Contango Oil & Gas (MCF) 10-Q 8 May 19 2019 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 03, 2019
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Entity Registrant Name	Contango Oil & Gas Company
Entity Central Index Key	0001071993
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		34,400,594
Entity Current Reporting Status	Yes
Entity Small Business	true
Entity Emerging Growth Company	false

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents
Accounts receivable, net	11,530	11,531
Prepaid expenses	468	1,303
Current derivative asset	1,371	4,600
Other current assets	112
Total current assets	13,481	17,434
Natural gas and oil properties, successful efforts method of accounting:
Proved properties	1,096,714	1,095,417
Unproved properties	35,538	34,612
Other property and equipment	1,331	1,314
Accumulated depreciation, depletion and amortization	(905,437)	(898,169)
Total property, plant and equipment, net	228,146	233,174
OTHER NON-CURRENT ASSETS:
Investments in affiliates	6,053	5,743
Deferred tax asset		424
Other	352	357
Total other non-current assets	6,405	6,524
TOTAL ASSETS	248,032	257,132
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	32,188	39,506
Current derivative liability	839	422
Current asset retirement obligations	1,373	1,329
Current portion of long-term debt	65,552	60,000
Total current liabilities	99,952	101,257
NON-CURRENT LIABILITIES:
Asset retirement obligations	12,108	12,168
Other long term liabilities	3,421	3,318
Total non-current liabilities	15,529	15,486
Total liabilities	115,481	116,743
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY:
Common stock, $0.04 par value, 50 million shares authorized, 39,925,092 shares issued and 34,416,727 shares outstanding at March 31, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018	1,585	1,573
Additional paid-in capital	340,935	339,981
Treasury shares at cost (5,508,365 shares at March 31, 2019 and 5,458,950 shares at December 31, 2018)	(129,216)	(129,030)
Retained earnings (deficit)	(80,753)	(72,135)
Total shareholders’ equity	132,551	140,389
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$ 248,032	$ 257,132

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Mar. 31, 2019	Dec. 31, 2018
CONSOLIDATED BALANCE SHEETS
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	39,925,092	39,617,442
Common stock, shares outstanding	34,416,727	34,158,492
Treasury stock, shares	5,508,365	5,458,950

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
REVENUES:
Revenues	$ 14,011	$ 20,437
EXPENSES:
Operating expenses	5,192	6,927
Exploration expenses	224	469
Depreciation, depletion and amortization	7,556	10,485
Impairment and abandonment of oil and gas properties	587	3,327
General and administrative expenses	5,005	6,726
Total expenses	18,564	27,934
OTHER INCOME (EXPENSE):
Gain (loss) from investment in affiliates (net of income taxes)	30	707
Gain (loss) from sale of assets and return on investments	(12)	9,447
Interest expense	(1,092)	(1,409)
Loss on derivatives, net	(2,878)	(1,032)
Other income (expense)	(86)	879
Total other income (expense)	(4,038)	8,592
NET INCOME (LOSS) BEFORE INCOME TAXES	(8,591)	1,095
Income tax provision	(27)	(158)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$ (8,618)	$ 937
NET INCOME (LOSS) PER SHARE:
Basic (in dollars per share)	$ (0.26)	$ 0.04
Diluted (in dollars per share)	$ (0.26)	$ 0.04
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic (in shares)	33,770	24,793
Diluted (in shares)	33,770	24,841
Oil and Condensate [Member]
REVENUES:
Revenues	$ 6,406	$ 8,811
Natural Gas, Production [Member]
REVENUES:
Revenues	5,642	8,609
Natural gas liquids [Member]
REVENUES:
Revenues	$ 1,963	$ 3,017

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (8,618)	$ 937
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	7,556	10,485
Impairment of natural gas and oil properties	483	3,097
Deferred income taxes	424
Loss (gain) on sale of assets	12	(9,447)
Loss (gain) from investment in affiliates	(30)	(707)
Stock-based compensation	1,052	1,424
Unrealized loss on derivative instruments	3,646	519
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable & other	146	(642)
Decrease (increase) in prepaid expenses	835	940
Increase (decrease) in accounts payable & advances from joint owners	(4,299)	(6,053)
Decrease in other accrued liabilities	(826)	(1,921)
Decrease in income taxes receivable, net	(424)
Increase in income taxes payable, net	27	158
Other	(123)	3,279
Net cash provided by (used in) operating activities	(139)	2,069
CASH FLOWS FROM INVESTING ACTIVITIES:
Natural gas and oil exploration and development expenditures	(5,124)	(16,244)
Additions to furniture & equipment	(17)
Sale of oil & gas properties		20,965
Net cash provided by (used in) investing activities	(5,141)	4,721
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under Credit Facility	37,025	74,832
Repayments under Credit Facility	(31,473)	(81,551)
Net costs from equity offering	(86)
Purchase of treasury stock	(186)	(71)
Net cash provided by (used in) financing activities	5,280	(6,790)
NET CHANGE IN CASH AND CASH EQUIVALENTS	0	0
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	0	0
CASH AND CASH EQUIVALENTS, END OF PERIOD	$ 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, 2017	$ 1,223	$ 302,527	$ (128,583)	$ 49,433	$ 224,600
Balance, shares at Dec. 31, 2017	25,505,715
Treasury shares at cost			(71)		(71)
Treasury shares at cost, shares	(16,032)
Restricted shares activity	$ 8	(8)
Restricted shares activity, shares	206,114
Stock-based compensation		1,424			1,424
Net income (loss)				937	937
Balance at Mar. 31, 2018	$ 1,231	303,943	(128,654)	50,370	226,890
Balance, shares at Mar. 31, 2018	25,695,797
Balance at Dec. 31, 2018	$ 1,573	339,981	(129,030)	(72,135)	$ 140,389
Balance, shares at Dec. 31, 2018	34,158,492				34,158,492
Equity offering costs		(86)			$ (86)
Treasury shares at cost			(186)		(186)
Treasury shares at cost, shares	(49,415)
Restricted shares activity	$ 12	(12)
Restricted shares activity, shares	307,650
Stock-based compensation		1,052			1,052
Net income (loss)				(8,618)	(8,618)
Balance at Mar. 31, 2019	$ 1,585	$ 340,935	$ (129,216)	$ (80,753)	$ 132,551
Balance, shares at Mar. 31, 2019	34,416,727				34,416,727

