Document And Entity Information
Document And Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Mar. 11, 2019 | Jun. 29, 2018 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2018 | ||
Document Fiscal Year Focus | 2018 | ||
Document Fiscal Period Focus | FY | ||
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 Public Float | $ 112 | ||
Entity Common Stock, Shares Outstanding | 34,465,980 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 0 | |
Accounts receivable, net | 11,531 | $ 13,059 |
Prepaid expenses | 1,303 | 1,892 |
Current derivative asset | 4,600 | 822 |
Total current assets | 17,434 | 15,773 |
Natural gas and oil properties, successful efforts method of accounting: | ||
Proved properties | 1,095,417 | 1,239,662 |
Unproved properties | 34,612 | 35,243 |
Other property and equipment | 1,314 | 1,272 |
Accumulated depreciation, depletion and amortization | (898,169) | (930,220) |
Total property, plant and equipment, net | 233,174 | 345,957 |
OTHER NON-CURRENT ASSETS: | ||
Investments in affiliates | 5,743 | 18,464 |
Deferred tax asset | 424 | 424 |
Other | 357 | 835 |
Total other non-current assets | 6,524 | 19,723 |
TOTAL ASSETS | 257,132 | 381,453 |
CURRENT LIABILITIES: | ||
Accounts payable and accrued liabilities | 39,506 | 46,755 |
Current derivative liability | 422 | 1,765 |
Current asset retirement obligations | 1,329 | 2,017 |
Current portion of long-term debt | 60,000 | |
Total current liabilities | 101,257 | 50,537 |
NON-CURRENT LIABILITIES: | ||
Long-term debt | 85,380 | |
Long-term derivative liability | 300 | |
Asset retirement obligations | 12,168 | 20,388 |
Other long term liabilities | 3,318 | 248 |
Total non-current liabilities | 15,486 | 106,316 |
Total liabilities | 116,743 | 156,853 |
COMMITMENTS AND CONTINGENCIES (NOTE 13) | ||
SHAREHOLDERS’ EQUITY: | ||
Common stock, $0.04 par value, 50 million shares authorized, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018, 30,873,470 shares issued and 25,505,715 shares outstanding at December 31, 2017 | 1,573 | 1,223 |
Additional paid-in capital | 339,981 | 302,527 |
Treasury shares at cost (5,458,950 shares at December 31, 2018 and 5,367,755 shares at December 31, 2017) | (129,030) | (128,583) |
Retained earnings (deficit) | (72,135) | 49,433 |
Total shareholders’ equity | 140,389 | 224,600 |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ 257,132 | $ 381,453 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Dec. 31, 2018 | Dec. 31, 2017 |
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 | 39,617,442 | 30,873,470 |
Common stock, shares outstanding | 34,158,492 | 25,505,715 |
Treasury stock, shares | 5,458,950 | 5,367,755 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
REVENUES: | ||
Revenues | $ 77,087 | $ 78,545 |
EXPENSES: | ||
Operating expenses | 25,552 | 27,183 |
Exploration expenses | 1,637 | 1,106 |
Depreciation, depletion and amortization | 41,657 | 47,215 |
Impairment and abandonment of oil and gas properties | 103,732 | 2,395 |
General and administrative expenses | 24,157 | 24,161 |
Total expenses | 196,735 | 102,060 |
OTHER INCOME (EXPENSE): | ||
Gain (loss) from investment in affiliates (net of income taxes) | (12,721) | 2,697 |
Gain from sale of assets and return on investments | 13,224 | 2,280 |
Interest expense | (5,548) | (4,100) |
Gain on derivatives, net | 1,939 | 3,325 |
Other income | 1,306 | 1,275 |
Total other income (expense) | (1,800) | 5,477 |
NET LOSS BEFORE INCOME TAXES | (121,448) | (18,038) |
Income tax benefit (provision) | (120) | 395 |
NET LOSS ATTRIBUTABLE TO COMMON STOCK | $ (121,568) | $ (17,643) |
NET LOSS PER SHARE: | ||
Basic (in dollars per share) | $ (4.69) | $ (0.71) |
Diluted (in dollars per share) | $ (4.69) | $ (0.71) |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | ||
Basic (in shares) | 25,945 | 24,686 |
Diluted (in shares) | 25,945 | 24,686 |
Oil and Condensate [Member] | ||
REVENUES: | ||
Revenues | $ 34,413 | $ 25,347 |
Natural Gas, Production [Member] | ||
REVENUES: | ||
Revenues | 29,824 | 41,317 |
Natural gas liquids [Member] | ||
REVENUES: | ||
Revenues | $ 12,850 | $ 11,881 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net loss | $ (121,568) | $ (17,643) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 41,657 | 47,215 |
Impairment of natural gas and oil properties | 103,164 | 1,785 |
Exploration recovery | (232) | |
Deferred income taxes | (424) | |
Gain on sale of assets | (13,224) | (2,321) |
Loss (gain) from investment in affiliates | 12,721 | (2,697) |
Stock-based compensation | 4,766 | 6,100 |
Unrealized gain on derivative instruments | (5,421) | (2,204) |
Changes in operating assets and liabilities: | ||
Decrease in accounts receivable & other | 1,316 | 3,914 |
Decrease (increase) in prepaid expenses | 589 | (105) |
Increase (decrease) in accounts payable & advances from joint owners | (2,433) | 450 |
Increase (decrease) in other accrued liabilities | (1,209) | 1,353 |
Increase in income taxes receivable, net | (332) | |
Increase (decrease) in income taxes payable, net | 40 | (252) |
Other | 3,079 | 79 |
Net cash provided by operating activities | 23,477 | 34,686 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Natural gas and oil exploration and development expenditures | (58,947) | (66,571) |
Additions to furniture & equipment | (42) | (42) |
Sale of furniture & equipment | 12 | |
Sale of oil & gas properties | 27,805 | 1,151 |
Sale of energy credits | 497 | |
Net cash used in investing activities | (30,687) | (65,450) |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under Credit Facility | 236,611 | 239,514 |
Repayments under Credit Facility | (261,992) | (208,488) |
Net proceeds from equity offering | 33,038 | |
Purchase of treasury stock | (447) | (262) |
Net cash provided by financing activities | 7,210 | 30,764 |
NET DECREASE 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, 2016 | $ 1,211 | $ 296,439 | $ (128,321) | $ 67,076 | $ 236,405 |
Balance, shares at Dec. 31, 2016 | 25,238,600 | ||||
Treasury shares at cost | (262) | (262) | |||
Treasury shares at cost, shares | (48,368) | ||||
Restricted shares activity | $ 12 | (12) | |||
Restricted shares activity, shares | 315,483 | ||||
Stock-based compensation | 6,100 | 6,100 | |||
Net loss | (17,643) | (17,643) | |||
Balance at Dec. 31, 2017 | $ 1,223 | 302,527 | (128,583) | 49,433 | $ 224,600 |
Balance, shares at Dec. 31, 2017 | 25,505,715 | 25,505,715 | |||
Equity Offering | $ 344 | 32,694 | $ 33,038 | ||
Equity Offering, shares | 8,596,068 | ||||
Treasury shares at cost | (447) | (447) | |||
Treasury shares at cost, shares | (91,195) | ||||
Restricted shares activity | $ 6 | (6) | |||
Restricted shares activity, shares | 147,904 | ||||
Stock-based compensation | 4,766 | 4,766 | |||
Net loss | (121,568) | (121,568) | |||
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 |
Organization and Business
Organization and Business | 12 Months Ended |
Dec. 31, 2018 | |
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. Since 2016, the Company has been focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas (“Bullseye”). A s of December 31, 2018, the Company was producing from twelve wells over its 15,400 gross (6,500 net) acre position, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations. In December 2018, the Company purchased an additional 4,200 gross operated (1,700 net) acres and 4,000 gross non-operated (200 net) acres to the northeast of its existing acreage (“NE Bullseye”) for approximately $7.5 million. The Company paid $3.2 million cash in December 2018, with the balance to be paid by the earlier of the commencement of completion operations on the third well on the acreage acquired or October 1, 2019. The Company currently expects the Bullseye and NE Bullseye to be the primary focus of its drilling program for 2019. 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. As the Company continues to expand its presence in the Southern Delaware Basin, it has begun to sell small non-core assets to allow the Company to focus on West Texas. These asset sales provide some immediate liquidity and improve the Company’s balance sheet by removing potential asset retirement obligations. Beginning in 2016, the Company sold all of its Colorado assets for approximately $5.0 million. Then in 2018, the Company sold some Eagle Ford Shale assets in Karnes County, Texas for $21.0 million; Gulf Coast conventional assets in Southeast Texas for $6.0 million, and Gulf Coast conventional and unconventional assets in South Texas for $0.9 million. The Company also sold its offshore well at Vermilion 170 in exchange for the buyer’s assumption of the plugging and abandonment liability for the well and a retained overriding royalty interest (“ORRI”) in the well and in any future wells that produce through this platform. Additionally, the Company has (i) a 37% equity investment in Exaro Energy III LLC (“Exaro”) that is primarily focused on the development of proved natural gas reserves in the Jonah Field in Wyoming; (ii) operated properties producing from various conventional formations in various counties along the Texas Gulf Coast; and (iii) operated producing properties in the Haynesville Shale, Mid Bossier and James Lime formations in East Texas. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Summary Of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 2. Summary of Significant Accounting Policies Basis of Presentation The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated. Liquidity and Going Concern Over the past few 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 revolving credit facility with the Royal Bank of Canada (the “Credit Facility”), 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, etc. 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. Other Investments The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company's proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statement of operations, the Company’s proportionate share of Exaro's net income or loss is reported as a single line-item in Gain (loss) from investment in affiliates (net of income taxes). Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates include oil and gas revenues, income taxes, stock-based compensation, reserve estimates, impairment of natural gas and oil properties, valuation of derivatives and accrued liabilities. Actual results could differ from those estimates. Revenue Recognition 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 twelve months ended December 31, 2018. 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. Cash Equivalents Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2018 , the Company had no cash and cash equivalents, as cash balances at the end of each day are transferred to reduce outstanding debt under the Company’s revolving Credit Facility to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2018, accounts payable included $4.8 million in outstanding checks that had not been presented for payment. At December 31, 2017, accounts payable included $2.3 million in outstanding checks that had not been presented for payment. Accounts Receivable The Company sells natural gas and crude oil to a limited number of customers. In addition, the Company participates with other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accounts receivables are due from either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells for which the Company serves as the operator. Generally, operators of natural gas and crude oil properties have the right to offset future revenues against unpaid charges related to operated wells. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance. Accounts receivable allowance for bad debt was $1.0 and $0.8 million as of December 31, 2018 and 2017, respectively . At December 31, 2018 and 2017, the carrying value of the Company’s accounts receivable approximated fair value. Oil and Gas Properties - Successful Efforts The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. Depreciation, depletion and amortization is calculated on a field by field basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other capitalized costs amortized over proved developed reserves. Depreciation, depletion and amortization ("DD&A") of capitalized drilling and development costs of producing natural gas and crude oil properties, including related support equipment and facilities net of salvage value, are computed using the unit of production method on a field basis based on total estimated proved developed natural gas and crude oil reserves. Amortization of producing leaseholds is based on the unit of production method using total estimated proved reserves. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates. Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 13 years. Impairment of Oil and Gas Properties 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 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. For the year ended December 31, 2018, the Company recorded an impairment expense of approximately $101.9 million related to proved properties. Included in proved property impairment expense for the current year was $61.7 million related to the impairment of the carrying costs of its offshore Gulf of Mexico properties made during the quarter ended September 30, 2018. This impairment was primarily a result of revised proved reserve estimates based on new bottom hole pressure data gathered during the planned installation of a second stage of compression in the Company’s Eugene Island 11 field. In 2018, the Company also recognized onshore proved property impairment expense of $40.2 million, of which $24.9 million was related to certain of its non-core properties in South and Southeast Texas that were reduced to their fair value as a result of planned sales during the quarters ended September 30, 2018 and December 31, 2018, and $15.3 million of impairment was due to price related reserve revisions primarily on the Company’s Wyoming and certain South Texas assets. See Note 4 – “Acquisitions and Dispositions” for further information regarding the property dispositions. For the year ended December 31, 2017, the Company recorded an impairment expense of approximately $0.3 million related to its proved properties. Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, with any such impairment charged to expense in the period. During the year ended December 31, 2018, the Company recognized impairment expense of approximately $1.3 million related to unproved properties due to expiring leases. During the year ended December 31, 2017, the Company recognized impairment expense of approximately $1.5 million for the partial impairment of two unused offshore platforms that were sold during the year. Asset Retirement Obligations Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records an asset retirement obligation (“ARO”) to reflect the Company's legal obligation related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in depreciation, depletion and amortization expense. The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and gas properties expense. See Note 11 - "Asset Retirement Obligation" for additional information. Income Taxes The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2018 . Except as described below with respect to Section 382 Ownership Change, the amount of unrecognized tax benefits did not materially change from December 31, 2017 . The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its statement of operations. The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal tax returns for 1999 – 2017 , and state tax returns for 2011 – 2017 , remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed. Concentration of Credit Risk Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 - "Concentration of Credit Risk" for additional information. Debt Issuance Costs Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. During the year ended December 31, 2013, the Company initially incurred $2.2 million of debt issuance costs relating to the Credit Facility entered into in conjunction with the merger with Crimson Exploration, Inc. The debt issuance costs were to be amortized over the original four year term of the credit line. In connection with the Credit Facility amendment in May 2016, the Company incurred an additional $1.0 million of debt issuance costs. As of December 31, 2018, the remaining balance of these debt issuance costs was $0.4 million, which will be amortized through October 1, 2019, with amortization expense included in the DD&A line item in the Company's income statement for the years ended December 31, 2018 and 2017. Stock-Based Compensation The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each restricted stock award is estimated as of the date of grant. The fair value of the Performance Stock Units is estimated as of the date of grant using the Monte Carlo simulation pricing model. Inventory Inventory primarily consists of casing and tubing which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method. Derivative Instruments and Hedging Activities The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting requirements that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in "Gain on derivatives, net" on the consolidated statements of operations for the years ended December 31, 2018 and 2017. Derivative instruments with settlement dates within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates a net asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 - "Derivative Instruments" for additional information. Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Crimson Exploration Inc., Crimson Exploration Operating, Inc., Contango Energy Company, Contango Operators, Inc., Contango Mining Company, Conterra Company, Contaro Company, Contango Alta Investments, Inc., Contango Venture Capital Corporation, Contango Rocky Mountain Inc. and any other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one other wholly-owned subsidiary that is inactive. Finally, the Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. Recent Accounting Pronouncements Leases: In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP treatment of leases and that proposed in ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize a right-of-use asset and lease liability arising from such operating leases on the balance sheet. ASU 2016-02 contains several optional practical expedients, 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 has elected to apply this practical expedient package to all of its leases. The Company has also chosen to implement the “short-term accounting policy election” which allows the Company to not include leases with an initial term of 12 months or less on the balance sheet. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company adopted this standard on January 1, 2019, and the impact of adoption is immaterial. Other: In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishment costs; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after a business combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity method investees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The provisions of this update are not expected to have a material impact on the Company’s presentation of cash flows. In January 2017, the FASB issued ASU No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (ASU 2018-01). The amendments in this update are intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill and consolidation. Public business entities should apply the amendments in this update to annual periods beginning after December 15, 2018, including interim periods within those periods. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations. 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. |
Concentration of Credit Risk
Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2018 | |
Concentration Of Credit Risk [Abstract] | |
Concentration of Credit Risk | 3. Concentration of Credit Risk The customer base for the Company is concentrated in the natural gas and oil industry. The largest purchaser of the Company’s production for the year ended December 31, 2018 was ConocoPhillips Company (36.9 % ). The Company’s sales to this company are not secured with letters of credit and in the event of non-payment, the Company could lose up to two months of revenues. The loss of two months of revenues would have a material adverse effect on the Company’s financial position. There are numerous other potential purchasers of the Company’s production. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 12 Months Ended |
Dec. 31, 2018 | |
Business Combinations [Abstract] | |
Acquisitions and Dispositions | 4. Acquisitions and Dispositions Southern Delaware Basin Acquisition In July 2016, the Company purchased approximately 12,100 gross undeveloped acres (approximately 5,000 net) acres (“Bullseye”) in the Southern Delaware Basin of Texas for up to $25 million. The purchase price was comprised of $10 million in cash paid on July 26, 2016, plus $10 million in carried well costs over the first six wells. Additionally, contingent upon success, $5 million in spud bonuses is to be paid by the Company ratably over the following 14 wells drilled, which would increase the total consideration paid by the Company to $25 m illion. As of December 31, 2018, the Company had paid all $10 million of the carried well costs and $3.7 million in spud bonuses. In December 2018, the Company purchased an additional 4,200 gross operated (1,700 net) acres and 4,000 gross non-operated (200 net) acres to the northeast of its existing acreage (“NE Bullseye”) for approximately $7.5 million. The Company paid $3.2 million cash in December 2018, with the balance to be paid by the earlier of the commencement of completion operations on the third well on the acreage acquired or October 1, 2019. North Bob West Property Sale Effective February 1, 2017, the Company sold to a third party all of its assets in the North Bob West area and its operated assets in the Escobas area, both located in Southeast Texas, for a cash purchase price of $650,000. The Company recorded a net gain of $2.9 million after removal of the asset retirement obligations associated with the sold properties. Karnes County Property Sale 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 $9.5 million. Starr County Property Sale On May 25, 2018, the Company sold its non-operated assets located in Starr County, Texas for a cash purchase price of $0.6 million. The Company recorded a gain of $1.3 million after removal of the asset retirement obligations associated with the sold properties. Liberty and Hardin County Property Sale On September 11, 2018, the Company entered into a definitive agreement to divest certain of its non-core assets in Liberty and Hardin counties in Southeast Texas. As a result of the sale, the Company reduced the value of the assets to their purchase price and recorded an impairment of approximately $12.8 million during the three months ended September 30, 2018 in “Impairment and abandonment of oil and gas properties” in the Company’s consolidated statement of operations. The sale was completed on November 2, 2018 for cash proceeds of $6.0 million. Elm Hill Property Sale On December 4, 2018, the Company sold its non-core assets located in Fayette, Gonzales, Caldwell and Bastrop counties in South Texas for a cash purchase price of $85,000. The Company recorded a gain of approximately $175,000 after removal of the asset retirement obligations associated with the sold properties. Vermilion 170 Property Sale Effective December 1, 2018, the Company sold its offshore Vermilion 170 well in exchange for a continuing ORRI in the Vermilion 170 well, the buyer’s assumption of the plugging and abandonment liability for the well, platform and associated pipeline and an ORRI in any future wells drilled by the buyer on two nearby prospects that would produce through this platform. Brooks and Zapata County Property Sale Effective December 31, 2018, the Company sold its assets located primarily in Brooks and Zapata counties in South Texas for a cash purchase price of $150,000. As a result of this planned sale, the Company reduced the value of the assets to their fair value and recorded an impairment of approximately $12.1 million included in “Impairment and abandonment of oil and gas properties” in the Company’s consolidated statement of operations. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2018 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | 5. Fair Value Measurements Pursuant to ASC 820, Fair Value Measurements and Disclosures (ASC 820), the Company's determination of fair value incorporates not only the credit standing of the counterparties involved in transactions with the Company resulting in receivables on the Company's consolidated balance sheets, but also the impact of the Company's nonperformance risk on its own liabilities. ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. As required by ASC 820, a financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3. Derivatives are recorded at fair value at the end of each reporting period. The Company records the net change in the fair value of these positions in "Gain on derivatives, net" in the Company's consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted markets prices and implied volatility factors related to changes in the forward curves. See Note 6 - "Derivative Instruments" for additional discussion of derivatives. During the year ended December 31, 2018, the Company's derivative contracts were with major financial institutions with investment grade credit ratings which were believed to have a minimal credit risk. As such, the Company was exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company did not anticipate any nonperformance. The counterparties to the Company's current and previous derivative contracts are lenders in the Company's Credit Facility. The Company did not post collateral under any of these contracts as they were secured under the Credit Facility. Estimates of the fair value of financial instruments are made in accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the Company's Credit Facility approximates carrying value because the interest rate approximates current market rates and are re-set at least every three months. See Note 12 - "Indebtedness" for further information. Fair value estimates used for non-financial assets are evaluated at fair value on a non-recurring basis include oil and gas properties evaluated for impairment when facts and circumstances indicate that there may be an impairment. If the unamortized cost of properties exceeds the undiscounted cash flows related to the properties, the value of the properties is compared to the fair value estimated as discounted cash flows related to the risk-adjusted proved, probable and possible reserves related to the properties. Fair value measurements based on these inputs are classified as Level 3. Impairments Contango tests proved oil and gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Asset Retirement Obligations The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 at inception. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments [Abstract] | |
Derivative Instruments | 6. Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts. As of December 31, 2018, the Company’s natural gas and oil derivative positions consisted of “swaps” and “costless collars”. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a sold call, which establishes a maximum price the Company will receive for the volumes under contract, and a purchased put, which establishes a minimum price. A sold put option limits the exposure of the counterparty's risk should the price fall below the strike price. Sold put options limit the effectiveness of purchased put options at the low end of the put/call collars to market prices in excess of the strike price of the put option sold. It is the Company's practice to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The counterparties to the Company's current and previous derivative contracts are lenders or affiliates of lenders in the Credit Facility. The Company does not post collateral under any of these contracts as they are secured under 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 "Gain on derivatives, net" on the consolidated statements of operations. See Note 5 – “Fair Value Measurements” for additional information. The Company had the following financial derivative contracts in place as of December 31, 2018: Commodity Period Derivative Volume/Month Price/Unit (1) Fair Value Natural Gas Jan 2019 - March 2019 Swap 600,000 MMBtus $ 3.21 (1) 121 Natural Gas April 2019 - July 2019 Swap 600,000 MMBtus $ 2.75 (1) 109 Natural Gas Aug 2019 - Oct 2019 Swap 100,000 MMBtus $ 2.75 (1) 3 Natural Gas Nov 2019 - Dec 2019 Swap 500,000 MMBtus $ 2.75 (1) (116) Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) (27) Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) 233 Oil Jan 2019 - June 2019 Collar 12,000 Bbls $ 70.00 - 76.25 (3) 1,569 Oil Jan 2019 - July 2019 Swap 6,000 Bbls $ 66.10 (3) 811 Oil July 2019 Swap 12,000 Bbls $ 72.10 (3) 288 Oil Aug 2019 - Oct 2019 Swap 9,000 Bbls $ 72.10 (3) 635 Oil Nov 2019 - Dec 2019 Swap 12,000 Bbls $ 72.10 (3) 552 Total net fair value of derivative instruments $ 4,178 (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on Argus Louisiana Light Sweet crude oil prices. (3) Based on West Texas Intermediate crude oil prices. The Company had the following financial derivative contracts in place as of December 31, 2017: Commodity Period Derivative Volume/Month Price/Unit Fair Value Natural Gas Jan 2018 - July 2018 Swap 370,000 MMBtus $ 3.07 (1) 678 Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $ 3.07 (1) 56 Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $ 3.07 (1) 89 Oil Jan 2018 - June 2018 Swap 20,000 Bbls $ 56.40 (2) (994) Oil July 2018 - Oct 2018 Collar 20,000 Bbls $ 52.00 - 56.85 (2) (544) Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $ 52.00 - 56.85 (2) (173) Oil Jan 2018 - Dec 2018 Collar 2,000 Bbls $ 52.00 - 58.76 (3) (55) Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) (300) Total net fair value of derivative instruments $ (1,243) (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 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 summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2017 (in thousands): Gross Netting (1) Total Assets $ 1,188 $ (1,188) $ — Liabilities $ (2,431) $ 1,188 $ (1,243) (1) Represents counterparty netting under agreements governing such derivatives. The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years ended December 31, 2018 and 2017 (in thousands): Year Ended December 31, Contract Type 2018 2017 Crude oil contracts $ (2,969) $ 861 Natural gas contracts (513) 260 Realized gain (loss) $ (3,482) $ 1,121 Crude oil contracts $ 6,126 $ (2,065) Natural gas contracts (705) 4,269 Unrealized gain $ 5,421 $ 2,204 Gain on derivatives, net $ 1,939 $ 3,325 |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2018 | |
