31, 2017, 2016 and 2015. Stock-Based Compensation The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each restricted stock award is estimated as of the date of grant. The fair value of the Performance Stock Units is estimated as of the date of grant using the Monte Carlo simulation pricing model. Inventory Inventory primarily consists of casing and tubing which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method. Derivative Instruments and Hedging Activities The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in "Gain (loss) on derivatives, net" on the consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015. Derivative instruments with settlement dates within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates a net asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 - "Derivative Instruments" for additional information. Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), 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. Crimson Exploration Inc., Crimson Exploration Operating, Inc., Contango Energy Company, Contango Operators, Inc., Contango Mining Company, Conterra Company, Contaro Company, Contango Alta Investments, Inc., Contango Venture Capital Corporation, Contango Rocky Mountain Inc. and any other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. 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 other wholly-owned subsidiary that is inactive. 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 2017-01). 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 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. 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. This new standard is now effective for annual reporting periods beginning after December 15, 2017, and the Company has completed the assessment of this standard. The impact on the Company’s financial statements is not material, and there is no material impact expected to opening retained earnings. The standard was adopted January 1, 2018 using the modified retrospective method. Certain items netted in revenue or recorded as expense prior to adoption have changed based on the requirements of the new ASU using the control model and the definitions of parties to the contract as principal or agent. The company implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and additional disclosures will be required in our Form 10-Q for the three months ended March 31, 2018.

Concentration of Credit Risk

Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2017
Concentration Of Credit Risk [Abstract]
Concentration of Credit Risk	3. Concentration of Credit Risk The customer base for the Company is concentrated in the natural gas and oil industry. The largest purchaser of the Company’s production for the year ended December 31, 2017 was ConocoPhillips Company (51.2 % ). The Company’s sales to this company is not secured with letters of credit and in the event of non-payment, the Company could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financial position. There are numerous other potential purchasers of the Company’s production.

Acquisitions, Dispositions and

Acquisitions, Dispositions and Gains from Affiliates	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions, Dispositions and Gains from Affiliates	4. Acquisitions, Dispositions and Gains from Affiliates Southern Delaware Basin Acquisition In July 2016, 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 (the “Acquisition”) for up to $25 million. The purchase price was comprised of $10 million in cash paid on July 26, 2016, plus $10 million to be paid in the form of carried well costs expected to be paid over the period of drilling and completing the first six wells. Additionally, contingent upon success, $5 million in spud bonuses is to be paid by the Company ratably over the following 14 wells drilled, which would increase the total consideration paid by the Company to $25 m illion. As of December 31, 2017, the Company had paid all $10 million of the carried well costs and $1.1 million in spud bonuses. As of December 31, 2017, the Company has increased its acreage to approximately 16,500 gross operated acres (6,800 net). Colorado Property Sale 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. North Bob West Property Sale Effective February 1, 2017, the Company sold to a third party all of its assets in the North Bob West area and its operated assets in the Escobas area, both located in Southeast Texas, for a cash purchase price of $650,000. 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	12 Months Ended
	Dec. 31, 2017
Fair Value Measurements [Abstract]
Fair Value Measurements	5. Fair Value Measurements Pursuant to ASC 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. 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. Derivatives are recorded at fair value at the end of each reporting period. The Company records the net change in the fair value of these positions in "Gain (loss) 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 6 - "Derivative Instruments" for additional discussion of derivatives. During the year ended December 31, 2017, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which were believed to have a minimal credit risk. As such, the Company was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company did not anticipate any nonperformance. The counterparties to the Company's current and previous derivative contracts are lenders in the Company's RBC Credit Facility. The Company did not post collateral under any of these contracts as they were secured under the RBC Credit Facility. 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 have been 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 RBC Credit Facility approximates carrying value because the interest rate approximates current market rates and are re-set at least every three months. See Note 12 - "Long-Term Debt" for further information. Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis include oil and gas properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If the unamortized cost of properties exceeds the undiscounted cash flows related to the properties, the value of the properties is compared to the fair value estimated as discounted cash flows related to the risk-adjusted proved, probable and possible reserves related to the properties. Fair value measurements based on these inputs are classified as Level 3. Impairments Contango tests proved oil and 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. 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. Asset Retirement Obligations The initial measurement of ARO 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. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 at inception.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments [Abstract]
Derivative Instruments	6. Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are 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 December 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 sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put, which establishes a minimum price. A sold put option limits the exposure of the counterparty's risk should the price fall below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of the put option sold. It is the Company's practice to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The counterparties to the Company's current and previous derivative contracts are lenders or affiliates of lenders in the RBC Credit Facility. The Company does not post collateral under any of these contracts as they are secured under 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 (loss) on derivatives, net" on the consolidated statements of operations. See Note 5 – “Fair Value Measurements” for additional information. The Company had the following financial derivative contracts in place as of December 31, 2017: Commodity Period Derivative Volume/Month Price/Unit Natural Gas Jan 2018 - July 2018 Swap 370,000 MMBtus $ 3.07 (1) Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $ 3.07 (1) Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $ 3.07 (1) Oil Jan 2018 - June 2018 Swap 20,000 Bbls $ 56.40 (2) Oil July 2018 - Oct 2018 Collar 20,000 Bbls $ 52.00 - 56.85 (2) Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $ 52.00 - 56.85 (2) Oil Jan 2018 - Dec 2018 Collar 2,000 Bbls $ 52.00 - 58.76 (3) Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) Additionally, in January 2018, the Company entered into the following additional derivative contracts with members of its bank group: Commodity Period Derivative Volume/Month Price/Unit Oil Jan 2018 - July 2018 Collar 6,000 Bbls $ 58.00 - 68.00 (2) Oil Nov 2018 - Dec 2018 Collar 5,000 Bbls $ 58.00 - 68.00 (2) Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on Argus Louisiana Light Sweet crude oil prices. (3) Based on West Texas Intermediate crude oil prices. The Company had the following financial derivative contracts in place as of December 31, 2016: Commodity Period Derivative Volume/Month Price/Unit (1) Natural Gas Jan 2017 - July 2017 Collar 400,000 MMBtus $ 2.65 - 3.00 Natural Gas Aug 2017 - Oct 2017 Collar 200,000 MMBtus $ 2.65 - 3.00 Natural Gas Nov 2017 - Dec 2017 Collar 400,000 MMBtus $ 2.65 - 3.00 Natural Gas Jan 2017 - July 2017 Swap 300,000 MMBtus $ 3.51 Natural Gas Aug 2017 - Oct 2017 Swap 70,000 MMBtus $ 3.51 Natural Gas Nov 2017 - Dec 2017 Swap 300,000 MMBtus $ 3.51 Oil Jan 2017 - July 2017 Swap 9,000 Bbls $ 53.95 Oil Aug 2017 - Oct 2017 Swap 6,000 Bbls $ 53.95 Oil Nov 2017 - Dec 2017 Swap 8,000 Bbls $ 53.95 Oil Jan 2017 - Dec 2017 Swap 9,000 Bbls $ 56.20 (1) Commodity price derivatives are based on Henry Hub NYMEX natural gas prices and West Texas Intermediate oil prices, as applicable. There were no derivative contracts in place as of December 31, 2015. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2017 (in thousands). Gross Netting (1) Total Assets $ 1,188 $ (1,188) $ — Liabilities $ (2,431) $ 1,188 $ (1,243) (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 years ended December 31, 2017, 2016 and 2015 (in thousands): Year Ended December 31, Contract Type 2017 2016 2015 Crude oil contracts $ 861 $ 1,814 $ 2,348 Natural gas contracts 260 — — Realized gain $ 1,121 $ 1,814 $ 2,348 Crude oil contracts $ (2,065) $ — $ — Natural gas contracts 4,269 (3,446) — Unrealized gain (loss) $ 2,204 $ (3,446) $ — Gain (loss) on derivatives, net $ 3,325 $ (1,632) $ 2,348

