Document And Entity Information
Document And Entity Information - shares | 9 Months Ended | |
Sep. 30, 2019 | Nov. 06, 2019 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Sep. 30, 2019 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | Q3 | |
Entity Registrant Name | CONTANGO OIL & GAS CO | |
Entity Central Index Key | 0001071993 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Accelerated Filer | |
Entity Interactive Data Current | Yes | |
Entity Common Stock, Shares Outstanding | 89,357,332 | |
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 | Sep. 30, 2019 | Dec. 31, 2018 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 2,044 | |
Accounts receivable, net | 11,118 | $ 11,531 |
Prepaid expenses | 995 | 1,303 |
Current derivative asset | 2,625 | 4,600 |
Other current assets | 14,820 | |
Total current assets | 31,602 | 17,434 |
Natural gas and oil properties, successful efforts method of accounting: | ||
Proved properties | 1,110,042 | 1,095,417 |
Unproved properties | 42,427 | 34,612 |
Other property and equipment | 1,331 | 1,314 |
Accumulated depreciation, depletion and amortization | (912,098) | (898,169) |
Total property, plant and equipment, net | 241,702 | 233,174 |
OTHER NON-CURRENT ASSETS: | ||
Investments in affiliates | 5,872 | 5,743 |
Long-term derivative asset | 509 | |
Deferred tax asset | 424 | |
Other non-current assets | 1,962 | 357 |
Total other non-current assets | 8,343 | 6,524 |
TOTAL ASSETS | 281,647 | 257,132 |
CURRENT LIABILITIES: | ||
Accounts payable and accrued liabilities | 62,744 | 39,506 |
Current derivative liability | 24 | 422 |
Current asset retirement obligations | 679 | 1,329 |
Current portion of long-term debt | 60,000 | |
Total current liabilities | 63,447 | 101,257 |
NON-CURRENT LIABILITIES: | ||
Long-term debt | 28,100 | |
Asset retirement obligations | 11,636 | 12,168 |
Other long-term liabilities | 3,883 | 3,318 |
Total non-current liabilities | 43,619 | 15,486 |
Total liabilities | 107,066 | 116,743 |
COMMITMENTS AND CONTINGENCIES (NOTE 12) | ||
SHAREHOLDERS’ EQUITY: | ||
Series A convertible preferred stock, $0.04 par value, 789,474 shares authorized, issued and outstanding at September 30, 2019 | 32 | |
Common stock, $0.04 par value, 100 million shares authorized, 85,864,463 shares issued and outstanding at September 30, 2019, 39,617,442 shares issued and 34,158,492 shares outstanding at December 31, 2018 | 3,423 | 1,573 |
Additional paid-in capital | 393,723 | 339,981 |
Treasury shares at cost (No shares at September 30, 2019 and 5,458,950 shares at December 31, 2018) | (129,030) | |
Retained deficit | (222,597) | (72,135) |
Total shareholders’ equity | 174,581 | 140,389 |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ 281,647 | $ 257,132 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Sep. 30, 2019 | Dec. 31, 2018 |
CONSOLIDATED BALANCE SHEETS | ||
Preferred stock, par value (in dollars per share) | $ 0.04 | |
Preferred stock, shares authorized | 789,474 | |
Preferred stock, shares issued | 789,474 | |
Preferred stock, shares outstanding | 789,474 | |
Common stock, par value (in dollars per share) | $ 0.04 | $ 0.04 |
Common stock, shares authorized | 100,000,000 | |
Common stock, shares issued | 85,864,463 | 39,617,442 |
Common stock, shares outstanding | 85,864,463 | 34,158,492 |
Treasury stock, shares | 0 | 5,458,950 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
REVENUES: | ||||
Revenues | $ 12,547 | $ 19,508 | $ 39,320 | $ 58,393 |
EXPENSES: | ||||
Operating expenses | 5,435 | 6,382 | 16,321 | 19,787 |
Exploration expenses | 218 | 425 | 691 | 1,288 |
Depreciation, depletion and amortization | 8,473 | 12,853 | 23,602 | 32,836 |
Impairment and abandonment of oil and gas properties | 1,336 | 72,524 | 3,170 | 76,628 |
General and administrative expenses | 5,879 | 6,724 | 15,340 | 18,804 |
Total expenses | 21,341 | 98,908 | 59,124 | 149,343 |
OTHER INCOME (EXPENSE): | ||||
Gain (loss) from investment in affiliates, net of income taxes | (608) | (270) | (151) | (38) |
Gain from sale of assets | 192 | 498 | 601 | 11,315 |
Interest expense | (998) | (1,411) | (3,169) | (4,082) |
Gain (loss) on derivatives, net | 1,881 | (1,319) | 1,068 | (4,961) |
Other income | 519 | 357 | 522 | 1,239 |
Total other income (expense) | 986 | (2,145) | (1,129) | 3,473 |
NET LOSS BEFORE INCOME TAXES | (7,808) | (81,545) | (20,933) | (87,477) |
Income tax benefit (provision) | (30) | 21 | (484) | (288) |
NET LOSS | $ (7,838) | $ (81,524) | $ (21,417) | $ (87,765) |
NET LOSS PER SHARE: | ||||
Basic (in dollars per share) | $ (0.19) | $ (3.26) | $ (0.59) | $ (3.52) |
Diluted (in dollars per share) | $ (0.19) | $ (3.26) | $ (0.59) | $ (3.52) |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | ||||
Basic (in shares) | 41,786 | 25,001 | 36,518 | 24,910 |
Diluted (in shares) | 41,786 | 25,001 | 36,518 | 24,910 |
Oil and Condensate [Member] | ||||
REVENUES: | ||||
Revenues | $ 7,281 | $ 8,558 | $ 21,126 | $ 26,976 |
Natural Gas, Production [Member] | ||||
REVENUES: | ||||
Revenues | 4,293 | 7,128 | 13,792 | 21,585 |
Natural gas liquids [Member] | ||||
REVENUES: | ||||
Revenues | $ 973 | $ 3,822 | $ 4,402 | $ 9,832 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | ||
Net loss | $ (21,417) | $ (87,765) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Depreciation, depletion and amortization | 23,602 | 32,836 |
Impairment of natural gas and oil properties | 2,246 | 76,175 |
Deferred income taxes | 424 | |
Gain on sale of assets | (601) | (11,315) |
Loss (gain) from investment in affiliates | (151) | (38) |
Stock-based compensation | 2,193 | 3,772 |
Unrealized loss on derivative instruments | 1,068 | 2,551 |
Changes in operating assets and liabilities: | ||
Decrease in accounts receivable & other receivables | 590 | 355 |
Decrease in prepaids | 308 | 702 |
Increase (decrease) in accounts payable & advances from joint owners | 14,871 | 3,571 |
Increase (decrease) in Other Accrued Liabilities | 1,211 | 964 |
Increase in income taxes receivable, net | (454) | |
Increase (decrease) in income taxes payable, net | (126) | 208 |
Increase (decrease) in deposits and other | 14,819 | (3,051) |
Net cash provided by operating activities | 9,247 | 25,143 |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||
Natural gas and oil exploration and development expenditures | (27,309) | (43,223) |
Additions to furniture & equipment | (17) | |
Sale of oil & gas properties | 10 | 21,562 |
Sale of energy credits | 497 | |
Net cash used in investing activities | (27,316) | (21,164) |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||
Borrowings under credit facility | 137,655 | 182,319 |
Repayments under credit facility | (169,554) | (185,928) |
Net proceeds from equity offering | 53,650 | |
Purchase of treasury stock | (236) | (370) |
Debt issuance costs | (1,402) | |
Net cash used in financing activities | 20,113 | (3,979) |
NET CHANGE IN CASH AND CASH EQUIVALENTS | 2,044 | 0 |
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 0 | 0 |
CASH AND CASH EQUIVALENTS, END OF PERIOD | $ 2,044 | $ 0 |
CONSOLIDATED STATEMENT OF SHARE
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Preferred Stock [Member] | Common Stock [Member] | Additional Paid-In Capital [Member] | Treasury Stock [Member] | Retained Deficit [Member] | Total |
Balance at Dec. 31, 2017 | $ 1,223 | $ 302,527 | $ (128,583) | $ 49,433 | $ 224,600 | |
Balance, shares at Dec. 31, 2017 | 25,505,715 | |||||
Treasury shares at cost | (71) | (71) | ||||
Treasury shares at cost, shares | (16,032) | |||||
Restricted shares activity | $ 8 | (8) | ||||
Restricted shares activity, shares | 206,114 | |||||
Stock-based compensation | 1,424 | 1,424 | ||||
Net income (loss) | 937 | 937 | ||||
Balance at Mar. 31, 2018 | $ 1,231 | 303,943 | (128,654) | 50,370 | 226,890 | |
Balance, shares at Mar. 31, 2018 | 25,695,797 | |||||
Balance at Dec. 31, 2017 | $ 1,223 | 302,527 | (128,583) | 49,433 | 224,600 | |
Balance, shares at Dec. 31, 2017 | 25,505,715 | |||||
Net income (loss) | (87,765) | |||||
Balance at Sep. 30, 2018 | $ 1,229 | 306,293 | (128,953) | (38,332) | 140,237 | |
Balance, shares at Sep. 30, 2018 | 25,584,108 | |||||
Balance at Mar. 31, 2018 | $ 1,231 | 303,943 | (128,654) | 50,370 | 226,890 | |
Balance, shares at Mar. 31, 2018 | 25,695,797 | |||||
Treasury shares at cost | (124) | (124) | ||||
Treasury shares at cost, shares | (33,703) | |||||
Restricted shares activity | $ 4 | (4) | ||||
Restricted shares activity, shares | 77,188 | |||||
Stock-based compensation | 1,584 | 1,584 | ||||
Net income (loss) | (7,178) | (7,178) | ||||
Balance at Jun. 30, 2018 | $ 1,235 | 305,523 | (128,778) | 43,192 | 221,172 | |
Balance, shares at Jun. 30, 2018 | 25,739,282 | |||||
Treasury shares at cost | (175) | (175) | ||||
Treasury shares at cost, shares | (27,860) | |||||
Restricted shares activity | $ (6) | 6 | ||||
Restricted shares activity, shares | (127,314) | |||||
Stock-based compensation | 764 | 764 | ||||
Net income (loss) | (81,524) | (81,524) | ||||
Balance at Sep. 30, 2018 | $ 1,229 | 306,293 | (128,953) | (38,332) | 140,237 | |
Balance, shares at Sep. 30, 2018 | 25,584,108 | |||||
Balance at Dec. 31, 2018 | $ 1,573 | 339,981 | (129,030) | (72,135) | $ 140,389 | |
Balance, shares at Dec. 31, 2018 | 34,158,492 | 34,158,492 | ||||
Equity offering costs | (86) | $ (86) | ||||
Treasury shares at cost | (186) | (186) | ||||
Treasury shares at cost, shares | (49,415) | |||||
Restricted shares activity | $ 12 | (12) | ||||
Restricted shares activity, shares | 307,650 | |||||
Stock-based compensation | 1,052 | 1,052 | ||||
Net income (loss) | (8,618) | (8,618) | ||||
Balance at Mar. 31, 2019 | $ 1,585 | 340,935 | (129,216) | (80,753) | 132,551 | |
Balance, shares at Mar. 31, 2019 | 34,416,727 | |||||
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 | ||||
Net income (loss) | $ (21,417) | |||||
Balance at Sep. 30, 2019 | $ 32 | $ 3,423 | 393,723 | (222,597) | $ 174,581 | |
Balance, shares at Sep. 30, 2019 | 789,474 | 85,864,463 | 85,864,463 | |||
Balance at Mar. 31, 2019 | $ 1,585 | 340,935 | (129,216) | (80,753) | $ 132,551 | |
Balance, shares at Mar. 31, 2019 | 34,416,727 | |||||
Equity offering-common stock | 45 | 45 | ||||
Treasury shares at cost | (50) | (50) | ||||
Treasury shares at cost, shares | (16,133) | |||||
Restricted shares activity | $ 2 | (2) | ||||
Restricted shares activity, shares | 42,249 | |||||
Stock-based compensation | 585 | 585 | ||||
Net income (loss) | (4,961) | (4,961) | ||||
Balance at Jun. 30, 2019 | $ 1,587 | 341,563 | (129,266) | (85,714) | 128,170 | |
Balance, shares at Jun. 30, 2019 | 34,442,843 | |||||
Equity offering-common stock | $ 2,058 | 44,181 | $ 46,239 | |||
Equity offering-common stock, shares | 45,922,870 | 51,400,000 | ||||
Equity offering-preferred stock | $ 32 | 7,420 | $ 7,452 | |||
Equity offering-preferred stock, shares | 789,474 | |||||
Treasury shares reissuance | $ (221) | $ 129,266 | (129,045) | |||
Treasury shares reissuance, shares | 5,524,498 | |||||
Restricted shares activity | $ (1) | 1 | ||||
Restricted shares activity, shares | (25,748) | |||||
Stock-based compensation | 558 | 558 | ||||
Net income (loss) | (7,838) | (7,838) | ||||
Balance at Sep. 30, 2019 | $ 32 | $ 3,423 | $ 393,723 | $ (222,597) | $ 174,581 | |
Balance, shares at Sep. 30, 2019 | 789,474 | 85,864,463 | 85,864,463 |
Organization and Business
Organization and Business | 9 Months Ended |
Sep. 30, 2019 | |
Organization And Business [Abstract] | |
Organization and Business | 1. Organization and Business Contango Oil & Gas Company (collectively with its subsidiaries, “Contango” or the “Company”) is a Houston, Texas based, independent oil and natural gas company. The Company’s business is to maximize production and cash flow from its offshore properties in the shallow waters of the Gulf of Mexico (“GOM”) and onshore Texas and Wyoming properties and use that cash flow to explore, develop, exploit, increase production from and acquire crude oil and natural gas properties across the United States. On June 14, 2019, following approval by the Company’s stockholders at the 2019 annual meeting of stockholders, the Company changed its state of incorporation from the State of Delaware to the State of Texas and increased the Company’s number of authorized shares of common stock from 50 million to 100 million. In September 2019, the Company entered into a purchase agreement with Will Energy Corporation (“Will Energy”) and a purchase agreement with White Star Petroleum, LLC and certain of its affiliates (collectively, “White Star”) to purchase certain producing assets and undeveloped acreage, primarily in Oklahoma. These transactions closed subsequent to September 30, 2019. See Note 3 – “Acquisitions and Dispositions” for more information. Also in September 2019, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank and other lenders (the “Credit Agreement”). In connection with the entry into the Credit Agreement, the Company repaid all obligations and terminated its previous credit agreement with Royal Bank of Canada, which had an October 1, 2019 maturity. The new revolving credit agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star acquisitions on October 25 and November 1, 2019, respectively, to add two additional lenders and increase the borrowing base thereunder to $145 million. See Note 10 – “Long-Term Debt” for more information. The following table lists the Company’s primary producing areas as of September 30, 2019: Location Formation Gulf of Mexico Offshore Louisiana - water depths less than 300 feet Southern Delaware Basin, Pecos County, Texas Wolfcamp A and B Madison and Grimes counties, Texas Woodbine (Upper Lewisville) Zavala and Dimmit counties, Texas Buda / Eagle Ford / Georgetown San Augustine County, Texas Haynesville shale, Mid Bossier shale and James Lime formations Other Texas Gulf Coast Conventional and smaller unconventional formations Weston County, Wyoming Muddy Sandstone Sublette County, Wyoming Jonah Field (1) (1) Through a 37% equity investment in Exaro Energy III LLC (“Exaro”). Production associated with this investment is not