Stock-Based Compensation [Abstract] | |
Stock-Based Compensation | 7. Stock Based Compensation As of December 31, 2018, the Company had in place the Contango Oil & Gas Company Second Amended and Restated 2009 Incentive Compensation Plan (“the Second Amended 2009 Plan”) which allows for stock options, restricted stock or performance stock units to be awarded to officers, directors and employees as a performance-based award. Second Amended and Restated 2009 Incentive Compensation Plan On March 21, 2017, the Company’s board of directors (the “Board”) amended and restated the Company’s then existing incentive compensation plan through the adoption of the Second Amended 2009 Plan. The Second Amended 2009 Plan provides for both cash awards and equity awards to officers, directors, employees or consultants of the Company. Awards made under the Second Amended 2009 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Board. Under the terms of the Second Amended 2009 Plan, shares of the Company’s common stock may be issued for plan awards. Stock options under the Second Amended 2009 Plan must have an exercise price of each option equal to or greater than the market price of the Company’s common stock on the date of grant. The Company may grant officers and employees both incentive stock options intended to qualify under Section 422 of the Internal Revenue Code of 1986, as amended, and stock options that are not qualified as incentive stock options. Stock option grants to non-employees, such as directors and consultants, can only be stock options that are not qualified as incentive stock options. Options granted generally expire after five or ten years. The vesting schedule for all equity awards varies from immediately to over a four -year period. As of December 31, 2018 , the Company had approximately 1.6 million shares of equity awards available for future grant under the Second Amended 2009 Plan, assuming Performance Stock Units are settled at 100% of target. Effective January 1, 2014, the Company implemented performance-based long-term bonus plans under the 2009 Plan for the benefit of all employees through a Cash Incentive Bonus Plan ( “ CIBP ” ) and a Long-Term Incentive Plan ( “ LTIP ” ). The specific targeted performance measures under these sub-plans are approved by the Compensation Committee and/or the Board. Upon achieving the performance levels established each year, bonus awards under the CIBP and LTIP will be calculated as a percentage of base salary of each employee for the plan year. The CIBP and LTIP plan awards for each year are expected to be disbursed in the first quarter of the following year. Employees must be employed by the Company at the time that awards are disbursed to be eligible. The CIBP awards will be paid in cash while LTIP awards will consist of restricted common stock, performance stock units and/or stock options. The number of shares of restricted common stock and the number of shares underlying the stock options granted will be determined based upon the fair market value of the common stock on the date of the grant. 2005 Stock Incentive Plan The 2005 Plan was adopted by the Company's Board in conjunction with the merger with Crimson Exploration, Inc. This plan expired on February 25, 2015, and therefore, no additional shares are available for grant. Stock Options A summary of stock options as of and for the years ended December 31, 2018 and 2017 is presented in the table below (dollars in thousands, except per share data): Year Ended December 31, 2018 2017 Weighted Weighted Shares Average Shares Average Under Exercise Under Exercise Options Price Options Price Outstanding, beginning of the period 94,833 $ 57.69 111,905 $ 55.53 Exercised — $ — — $ — Expired / Forfeited (61,196) $ 58.72 (17,072) $ 43.50 Outstanding, end of year 33,637 $ 55.82 94,833 $ 57.69 Aggregate intrinsic value $ — $ — Exercisable, end of year 33,637 $ 55.82 94,833 $ 57.69 Aggregate intrinsic value $ — $ — Available for grant, end of the period * 1,854,588 2,002,492 Weighted average fair value of options granted during the period $ — $ — * Excludes Performance Stock Units. During the years ended December 31, 2018 and 2017, the Company did not issue any stock options. During the year ended December 31, 2018, 61,196 stock options previously issued were forfeited by former employees, of which 55,943 were related to the resignation of the Company’s former President and CEO in September 2018. During the year ended December 31, 2017, 17,072 stock options previously issued were forfeited. As of December 31, 2018, there were 33,637 stock options vested and exercisable under the 2005 Plan. The exercise price for such options ranges from $28.96 to $60.33 per share, with an average remaining contractual life of two years. Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the years ended December 31, 2018 and 2017, there was no excess tax benefit recognized. See Note 2 – "Summary of Significant Accounting Policies". Compensation expense related to employee stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. During the years ended December 31, 2018 and 2017, the Company did not recognize any stock option expense. The aggregate intrinsic value of stock options exercised/forfeited during each of the years ended December 31, 2018 and 2017 was zero. Restricted Stock During the year ended December 31, 2018, the Company issued 225,782 restricted stock awards from the 2009 Plan, which vest over three years, to executive officers as part of their overall 2018 compensation packages. Additionally, the Company issued 82,500 restricted stock awards from the 2009 Plan, which vest on the one-year anniversary of the date of grant, to the members of the board of directors as part of their 2018 director compensation. During the year ended December 31, 2018, 160,378 restricted stock awards were forfeited by former employees, of which 105,800 were related to the resignation of the Company’s former President and CEO in September 2018. 102,573 of the shares vested in 2018 were also related to the resignation of the Company’s former President and CEO in September 2018. The weighted average fair value of the restricted shares granted during the year was $3.76, with a total grant date fair value of approximately $1.2 million after adjustment for estimated weighted average forfeiture rate of 0.0%. During the year ended December 31, 2017, the Company issued 383,376 restricted stock awards to new and existing employees, which vest over three years, plus an additional 74,325 restricted stock awards to the members of the board of directors which vest on the one-year anniversary of the date of grant. During the year ended December 31, 2017, 142,218 restricted stock awards were forfeited by former employees. The weighted average fair value of the restricted shares granted during the year was $7.55, with a total grant date fair value of approximately $3.5 million after adjustment for estimated weighted average forfeiture rate of 4.8%. Restricted stock activity as of December 31, 2018 and 2017 and for the years then ended is presented in the table below (dollars in thousands, except per share data): 2018 2017 Weighted Aggregate Weighted Aggregate Restricted Average Intrinsic Restricted Average Intrinsic Shares Fair Value Value Shares Fair Value Value Outstanding, beginning of the period 731,073 $ 10.55 $ 1,667 638,158 $ 14.22 $ 5,960 Granted 308,282 3.76 1,158 457,701 7.55 3,457 Vested (419,356) 10.72 1,965 (222,568) 15.12 1,263 Canceled / Forfeited (160,378) 6.49 309 (142,218) 10.23 814 Not vested, end of the period 459,621 7.26 662 731,073 10.55 1,667 The Company recognized approximately $4.8 million and $6.1 million in stock compensation expense during the years ended December 31, 2018 and 2017, respectively, for restricted shares granted to its officers, employees and directors. As of December 31, 2018, there were 459,621 shares of unvested restricted stock outstanding. An additional $1.9 million of compensation expense will be recognized over the remaining vesting period. Performance Stock Units Performance stock units (“PSUs”) represent a contractual right to receive shares of the Company's common stock. The settlement of PSUs may range from 0% to 300% of the targeted number of PSUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PSUs vest and settlement is determined after a three year period. Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PSUs with shares of the Company's common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award. During the year ended December 31, 2018, the Company granted 190,782 PSUs to executive officers, as part of their overall compensation package, at a weighted average fair value of $7.69 per unit. All prices were determined using the Monte Carlo simulation model. Also during the year, 188,927 PSUs were forfeited by former employees, of which 153,127 were related to the resignation of the Company’s former President and CEO in September 2018. 147,800 PSUs that were issued in 2016 expired during the year ended December 31, 2018, as the Company did not meet the performance criteria, and are available to be reissued. During the year ended December 31, 2017, the Company granted 30,000 PSUs to a new employee, at a weighted average fair value of $8.32 per unit and 160,908 PSUs to executive officers, as part of their overall compensation package, at a value of $13.91 per unit. All prices were determined using the Monte Carlo simulation model. During the year ended December 31, 2017, 99,363 PSUs were forfeited by former employees. |
Share Repurchase Programs
Share Repurchase Programs | 12 Months Ended |
Dec. 31, 2018 | |
Share Repurchase Programs [Abstract] | |
Share Repurchase Programs | 8. Share Repurchase Program In September 2011, the Company’s board of directors approved a $50 million share repurchase program. All shares are to be purchased in the open market or through privately negotiated transactions. Purchases are made subject to market conditions and certain volume, pricing and timing restrictions to minimize the impact of the purchases upon the market, and when the Company believes its stock price to be undervalued. Repurchased shares of common stock become authorized but unissued shares, and may be issued in the future for general corporate and other purposes. No shares were purchased during the years ended December 31, 2018 and 2017. As of December 31, 2018, the Company had $31.8 million available under the share repurchase program for future purchases. On November 2, 2018, the Company amended its revolving Credit Facility with Royal Bank of Canada to, among other things, prevent for share repurchases subject to certain conditions. The Company is currently in compliance with these conditions. |
Other Financial Information
Other Financial Information | 12 Months Ended |
Dec. 31, 2018 | |
Other Financial Information [Abstract] | |
Other Financial Information | 9. Other Financial Information The following table provides additional detail for accounts receivable, prepaids, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): December 31, December 31, 2018 2017 Accounts receivable: Trade receivables $ 6,052 $ 6,565 Receivable for Alta Resources distribution 1,993 1,993 Joint interest billings 3,833 4,030 Income taxes receivable 424 424 Other receivables 223 828 Allowance for doubtful accounts (994) (781) Total accounts receivable $ 11,531 $ 13,059 Prepaid expenses and other: Prepaid insurance $ 792 $ 1,177 Other 511 715 Total prepaid expenses and other $ 1,303 $ 1,892 Accounts payable and accrued liabilities: Royalties and revenue payable $ 17,986 $ 18,181 Advances from partners 1,785 2,243 Accrued exploration and development 4,751 8,400 Accrued acquisition costs 4,352 — Trade payables 3,385 9,559 Accrued general and administrative expenses 2,545 2,960 Accrued operating expenses 1,801 1,654 Other accounts payable and accrued liabilities 2,901 3,758 Total accounts payable and accrued liabilities $ 39,506 $ 46,755 Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the years ended December 31, 2018 and 2017, in thousands: Year Ended December 31, 2018 2017 Cash payments: Interest payments $ 5,656 $ 3,699 Income tax payments, net of cash refunds 81 616 Non-cash items excluded from investing activities in the consolidated statements of cash flows: Decrease in accrued capital expenditures (3,649) (9,931) |
Investment In Exaro Energy III
Investment In Exaro Energy III LLC | 12 Months Ended |
Dec. 31, 2018 | |
Investment In Exaro Energy III LLC [Abstract] | |
Investment In Exaro Energy III LLC | 10. Investment in Exaro Energy III LLC Through the Company’s wholly-owned subsidiary, Contaro Company (“Contaro”), the Company committed to invest up to $67.5 million in Exaro for an ownership interest of approximately 37%. The aggregate commitment of all the Exaro investors was approximately $183 million. The Company did not make any contributions during the year ended December 31, 2018 and has no plans to invest additional funds in Exaro, as the commitment to invest in Exaro expired on March 31, 2017. As of December 31, 2018, the Company had invested approximately $46.9 million. Contango’s share in the equity of Exaro at December 31, 2018 was approximately $5.7 million. The Company's share in Exaro's results of operations recognized for the years ended December 31, 2018 and 2017 was a loss of $12.6 million, net of zero tax expense and a gain of $2.7 million, net of zero tax, respectively. |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation | 11. Asset Retirement Obligation The Company accounts for its retirement obligation of long lived assets by recording the net present value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. When the liability is initially recorded, a company increases the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. Activities related to the Company’s ARO during the years ended December 31, 2018 and 2017 were as follows (in thousands): Year Ended December 31, 2018 2017 Balance as of the beginning of the period $ 22,405 $ 26,926 Liabilities incurred during period 163 308 Liabilities settled during period (1,339) (4,503) Accretion 960 1,056 Sales (8,599) (2,949) Change in estimate (93) 1,567 Balance as of the end of the period $ 13,497 $ 22,405 All of the total liabilities incurred during the years ended December 31, 2018 and 2017 were related to new wells drilled during the period. All of the total liabilities settled during the years ended December 31, 2018 and 2017 were related to wells plugged and abandoned during the period. |
Indebtedness
Indebtedness | 12 Months Ended |
Dec. 31, 2018 | |
Indebtedness | |