Organization and Business

Organization and Business	3 Months Ended
	Mar. 31, 2019
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 West Texas, the onshore Texas Gulf Coast and the Rocky Mountain regions of the United States. The following table lists the Company’s primary producing areas as of March 31, 2019: Location Formation Gulf of Mexico Offshore Louisiana - water depths less than 300 feet Southern Delaware Basin, Pecos County, Texas Wolfcamp Madison and Grimes counties, Texas Woodbine (Upper Lewisville) Zavala and Dimmit counties, Texas Buda / Eagle Ford / Georgetown San Augustine County, Texas Haynesville shale, Mid Bossier shale and James Lime formations Other Texas Gulf Coast Conventional and smaller unconventional formations Weston County, Wyoming Muddy Sandstone Sublette County, Wyoming Jonah Field (1) (1) Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this investment is not included in the Company’s reported production results for all periods shown in this report. The Company has recently been focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas , which is expected to continue to generate positive returns on its drilling investment in the current price environment. As of March 31, 2019, the Company was producing from twelve wells over its 17,700 gross operated (8,200 total net) acre position in this West Texas area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations. The Company currently expects this acreage in West Texas to be the primary focus of its drilling program for 2019. Until a sustained improvement in commodity prices occurs, the Company will commit drilling capital to West Texas, and other areas, only to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand its presence in those existing areas. The Company will continue to make balance sheet strength a priority in 2019 by limiting capital expenditures to a level that can be funded through internally generated cash flow and non-core asset sales. Throughout all this, the Company will continue to identify opportunities for cost reductions and operating efficiencies in all areas of its operations, while also searching for new resource acquisition opportunities. Acquisition efforts will be focused on areas in which the Company can leverage its geological and operational experience and expertise to exploit identified drilling opportunities and where it can develop an inventory of additional drilling prospects that the Company believes will enable it to economically grow production and add reserves.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2019
Summary Of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	2. Summary of Significant Accounting Policies The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2018 (the “2018 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2018 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this report. Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2018 Form 10-K. These unaudited interim consolidated results of operations for the quarter ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by the Company’s wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results or production in those reported for the Company’s consolidated results of operations. Liquidity and Going Concern Over the past several months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its Credit Facility (as defined in Note 10 – “Indebtedness”), which matures on October 1, 2019. The refinancing or replacement of the Credit Facility could be made in conjunction with an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming the Company will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern. Oil and Gas Properties - Successful Efforts The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible 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. No impairment of proved properties was recognized during the quarter ended March 31, 2019. During the quarter ended March 31, 2018, the Company recognized $2.3 million in non-cash proved property impairment charges related to its Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized impairment expense of approximately $0.5 million and approximately $0.8 million for quarters ended March 31, 2019 and 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases. Net Income (Loss) Per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the quarter ended March 31, 2019, the Company excluded 526,309 shares or units of potentially dilutive securities, as they were antidilutive. For the quarter ended March 31, 2018, the Company excluded 670,210 shares or units of potentially dilutive securities, as they were antidilutive. Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. 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. Revenue Recognition Adoption of ASC 606 As of January 1, 2018, the Company adopted Accounting Standards Codification Topic 606 – Revenue from Contracts with Customers (“ASC 606”), which supersedes the revenue recognition requirements and industry-specific guidance under Accounting Standards Codification Top 605 – Revenue Recognition (“ASC 605”). The Company adopted ASC 606 using the modified retrospective method which allows the Company to apply the new standard to all new contracts entered into after December 31, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance prior to December 31, 2017. The Company identified no material impact on its historical revenues upon initial application of ASC 606, and as such has not recognized any cumulative catch-up effect to the opening balance of the Company’s shareholders’ equity as of January 1, 2018. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Revenue from Contracts with Customers Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. When sales volumes exceed the Company’s entitled share, a 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. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606. Transaction Price Allocated to Remaining Performance Obligations Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required. Contract Balances The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply. Prior Period Performance Obligations The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. Impact of Adoption of ASC 606 The Company has reviewed all of its natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to its results of operations for the quarter ended March 31, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment. Recent Accounting Pronouncements In August 2018, the FASB issued ASU 2018-13 – Fair Value Measurement (Topic 820). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

Acquisitions and Dispositions

Acquisitions and Dispositions	3 Months Ended
	Mar. 31, 2019
Business Combinations [Abstract]
Acquisitions and Dispositions	3. Acquisitions and Dispositions On March 28, 2018, the Company sold its operated Eagle Ford Shale assets located in Karnes County, Texas for a cash purchase price of $21.0 million. The Company recorded a net gain of $9.4 million, prior to final closing adjustments.

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2019
Fair Value Measurements [Abstract]
Fair Value Measurements	4. Fair Value Measurements Pursuant to Accounting Standards Codification Topic 820, Fair Value Measurements and Disclosures (“ASC 820”), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of March 31, 2019. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3. Fair value information for financial assets and liabilities was as follows as of March 31, 2019 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 1,371 $ — $ 1,371 $ — Commodity price contracts - liabilities $ (839) $ — $ (839) $ — Derivatives listed above are recorded in “Current derivative asset or liability” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Loss on derivatives, net" in its 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 reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 5 - "Derivative Instruments" for additional discussion of derivatives. As of March 31, 2019, the Company's derivative contracts were all with certain members of its Credit Facility lending group, which are major financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Estimates of the fair value of financial instruments are made in accordance with the requirements of Accounting Standards Codification Topic 825, Financial Instruments. The estimated fair value amounts are determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's Credit Facility approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note 10 - "Indebtedness" for further information. Impairments The Company tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible 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 asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3.