included in the Company’s reported production results for all periods shown in this report. Since 2016, the Company has been focused on the development of its Southern Delaware Basin acreage in Pecos County, Texas , which is expected to continue to generate positive returns in the current price environment. As of September 30, 2019, the Company was producing from fourteen wells over its approximate 17,400 gross operated (8,400 total net) acre position in this West Texas area, prospective for the Wolfcamp A, Wolfcamp B and Second Bone Spring formations. In October 2019, the Company brought two more West Texas wells online and finished completing another West Texas well, which is expected to begin producing in mid-November 2019. Additionally, the Company is currently preparing to begin completion operations on a drilled but uncompleted well which it acquired in connection with the White Star acquisition. See Note 3 – “Acquisitions and Dispositions” for more information. The Company currently plans to limit its near-term drilling program expenditures, in West Texas and other areas, to only those necessary to fulfill leasehold commitments, preserve core acreage and, where determined appropriate to do so, expand its presence in those existing areas, or to add production and cash flow at attractive rates of return. The Company will continue to make balance sheet strength a priority in 2019 and will continue to identify opportunities for cost reductions and operating efficiencies in all areas of its operations, while also searching for new resource acquisition opportunities. Acquisition efforts will be focused on areas in which the Company can leverage its geological and operational experience and expertise to exploit identified drilling opportunities and where it can develop an inventory of additional drilling prospects that the Company believes will enable it to economically grow production and add reserves. On September 12, 2019, the Company completed an underwritten public offering (the “Public Offering”) of 51,447,368 shares of its common stock (of which 5,524,498 was reissued treasury shares) for net proceeds of approximately $46.2 million, after deducting the underwriting discount and fees and expenses. Net proceeds from the Series A Private Placement (defined below) and Public Offering were used to fund the cash portion of the purchase price for the Will Energy acquisition and to reduce borrowings under the Company’s revolving credit facility then in effect. In conjunction with the Public Offering, also on September 12, 2019, the Company entered into a purchase agreement with affiliates of John C. Goff, a director and significant shareholder of the Company, to issue and sell in a private placement (the “Series A Private Placement”) 789,474 shares of Series A contingent convertible preferred stock, which resulted in net proceeds of approximately $7.5 million. On November 1, 2019, the Company completed a private placement of 1,102,838 shares of Series B contingent convertible preferred stock, which resulted in net proceeds of approximately $21 million (the “Series B Private Placement”). Net proceeds from the Series B Private Placement were used to fund a portion of the purchase price and related transaction expenses for the White Star acquisition. Each of the series A and series B preferred shares are a new class of equity interests that rank equal to the common shares with respect to dividend rights and rights upon liquidation. The preferred shares will be entitled to vote on an as-converted basis on all matters submitted to a vote of the Company’s stockholders, with voting rights of the series A preferred shares equal to 19.99% of the common shares outstanding prior to the closing of the Public Offering and the series B preferred shares voting on an as-converted basis. Each series A preferred share and series B preferred share will then automatically convert into the number of common shares the purchaser would have received if the purchaser had purchased such common shares in the Public Offering and Series B Private Placement, respectively, for the same gross proceeds (the “Conversion”) and, upon the Conversion, the outstanding preferred shares will be cancelled. As of November 1, 2019, the Company has obtained approval of, or written agreements to approve, such increase in the number of authorized shares, and the issuance of the common shares underlying the series A preferred shares, from holders of a majority of the voting power of its capital stock, and will complete that process as soon as practicably possible. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2019 | |
Summary Of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 2. Summary of Significant Accounting Policies The accounting policies followed by the Company are set forth in the notes to the Company’s audited consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 Form 10-K”) filed with the Securities and Exchange Commission (“SEC”). Please refer to the notes to the financial statements included in the 2018 Form 10-K for additional details of the Company’s financial condition, results of operations and cash flows. No material items included in those notes have changed except as a result of normal transactions in the interim or as disclosed within this interim report. Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2018 Form 10-K. These unaudited interim consolidated results of operations for the nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019. The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by the Company’s wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results or production in those reported for the Company’s consolidated results of operations. Oil and Gas Properties - Successful Efforts The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed, whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. During the nine months ended September 30, 2019, the Company recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018. No impairment expense was recognized during the three months ended September 30, 2019. During the three and nine months ended September 30, 2018, the Company recognized $72.2 million and $74.9 million in total offshore and onshore non-cash proved property impairment charges, respectively. Included in offshore proved property impairment expense for the three and nine months ended September 30, 2018 was a $59.4 million impairment of the carrying costs of the Company’s Gulf of Mexico properties primarily due to revised proved reserve estimates made during the quarter ended September 30, 2018, as a result of new bottom hole pressure data gathered during the planned installation of a second stage of compression in the Eugene Island 11 field. Offshore non-cash proved property impairment expense for the nine months ended September 30, 2018 included an additional $2.3 million related to the Company’s Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018. The three and nine months ended September 30, 2018 also included onshore proved property impairment expense of $12.8 million and $13.2 million, respectively, substantially all of which was related to the reduction in fair value on certain of the Company’s non-core properties in Southeast Texas, as a result of a planned sale. See Note 3 – “Acquisitions and Dispositions” for further information regarding the sale of these certain non-core properties in Southeast Texas. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. The Company recognized non-cash impairment expense of approximately $1.2 million and approximately $2.0 million for the three and nine months ended September 30, 2019, respectively, related to impairment of certain unproved properties primarily due to expiring leases. The Company recognized non-cash impairment expense of approximately $0.1 million and approximately $1.3 million for the three and nine months ended September 30, 2018, respectively, also related to impairment of certain non-core unproved properties primarily due to expiring leases. Net Loss Per Common Share Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three and nine months ended September 30, 2019, the Company excluded 2,621,614 shares or units and 1,115,719 shares or units, respectively, of potentially dilutive securities, as they were antidilutive. For the three and nine months ended September 30, 2018, the Company excluded 884,948 shares or units and 1,328,884 shares or units, respectively, of potentially dilutive securities, as they were antidilutive. Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a joint and several and full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. The Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. Revenue Recognition Adoption of ASC 606 As of January 1, 2018, the Company adopted Accounting Standards Codification Topic 606 – Revenue from Contracts with Customers (“ASC 606”), which supersedes the revenue recognition requirements and industry-specific guidance under Accounting Standards Codification Topic 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 did not recognize 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 a 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 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 nine months ended September 30, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment. Recent Accounting Pronouncements In August 2018, the FASB issued ASU 2018-13 – Fair Value Measurement (“Topic 820”). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations. |
Acquisitions and Dispositions
Acquisitions and Dispositions | 9 Months Ended |
Sep. 30, 2019 | |
Business Combinations [Abstract] | |
Acquisitions and Dispositions | 3. Acquisitions and Dispositions On March 28, 2018, the Company sold its operated Eagle Ford Shale assets located in Karnes County, Texas for a cash purchase price of $21.0 million. The Company recorded a net gain of $9.5 million, after final closing adjustments. 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 and final closing adjustments. 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. The sale was completed on November 2, 2018 for cash proceeds of $6.0 million. On June 10, 2019, the Company sold certain minor, non-core operated assets located in Lavaca and Wharton counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.4 million after removal of the asset retirement obligations associated with the sold properties. On July 1, 2019, the Company sold certain minor, non-core operated assets located in Frio and Zavala counties, Texas in exchange for the buyer’s assumption of the plugging and abandonment liabilities of the properties. The Company recorded a gain of $0.2 million after removal of the asset retirement obligations associated with the sold properties. On September 12, 2019, the Company announced it entered into a contribution and purchase agreement with Will Energy to acquire approximately 159,872 net acres located in North Louisiana (12,560 net acres) and the Western Anadarko Basin in Western Oklahoma and the Texas Panhandle (147,312 net acres). As of September 30, 2019, the Company paid a $1.6 million deposit which is included in “Other current assets” on the Company’s consolidated balance sheet and as “Decrease (increase) in deposits and other” on the Company’s consolidated statement of cash flows. Closing of the Will Energy acquisition occurred on October 25, 2019, for a total aggregate consideration of $23 million. Following adjustments for recent sales of non-core, non-operated Louisiana properties by Will Energy, the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid consisted of $14.75 million in cash, including the $1.6 million deposit, and 3.5 million shares of common stock. On September 30, 2019, the Company entered into an asset purchase and sale agreement with White Star to acquire certain assets and liabilities, including approximately 315,000 net acres located in the STACK, Anadarko and Cherokee operating districts in Oklahoma. As of September 30, 2019, the Company paid a $12.5 million deposit which is included in “Other current assets” on the Company’s consolidated balance sheet and as “Decrease (increase) in deposits and other” on the Company’s consolidated statement of cash flows. Closing of the White Star acquisition occurred on November 1, 2019, for a total aggregate consideration of $132.5 million. Following adjustments for the results of operations for the period between the effective and closing dates, and other estimated, customary closing adjustments, the net consideration paid was approximately $95.6 million in cash, including the $12.5 million deposit. |
Fair Value Measurements
Fair Value Measurements | 9 Months Ended |