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Stock-Based Compensation [Abstract]
Stock-Based Compensation	7. Stock Based Compensation As of December 31, 2017, the Company had in place the Contango Oil & Gas Company Amended and Restated 2009 Incentive Compensation Plan (“the 2009 Plan”) which allows for stock options, restricted stock or performance stock units to be awarded to officers, directors and employees as a performance-based award. Amended and Restated 2009 Incentive Compensation Plan On April 10, 2014, the Company’s board of directors (the “Board”) amended and restated the Company’s then existing incentive compensation plan through the adoption of the 2009 Plan. The 2009 Plan provides for both cash awards and equity awards to officers, directors, employees or consultants of the Company. Awards made under the 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board. Under the terms of the 2009 Plan, shares of the Company’s common stock may be issued for plan awards. Stock options under the 2009 Plan must have an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule for all equity awards varies from immediately to over a four -year period. As of December 31, 2017 , the Company had approximately 1.6 million shares of equity awards available for future grant under the 2009 Plan, assuming Performance Stock Units are settled at 100% of target. Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009 Plan for the benefit of all employees through a Cash Incentive Bonus Plan ( “ CIBP ” ) and a Long-Term Incentive Plan ( “ LTIP ” ). The specific targeted performance measures under these sub-plans are approved by the Compensation Committee and/or the Board. Upon achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible. The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock and/or stock options. The number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based upon the fair market value of the common stock on the date of the grant. 2005 Stock Incentive Plan The 2005 Plan was adopted by the Company's Board in conjunction with the Merger with Crimson. This plan expired on February 25, 2015, and therefore, no additional shares are available for grant. Stock Options During the years ended December 31, 2017, 2016 and 2015, the Company did not issue any stock options. A summary of stock options as of and for the years ended December 31, 2017 , 2016 and 2015 is presented in the table below (dollars in thousands, except per share data): Year Ended December 31, 2017 2016 2015 Weighted Weighted Weighted Shares Average Shares Average Shares Average Under Exercise Under Exercise Under Exercise Options Price Options Price Options Price Outstanding, beginning of the period 111,905 $ 55.53 116,461 $ 55.03 129,934 $ 53.85 Exercised — $ — — $ — — $ — Expired / Forfeited (17,072) $ 43.50 (4,556) $ 42.92 (13,473) $ 43.65 Outstanding, end of year 94,833 $ 57.69 111,905 $ 55.53 116,461 $ 55.03 Aggregate intrinsic value $ — $ — $ — Exercisable, end of year 94,833 $ 57.69 111,905 $ 55.53 116,461 $ 55.03 Aggregate intrinsic value $ — $ — $ — Available for grant, end of the period * 2,002,492 323,172 885,449 Weighted average fair value of options granted during the period $ — $ — $ — * Excludes Performance Stock Units. 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 years ended December 31, 2017, 2016 and 2015, there was no excess tax benefit recognized. See Note 2 – "Summary of Significant Accounting Policies". Compensation expense related to employee 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. During the years ended December 31, 2017, 2016 and 2015, the Company did not recognize any stock option expense. The aggregate intrinsic value of stock options exercised/forfeited during each of the years ended December 31, 2017, 2016 and 2015 was zero. Restricted Stock During the year ended December 31, 2017, the Company issued 383,376 restricted stock awards to new and existing employees, which vest over three years, plus an additional 74,325 restricted stock awards to the members of the board of directors which vest on the one-year anniversary of the date of grant. During the year ended December 31, 2017, 142,218 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $7.55, with a total grant date fair value of approximately $3.5 million after adjustment for estimated weighted average forfeiture rate of 4.8%. During the year ended December 31, 2016, the Company issued 489,805 restricted stock awards to new and existing employees, which vest over three or four years, an additional 49,460 restricted stock awards to the members of the board of directors which vest on the one-year anniversary of the date of grant, plus an additional 40,876 immediately vested shares to employees and board members as a result of temporarily deferring 10% of 2015 employee salaries and director fees (the “Salary Replacement Program”). During the year ended December 31, 2016, 19,090 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $10.99, with a total grant date fair value of approximately $6.4 million after adjustment for estimated weighted average forfeiture rate of 4.2%. During the year ended December 31, 2015, the Company issued 249,917 restricted stock awards to new and existing employees, which vest over four years, plus an additional 27,204 restricted stock awards to the members of the board of directors which vest on the one-year anniversary of the date of grant. During the year ended December 31, 2015, 12,723 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $21.83, with a total grant date fair value of approximately $6.1 million after adjustment for estimated weighted average forfeiture rate of 4.9%. Restricted stock activity as of December 31, 2017, 2016 and 2015 and for the years then ended is presented in the table below (dollars in thousands, except per share data): 2017 2016 2015 Weighted Aggregate Weighted Aggregate Weighted Aggregate Restricted Average Intrinsic Restricted Average Intrinsic Restricted Average Intrinsic Shares Fair Value Value Shares Fair Value Value Shares Fair Value Value Outstanding, beginning of the period 638,158 $ 14.22 $ 5,960 337,165 $ 28.16 $ 2,161 209,962 $ 43.86 $ 6,139 Granted 457,701 7.55 3,457 580,141 10.99 6,375 277,121 21.83 6,049 Vested (222,568) 15.12 1,263 (260,058) 24.51 2,422 (137,195) 39.35 1,169 Canceled / Forfeited (142,218) 10.23 814 (19,090) 22.03 202 (12,723) 32.97 154 Not vested, end of the period 731,073 10.55 1,667 638,158 14.22 5,960 337,165 28.16 2,161 Vested, end of the period — — — — — — — — — Expected to vest, end of the period 690,016 10.58 1,574 590,511 14.28 5,515 312,986 28.17 2,006 The Company recognized approximately $6.1 million, $6.5 million and $6.5 million in stock compensation expense during the years ended December 31, 2017, 2016 and 2015, respectively, for restricted shares granted to its officers, employees and directors. An additional $5.6 million of compensation expense will be recognized over the remaining vesting period. Performance Stock Units During the year ended December 31, 2017, the Company granted 30,000 Performance Stock Units (“PSUs”) to a new employee, at a weighted average fair value of $8.32 per unit and 160,908 PSUs to executive officers, as part of their overall compensation package, at a value of $13.91 per unit. All prices were determined using the Monte Carlo simulation model. During the year ended December 31, 2017, 99,363 PSUs were forfeited by former employees. During the year ended December 31, 2016, the Company granted 285,800 PSUs to all employees as part of its LTIP, at a fair value of $16.32 per unit, and an additional 6,699 PSUs to new employees, at a fair value of $13.06 per unit using the Monte Carlo simulation model. During the year ended December 31, 2016, 1,300 PSUs were forfeited by former employees. PSUs represent a contractual right to receive shares of the Company's common stock. The settlement of PSUs may range from 0% to 300% of the targeted number of PSUs stated in the agreement 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 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.

Share Repurchase Programs

Share Repurchase Programs	12 Months Ended
	Dec. 31, 2017
Share Repurchase Programs [Abstract]
Share Repurchase Programs	8. Share Repurchase Program In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market or through privately negotiated transactions. Purchases are made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, and when the Company believes its stock price to be undervalued. Repurchased shares of common stock became authorized but unissued shares, and may be issued in the future for general corporate and other purposes. No shares were purchased during the years ended December 31, 2017, 2016 and 2015. As of December 31, 2017, the Company had $31.8 million available under the share repurchase program for future purchases. In October 2014, the Company amended its revolving credit facility with Royal Bank of Canada to, among other things, allow for share repurchases subject to certain conditions. The Company is currently in compliance with these conditions.

Other Financial Information

Other Financial Information	12 Months Ended
	Dec. 31, 2017
Other Financial Information [Abstract]
Other Financial Information	9. Other Financial Information The following table provides additional detail for accounts receivable, prepaids, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): December 31, December 31, 2017 2016 Accounts receivable: Trade receivables $ 6,565 $ 8,424 Receivable for Alta Resources distribution 1,993 1,993 Joint interest billings 4,030 3,519 Income taxes receivable 424 91 Other receivables 828 3,395 Allowance for doubtful accounts (781) (695) Total accounts receivable $ 13,059 $ 16,727 Prepaid expenses and other: Prepaid insurance $ 1,177 $ 1,086 Other 715 701 Total prepaid expenses and other $ 1,892 $ 1,787 Accounts payable and accrued liabilities: Royalties and revenue payable $ 18,181 $ 16,920 Advances from partners 2,243 5,792 Accrued exploration and development 8,400 11,176 Accrued carried well costs — 7,155 Trade payables 9,559 5,406 Accrued general and administrative expenses 2,960 5,016 Accrued operating expenses 1,654 1,867 Other accounts payable and accrued liabilities 3,758 1,803 Total accounts payable and accrued liabilities $ 46,755 $ 55,135 Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the years ended December 31, 2017, 2016 and 2015, in thousands: Year Ended December 31, 2017 2016 2015 Cash payments: Interest payments $ 3,699 $ 3,806 $ 3,147 Income tax payments (refunds), net of cash refunds 616 (2,089) (180) Non-cash items excluded from investing activities in the consolidated statements of cash flows: Increase (decrease) in accrued capital expenditures (9,931) 14,672 (22,879)