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2019
Derivative Instruments [Abstract]
Derivative Instruments	5. Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts. As of March 31, 2019, the Company’s natural gas and oil derivative positions consisted of swaps and costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract. It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts, as they are secured under the Credit Facility. See Note 10 – “Indebtedness” for further information regarding the 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 “Loss on derivatives, net” on the consolidated statements of operations. As of March 31, 2019, the following financial derivative instruments were in place (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit Fair Value Natural Gas April 2019 - July 2019 Swap 600,000 Mmbtus $ 2.75 (1) $ Natural Gas Aug 2019 - Oct 2019 Swap 100,000 Mmbtus $ 2.75 (1) $ Natural Gas Nov 2019 - Dec 2019 Swap 500,000 Mmbtus $ 2.75 (1) $ Oil April 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) $ Oil April 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) $ Oil April 2019 - June 2019 Collar 12,000 Bbls $ 70.00 - 76.25 (3) $ Oil April 2019 - July 2019 Swap 6,000 Bbls $ 66.10 (3) $ Oil July 2019 Swap 12,000 Bbls $ 72.10 (3) $ Oil Aug 2019 - Oct 2019 Swap 9,000 Bbls $ 72.10 (3) $ Oil Nov 2019 - Dec 2019 Swap 12,000 Bbls $ 72.10 (3) $ Total net fair value of derivative instruments $ 532 (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 following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of March 31, 2019 (in thousands): Gross Netting (1) Total Assets $ 1,371 $ — $ 1,371 Liabilities $ (839) $ — $ (839) (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, 2018 (in thousands): Gross Netting (1) Total Assets $ 4,600 $ — $ 4,600 Liabilities $ (422) $ — $ (422) (1) Represents counterparty netting under agreements governing such derivatives. The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the quarters ended March 31, 2019 and 2018 (in thousands): Three Months Ended March 31, 2019 2018 Crude oil contracts $ 655 $ (588) Natural gas contracts 113 75 Realized gain (loss) $ 768 $ (513) Crude oil contracts $ (3,443) $ (284) Natural gas contracts (203) (235) Unrealized loss $ (3,646) $ (519) Loss on derivatives, net $ (2,878) $ (1,032) In May 2019, the Company entered into the following additional financial derivative contracts with a third party counterparty under an unsecured line of credit with no margin call provisions: Commodity Period Derivative Volume/Month Price/Unit Natural Gas Jan 2020 - March 2020 Swap 425,000 Mmbtus $ 2.84 (1) Natural Gas April 2020 - July 2020 Swap 400,000 Mmbtus $ 2.53 (1) Natural Gas Aug 2020 - Oct 2020 Swap 40,000 Mmbtus $ 2.53 (1) Natural Gas Nov 2020 - Dec 2020 Swap 375,000 Mmbtus $ 2.70 (1) Oil May 2019 - Dec 2019 Swap 2,400 Bbls $ 61.72 (2) Oil Jan 2020 - June 2020 Swap 22,000 Bbls $ 57.74 (2) Oil July 2020 - Dec 2020 Swap 15,000 Bbls $ 57.74 (2) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on West Texas Intermediate crude oil prices. In May 2019, the Company also entered into a costless swap agreement with a Mid-Cushing oil differential swap price of $0.05 per barrel of crude oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of crude oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020.

Stock-Based Compensation

Stock-Based Compensation	3 Months Ended
	Mar. 31, 2019
Stock-Based Compensation [Abstract]
Stock-Based Compensation	6. Stock-Based Compensation Restricted Stock During the quarter ended March 31, 2019, the Company granted 307,650 shares of restricted common stock, which vest over three years, to employees and executive officers as part of their overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2019, was $3.20 per share, with a total fair value of approximately $1.0 million and no adjustment for an estimated weighted average forfeiture rate. There were no forfeitures of restricted stock during the quarter ended March 31, 2019. The Company recognized approximately $1.0 million in restricted stock compensation expense during the quarter ended March 31, 2019 related to restricted stock granted to its officers, employees and directors. As of March 31, 2019, an additional $1.9 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 2.0 years. Approximately 1.2 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of March 31, 2019, assuming PSUs (as defined below) are settled at 100% of target. During the quarter ended March 31, 2018, the Company granted 225,782 shares of restricted common stock, which vest over three years, to executive officers as part of their overall compensation package. The weighted average fair value of the restricted shares granted during the quarter ended March 31, 2018, was $3.57 per share, with a total fair value of approximately $0.8 million and no adjustment for an estimated weighted average forfeiture rate. During the quarter ended March 31, 2018, 19,668 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the quarter ended March 31, 2018 was approximately $0.2 million. The Company recognized approximately $1.0 million in restricted stock compensation expense during the quarter ended March 31, 2018 related to restricted stock granted to its officers, employees and directors. Performance Stock Units Performance stock units (“PSUs”) represent the opportunity to receive shares of the Company's common stock at the time of settlement. The number of shares to be awarded upon settlement of these PSUs may range from 0% to 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 it is contemplated that the PSUs will be settled 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. During the quarter ended March 31, 2019, the Company granted 117,105 PSUs to executive officers and employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the quarter ended March 31, 2019, 49,773 PSUs were forfeited due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company only recognized approximately $14 thousand in stock compensation expense related to PSUs during the quarter ended March 31, 2019, primarily due to the expiration of PSUs which failed to meet their target as of December 31, 2018 and the above referenced forfeitures. As of March 31, 2019, an additional $1.5 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 2.2 years. During the quarter ended March 31, 2018, the Company granted 190,782 PSUs to executive officers as part of their overall compensation package, which will be measured between January 1, 2018 and December 31, 2020, and were valued at a weighted average fair value of $7.69 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the quarter ended March 31, 2018, 16,900 PSUs were forfeited by former employees. The Company recognized approximately $0.4 million in stock compensation expense related to PSUs during the quarter ended March 31, 2018. Stock Options Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the quarters ended March 31, 2019 and 2018, there was no excess tax benefit recognized. Compensation expense related to stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted during the quarters ended March 31, 2019 or 2018. During the quarter ended March 31, 2019, no stock options were exercised and stock options for 12,052 shares were forfeited by former employees. During the quarter ended March 31, 2018, no stock options were exercised or forfeited.