Sep. 30, 2019 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | 4. Fair Value Measurements 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. Fair value is 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). A fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 measurements are inputs that are observable for assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2019. A financial instrument's level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have been no transfers between Level 1, Level 2 or Level 3. Fair value information for financial assets and liabilities was as follows as of September 30, 2019 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 3,134 $ — $ 3,134 $ — Commodity price contracts - liabilities $ (24) $ — $ (24) $ — Derivatives listed above are recorded in “Current derivative asset or liability” and “Long-term derivative asset” on the Company’s consolidated balance sheet and include swaps and costless collars that are carried at fair value. The Company records the net change in the fair value of these positions in "Gain (loss) on derivatives, net" in its consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which resulted in reporting its derivatives as Level 2. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. See Note 5 – "Derivative Instruments" for additional discussion of derivatives. As of September 30, 2019, the Company's derivative contracts were all with major institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate such nonperformance. Estimates of the fair value of financial instruments are 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 Agreement approximates carrying value because the facility interest rate approximates current market rates and is reset at least every quarter. See Note 10 – “Long-Term Debt” for further information. Impairments The Company tests proved oil and natural gas properties for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. The Company estimates the undiscounted future cash flows expected in connection with the oil and gas properties on a field by field basis and compares such future cash flows to the unamortized capitalized costs of the properties. If the estimated future undiscounted cash flows are lower than the unamortized capitalized cost, the capitalized cost is reduced to its fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. Because these significant fair value inputs are typically not observable, impairments of long-lived assets are classified as a Level 3 fair value measure. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Asset Retirement Obligations The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. The factors used to determine fair value include, but are not limited to, estimated future plugging and abandonment costs and expected lives of the related reserves. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. |
Derivative Instruments
Derivative Instruments | 9 Months Ended |
Sep. 30, 2019 | |
Derivative Instruments [Abstract] | |
Derivative Instruments | 5. Derivative Instruments The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are typically utilized to hedge the Company's exposure to price fluctuations and reduce the variability in the Company's cash flows associated with anticipated sales of future oil and natural gas production. The Company typically hedges a substantial, but varying, portion of anticipated oil and natural gas production for future periods. The Company believes that these derivative arrangements, although not free of risk, allow it to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil, natural gas and natural gas liquids sales. Moreover, because its derivative arrangements apply only to a portion of its production, the Company’s strategy provides only partial protection against declines in commodity prices. Such arrangements may expose the Company to risk of financial loss in certain circumstances. The Company continuously reevaluates its hedging programs in light of changes in production, market conditions and commodity price forecasts. As of September 30, 2019, the Company’s natural gas and oil derivative positions consisted of swaps and costless collars. Swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. A costless collar consists of a purchased put option and a sold call option, which establishes a minimum and maximum price, respectively, that the Company will receive for the volumes under the contract. It is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy institutions deemed by management as competent and competitive market makers. The Company does not post collateral, nor is it exposed to potential margin calls, under any of these contracts, as they are secured under the Credit Agreement or under unsecured lines of credit with non-bank counterparties. See Note 10 – “Long-Term Debt” for further information regarding the Credit Agreement. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, derivatives are carried at fair value on the consolidated balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of operations for the period in which the change occurs. The Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in “Gain (loss) on derivatives, net” on the consolidated statements of operations. As of September 30, 2019, the following financial derivative instruments were in place (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit Fair Value Natural Gas Nov 2019 - Dec 2019 Swap 445,000 Mmbtus $ 2.62 (1) $ Crude Oil Oct 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) $ Crude Oil Oct 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) $ Crude Oil Oct 2019 Swap 9,000 Bbls $ 72.10 (3) $ Crude Oil Nov 2019 - Dec 2019 Swap 12,000 Bbls $ 72.10 (3) $ Crude Oil Oct 2019 - Dec 2019 Swap 2,400 Bbls $ 61.72 (3) $ Crude Oil Oct 2019 - Dec 2019 Swap 1,500 Bbls $ 57.67 (3) $ Natural Gas Jan 2020 - March 2020 Swap 425,000 Mmbtus $ 2.841 (1) $ Natural Gas April 2020 - July 2020 Swap 400,000 Mmbtus $ 2.532 (1) $ Natural Gas Aug 2020 - Oct 2020 Swap 40,000 Mmbtus $ 2.532 (1) $ Natural Gas Nov 2020 - Dec 2020 Swap 375,000 Mmbtus $ 2.696 (1) $ Crude Oil Jan 2020 - June 2020 Swap 22,000 Bbls $ 57.74 (3) $ Crude Oil July 2020 - Dec 2020 Swap 15,000 Bbls $ 57.74 (3) $ Crude Oil Jan 2020 - March 2020 Swap 2,700 Bbls $ 54.33 (3) $ Crude Oil April 2020 - June 2020 Swap 2,500 Bbls $ 54.33 (3) $ Crude Oil July 2020 Swap 5,500 Bbls $ 54.33 (3) $ Crude Oil Aug 2020 - Oct 2020 Swap 2,500 Bbls $ 54.33 (3) $ Crude Oil Nov 2020 - Dec 2020 Swap 3,500 Bbls $ 54.33 (3) $ Natural Gas Jan 2021 - March 2021 Swap 185,000 Mmbtus $ 2.505 (1) $ Natural Gas April 2021 - July 2021 Swap 120,000 Mmbtus $ 2.505 (1) $ Natural Gas Aug 2021 - Sept 2021 Swap 10,000 Mmbtus $ 2.505 (1) $ Natural Gas Jan 2021 - March 2021 Swap 185,000 Mmbtus $ 2.508 (1) $ Natural Gas April 2021 - July 2021 Swap 120,000 Mmbtus $ 2.508 (1) $ Natural Gas Aug 2021 - Sept 2021 Swap 10,000 Mmbtus $ 2.508 (1) $ Total net fair value of derivative instruments $ 3,188 (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. In addition to the above financial derivative instruments, the Company also had a costless swap agreement with a Midland WTI – Cushing crude oil differential swap price of $0.05 per barrel of crude oil. The agreement fixes the Company’s exposure to that differential on 12,000 barrels of crude oil per month for January 2020 through June 2020 and 10,000 barrels per month for July 2020 through December 2020. The fair value of this costless swap agreement was in a liability position of $0.1 million as of September 30, 2019. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2019 (in thousands): Gross Netting (1) Total Assets $ 3,134 $ — $ 3,134 Liabilities $ (24) $ — $ (24) (1) Represents counterparty netting under agreements governing such derivatives. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2018 (in thousands): Gross Netting (1) Total Assets $ 4,600 $ — $ 4,600 Liabilities $ (422) $ — $ (422) (1) Represents counterparty netting under agreements governing such derivatives. The following table summarizes the effect of derivative contracts on the consolidated statements of operations for the three and nine months ended September 30, 2019 and 2018 (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Crude oil contracts $ 500 $ (1,136) $ 1,442 $ (2,846) Natural gas contracts 371 57 694 436 Realized gain (loss) $ 871 $ (1,079) $ 2,136 $ (2,410) Crude oil contracts $ 1,049 $ (152) $ (2,029) $ (1,747) Natural gas contracts (39) (88) 961 (804) Unrealized gain (loss) $ 1,010 $ (240) $ (1,068) $ (2,551) Gain (loss) on derivatives, net $ 1,881 $ (1,319) $ 1,068 $ (4,961) In October 2019, in conjunction with the closing of the Will Energy acquisition (see Note 3 – “Acquisitions and Dispositions” for more information), the Company acquired the following additional derivative contracts with counterparties that are certain members of its credit facility lender group: Commodity Period Derivative Volume/Month Price/Unit Natural Gas October 2019 Collar 40,524 Mmbtus $ 2.45 - 3.40 (1) Natural Gas November 2019 Collar 46,377 Mmbtus $ 2.45 - 3.40 (1) Natural Gas December 2019 Collar 40,524 Mmbtus $ 2.45 - 3.40 (1) Natural Gas Jan 2020 - March 2020 Collar 225,000 Mmbtus $ 2.45 - 3.40 (1) Natural Gas October 2019 Collar 186,000 Mmbtus $ 2.50 - 2.975 (1) Natural Gas November 2019 Collar 180,000 Mmbtus $ 2.50 - 2.975 (1) Natural Gas December 2019 Collar 186,000 Mmbtus $ 2.50 - 2.975 (1) Crude Oil Oct 2019 - Dec 2019 Collar 4,000 Bbls $ 45.00 - 81.00 (2) Crude Oil Jan 2020 - Oct 2020 Collar 3,442 Bbls $ 52.00 - 65.70 (2) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on West Texas Intermediate crude oil prices. In the fourth quarter of 2019, the Company entered into the following additional derivative contracts: Commodity Period Derivative Volume/Month Price/Unit Natural Gas Dec 2019 Swap 330,000 Mmbtus $ 2.813 (1) Natural Gas Dec 2019 Swap 330,000 Mmbtus $ 2.81 (1) Natural Gas Jan 2020 - March 2020 Swap 300,000 Mmbtus $ 2.53 (1) Natural Gas April 2020 - July 2020 Swap 400,000 Mmbtus $ 2.53 (1) Natural Gas Aug 2020 - Dec 2020 Swap 350,000 Mmbtus $ 2.53 (1) Natural Gas Jan 2020 - March 2020 Swap 300,000 Mmbtus $ 2.532 (1) Natural Gas April 2020 - July 2020 Swap 400,000 Mmbtus $ 2.532 (1) Natural Gas Aug 2020 - Dec 2020 Swap 350,000 Mmbtus $ 2.532 (1) Natural Gas Jan 2021 - March 2021 Swap 650,000 Mmbtus $ 2.508 (1) Natural Gas April 2021 - Oct 2021 Swap 400,000 Mmbtus $ 2.508 (1) Natural Gas Nov 2021 - Dec 2021 Swap 580,000 Mmbtus $ 2.508 (1) Crude Oil Nov 2019 - Dec 2019 Swap 88,000 Bbls $ 56.80 (2) Crude Oil Jan 2020 - Feb 2020 Swap 42,500 Bbls $ 54.70 (2) Crude Oil March 2020 - July 2020 Swap 37,500 Bbls $ 54.70 (2) Crude Oil Aug 2020 - Dec 2020 Swap 35,000 Bbls $ 54.70 (2) Crude Oil Jan 2020 - Feb 2020 Swap 42,500 Bbls $ 54.58 (2) Crude Oil March 2020 - July 2020 Swap 37,500 Bbls $ 54.58 (2) Crude Oil Aug 2020 - Dec 2020 Swap 35,000 Bbls $ 54.58 (2) Crude Oil Jan 2021 - March 2021 Swap 19,000 Bbls $ 50.00 (2) Crude Oil April 2021 - July 2021 Swap 12,000 Bbls $ 50.00 (2) Crude Oil Aug 2021 - Sept 2021 Swap 10,000 Bbls $ 50.00 (2) Crude Oil Jan 2021 - July 2021 Swap 62,000 Bbls $ 52.00 (2) Crude Oil Aug 2021 - Sept 2021 Swap 55,000 Bbls $ 52.00 (2) Crude Oil Oct 2021 - Dec 2021 Swap 64,000 Bbls $ 52.00 (2) (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on West Texas Intermediate crude oil prices. |
Stock-Based Compensation
Stock-Based Compensation | 9 Months Ended |
Sep. 30, 2019 | |
Stock-Based Compensation [Abstract] | |
Stock-Based Compensation | 6. Stock-Based Compensation Restricted Stock During the nine months ended September 30, 2019, the Company granted 307,650 shares of restricted common stock, which vest over three years, to employees and executive officers as part of their overall compensation package. Additionally, during the nine months ended September 30, 2019, the Company granted 80,410 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2019, was $2.91 per share, with a total fair value of approximately $1.1 million and no adjustment for an estimated weighted average forfeiture rate. During the nine months ended September 30, 2019, 63,909 restricted shares were forfeited by former employees. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2019 was approximately $0.3 million. The Company recognized approximately $1.7 million in restricted stock compensation expense during the nine months ended September 30, 2019 related to restricted stock granted to its officers, employees and directors. As of September 30, 2019, an additional $1.2 million of compensation expense related to restricted stock remained to be recognized over the remaining weighted-average vesting period of 1.7 years. Approximately 1.2 million shares remained available for grant under the Second Amended and Restated 2009 Incentive Compensation Plan as of September 30, 2019, assuming PSUs (as defined below) are settled at 100% of target. During the nine months ended September 30, 2018, the Company granted 225,782 shares of restricted common stock, which vest over three years, to executive officers as part of their overall compensation package. Additionally, during the nine months ended September 30, 2018, the Company granted 82,500 shares of restricted common stock, which vest over one year, to directors pursuant to the Company’s Director Compensation Plan. The weighted average fair value of the restricted shares granted during the nine months ended September 30, 2018, was $3.76 per share, with a total fair value of approximately $1.2 million and no adjustment for an estimated weighted average forfeiture rate. During the nine months ended September 30, 2018, 152,294 restricted shares were forfeited by former employees, of which 105,800 forfeited shares were related to the resignation of the Company’s former President and CEO in September 2018. The aggregate intrinsic value of restricted shares forfeited during the nine months ended September 30, 2018 was approximately $1.0 million. The Company recognized approximately $3.2 million in restricted stock compensation expense during the nine months ended September 30, 2018 related to restricted stock granted to its officers, employees and directors. Performance Stock Units Performance stock units (“PSUs”) represent the opportunity to receive shares of the Company's common stock at the time of settlement. The number of shares to be awarded upon settlement of these PSUs may range from 0% to 300% of the targeted number of PSUs stated in the agreement, contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PSUs vest and settlement is determined after a three year period. Compensation expense associated with PSUs is based on the grant date fair value of a single PSU as determined using the Monte Carlo simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As it is contemplated that the PSUs will be settled with shares of the Company's common stock after three years, the PSU awards are accounted for as equity awards, and the fair value is calculated on the grant date. The simulation model calculates the payout percentage based on the stock price performance over the performance period. The concluded fair value is based on the average achievement percentage over all the iterations. The resulting fair value expense is amortized over the life of the PSU award. During the nine months ended September 30, 2019, the Company granted 117,105 PSUs to executive officers