Document And Entity Information
Document And Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017 | Mar. 12, 2018 | Jun. 30, 2017 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Gastar Exploration Inc. | ||
Trading Symbol | GST | ||
Entity Central Index Key | 1,431,372 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Accelerated Filer | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 116 | ||
Entity Common Stock, Shares Outstanding | 220,895,069 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS: | ||
Cash and cash equivalents | $ 13,266 | $ 71,529 |
Accounts receivable, net of allowance for doubtful accounts of $1,953 | 38,575 | 26,883 |
Commodity derivative contracts | 1,370 | 6,212 |
Prepaid expenses | 960 | 755 |
Total current assets | 54,171 | 105,379 |
Oil and natural gas properties, full cost method of accounting: | ||
Unproved properties, excluded from amortization | 131,955 | 67,333 |
Proved properties | 1,344,329 | 1,253,061 |
Total natural gas and oil properties | 1,476,284 | 1,320,394 |
Furniture and equipment | 3,838 | 2,622 |
Total property, plant and equipment | 1,480,122 | 1,323,016 |
Accumulated depreciation, depletion and amortization | (1,155,027) | (1,131,012) |
Total property, plant and equipment, net | 325,095 | 192,004 |
OTHER ASSETS: | ||
Restricted cash | 370 | 0 |
Commodity derivative contracts | 0 | 1,638 |
Deferred charges, net | 0 | 676 |
Advances to operators | 82 | 102 |
Other | 405 | 405 |
Total other assets | 857 | 2,821 |
TOTAL ASSETS | 380,123 | 300,204 |
CURRENT LIABILITIES: | ||
Accounts payable | 24,382 | 8,867 |
Revenue payable | 11,823 | 6,690 |
Accrued interest | 7,298 | 3,515 |
Accrued drilling and operating costs | 9,381 | 2,615 |
Advances from non-operators | 1,445 | 3,504 |
Commodity derivative contracts | 4,416 | 338 |
Commodity derivative premium payable | 135 | 1,654 |
Asset retirement obligation | 0 | 89 |
Other accrued liabilities | 2,706 | 2,462 |
Total current liabilities | 61,586 | 29,734 |
LONG-TERM LIABILITIES: | ||
Long-term debt, net | 342,952 | 404,493 |
Commodity derivative contracts | 2,572 | 0 |
Commodity derivative premium payable | 0 | 969 |
Asset retirement obligation | 4,841 | 5,443 |
Total long-term liabilities | 350,365 | 410,905 |
Commitments and contingencies (Note 13) | ||
STOCKHOLDERS’ DEFICIT: | ||
Common Stock, par value $0.001 per share; 800,000,000 and 550,000,000 shares authorized at December 31, 2017 and 2016, respectively; 218,874,418 and 150,377,870 shares issued and outstanding at December 31, 2017 and 2016, respectively | 219 | 150 |
Additional paid-in capital | 819,554 | 644,306 |
Accumulated deficit | (851,663) | (784,953) |
Total stockholders’ deficit | (31,828) | (140,435) |
TOTAL LIABILITIES AND STOCKHOLDERS’ DEFICIT | 380,123 | 300,204 |
Series A Preferred Stock | ||
STOCKHOLDERS’ DEFICIT: | ||
Preferred stock | 41 | 41 |
Series B Preferred Stock | ||
STOCKHOLDERS’ DEFICIT: | ||
Preferred stock | $ 21 | $ 21 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Allowance for doubtful accounts | $ 1,953 | $ 1,953 |
Preferred stock, shares authorized | 40,000,000 | 40,000,000 |
Common stock, par value | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 800,000,000 | 550,000,000 |
Common stock, shares issued | 218,874,418 | 150,377,870 |
Common stock, shares outstanding | 218,874,418 | 150,377,870 |
Series A Preferred Stock | ||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares issued | 4,045,000 | 4,045,000 |
Preferred stock, shares outstanding | 4,045,000 | 4,045,000 |
Liquidation preference per share | $ 25 | $ 25 |
Series B Preferred Stock | ||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares issued | 2,140,000 | 2,140,000 |
Preferred stock, shares outstanding | 2,140,000 | 2,140,000 |
Liquidation preference per share | $ 25 | $ 25 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
REVENUES: | |||
Oil and condensate | $ 54,667,000 | $ 43,011,000 | $ 58,668,000 |
Natural gas | 10,079,000 | 10,854,000 | 16,901,000 |
NGLs | 11,841,000 | 7,252,000 | 7,136,000 |
Total oil and condensate, natural gas and NGLs revenues | 76,587,000 | 61,117,000 | 82,705,000 |
(Loss) gain on commodity derivatives contracts | (4,457,000) | (2,863,000) | 24,589,000 |
Total revenues and other (loss) gain | 72,130,000 | 58,254,000 | 107,294,000 |
EXPENSES: | |||
Production taxes | 2,830,000 | 1,908,000 | 2,877,000 |
Lease operating expenses | 22,195,000 | 20,605,000 | 23,728,000 |
Transportation, treating and gathering | 1,814,000 | 1,704,000 | 2,187,000 |
Depreciation, depletion and amortization | 24,015,000 | 29,673,000 | 62,887,000 |
Impairment of natural gas and oil properties | 0 | 48,497,000 | 426,878,000 |
Accretion of asset retirement obligation | 237,000 | 368,000 | 502,000 |
General and administrative expense | 16,842,000 | 19,445,000 | 17,069,000 |
Litigation settlement benefit | 0 | (10,100,000) | 0 |