Leases

Leases	3 Months Ended
	Mar. 31, 2019
Leases
Leases	7. Leases As of January 1, 2019, the Company adopted Accounting Standards Codification Topic 842 – Leases (“ASC 842”), which requires lessees to recognize a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. Expanded disclosures with additional qualitative and quantitative information are also required. ASC 842 contains several optional practical expedients upon adoption, one of which is referred to as the “package of three practical expedients”. The expedients must be taken together and allow entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. The Company elected to apply this practical expedient package to all of its leases upon adoption. The Company also chose to implement the “short-term accounting policy election” which allows the Company to not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statement of operations. ASC 842 provides for a modified retrospective transition approach requiring lessees to recognize and measure leases on the balance sheet at the beginning of either the earliest period presented or as of the beginning of the period of adoption. The Company elected to apply ASC 842 as of the beginning of the period of adoption (January 1, 2019) and will not restate comparative periods. For new leases, the Company will determine if an arrangement is or contains a lease at inception. The Company has elected to combine and account for lease and non-lease contract components as a lease. Leases are included as right-of-use assets within “Other current assets” and “Other non-current assets” and a lease liability within “Accounts payable and accrued liabilities” and “Other long term liabilities” on the Company’s consolidated balance sheet. As of January 1, 2019, the majority of the Company’s operating leases were for field equipment, such as compressors. The adoption of ASC 842 did not have a material effect on the Company’s financial results or disclosures. Most of the Company’s compressor contracts are on a month-to-month basis, and while it is probable the contract will be renewed on a monthly basis, the compressors can be easily substituted or cancelled be either party, with minimal penalties. Leases with these terms are not included on the Company’s balance sheet and are recognized on the statement of operations on a straight-line basis over the lease term. During the quarter ended March 31, 2019, the Company entered into three new compressor contracts, with lease terms of twelve months or more, which qualify as operating leases under the new standard. The Company’s consolidated balance sheet as of March 31, 2019 includes a right of use asset of $0.2 million and lease liability of $0.2 million for these new operating leases. There were no cash payments related to these new operating leases during the quarter ended March 31, 2019. The Company's leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease within a particular currency environment. For operating leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term. The weighted average discount rate and weighted average remaining lease term as of March 31, 2019 was 6.00% and 24.2 months, respectively. Maturities for the Company’s operating lease liabilities on the consolidated balance sheet as of March 31, 2019, were as follows (in thousands): Three Months Ended March 31, 2019 2019 (remaining after March 31, 2019) $ 2020 2021 2022 Total future minimum lease payments Less: imputed interest (15) Present value of lease liabilities $ The following table summarizes expenses related to operating leases for the three months ended March 31, 2019 (in thousands): Three Months Ended March 31, 2019 Operating lease cost (1) (2) $ Administrative lease cost (3) Short-term lease cost (1) (4) Total lease cost $ (1) This total does not reflect amounts that may be reimbursed by other third-parties in the normal course of business, such as non-operating working interest owners. (2) Includes operating expense related to office lease which expired on March 31, 2019. (3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. (4) Costs related primarily to rig and compressor agreements with lease terms of more than one month and less than one year. On April 1, 2019, the Company entered into a two year extension of its office lease, which will result in an estimated $0.5 million right of use asset and lease liability to be recognized on the Company’s consolidated balance sheet for the quarter ending June 30, 2019.

Other Financial Information

Other Financial Information	3 Months Ended
	Mar. 31, 2019
Other Financial Information [Abstract]
Other Financial Information	8. Other Financial Information The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): March 31, 2019 December 31, 2018 Accounts receivable: Trade receivables $ 5,371 $ 6,052 Receivable for Alta Resources distribution 1,712 1,993 Joint interest billings 4,472 3,833 Income taxes receivable 848 424 Other receivables 121 223 Allowance for doubtful accounts (994) (994) Total accounts receivable $ 11,530 $ 11,531 Prepaid expenses and other: Prepaid insurance $ 256 $ 792 Other 212 511 Total prepaid expenses and other $ 468 $ 1,303 Accounts payable and accrued liabilities: Royalties and revenue payable $ 13,615 $ 17,986 Advances from partners 2,101 1,785 Accrued exploration and development 2,531 4,751 Accrued acquisition costs 3,763 4,352 Trade payables 3,099 3,385 Accrued general and administrative expenses 2,403 2,545 Accrued operating expenses 1,229 1,801 Other accounts payable and accrued liabilities 3,447 2,901 Total accounts payable and accrued liabilities $ 32,188 $ 39,506 Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the quarters ended March 31, 2019 and 2018 (in thousands): Three Months Ended March 31, 2019 2018 Cash payments: Interest payments $ 1,046 $ 1,448 Income tax payments $ 40 $ — Non-cash investing activities in the consolidated statements of cash flows: Increase (decrease) in accrued capital expenditures $ (2,220) $ 3,669

Investment In Exaro Energy III

Investment In Exaro Energy III LLC	3 Months Ended
	Mar. 31, 2019
Investment In Exaro Energy III LLC [Abstract]
Investment In Exaro Energy III LLC	9. Investment in Exaro Energy III LLC The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at March 31, 2019 was approximately $6.1 million. The Company’s share in Exaro’s results of operations recognized for the quarters ended March 31, 2019 and 2018 was a gain of $0.3 million, net of no tax expense, and a gain of $0.7 million, net of no tax expense, respectively.