and employees as part of their overall compensation package, which will be measured between January 1, 2019 and December 31, 2021, and were valued at a weighted average fair value of $6.42 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the nine months ended September 30, 2019, 49,773 PSUs were forfeited due to the resignations of the Company’s former Senior Vice President of Exploration and Senior Vice President of Operations and Engineering in February 2019. The Company only recognized approximately $0.5 million in stock compensation expense related to PSUs during the nine months ended September 30, 2019, primarily due to the expiration of PSUs which failed to meet their target as of December 31, 2018 and the above referenced forfeitures. As of September 30, 2019, an additional $1.0 million of compensation expense related to PSUs remained to be recognized over the remaining weighted-average vesting period of 1.9 years. During the nine months ended September 30, 2018, the Company granted 190,782 PSUs to executive officers as part of their overall compensation package, which will be measured between January 1, 2018 and December 31, 2020, and were valued at a weighted average fair value of $7.69 per unit. All fair value prices were determined using the Monte Carlo simulation model. During the nine months ended September 30, 2018, 182,227 PSUs were forfeited by former employees, of which 153,127 forfeited shares were related to the resignation of the Company’s former President and CEO in September 2018. The Company only recognized approximately $0.6 million in stock compensation expense related to PSUs during the nine months ended September 30, 2018, primarily due to the above referenced forfeitures. Stock Options Under the fair value method of accounting for stock options, cash flows from the exercise of stock options resulting from tax benefits in excess of recognized cumulative compensation cost (excess tax benefits) are classified as financing cash flows. For the nine months ended September 30, 2019 and 2018, there was no excess tax benefit recognized. Compensation expense related to stock option grants are recognized over the stock option’s vesting period based on the fair value at the date the options are granted. The fair value of each option is estimated as of the date of grant using the Black-Scholes options-pricing model. No stock options were granted during the nine months ended September 30, 2019 or 2018. During the nine months ended September 30, 2019, no stock options were exercised and stock options for 12,673 shares were forfeited by former employees. During the nine months ended September 30, 2018, no stock options were exercised and stock options for 4,500 shares were forfeited by former employees. |
Leases
Leases | 9 Months Ended |
Sep. 30, 2019 | |
Leases | |
Leases | 7. Leases As of January 1, 2019, the Company adopted Accounting Standards Codification Topic 842 – Leases (“ASC 842”), which requires lessees to recognize a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term on the Company’s consolidated balance sheet. Expanded disclosures with additional qualitative and quantitative information are also required. ASC 842 contains several optional practical expedients upon adoption, one of which is referred to as the “package of three practical expedients”. The expedients must be taken together and allow entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. The Company elected to apply this practical expedient package to all of its leases upon adoption. The Company also chose to implement the “short-term accounting policy election” which allows the Company to not include leases with an initial term of twelve months or less on the balance sheet. The Company recognizes payments on these leases within “Operating expenses” on its consolidated statement of operations. ASC 842 provides for a modified retrospective transition approach requiring lessees to recognize and measure leases on the balance sheet at the beginning of either the earliest period presented or as of the beginning of the period of adoption. The Company elected to apply ASC 842 as of the beginning of the period of adoption (January 1, 2019) and will not restate comparative periods. For new leases, the Company determines if an arrangement is, or contains, a lease at inception. The Company has elected to combine and account for lease and non-lease contract components as a lease. As of January 1, 2019, the majority of the Company’s operating leases were for field equipment, such as compressors. The adoption of ASC 842 did not have a material effect on the Company’s financial results or disclosures. Most of the Company’s compressor contracts are on a month-to-month basis, and while it is probable the contract will be renewed on a monthly basis, the compressors can be easily substituted or cancelled by either party, with minimal penalties. Leases with these terms are not included on the Company’s balance sheet and are recognized on the statement of operations on a straight-line basis over the lease term. During the nine months ended September 30, 2019, the Company entered into a new office lease and new compressor contracts, with lease terms of twelve months or more, which qualify as operating leases under the new standard. The Company also entered into a new office equipment contract, which qualifies as a finance lease, during the nine months ended September 30, 2019. These leases do not have a material impact on the Company’s consolidated financial statements. The following table summarizes the balance sheet information related to the Company’s leases as of September 30, 2019 (in thousands): September 30, 2019 Operating lease right of use asset - current (1) $ 690 Operating lease right of use asset - long-term (2) 489 Total operating lease right of use asset $ 1,179 Operating lease liability - current (3) $ (690) Operating lease liability - long-term (4) (489) Total operating lease liability $ (1,179) Financing lease right of use asset - current (1) $ 19 Financing lease right of use asset - long-term (2) 70 Total financing lease right of use asset $ 89 Financing lease liability - current (3) $ (17) Financing lease liability - long-term (4) (74) Financing lease liability - current $ (91) (1) Included in “Other current assets” on the consolidated balance sheet. (2) Included in “Other non-current assets” on the consolidated balance sheet. (3) Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet. (4) Included in “Other long-term liabilities” on the consolidated balance sheet. The Company's leases generally do not provide an implicit rate, and therefore the Company uses its incremental borrowing rate as the discount rate when measuring operating lease liabilities. The incremental borrowing rate represents an estimate of the interest rate the Company would incur at lease commencement to borrow an amount equal to the lease payments on a collateralized basis over the term of a lease within a particular currency environment. For operating leases existing prior to January 1, 2019, the incremental borrowing rate as of January 1, 2019 was used for the remaining lease term. The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of September 30, 2019: September 30, 2019 Weighted Average Remaining Lease Terms (in months): Operating leases Financing leases Weighted Average Discount Rate: Operating leases Financing leases Maturities for the Company’s lease liabilities on the consolidated balance sheet as of September 30, 2019, were as follows (in thousands): September 30, 2019 Operating Leases Financing Leases 2019 (remaining after September 30, 2019) $ 170 $ 6 2020 677 17 2021 324 18 2022 8 19 2023 - 20 2024 - 11 Total future minimum lease payments 1,179 91 Less: imputed interest (57) (14) Present value of lease liabilities $ 1,122 $ 77 The following table summarizes expenses related to the Company’s leases for the three and nine months ended September 30, 2019 (in thousands): Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating lease cost (1) (2) $ 138 $ 609 Financing lease cost 5 5 Administrative lease cost (3) 19 56 Short-term lease cost (1) (4) 781 3,359 Total lease cost $ 943 $ 4,029 (1) This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. (2) Includes operating expense related to an office lease which expired on March 31, 2019 and a new office lease which began on April 1, 2019. (3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. (4) Costs related primarily to drilling rig and compressor agreements with lease terms of more than one month and less than one year. There were $228 thousand and $4 thousand in cash payments related to operating leases and financing leases, respectively, during the nine months ended September 30, 2019. |
Other Financial Information
Other Financial Information | 9 Months Ended |
Sep. 30, 2019 | |
Other Financial Information [Abstract] | |
Other Financial Information | 8. Other Financial Information The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): September 30, 2019 December 31, 2018 Accounts receivable: Trade receivables $ 4,463 $ 6,052 Receivable for Alta Resources distribution 1,712 1,993 Joint interest billings 4,005 3,833 Income taxes receivable 878 424 Other receivables 1,054 223 Allowance for doubtful accounts (994) (994) Total accounts receivable $ 11,118 $ 11,531 Prepaid expenses and other: Prepaid insurance $ 848 $ 792 Other 147 511 Total prepaid expenses and other $ 995 $ 1,303 Accounts payable and accrued liabilities: Royalties and revenue payable $ 12,704 $ 17,986 Advances from partners (1) 13,657 1,785 Accrued exploration and development (1) 12,036 4,751 Accrued acquisition costs 3,763 4,352 Trade payables (1) 12,441 3,385 Accrued general and administrative expenses (2) 4,365 2,545 Accrued operating expenses 1,651 1,801 Other accounts payable and accrued liabilities 2,127 2,901 Total accounts payable and accrued liabilities $ 62,744 $ 39,506 (1) Increase in 2019 primarily due to an increase in drilling and completion activity in West Texas during the three months ended September 30, 2019. The Company limited its drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019 to only that which was necessary to meet leasehold drilling obligations. (2) Includes a $2.1 million accrual related to a legal judgement determined during the three months ended September 30, 2019. See Note 12 – Commitments and Contingencies” for more information. Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the nine months ended September 30, 2019 and 2018 (in thousands): Nine Months Ended September 30, 2019 2018 Cash payments: Interest payments $ 3,037 $ 3,846 Income tax payments $ 668 $ 81 Non-cash investing activities in the consolidated statements of cash flows: Increase in accrued capital expenditures $ 7,284 $ 2,764 |
Investment In Exaro Energy III
Investment In Exaro Energy III LLC | 9 Months Ended |
Sep. 30, 2019 | |
Investment In Exaro Energy III LLC [Abstract] | |
Investment In Exaro Energy III LLC | 9. Investment in Exaro Energy III LLC The Company maintains an ownership interest in Exaro of approximately 37%. The Company’s share in the equity of Exaro at September 30, 2019 was approximately $5.9 million. The Company accounts for its ownership in Exaro using the equity method of accounting, and therefore, does not include its share of individual operating results or production in those reported for the Company’s consolidated results. The Company’s share in Exaro’s results of operations recognized for the three months ended September 30, 2019 and 2018 was a loss of $0.6 million, net of no tax expense, and a loss of $0.3 million, net of no tax expense, respectively. The Company’s share in Exaro’s results of operations recognized for the nine months ended September 30, 2019 and 2018 was a gain of $0.1 million, net of no tax expense, and a loss of $38 thousand, net of no tax expense, respectively. |
Long-Term Debt
Long-Term Debt | 9 Months Ended |
Sep. 30, 2019 | |
Long-Term Debt | |
Long-Term Debt | 10. Long-Term Debt Credit Agreement On September 17, 2019, the Company entered into a new revolving credit agreement with JPMorgan Chase Bank and other lenders (the “Credit Agreement”), which established a borrowing base of $65 million. The Credit Agreement was amended on November 1, 2019, in conjunction with the closing of the Will Energy and White Star acquisitions, to add two additional lenders and increase the borrowing base thereunder to $145 million. The borrowing base is subject to semi-annual redeterminations. The next redetermination will occur on or about December 1, 2019. Beginning in 2020, the semi-annual redeterminations will occur on May 1 st and November 1 st of each year. The borrowing base may also be adjusted by certain events, including the incurrence of any senior unsecured debt, material asset dispositions or liquidation of hedges in excess of certain thresholds. The Credit Agreement matures on September 17, 2024 . On September 18, 2019, the Company repaid all obligations with borrowings under the Credit Agreement, and terminated, its previous credit agreement with the Royal Bank of Canada (the “Credit Facility”), which had an October 1, 2019 maturity. As of September 30, 2019, the Company had approximately $28.1 million outstanding under the Credit Agreement and $1.9 million in an outstanding letter of credit. As of December 31, 2018, the Company had approximately $60.0 million outstanding under the Credit Facility and $1.9 million in an outstanding letter of credit. As of September 30, 2019, borrowing availability under the Credit Agreement was $35.0 million. The Credit Agreement is collateralized by liens on substantially all of the Company’s oil and gas properties and other assets and security interests in the stock of its wholly owned and/or controlled subsidiaries. The Company’s wholly owned and/or controlled subsidiaries are also required to join as guarantors under the Credit Agreement. Total interest expense under the Company’s current and previous credit agreements, including commitment fees, for the three and nine months ended September 30, 2019 was approximately $1.0 million and $3.2 million, respectively. Total interest expense under the Company’s previous credit agreement, including commitment fees, for the three and nine months ended September 30, 2018 was approximately $1.4 million and $4.1 million, respectively. The weighted average interest rates in effect at September 30, 2019 and December 31, 2018 were 5.4% under the Credit Agreement and 6.3% under the Credit Facility, respectively. The Credit Agreement contains customary and typical restrictive covenants. Commencing in the quarter ending December 31, 2019, the Credit Agreement requires a Current Ratio of greater than or equal to 1.00 and a Leverage Ratio of less than or equal to 3.50, both as defined in the Credit Agreement. |