Total expenses | 67,933,000 | 112,100,000 | 536,128,000 |
INCOME (LOSS) FROM OPERATIONS | 4,197,000 | (53,846,000) | (428,834,000) |
OTHER (EXPENSE) INCOME: | |||
Interest expense | (38,955,000) | (35,246,000) | (30,686,000) |
Loss on early extinguishment of debt | (12,172,000) | 0 | 0 |
Investment and other income | 175,000 | 31,000 | 13,000 |
LOSS BEFORE PROVISION FOR INCOME TAXES | (46,755,000) | (89,061,000) | (459,507,000) |
Provision for income taxes | 0 | 0 | 0 |
NET LOSS | (46,755,000) | (89,061,000) | (459,507,000) |
Dividends on preferred stock | (8,443,000) | (3,618,000) | (14,473,000) |
Undeclared cumulative dividends on preferred stock | (6,030,000) | (10,855,000) | 0 |
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS | $ (61,228,000) | $ (103,534,000) | $ (473,980,000) |
NET LOSS PER SHARE OF COMMON STOCK ATTRIBUTABLE TO COMMON STOCKHOLDERS: | |||
Basic (in dollars per share) | $ (0.31) | $ (0.93) | $ (6.11) |
Diluted (in dollars per share) | $ (0.31) | $ (0.93) | $ (6.11) |
WEIGHTED AVERAGE SHARES OF COMMON STOCK OUTSTANDING: | |||
Basic (shares) | 195,369,489 | 111,367,452 | 77,511,677 |
Diluted (shares) | 195,369,489 | 111,367,452 | 77,511,677 |
Consolidated Statement of Stock
Consolidated Statement of Stockholders' Equity (Deficit) - USD ($) $ in Thousands | Total | Common Stock | Additional Paid-in Capital | Accumulated Deficit | Series A Preferred StockPreferred Stock | Series B Preferred StockPreferred Stock |
Balance at beginning of period at Dec. 31, 2014 | $ 350,286 | $ 78 | $ 568,440 | $ (218,294) | $ 41 | $ 21 |
Balance at beginning of period (in shares) at Dec. 31, 2014 | 78,632,810 | 4,045,000 | 2,140,000 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Issuance of common shares - PBUs vesting, net of forfeitures | $ 1 | (1) | ||||
Issuance of common shares - PBUs vesting, net of forfeitures (shares) | 497,636 | |||||
Issuance of restricted stock | $ 1 | (1) | ||||
Issuance of restricted stock (shares) | 1,426,604 | |||||
Forfeitures of restricted stock | (1,472) | (1,472) | ||||
Forfeitures of restricted stock (shares) | (532,832) | |||||
Stock-based compensation | 4,981 | 4,981 | ||||
Preferred stock dividends | (14,473) | (14,473) | ||||
Net loss | (459,507) | (459,507) | ||||
Balance at end of period at Dec. 31, 2015 | (120,185) | $ 80 | 571,947 | (692,274) | $ 41 | $ 21 |
Balance at end of period (in shares) at Dec. 31, 2015 | 80,024,218 | 4,045,000 | 2,140,000 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Issuance of common shares - cash, net of offering costs | 44,813 | $ 50 | 44,763 | |||
Issuance of common shares - cash, net of offering costs (shares) | 50,000,000 | |||||
Issuance of common shares under ATM - cash, net of offering costs | 24,411 | $ 19 | 24,392 | |||
Issuance of common shares under ATM - cash, net of offering costs (shares) | 18,606,943 | |||||
Issuance of common shares - PBUs vesting, net of forfeitures | $ 1 | (1) | ||||
Issuance of common shares - PBUs vesting, net of forfeitures (shares) | 502,593 | |||||
Issuance of restricted stock | $ 1 | (1) | ||||
Issuance of restricted stock (shares) | 1,764,645 | |||||
Forfeitures of restricted stock | (713) | $ (1) | (712) | |||
Forfeitures of restricted stock (shares) | (520,529) | |||||
Stock-based compensation | 3,918 | 3,918 | ||||
Preferred stock dividends | (3,618) | (3,618) | ||||
Net loss | (89,061) | (89,061) | ||||
Balance at end of period at Dec. 31, 2016 | (140,435) | $ 150 | 644,306 | (784,953) | $ 41 | $ 21 |
Balance at end of period (in shares) at Dec. 31, 2016 | 150,377,870 | 4,045,000 | 2,140,000 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||||
Cumulative effect of adoption of accounting standard | 657 | (657) | ||||
Issuance of common shares - cash, net of offering costs | 48,021 | $ 29 | 47,992 | |||
Issuance of common shares - cash, net of offering costs (shares) | 29,408,305 | |||||
Issuance of common shares under ATM - cash, net of offering costs | 8,345 | $ 6 | 8,339 | |||
Issuance of common shares under ATM - cash, net of offering costs (shares) | 5,447,919 | |||||
Conversion option relating to Convertible Notes, net of allocated costs | 75,462 | 75,462 | ||||
Issuance of common shares in debt conversion | 37,500 | $ 26 | 37,474 | |||
Issuance of common shares in debt conversion (shares) | 25,456,521 | |||||
Issuance of restricted stock | $ 8 | (8) | ||||
Issuance of restricted stock (shares) | 8,649,345 | |||||
Forfeitures of restricted stock | (589) | (589) | ||||
Forfeitures of restricted stock (shares) | (465,542) | |||||
Stock-based compensation | 5,921 | 5,921 | ||||
Preferred stock dividends | (19,298) | (19,298) | ||||
Net loss | (46,755) | (46,755) | ||||
Balance at end of period at Dec. 31, 2017 | $ (31,828) | $ 219 | $ 819,554 | $ (851,663) | $ 41 | $ 21 |
Balance at end of period (in shares) at Dec. 31, 2017 | 218,874,418 | 4,045,000 | 2,140,000 |