Indebtedness

Indebtedness	3 Months Ended
	Mar. 31, 2019
Indebtedness
Indebtedness	10. Indebtedness Credit Facility The Company’s $500 million revolving credit facility with Royal Bank of Canada and other lenders (the “Credit Facility”) currently matures on October 1, 2019. The borrowing base under the facility is redetermined each November 1 and May 1. As of March 31, 2019, the borrowing base under the Credit Facility was $90 million. The Company is currently going through its regularly scheduled May redetermination process. As of March 31, 2019, the Company had approximately $65.6 million outstanding under the Credit Facility and $1.9 million in an outstanding letter of credit. As of December 31, 2018, the Company had approximately $60.0 million outstanding under the Credit Facility and $1.9 million in outstanding letters of credit. As of March 31, 2019, borrowing availability under the Credit Facility was $22.6 million. The 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. Total interest expense under the Credit Facility, including commitment fees, for the quarter ended March 31, 2019 was approximately $1.1 million. Total interest expense under the Credit Facility, including commitment fees, for the quarter ended March 31, 2018 was approximately $1.4 million. The weighted average interest rate in effect at March 31, 2019 and December 31, 2018 was 6.2% and 6.3%, respectively. The Credit Facility contains restrictive covenants which, among other things, require a Current Ratio of greater than or equal to 1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Facility. The 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, audited financial statements that include a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of March 31, 2019, the Company was in compliance with all of its covenants under the Credit Facility. Pursuit of Refinancing and Other Liquidity-Enhancing Alternatives Over the past several months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its existing Credit Facility, which matures on October 1, 2019. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures, and in such case there is substantial doubt that the Company could continue as a going concern. The refinancing and/or replacement of the Credit Facility could be made in conjunction with a substantial acquisition or disposition, an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended Credit Facility that would be expected to provide additional borrowing capacity for future capital expenditures. While the Company reviews such liquidity-enhancing alternative sources of capital, it intends to continue to minimize its drilling program capital expenditures in the Southern Delaware Basin and pursue a reduction in its borrowings under the Credit Facility, including through a reduction in cash general and administrative expenses and the possible sale of additional non-core properties.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2019
Income Taxes [Abstract]
Income Taxes	11. Income Taxes The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended March 31, 2019 2018 Current tax provision: Federal $ — $ — State 27 158 Total $ 27 $ 158 Total tax provision: Federal $ — $ — State 27 158 Total income tax provision $ 27 $ 158 In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the quarter ended March 31, 2019, the Company continued to record a full valuation allowance against its net deferred tax assets. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. The Company expects that its effective income tax rate for 2019 will be less than 1% consisting entirely of state of Louisiana income taxes. In the quarter ended December 31, 2018, the Company experienced an Ownership Change as described in Internal Revenue Code section 382 as a result of a completed follow-on equity offering. Management estimates that as a result of this Ownership Change, its future Net Operating Loss (NOL) and other tax attribute carryforwards will be limited in usage to approximately $2.4 million per year, plus the amount of any built in gains (essentially: the excess of the fair market value of properties over their respective income tax bases) recognized in the five years after 2018. As a result of these limitations, it is likely that a substantial portion of the Company’s pre-2018 NOLs will expire unused. Due to the presence of the valuation allowance from prior years, this event resulted in no net charge to earnings. The Company is performing additional analysis related to this matter which will be finalized when the Company files its 2018 U.S. federal income tax return later this year.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2019
Commitments And Contingencies [Abstract]
Commitments and Contingencies	12. Commitments and Contingencies Legal Proceedings From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below. In 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, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company continues to vigorously defend this lawsuit and has filed a petition requesting a review by the Texas Supreme Court, as the Company believes the trial and appellate courts erred in the interpretation of the law. The Company is awaiting a response from the Texas Supreme Court as to whether it intends to review the case. In addition, the Company is also in the process of seeking amicus briefs from industry associations whose members would be affected by the Court of Appeals’ ruling. In September 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in the 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. In December 2017, the Court of Appeals affirmed the judgment in the Company’s favor. The plaintiff filed a motion for rehearing, which was denied in May 2018. The plaintiff has filed a petition requesting that the matter be reviewed by the Texas Supreme Court; the parties are awaiting a response from the Texas Supreme Court as to whether it intends to review the case. 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. 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. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in its Southeast Texas area and currently forecasts it will continue to not meet the minimum throughput requirements under the agreement based upon the current commodity price market and the Company’s short term strategic drilling plans. 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. The Company incurred fees of $0.2 million and $0.3 million during the quarters ended March 31, 2019 and 2018, respectively. As of March 31, 2019, the Company estimates that the net deficiency fee will be approximately $1.0 million for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. The Company has now accrued the total estimated remaining $2.0 million loss contingency through the expiration of the contract on March 31, 2020.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2019
Summary Of Significant Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2018 Form 10-K. These unaudited interim consolidated results of operations for the quarter ended March 31, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019.
Principles Of Consolidation	The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by the Company’s wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results or production in those reported for the Company’s consolidated results of operations.
Liquidity and Going Concern	Liquidity and Going Concern Over the past several months, the Company has been in discussions with its current lenders and other sources of capital regarding a possible refinancing and/or replacement of its Credit Facility (as defined in Note 10 – “Indebtedness”), which matures on October 1, 2019. The refinancing or replacement of the Credit Facility could be made in conjunction with an issuance of unsecured or non-priority secured debt or preferred or common equity, non-core property monetization, potential monetization of certain midstream and/or water handling facilities, or a combination of the foregoing. These discussions have included a possible new, replacement or extended credit facility that would be expected to provide additional borrowing capacity for future capital expenditures. There is no assurance, however, that such discussions will result in a refinancing of the Credit Facility on acceptable terms, if at all, or provide any specific amount of additional liquidity for future capital expenditures. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. However, the accompanying financial statements have been prepared assuming the Company will continue to operate as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The accompanying financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.
Oil and Gas Properties - Successful Efforts	Oil and Gas Properties - Successful Efforts The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
Impairment of Oil and Gas Properties	Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible 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. No impairment of proved properties was recognized during the quarter ended March 31, 2019. During the quarter ended March 31, 2018, the Company recognized $2.3 million in non-cash proved property impairment charges related to its Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. The Company recognized impairment expense of approximately $0.5 million and approximately $0.8 million for quarters ended March 31, 2019 and 2018, respectively, related to impairment of certain non-core unproved properties primarily due to expiring leases.
Net Income (Loss) Per Common Share	Net Income (Loss) Per Common Share Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the quarter ended March 31, 2019, the Company excluded 526,309 shares or units of potentially dilutive securities, as they were antidilutive. For the quarter ended March 31, 2018, the Company excluded 670,210 shares or units of potentially dilutive securities, as they were antidilutive.
Subsidiary Guarantees	Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. 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.
Revenue Recognition	Revenue Recognition Adoption of ASC 606 As of January 1, 2018, the Company adopted Accounting Standards Codification Topic 606 – Revenue from Contracts with Customers (“ASC 606”), which supersedes the revenue recognition requirements and industry-specific guidance under Accounting Standards Codification Top 605 – Revenue Recognition (“ASC 605”). The Company adopted ASC 606 using the modified retrospective method which allows the Company to apply the new standard to all new contracts entered into after December 31, 2017 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance prior to December 31, 2017. The Company identified no material impact on its historical revenues upon initial application of ASC 606, and as such has not recognized any cumulative catch-up effect to the opening balance of the Company’s shareholders’ equity as of January 1, 2018. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Revenue from Contracts with Customers Sales of oil, condensate, natural gas and natural gas liquids (“NGLs”) are recognized at the time control of the products are transferred to the customer. Based upon the Company’s current purchasers’ past experience and expertise in the market, collectability is probable, and there have not been payment issues with the Company’s purchasers over the past year or currently. Generally, the Company’s gas processing and purchase agreements indicate that the processors take control of the gas at the inlet of the plant and that control of residue gas is returned to the Company at the outlet of the plant. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs. The Company delivers oil and condensate to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. When sales volumes exceed the Company’s entitled share, a 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. Production imbalances have not had and currently do not have a material impact on the financial statements, and this did not change with the adoption of ASC 606. Transaction Price Allocated to Remaining Performance Obligations Generally, the Company’s contracts have an initial term of one year or longer but continue month to month unless written notification of termination in a specified time period is provided by either party to the contract. The Company has used the practical expedient in ASC 606 which states that the Company is not required to disclose that transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligation is not required. Contract Balances The Company receives purchaser statements from the majority of its customers, but there are a few contracts where the Company prepares the invoice. Payment is unconditional upon receipt of the statement or invoice. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under ASC 606. The majority of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and supply and demand conditions. The price of these commodities fluctuates to remain competitive with supply. Prior Period Performance Obligations The Company records revenue in the month production is delivered to the purchaser. Settlement statements may not be received for 30 to 90 days after the date production is delivered, and therefore the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Differences between the Company’s estimates and the actual amounts received for product sales are generally recorded in the following month that payment is received. Any differences between the Company’s revenue estimates and actual revenue received historically have not been significant. The Company has internal controls in place for its revenue estimation accrual process. Impact of Adoption of ASC 606 The Company has reviewed all of its natural gas, NGLs, residue gas, condensate and crude oil sales contracts to assess the impact of the provisions of ASC 606. Based upon the Company’s review, there were no required changes to the recording of residue gas or condensate and crude oil contracts. Certain NGL and natural gas contracts would require insignificant changes to the recording of transportation, gathering and processing fees as net to revenue or as an expense. The Company concluded that these minor changes were not material to its operating results on a quantitative or qualitative basis. Therefore, there was no impact to its results of operations for the quarter ended March 31, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2018, the FASB issued ASU 2018-13 – Fair Value Measurement (Topic 820). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2019
Fair Value Measurements [Abstract]
Schedule Of Fair Value Of Financial Assets And (Liabilities)	Fair value information for financial assets and liabilities was as follows as of March 31, 2019 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 1,371 $ — $ 1,371 $ — Commodity price contracts - liabilities $ (839) $ — $ (839) $ —