Indebtedness | 12. 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. On November 2, 2018, the Company entered into the Sixth Amendment to the Credit Facility (the “Sixth Amendment”), whereby the current borrowing base was reaffirmed at $105 million and was reduced to $90 million on and after January 31, 2019 until the next scheduled redetermination date on May 1, 2019. The Sixth Amendment also provides for, among other things: (i) reducing the letter of credit issuance commitment capacity from $20.0 million to $5.0 million; (ii) waiving compliance with the required minimum 1.00 to 1.00 Current Ratio for the fiscal quarters ended September 30, 2018 and December 31, 2018; (iii) eliminating an exception from the restriction on payment of dividends, stock repurchases or redemptions of equity for repurchases under certain circumstances; (iv) waiving advance notice and a requirement for delivery of a revised reserve report related to the Liberty and Hardin County, Texas asset sale; and (v) requires delivery to the administrative agent of internally-prepared monthly consolidated financial statements of the Company within 25 days of the end of such month. Initially, the Company incurred $2.2 million of arrangement and upfront fees in connection with the Credit Facility which was to be amortized over the original four-year term of the facility. In May 2016, in connection with the amendment, the Company incurred an additional $1.0 million of arrangement and upfront fees. As of December 31, 2018, the remaining balance of these fees was $0.4 million, which will be amortized through October 1, 2019. As of December 31, 2018, the Company had $60.0 million outstanding under the Credit Facility, which matures on October 1, 2019, and $1.9 million in outstanding letters of credit. As of December 31, 2017, the Company had $85.4 million outstanding under the Credit Facility and $1.9 million in outstanding letters of credit. As of December 31, 2018, borrowing availability under the Credit Facility was $43.1 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. Borrowings under the Credit Facility bear interest at LIBOR, the U.S. prime rate, or the federal funds rate, plus a 2.5% to 4.0% margin, dependent upon the amount outstanding. Additionally, the Company must pay a 0.5% commitment fee regardless of the amount of the Credit Facility that is unused. Total interest expense under the Credit Facility, including commitment fees, for the years ended December 31, 2018 and 2017 was approximately $5.5 million and $4.1 million, respectively. The Credit Facility contains restrictive covenants which, among other things, requires a Current Ratio of greater than or equal to 1.0 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Facility agreement. As of December 31, 2018, the Company was in compliance with all of its covenants. However, the Company was not in compliance with the Current Ratio covenant as of September 30, 2018 and obtained a waiver for such non-compliance, if any, for the quarters ending September 30, 2018 and December 31, 2018. 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, a going concern qualification, payment defaults, breach of certain covenants, bankruptcy, insolvency or change of control events. As of December 31, 2018, the Company was in compliance with all of its covenants under the Credit Facility agreement. Pursuit of Refinancing and Other Liquidity-Enhancing Alternatives Over the past few 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 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, etc. 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. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments And Contingencies [Abstract] | |
Commitments and Contingencies | 13. Commitments and Contingencies Contango pays delay rentals on its oil and gas leases and leases its office space and certain other equipment. The Company’s corporate offices are located at 717 Texas Avenue in downtown Houston, Texas, under a lease that expires March 31, 2021. As of December 31, 2018, minimum future lease payments for delay rentals and operating leases for Contango’s fiscal years are as follows (in thousands): Fiscal years ending December 31, 2019 $ 958 2020 265 2021 179 2022 70 2023 69 2024 and thereafter 69 Total $ 1,610 The amounts incurred under operating leases and delay rentals during the years ended December 31, 2018 and 2017 were approximately $5.1 million and $4.8 million, respectively. Throughput Contract Commitment The Company signed a throughput agreement with a third party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. 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. 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 $1.0 million, $1.1 million and $0.4 million during the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, the Company estimates that the net deficiency fee will be approximately $1.0 million annually for the remaining contract period, based upon forecasted production volumes from existing proved producing reserves only, assuming no future development during this commitment period. As of December 31, 2018, based upon the current commodity price market and the Company’s short term strategic drilling plans, the Company has recorded a $1.7 million loss contingency through December 31, 2019. The Company will continue to assess this commitment in light of its drilling and development plans for this area and will need to accrue an additional $240 thousand through the expiration of the throughput commitment, if there is no new development in this area. Legal Proceedings From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below. On November 16, 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 Texas 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. On September 14, 2012, a subsidiary of the Company was named as defendant in a lawsuit filed in district court for Harris County in Texas involving a title dispute over a 1/16th mineral interest in the producing intervals of certain wells operated by the Company in the Catherine Henderson “A” Unit in Liberty County in Texas. This case was subsequently transferred to the district court for Liberty County, Texas and combined with a suit filed by other parties against the plaintiff claiming ownership of the disputed interest. The plaintiff has alleged that, based on its interpretation of a series of 1972 deeds, it owns an additional 1/16th unleased mineral interest in the producing intervals of these wells on which it has not been paid (this claimed interest is in addition to a 1/16th unleased mineral interest on which it has been paid). The Company has made royalty payments with respect to the disputed interest in reliance, in part, upon leases obtained from successors to the grantors under the aforementioned deeds, who claim to have retained the disputed mineral interests thereunder. The plaintiff previously alleged damages of approximately $10.7 million although the plaintiff’s claim increases as additional hydrocarbons are produced from the subject wells. The trial court has entered judgment in favor of the Company’s subsidiary and the successors to the grantors under the aforementioned deeds. The plaintiff appealed the trial court’s decision to the applicable state Court of Appeals. On December 14, 2017, the Court of Appeals affirmed the judgement in the Company’s favor. The plaintiff 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. Employment Agreements On November 30, 2016, all of the Company’s existing employment agreements expired through nonrenewal, and the Company and Mr. Keel, Mr. Grady, Mr. Mengle and Mr. Atkins entered into Amended and Restated Employment Agreements (“Employment Agreements”). The Employment Agreements provided for an initial term of three years for Messrs. Keel and Grady and an initial term of two years for Messrs. Mengle and Atkins. Each of the Employment Agreements will automatically renew for additional one year terms, unless Contango or the executive provides prior notice of intention not to extend the agreement. Mr. Keel’s employment agreement was terminated in conjunction with the Separation Agreement entered into between the Company and Mr. Keel on August 14, 2018. The employment agreements with Mr. Mengle and Mr. Atkins expired on November 30, 2018 and were not renewed pursuant to the Company’s plan to phase out the use of employment agreements. During the term of the Employment Agreements, Mr. Keel was entitled to a base salary of $600,000 until his resignation. Mr. Grady is entitled to a base salary of $400,000, Mr. Mengle was entitled to a base salary of $300,000 and Mr. Atkins was entitled to a base salary of $310,000. The Employment Agreements provided that each executive shall participate in the Company’s CIBP and LTIP. With respect to the CIBP, the Employment Agreements provide that the executives are eligible to receive an annual cash incentive bonus with a target award level of 100% for Messrs. Keel and Grady and 80% for Messrs. Mengle and Atkins, of such executive’s base salary, under such terms and conditions as the Company may determine each applicable year. With respect to the LTIP, the Employment Agreements provide that the executives are eligible to participate in the Company’s equity compensation plan for each calendar year in which the executive is employed by the Company, under such terms and conditions as the Company may determine in each applicable year. |
Net Loss Per Common Share
Net Loss Per Common Share | 12 Months Ended |
Dec. 31, 2018 | |
Net Loss Per Common Share | |
Net Loss Per Common Share | 14. Net Loss Per Common Share A reconciliation of the components of basic and diluted net loss per common share for the years ended December 31, 2018 and 2017 is presented below (in thousands): Year Ended December 31, 2018 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (121,568) 25,945 $ (4.69) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (121,568) 25,945 $ (4.69) Year Ended December 31, 2017 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (17,643) 24,686 $ (0.71) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (17,643) 24,686 $ (0.71) The numerator for basic earnings per share is net loss attributable to common stockholders. The numerator for diluted earnings per share is net loss available to common stockholders. Potential dilutive securities (stock options, restricted stock and PSUs) have not been considered when their effect would be antidilutive. The potentially dilutive shares would have been 1,141,707 shares and 1,282,590 shares for the years ended December 31, 2018 and 2017, respectively. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2018 | |
Income Taxes [Abstract] | |
Income Taxes | 15. Income Taxes Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statements and income tax reporting. Numerous judgments and assumptions are inherent in the determination of deferred income tax assets and liabilities as well as income taxes payable in the current period. The Company is subject to taxation in several jurisdictions, and the calculation of its tax liabilities involves dealing with uncertainties in the application of complex tax laws (including the effect of the Tax Cuts and Jobs Act of 2017) and regulations in various taxing jurisdictions. The Tax Cuts and Jobs Act 2017 On December 22, 2017, the United States enacted tax reform legislation known as the H.R.1, commonly referred to as the “Tax Cuts and Jobs Act” (the “Act”), resulting in significant modifications to existing law. The Company completed the accounting for the effects of the Act during 2017. The Company’s financial statements for the year ended December 31, 2018 reflect certain effects of the Act which includes a reduction in the corporate tax rate from 35 percent to 21 percent effective January 1, 2018, as well as other changes. The Tax Cuts and Jobs Act of 2017 contained a significant limitation on Section 163(j) interest taken in any given tax year. As of December 31, 2018, the Company had a limitation of $5.5 million which will carry over indefinitely. The carryover is subject to any applicable Section 382 limitation (discussed below). Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 21 percent and 35 percent for the years ended December 31, 2018 and 2017, respectively, to pretax income as follows (dollars in thousands): Year Ended December 31, 2018 2017 Provision/(benefit) at statutory tax rate $ (25,504) 21.00 % $ (6,314) 35.00 % State income tax provision, net of federal benefit 120 (0.10) % (864) 4.79 % Permanent differences 579 (0.48) % 50 (0.28) % Stock based compensation 1,353 (1.11) % (361) 2.00 % Valuation allowance 21,941 (18.07) % 7,209 (39.96) % Rate change (35% to 21% fed rate) % 35,250 (195.41) % Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act % (35,674) 197.76 % Other 1,631 (1.34) % 309 (1.71) % Income tax provision /(benefit) $ 120 (0.10) % $ (395) 2.19 % The effective tax rate for the years ended December 31, 2018 and 2017 varies from the statutory rate primarily as a result of recording a valuation allowance. The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands): Year Ended December 31, 2018 2017 Current tax provision (benefit): Federal $ — $ (424) State 120 453 Total $ 120 $ 29 Deferred tax provision (benefit): Federal $ — $ (424) State — — Total $ — $ (424) Total tax provision (benefit): Federal $ — $ (848) State 120 453 Total $ 120 $ (395) Included in gain (loss) from investment in affiliates $ — $ — Total income tax provision (benefit) $ 120 $ (395) The net deferred tax is comprised of the following (in thousands): December 31, 2018 2017 Deferred tax assets: Net operating loss carryforward $ 80,930 $ 60,464 Income tax credits 454 454 Derivative instruments — 261 Deferred compensation 678 1,418 Oil and gas properties — — Other 1,529 491 Total deferred tax assets before valuation allowance $ 83,591 $ 63,088 Valuation allowance (70,973) (49,032) Net deferred tax assets $ 12,618 $ 14,056 Deferred tax liability: Oil and gas properties $ (11,042) $ (10,567) Investment in affiliates (275) (3,065) Derivative instruments (877) — Deferred tax liability $ (12,194) $ (13,632) Total net deferred tax $ 424 $ 424 Accounting for uncertainty in income taxes prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the amount of deferred tax liabilities, level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, the Company believes it is not more-likely-than-not that it will realize the benefits of these deductible differences and has recorded a valuation allowance for federal and state purposes of approximately $70 million and approximately $1 million, respectively. As of December 31, 2018, the Company had federal net operating loss (“NOL”) carryforwards of approximately $380.8 million and state NOLs of $20.4 million. The Federal NOL carryforwards occurred due to the merger with Crimson Exploration, Inc. (“Crimson”) in 2013 (the “Merger”) and subsequent taxable losses during the years 2014 through 2018 due to lower commodity prices and utilization of various elections available to the Company in expensing capital expenditures incurred in the development of oil and gas properties. Generally, these NOLs are available to reduce future taxable income and the related income tax liability subject to the limitations set forth in Internal Revenue Code Section 382 related to changes of more than 50% of ownership of the Company’s stock by 5% or greater shareholders over a three-year period (a Section 382 Ownership Change) from the time of such an ownership change. On November 19, 2018, the Company completed a follow-on offering (the “Offering”) of 7.5 million additional shares of common stock. Prior to December 18, 2018, the underwriters exercised their Green Shoe option purchasing an additional approximate 1.1 million shares, resulting in a total of approximately 8.6 million primary shares issued in the Offering. This issuance resulted in a Section 382 Ownership Change which limits the Company’s future ability to use its NOLs. As such, the Company is limited in use of NOLs and Section 163(j) interest expense limitations for amounts incurred prior to November 20, 2018 in an amount estimated to be approximately $2.4 million per year (plus any recognized built in gains during the next five years) or until expiration of each annual vintage of NOL (generally, 20 years for each annual vintage of NOLs incurred prior to 2018). Based on current year estimates, it is likely that a substantial portion of the Company’s pre-2018 NOL’s will expire unused as a result of these limitations. Due to the presence of the valuation allowance from prior years, this event resulted in a no net charge to earnings. ASC 740, Income Taxes (“ASC 740”) prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of income tax positions taken or expected to be taken in an income tax return. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. As a result of the Merger, the Company acquired certain tax positions taken by Crimson in prior years. These positions are not expected to have a material impact on results of operations, financial position or cash flows. A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands): Unrecognized Tax Benefits Balance at December 31, 2017 $ 227 Additions based on tax positions related to the current year — Additions based on tax positions related to prior years — Additions due to acquisitions — Reductions due to a lapse of the applicable statute of limitations — Change in rate due to remeasurement — Balance at December 31, 2018 $ 227 The Company's policy is to recognize interest and penalties related to uncertain tax positions as income tax benefit (expense) in the Company’s Consolidated Statements of Operations. The Company had no interest or penalties related to unrecognized tax benefits for the year ended December 31, 2018 or any prior years. The total amount of unrecognized tax benefit, if recognized, that would affect the effective tax rate was zero. The Company's tax returns are subject to periodic audits by the various jurisdictions in which the Company operates. These audits can result in adjustments of taxes due or adjustments of the NOL carryforwards that are available to offset future taxable income. The Company does not anticipate that the total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to December 31, 2018. Generally, the Company's income tax years of 1999 through 2017 remain open and subject to examination by Federal tax authorities, and the tax years of 2011 through 2017 remain open and subject to examination by the tax authorities in Texas and Louisiana which are the jurisdictions where the Company carries its principal operations. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | 16. Subsequent Events The Company has evaluated subsequent events through the date the financial statements were available to be issued. Nothing that would require recognition or disclosure in the financial statements was identified in addition to the items disclosed in the financial statements. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
Summary Of Significant Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly-owned subsidiaries are consolidated. |
Liquidity and Going Concern | Liquidity and Going Concern Over the past few 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 revolving credit facility with the Royal Bank of Canada (the “Credit Facility”), 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, etc. 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. |
Other Investments | Other Investments The Company has two seats on the board of directors of Exaro and has significant influence, but not control, over the company. As a result, the Company's 37% ownership in Exaro is accounted for using the equity method. Under the equity method, the Company's proportionate share of Exaro's net income increases the balance of its investment in Exaro, while a net loss or payment of dividends decreases its investment. In the consolidated statement of operations, the Company’s proportionate share of Exaro's net income or loss is reported as a single line-item in Gain (loss) from investment in affiliates (net of income taxes). |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The most significant estimates include oil and gas revenues, income taxes, stock-based compensation, reserve estimates, impairment of natural gas and oil properties, valuation of derivatives and accrued liabilities. Actual results could differ from those estimates. |
Revenue Recognition | Revenue Recognition 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 twelve months ended December 31, 2018. 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. |
Cash Equivalents | Cash Equivalents Cash equivalents are considered to be highly liquid investment grade debt investments having an original maturity of 90 days or less. As of December 31, 2018 , the Company had no cash and cash equivalents, as cash balances at the end of each day are transferred to reduce outstanding debt under the Company’s revolving Credit Facility to minimize debt service costs. Under the Company’s cash management system, checks issued but not yet presented to banks by the payee frequently result in book overdraft balances for accounting purposes and are classified in accounts payable in the consolidated balance sheets. At December 31, 2018, accounts payable included $4.8 million in outstanding checks that had not been presented for payment. At December 31, 2017, accounts payable included $2.3 million in outstanding checks that had not been presented for payment. |
Accounts Receivable | Accounts Receivable The Company sells natural gas and crude oil to a limited number of customers. In addition, the Company participates with other parties in the operation of natural gas and crude oil wells. Substantially all of the Company’s accounts receivables are due from either purchasers of natural gas and crude oil or participants in natural gas and crude oil wells for which the Company serves as the operator. Generally, operators of natural gas and crude oil properties have the right to offset future revenues against unpaid charges related to operated wells. The allowance for doubtful accounts is an estimate of the losses in the Company’s accounts receivable. The Company periodically reviews the accounts receivable from customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions and other pertinent factors. Amounts deemed uncollectible are charged to the allowance. Accounts receivable allowance for bad debt was $1.0 and $0.8 million as of December 31, 2018 and 2017, respectively . At December 31, 2018 and 2017, the carrying value of the Company’s accounts receivable approximated fair value. |
Oil and Gas Properties - Successful Efforts | Oil and Gas Properties - Successful Efforts The Company follows the successful efforts method of accounting for its natural gas and oil activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs, such as seismic costs and other geological and geophysical expenses, are expensed as incurred. Depreciation, depletion and amortization is calculated on a field by field basis using the unit of production method, with lease acquisition costs amortized over total proved reserves and other capitalized costs amortized over proved developed reserves. Depreciation, depletion and amortization ("DD&A") of capitalized drilling and development costs of producing natural gas and crude oil properties, including related support equipment and facilities net of salvage value, are computed using the unit of production method on a field basis based on total estimated proved developed natural gas and crude oil reserves. Amortization of producing leaseholds is based on the unit of production method using total estimated proved reserves. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least annually. Revisions are accounted for prospectively as changes in accounting estimates. Other property and equipment are depreciated using the straight-line method over their estimated useful lives which range between three and 13 years. |
Impairment of Oil and Gas Properties | Impairment of Oil and Gas Properties 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 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. For the year ended December 31, 2018, the Company recorded an impairment expense of approximately $101.9 million related to proved properties. Included in proved property impairment expense for the current year was $61.7 million related to the impairment of the carrying costs of its offshore Gulf of Mexico properties made during the quarter ended September 30, 2018. This impairment was primarily a result of revised proved reserve estimates based on new bottom hole pressure data gathered during the planned installation of a second stage of compression in the Company’s Eugene Island 11 field. In 2018, the Company also recognized onshore proved property impairment expense of $40.2 million, of which $24.9 million was related to certain of its non-core properties in South and Southeast Texas that were reduced to their fair value as a result of planned sales during the quarters ended September 30, 2018 and December 31, 2018, and $15.3 million of impairment was due to price related reserve revisions primarily on the Company’s Wyoming and certain South Texas assets. See Note 4 – “Acquisitions and Dispositions” for further information regarding the property dispositions. For the year ended December 31, 2017, the Company recorded an impairment expense of approximately $0.3 million related to its proved properties. Unproved properties are reviewed quarterly to determine if there has been an impairment of the carrying value, with any such impairment charged to expense in the period. During the year ended December 31, 2018, the Company recognized impairment expense of approximately $1.3 million related to unproved properties due to expiring leases. During the year ended December 31, 2017, the Company recognized impairment expense of approximately $1.5 million for the partial impairment of two unused offshore platforms that were sold during the year. |
Asset Retirement Obligations | Asset Retirement Obligations Asset Retirement and Environmental Obligations (ASC 410) requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company records an asset retirement obligation (“ARO”) to reflect the Company's legal obligation related to future plugging and abandonment of its oil and natural gas wells, platforms and associated pipelines and equipment. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted, risk-free interest rate. At least annually, the Company reassesses the obligation to determine whether a change in the estimated obligation is necessary. The Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should these indicators suggest the estimated obligation may have materially changed on an interim basis (quarterly), the Company will accordingly update its assessment. Additional retirement obligations increase the liability associated with new oil and natural gas wells, platforms, and associated pipelines and equipment as these obligations are incurred. The liability is accreted to its present value each period and the capitalized cost is depleted over the useful life of the related asset. The accretion expense is included in depreciation, depletion and amortization expense. The estimated liability is based on historical experience in plugging and abandoning wells. The estimated remaining lives of the wells is based on reserve life estimates and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free rate, changes in the remaining lives of the wells or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company recognizes a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs. This gain or loss on abandonment is included in impairment and abandonment of oil and gas properties expense. See Note 11 - "Asset Retirement Obligation" for additional information. |
Income Taxes | Income Taxes The Company follows the liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when, based upon management’s estimates, it is more likely than not that a portion of the deferred tax assets will not be realized in a future period. The Company reviews its tax positions quarterly for tax uncertainties. The Company did not have significant uncertain tax positions as of December 31, 2018 . Except as described below with respect to Section 382 Ownership Change, the amount of unrecognized tax benefits did not materially change from December 31, 2017 . The amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on its financial position or results of operations. The Company includes interest and penalties in interest income and general and administrative expenses, respectively, in its statement of operations. The Company files income tax returns in the United States and various state jurisdictions. The Company’s federal tax returns for 1999 – 2017 , and state tax returns for 2011 – 2017 , remain open for examination by the taxing authorities in the respective jurisdictions where those returns were filed. |
Concentration of Credit Risk | Concentration of Credit Risk Substantially all of the Company’s accounts receivable result from natural gas and oil sales or joint interest billings to a limited number of third parties in the natural gas and oil industry. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. See Note 3 - "Concentration of Credit Risk" for additional information. |
Debt Issuance Costs | Debt Issuance Costs Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt. During the year ended December 31, 2013, the Company initially incurred $2.2 million of debt issuance costs relating to the Credit Facility entered into in conjunction with the merger with Crimson Exploration, Inc. The debt issuance costs were to be amortized over the original four year term of the credit line. In connection with the Credit Facility amendment in May 2016, the Company incurred an additional $1.0 million of debt issuance costs. As of December 31, 2018, the remaining balance of these debt issuance costs was $0.4 million, which will be amortized through October 1, 2019, with amortization expense included in the DD&A line item in the Company's income statement for the years ended December 31, 2018 and 2017. |
Stock-Based Compensation | Stock-Based Compensation The Company applies the fair value based method to account for stock based compensation. Under this method, compensation cost is measured at the grant date based on the fair value of the award and is recognized over the requisite service period, which generally aligns with the award vesting period. The Company classifies the benefits of tax deductions in excess of the compensation cost recognized for the options (excess tax benefit) as financing cash flows. The fair value of each restricted stock award is estimated as of the date of grant. The fair value of the Performance Stock Units is estimated as of the date of grant using the Monte Carlo simulation pricing model. |
Inventory | Inventory Inventory primarily consists of casing and tubing which will be used for drilling or completion of wells. Inventory is recorded at the lower of cost or market using specific identification method. |