Investment In Exaro Energy III

Investment In Exaro Energy III LLC	12 Months Ended
	Dec. 31, 2017
Investment In Exaro Energy III LLC [Abstract]
Investment In Exaro Energy III LLC	10. Investment in Exaro Energy III LLC Through the Company’s wholly-owned subsidiary, Contaro Company (“Contaro”), the Company committed to invest up to $67.5 million in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all the Exaro investors was approximately $183 million. The Company did not make any contributions during the year ended December 31, 2017 and has no plans to invest additional funds in Exaro, as the commitment to invest in Exaro expired on March 31, 2017. As of December 31, 2017, the Company had invested approximately $46.9 million . The following table presents condensed balance sheet data for Exaro as of December 31, 2017 and December 31, 2016. The balance sheet data was derived from the Exaro balance sheet as of December 31, 2017 and December 31, 2016 and was not adjusted to represent Contango’s percentage of ownership interest in Exaro. Contango’s share in the equity of Exaro at December 31, 2017 was approximately $18.4 million. December 31, December 31, 2017 2016 (in thousands) Current assets (1) $ 17,063 $ 25,296 Non-current assets: Net property and equipment 82,450 90,621 Gas processing deposit 1,150 1,150 Other non-current assets 390 8 Total non-current assets 83,990 91,779 Total assets $ 101,053 $ 117,075 Current liabilities (2) $ 6,199 $ 65,694 Non-current liabilities: Long-term debt 40,375 — Other non-current liabilities 3,858 8,106 Total non-current liabilities 44,233 8,106 Members' equity 50,621 43,275 Total liabilities & members' equity $ 101,053 $ 117,075 (1) Approximately $12.8 million and $19.6 million of current assets as of December 31, 2017 and December 31, 2016, respectively, is cash. (2) Approximately $59.3 million of current liabilities as of December 31, 2016, was attributable to Exaro’s senior loan facility maturing in 2017, which has since been refinanced. The following table presents the condensed results of operations for Exaro for the years ended December 31, 2017, 2016 and 2015. The results of operations for the years ended December 31, 2017, 2016 and 2015 were derived from Exaro's financial statements for the respective periods. The income statement data below was not adjusted to represent Contango’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 years ended December 31, 2017, 2016 and 2015 was a gain of $2.7 million, net of no tax expense; a gain of $1.5 million, net of no tax expense; and a loss of $30.6 million, net of tax benefit of $16.5 million, respectively. Year Ended December 31, 2017 2016 2015 ($ in thousands) Production: Oil (MBbls) 101 127 166 Gas (MMcf) 9,019 10,626 13,059 Total (Mmcfe) 9,625 11,388 14,055 Oil and natural gas sales $ 32,281 $ 30,028 $ 40,474 Other gain (loss) 5,368 (3,889) 6,358 Less: Lease operating expenses 15,479 15,846 20,922 Depreciation, depletion, amortization & accretion 9,857 10,644 29,417 Impairment expense — — 118,000 General & administrative expense 2,920 3,123 3,255 Income (loss) from continuing operations 9,393 (3,474) (124,762) Net other income (expense) (2,189) 7,900 (2,910) Net income (loss) $ 7,204 $ 4,426 $ (127,672) Included in Other gain (loss) are realized and unrealized gain (losses) attributable to derivatives, whose value is likely to change based on future oil and gas prices. Exaro's results of operations do not include income taxes, because Exaro is treated as a partnership for tax purposes.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	11. Asset Retirement Obligation The Company accounts for its retirement obligation of long lived assets by recording the net present value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Activities related to the Company’s ARO during the year ended December 31, 2017 and 2016 were as follows (in thousands): Year Ended December 31, 2017 2016 Balance as of the beginning of the period $ 26,926 $ 27,109 Liabilities incurred during period 308 69 Liabilities settled during period (4,503) (707) Accretion 1,056 1,187 Sales (2,949) (851) Change in estimate 1,567 119 Balance as of the end of the period $ 22,405 $ 26,926 All of the total liabilities incurred during the years ended December 31, 2017 and 2016 were related to new wells drilled during the period. All of the total liabilities settled during the years ended December 31, 2017 and 2016 were related to wells plugged and abandoned during the period.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2017
Long-Term Debt [Abstract]
Long-Term Debt	12. Long-Term Debt RBC Credit Facility In October 2013, the Company entered into a $500 million revolving credit facility with Royal Bank of Canada and other lenders (the “RBC Credit Facility”), which matures on October 1, 2019. The borrowing base under the facility is redetermined each November 1 and May 1. Effective November 6, 2017, the borrowing base under the RBC Credit Facility was redetermined at $115 million. Effective May 6, 2016, the RBC Credit Facility was amended to, among other things, extend the maturity of the facility from October 1, 2017 to October 1, 2019, increase the LIBOR, U.S. prime rate and federal funds rate margins to 2.5% - 4.0% and increase the commitment fee to 0.5%, regardless of the amount of the credit facility that is unused. Initially, the Company incurred $2.2 million of arrangement and upfront fees in connection with the RBC Credit Facility which was to be amortized over the original four-year term of the facility. In May 2016, in connection with the amendment, the Company incurred an additional $1.0 million of arrangement and upfront fees. As of December 31, 2017, the remaining balance of these fees was $0.8 million, which will be amortized through October 1, 2019. As of December 31, 2017, the Company had $85.4 million outstanding under the RBC Credit Facility, which matures on October 1, 2019, and $1.9 million in outstanding letters of credit. As of December 31, 2016, the Company had $54.4 million outstanding under the RBC Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2017, borrowing availability under the RBC Credit Facility was $27.7 million. The RBC Credit Facility is collateralized by a lien on substantially all the producing assets of the Company and its subsidiaries, including a security interest in the stock of Contango’s subsidiaries and a lien on the Company’s oil and gas properties. Borrowings under the RBC Credit Facility bear interest at LIBOR, the U.S. prime rate, or the federal funds rate, plus a 2.5% to 4.0% margin, dependent upon the amount outstanding. Additionally, the Company must pay a 0.5% commitment fee regardless of the amount of the credit facility that is unused. Total interest expense under the RBC Credit Facility, including commitment fees, for the years ended December 31, 2017, 2016 and 2015 was approximately $4.1 million, $3.8 million and $3.2 million, respectively. 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 December 31, 2017, the Company was in compliance with all but the Current Ratio covenant under the RBC Credit Facility, although the Company obtained a waiver for such non-compliance. 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.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies [Abstract]
Commitments And Contingencies	13. Commitments and Contingencies Contango pays delay rentals on its leases and leases its office space and certain other equipment. The Company’s corporate offices are located at 717 Texas Avenue in downtown Houston, Texas, under a lease that expires March 31, 2019. As of December 31, 2017, minimum future lease payments for delay rentals and operating leases for Contango’s fiscal years are as follows (in thousands): Fiscal years ending December 31, 2018 $ 3,542 2019 849 2020 112 2021 89 2022 82 2023 and thereafter 81 Total $ 4,755 The amounts incurred under operating leases and delay rentals during the years ended December 31, 2017 , 2016, and 2015 were approximately $4.8 million, $5.4 million and $6.3 million, respectively. 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 December 31, 2017, the Company estimates that the net deficiency fee will be approximately $1.0 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. As of December 31, 2017, based upon the current commodity price market and the Company’s short term strategic drilling plans, the Company has recorded a $1.8 million loss contingency through December 31, 2018. The Company will continue to assess this commitment in light of its drilling and development plans for this area. 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, and 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 case went to trial in December 2017. As the Court did not allow virtually all of the plaintiff’s claims, a nominal settlement agreement was executed to settle all claims. 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 appealed the trial court’s decision to the applicable state Court of Appeals. In the fourth quarter of 2017 the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. The Company continues to vigorously defend this lawsuit and has filed a motion for rehearing with the Court of Appeals, and if denied, will petition the Texas Supreme Court. 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 appealed the trial court’s decision to the applicable state Court of Appeals. On December 14, 2017, the Court of Appeals affirmed the judgement in the Company’s favor. The plaintiff has filed a motion for rehearing. The Company continues to vigorously defend 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. Employment Agreements On November 30, 2016, all of the Company’s existing employment agreements were terminated, and the Company and Mr. Keel, Mr. Grady, Mr. Mengle and Mr. Atkins entered into Amended and Restated Employment Agreements (“Employment Agreements”). The Employment Agreements provide for an initial term of three years for Messrs. Keel and Grady and an initial term of two years for Messrs. Mengle and Atkins. Each of the Employment Agreements will automatically renew for additional one year terms, unless Contango or the executive provides prior notice of intention not to extend the agreement. Under the Employment Agreements, Mr. Keel is entitled to a base salary of $600,000, Mr. Grady is entitled to a base salary of $400,000, Mr. Mengle is entitled to a base salary of $300,000 and Mr. Atkins is entitled to a base salary of $310,000. The Employment Agreements provide that each executive shall participate in the Company’s CIBP and LTIP. With respect to the CIBP, the Employment Agreements provide that the executives are eligible to receive an annual cash incentive bonus with a target award level of 100% for Messrs. Keel and Grady and 80% for Messrs. Mengle and Atkins, of such executive’s base salary, under such terms and conditions as the Company may determine each applicable year. With respect to the LTIP, the Employment Agreements provide that the executives are eligible to participate in the Company’s equity compensation plan for each calendar year in which the executive is employed by the Company, under such terms and conditions as the Company may determine in each applicable year.