Income Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2019 | |
Income Taxes [Abstract] | |
Income Taxes | 11. Income Taxes The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Current tax provision (benefit): Federal $ — $ — $ — $ — State 30 (21) 484 288 Total $ 30 $ (21) $ 484 $ 288 Total tax provision (benefit): Federal $ — $ — $ — $ — State 30 (21) 484 288 Total income tax provision (benefit) $ 30 $ (21) $ 484 $ 288 In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, established a full valuation allowance at September 30, 2015. For the nine months ended September 30, 2019, the Company continued to take a full valuation allowance against its deferred tax asset. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. Income tax expense relates to cash income taxes paid to the State of Louisiana on properties within the state that is not shielded by existing Federal tax attributes. In the quarter ended December 31, 2018, the Company experienced an Ownership Change (the “2018 Ownership Change”) as described in Internal Revenue Code (“IRC”) section 382 as a result of a completed follow-on equity offering. Management estimates that as a result of this Ownership Change, its future Net Operating Loss (“NOL”) and other tax attribute carryforwards will be limited in usage to approximately $2.4 million per year. As a result of these limitations, it is likely that a substantial portion of the Company’s pre-2018 NOLs will expire unused. Due to the presence of the valuation allowance from prior years, this event resulted in no net charge to earnings. The Company is performing additional analysis related to this matter and expects it to be finalized in the fourth quarter of 2019. In the quarter ended September 30, 2019, the Company issued 51.4 million additional shares of common stock pursuant to a follow-on equity offering (see Note 1 – “Organization and Business”). The cumulative effect of this equity offering, combined with other equity issuances, could have resulted in a subsequent Ownership Change, within the meaning of the IRC section 382. Based upon the information known to date, it is anticipated that if the Company experienced a subsequent Ownership Change, the IRC section 382 limit imposed by the Ownership Change could be more limiting on the ability of the Company to recover its NOLs than the 2018 Ownership Change. More specifically, the limit imposed by the subsequent Ownership Change could cause more of the Company’s NOLs to expire unused, resulting in a net impact to the Company’s effective tax rate and reported earnings. The Company is presently pursuing avenues set out in IRS guidance that allows the Company to inquire of (and rely upon) substantial shareholders as to the nature and timing of their purchases based on reliance of “actual knowledge” (as defined in IRS guidance) to properly assess the effect of the stock issuances on its NOL recovery. The Company expects this analysis to be completed in the fourth quarter of 2019 and will record the effect (if any) on its NOLs in that period. |
Commitments and Contingencies
Commitments and Contingencies | 9 Months Ended |
Sep. 30, 2019 | |
Commitments And Contingencies [Abstract] | |
Commitments and Contingencies | 12. Commitments and Contingencies Legal Proceedings From time to time, the Company is involved in legal proceedings relating to claims associated with its properties, operations or business or arising from disputes with vendors in the normal course of business, including the material matters discussed below. In November 2010, a subsidiary of the Company, several predecessor operators and several product purchasers were named in a lawsuit filed in the District Court for Lavaca County in Texas by an entity alleging that it owns a working interest in two wells that has not been recognized by the Company or by predecessor operators to which the Company had granted indemnification rights. In dispute is whether ownership rights were transferred through a number of decades-old poorly documented transactions. Based on prior summary judgments, the trial court entered a final judgment in the case in favor of the plaintiffs for approximately $5.3 million, plus post-judgment interest. The Company appealed the trial court’s decision to the applicable state Court of Appeals, and in the fourth quarter of 2017, the Court of Appeals issued its opinion and affirmed the trial court’s summary decision. In the first quarter of 2018, the Company filed a motion for rehearing with the Court of Appeals, which was denied, as expected. The Company 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. In early October 2019, the Supreme Court notified the Company that it would not hear this case. The Company has engaged additional legal representation to assist in the preparation of an amended petition requesting that the Texas Supreme Court reconsider its initial decision to not review the case and is seeking amicus briefs from industry associations whose members would be affected by the Court of Appeals ruling. In January 2016, the Company was named as the defendant in a lawsuit filed in the District Court for Harris County in Texas by a third-party operator. The Company participated in the drilling of a well in 2012, which experienced serious difficulties during the initial drilling, which eventually led to the plugging and abandoning of the wellbore prior to reaching the target depth. In dispute is whether the Company is responsible for the additional costs related to the drilling difficulties and plugging and abandonment. In September 2019, the case went to trial, and the court ruled in favor of the plaintiff. Prior to the judgement, the Company had approximately $1.1 million in accounts payable related to the disputed costs associated with this case. As a result of the judgement, during the three months ended September 30, 2019, the Company recorded an additional $2.1 million liability for the final judgement plus fees and interest. The Company is currently preparing an appeal of that court decision. While many of these matters involve inherent uncertainty and the Company is unable at the date of this filing to estimate an amount of possible loss with respect to certain of these matters, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings or claims will not have a material adverse effect on its consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company maintains various insurance policies that may provide coverage when certain types of legal proceedings are determined adversely. Throughput Contract Commitment The Company signed a throughput agreement with a third-party pipeline owner/operator that constructed a natural gas gathering pipeline in the Company’s Southeast Texas area that allows the Company to defray the cost of building the pipeline itself. Beginning in late 2016, the Company was unable to meet the minimum monthly gas volume deliveries through this line in its Southeast Texas area and currently forecasts it will continue to not meet the minimum throughput requirements under the agreement based upon the current commodity price market and the Company’s short term strategic drilling plans. Without further development in that area, the volume deficiency will continue through the expiration of the throughput commitment in March 2020. The throughput deficiency fee is paid in April of each calendar year. The Company incurred net fees of $0.7 million during each of the nine months ended September 30, 2019 and 2018. As of September 30, 2019, the Company estimates that the remaining net deficiency fee will be approximately $0.5 million through the expiration of the contract on March 31, 2020, all of which is currently accrued. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 9 Months Ended |
Sep. 30, 2019 | |
Summary Of Significant Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The accompanying unaudited consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information, pursuant to the rules and regulations of the SEC, including instructions to Quarterly Reports on Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, all adjustments considered necessary for a fair statement of the unaudited consolidated financial statements have been included. All such adjustments are of a normal recurring nature. The consolidated financial statements should be read in conjunction with the 2018 Form 10-K. These unaudited interim consolidated results of operations for the nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the full year ending December 31, 2019. |
Principles Of Consolidation | The Company’s consolidated financial statements include the accounts of Contango Oil & Gas Company and its subsidiaries, after elimination of all material intercompany balances and transactions. All wholly owned subsidiaries are consolidated. The investment in Exaro by the Company’s wholly owned subsidiary, Contaro Company, is accounted for using the equity method of accounting, and therefore, the Company does not include its share of individual operating results or production in those reported for the Company’s consolidated results of operations. |
Oil and Gas Properties - Successful Efforts | Oil and Gas Properties - Successful Efforts The Company’s application of the successful efforts method of accounting for its natural gas and oil exploration and production activities requires judgment as to whether particular wells are developmental or exploratory, since exploratory costs and the costs related to exploratory wells that are determined to not have proved reserves must be expensed, whereas developmental costs are capitalized. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver natural gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. On occasion, wells are drilled which have targeted geologic structures that are both developmental and exploratory in nature, and in such instances an allocation of costs is required to properly account for the results. Delineation seismic costs incurred to select development locations within a productive natural gas and oil field are typically treated as development costs and capitalized, but often these seismic programs extend beyond the proved reserve areas, and therefore, management must estimate the portion of seismic costs to expense as exploratory. The evaluation of natural gas and oil leasehold acquisition costs included in unproved properties requires management's judgment of exploratory costs related to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. |
Impairment of Oil and Gas Properties | Impairment of Long-Lived Assets Pursuant to GAAP, when circumstances indicate that proved properties may be impaired, the Company compares expected undiscounted future cash flows on a field by field basis to the unamortized capitalized cost of the asset. If the estimated future undiscounted cash flows based on the Company’s estimate of future reserves, natural gas and oil prices, operating costs and production levels from oil and natural gas reserves, are lower than the unamortized capitalized cost, then the capitalized cost is reduced to fair value. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Additionally, the Company may use appropriate market data to determine fair value. During the nine months ended September 30, 2019, the Company recognized $0.2 million in non-cash proved property impairment related to leases in Wyoming and an onshore non-operated property in an area previously impaired due to revised reserve estimates made during the quarter ended December 31, 2018. No impairment expense was recognized during the three months ended September 30, 2019. During the three and nine months ended September 30, 2018, the Company recognized $72.2 million and $74.9 million in total offshore and onshore non-cash proved property impairment charges, respectively. Included in offshore proved property impairment expense for the three and nine months ended September 30, 2018 was a $59.4 million impairment of the carrying costs of the Company’s Gulf of Mexico properties primarily due to revised proved reserve estimates made during the quarter ended September 30, 2018, as a result of new bottom hole pressure data gathered during the planned installation of a second stage of compression in the Eugene Island 11 field. Offshore non-cash proved property impairment expense for the nine months ended September 30, 2018 included an additional $2.3 million related to the Company’s Vermilion 170 offshore property, which was subsequently sold effective December 1, 2018. The three and nine months ended September 30, 2018 also included onshore proved property impairment expense of $12.8 million and $13.2 million, respectively, substantially all of which was related to the reduction in fair value on certain of the Company’s non-core properties in Southeast Texas, as a result of a planned sale. See Note 3 – “Acquisitions and Dispositions” for further information regarding the sale of these certain non-core properties in Southeast Texas. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value of those properties, with any such impairment charged to expense in the period. The Company recognized non-cash impairment expense of approximately $1.2 million and approximately $2.0 million for the three and nine months ended September 30, 2019, respectively, related to impairment of certain unproved properties primarily due to expiring leases. The Company recognized non-cash impairment expense of approximately $0.1 million and approximately $1.3 million for the three and nine months ended September 30, 2018, respectively, also related to impairment of certain non-core unproved properties primarily due to expiring leases. |