Derivatives Instruments and Hedging Activities | Derivative Instruments and Hedging Activities The Company accounts for its derivative activities under the provisions of ASC 815, Derivatives and Hedging (ASC 815). ASC 815 establishes accounting and reporting requirements that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at fair value. From time to time, the Company hedges a portion of its forecasted oil and natural gas production. Derivative contracts entered into by the Company have consisted of transactions in which the Company hedges the variability of cash flow related to a forecasted transaction using variable to fixed swaps and collars. The Company elected to not designate any of its derivative positions for hedge accounting. Accordingly, the net change in the mark-to-market valuation of these positions as well as all payments and receipts on settled derivative contracts are recognized in "Gain on derivatives, net" on the consolidated statements of operations for the years ended December 31, 2018 and 2017. Derivative instruments with settlement dates within one year are included in current assets or liabilities, whereas derivative instruments with settlement dates exceeding one year are included in non-current assets or liabilities. The Company calculates a net asset or liability for current and non-current derivative instruments for each counterparty based on the settlement dates within the respective contracts. See Note 6 - "Derivative Instruments" for additional information. |
Subsidiary Guarantees | Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Crimson Exploration Inc., Crimson Exploration Operating, Inc., Contango Energy Company, Contango Operators, Inc., Contango Mining Company, Conterra Company, Contaro Company, Contango Alta Investments, Inc., Contango Venture Capital Corporation, Contango Rocky Mountain Inc. and any other of the Company’s future subsidiaries specified in the prospectus supplement (each a “Subsidiary Guarantor”) are Co-Registrants with the Parent Company under the registration statement, and the registration statement also registered guarantees of debt securities by the Subsidiary Guarantors. The Subsidiary Guarantors are wholly-owned by the Parent Company, either directly or indirectly, and any guarantee by the Subsidiary Guarantors will be full and unconditional. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one other wholly-owned subsidiary that is inactive. Finally, the Parent Company’s wholly-owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Leases: In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02: Leases (Topic 842) (ASU 2016-02). The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP treatment of leases and that proposed in ASU 2016-02 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize a right-of-use asset and lease liability arising from such operating leases on the balance sheet. ASU 2016-02 contains several optional practical expedients, 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 has elected to apply this practical expedient package to all of its leases. The Company has also chosen to implement the “short-term accounting policy election” which allows the Company to not include leases with an initial term of 12 months or less on the balance sheet. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company adopted this standard on January 1, 2019, and the impact of adoption is immaterial. Other: In August 2016, the FASB issued ASU No. 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The main objective of this update is to reduce the diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows under Topic 230, Statement of Cash Flows, and other Topics. This update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The eight cash flow updates relate to the following issues: 1) debt prepayment or debt extinguishment costs; 2) settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; 3) contingent consideration payments made after a business combination; 4) proceeds from the settlement of insurance claims; 5) proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; 6) distributions received from equity method investees; 7) beneficial interest in securitization transactions; and 8) separately identifiable cash flows and application of the predominance principle. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The provisions of this update are not expected to have a material impact on the Company’s presentation of cash flows. In January 2017, the FASB issued ASU No. 2017-01: Business Combinations (Topic 805) Clarifying the Definition of a Business (ASU 2018-01). The amendments in this update are intended to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill and consolidation. Public business entities should apply the amendments in this update to annual periods beginning after December 15, 2018, including interim periods within those periods. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations. 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. |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Derivative Instruments [Abstract] | |
Schedule Of Derivative Contracts | The Company had the following financial derivative contracts in place as of December 31, 2018: Commodity Period Derivative Volume/Month Price/Unit (1) Fair Value Natural Gas Jan 2019 - March 2019 Swap 600,000 MMBtus $ 3.21 (1) 121 Natural Gas April 2019 - July 2019 Swap 600,000 MMBtus $ 2.75 (1) 109 Natural Gas Aug 2019 - Oct 2019 Swap 100,000 MMBtus $ 2.75 (1) 3 Natural Gas Nov 2019 - Dec 2019 Swap 500,000 MMBtus $ 2.75 (1) (116) Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) (27) Oil Jan 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) 233 Oil Jan 2019 - June 2019 Collar 12,000 Bbls $ 70.00 - 76.25 (3) 1,569 Oil Jan 2019 - July 2019 Swap 6,000 Bbls $ 66.10 (3) 811 Oil July 2019 Swap 12,000 Bbls $ 72.10 (3) 288 Oil Aug 2019 - Oct 2019 Swap 9,000 Bbls $ 72.10 (3) 635 Oil Nov 2019 - Dec 2019 Swap 12,000 Bbls $ 72.10 (3) 552 Total net fair value of derivative instruments $ 4,178 (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on Argus Louisiana Light Sweet crude oil prices. (3) Based on West Texas Intermediate crude oil prices. The Company had the following financial derivative contracts in place as of December 31, 2017: Commodity Period Derivative Volume/Month Price/Unit Fair Value Natural Gas Jan 2018 - July 2018 Swap 370,000 MMBtus $ 3.07 (1) 678 Natural Gas Aug 2018 - Oct 2018 Swap 70,000 MMBtus $ 3.07 (1) 56 Natural Gas Nov 2018 - Dec 2018 Swap 320,000 MMBtus $ 3.07 (1) 89 Oil Jan 2018 - June 2018 Swap 20,000 Bbls $ 56.40 (2) (994) Oil July 2018 - Oct 2018 Collar 20,000 Bbls $ 52.00 - 56.85 (2) (544) Oil Nov 2018 - Dec 2018 Collar 15,000 Bbls $ 52.00 - 56.85 (2) (173) Oil Jan 2018 - Dec 2018 Collar 2,000 Bbls $ 52.00 - 58.76 (3) (55) Oil Jan 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) (300) Total net fair value of derivative instruments $ (1,243) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on Argus Louisiana Light Sweet crude oil prices. 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 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 summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2017 (in thousands): Gross Netting (1) Total Assets $ 1,188 $ (1,188) $ — Liabilities $ (2,431) $ 1,188 $ (1,243) (1) Represents counterparty netting under agreements governing such derivatives. |
Schedule Of Derivative Contracts On Operations | The following table summarizes the effect of derivative contracts on the Consolidated Statements of Operations for the years ended December 31, 2018 and 2017 (in thousands): Year Ended December 31, Contract Type 2018 2017 Crude oil contracts $ (2,969) $ 861 Natural gas contracts (513) 260 Realized gain (loss) $ (3,482) $ 1,121 Crude oil contracts $ 6,126 $ (2,065) Natural gas contracts (705) 4,269 Unrealized gain $ 5,421 $ 2,204 Gain on derivatives, net $ 1,939 $ 3,325 |
Stock Based Compensation (Table
Stock Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Stock-Based Compensation [Abstract] | |
Summary Of Stock Options Granted | A summary of stock options as of and for the years ended December 31, 2018 and 2017 is presented in the table below (dollars in thousands, except per share data): Year Ended December 31, 2018 2017 Weighted Weighted Shares Average Shares Average Under Exercise Under Exercise Options Price Options Price Outstanding, beginning of the period 94,833 $ 57.69 111,905 $ 55.53 Exercised — $ — — $ — Expired / Forfeited (61,196) $ 58.72 (17,072) $ 43.50 Outstanding, end of year 33,637 $ 55.82 94,833 $ 57.69 Aggregate intrinsic value $ — $ — Exercisable, end of year 33,637 $ 55.82 94,833 $ 57.69 Aggregate intrinsic value $ — $ — Available for grant, end of the period * 1,854,588 2,002,492 Weighted average fair value of options granted during the period $ — $ — * Excludes Performance Stock Units. During the years ended December 31, 2018 and 2017, the Company did not issue any stock options. During the year ended December 31, 2018, 61,196 stock options previously issued were forfeited by former employees, of which 55,943 were related to the resignation of the Company’s former President and CEO in September 2018. During the year ended December 31, 2017, 17,072 stock options previously issued were forfeited. As of December 31, 2018, there were 33,637 stock options vested and exercisable under the 2005 Plan. The exercise price for such options ranges from $28.96 to $60.33 per share, with an average remaining contractual life of two years. |
Summary Of Restricted Stock Activity | Restricted stock activity as of December 31, 2018 and 2017 and for the years then ended is presented in the table below (dollars in thousands, except per share data): 2018 2017 Weighted Aggregate Weighted Aggregate Restricted Average Intrinsic Restricted Average Intrinsic Shares Fair Value Value Shares Fair Value Value Outstanding, beginning of the period 731,073 $ 10.55 $ 1,667 638,158 $ 14.22 $ 5,960 Granted 308,282 3.76 1,158 457,701 7.55 3,457 Vested (419,356) 10.72 1,965 (222,568) 15.12 1,263 Canceled / Forfeited (160,378) 6.49 309 (142,218) 10.23 814 Not vested, end of the period 459,621 7.26 662 731,073 10.55 1,667 |
Other Financial Information (Ta
Other Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Other Financial Information [Abstract] | |
Schedule Of Additional Financial Details | The following table provides additional detail for accounts receivable, prepaids, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): December 31, December 31, 2018 2017 Accounts receivable: Trade receivables $ 6,052 $ 6,565 Receivable for Alta Resources distribution 1,993 1,993 Joint interest billings 3,833 4,030 Income taxes receivable 424 424 Other receivables 223 828 Allowance for doubtful accounts (994) (781) Total accounts receivable $ 11,531 $ 13,059 Prepaid expenses and other: Prepaid insurance $ 792 $ 1,177 Other 511 715 Total prepaid expenses and other $ 1,303 $ 1,892 Accounts payable and accrued liabilities: Royalties and revenue payable $ 17,986 $ 18,181 Advances from partners 1,785 2,243 Accrued exploration and development 4,751 8,400 Accrued acquisition costs 4,352 — Trade payables 3,385 9,559 Accrued general and administrative expenses 2,545 2,960 Accrued operating expenses 1,801 1,654 Other accounts payable and accrued liabilities 2,901 3,758 Total accounts payable and accrued liabilities $ 39,506 $ 46,755 |
Schedule Of Supplemental Disclosures | Included in the table below is supplemental cash flow disclosures and non-cash investing activities during the years ended December 31, 2018 and 2017, in thousands: Year Ended December 31, 2018 2017 Cash payments: Interest payments $ 5,656 $ 3,699 Income tax payments, net of cash refunds 81 616 Non-cash items excluded from investing activities in the consolidated statements of cash flows: Decrease in accrued capital expenditures (3,649) (9,931) |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Change in Asset Retirement Obligation | Activities related to the Company’s ARO during the years ended December 31, 2018 and 2017 were as follows (in thousands): Year Ended December 31, 2018 2017 Balance as of the beginning of the period $ 22,405 $ 26,926 Liabilities incurred during period 163 308 Liabilities settled during period (1,339) (4,503) Accretion 960 1,056 Sales (8,599) (2,949) Change in estimate (93) 1,567 Balance as of the end of the period $ 13,497 $ 22,405 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Commitments And Contingencies [Abstract] | |
Schedule of Minimum Future Lease Operating Leases | As of December 31, 2018, minimum future lease payments for delay rentals and operating leases for Contango’s fiscal years are as follows (in thousands): Fiscal years ending December 31, 2019 $ 958 2020 265 2021 179 2022 70 2023 69 2024 and thereafter 69 Total $ 1,610 |
Net Loss Per Common Share (Tabl
Net Loss Per Common Share (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Net Loss Per Common Share | |
Components Of Basic And Diluted Net Loss Per Share Of Common Stock | Year Ended December 31, 2018 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (121,568) 25,945 $ (4.69) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (121,568) 25,945 $ (4.69) Year Ended December 31, 2017 Net Loss Shares Per Share Basic Earnings per Share: Net loss attributable to common stock $ (17,643) 24,686 $ (0.71) Diluted Earnings per Share: Effect of potential dilutive securities: Weighted average of incremental shares (stock options, restricted stock and PSUs) — — — Net loss attributable to common stock $ (17,643) 24,686 $ (0.71) |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Income Taxes [Abstract] | |
Schedule Of Effective Income Tax Rate Reconciliation | Actual income tax expense differs from income tax expense computed by applying the U.S. federal statutory corporate rate of 21 percent and 35 percent for the years ended December 31, 2018 and 2017, respectively, to pretax income as follows (dollars in thousands): Year Ended December 31, 2018 2017 Provision/(benefit) at statutory tax rate $ (25,504) 21.00 % $ (6,314) 35.00 % State income tax provision, net of federal benefit 120 (0.10) % (864) 4.79 % Permanent differences 579 (0.48) % 50 (0.28) % Stock based compensation 1,353 (1.11) % (361) 2.00 % Valuation allowance 21,941 (18.07) % 7,209 (39.96) % Rate change (35% to 21% fed rate) % 35,250 (195.41) % Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act % (35,674) 197.76 % Other 1,631 (1.34) % 309 (1.71) % Income tax provision /(benefit) $ 120 (0.10) % $ (395) 2.19 % |
Components Of Income Tax Expense (Benefit) | The provision (benefit) for income taxes for the periods indicated are comprised of the following (in thousands): Year Ended December 31, 2018 2017 Current tax provision (benefit): Federal $ — $ (424) State 120 453 Total $ 120 $ 29 Deferred tax provision (benefit): Federal $ — $ (424) State — — Total $ — $ (424) Total tax provision (benefit): Federal $ — $ (848) State 120 453 Total $ 120 $ (395) Included in gain (loss) from investment in affiliates $ — $ — Total income tax provision (benefit) $ 120 $ (395) |
Schedule Of Net Deferred Tax Liability | The net deferred tax is comprised of the following (in thousands): December 31, 2018 2017 Deferred tax assets: Net operating loss carryforward $ 80,930 $ 60,464 Income tax credits 454 454 Derivative instruments — 261 Deferred compensation 678 1,418 Oil and gas properties — — Other 1,529 491 Total deferred tax assets before valuation allowance $ 83,591 $ 63,088 Valuation allowance (70,973) (49,032) Net deferred tax assets $ 12,618 $ 14,056 Deferred tax liability: Oil and gas properties $ (11,042) $ (10,567) Investment in affiliates (275) (3,065) Derivative instruments (877) — Deferred tax liability $ (12,194) $ (13,632) Total net deferred tax $ 424 $ 424 |