Net Loss Per Common Share

Net Loss Per Common Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Net Loss Per Common Share	14. Net Loss Per Common Share A reconciliation of the components of basic and diluted net loss per common share for the years ended December 31, 2017, 2016 and 2015 is presented below (in thousands): Year Ended December 31, 2017 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (17,643) 24,686 $ (0.71) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (17,643) 24,686 $ (0.71) Year Ended December 31, 2016 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (58,029) 21,424 $ (2.71) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (58,029) 21,424 $ (2.71) Year Ended December 31, 2015 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (335,048) 18,965 $ (17.67) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options and restricted stock) — — — Net loss attributable to common stock $ (335,048) 18,965 $ (17.67) The numerator for basic earnings per share is net loss attributable to common stockholders. The numerator for diluted earnings per share is net loss available to common stockholders. Potential dilutive securities (stock options, restricted stock and PSUs) have not been considered when their effect would be antidilutive. The potentially dilutive shares would have been 1,282,590 shares for the year ended December 31, 2017, 1,282,957 shares for the year ended December 31, 2016 and 453,626 shares for the year ended December 31, 2015.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Taxes [Abstract]
Income Taxes	15. Income Taxes The Tax Cuts and Jobs Act 2017 On December 22, 2017, the United States enacted tax reform legislation known as the H.R.1, commonly referred to as the “Tax Cuts and Jobs Act” (the “Act”), resulting in significant modifications to existing law. The Company has completed the accounting for the effects of the Act during 2017. Our financial statements for the year ended December 31, 2017 reflect certain effects of the Act which includes a reduction in the corporate tax rate from 35% to 21% effective January 1, 2018, as well as other changes. Due to the Company’s valuation allowance position and as a result of changes to tax laws and rates under the Act, the Company recorded a net tax benefit due primarily to the remeasurement of deferred tax assets and liabilities from 35% to 21% and the removal of the valuation allowance on the estimated refundable Alternative Minimum Tax (“AMT”) credits. The valuation allowance decreased by $35.7 million in 2017 due to the changes to tax laws and rates under the Act and increased by $7.2 million for normal operations. The staff of the US Securities and Exchange Commission has recognized the complexity of reflecting the impacts of the Act, and on December 22, 2017 issued guidance in Staff Accounting Bulletin 118 (“SAB 118”) which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete and provides for up to a one year period to complete the required analyses and accounting (the measurement period). SAB 118 describes three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its accounting for certain effects of tax reform, (2) a company is able to determine a reasonable estimate for certain effects of tax reform and records that estimate as a provisional amount, or (3) a company is not able to determine a reasonable estimate and therefore continues to apply ASC 740, based on the provisions of the tax laws that were in effect immediately prior to the Act being enacted. The Company has completed the accounting for the effects of the Act. Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 35 percent to pretax income as follows (dollars in thousands): Year Ended December 31, 2017 2016 2015 Provision/(benefit) at statutory tax rate $ (6,314) 35.00 % $ (20,190) 35.00 % $ (148,925) 35.00 % State income tax provision, net of federal benefit (864) 4.79 % (774) 1.34 % (116) 0.03 % Permanent differences 50 (0.28) % 67 (0.12) % 30 (0.01) % Stock based compensation (361) 2.00 % 1,599 (2.77) % — — % Valuation allowance 7,209 (39.96) % 20,026 (34.72) % 55,310 (13.00) % Rate change (35% to 21% fed rate) 35,250 (195.41) % — — % — — % Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act (35,674) 197.76 % — — % — — % Other 309 (1.71) % (386) 0.68 % 2,008 (0.47) % Income tax provision /(benefit) $ (395) 2.19 % $ 342 (0.59) % $ (91,693) 21.55 % The effective tax rate for the years ended December 31, 2017, 2016 and 2015 varies from the statutory rate primarily as a result of recording a valuation allowance. The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands): Year Ended December 31, 2017 2016 2015 Current tax provision (benefit): Federal $ (424) $ (91) $ — State 453 433 636 Total $ 29 $ 342 $ 636 Deferred tax provision (benefit): Federal $ (424) $ — $ (92,329) State — — — Total $ (424) $ — $ (92,329) Total tax provision (benefit): Federal $ (848) $ (91) $ (92,329) State 453 433 636 Total $ (395) $ 342 $ (91,693) Included in gain (loss) from investment in affiliates $ — $ — $ (16,467) Total income tax provision (benefit) $ (395) $ 342 $ (75,226) The net deferred tax is comprised of the following (in thousands): December 31, 2017 2016 Deferred tax assets: Net operating loss carryforward $ 60,464 $ 69,828 Income tax credits 454 908 Derivative instruments 261 1,208 Deferred compensation 1,418 308 Oil and gas properties — 6,806 Other 491 1,477 Total deferred tax assets before valuation allowance $ 63,088 $ 80,535 Valuation allowance (49,032) (77,497) Net deferred tax assets $ 14,056 $ 3,038 Deferred tax liability: Oil and gas properties $ (10,567) $ — Investment in affiliates (3,065) (3,038) Other — — Deferred tax liability $ (13,632) $ (3,038) Total net deferred tax $ 424 $ — In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is not more-likely-than-not that it will realize the benefits of these deductible differences and has recorded a valuation allowance of $49.0 million. As of December 31, 2017, the Company had federal net operating loss (“NOL”) carryforwards of approximately $284.4 million and state NOLs of $20.4 million. The federal NOL carryforwards reported as of December 31, 2014 were acquired in the 2013 Merger with Crimson. A valuation allowance was recorded at the time of the Merger to reflect the impact of Internal Revenue Code Section 382 limitations on the use of the federal NOLs acquired. The federal NOL carryforwards expire at various dates beginning in 2018 and ending in 2037. ASC 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As a result of the Merger, the Company acquired certain tax positions taken by Crimson in prior years. These positions are not expected to have a material impact on results of operations, financial position or cash flows. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands): Unrecognized Tax Benefits Balance at December 31, 2016 $ 360 Additions based on tax positions related to the current year — Additions based on tax positions related to prior years — Additions due to acquisitions — Reductions due to a lapse of the applicable statute of limitations — Change in rate due to remeasurement (133) Balance at December 31, 2017 $ 227 The Company's policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in the Company’s Consolidated Statements of Operations. The Company had no interest or penalties related to unrecognized tax benefits for the year ended December 31, 2017 or any prior years. The total amount of unrecognized tax benefit, if recognized, that would affect the effective tax rate was zero. The Company's tax returns are subject to periodic audits by the various jurisdictions in which the Company operates. These audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable income. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2017. Generally, the Company's income tax years of 1998 through 2016 remain open and subject to examination by Federal tax authorities, and the tax years of 2010 through 2016 remain open and subject to examination by the tax authorities in Texas and Louisiana which are the jurisdictions where the Company carries its principal operations.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	16. Related Party Transactions Olympic Energy Partners Mr. Joseph J. Romano was elected President and Chief Executive Officer of the Company in December 2012 and named Chairman of the Company in April 2013. Upon the Merger with Crimson on October 1, 2013, Mr. Romano resigned as President and Chief Executive Officer, but continued as Chairman. Mr. Romano is also the President and Chief Executive Officer of Olympic Energy Partners LLC ("Olympic"). Olympic has historically participated with the Company in the drilling and development of certain prospects through participation agreements and joint operating agreements, which specify each participant’s working interest ("WI"), net revenue interest ("NRI") and describe when such interests are earned. Olympic last participated with the Company in the drilling of wells in March 2010, and its ownership in Company-operated wells is limited to its Dutch and Mary Rose wells as follows: Olympic WI NRI Dutch #1 - #5 Mary Rose #1 Mary Rose #2 - #3 Mary Rose #4 Mary Rose #5 During each of the years ended December 31, 2017 and 2016, Mr. Romano earned $56 thousand for his service as a director of the Company. Additionally, during the year ended December 31, 2017, Mr. Romano received 14,865 shares of restricted stock, which vest 100% on the one-year anniversary of the date of grant, as part of his board of director compensation. During the year ended December 31, 2016, Mr. Romano received 261 shares of restricted stock, pursuant to the Salary Replacement Program, and an additional 9,892 shares of restricted stock, which vest in one year, as part of Mr. Romano’s board of director compensation. The Company recognized compensation expense of $117 thousand and $99 thousand related to shares granted to Mr. Romano during the years ended December 31, 2017 and 2016, respectively. Below is a summary of payments the Company received from (paid to) Olympic in the ordinary course of business in its 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): Year Ended December 31, 2017 2016 2015 Revenue payments as well owners $ (2,673) $ (2,485) $ (4,115) Joint interest billing receipts 391 323 531 As of December 31, 2017 and 2016, the Company's consolidated balance sheets reflected the following balances relating to Olympic (in thousands): Year Ended December 31, 2017 2016 Accounts Receivable: Joint interest billing $ 48 $ 59 Accounts Payable: Royalties and revenue payable (442) (557) Oaktree Capital Management L.P. In November 2017, Oaktree Capital Management L.P. ("Oaktree") sold all of its shares of the Company's stock. Mr. James Ford, previously a Managing Director and Portfolio Manager within Oaktree, and a Senior Advisor to Oaktree at the time of sale, has been on the Company’s board of directors since October 1, 2013. Mr. Ford was previously a member of Crimson’s board of directors from February 2005 until the closing of the Merger. Historically, all cash and equity awards payable to Mr. Ford were instead granted to an affiliate of Oaktree. Beginning October 1, 2016, all cash and equity awards payable to Oaktree for Mr. Ford’s service as a director became payable to him directly. During the year ended December 31, 2017, Mr. Ford directly earned $68 thousand for his service. During the year ended December 31, 2016, Mr. Ford directly earned $18 thousand for his service, and the affiliate of Oaktree earned $48 thousand, as a result of Mr. Ford’s participation. During the year ended December 31, 2017, Mr. Ford received 14,865 shares of restricted stock, which vest 100% on the one-year anniversary of the date of grant, as part of his board of director compensation. During the year ended December 31, 2016, the affiliate of Oaktree received 313 shares of restricted stock, pursuant to the Salary Replacement Program, and an additional 9,892 shares of restricted stock, which also vest in one year, as part of Mr. Ford’s board of director compensation. During the years ended December 31, 2017 and 2016, the Company recognized compensation expense of $117 thousand and $99 thousand, respectively, related to the shares granted to an affiliate of Oaktree and Mr. Ford.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	17. Subsequent Events The Company has evaluated subsequent events through the date the financial statements were available to be issued. Nothing that would require recognition or disclosure in the financial statements was identified in addition to the items disclosed in the financial statements.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Summary Of Significant Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and 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. Oil and gas exploration and development affiliates which are not controlled by the Company, such as Republic Exploration LLC (“REX”), are proportionately consolidated. REX was dissolved as of December 31, 2015.
Other Investments	Other Investments The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company's proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statement of operations, the Company’s proportionate share of Exaro's net income or loss is reported as a single line-item in Gain (loss) from investment in affiliates (net of income taxes).
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates include oil and gas revenues, income taxes, stock-based compensation, reserve estimates, impairment of natural gas and oil properties, valuation of derivatives and accrued liabilities. Actual results could differ from those estimates.
Revenue Recognition	Revenue Recognition Revenues from the sale of natural gas and oil produced are recognized upon the passage of title, net of royalties. Revenues from natural gas production are recorded using the sales method. When sales volumes exceed the Company’s entitled share, production imbalance occurs. If production imbalance exceeds the Company’s share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. As of December 31, 2017 , 2016 and 2015, the Company had no significant imbalances.
Cash Equivalents	Cash Equivalents Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2017 , the Company had no cash and cash equivalents, as cash balances at the end of each day are transferred to reduce outstanding debt under the Company’s revolving credit facility to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2017, accounts payable included $2.3 million in outstanding checks that had not been presented for payment. At December 31, 2016, accounts payable included $3.5 million in outstanding checks that had not been presented for payment.
Accounts Receivable	Accounts Receivable The Company sells natural gas and crude oil to a limited number of customers. In addition, the Company participates with other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accounts receivables are due from either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells for which the Company serves as the operator. Generally, operators of natural gas and crude oil properties have the right to offset future revenues against unpaid charges related to operated wells. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance. Accounts receivable allowance for bad debt was $0.8 and $0.7 million as of December 31, 2017 and 2016, respectively . At December 31, 2017 and 2016, the carrying value of the Company’s accounts receivable approximated fair value.
Oil and Gas Properties - Successful Efforts	Oil and Gas Properties - Successful Efforts The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. Depreciation, depletion and amortization is calculated on a field by field basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other capitalized costs amortized over proved developed reserves. Depreciation, depletion and amortization ("DD&A") of capitalized drilling and development costs of producing natural gas and crude oil properties, including related support equipment and facilities net of salvage value, are computed using the unit of production method on a field basis based on total estimated proved developed natural gas and crude oil reserves. Amortization of producing leaseholds is based on the unit of production method using total estimated proved reserves. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates. Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 13 years.
Impairment of Oil and Gas Properties	Impairment of Oil and Gas Properties 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 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. For the year ended December 31, 2017, the Company recorded an impairment expense of approximately $0.3 million related to proved properties. For the year ended December 31, 2016, the Company recorded an impairment expense of approximately $0.7 million related to proved properties. For the year ended December 31, 2015, the Company recorded an impairment expense of approximately $269.6 million related to proved properties. Approximately $235.8 million of this amount was attributable to the Madison/Grimes counties and Zavala/Dimmit/Karnes counties properties. Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, and any such impairment is charged to expense in the period. During the year ended December 31, 2017, the Company recognized impairment expense of approximately $1.5 million related to the partial impairment of two unused offshore platforms in onshore storage. During the year ended December 31, 2016, the Company recognized impairment expense of approximately $6.8 million related to unproved properties in Fayette and Gonzales counties, Texas and $2.9 million related to unproved acreage in Natrona County, Wyoming. During the year ended December 31, 2015, the Company recognized impairment expense of approximately $16.3 million related to impairment and partial impairment of certain unproved properties and onshore prospects due primarily to the sustained low commodity price environment and expiring leases. Approximately $9.3 million of this amount related to unproved lease cost amortization of properties in Fayette and Gonzales counties, Texas.
Asset Retirement Obligations	Asset Retirement Obligations ASC 410, Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records an asset retirement obligation (“ARO”) to reflect the Company's legal obligation related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in depreciation, depletion and amortization expense. The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and gas properties expense. See Note 11 - "Asset Retirement Obligation" for additional information.
Income Taxes	Income Taxes The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2017 . The amount of unrecognized tax benefits did not materially change from December 31, 2016 . The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its statement of operations. The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal tax returns for 1998 – 2016 , and state tax returns for 2010 – 2016 , remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed.
Concentration of Credit Risk	Concentration of Credit Risk Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 - "Concentration of Credit Risk" for additional information.
Debt Issuance Costs	Debt Issuance Costs Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. During the year ended December 31, 2013, the Company initially incurred $2.2 million of debt issuance costs relating to the new RBC credit facility entered into in conjunction with the Merger with Crimson. The debt issuance costs were to be amortized over the original four year term of the credit line. In connection with RBC Credit Facility amendment in May 2016, the Company incurred an additional $1.0 million of debt issuance costs. As of December 31, 2017, the remaining balance of these debt issuance costs was $0.8 million, which will be amortized through October 1, 2019, with amortization expense included in the DD&A line item in the Company's income statement for the years ended December 31, 2017, 2016 and 2015.
Stock-Based Compensation	Stock-Based Compensation The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each restricted stock award is estimated as of the date of grant. The fair value of the Performance Stock Units is estimated as of the date of grant using the Monte Carlo simulation pricing model.
Inventory	Inventory Inventory primarily consists of casing and tubing which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method.
Derivatives Instruments and Hedging Activities	Derivative Instruments and Hedging Activities The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in "Gain (loss) on derivatives, net" on the consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015. Derivative instruments with settlement dates within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates a net asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 - "Derivative Instruments" for additional information.
Subsidiary Guarantees	Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), 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. Crimson Exploration Inc., Crimson Exploration Operating, Inc., Contango Energy Company, Contango Operators, Inc., Contango Mining Company, Conterra Company, Contaro Company, Contango Alta Investments, Inc., Contango Venture Capital Corporation, Contango Rocky Mountain Inc. and any other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. 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 other wholly-owned subsidiary that is inactive. 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 2017-01). 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 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. 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. This new standard is now effective for annual reporting periods beginning after December 15, 2017, and the Company has completed the assessment of this standard. The impact on the Company’s financial statements is not material, and there is no material impact expected to opening retained earnings. The standard was adopted January 1, 2018 using the modified retrospective method. Certain items netted in revenue or recorded as expense prior to adoption have changed based on the requirements of the new ASU using the control model and the definitions of parties to the contract as principal or agent. The company implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and additional disclosures will be required in our Form 10-Q for the three months ended March 31, 2018.