Net Loss Per Common Share | Net Loss Per Common Share Basic net loss per common share is computed by dividing the net loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net loss per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Potentially dilutive securities, including unexercised stock options, performance stock units and unvested restricted stock, have not been considered when their effect would be antidilutive. For the three and nine months ended September 30, 2019, the Company excluded 2,621,614 shares or units and 1,115,719 shares or units, respectively, of potentially dilutive securities, as they were antidilutive. For the three and nine months ended September 30, 2018, the Company excluded 884,948 shares or units and 1,328,884 shares or units, respectively, of potentially dilutive securities, as they were antidilutive. |
Subsidiary Guarantees | Subsidiary Guarantees Contango Oil & Gas Company, as the parent company (the “Parent Company”), has filed a registration statement on Form S-3 with the SEC to register, among other securities, debt securities that the Parent Company may issue from time to time. Any such debt securities would likely be guaranteed on a joint and several and full and unconditional basis by each of the Company’s current subsidiaries and any future subsidiaries specified in any future prospectus supplement (each a “Subsidiary Guarantor”). Each of the Subsidiary Guarantors is wholly owned by the Parent Company, either directly or indirectly. The Parent Company has no assets or operations independent of the Subsidiary Guarantors, and there are no significant restrictions upon the ability of the Subsidiary Guarantors to distribute funds to the Parent Company. The Parent Company has one wholly owned subsidiary that is inactive and not a Subsidiary Guarantor. The Parent Company’s wholly owned subsidiaries do not have restricted assets that exceed 25% of net assets as of the most recent fiscal year end that may not be transferred to the Parent Company in the form of loans, advances or cash dividends by such subsidiary without the consent of a third party. |
Revenue Recognition | Revenue Recognition Adoption of ASC 606 As of January 1, 2018, the Company adopted Accounting Standards Codification Topic 606 – Revenue from Contracts with Customers (“ASC 606”), which supersedes the revenue recognition requirements and industry-specific guidance under Accounting Standards Codification Topic 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 did not recognize 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 a 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 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 nine months ended September 30, 2019. The Company has modified procedures to its existing internal controls relating to revenue by reviewing for any significant increase in sales level, primarily on gas processing or gas purchasing contracts, on a quarterly basis to monitor the significance of gross revenue versus net revenue and expenses under ASC 606. As under previous revenue guidance, the Company will continue to review all new or modified revenue contracts on a quarterly basis for proper treatment. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In August 2018, the FASB issued ASU 2018-13 – Fair Value Measurement (“Topic 820”). The amendments in ASU 2018-13 modify the disclosure requirements on fair value measurements in Topic 820. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. The provisions of this update are not expected to have a material impact on the Company’s financial position or results of operations. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Fair Value Measurements [Abstract] | |
Schedule Of Fair Value Of Financial Assets And (Liabilities) | Fair value information for financial assets and liabilities was as follows as of September 30, 2019 (in thousands): Total Fair Value Measurements Using Carrying Value Level 1 Level 2 Level 3 Derivatives Commodity price contracts - assets $ 3,134 $ — $ 3,134 $ — Commodity price contracts - liabilities $ (24) $ — $ (24) $ — |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Derivative Instruments [Abstract] | |
Schedule Of Derivative Contracts | As of September 30, 2019, the following financial derivative instruments were in place (fair value in thousands): Commodity Period Derivative Volume/Month Price/Unit Fair Value Natural Gas Nov 2019 - Dec 2019 Swap 445,000 Mmbtus $ 2.62 (1) $ Crude Oil Oct 2019 - Dec 2019 Collar 7,000 Bbls $ 50.00 - 58.00 (2) $ Crude Oil Oct 2019 - Dec 2019 Collar 4,000 Bbls $ 52.00 - 59.45 (3) $ Crude Oil Oct 2019 Swap 9,000 Bbls $ 72.10 (3) $ Crude Oil Nov 2019 - Dec 2019 Swap 12,000 Bbls $ 72.10 (3) $ Crude Oil Oct 2019 - Dec 2019 Swap 2,400 Bbls $ 61.72 (3) $ Crude Oil Oct 2019 - Dec 2019 Swap 1,500 Bbls $ 57.67 (3) $ Natural Gas Jan 2020 - March 2020 Swap 425,000 Mmbtus $ 2.841 (1) $ Natural Gas April 2020 - July 2020 Swap 400,000 Mmbtus $ 2.532 (1) $ Natural Gas Aug 2020 - Oct 2020 Swap 40,000 Mmbtus $ 2.532 (1) $ Natural Gas Nov 2020 - Dec 2020 Swap 375,000 Mmbtus $ 2.696 (1) $ Crude Oil Jan 2020 - June 2020 Swap 22,000 Bbls $ 57.74 (3) $ Crude Oil July 2020 - Dec 2020 Swap 15,000 Bbls $ 57.74 (3) $ Crude Oil Jan 2020 - March 2020 Swap 2,700 Bbls $ 54.33 (3) $ Crude Oil April 2020 - June 2020 Swap 2,500 Bbls $ 54.33 (3) $ Crude Oil July 2020 Swap 5,500 Bbls $ 54.33 (3) $ Crude Oil Aug 2020 - Oct 2020 Swap 2,500 Bbls $ 54.33 (3) $ Crude Oil Nov 2020 - Dec 2020 Swap 3,500 Bbls $ 54.33 (3) $ Natural Gas Jan 2021 - March 2021 Swap 185,000 Mmbtus $ 2.505 (1) $ Natural Gas April 2021 - July 2021 Swap 120,000 Mmbtus $ 2.505 (1) $ Natural Gas Aug 2021 - Sept 2021 Swap 10,000 Mmbtus $ 2.505 (1) $ Natural Gas Jan 2021 - March 2021 Swap 185,000 Mmbtus $ 2.508 (1) $ Natural Gas April 2021 - July 2021 Swap 120,000 Mmbtus $ 2.508 (1) $ Natural Gas Aug 2021 - Sept 2021 Swap 10,000 Mmbtus $ 2.508 (1) $ Total net fair value of derivative instruments $ 3,188 (1) Based on Henry Hub NYMEX natural gas prices. (2) Based on Argus Louisiana Light Sweet crude oil prices. (3) Based on West Texas Intermediate crude oil prices. |
Schedule Of Fair Value Of Commodity Derivatives | The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of September 30, 2019 (in thousands): Gross Netting (1) Total Assets $ 3,134 $ — $ 3,134 Liabilities $ (24) $ — $ (24) (1) Represents counterparty netting under agreements governing such derivatives. The following summarizes the fair value of commodity derivatives outstanding on a gross and net basis as of December 31, 2018 (in thousands): Gross Netting (1) Total Assets $ 4,600 $ — $ 4,600 Liabilities $ (422) $ — $ (422) (1) Represents counterparty netting under agreements governing such derivatives. |
Schedule Of Derivative Contracts On Operations | Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Crude oil contracts $ 500 $ (1,136) $ 1,442 $ (2,846) Natural gas contracts 371 57 694 436 Realized gain (loss) $ 871 $ (1,079) $ 2,136 $ (2,410) Crude oil contracts $ 1,049 $ (152) $ (2,029) $ (1,747) Natural gas contracts (39) (88) 961 (804) Unrealized gain (loss) $ 1,010 $ (240) $ (1,068) $ (2,551) Gain (loss) on derivatives, net $ 1,881 $ (1,319) $ 1,068 $ (4,961) |
Leases (Tables)
Leases (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Leases | |
Summary of balance sheet information related to the leases | The following table summarizes the balance sheet information related to the Company’s leases as of September 30, 2019 (in thousands): September 30, 2019 Operating lease right of use asset - current (1) $ 690 Operating lease right of use asset - long-term (2) 489 Total operating lease right of use asset $ 1,179 Operating lease liability - current (3) $ (690) Operating lease liability - long-term (4) (489) Total operating lease liability $ (1,179) Financing lease right of use asset - current (1) $ 19 Financing lease right of use asset - long-term (2) 70 Total financing lease right of use asset $ 89 Financing lease liability - current (3) $ (17) Financing lease liability - long-term (4) (74) Financing lease liability - current $ (91) (1) Included in “Other current assets” on the consolidated balance sheet. (2) Included in “Other non-current assets” on the consolidated balance sheet. (3) Included in “Accounts payable and accrued liabilities” on the consolidated balance sheet. (4) Included in “Other long-term liabilities” on the consolidated balance sheet. |
Summary of weighted average remaining lease terms and weighted average discount rates | The table below presents the weighted average remaining lease terms and weighted average discount rates for the Company’s leases as of September 30, 2019: September 30, 2019 Weighted Average Remaining Lease Terms (in months): Operating leases Financing leases Weighted Average Discount Rate: Operating leases Financing leases |
Summary of maturities for the Company’s lease liabilities on the consolidated balance sheet, Operating lease | Maturities for the Company’s lease liabilities on the consolidated balance sheet as of September 30, 2019, were as follows (in thousands): September 30, 2019 Operating Leases Financing Leases 2019 (remaining after September 30, 2019) $ 170 $ 6 2020 677 17 2021 324 18 2022 8 19 2023 - 20 2024 - 11 Total future minimum lease payments 1,179 91 Less: imputed interest (57) (14) Present value of lease liabilities $ 1,122 $ 77 |
Summary of maturities for the Company’s lease liabilities on the consolidated balance sheet, Finance lease | September 30, 2019 Operating Leases Financing Leases 2019 (remaining after September 30, 2019) $ 170 $ 6 2020 677 17 2021 324 18 2022 8 19 2023 - 20 2024 - 11 Total future minimum lease payments 1,179 91 Less: imputed interest (57) (14) Present value of lease liabilities $ 1,122 $ 77 |
Summary of operating lease costs | The following table summarizes expenses related to the Company’s leases for the three and nine months ended September 30, 2019 (in thousands): Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019 Operating lease cost (1) (2) $ 138 $ 609 Financing lease cost 5 5 Administrative lease cost (3) 19 56 Short-term lease cost (1) (4) 781 3,359 Total lease cost $ 943 $ 4,029 (1) This total does not reflect amounts that may be reimbursed by other third parties in the normal course of business, such as non-operating working interest owners. (2) Includes operating expense related to an office lease which expired on March 31, 2019 and a new office lease which began on April 1, 2019. (3) Costs related primarily to office equipment and IT solutions with lease terms of more than one month and less than one year. (4) Costs related primarily to drilling rig and compressor agreements with lease terms of more than one month and less than one year. |
Other Financial Information (Ta
Other Financial Information (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Other Financial Information [Abstract] | |
Schedule Of Additional Financial Details | The following table provides additional detail for accounts receivable, prepaid expenses and other, and accounts payable and accrued liabilities which are presented on the consolidated balance sheets (in thousands): September 30, 2019 December 31, 2018 Accounts receivable: Trade receivables $ 4,463 $ 6,052 Receivable for Alta Resources distribution 1,712 1,993 Joint interest billings 4,005 3,833 Income taxes receivable 878 424 Other receivables 1,054 223 Allowance for doubtful accounts (994) (994) Total accounts receivable $ 11,118 $ 11,531 Prepaid expenses and other: Prepaid insurance $ 848 $ 792 Other 147 511 Total prepaid expenses and other $ 995 $ 1,303 Accounts payable and accrued liabilities: Royalties and revenue payable $ 12,704 $ 17,986 Advances from partners (1) 13,657 1,785 Accrued exploration and development (1) 12,036 4,751 Accrued acquisition costs 3,763 4,352 Trade payables (1) 12,441 3,385 Accrued general and administrative expenses (2) 4,365 2,545 Accrued operating expenses 1,651 1,801 Other accounts payable and accrued liabilities 2,127 2,901 Total accounts payable and accrued liabilities $ 62,744 $ 39,506 (1) Increase in 2019 primarily due to an increase in drilling and completion activity in West Texas during the three months ended September 30, 2019. The Company limited its drilling program in West Texas for the fourth quarter of 2018 and first quarter of 2019 to only that which was necessary to meet leasehold drilling obligations. (2) Includes a $2.1 million accrual related to a legal judgement determined during the three months ended September 30, 2019. See Note 12 – Commitments and Contingencies” for more information. |
Schedule Of Supplemental Disclosures | Included in the table below are supplemental cash flow disclosures and non-cash investing activities during the nine months ended September 30, 2019 and 2018 (in thousands): Nine Months Ended September 30, 2019 2018 Cash payments: Interest payments $ 3,037 $ 3,846 Income tax payments $ 668 $ 81 Non-cash investing activities in the consolidated statements of cash flows: Increase in accrued capital expenditures $ 7,284 $ 2,764 |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Income Taxes [Abstract] | |
Components Of Income Tax Expense (Benefit) | The Company’s income tax provision for continuing operations consists of the following (in thousands): Three Months Ended September 30, Nine Months Ended September 30, 2019 2018 2019 2018 Current tax provision (benefit): Federal $ — $ — $ — $ — State 30 (21) 484 288 Total $ 30 $ (21) $ 484 $ 288 Total tax provision (benefit): Federal $ — $ — $ — $ — State 30 (21) 484 288 Total income tax provision (benefit) $ 30 $ (21) $ 484 $ 288 |
Organization and Business (Deta