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2019
Schedule Of Derivative Contracts	As of March 31, 2019, the following financial derivative instruments were in place (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit Fair Value Natural Gas April 2019 - July 2019 Swap 600,000 Mmbtus $ 2.75 (1) $ Natural Gas Aug 2019 - Oct 2019 Swap 100,000 Mmbtus $ 2.75 (1) $ Natural Gas Nov 2019 - Dec 2019 Swap 500,000 Mmbtus $ 2.75 (1) $ Oil April 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) $ Oil April 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) $ Oil April 2019 - June 2019 Collar 12,000 Bbls $ 70.00 - 76.25 (3) $ Oil April 2019 - July 2019 Swap 6,000 Bbls $ 66.10 (3) $ Oil July 2019 Swap 12,000 Bbls $ 72.10 (3) $ Oil Aug 2019 - Oct 2019 Swap 9,000 Bbls $ 72.10 (3) $ Oil Nov 2019 - Dec 2019 Swap 12,000 Bbls $ 72.10 (3) $ Total net fair value of derivative instruments $ 532 (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.
Schedule Of Fair Value Of Commodity Derivatives	The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of March 31, 2019 (in thousands): Gross Netting (1) Total Assets $ 1,371 $ — $ 1,371 Liabilities $ (839) $ — $ (839) (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, 2018 (in thousands): Gross Netting (1) Total Assets $ 4,600 $ — $ 4,600 Liabilities $ (422) $ — $ (422) (1) Represents counterparty netting under agreements governing such derivatives.
Schedule Of Derivative Contracts On Operations	The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the quarters ended March 31, 2019 and 2018 (in thousands): Three Months Ended March 31, 2019 2018 Crude oil contracts $ 655 $ (588) Natural gas contracts 113 75 Realized gain (loss) $ 768 $ (513) Crude oil contracts $ (3,443) $ (284) Natural gas contracts (203) (235) Unrealized loss $ (3,646) $ (519) Loss on derivatives, net $ (2,878) $ (1,032)
Subsequent Derivative Contracts [Member]
Schedule Of Derivative Contracts	Commodity Period Derivative Volume/Month Price/Unit Natural Gas Jan 2020 - March 2020 Swap 425,000 Mmbtus $ 2.84 (1) Natural Gas April 2020 - July 2020 Swap 400,000 Mmbtus $ 2.53 (1) Natural Gas Aug 2020 - Oct 2020 Swap 40,000 Mmbtus $ 2.53 (1) Natural Gas Nov 2020 - Dec 2020 Swap 375,000 Mmbtus $ 2.70 (1) Oil May 2019 - Dec 2019 Swap 2,400 Bbls $ 61.72 (2) Oil Jan 2020 - June 2020 Swap 22,000 Bbls $ 57.74 (2) Oil July 2020 - Dec 2020 Swap 15,000 Bbls $ 57.74 (2) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on West Texas Intermediate crude oil prices.

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2019
Leases
Summary of maturities of operating lease liabilities	Maturities for the Company’s operating lease liabilities on the consolidated balance sheet as of March 31, 2019, were as follows (in thousands): Three Months Ended March 31, 2019 2019 (remaining after March 31, 2019) $ 2020 2021 2022 Total future minimum lease payments Less: imputed interest (15) Present value of lease liabilities $
Summary of operating lease costs	Three Months Ended March 31, 2019 2019 (remaining after March 31, 2019) $ 2020 2021 2022 Total future minimum lease payments Less: imputed interest (15) Present value of lease liabilities $ The following table summarizes expenses related to operating leases for the three months ended March 31, 2019 (in thousands): Three Months Ended March 31, 2019 Operating lease cost (1) (2) $ Administrative lease cost (3) Short-term lease cost (1) (4) Total lease cost $ (1) This total does not reflect amounts that may be reimbursed by other third-parties in the normal course of business, such as non-operating working interest owners. (2) Includes operating expense related to office lease which expired on March 31, 2019. (3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. (4) Costs related primarily to rig and compressor agreements with lease terms of more than one month and less than one year.

Other Financial Information (Ta

Other Financial Information (Tables)	3 Months Ended
	Mar. 31, 2019
Other Financial Information [Abstract]
Schedule Of Additional Financial Details	The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): March 31, 2019 December 31, 2018 Accounts receivable: Trade receivables $ 5,371 $ 6,052 Receivable for Alta Resources distribution 1,712 1,993 Joint interest billings 4,472 3,833 Income taxes receivable 848 424 Other receivables 121 223 Allowance for doubtful accounts (994) (994) Total accounts receivable $ 11,530 $ 11,531 Prepaid expenses and other: Prepaid insurance $ 256 $ 792 Other 212 511 Total prepaid expenses and other $ 468 $ 1,303 Accounts payable and accrued liabilities: Royalties and revenue payable $ 13,615 $ 17,986 Advances from partners 2,101 1,785 Accrued exploration and development 2,531 4,751 Accrued acquisition costs 3,763 4,352 Trade payables 3,099 3,385 Accrued general and administrative expenses 2,403 2,545 Accrued operating expenses 1,229 1,801 Other accounts payable and accrued liabilities 3,447 2,901 Total accounts payable and accrued liabilities $ 32,188 $ 39,506
Schedule Of Supplemental Disclosures	Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the quarters ended March 31, 2019 and 2018 (in thousands): Three Months Ended March 31, 2019 2018 Cash payments: Interest payments $ 1,046 $ 1,448 Income tax payments $ 40 $ — Non-cash investing activities in the consolidated statements of cash flows: Increase (decrease) in accrued capital expenditures $ (2,220) $ 3,669

Income Taxes (Tables)