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments [Abstract]
Schedule Of Derivative Contracts	The Company had the following financial derivative contracts in place as of December 31, 2017: Commodity Period Derivative Volume/Month Price/Unit Natural Gas Jan 2018 - July 2018 Swap 370,000 MMBtus $ 3.07 (1) Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $ 3.07 (1) Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $ 3.07 (1) Oil Jan 2018 - June 2018 Swap 20,000 Bbls $ 56.40 (2) Oil July 2018 - Oct 2018 Collar 20,000 Bbls $ 52.00 - 56.85 (2) Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $ 52.00 - 56.85 (2) Oil Jan 2018 - Dec 2018 Collar 2,000 Bbls $ 52.00 - 58.76 (3) Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) Additionally, in January 2018, the Company entered into the following additional derivative contracts with members of its bank group: Commodity Period Derivative Volume/Month Price/Unit Oil Jan 2018 - July 2018 Collar 6,000 Bbls $ 58.00 - 68.00 (2) Oil Nov 2018 - Dec 2018 Collar 5,000 Bbls $ 58.00 - 68.00 (2) Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on Argus Louisiana Light Sweet crude oil prices. (3) Based on West Texas Intermediate crude oil prices. The Company had the following financial derivative contracts in place as of December 31, 2016: Commodity Period Derivative Volume/Month Price/Unit (1) Natural Gas Jan 2017 - July 2017 Collar 400,000 MMBtus $ 2.65 - 3.00 Natural Gas Aug 2017 - Oct 2017 Collar 200,000 MMBtus $ 2.65 - 3.00 Natural Gas Nov 2017 - Dec 2017 Collar 400,000 MMBtus $ 2.65 - 3.00 Natural Gas Jan 2017 - July 2017 Swap 300,000 MMBtus $ 3.51 Natural Gas Aug 2017 - Oct 2017 Swap 70,000 MMBtus $ 3.51 Natural Gas Nov 2017 - Dec 2017 Swap 300,000 MMBtus $ 3.51 Oil Jan 2017 - July 2017 Swap 9,000 Bbls $ 53.95 Oil Aug 2017 - Oct 2017 Swap 6,000 Bbls $ 53.95 Oil Nov 2017 - Dec 2017 Swap 8,000 Bbls $ 53.95 Oil Jan 2017 - Dec 2017 Swap 9,000 Bbls $ 56.20 (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 December 31, 2017 (in thousands). Gross Netting (1) Total Assets $ 1,188 $ (1,188) $ — Liabilities $ (2,431) $ 1,188 $ (1,243) (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 years ended December 31, 2017, 2016 and 2015 (in thousands): Year Ended December 31, Contract Type 2017 2016 2015 Crude oil contracts $ 861 $ 1,814 $ 2,348 Natural gas contracts 260 — — Realized gain $ 1,121 $ 1,814 $ 2,348 Crude oil contracts $ (2,065) $ — $ — Natural gas contracts 4,269 (3,446) — Unrealized gain (loss) $ 2,204 $ (3,446) $ — Gain (loss) on derivatives, net $ 3,325 $ (1,632) $ 2,348

Stock Based Compensation (Table

Stock Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Stock-Based Compensation [Abstract]
Summary Of Stock Options Granted	A summary of stock options as of and for the years ended December 31, 2017 , 2016 and 2015 is presented in the table below (dollars in thousands, except per share data): Year Ended December 31, 2017 2016 2015 Weighted Weighted Weighted Shares Average Shares Average Shares Average Under Exercise Under Exercise Under Exercise Options Price Options Price Options Price Outstanding, beginning of the period 111,905 $ 55.53 116,461 $ 55.03 129,934 $ 53.85 Exercised — $ — — $ — — $ — Expired / Forfeited (17,072) $ 43.50 (4,556) $ 42.92 (13,473) $ 43.65 Outstanding, end of year 94,833 $ 57.69 111,905 $ 55.53 116,461 $ 55.03 Aggregate intrinsic value $ — $ — $ — Exercisable, end of year 94,833 $ 57.69 111,905 $ 55.53 116,461 $ 55.03 Aggregate intrinsic value $ — $ — $ — Available for grant, end of the period * 2,002,492 323,172 885,449 Weighted average fair value of options granted during the period $ — $ — $ — * Excludes Performance Stock Units.
Summary Of Restricted Stock Activity	Restricted stock activity as of December 31, 2017, 2016 and 2015 and for the years then ended is presented in the table below (dollars in thousands, except per share data): 2017 2016 2015 Weighted Aggregate Weighted Aggregate Weighted Aggregate Restricted Average Intrinsic Restricted Average Intrinsic Restricted Average Intrinsic Shares Fair Value Value Shares Fair Value Value Shares Fair Value Value Outstanding, beginning of the period 638,158 $ 14.22 $ 5,960 337,165 $ 28.16 $ 2,161 209,962 $ 43.86 $ 6,139 Granted 457,701 7.55 3,457 580,141 10.99 6,375 277,121 21.83 6,049 Vested (222,568) 15.12 1,263 (260,058) 24.51 2,422 (137,195) 39.35 1,169 Canceled / Forfeited (142,218) 10.23 814 (19,090) 22.03 202 (12,723) 32.97 154 Not vested, end of the period 731,073 10.55 1,667 638,158 14.22 5,960 337,165 28.16 2,161 Vested, end of the period — — — — — — — — — Expected to vest, end of the period 690,016 10.58 1,574 590,511 14.28 5,515 312,986 28.17 2,006

Other Financial Information (Ta

Other Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Other Financial Information [Abstract]
Schedule Of Additional Financial Details	The following table provides additional detail for accounts receivable, prepaids, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): December 31, December 31, 2017 2016 Accounts receivable: Trade receivables $ 6,565 $ 8,424 Receivable for Alta Resources distribution 1,993 1,993 Joint interest billings 4,030 3,519 Income taxes receivable 424 91 Other receivables 828 3,395 Allowance for doubtful accounts (781) (695) Total accounts receivable $ 13,059 $ 16,727 Prepaid expenses and other: Prepaid insurance $ 1,177 $ 1,086 Other 715 701 Total prepaid expenses and other $ 1,892 $ 1,787 Accounts payable and accrued liabilities: Royalties and revenue payable $ 18,181 $ 16,920 Advances from partners 2,243 5,792 Accrued exploration and development 8,400 11,176 Accrued carried well costs — 7,155 Trade payables 9,559 5,406 Accrued general and administrative expenses 2,960 5,016 Accrued operating expenses 1,654 1,867 Other accounts payable and accrued liabilities 3,758 1,803 Total accounts payable and accrued liabilities $ 46,755 $ 55,135
Schedule Of Supplemental Disclosures	Year Ended December 31, 2017 2016 2015 Cash payments: Interest payments $ 3,699 $ 3,806 $ 3,147 Income tax payments (refunds), net of cash refunds 616 (2,089) (180) Non-cash items excluded from investing activities in the consolidated statements of cash flows: Increase (decrease) in accrued capital expenditures (9,931) 14,672 (22,879)

Investment In Exaro Energy II28

Investment In Exaro Energy III LLC (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule Of Condensed Balance Sheet Data	December 31, December 31, 2017 2016 (in thousands) Current assets (1) $ 17,063 $ 25,296 Non-current assets: Net property and equipment 82,450 90,621 Gas processing deposit 1,150 1,150 Other non-current assets 390 8 Total non-current assets 83,990 91,779 Total assets $ 101,053 $ 117,075 Current liabilities (2) $ 6,199 $ 65,694 Non-current liabilities: Long-term debt 40,375 — Other non-current liabilities 3,858 8,106 Total non-current liabilities 44,233 8,106 Members' equity 50,621 43,275 Total liabilities & members' equity $ 101,053 $ 117,075 (1) Approximately $12.8 million and $19.6 million of current assets as of December 31, 2017 and December 31, 2016, respectively, is cash. (2) Approximately $59.3 million of current liabilities as of December 31, 2016, was attributable to Exaro’s senior loan facility maturing in 2017, which has since been refinanced.
Exaro Energy III LLC [Member]
Schedule Of Condensed Income Statement Data	Year Ended December 31, 2017 2016 2015 ($ in thousands) Production: Oil (MBbls) 101 127 166 Gas (MMcf) 9,019 10,626 13,059 Total (Mmcfe) 9,625 11,388 14,055 Oil and natural gas sales $ 32,281 $ 30,028 $ 40,474 Other gain (loss) 5,368 (3,889) 6,358 Less: Lease operating expenses 15,479 15,846 20,922 Depreciation, depletion, amortization & accretion 9,857 10,644 29,417 Impairment expense — — 118,000 General & administrative expense 2,920 3,123 3,255 Income (loss) from continuing operations 9,393 (3,474) (124,762) Net other income (expense) (2,189) 7,900 (2,910) Net income (loss) $ 7,204 $ 4,426 $ (127,672)

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	Activities related to the Company’s ARO during the year ended December 31, 2017 and 2016 were as follows (in thousands): Year Ended December 31, 2017 2016 Balance as of the beginning of the period $ 26,926 $ 27,109 Liabilities incurred during period 308 69 Liabilities settled during period (4,503) (707) Accretion 1,056 1,187 Sales (2,949) (851) Change in estimate 1,567 119 Balance as of the end of the period $ 22,405 $ 26,926

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies [Abstract]
Schedule of Minimum Future Lease Operating Leases	As of December 31, 2017, minimum future lease payments for delay rentals and operating leases for Contango’s fiscal years are as follows (in thousands): Fiscal years ending December 31, 2018 $ 3,542 2019 849 2020 112 2021 89 2022 82 2023 and thereafter 81 Total $ 4,755

Net Loss Per Common Share (Tabl

Net Loss Per Common Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Components Of Basic And Diluted Net Loss Per Share Of Common Stock	Year Ended December 31, 2017 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (17,643) 24,686 $ (0.71) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (17,643) 24,686 $ (0.71) Year Ended December 31, 2016 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (58,029) 21,424 $ (2.71) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (58,029) 21,424 $ (2.71) Year Ended December 31, 2015 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (335,048) 18,965 $ (17.67) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options and restricted stock) — — — Net loss attributable to common stock $ (335,048) 18,965 $ (17.67)