Schedule Of Unrecognized Tax Benefits | A reconciliation of the beginning and ending amount of unrecognized income tax benefits is as follows (in thousands): Unrecognized Tax Benefits Balance at December 31, 2017 $ 227 Additions based on tax positions related to the current year — Additions based on tax positions related to prior years — Additions due to acquisitions — Reductions due to a lapse of the applicable statute of limitations — Change in rate due to remeasurement — Balance at December 31, 2018 $ 227 |
Organization and Business (Deta
Organization and Business (Details) $ in Millions | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2018USD ($)a | Jul. 31, 2016USD ($) | Dec. 31, 2018USD ($)aitem | Dec. 31, 2016USD ($) | |
Colorado Assets [Member] | ||||
Organization and Business | ||||
Asset sale price | $ 5 | |||
Eagle Ford Shale Assets, Karnes County, Texas [Member] | ||||
Organization and Business | ||||
Asset sale price | $ 21 | $ 21 | ||
Gulf Coast Conventional Assets in Southeast Texas [Member] | ||||
Organization and Business | ||||
Asset sale price | 6 | 6 | ||
Gulf Coast Conventional And Unconventional Assets in South Texas [Member] | ||||
Organization and Business | ||||
Asset sale price | $ 0.9 | $ 0.9 | ||
Bullseye | ||||
Organization and Business | ||||
Gross acres | a | 15,400 | 15,400 | ||
Net acres | a | 6,500 | 6,500 | ||
Number of wells | item | 12 | |||
Cash consideration for acquisition | $ 10 | |||
NE Bullseye | ||||
Organization and Business | ||||
Gross acres - operated | a | 4,200 | 4,200 | ||
Net acres - operated | a | 1,700 | 1,700 | ||
Gross non-operated acres | a | 4,000 | 4,000 | ||
Net non-operated acres | a | 200 | 200 | ||
Estimated consideration | $ 7.5 | |||
Cash consideration for acquisition | $ 3.2 | |||
Exaro Energy III LLC [Member] | ||||
Organization and Business | ||||
Equity method investment, ownership percentage | 37.00% | 37.00% |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018USD ($)item | Dec. 31, 2017USD ($) | |
Significant Accounting Policies [Line Items] | ||
Cash and cash equivalents | $ 0 | |
Outstanding checks in accounts payable that have not yet been presented for payment | 4,800 | $ 2,300 |
Allowance for doubtful accounts receivable | $ 1,000 | $ 800 |
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 | |
Property and equipment depreciation, estimated useful life | 3 years | |
Maximum [Member] | ||
Significant Accounting Policies [Line Items] | ||
Period settlement statements are received | 90 days | |
Property and equipment depreciation, estimated useful life | 13 years | |
Exaro Energy III LLC [Member] | ||
Significant Accounting Policies [Line Items] | ||
Number of seats on Board of Directors | item | 2 | |
Equity method investment, ownership percentage | 37.00% |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Impairment and Debt (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||
May 31, 2016USD ($) | Oct. 31, 2013USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2018USD ($)item | Dec. 31, 2017USD ($)item | Dec. 31, 2013USD ($) | |
Policies | ||||||
Impairment of natural gas and oil properties | $ 103,164 | $ 1,785 | ||||
Number of subsidiaries inactive and not Subsidiary Guarantor | item | 1 | |||||
Restricted assets, percent of net assets | 25.00% | |||||
RBC Credit Facility [Member] | ||||||
Policies | ||||||
Debt issuance costs incurred | $ 1,000 | $ 2,200 | $ 2,200 | |||
Original term of credit line | 4 years | 4 years | ||||
Remaining balance debt issue costs | $ 400 | |||||
Proved property [Member] | ||||||
Policies | ||||||
Impairment of natural gas and oil properties | 101,900 | 300 | ||||
Proved property [Member] | Gulf of Mexico Properties [Member] | ||||||
Policies | ||||||
Impairment of natural gas and oil properties | $ 61,700 | |||||
Proved property [Member] | South and Southeast Texas [Member] | ||||||
Policies | ||||||
Impairment of natural gas and oil properties | 24,900 | |||||
Proved property [Member] | Wyoming And South Texas [Member] | ||||||
Policies | ||||||
Impairment of natural gas and oil properties | 15,300 | |||||
Proved property [Member] | Onshore Properties [Member] | ||||||
Policies | ||||||
Impairment of natural gas and oil properties | 40,200 | |||||
Unproved property [Member] | ||||||
Policies | ||||||
Impairment of natural gas and oil properties | $ 1,300 | $ 1,500 | ||||
Number of platforms | item | 2 |
Concentration of Credit Risk (D
Concentration of Credit Risk (Details) - Sales Revenue, Goods, Net [Member] - Customer Concentration Risk [Member] | 12 Months Ended |
Dec. 31, 2018 | |
Concentration Risk [Line Items] | |
Number of months of potential revenue loss | 2 months |
ConocoPhillips Company [Member] | |
Concentration Risk [Line Items] | |
Concentration risk, percentage | 36.90% |
Acquisitions and Dispositions -
Acquisitions and Dispositions - Acquisitions (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |
Dec. 31, 2018USD ($)a | Jul. 31, 2016USD ($)aitem | Dec. 31, 2018USD ($)aitem | |
Bullseye | |||
Acquisition | |||
Gross acres - Undeveloped | a | 12,100 | ||
Net acres - Undeveloped | a | 5,000 | ||
Cash consideration for acquisition | $ 10 | ||
Carried well cost | 10 | ||
Number of wells | item | 12 | ||
Carried cost payments | $ 10 | ||
Spud bonus | $ 3.7 | $ 3.7 | |
Bullseye | Maximum [Member] | |||
Acquisition | |||
Estimated consideration | $ 25 | ||
NE Bullseye | |||
Acquisition | |||
Gross acres - operated | a | 4,200 | 4,200 | |
Net acres - operated | a | 1,700 | 1,700 | |
Gross non-operated acres | a | 4,000 | 4,000 | |
Net non-operated acres | a | 200 | 200 | |
Estimated consideration | $ 7.5 | ||
Cash consideration for acquisition | $ 3.2 | ||
Phase One [Member] | Bullseye | |||
Acquisition | |||
Number of wells | item | 6 | ||
Phase Two [Member] | Bullseye | |||
Acquisition | |||
Number of wells | item | 14 | ||
Spud bonus | $ 5 |
Acquisitions and Dispositions_2
Acquisitions and Dispositions - Dispositions (Details) - USD ($) | Dec. 31, 2018 | Dec. 04, 2018 | May 25, 2018 | Mar. 28, 2018 | Feb. 01, 2017 | Sep. 30, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Nov. 02, 2018 |
Disposals | |||||||||
Impairment of natural gas and oil properties | $ 103,164,000 | $ 1,785,000 | |||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Liberty and Hardin County, TX Assets [Member] | |||||||||
Disposals | |||||||||
Impairment of natural gas and oil properties | $ 12,800,000 | ||||||||
Cash purchase price | $ 6,000,000 | ||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Starr County, TX Assets [Member] | |||||||||
Disposals | |||||||||
Cash purchase price | $ 600,000 | ||||||||
Gain (loss) on sale of oil and gas property | $ 1,300,000 | ||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Karnes County, TX Assets [Member] | |||||||||
Disposals | |||||||||
Cash purchase price | $ 21,000,000 | ||||||||
Gain (loss) on sale of oil and gas property | $ 9,500,000 | ||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Bob West North and Escobas Assets [Member] | |||||||||
Disposals | |||||||||
Cash purchase price | $ 650,000 | ||||||||
Gain (loss) on sale of oil and gas property | $ 2,900,000 | ||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Elm Hill Country Texas Assets Member | |||||||||
Disposals | |||||||||
Cash purchase price | $ 85,000 | ||||||||
Gain (loss) on sale of oil and gas property | $ 175,000 | ||||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Brooks and Zapata County Texas Assets Member | |||||||||
Disposals | |||||||||
Impairment of natural gas and oil properties | $ 12,100,000 | ||||||||
Cash purchase price | $ 150,000 | $ 150,000 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) | 12 Months Ended |
Dec. 31, 2018 | |
RBC Credit Facility [Member] | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |
Maximum period of interest rate on floating-rate debt | 3 months |
Derivative Instruments (Derivat
Derivative Instruments (Derivative Contracts) (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018USD ($)item$ / Mcf$ / bbl | Dec. 31, 2017USD ($)item$ / Mcf$ / bbl | |
Derivative [Line Items] | ||
Fair Value | $ 4,178 | $ (1,243) |
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January To March 2019[Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 121 | |
Commodity Derivative Flow Rate | item | 600,000 | |
Price/Unit-Swap | $ / Mcf | 3.21 | |
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April To July 2019 [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 109 | |
Commodity Derivative Flow Rate | item | 600,000 | |
Price/Unit-Swap | $ / Mcf | 2.75 | |
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August To October 2019[Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 3 | |
Commodity Derivative Flow Rate | item | 100,000 | |
Price/Unit-Swap | $ / Mcf | 2.75 | |
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November To December 2019[Member] | ||
Derivative [Line Items] | ||
Fair Value | $ (116) | |
Commodity Derivative Flow Rate | item | 500,000 | |
Price/Unit-Swap | $ / Mcf | 2.75 | |
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January To July 2018 Member | ||
Derivative [Line Items] | ||
Fair Value | $ 678 | |
Commodity Derivative Flow Rate | item | 370,000 | |
Price/Unit-Swap | $ / Mcf | 3.07 | |
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August To October 2018 Member | ||
Derivative [Line Items] | ||
Fair Value | $ 56 | |
Commodity Derivative Flow Rate | item | 70,000 | |
Price/Unit-Swap | $ / Mcf | 3.07 | |
Natural Gas [Member] | Swap [Member] | Derivative Contract Period1, November To December 2018 [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 89 | |
Commodity Derivative Flow Rate | item | 320,000 | |
Price/Unit-Swap | $ / Mcf | 3.07 | |
Oil [Member] | Swap [Member] | Derivative Contract Period August To October 2019[Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 635 | |
Commodity Derivative Flow Rate | item | 9,000 | |
Price/Unit-Swap | $ / bbl | 72.10 | |
Oil [Member] | Swap [Member] | Derivative Contract Period November To December 2019[Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 552 | |
Commodity Derivative Flow Rate | item | 12,000 | |
Price/Unit-Swap | $ / bbl | 72.10 | |
Oil [Member] | Swap [Member] | Derivative Contract Period January To July 2019 [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 811 | |
Commodity Derivative Flow Rate | item | 6,000 | |
Price/Unit-Swap | $ / bbl | 66.10 | |
Oil [Member] | Swap [Member] | Derivative Contract Period July 2019[Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 288 | |
Commodity Derivative Flow Rate | item | 12,000 | |
Price/Unit-Swap | $ / bbl | 72.10 | |
Oil [Member] | Swap [Member] | Derivative Contract Period January To June 2018 Member | ||
Derivative [Line Items] | ||
Fair Value | $ (994) | |
Commodity Derivative Flow Rate | item | 20,000 | |
Price/Unit-Swap | $ / bbl | 56.40 | |
Oil [Member] | Collar Options [Member] | Derivative Contract Period1, January to December 2019 [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ (27) | |
Commodity Derivative Flow Rate | item | 7,000 | |
Price/Unit-Floor | $ / bbl | 50 | |
Price/Unit-Cap | $ / bbl | 58 | |
Oil [Member] | Collar Options [Member] | Derivative Contract Period2, January to December 2019 [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 233 | |
Commodity Derivative Flow Rate | item | 4,000 | |
Price/Unit-Floor | $ / bbl | 52 | |
Price/Unit-Cap | $ / bbl | 59.45 | |
Oil [Member] | Collar Options [Member] | Derivative Contract Period January To June 2019[Member] | ||
Derivative [Line Items] | ||
Fair Value | $ 1,569 | |
Commodity Derivative Flow Rate | item | 12,000 | |
Price/Unit-Floor | $ / bbl | 70 | |
Price/Unit-Cap | $ / bbl | 76.25 | |
Oil [Member] | Collar Options [Member] | Derivative Contract Period1, November To December 2018 [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ (173) | |
Commodity Derivative Flow Rate | item | 15,000 | |
Price/Unit-Floor | $ / bbl | 52 | |
Price/Unit-Cap | $ / bbl | 56.85 | |
Oil [Member] | Collar Options [Member] | Derivative Contract Period July To October 2018 Member | ||
Derivative [Line Items] | ||
Fair Value | $ (544) | |
Commodity Derivative Flow Rate | item | 20,000 | |
Price/Unit-Floor | $ / bbl | 52 | |
Price/Unit-Cap | $ / bbl | 56.85 | |
Oil [Member] | Collar Options [Member] | Derivative Contract Period January To December 2018 | ||
Derivative [Line Items] | ||
Fair Value | $ (55) | |
Commodity Derivative Flow Rate | item | 2,000 | |
Price/Unit-Floor | $ / bbl | 52 | |
Price/Unit-Cap | $ / bbl | 58.76 | |
Oil [Member] | Collar Options [Member] | Derivative Contract Period, January to December 2019 [Member] | ||
Derivative [Line Items] | ||
Fair Value | $ (300) | |
Commodity Derivative Flow Rate | item | 7,000 | |
Price/Unit-Floor | $ / bbl | 50 | |
Price/Unit-Cap | $ / bbl | 58 |
Derivative Instruments (Fair Va
Derivative Instruments (Fair Value) (Details) - Commodity Derivatives [Member] - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Assets | ||
Gross | $ 4,600 | $ 1,188 |
Netting | (1,188) | |
Total | 4,600 | |
Liabilities: | ||
Gross | (422) | (2,431) |
Netting | 1,188 | |
Total | $ (422) | $ (1,243) |
Derivative Instruments (Operati
Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized gain (loss) | $ (3,482) | $ 1,121 |
Unrealized gain (loss) | 5,421 | 2,204 |
Gain (loss) on derivatives, net | 1,939 | 3,325 |
Oil [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized gain (loss) | (2,969) | 861 |
Unrealized gain (loss) | 6,126 | (2,065) |
Natural Gas [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized gain (loss) | (513) | 260 |
Unrealized gain (loss) | $ (705) | $ 4,269 |
Stock Based Compensation (Narra
Stock Based Compensation (Narrative) (Details) - shares | Mar. 21, 2017 | Dec. 31, 2018 | Dec. 31, 2017 | Feb. 25, 2015 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares available for grant | 1,854,588 | 2,002,492 | ||
Performance Stock Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 3 years | |||
Performance Stock Units [Member] | Minimum [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Target (as a percent) | 0.00% | |||
Performance Stock Units [Member] | Maximum [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Target (as a percent) | 300.00% | |||
Second Amended 2009 Equity Compensation Plan | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares available for grant | 1,600,000 | |||
Second Amended 2009 Equity Compensation Plan | Maximum [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Vesting period | 4 years | |||
Second Amended 2009 Equity Compensation Plan | Employee Stock Options [Member] | Minimum [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Expiration term | 5 years | |||
Second Amended 2009 Equity Compensation Plan | Employee Stock Options [Member] | Maximum [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Expiration term | 10 years | |||
Second Amended 2009 Equity Compensation Plan | Performance Stock Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Target (as a percent) | 100.00% | |||
Stock Incentive Plan 2005 [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Shares available for grant | 0 |
Stock Based Compensation (Optio