Organization and Business (Details) $ in Thousands | Nov. 01, 2019USD ($)shares | Sep. 12, 2019USD ($)shares | Oct. 31, 2019item | Sep. 30, 2019ashares | Sep. 30, 2019USD ($)aitemftshares | Sep. 17, 2019USD ($) | Jun. 14, 2019shares | Jun. 13, 2019shares |
Common stock, shares authorized | 100,000,000 | 100,000,000 | 100,000,000 | 50,000,000 | ||||
Number of wells | item | 2 | |||||||
Equity offering-common stock, shares | 51,400,000 | |||||||
Net proceeds from equity offering | $ | $ 53,650 | |||||||
Exaro Energy III LLC [Member] | ||||||||
Equity method investment, ownership percentage | 37.00% | 37.00% | ||||||
Preferred Stock [Member] | ||||||||
Equity offering-common stock, shares | 1,102,838 | 789,474 | ||||||
Net proceeds from equity offering | $ | $ 21,000 | $ 7,500 | ||||||
Voting rights of preferred stock (as a percent) | 19.99% | |||||||
Common Stock [Member] | ||||||||
Equity offering-common stock, shares | 51,447,368 | 45,922,870 | ||||||
Treasury shares reissuance, shares | 5,524,498 | 5,524,498 | ||||||
Net proceeds from equity offering | $ | $ 46,200 | |||||||
Bullseye | ||||||||
Number of wells | item | 14 | |||||||
Gross acres | a | 17,400 | 17,400 | ||||||
Net acres | a | 8,400 | 8,400 | ||||||
Gulf of Mexico [Member] | Maximum [Member] | ||||||||
Water depth of operations | ft | 300 | |||||||
JPMorgan Chase Bank [Member] | ||||||||
Maximum borrowing capacity | $ | $ 145,000 | $ 65,000 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies - Impairment and Debt (Details) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2019USD ($)item | Sep. 30, 2018USD ($) | Dec. 31, 2018 | |
Policies | |||||
Impairment of natural gas and oil properties | $ 2,246 | $ 76,175 | |||
Debt issuance costs incurred | $ 1,402 | ||||
Number of subsidiaries inactive and not Subsidiary Guarantor | item | 1 | ||||
Restricted assets, percent of net assets | 25.00% | ||||
Proved property [Member] | |||||
Policies | |||||
Impairment of natural gas and oil properties | $ 0 | $ 72,200 | $ 200 | 74,900 | |
Proved property [Member] | Gulf of Mexico Properties [Member] | |||||
Policies | |||||
Impairment of natural gas and oil properties | 59,400 | 59,400 | |||
Proved property [Member] | Vermilion 170 [Member] | |||||
Policies | |||||
Impairment of natural gas and oil properties | 2,300 | ||||
Proved property [Member] | Onshore Properties [Member] | |||||
Policies | |||||
Impairment of natural gas and oil properties | 12,800 | 13,200 | |||
Unproved property [Member] | |||||
Policies | |||||
Impairment of natural gas and oil properties | $ 1,200 | $ 100 | $ 2,000 | $ 1,300 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Details) - shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Significant Accounting Policies [Line Items] | ||||
Potentially dilutive (in shares) | 2,621,614 | 884,948 | 1,115,719 | 1,328,884 |
Term of contract | 1 year | |||
Revenue, Practical Expedient, Initial Application and Transition, Nondisclosure of Transaction Price Allocation to Remaining Performance Obligation [true/false] | true | |||
Minimum [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Period settlement statements are received | 30 days | |||
Maximum [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Period settlement statements are received | 90 days |
Acquisitions and Dispositions -
Acquisitions and Dispositions - Dispositions (Details) - USD ($) $ in Thousands | Jul. 01, 2019 | Jun. 10, 2019 | Sep. 11, 2018 | May 25, 2018 | Mar. 28, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Nov. 02, 2018 |
Disposals | ||||||||
Impairment of natural gas and oil properties | $ 2,246 | $ 76,175 | ||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Karnes County, TX Assets [Member] | ||||||||
Disposals | ||||||||
Cash purchase price | $ 21,000 | |||||||
Gain (loss) on sale of oil and gas property | $ 9,500 | |||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Starr County, TX Assets [Member] | ||||||||
Disposals | ||||||||
Cash purchase price | $ 600 | |||||||
Gain (loss) on sale of oil and gas property | $ 1,300 | |||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Liberty and Hardin County, TX Assets [Member] | ||||||||
Disposals | ||||||||
Cash purchase price | $ 6,000 | |||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Lavaca and Wharton County, Texas Assets [Member] | ||||||||
Disposals | ||||||||
Gain (loss) on sale of oil and gas property | $ 400 | |||||||
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Frio and Zavala County Texas [Member] | ||||||||
Disposals | ||||||||
Gain (loss) on sale of oil and gas property | $ 200 | |||||||
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Liberty and Hardin County, TX Assets [Member] | ||||||||
Disposals | ||||||||
Impairment of natural gas and oil properties | $ 12,800 |
Acquisitions and Dispositions_2
Acquisitions and Dispositions - Acquisitions (Details) $ in Thousands, shares in Millions | Nov. 01, 2019USD ($) | Oct. 25, 2019USD ($)shares | Sep. 30, 2019USD ($)a | Sep. 12, 2019a |
Will Energy [Member] | ||||
Acquisition | ||||
Gross acres | a | 159,872 | |||
Acquisition consideration | $ | $ 23,000 | |||
Cash consideration for acquisition | $ | $ 14,750 | $ 1,600 | ||
Equity issued for acquisition consideration (in shares) | shares | 3.5 | |||
Will Energy [Member] | North Louisiana [Member] | ||||
Acquisition | ||||
Net acres | a | 12,560 | |||
Will Energy [Member] | Western Anadarko Basin [Member] | ||||
Acquisition | ||||
Net acres | a | 147,312 | |||
White Star [Member] | ||||
Acquisition | ||||
Net acres | a | 315,000 | |||
Acquisition consideration | $ | $ 132,500 | |||
Cash consideration for acquisition | $ | $ 95,600 | $ 12,500 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity price contracts - assets | $ 3,134 | $ 4,600 |
Commodity price contracts - liabilities | (24) | $ (422) |
Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Commodity price contracts - assets | 3,134 | |
Commodity price contracts - liabilities | $ (24) |
Derivative Instruments (Derivat
Derivative Instruments (Derivative Contracts) (Details) $ in Thousands | Nov. 12, 2019item$ / MMBTU$ / bbl | Oct. 31, 2019item$ / MMBTU$ / bbl | Sep. 30, 2019USD ($)item$ / MMBTU$ / bbl |
Derivative [Line Items] | |||
Fair Value | $ | $ 3,188 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November To December 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 445,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.62 | ||
Fair Value | $ | $ 180 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period December 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 330,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.813 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period December 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 330,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.81 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January to March 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 300,000 | 425,000 | |
Price/Unit-Swap | $ / MMBTU | 2.53 | 2.841 | |
Fair Value | $ | $ 341 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period January to March 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 300,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.532 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to July 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 400,000 | 400,000 | |
Price/Unit-Swap | $ / MMBTU | 2.53 | 2.532 | |
Fair Value | $ | $ 370 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period April to July 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 400,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.532 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to October 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 40,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.532 | ||
Fair Value | $ | $ 21 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to December 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 350,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.53 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period August to December 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 350,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.532 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November to December 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 375,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.696 | ||
Fair Value | $ | $ 133 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period January to March 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 650,000 | 185,000 | |
Price/Unit-Swap | $ / MMBTU | 2.508 | 2.505 | |
Fair Value | $ | $ (82) | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period January to March 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 185,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.508 | ||
Fair Value | $ | $ (76) | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to July 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 120,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.505 | ||
Fair Value | $ | $ 90 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period April to July 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 120,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.508 | ||
Fair Value | $ | $ 94 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period April to October 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 400,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.508 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period August to September 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 10,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.505 | ||
Fair Value | $ | $ 3 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract 2 Period August to September 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 10,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.508 | ||
Fair Value | $ | $ 3 | ||
Natural Gas [Member] | Swap [Member] | Derivative Contract Period November to December 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 580,000 | ||
Price/Unit-Swap | $ / MMBTU | 2.508 | ||
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period October 2019 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 40,524 | ||
Price/Unit-Floor | $ / MMBTU | 2.45 | ||
Price/Unit-Cap | $ / MMBTU | 3.40 | ||
Natural Gas [Member] | Collar Options [Member] | Derivative Contract 2 Period October 2019 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 186,000 | ||
Price/Unit-Floor | $ / MMBTU | 2.50 | ||
Price/Unit-Cap | $ / MMBTU | 2.975 | ||
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period November 2019 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 46,377 | ||
Price/Unit-Floor | $ / MMBTU | 2.45 | ||
Price/Unit-Cap | $ / MMBTU | 3.40 | ||
Natural Gas [Member] | Collar Options [Member] | Derivative Contract 2 Period November 2019 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 180,000 | ||
Price/Unit-Floor | $ / MMBTU | 2.50 | ||
Price/Unit-Cap | $ / MMBTU | 2.975 | ||
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period December 2019 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 40,524 | ||
Price/Unit-Floor | $ / MMBTU | 2.45 | ||
Price/Unit-Cap | $ / MMBTU | 3.40 | ||
Natural Gas [Member] | Collar Options [Member] | Derivative Contract 2 Period December 2019 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 186,000 | ||
Price/Unit-Floor | $ / MMBTU | 2.50 | ||
Price/Unit-Cap | $ / MMBTU | 2.975 | ||
Natural Gas [Member] | Collar Options [Member] | Derivative Contract Period January to March 2020 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 225,000 | ||
Price/Unit-Floor | $ / MMBTU | 2.45 | ||
Price/Unit-Cap | $ / MMBTU | 3.40 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period October To December 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 2,400 | ||
Price/Unit-Swap | $ / bbl | 61.72 | ||
Fair Value | $ | $ 57 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period October To December 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 1,500 | ||
Price/Unit-Swap | $ / bbl | 57.67 | ||
Fair Value | $ | $ 17 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period October 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 9,000 | ||
Price/Unit-Swap | $ / bbl | 72.10 | ||
Fair Value | $ | $ 162 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period November To December 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 88,000 | 12,000 | |
Price/Unit-Swap | $ / bbl | 56.80 | 72.10 | |
Fair Value | $ | $ 439 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to February 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 42,500 | ||
Price/Unit-Swap | $ / bbl | 54.70 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period January to February 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 42,500 | ||
Price/Unit-Swap | $ / bbl | 54.58 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to March 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 2,700 | ||
Price/Unit-Swap | $ / bbl | 54.33 | ||
Fair Value | $ | $ 12 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to June 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 22,000 | ||
Price/Unit-Swap | $ / bbl | 57.74 | ||
Fair Value | $ | $ 720 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period March to July 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 37,500 | ||
Price/Unit-Swap | $ / bbl | 54.70 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period March to July 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 37,500 | ||
Price/Unit-Swap | $ / bbl | 54.58 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period April to June 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 2,500 | ||
Price/Unit-Swap | $ / bbl | 54.33 | ||
Fair Value | $ | $ 20 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period July to December 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 15,000 | ||
Price/Unit-Swap | $ / bbl | 57.74 | ||