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Taxes [Abstract]
Schedule Of Effective Income Tax Rate Reconciliation	Year Ended December 31, 2017 2016 2015 Provision/(benefit) at statutory tax rate $ (6,314) 35.00 % $ (20,190) 35.00 % $ (148,925) 35.00 % State income tax provision, net of federal benefit (864) 4.79 % (774) 1.34 % (116) 0.03 % Permanent differences 50 (0.28) % 67 (0.12) % 30 (0.01) % Stock based compensation (361) 2.00 % 1,599 (2.77) % — — % Valuation allowance 7,209 (39.96) % 20,026 (34.72) % 55,310 (13.00) % Rate change (35% to 21% fed rate) 35,250 (195.41) % — — % — — % Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act (35,674) 197.76 % — — % — — % Other 309 (1.71) % (386) 0.68 % 2,008 (0.47) % Income tax provision /(benefit) $ (395) 2.19 % $ 342 (0.59) % $ (91,693) 21.55 %
Components Of Income Tax Expense (Benefit)	The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands): Year Ended December 31, 2017 2016 2015 Current tax provision (benefit): Federal $ (424) $ (91) $ — State 453 433 636 Total $ 29 $ 342 $ 636 Deferred tax provision (benefit): Federal $ (424) $ — $ (92,329) State — — — Total $ (424) $ — $ (92,329) Total tax provision (benefit): Federal $ (848) $ (91) $ (92,329) State 453 433 636 Total $ (395) $ 342 $ (91,693) Included in gain (loss) from investment in affiliates $ — $ — $ (16,467) Total income tax provision (benefit) $ (395) $ 342 $ (75,226)
Schedule Of Net Deferred Tax Liability	The net deferred tax is comprised of the following (in thousands): December 31, 2017 2016 Deferred tax assets: Net operating loss carryforward $ 60,464 $ 69,828 Income tax credits 454 908 Derivative instruments 261 1,208 Deferred compensation 1,418 308 Oil and gas properties — 6,806 Other 491 1,477 Total deferred tax assets before valuation allowance $ 63,088 $ 80,535 Valuation allowance (49,032) (77,497) Net deferred tax assets $ 14,056 $ 3,038 Deferred tax liability: Oil and gas properties $ (10,567) $ — Investment in affiliates (3,065) (3,038) Other — — Deferred tax liability $ (13,632) $ (3,038) Total net deferred tax $ 424 $ —
Schedule Of Unrecognized Tax Benefits	A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands): Unrecognized Tax Benefits Balance at December 31, 2016 $ 360 Additions based on tax positions related to the current year — Additions based on tax positions related to prior years — Additions due to acquisitions — Reductions due to a lapse of the applicable statute of limitations — Change in rate due to remeasurement (133) Balance at December 31, 2017 $ 227

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule Of Oil and Gas Ownership Interests	Olympic WI NRI Dutch #1 - #5 Mary Rose #1 Mary Rose #2 - #3 Mary Rose #4 Mary Rose #5
Schedule Of Payments Received From (Made To) Related Parties	The Company made and received similar types of payments with other well owners (in thousands): Year Ended December 31, 2017 2016 2015 Revenue payments as well owners $ (2,673) $ (2,485) $ (4,115) Joint interest billing receipts 391 323 531
Schedule Of Related Party Balances	As of December 31, 2017 and 2016, the Company's consolidated balance sheets reflected the following balances relating to Olympic (in thousands): Year Ended December 31, 2017 2016 Accounts Receivable: Joint interest billing $ 48 $ 59 Accounts Payable: Royalties and revenue payable (442) (557)

Organization and Business (Deta

Organization and Business (Details)	12 Months Ended
	Dec. 31, 2017aitem
Southern Delaware Basin Of Texas [Member]
Gas and Oil Acreage [Line Items]
Gross acres - Operated	16,500
Net acres - Operated	6,800
Number of wells | item	7
Exaro Energy III LLC [Member]
Gas and Oil Acreage [Line Items]
Equity method investment, ownership percentage	37.00%

Summary of Significant Accoun35

Summary of Significant Accounting Policies (Details) $ in Thousands	1 Months Ended		12 Months Ended
	May 31, 2016USD ($)	Oct. 31, 2013USD ($)	Dec. 31, 2017USD ($)item	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2013USD ($)
Significant Accounting Policies [Line Items]
Gas balancing asset (liability)			$ 0	$ 0	$ 0
Cash and cash equivalents			0	0	0
Outstanding checks in accounts payable that have not yet been presented for payment			2,300	3,500
Allowance for doubtful accounts receivable			800	700
Impairment of proved properties			300	700	269,600
Impairment charges, unproved properties			$ 1,500		16,300
Number of platforms | item			2
Debt issuance costs incurred				996
Number of subsidiaries inactive and not Subsidiary Guarantor | item			1
RBC Credit Facility [Member]
Significant Accounting Policies [Line Items]
Debt issuance costs incurred	$ 1,000	$ 2,200				$ 2,200
Original term of credit line		4 years				4 years
Remaining balance debt issue costs			$ 800
Madison/Grimes and Zavala/Dimmitt/Karnes Counties[Member]
Significant Accounting Policies [Line Items]
Impairment of proved properties					235,800
Fayette and Gonzales [Member]
Significant Accounting Policies [Line Items]
Impairment charges, unproved properties				6,800	$ 9,300
Natrona County Wyoming [Member]
Significant Accounting Policies [Line Items]
Impairment charges, unproved properties				$ 2,900
Maximum [Member]
Significant Accounting Policies [Line Items]
Property and equipment depreciation, estimated useful life			13 years
Restricted assets, percent of net assets			25.00%
Minimum [Member]
Significant Accounting Policies [Line Items]
Property and equipment depreciation, estimated useful life			3 years
Exaro Energy III LLC [Member]
Significant Accounting Policies [Line Items]
Number of seats on Board of Directors | item			2
Equity method investment, ownership percentage			37.00%

Concentration of Credit Risk (D

Concentration of Credit Risk (Details) - Sales Revenue, Goods, Net [Member] - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2017
Concentration Risk [Line Items]
Number of months of potential revenue loss	2 months
ConocoPhillips Company [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	51.20%

Acquisitions, Dispositions an37

Acquisitions, Dispositions and Gains from Affiliates (Details)	Feb. 01, 2017USD ($)	Jul. 31, 2016USD ($)aitem	Dec. 31, 2017USD ($)aitem	Dec. 31, 2016USD ($)	Dec. 30, 2016USD ($)a
Acquisition
Carried well cost				$ 7,155,000
Southern Delaware Basin Of Texas [Member]
Acquisition
Percentage of working interest acquired		50.00%
Gross acres - Undeveloped | a		12,100
Net acres - Undeveloped | a		5,000
Cash consideration for acquisition		$ 10,000,000
Carried well cost		10,000,000
Number of wells | item			7
Carried cost payments			$ 10,000,000
Spud bonus			$ 1,100,000
Gross acres - Operated | a			16,500
Net acres - Operated | a			6,800
Southern Delaware Basin Of Texas [Member] | Maximum [Member]
Acquisition
Estimated consideration		$ 25,000,000
Disposal Group Disposed Of By Sale Not Discontinued Operations [Member] | Colorado Properties [Member]
Acquisition
Aggregate sales price of assets sold					$ 5,000,000
Gross acres - Developed | a					16,000
Net acres - Developed | a					11,200
Disposal Group Disposed Of By Sale Not Discontinued Operations [Member] | Southeast Texas Assets [Member]
Acquisition
Aggregate sales price of assets sold	$ 650,000
Gain on sale of oil and gas property	$ 2,900,000
Phase One [Member] | Southern Delaware Basin Of Texas [Member]
Acquisition
Number of wells | item		6
Phase Two [Member] | Southern Delaware Basin Of Texas [Member]
Acquisition
Number of wells | item		14
Spud bonus		$ 5,000,000

Fair Value Measurements (Detail

Fair Value Measurements (Details)	12 Months Ended
	Dec. 31, 2017
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	3 months

Derivative Instruments (Derivat

Derivative Instruments (Derivative Contracts) (Details)	1 Months Ended	12 Months Ended
	Jan. 31, 2018item$ / bbl	Dec. 31, 2017item$ / bbl$ / Mcf	Dec. 31, 2016item$ / bbl$ / Mcf	Dec. 31, 2015USD ($)
Derivative [Line Items]
Fair Value | $				$ 0
Derivative Contract Period January To July 2017 [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			400,000
Price/Unit-Floor | $ / Mcf			2.65
Price/Unit-Cap | $ / Mcf			3
Derivative Contract Period January To July 2017 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			300,000
Price/Unit-Swap | $ / Mcf			3.51
Derivative Contract Period January To July 2017 [Member] | Swap [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			9,000
Price/Unit-Swap | $ / bbl			53.95
Derivative Contract Period, August to October 2017 [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			200,000
Price/Unit-Floor | $ / Mcf			2.65
Price/Unit-Cap | $ / Mcf			3
Derivative Contract Period, August to October 2017 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			70,000
Price/Unit-Swap | $ / Mcf			3.51
Derivative Contract Period, August to October 2017 [Member] | Swap [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			6,000
Price/Unit-Swap | $ / bbl			53.95
Derivative Contract Period, November to December 2017 [Member] | Collar Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			400,000
Price/Unit-Floor | $ / Mcf			2.65
Price/Unit-Cap | $ / Mcf			3
Derivative Contract Period, November to December 2017 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			300,000
Price/Unit-Swap | $ / Mcf			3.51
Derivative Contract Period, November to December 2017 [Member] | Swap [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			8,000
Price/Unit-Swap | $ / bbl			53.95
Derivative Contract Period January To December 2017 | Swap [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate			9,000
Price/Unit-Swap | $ / bbl			56.20
Derivative Contract Period January To July 2018 [Member] | Collar Options [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	6,000
Price/Unit-Floor | $ / bbl	58
Price/Unit-Cap | $ / bbl	68
Derivative Contract Period January To July 2018 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		370,000
Price/Unit-Swap | $ / Mcf		3.07
Derivative Contract Period August To October 2018 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		70,000
Price/Unit-Swap | $ / Mcf		3.07
Derivative Contract Period November To December 2018 [Member] | Collar Options [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	5,000	15,000
Price/Unit-Floor | $ / bbl	58	52
Price/Unit-Cap | $ / bbl	68	56.85
Derivative Contract Period November To December 2018 [Member] | Swap [Member] | Natural Gas [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		320,000
Price/Unit-Swap | $ / Mcf		3.07
Derivative Contract Period January To June 2018 [Member] | Swap [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		20,000
Price/Unit-Swap | $ / bbl		56.40
Derivative Contract Period July To October 2018 [Member] | Collar Options [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		20,000
Price/Unit-Floor | $ / bbl		52
Price/Unit-Cap | $ / bbl		56.85
Derivative Contract Period January To December 2018 | Collar Options [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate		2,000
Price/Unit-Floor | $ / bbl		52
Price/Unit-Cap | $ / bbl		58.76
Derivative Contract Period, January to December 2019 [Member] | Collar Options [Member] | Oil [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate	4,000	7,000
Price/Unit-Floor | $ / bbl	52	50
Price/Unit-Cap | $ / bbl	59.45	58