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2019
Income Taxes [Abstract]
Components Of Income Tax Expense (Benefit)	The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended March 31, 2019 2018 Current tax provision: Federal $ — $ — State 27 158 Total $ 27 $ 158 Total tax provision: Federal $ — $ — State 27 158 Total income tax provision $ 27 $ 158

Organization and Business (Deta

Organization and Business (Details)	3 Months Ended
	Mar. 31, 2019aitemft
Exaro Energy III LLC [Member]
Organization and Business
Equity method investment, ownership percentage	37.00%
Bullseye
Organization and Business
Number of wells | item	12
Gross acres	17,700
Net acres	8,200
Gulf of Mexico [Member] | Maximum [Member]
Organization and Business
Water depth of operations | ft	300

Summary of Significant Accoun_3

Summary of Significant Accounting Policies - Impairment and Debt (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)item	Mar. 31, 2018USD ($)	Dec. 31, 2018
Policies
Impairment of natural gas and oil properties	$ 483	$ 3,097
Number of subsidiaries inactive and not Subsidiary Guarantor | item	1
Restricted assets, percent of net assets			25.00%
Proved property [Member]
Policies
Impairment of natural gas and oil properties	$ 0	2,300
Unproved property [Member]
Policies
Impairment of natural gas and oil properties	$ 500	$ 800

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Significant Accounting Policies [Line Items]
Cash and cash equivalents
Potentially dilutive (in shares)	526,309	670,210
Term of contract	1 year
Revenue, Practical Expedient, Initial Application and Transition, Nondisclosure of Transaction Price Allocation to Remaining Performance Obligation [true/false]	true
Minimum [Member]
Significant Accounting Policies [Line Items]
Period settlement statements are received	30 days
Maximum [Member]
Significant Accounting Policies [Line Items]
Period settlement statements are received	90 days
Exaro Energy III LLC [Member]
Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	37.00%

Acquisitions and Dispositions -

Acquisitions and Dispositions - Dispositions (Details) - Disposal Group, Held-for-sale, Not Discontinued Operations [Member] - Karnes County, TX Assets [Member] $ in Millions	Mar. 28, 2018USD ($)
Disposals
Cash purchase price	$ 21
Gain (loss) on sale of oil and gas property	$ 9.4

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - assets	$ 1,371	$ 4,600
Commodity price contracts - liabilities	(839)	$ (422)
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price contracts - assets	1,371
Commodity price contracts - liabilities	$ (839)

Derivative Instruments (Derivat

Derivative Instruments (Derivative Contracts) (Details) $ in Thousands	1 Months Ended	3 Months Ended
	May 31, 2019item$ / MMBTU$ / bbl	Mar. 31, 2019USD ($)item$ / Mcf$ / bbl
Derivative [Line Items]
Fair Value | $		$ 532
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April To July 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ 98
Commodity Derivative Flow Rate | item		600,000
Price/Unit-Swap | $ / Mcf		2.75
Price/Unit-Floor		2.75
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August To October 2019[Member]
Derivative [Line Items]
Fair Value | $		$ (14)
Commodity Derivative Flow Rate | item		100,000
Price/Unit-Swap | $ / Mcf		2.75
Price/Unit-Floor		2.75
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November To December 2019[Member]
Derivative [Line Items]
Fair Value | $		$ (170)
Commodity Derivative Flow Rate | item		500,000
Price/Unit-Swap | $ / Mcf		2.75
Price/Unit-Floor		2.75
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January to March 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	425,000
Price/Unit-Swap | $ / MMBTU	2.84
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to July 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	400,000
Price/Unit-Swap | $ / MMBTU	2.53
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to October 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	40,000
Price/Unit-Swap | $ / MMBTU	2.53
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	375,000
Price/Unit-Swap | $ / MMBTU	2.70
Oil [Member] | Swap [Member] | Derivative Contract Period April To July 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ 137
Commodity Derivative Flow Rate | item		6,000
Price/Unit-Swap		66.10
Price/Unit-Floor		66.10
Oil [Member] | Swap [Member] | Derivative Contract Period August To October 2019[Member]
Derivative [Line Items]
Fair Value | $		$ 311
Commodity Derivative Flow Rate | item		9,000
Price/Unit-Swap		72.10
Price/Unit-Floor		72.10
Oil [Member] | Swap [Member] | Derivative Contract Period November To December 2019[Member]
Derivative [Line Items]
Fair Value | $		$ 284
Commodity Derivative Flow Rate | item		12,000
Price/Unit-Swap		72.10
Price/Unit-Floor		72.10
Oil [Member] | Swap [Member] | Derivative Contract Period July 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ 138
Commodity Derivative Flow Rate | item		12,000
Price/Unit-Swap		72.10
Price/Unit-Floor		72.10
Oil [Member] | Swap [Member] | Derivative Contract Period May To December 2019 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	2,400
Price/Unit-Swap	61.72
Oil [Member] | Swap [Member] | Derivative Contract Period January to June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	22,000
Price/Unit-Swap	57.74
Oil [Member] | Swap [Member] | Derivative Contract Period July to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	15,000
Price/Unit-Swap	57.74
Oil [Member] | Collar Options [Member] | Derivative Contract Period April To December 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ (499)
Commodity Derivative Flow Rate | item		7,000
Price/Unit-Floor		50
Price/Unit-Cap		58
Oil [Member] | Collar Options [Member] | Derivative Contract 2 Period April To December 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ (103)
Commodity Derivative Flow Rate | item		4,000
Price/Unit-Floor		52
Price/Unit-Cap		59.45
Oil [Member] | Collar Options [Member] | Derivative Contract Period April To June 2019 [Member]
Derivative [Line Items]
Fair Value | $		$ 350
Commodity Derivative Flow Rate | item		12,000
Price/Unit-Floor		70
Price/Unit-Cap		76.25
Oil [Member] | Costless Swap [Member]
Derivative [Line Items]
Price/Unit-Swap	0.05
Oil [Member] | Costless Swap [Member] | Derivative Contract Period January to June 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	12,000
Oil [Member] | Costless Swap [Member] | Derivative Contract Period July to December 2020 [Member]
Derivative [Line Items]
Commodity Derivative Flow Rate | item	10,000

Derivative Instruments (Fair Va

Derivative Instruments (Fair Value) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Assets
Gross	$ 1,371	$ 4,600
Total	1,371	4,600
Liabilities:
Gross	(839)	(422)
Total	$ (839)	$ (422)

Derivative Instruments (Operati

Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	$ 768	$ (513)
Unrealized gain (loss)	(3,646)	(519)
Gain (loss) on derivatives, net	(2,878)	(1,032)
Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	655	(588)
Unrealized gain (loss)	(3,443)	(284)
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain (loss)	113	75
Unrealized gain (loss)	$ (203)	$ (235)