Stock Based Compensation (Options) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Option roll forward | ||
Outstanding, beginning of year (in shares) | 94,833 | 111,905 |
Expired / Forfeited (in shares) | (61,196) | (17,072) |
Outstanding, end of year (in shares) | 33,637 | 94,833 |
Exercisable, end of year (in shares) | 33,637 | 94,833 |
Option roll forward per share | ||
Outstanding, beginning of year (in dollars per share) | $ 57.69 | $ 55.53 |
Expired / Forfeited (in dollars per share) | 58.72 | 43.50 |
Outstanding, end of year (in dollars per share) | 55.82 | 57.69 |
Exercisable, end of year (in dollars per share) | $ 55.82 | $ 57.69 |
Stock-based compensation | ||
Excess tax benefit from exercise/cancellation of stock options | $ 0 | $ 0 |
Aggregate intrinsic value of exercises during period | $ 0 | $ 0 |
Employee Stock Options [Member] | ||
Stock-based compensation | ||
Options exercise price, minimum (in dollars per share) | $ 28.96 | |
Options exercise price, maximum (in dollars per share) | $ 60.33 | |
Granted vested options, remaining contractual term | 2 years | |
Employee Stock Options [Member] | Former President and CEO | ||
Option roll forward | ||
Expired / Forfeited (in shares) | (55,943) |
Stock Based Compensation (NonOp
Stock Based Compensation (NonOption) (Details) $ / shares in Units, $ in Thousands | 1 Months Ended | 12 Months Ended | |
Sep. 30, 2018shares | Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)$ / sharesshares | |
Restricted Stock [Member] | |||
Activity, shares | |||
Outstanding, beginning of the period (in shares) | 731,073 | 638,158 | |
Granted (in shares) | 308,282 | 457,701 | |
Vested (in shares) | (419,356) | (222,568) | |
Canceled/Forfeited (in shares) | (160,378) | (142,218) | |
Not vested, end of the period (in shares) | 459,621 | 731,073 | |
Activity, weighted average fair value | |||
Outstanding, beginning of the period (in dollars per share) | $ / shares | $ 10.55 | $ 14.22 | |
Granted (in dollars per share) | $ / shares | 3.76 | 7.55 | |
Vested (in dollars per share) | $ / shares | 10.72 | 15.12 | |
Canceled/Forfeited (in dollars per share) | $ / shares | 6.49 | 10.23 | |
Not vested, end of the period (in dollars per share) | $ / shares | $ 7.26 | $ 10.55 | |
Activity, intrinsic value | |||
Outstanding, beginning of the period | $ | $ 1,667 | $ 5,960 | |
Granted | $ | 1,158 | 3,457 | |
Vested | $ | 1,965 | 1,263 | |
Canceled/Forfeited | $ | 309 | 814 | |
Not vested, end of the period | $ | 662 | 1,667 | |
Stock-based compensation | |||
Stock-based compensation expense | $ | 4,800 | 6,100 | |
Compensation expense not yet recognized | $ | 1,900 | ||
Value of issued stock | $ | $ 1,200 | $ 3,500 | |
Weighted average forfeiture rate | 0 | 4.8 | |
Performance Stock Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Activity, shares | |||
Canceled/Forfeited (in shares) | (147,800) | ||
Executive Officer [Member] | Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Activity, shares | |||
Granted (in shares) | 225,782 | ||
Executive Officer [Member] | Performance Stock Units [Member] | |||
Activity, shares | |||
Granted (in shares) | 190,782 | 160,908 | |
Activity, weighted average fair value | |||
Granted (in dollars per share) | $ / shares | $ 7.69 | $ 13.91 | |
New Employees [Member] | Performance Stock Units [Member] | |||
Activity, shares | |||
Granted (in shares) | 30,000 | ||
Activity, weighted average fair value | |||
Granted (in dollars per share) | $ / shares | $ 8.32 | ||
New And Existing Employees [Member] | Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Activity, shares | |||
Granted (in shares) | 383,376 | ||
Board of Directors [Member] | Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 1 year | 1 year | |
Activity, shares | |||
Granted (in shares) | 82,500 | 74,325 | |
Former Employee [Member] | Restricted Stock [Member] | |||
Activity, shares | |||
Canceled/Forfeited (in shares) | (160,378) | (142,218) | |
Former Employee [Member] | Performance Stock Units [Member] | |||
Activity, shares | |||
Canceled/Forfeited (in shares) | (188,927) | (99,363) | |
Former President and CEO | Restricted Stock [Member] | |||
Activity, shares | |||
Vested (in shares) | (102,573) | ||
Canceled/Forfeited (in shares) | (105,800) | ||
Former President and CEO | Performance Stock Units [Member] | |||
Activity, shares | |||
Canceled/Forfeited (in shares) | (153,127) | ||
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% |
Share Repurchase Programs (Deta
Share Repurchase Programs (Details) - $50 Million Share Repurchase Program [Member] - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2011 | |
Equity, Class of Treasury Stock [Line Items] | |||
Approved share repurchase program value | $ 50 | ||
Treasury shares at cost (in shares) | 0 | 0 | |
Value of repurchase program available for future purchases | $ 31.8 |
Other Financial Information (Ba
Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts receivable: | ||
Trade receivables | $ 6,052 | $ 6,565 |
Receivable for Alta Resources Distribution | 1,993 | 1,993 |
Joint interest billings | 3,833 | 4,030 |
Income taxes receivable | 424 | 424 |
Other receivables | 223 | 828 |
Allowance for doubtful accounts | (994) | (781) |
Total accounts receivable | 11,531 | 13,059 |
Prepaid expenses and other: | ||
Prepaid insurance | 792 | 1,177 |
Other | 511 | 715 |
Total prepaid expenses and other | 1,303 | 1,892 |
Accounts payable and accrued liabilities: | ||
Royalties and revenue payable | 17,986 | 18,181 |
Advances from partners | 1,785 | 2,243 |
Accrued exploration and development | 4,751 | 8,400 |
Accrued acquisition costs | 4,352 | |
Trade payables | 3,385 | 9,559 |
Accrued general and administrative expenses | 2,545 | 2,960 |
Accrued operating expenses | 1,801 | 1,654 |
Other accounts payable and accrued liabilities | 2,901 | 3,758 |
Total accounts payable and accrued liabilities | $ 39,506 | $ 46,755 |
Other Financial Information (Su
Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Cash payments: | ||
Interest payments | $ 5,656 | $ 3,699 |
Income tax payments (refunds), net of cash refunds | 81 | 616 |
Non-cash investing activities in the consolidated statements of cash flows: | ||
Increase (decrease) in accrued capital expenditures | $ (3,649) | $ (9,931) |
Investment in Exaro Energy II_2
Investment in Exaro Energy III LLC (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Schedule of Equity Method Investments Financials | ||
Gain (loss) from investment in affiliates, net of income taxes | $ (12,721) | $ 2,697 |
Exaro Energy III LLC [Member] | ||
Schedule of Equity Method Investments Financials | ||
Investment in affiliate | $ 46,900 | |
Equity method investment, ownership percentage | 37.00% | |
Total Investment Commitment In Affiliates With Other Parties | $ 183,000 | |
Share of equity in investment | 5,700 | |
Gain (loss) from investment in affiliates, net of income taxes | (12,600) | 2,700 |
Tax (expense) benefit from equity investment | 0 | $ 0 |
Exaro Energy III LLC [Member] | Maximum [Member] | ||
Schedule of Equity Method Investments Financials | ||
Investment in affiliate | $ 67,500 |
Asset Retirement Obligation (De
Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation [Abstract] | ||
Balance as of the beginning of the period | $ 22,405 | $ 26,926 |
Liabilities incurred during period | 163 | 308 |
Liabilities settled during period | (1,339) | (4,503) |
Accretion | 960 | 1,056 |
Sales | (8,599) | (2,949) |
Change in estimate | (93) | 1,567 |
Balance as of the end of the period | $ 13,497 | $ 22,405 |
Indebtedness (Details)
Indebtedness (Details) $ in Thousands | Nov. 02, 2018USD ($) | May 31, 2016USD ($) | Oct. 31, 2013USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2013USD ($) | Jan. 31, 2019USD ($) | Nov. 01, 2018USD ($) |
Debt Instrument [Line Items] | ||||||||
Interest expense | $ 5,548 | $ 4,100 | ||||||
RBC Credit Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maximum borrowing capacity | $ 500,000 | |||||||
Original term of credit line | 4 years | 4 years | ||||||
Revolving credit facility, borrowing base | $ 105,000 | $ 90,000 | ||||||
Commitment fee percentage | 0.50% | |||||||
Remaining balance debt issue costs | $ 400 | |||||||
Debt issuance costs incurred | $ 1,000 | $ 2,200 | $ 2,200 | |||||
Current ratio | 1 | 1 | ||||||
Financial statements delivery period | 25 days | |||||||
Credit facility amount outstanding | 60,000 | 85,400 | ||||||
Letters of credit amount outstanding | 1,900 | 1,900 | ||||||
Line of credit, available | 43,100 | |||||||
Interest expense | $ 5,500 | $ 4,100 | ||||||
Leverage ratio | 3.50 | |||||||
RBC Credit Facility [Member] | Minimum [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Variable interest rate (as a percent) | 2.50% | |||||||
RBC Credit Facility [Member] | Maximum [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Variable interest rate (as a percent) | 4.00% | |||||||
Letter of Credit [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maximum borrowing capacity | $ 5,000 | $ 20,000 |
Commitments and Contingencies_2
Commitments and Contingencies (Leases) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Delay Rentals and Operating and Capital Leases [Abstract] | ||
2019 | $ 958 | |
2020 | 265 | |
2021 | 179 | |
2022 | 70 | |
2023 | 69 | |
2024 and thereafter | 69 | |
Total | 1,610 | |
Lease commitment | $ 5,100 | $ 4,800 |
Commitments and Contingencies_3
Commitments and Contingencies (Narrative) (Details) | Sep. 14, 2012USD ($) | Nov. 16, 2010USD ($)item | Nov. 30, 2016USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
Employment Agreements | ||||||
Employment agreement, extension term | 1 year | |||||
Chief Executive Officer [Member] | ||||||
Employment Agreements | ||||||
Employment agreement, initial term | 3 years | |||||
Base salary under employment agreement | $ 600,000 | |||||
Cash bonus awards based on % of salary | 100.00% | |||||
Chief Financial Officer [Member] | ||||||
Employment Agreements | ||||||
Employment agreement, initial term | 3 years | |||||
Base salary under employment agreement | $ 400,000 | |||||
Cash bonus awards based on % of salary | 100.00% | |||||
VP, Mengle | ||||||
Employment Agreements | ||||||
Employment agreement, initial term | 2 years | |||||
Base salary under employment agreement | $ 300,000 | |||||
Cash bonus awards based on % of salary | 80.00% | |||||
VP, Atkins | ||||||
Employment Agreements | ||||||
Employment agreement, initial term | 2 years | |||||
Base salary under employment agreement | $ 310,000 | |||||
Cash bonus awards based on % of salary | 80.00% | |||||
Lavaca County Case [Member] | ||||||
Legal Proceedings | ||||||
Number of wells involved in litigation | item | 2 | |||||
Settlement awarded against Contango | $ 5,300,000 | |||||
Litigation Case Filed by Mineral Interest Owner Harris County [Member] | ||||||
Legal Proceedings | ||||||
Additional portion of mineral interest claimed by plaintiff | 0.0625% | |||||
Damages sought by plaintiffs | $ 10,700,000 | |||||
Throughput commitment | ||||||
Loss Contingency | ||||||
Fees incurred | $ 1,000,000 | $ 1,100,000 | $ 400,000 | |||
Estimated annual loss | 1,000,000 | |||||
Loss contingency provision accrual | 1,700,000 | |||||
Estimated deficiency | $ 240,000 |
Net Loss Per Common Share (Deta
Net Loss Per Common Share (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Net Loss Per Common Share | ||
Net loss attributable to common stock | $ (121,568) | $ (17,643) |
Net loss attributable to common stock | $ (121,568) | $ (17,643) |
Weighted average shares, basic (in shares) | 25,945,000 | 24,686,000 |
Diluted (in shares) | 25,945,000 | 24,686,000 |
Basic (in dollars per share) | $ (4.69) | $ (0.71) |
Diluted (in dollars per share) | $ (4.69) | $ (0.71) |
Potentially dilutive (in shares) | 1,141,707 | 1,282,590 |
Income Taxes (Tax Rate Reconcil
Income Taxes (Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Income Taxes [Abstract] | ||
Provision/(benefit) at statutory tax rate | 21.00% | 35.00% |
Interest limitation carryforward | $ 5,500 | |
Effective Income Tax Rate Reconciliation, Amount [Abstract] | ||
Provision/(benefit) at statutory tax rate | (25,504) | $ (6,314) |
State income tax provision, net of federal benefit | 120 | (864) |
Permanent differences | 579 | 50 |
Stock based compensation | 1,353 | (361) |
Valuation allowance | 21,941 | 7,209 |
Rate Change (35% to 21% fed rate) | 0 | 35,250 |
Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act | 0 | (35,674) |
Other | 1,631 | 309 |
Total | $ 120 | $ (395) |
Effective Income Tax Rate Reconciliation, Percent [Abstract] | ||
State income tax provision, net of federal benefit | (0.10%) | 4.79% |
Permanent differences | (0.48%) | (0.28%) |
Stock based compensation | (1.11%) | 2.00% |
Valuation allowance | (18.07%) | (39.96%) |
Rate Change (35% to 21% fed rate) | 0.00% | (195.41%) |
Valuation allowance for remeasurement and changes relating to the Tax Cuts and Jobs Act | 0.00% | 197.76% |
Other | (1.34%) | (1.71%) |
Income tax provision /(benefit) | (0.10%) | 2.19% |
Income Taxes (Expense Benefit)
Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Current tax provision (benefit): | ||
Federal | $ (424) | |
State | $ 120 | 453 |
Total | 120 | 29 |
Deferred tax provision (benefit): | ||
Federal | (424) | |
Total | (424) | |
Total tax provision (benefit): | ||
Federal | (848) | |
State | 120 | 453 |
Total | 120 | (395) |
Income tax provision (benefit) | $ 120 | $ (395) |
Income Taxes (Deferred Tax) (De
Income Taxes (Deferred Tax) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Deferred tax assets: | ||
Net operating loss carryforward | $ 80,930 | $ 60,464 |
Income tax credits | 454 | 454 |
Derivative instruments | 261 | |
Deferred compensation | 678 | 1,418 |
Other | 1,529 | 491 |
Total deferred tax assets before valuation allowance | 83,591 | 63,088 |
Valuation allowance | (70,973) | (49,032) |
Net deferred tax assets | 12,618 | 14,056 |
Deferred tax liability: | ||
Oil and gas properties | (11,042) | (10,567) |
Investment in affiliates | (275) | (3,065) |
Derivative instruments | (877) | |
Deferred tax liability | (12,194) | (13,632) |
Total net deferred tax | $ 424 | $ 424 |
Income Taxes (NOL) (Details)
Income Taxes (NOL) (Details) - USD ($) $ in Thousands, shares in Millions | Nov. 19, 2018 | Dec. 31, 2018 | Dec. 31, 2017 |
Operating Loss Carryforwards [Line Items] | |||
Valuation allowance | $ 70,973 | $ 49,032 | |
Equity Offering, shares | 8.6 | ||
Annual carryover limitation | $ 2,400 | ||
Built in gains carryover limitation period | 5 years | ||
Follow On Offering [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Equity Offering, shares | 7.5 | ||
Over-Allotment Option [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Equity Offering, shares | 1.1 | ||
Federal [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Valuation allowance | 70,000 | ||
Operating loss carryforwards | 380,800 | ||
State [Member] | |||
Operating Loss Carryforwards [Line Items] | |||
Valuation allowance | 1,000 | ||
Operating loss carryforwards | $ 20,400 |
Income Taxes (Unrecognized Tax
Income Taxes (Unrecognized Tax Benefits) (Details) | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Reconciliation of Unrecognized Tax Benefits [Roll Forward] | |
Beginning Balance | $ 227,000 |
Ending Balance | 227,000 |
Interest and penalties related to unrecognized tax benefits | 0 |
Unrecognized tax benefits that would impact effective tax rate | $ 0 |