Derivative Instruments (Fair Va

Derivative Instruments (Fair Value) (Details) - Commodity Derivatives [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets
Gross	$ 1,188
Netting	(1,188)
Liabilities:
Gross	(2,431)	$ (3,446)
Netting	1,188
Total	$ (1,243)	$ (3,446)

Derivative Instruments (Operati

Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain	$ 1,121	$ 1,814	$ 2,348
Unrealized gain (loss)	2,204	(3,446)
Gain (loss) on derivatives, net	3,325	(1,632)	2,348
Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain	861	1,814	$ 2,348
Unrealized gain (loss)	(2,065)
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain	260
Unrealized gain (loss)	$ 4,269	$ (3,446)

Stock Based Compensation (Narra

Stock Based Compensation (Narrative) (Details) - USD ($) $ in Thousands	Sep. 15, 2009	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 25, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant		2,002,492	323,172	885,449
Options issued and outstanding		94,833	111,905	116,461		129,934
Options vested and exercisable (in shares)		94,833	111,905	116,461
Stock-based compensation		$ 6,100	$ 6,457	$ 6,516
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock vested in period, non options (in shares)		222,568	260,058	137,195
Stock-based compensation		$ 6,100	$ 6,500	$ 6,500
Compensation expense not yet recognized		$ 5,600
Restricted Stock [Member] | Board of Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		1 year	1 year	1 year
Restricted Stock [Member] | New And Existing Employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years		4 years
Restricted Stock [Member] | New And Existing Employees [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)			3 years
Restricted Stock [Member] | New And Existing Employees [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)			4 years
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		3 years
Performance Stock Units [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target (as a percent)		0.00%
Performance Stock Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target (as a percent)		300.00%
2009 Equity Compensation Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant		1,600,000
2009 Equity Compensation Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	4 years
2009 Equity Compensation Plan [Member] | Employee Stock Options [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration term	5 years
2009 Equity Compensation Plan [Member] | Employee Stock Options [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration term	10 years
2009 Equity Compensation Plan [Member] | Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target (as a percent)		100.00%
Stock Incentive Plan 2005 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for grant					0

Stock Based Compensation (Optio

Stock Based Compensation (Options) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 25, 2015
Option roll forward
Outstanding, beginning of year (in shares)	111,905	116,461	129,934
Expired / Forfeited (in shares)	(17,072)	(4,556)	(13,473)
Outstanding, end of year (in shares)	94,833	111,905	116,461
Exercisable, end of year (in shares)	94,833	111,905	116,461
Available for grant, end of year (in shares)	2,002,492	323,172	885,449
Option roll forward per share
Outstanding, beginning of year (in dollars per share)	$ 55.53	$ 55.03	$ 53.85
Expired / Forfeited (in dollars per share)	43.50	42.92	43.65
Outstanding, end of year (in dollars per share)	57.69	55.53	55.03
Exercisable, end of year (in dollars per share)	$ 57.69	$ 55.53	$ 55.03
Stock-based compensation
Excess tax benefit from exercise/cancellation of stock options	$ 0	$ 0	$ 0
Aggregate intrinsic value of exercises during period	$ 0	$ 0	$ 0
Stock Incentive Plan 2005 [Member]
Option roll forward
Available for grant, end of year (in shares)				0

Stock Based Compensation (NonOp

Stock Based Compensation (NonOption) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted Stock [Member]
Activity, shares
Outstanding, beginning of the period (in shares)	638,158	337,165	209,962
Granted non-option (in shares)	457,701	580,141	277,121
Vested (in shares)	(222,568)	(260,058)	(137,195)
Canceled/Forfeited (in shares)	(142,218)	(19,090)	(12,723)
Not vested, end of the period (in shares)	731,073	638,158	337,165
Expected to vest, end of the period (in shares)	690,016	590,511	312,986
Activity, weighted average fair value
Outstanding, beginning of the period (in dollars per share)	$ 14.22	$ 28.16	$ 43.86
Granted (in dollars per share)	7.55	10.99	21.83
Vested (in dollars per share)	15.12	24.51	39.35
Canceled/Forfeited (in dollars per share)	10.23	22.03	32.97
Not vested, end of the period (in dollars per share)	10.55	14.22	28.16
Expected to vest (in dollars per share)	$ 10.58	$ 14.28	$ 28.17
Activity, intrinsic value
Outstanding, beginning of the period	$ 5,960	$ 2,161	$ 6,139
Granted	3,457	6,375	6,049
Vested	1,263	2,422	1,169
Canceled/Forfeited	814	202	154
Not vested, end of the period	1,667	5,960	2,161
Expected to vest, end of the period	1,574	5,515	2,006
Stock-based compensation
Value of issued stock after adjustment for estimated forfeiture rate	$ 3,500	$ 6,400	$ 6,100
Weighted average forfeiture rate	4.80%	4.20%	4.90%
Performance Stock Units [Member]
Activity, shares
Canceled/Forfeited (in shares)	(99,363)	(1,300)
Stock-based compensation
Vesting period (in years)	3 years
Service period	3 years
New Employees [Member] | Performance Stock Units [Member]
Activity, shares
Granted non-option (in shares)	30,000	6,699
Activity, weighted average fair value
Granted (in dollars per share)	$ 8.32	$ 13.06
Employees [Member] | Performance Stock Units [Member]
Activity, shares
Granted non-option (in shares)		285,800
Activity, weighted average fair value
Granted (in dollars per share)		$ 16.32
New And Existing Employees [Member] | Restricted Stock [Member]
Activity, shares
Granted non-option (in shares)	383,376	489,805	249,917
Stock-based compensation
Vesting period (in years)	3 years		4 years
Board of Directors [Member] | Restricted Stock [Member]
Activity, shares
Granted non-option (in shares)	74,325	49,460	27,204
Stock-based compensation
Vesting period (in years)	1 year	1 year	1 year
Former Employee [Member] | Restricted Stock [Member]
Activity, shares
Canceled/Forfeited (in shares)	(142,218)	(19,090)	(12,723)
Executives [Member] | Performance Stock Units [Member]
Activity, shares
Granted non-option (in shares)	160,908
Activity, weighted average fair value
Granted (in dollars per share)	$ 13.91
Minimum [Member] | Performance Stock Units [Member]
Stock-based compensation
Target (as a percent)	0.00%
Minimum [Member] | New And Existing Employees [Member] | Restricted Stock [Member]
Stock-based compensation
Vesting period (in years)		3 years
Maximum [Member] | Performance Stock Units [Member]
Stock-based compensation
Target (as a percent)	300.00%
Maximum [Member] | New And Existing Employees [Member] | Restricted Stock [Member]
Stock-based compensation
Vesting period (in years)		4 years
Salary Replacement Plan [Member]
Stock-based compensation
Salary deferred (as a percent)			10.00%
Salary Replacement Plan [Member] | Restricted Stock [Member]
Activity, shares
Granted non-option (in shares)		40,876

Share Repurchase Programs (Deta

Share Repurchase Programs (Details) - $50 Million Share Repurchase Program [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 30, 2011
Equity, Class of Treasury Stock [Line Items]
Approved share repurchase program value				$ 50
Treasury shares at cost (in shares)	0	0	0
Value of repurchase program available for future purchases	$ 31.8

Other Financial Information (Ba

Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable:
Trade receivables	$ 6,565	$ 8,424
Receivable for Alta Resources Distribution	1,993	1,993
Joint interest billings	4,030	3,519
Income taxes receivable	424	91
Other receivables	828	3,395
Allowance for doubtful accounts	(781)	(695)
Total Accounts Receivable	13,059	16,727
Prepaid expenses and other:
Prepaid insurance	1,177	1,086
Other	715	701
Total prepaid expenses and other	1,892	1,787
Accounts payable and accrued liabilities:
Royalties and revenue payable	18,181	16,920
Advances from partners	2,243	5,792
Accrued exploration and development	8,400	11,176
Accrued carried well costs		7,155
Trade payables	9,559	5,406
Accrued operating expenses	1,654	1,867
Accrued general and administrative expenses	2,960	5,016
Other accounts payable and accrued liabilities	3,758	1,803
Total Accounts Payable and Accrued Liabilities	$ 46,755	$ 55,135

Other Financial Information (Su

Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash payments:
Interest payments	$ 3,699	$ 3,806	$ 3,147
Income tax payments (refunds), net of cash refunds	616	(2,089)	(180)
Non-cash items excluded from investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$ (9,931)	$ 14,672	$ (22,879)

Investment in Exaro Energy II48

Investment in Exaro Energy III LLC (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments Financials
Gain (loss) from investment in affiliates (net of income taxes)	$ 2,697	$ 1,545	$ (30,582)
Tax (expense) benefit from equity investment			16,467
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Investment in affiliate	$ 46,900
Equity method investment, ownership percentage	37.00%
Total Investment Commitment In Affiliates With Other Parties	$ 183,000
Share of equity in investment	18,400
Gain (loss) from investment in affiliates (net of income taxes)	2,700	1,500	(30,600)
Tax (expense) benefit from equity investment	0	$ 0	$ 16,500
Exaro Energy III LLC [Member] | Maximum [Member]
Schedule of Equity Method Investments Financials
Investment in affiliate	$ 67,500

Investment in Exaro Energy II49

Investment in Exaro Energy III LLC (Balance Sheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Non-current assets:
Net property and equipment	$ 345,957	$ 340,382
Other non-current assets	19,723	17,078
Non-current liabilities:
Other non-current liabilities	248	248
Cash and cash equivalents	0	0	$ 0
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Current assets	17,063	25,296
Non-current assets:
Net property and equipment	82,450	90,621
Gas processing deposit	1,150	1,150
Other non-current assets	390	8
Total non-current assets	83,990	91,779
Total assets	101,053	117,075
Current liabilities	6,199	65,694
Non-current liabilities:
Long-term debt	40,375
Other non-current liabilities	3,858	8,106
Total non-current liabilities	44,233	8,106
Member's equity	50,621	43,275
Total liabilities & member's equity	101,053	117,075
Cash and cash equivalents	$ 12,800	19,600
Current debt		$ 59,300