Stock Based Compensation (NonOp

Stock Based Compensation (NonOption) (Details)	3 Months Ended
	Mar. 31, 2019USD ($)$ / sharesshares	Mar. 31, 2018USD ($)$ / sharesshares
Stock-based compensation
Shares available for grant | shares	1,200,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	3 years
Activity, shares
Granted (in shares) | shares	307,650	225,782
Canceled/Forfeited (in shares) | shares		(19,668)
Activity, weighted average fair value
Granted (in dollars per share) | $ / shares	$ 3.20	$ 3.57
Stock-based compensation
Compensation expense not yet recognized	$ 1,900,000
Compensation expense, remaining weighted average vesting period	2 years
Value of issued stock	$ 1,000,000	$ 800,000
Weighted average forfeiture rate	0	0
Value of restricted shares forfeited	$ 0	$ 200,000
Stock-based compensation expense	$ 1,000,000	$ 1,000,000
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Activity, shares
Granted (in shares) | shares	117,105	190,782
Canceled/Forfeited (in shares) | shares	(49,773)	(16,900)
Activity, weighted average fair value
Granted (in dollars per share) | $ / shares	$ 6.42	$ 7.69
Stock-based compensation
Compensation expense not yet recognized	$ 1,500,000
Compensation expense, remaining weighted average vesting period	2 years 2 months 12 days
Target (as a percent)	100.00%
Stock-based compensation expense	$ 14,000	$ 400,000
Minimum [Member] | Performance Stock Units [Member]
Stock-based compensation
Target (as a percent)	0.00%
Maximum [Member] | Performance Stock Units [Member]
Stock-based compensation
Target (as a percent)	300.00%

Stock Based Compensation (Optio

Stock Based Compensation (Options) (Details) - Employee Stock Options [Member] - USD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Option roll forward
Stock options granted in period (in shares)	0	0
Exercise of stock options, shares	0	0
Expired / Forfeited (in shares)	(12,052)	0
Stock-based compensation
Excess tax benefit from exercise/cancellation of stock options	$ 0	$ 0

Leases (Details)

Leases (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Leases
Lease, Practical Expedients, Package [true false]	true
Operating lease right of use asset	$ 200
Operating lease liability	$ 211
Weighted average discount rate (as a percent)	6.00%
Weighted average remaining lease term	24 months 6 days

Leases (Maturities) (Details)

Leases (Maturities) (Details) $ in Thousands	Mar. 31, 2019USD ($)
Leases
2019 (remaining after March 31, 2019)	$ 91
2020	101
2021	25
2022	9
Total future minimum lease payments	226
Less: imputed interest	(15)
Total	$ 211

Leases (Costs) (Details)

Leases (Costs) (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2019USD ($)
Leases
Operating lease cost	$ 371
Administrative lease cost	19
Short-term lease cost	510
Total net lease cost	$ 900
Operating lease not yet commenced term	2 years
Right of use asset operating lease not yet commenced	$ 500
Operating leases not yet commenced	$ 500

Other Financial Information (Ba

Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands	Mar. 31, 2019	Dec. 31, 2018
Accounts receivable:
Trade receivables	$ 5,371	$ 6,052
Receivable for Alta Resources Distribution	1,712	1,993
Joint interest billings	4,472	3,833
Income taxes receivable	848	424
Other receivables	121	223
Allowance for doubtful accounts	(994)	(994)
Total accounts receivable	11,530	11,531
Prepaid expenses and other:
Prepaid insurance	256	792
Other	212	511
Total prepaid expenses and other	468	1,303
Accounts payable and accrued liabilities:
Royalties and revenue payable	13,615	17,986
Advances from partners	2,101	1,785
Accrued exploration and development	2,531	4,751
Accrued acquisition costs	3,763	4,352
Trade payables	3,099	3,385
Accrued general and administrative expenses	2,403	2,545
Accrued operating expenses	1,229	1,801
Other accounts payable and accrued liabilities	3,447	2,901
Total accounts payable and accrued liabilities	$ 32,188	$ 39,506

Other Financial Information (Su

Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Cash payments:
Interest payments	$ 1,046	$ 1,448
Income tax payments (refunds), net of cash refunds	40
Non-cash investing activities in the consolidated statements of cash flows:
Increase (decrease) in accrued capital expenditures	$ (2,220)	$ 3,669

Investment in Exaro Energy II_2

Investment in Exaro Energy III LLC (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Schedule of Equity Method Investments Financials
Gain (loss) from investment in affiliates, net of income taxes	$ 30	$ 707
Exaro Energy III LLC [Member]
Schedule of Equity Method Investments Financials
Equity method investment, ownership percentage	37.00%
Share of equity in investment	$ 6,100
Gain (loss) from investment in affiliates, net of income taxes	300	700
Tax (expense) benefit from equity investment	$ 0	$ 0

Indebtedness (Details)

Indebtedness (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Oct. 31, 2013USD ($)	Mar. 31, 2019USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2018USD ($)
Debt Instrument [Line Items]
Interest expense		$ 1,092	$ 1,409
RBC Credit Facility [Member]
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 500,000
Revolving credit facility, borrowing base		90,000
Credit facility amount outstanding		65,600		$ 60,000
Letters of credit amount outstanding		1,900		$ 1,900
Line of credit, available		22,600
Interest expense		$ 1,100	$ 1,400
Weighted average interest rate (as a percent)		6.20%		6.30%
RBC Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Current ratio	1
RBC Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Leverage ratio	3.50

Income Taxes (Expense Benefit)

Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018
Current tax provision:
State	$ 27		$ 158
Total	27		158
Total tax provision:
State	27		158
Income tax provision	$ 27		$ 158
Annual carryover limitation		$ 2,400
Built in gains carryover limitation period		5 years
Maximum [Member]
Total tax provision:
Effective tax rate (as a percent)	1.00%

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	1 Months Ended		3 Months Ended
	Sep. 30, 2012USD ($)	Nov. 30, 2010USD ($)site	Mar. 31, 2019USD ($)	Mar. 31, 2018USD ($)
Lavaca County Case [Member]
Legal Proceedings
Number of wells involved in litigation | site		2
Damages sought by plaintiffs		$ 5.3
Litigation Case Filed by Mineral Interest Owner Harris County [Member]
Legal Proceedings
Damages sought by plaintiffs	$ 10.7
Additional portion of mineral interest claimed by plaintiff	6.25%
Throughput commitment
Loss Contingency
Fees incurred			$ 0.2	$ 0.3
Estimated deficiency			1
Loss contingency provision accrual			$ 2