Fair Value | $ | $ 623 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period July 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 5,500 | ||
Price/Unit-Swap | $ / bbl | 54.33 | ||
Fair Value | $ | $ 18 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period August to October 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 2,500 | ||
Price/Unit-Swap | $ / bbl | 54.33 | ||
Fair Value | $ | $ 26 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period August to December 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 35,000 | ||
Price/Unit-Swap | $ / bbl | 54.70 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period August to December 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 35,000 | ||
Price/Unit-Swap | $ / bbl | 54.58 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period November to December 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 3,500 | ||
Price/Unit-Swap | $ / bbl | 54.33 | ||
Fair Value | $ | $ 27 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to March 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 19,000 | ||
Price/Unit-Swap | $ / MMBTU | 50 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period January to July 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 62,000 | ||
Price/Unit-Swap | $ / bbl | 52 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period April to July 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 12,000 | ||
Price/Unit-Swap | $ / MMBTU | 50 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period August to September 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 10,000 | ||
Price/Unit-Swap | $ / MMBTU | 50 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract 2 Period August to September 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 55,000 | ||
Price/Unit-Swap | $ / bbl | 52 | ||
Crude Oil [Member] | Swap [Member] | Derivative Contract Period October to December 2021 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 64,000 | ||
Price/Unit-Swap | $ / bbl | 52 | ||
Crude Oil [Member] | Collar Options [Member] | Derivative Contract Period October To December 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 7,000 | ||
Price/Unit-Floor | $ / bbl | 50 | ||
Price/Unit-Cap | $ / bbl | 58 | ||
Fair Value | $ | $ (24) | ||
Crude Oil [Member] | Collar Options [Member] | Derivative Contract Period October To December 2019 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 4,000 | ||
Price/Unit-Floor | $ / bbl | 45 | ||
Price/Unit-Cap | $ / bbl | 81 | ||
Crude Oil [Member] | Collar Options [Member] | Derivative Contract 2 Period October To December 2019 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 4,000 | ||
Price/Unit-Floor | $ / bbl | 52 | ||
Price/Unit-Cap | $ / bbl | 59.45 | ||
Fair Value | $ | $ 14 | ||
Crude Oil [Member] | Collar Options [Member] | Derivative Contract Period January to October 2020 [Member] | Will Energy [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 3,442 | ||
Price/Unit-Floor | $ / bbl | 52 | ||
Price/Unit-Cap | $ / bbl | 65.70 | ||
Crude Oil [Member] | Costless Swap [Member] | |||
Derivative [Line Items] | |||
Price/Unit-Swap | $ / bbl | 0.05 | ||
Fair Value | $ | $ (100) | ||
Crude Oil [Member] | Costless Swap [Member] | Derivative Contract Period January to June 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 12,000 | ||
Crude Oil [Member] | Costless Swap [Member] | Derivative Contract Period July to December 2020 [Member] | |||
Derivative [Line Items] | |||
Commodity Derivative Flow Rate | 10,000 |
Derivative Instruments (Fair Va
Derivative Instruments (Fair Value) (Details) - USD ($) $ in Thousands | Sep. 30, 2019 | Dec. 31, 2018 |
Assets | ||
Gross | $ 3,134 | $ 4,600 |
Total | 3,134 | 4,600 |
Liabilities: | ||
Gross | (24) | (422) |
Total | $ (24) | $ (422) |
Derivative Instruments (Operati
Derivative Instruments (Operations) (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | $ 871 | $ (1,079) | $ 2,136 | $ (2,410) |
Unrealized gain (loss) | 1,010 | (240) | (1,068) | (2,551) |
Gain (loss) on derivatives, net | 1,881 | (1,319) | 1,068 | (4,961) |
Crude Oil [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | 500 | (1,136) | 1,442 | (2,846) |
Unrealized gain (loss) | 1,049 | (152) | (2,029) | (1,747) |
Natural Gas [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Realized gain (loss) | 371 | 57 | 694 | 436 |
Unrealized gain (loss) | $ (39) | $ (88) | $ 961 | $ (804) |
Stock Based Compensation (NonOp
Stock Based Compensation (NonOption) (Details) $ / shares in Units, $ in Millions | 9 Months Ended | |
Sep. 30, 2019USD ($)$ / sharesshares | Sep. 30, 2018USD ($)$ / sharesshares | |
Stock-based compensation | ||
Shares available for grant | 1,200,000 | |
Restricted Stock [Member] | ||
Activity, shares | ||
Canceled/Forfeited (in shares) | (63,909) | (152,294) |
Activity, weighted average fair value | ||
Granted (in dollars per share) | $ / shares | $ 2.91 | $ 3.76 |
Stock-based compensation | ||
Compensation expense not yet recognized | $ | $ 1.2 | |
Compensation expense, remaining weighted average vesting period | 1 year 8 months 12 days | |
Value of issued stock | $ | $ 1.1 | $ 1.2 |
Weighted average forfeiture rate | 0 | 0 |
Value of restricted shares forfeited | $ | $ 0.3 | $ 1 |
Stock-based compensation expense | $ | $ 1.7 | $ 3.2 |
Performance Stock Units [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period | 3 years | |
Activity, shares | ||
Granted (in shares) | 117,105 | 190,782 |
Canceled/Forfeited (in shares) | (49,773) | (182,227) |
Activity, weighted average fair value | ||
Granted (in dollars per share) | $ / shares | $ 6.42 | $ 7.69 |
Stock-based compensation | ||
Compensation expense not yet recognized | $ | $ 1 | |
Compensation expense, remaining weighted average vesting period | 1 year 10 months 24 days | |
Target (as a percent) | 100.00% | |
Stock-based compensation expense | $ | $ 0.5 | $ 0.6 |
Executive Officers and 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) | 307,650 | |
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 | |
Board of Directors [Member] | Restricted Stock [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting period | 1 year | |
Activity, shares | ||
Granted (in shares) | 80,410 | 82,500 |
Former President and CEO | Restricted Stock [Member] | ||
Activity, shares | ||
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% |
Stock Based Compensation (Optio
Stock Based Compensation (Options) (Details) - Employee Stock Options [Member] - USD ($) | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
Option roll forward | ||
Stock options granted in period (in shares) | 0 | 0 |
Exercise of stock options, shares | 0 | 0 |
Expired / Forfeited (in shares) | (12,673) | (4,500) |
Stock-based compensation | ||
Excess tax benefit from exercise/cancellation of stock options | $ 0 | $ 0 |
Leases - Balance sheet (Details
Leases - Balance sheet (Details) $ in Thousands | 9 Months Ended |
Sep. 30, 2019USD ($) | |
Leases | |
Lease, Practical Expedients, Package [true false] | true |
Balance sheet information | |
Operating lease right of use asset - current | $ 690 |
Operating lease right of use asset - long-term | 489 |
Total operating lease right of use asset | 1,179 |
Operating lease liability - current | $ (690) |
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | Accounts Payable and Accrued Liabilities, Current |
Operating lease liability - long-term | $ (489) |
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | Other Liabilities, Noncurrent |
Total operating lease liability | $ (1,179) |
Financing lease right of use asset - current | 19 |
Financing lease right of use asset - long-term | 70 |
Total financing lease right of use asset | 89 |
Financing lease liability - current | $ (17) |
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List] | Accounts Payable and Accrued Liabilities, Current |
Financing lease liability - long-term | $ (74) |
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] | Other Liabilities, Noncurrent |
Total financing lease liability | $ (91) |
Leases - Lease Terms and Discou
Leases - Lease Terms and Discount (Details) | Sep. 30, 2019 |
Leases | |
Weighted Average Remaining Lease Terms (in months): Operating leases | 21 months |
Weighted Average Remaining Lease Terms (in months): Financing leases | 57 months |
Weighted Average Discount Rate: Operating leases | 5.31% |
Weighted Average Discount Rate: Financing leases | 6.00% |
Leases - Future Maturities (Det
Leases - Future Maturities (Details) $ in Thousands | Sep. 30, 2019USD ($) |
Operating lease maturities | |
2019 (remaining after September 30, 2019) | $ 170 |
2020 | 677 |
2021 | 324 |
2022 | 8 |
Total operating lease liability | 1,179 |
Less: imputed interest | (57) |
Present value of lease liabilities | 1,122 |
Finance lease maturities | |
2019 (remaining after September 30, 2019) | 6 |
2020 | 17 |
2021 | 18 |
2022 | 19 |
2023 | 20 |
2024 | 11 |
Total financing lease liability | 91 |
Less: imputed interest | (14) |
Present value of lease liabilities | $ 77 |
Leases - Costs (Details)
Leases - Costs (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended |
Sep. 30, 2019 | Sep. 30, 2019 | |
Leases | ||
Operating lease cost | $ 138 | $ 609 |
Financing lease cost | 5 | 5 |
Administrative lease cost | 19 | 56 |
Short-term lease cost | 781 | 3,359 |
Total net lease cost | $ 943 | 4,029 |
Cash payments relating to operating leases | 228 | |
Cash payments relating to finance leases | $ 4 |
Other Financial Information (Ba
Other Financial Information (Balance Sheet) (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Sep. 30, 2019 | Dec. 31, 2018 | |
Accounts receivable: | ||
Trade receivables | $ 4,463 | $ 6,052 |
Receivable for Alta Resources Distribution | 1,712 | 1,993 |
Joint interest billings | 4,005 | 3,833 |
Income taxes receivable | 878 | 424 |
Other receivables | 1,054 | 223 |
Allowance for doubtful accounts | (994) | (994) |
Total accounts receivable | 11,118 | 11,531 |
Prepaid expenses and other: | ||
Prepaid insurance | 848 | 792 |
Other | 147 | 511 |
Total prepaid expenses and other | 995 | 1,303 |
Accounts payable and accrued liabilities: | ||
Royalties and revenue payable | 12,704 | 17,986 |
Advances from partners | 13,657 | 1,785 |
Accrued exploration and development | 12,036 | 4,751 |
Accrued acquisition costs | 3,763 | 4,352 |
Trade payables | 12,441 | 3,385 |
Accrued general and administrative expenses | 4,365 | 2,545 |
Accrued operating expenses | 1,651 | 1,801 |
Other accounts payable and accrued liabilities | 2,127 | 2,901 |
Total accounts payable and accrued liabilities | 62,744 | $ 39,506 |
Litigation Case Harris County [Member] | ||
Accounts payable and accrued liabilities: | ||
Loss contingency provision accrual increase | $ 2,100 |
Other Financial Information (Su
Other Financial Information (Supplemental CFS) (Details) - USD ($) $ in Thousands | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
Cash payments: | ||
Interest payments | $ 3,037 | $ 3,846 |
Income tax payments | 668 | 81 |
Non-cash investing activities in the consolidated statements of cash flows: | ||
Increase (decrease) in accrued capital expenditures | $ 7,284 | $ 2,764 |
Investment in Exaro Energy II_2
Investment in Exaro Energy III LLC (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Schedule of Equity Method Investments Financials | ||||
Gain (loss) from investment in affiliates, net of income taxes | $ (608) | $ (270) | $ (151) | $ (38) |
Exaro Energy III LLC [Member] | ||||
Schedule of Equity Method Investments Financials | ||||
Equity method investment, ownership percentage | 37.00% | 37.00% | ||
Share of equity in investment | $ 5,900 | $ 5,900 | ||
Gain (loss) from investment in affiliates, net of income taxes | (600) | (300) | 100 | (38) |
Tax (expense) benefit from equity investment | $ 0 | $ 0 | $ 0 | $ 0 |
Long-Term Debt (Details)
Long-Term Debt (Details) $ in Thousands | Sep. 17, 2019USD ($) | Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Nov. 01, 2019USD ($) | Dec. 31, 2018USD ($) |
Debt Instrument [Line Items] | |||||||
Debt issuance costs incurred | $ 1,402 | ||||||
Interest expense | $ 998 | $ 1,411 | 3,169 | $ 4,082 | |||
JPMorgan Chase Bank [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Maximum borrowing capacity | $ 65,000 | $ 145,000 | |||||
Line of credit, available | 35,000 | 35,000 | |||||
Credit facility amount outstanding | 28,100 | 28,100 | |||||
Letters of credit amount outstanding | $ 1,900 | $ 1,900 | |||||
Weighted average interest rate (as a percent) | 5.40% | 5.40% | |||||
Current ratio, minimum | 1 | ||||||
Leverage ratio, maximum | 3.50 | ||||||
RBC Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Credit facility amount outstanding | $ 60,000 | ||||||
Letters of credit amount outstanding | $ 1,900 | ||||||
Weighted average interest rate (as a percent) | 6.30% |
Income Taxes (Expense Benefit)
Income Taxes (Expense Benefit) (Details) - USD ($) $ in Thousands, shares in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Dec. 31, 2018 | |
Current tax provision: | |||||
State | $ 30 | $ (21) | $ 484 | $ 288 | |
Total | 30 | (21) | 484 | 288 | |
Total tax provision: | |||||
State | 30 | (21) | 484 | 288 | |
Income tax provision | $ 30 | $ (21) | $ 484 | $ 288 | |
Annual carryover limitation | $ 2,400 | ||||
Equity offering-common stock, shares | 51.4 |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 9 Months Ended | |||
Nov. 30, 2010USD ($)site | Sep. 30, 2019USD ($) | Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Aug. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
Legal Proceedings | ||||||
Accounts payable and accrued liabilities | $ 62,744 | $ 62,744 | $ 39,506 | |||
Lavaca County Case [Member] | ||||||
Legal Proceedings | ||||||
Number of wells involved in litigation | site | 2 | |||||
Damages sought by plaintiffs | $ 5,300 | |||||
Litigation Case Harris County [Member] | ||||||
Legal Proceedings | ||||||
Accounts payable | $ 1,100 | |||||
Loss contingency provision accrual increase | 2,100 | |||||
Throughput commitment | ||||||
Loss Contingency | ||||||
Fees incurred | 700 | $ 700 | ||||
Estimated deficiency | $ 500 | $ 500 |