Investment in Exaro Energy II50

Investment in Exaro Energy III LLC (Income Statement) (Details) bbl in Thousands, Mcfe in Thousands, Mcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017Mcf	Dec. 31, 2017bbl	Dec. 31, 2017Mcfe	Dec. 31, 2017USD ($)	Dec. 31, 2016Mcf	Dec. 31, 2016bbl	Dec. 31, 2016Mcfe	Dec. 31, 2016USD ($)	Dec. 31, 2015Mcf	Dec. 31, 2015bbl	Dec. 31, 2015Mcfe	Dec. 31, 2015USD ($)
Schedule of Equity Method Investments Financials
Impairment expense				$ 1,785				$ 10,438				$ 285,870
General & administrative expense				24,161				26,802				26,402
Net income (loss)				(17,643)				(58,029)				(335,048)
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Production	9,019	101			10,626	127			13,059	166
Total Production (Mcfe) | Mcfe			9,625				11,388				14,055
Oil and natural gas sales				32,281				30,028				40,474
Other gain (loss)				5,368				(3,889)				6,358
Lease operating expenses				15,479				15,846				20,922
Depreciation, depletion, amortization & accretion				9,857				10,644				29,417
Impairment expense												118,000
General & administrative expense				2,920				3,123				3,255
Income (loss) from continuing operations				9,393				(3,474)				(124,762)
Net other income (expense)				(2,189)				7,900				(2,910)
Net income (loss)				$ 7,204				$ 4,426				$ (127,672)

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation [Abstract]
Balance as of the beginning of the period	$ 26,926	$ 27,109
Liabilities incurred during period	308	69
Liabilities settled during period	(4,503)	(707)
Accretion	1,056	1,187
Sales	(2,949)	(851)
Change in estimate	1,567	119
Balance as of the end of the period	$ 22,405	$ 26,926

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	May 06, 2016	May 31, 2016USD ($)	Oct. 31, 2013USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2013USD ($)	Nov. 06, 2017USD ($)
Debt Instrument [Line Items]
Arrangement fee					$ 996
Interest expense				$ 4,100	3,802	$ 3,164
RBC Credit Facility [Member]
Debt Instrument [Line Items]
Revolving credit facility, maximum borrowing capacity			$ 500,000
Original term of credit line			4 years				4 years
Revolving credit facility, borrowing base								$ 115,000
Commitment fee percentage	0.50%			0.50%
Arrangement fee		$ 1,000	$ 2,200				$ 2,200
Remaining balance debt issue costs				$ 800
Credit facility amount outstanding				85,400	54,400
Letters of credit amount outstanding				1,900	1,900
Line of credit, available				27,700
Interest expense				$ 4,100	$ 3,800	$ 3,200
Current ratio			1
Leverage ratio			3.50
RBC Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Variable interest rate (as a percent)	2.50%			2.50%
RBC Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Variable interest rate (as a percent)	4.00%			4.00%

Commitments and Contingencies53

Commitments and Contingencies (Leases) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Delay Rentals and Operating and Capital Leases [Abstract]
2,018	$ 3,542
2,019	849
2,020	112
2,021	89
2,022	82
2023 and thereafter	81
Total	4,755
Lease commitment	$ 4,800	$ 5,400	$ 6,300

Commitments And Contingencies54

Commitments And Contingencies (Narrative) (Details)	1 Months Ended			12 Months Ended
	Nov. 30, 2016USD ($)	Sep. 30, 2012USD ($)	Nov. 30, 2010USD ($)item	Dec. 31, 2017USD ($)
Employment Agreements
Employment agreement, extension term	1 year
Throughput commitment
Loss Contingency
Estimated deficiency				$ 1,000,000
Loss contingency expense				$ 1,800,000
Lavaca County Case [Member]
Legal Proceedings
Number of wells involved in litigation | item			2
Settlement awarded against Contango			$ 5,300,000
Litigation Case Filed by Mineral Interest Owner Harris County [Member]
Legal Proceedings
Damages sought by plaintiffs		$ 10,700,000
Additional portion of mineral interest claimed by plaintiff		0.0625%
CEO, Keel [Member]
Employment Agreements
Employment agreement, initial term	3 years
Base salary under employment agreement	$ 600,000
Cash bonus awards based on % of salary	100.00%
CFO, Grady [Member]
Employment Agreements
Employment agreement, initial term	3 years
Base salary under employment agreement	$ 400,000
Cash bonus awards based on % of salary	100.00%
VP, Mengle
Employment Agreements
Employment agreement, initial term	2 years
Base salary under employment agreement	$ 300,000
Cash bonus awards based on % of salary	80.00%
VP, Atkins
Employment Agreements
Employment agreement, initial term	2 years
Base salary under employment agreement	$ 310,000
Cash bonus awards based on % of salary	80.00%

Net Loss Per Common Share (Deta

Net Loss Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Net loss attributable to common stock	$ (17,643)	$ (58,029)	$ (335,048)
Weighted average shares, basic (in shares)	24,686,000	21,424,000	18,965,000
Diluted (in shares)	24,686,000	21,424,000	18,965,000
Basic (in dollars per share)	$ (0.71)	$ (2.71)	$ (17.67)
Diluted (in dollars per share)	$ (0.71)	$ (2.71)	$ (17.67)
Potentially dilutive (in shares)	1,282,590	1,282,957	453,626

Income Taxes (Tax Rate Reconcil

Income Taxes (Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Valuation allowance increase (decrease) due to normal operations		$ 7,200
Provision/(benefit) at statutory tax rate		(6,314)	$ (20,190)	$ (148,925)
State income tax provision, net of federal benefit		(864)	(774)	(116)
Permanent differences		50	67	30
Stock based compensation		(361)	1,599
Valuation allowance		7,209	20,026	55,310
Rate Change (35% to 21% fed rate)		35,250
Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act		(35,674)
Other		309	(386)	2,008
Total		$ (395)	$ 342	$ (91,693)
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Provision/(benefit) at statutory tax rate		35.00%	35.00%	35.00%
State income tax provision, net of federal benefit		4.79%	1.34%	0.03%
Permanent differences		(0.28%)	(0.12%)	(0.01%)
Stock based compensation		2.00%	(2.77%)
Valuation allowance		(39.96%)	(34.72%)	(13.00%)
Rate Change (35% to 21% fed rate)		(195.41%)
Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act		197.76%
Other		(1.71%)	0.68%	(0.47%)
Income tax provision /(benefit)		2.19%	(0.59%)	21.55%
Scenario, Forecast [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Provision/(benefit) at statutory tax rate	21.00%

Income Taxes (Expense Benefit)

Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
Federal	$ (424)	$ (91)
State	453	433	$ 636
Total	29	342	636
Deferred:
Federal	(424)		(92,329)
Total	(424)		(92,329)
Total:
Federal	(848)	(91)	(92,329)
State	453	433	636
Total	(395)	342	(91,693)
Included in gain from investment in affiliates			(16,467)
Income tax provision (benefit)	$ (395)	$ 342	$ (75,226)

Income Taxes (Deferred Tax) (De

Income Taxes (Deferred Tax) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets:
Net operating loss carryforward	$ 60,464	$ 69,828
Income tax credits	454	908
Derivative instruments	261	1,208
Deferred compensation	1,418	308
Oil and gas properties		6,806
Other	491	1,477
Total deferred tax assets before valuation allowance	63,088	80,535
Valuation allowance	(49,032)	(77,497)
Net deferred tax assets	14,056	3,038
Deferred tax liability:
Oil and gas properties	(10,567)
Investment in affiliates	(3,065)	(3,038)
Deferred tax liability	(13,632)	$ (3,038)
Total net deferred tax	$ 424

Income Taxes (NOL) (Details)

Income Taxes (NOL) (Details) $ in Millions	Dec. 31, 2017USD ($)
Federal [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 284.4
State [Member]
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 20.4

Income Taxes (Unrecognized Tax

Income Taxes (Unrecognized Tax Benefits) (Details)	12 Months Ended
	Dec. 31, 2017USD ($)
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Beginning Balance	$ 360,000
Change in rate due to remeasurement	133,000
Ending Balance	227,000
Interest and penalties related to unrecognized tax benefits	0
Unrecognized tax benefits that would impact effective tax rate	$ 0

Related Party Transactions (Wel

Related Party Transactions (Well Interests) (Details) - Olympic [Member]	Dec. 31, 2017
Dutch Number 1 - 5 [Member]
Related Party Transaction [Line Items]
Working interests	3.53%
Net revenue interest	2.84%
Mary Rose Number 1 [Member]
Related Party Transaction [Line Items]
Working interests	3.61%
Net revenue interest	2.70%
Mary Rose Number 2-3 [Member]
Related Party Transaction [Line Items]
Working interests	3.61%
Net revenue interest	2.58%
Mary Rose Number 4 [Member]
Related Party Transaction [Line Items]
Working interests	2.34%
Net revenue interest	1.70%
Mary Rose Number 5 [Member]
Related Party Transaction [Line Items]
Working interests	2.56%
Net revenue interest	1.87%

Related Party Transactions (Ser

Related Party Transactions (Services) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Mr. Romano [Member]
Related Party Transaction [Line Items]
Director compensation for related party	$ 56	$ 56
Stock-based compensation expense	$ 117	$ 99
Restricted Stock [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)	457,701	580,141	277,121
Restricted Stock [Member] | Mr. Romano [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)	14,865	9,892
Vesting period (in years)	1 year	1 year
Vesting percentage	100.00%
Salary Replacement Program [Member] | Restricted Stock [Member] | Mr. Romano [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)		261

Related Party Transactions (Oly

Related Party Transactions (Olympic) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounts receivable:
Accounts Receivable: Joint interest billing	$ 4,030	$ 3,519
Olympic [Member]
Related Party Transaction [Line Items]
Revenue payments as well owners	(2,673)	(2,485)	$ (4,115)
Joint interest billing receipts	391	323	$ 531
Accounts receivable:
Accounts Receivable: Joint interest billing	48	59
Accounts payable:
Accounts Payable: Royalties and revenue payable	(442)	(557)
Mr. Romano [Member]
Related Party Transaction [Line Items]
Director compensation for related party	56	56
Stock-based compensation expense	$ 117	$ 99
Restricted Stock [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)	457,701	580,141	277,121
Restricted Stock [Member] | Mr. Romano [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)	14,865	9,892
Vesting period (in years)	1 year	1 year
Restricted Stock [Member] | Salary Replacement Program [Member] | Mr. Romano [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)		261
Performance Stock Units [Member]
Related Party Transaction [Line Items]
Vesting period (in years)	3 years

Related Party Transactions (Oak

Related Party Transactions (Oaktree) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oaktree [Member]
Related Party Transaction [Line Items]
Director compensation for related party		$ 48
James Ford [Member]
Related Party Transaction [Line Items]
Director compensation for related party	$ 68	18
Stock-based compensation expense	$ 117	$ 99
Salary Replacement Program [Member] | James Ford [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)		313
Restricted Stock [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)	457,701	580,141	277,121
Restricted Stock [Member] | James Ford [Member]
Related Party Transaction [Line Items]
Restricted stock granted in period (in shares)	14,865	9,892
Vesting period (in years)	1 year	1 year
Vesting percentage	100.00%