Consolidated Statement of Stoc6
Consolidated Statement of Stockholders' Equity (Deficit) (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Statement Of Stockholders Equity [Abstract] | ||
Issuance of common shares- cash, offering costs | $ 1,979 | $ 2,687 |
Issuance of common shares under ATM- cash, offering costs | $ 172 | $ 557 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||
Net loss | $ (46,755) | $ (89,061) | $ (459,507) | |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||||
Depreciation, depletion and amortization | 24,015 | 29,673 | 62,887 | |
Impairment of natural gas and oil properties | 0 | 48,497 | 426,878 | |
Stock-based compensation | 5,921 | 3,918 | 4,981 | |
Total loss (gain) on commodity derivatives contracts | 4,457 | 2,863 | (24,589) | |
Cash settlements of matured commodity derivative contracts, net | 8,181 | 13,110 | 24,910 | |
Cash premiums paid for commodity derivatives contracts | (1,418) | (565) | (45) | |
Amortization of deferred financing costs and debt discount | [1] | 10,977 | 4,980 | 3,584 |
Paid-in-kind interest | 6,599 | 0 | 0 | |
Accretion of asset retirement obligation | 237 | 368 | 502 | |
Settlement of asset retirement obligation | 0 | (307) | (83) | |
Loss on sale of furniture and equipment | 0 | 97 | 0 | |
Loss on early extinguishment of debt | 12,172 | 0 | 0 | |
Changes in operating assets and liabilities: | ||||
Accounts receivable | (12,345) | (14,850) | 19,333 | |
Prepaid expenses | (205) | 4,301 | (2,973) | |
Accounts payable and accrued liabilities | 8,226 | 3,713 | (4,606) | |
Net cash provided by operating activities | 20,062 | 6,737 | 51,272 | |
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||
Development and purchase of oil and natural gas properties | (107,748) | (59,922) | (148,182) | |
(Acquisition of) refund for oil and natural gas properties | (54,496) | 1,143 | (45,575) | |
Proceeds from sale of oil and natural gas properties | 28,781 | 121,273 | 47,314 | |
(Application) receipt of proceeds from non-operators | (2,059) | 3,337 | (1,653) | |
(Advances to) reimbursements from operators | (44) | 576 | (2,302) | |
(Purchase) sale of furniture and equipment | (1,216) | 73 | (58) | |
Net cash (used in) provided by investing activities | (136,782) | 66,480 | (150,456) | |
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||
Proceeds from term loan | 250,000 | 0 | 0 | |
Proceeds from convertible notes | 200,000 | 0 | 0 | |
Repayment of senior secured notes | (325,000) | 0 | 0 | |
Proceeds from revolving credit facility | 0 | 0 | 196,000 | |
Repayment of revolving credit facility | (84,630) | (115,370) | (41,000) | |
Loss on early extinguishment of debt | (7,011) | 0 | 0 | |
Proceeds from issuance of common stock, net of issuance costs | 56,366 | 69,224 | 0 | |
Dividends paid on preferred stock | (19,298) | (3,618) | (14,473) | |
Deferred financing charges | (11,011) | (1,285) | (805) | |
Increase in restricted cash | (370) | 0 | 0 | |
Tax withholding related to restricted stock and PBU vestings | (589) | (713) | (1,472) | |
Net cash provided by (used in) financing activities | 58,457 | (51,762) | 138,250 | |
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS | (58,263) | 21,455 | 39,066 | |
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 71,529 | 50,074 | 11,008 | |
CASH AND CASH EQUIVALENTS, END OF PERIOD | $ 13,266 | $ 71,529 | $ 50,074 | |
[1] | The year ended December 31, 2017 includes $2.7 million and $6.1 million of debt discount accretion related to the Term Loan and Notes, respectively. The years ended December 31, 2017, 2016 and 2015 include $495,000, $2.8 million and $2.5 million, respectively, of debt discount accretion related to the Former Notes. |
Description of Business
Description of Business | 12 Months Ended |
Dec. 31, 2017 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Description of Business | 1. Gastar Exploration Inc. (“Gastar” or the “Company”) is a pure-play Mid-Continent independent energy company engaged in the exploration, development and production of oil, condensate, natural gas and natural gas liquids (“NGLs”). Gastar’s principal business activities include the identification, acquisition and subsequent exploration and development of oil and natural gas properties with an emphasis on unconventional reserves, such as shale resource plays. Gastar holds a concentrated acreage position in the normally pressured oil window of the STACK Play, an area of central Oklahoma which is home to multiple oil and natural gas-rich reservoirs including the Oswego limestone, Meramec and Osage bench formations within the Mississippi Lime, the Woodford shale and Hunton limestone formations. On April 8, 2016, Gastar sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin for an adjusted sales price of $75.7 million, net of $3.5 million of suspense liability transferred to buyer, with an effective date of January 1, 2016 (the “Appalachian Basin Sale”). Gastar sold its remaining Appalachian Basin interests on January 20, 2017 (effective January 1, 2017) for approximately $200,000 before fees and expenses. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 2. Summary of Significant Accounting Policies Basis of Presentation The consolidated financial statements of the Company are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved oil and natural gas reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. See Note 17. “Supplemental Oil and Gas Disclosures.” Subsequent Events In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate. WEHLU Sale On January 23, 2018, the Company entered into a definitive agreement of sale and purchase (the “Sale Agreement”) to divest its interest in the West Edmund Hunton Lime Unit (“WEHLU”) and adjacent undeveloped acreage to Revolution Resources, LLC, for $107.5 million, subject to, among other customary adjustments, adjustments for a property sale effective date of October 1, 2017 (the “WEHLU Sale”). Pursuant to the Sale Agreement, the WEHLU Sale closed on February 28, 2018. After effective date and other adjustments of approximately $8.7 million primarily related to revenues and direct operating expenses, net cash proceeds from the WEHLU Sale were approximately $98.8 million, subject to certain additional adjustments for final closing. The WEHLU Sale will be reflected as a reduction to the full cost pool and the Company will not record a gain or loss related to the divestiture as such divestiture did not result in a significant change to the depletion rate. CEO Resignation On February 26 Mr. Porter will remain employed by the Company until March 31, 2018 to assist with transitional matters. Mr. Porter’s resignation did not result from any disagreement with the Company regarding any matter related to the Company’s operations, policies or practices. In connection with the departure, on February 26, 2018, Mr. Porter entered into a Separation and Release Agreement with the Company, whereby (i) Mr. Porter immediately resigned from all positions, offices and directorships with the Company and any affiliates or subsidiaries, (ii) Mr. Porter’s employment with the Company is terminated effective March 31, 2018 (the “Termination Date”); (iii) Mr. Porter agreed to enter into a release of claims (the “Release”) in favor of the Company no earlier than the Termination Date and no later than the 21 st Principles of Consolidation The consolidated financial statements of the Company include the consolidated accounts of all its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation. Use of estimates in Preparation of Financial Statements The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate, natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties. Cash and Cash Equivalents The Company’s cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $13.3 million and $71.5 million as of December 31, 2017 and 2016, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss. Accounts Receivable Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible. During 2016, the Company determined that a receivable account from a third-party natural gas and NGLs purchaser would no longer be collectible as a result of the third-party purchaser filing for bankruptcy. A summary of the activity related to the allowance for doubtful accounts is as follows: For the Years Ended December 31, 2017 2016 2015 (in thousands) Allowance for doubtful accounts, beginning of year $ 1,953 $ — $ — Expense — 1,953 — Reductions/write-offs — — — Allowance for doubtful accounts, end of year $ 1,953 $ 1,953 $ — Oil and Natural Gas Properties The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company’s only cost center. Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations. In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization. The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2017 and 2016 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered. The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted. Asset Retirement Obligation Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations. Furniture and Equipment Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years. Capitalized Interest The Company capitalizes interest on assets not being amortized, such as our unproved oil and natural gas properties. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $7.2 million, $3.1 million and $3.9 million for 2017, 2016 and 2015, respectively. Fair Value of Financial Instruments The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, and accounts and revenue payables approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value. Deferred Financing Costs and Debt Discounts Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing paid to creditors. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense. Deferred financing costs are presented as a direct reduction to the carrying amount of the related debt liability where the debt liability is not a line-of-credit arrangement. Debt discounts are recorded when it is determined that the fair value of the debt instrument at issuance is less than the face value of such instrument. The debt discounts are presented as a direct reduction to the carrying amount of the related debt liability and are amortized over the life of the debt instrument using the effective interest method. Derivative Instruments and Hedging Activity The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.” The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in gain (loss) on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in gain (loss) on commodity derivatives contracts in the Company’s consolidated statement of operations. Stock-Based Compensation The Company reports compensation expense for restricted common stock and performance based units (“PBUs”) granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards. Stock-based compensation cost for restricted shares is estimated at the grant date based on the award’s fair value, which is equal to the prior day’s closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant date based on the award’s fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. Prior to 2017, forfeitures of unvested stock options and restricted common shares historically were calculated at the beginning of the year as a percentage of all stock option and restricted common share grants. Beginning in 2017, the Company no longer applies a forfeiture rate at grant and accounts for forfeitures as they occur. For 2016 and 2015, the Company used forfeiture rates in determining compensation expense of 19.1% and 17.5%, respectively. Revenue Recognition The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company’s NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company’s wet gas production. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2017, 2016 and 2015. The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet. Deferred Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time. Earnings or Loss per Share Basic earnings or loss per share is computed by dividing net income (loss) available to common stockholders, net of accumulated paid and unpaid dividends, by the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed by dividing net income (loss) available to common stockholders, net of accumulated and unpaid dividends, by the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of unvested restricted shares and PBUs. Co-participation Operations The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities. Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long-lived assets located outside the U.S. Recent Accounting Developments Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued updated guidance to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments in this update (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments in this update affect all reporting entities that must determine whether they have acquired or sold a business and are effective for public business entities for annual reporting periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after the effective date and no disclosures are required at transition. Early application is allowed as follows (1) for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance and (2) for transactions in which a subsidiary is deconsolidated or a group of assets is derecognized that occur before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The application of this guidance to future acquisitions and disposals could have an immediate effect on the Company’s financial position or results of operations. Statement of Cash Flows. In August 2016, the FASB issued updated guidance associated with the classification of certain cash receipts and cash payments on the statement of cash flows. The amended guidance addresses specific cash flow issues with the objective of reducing existing diversity in practice. The amendment provides guidance on the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The amendments in this update apply to all entities required to present a statement of cash flows. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company adopted this update guidance for the fiscal year beginning January 1, 2018 and has determined that such adoption does not have a material effect on its statement of cash flows nor does it affect the Company’s financial position or results of operations. Compensation – Stock Compensation. In March 2016, the FASB issued updated guidance as part of its simplification initiative which is intended to simplify several aspects of the accounting for stock-based compensation transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. The Company adopted this updated guidance for the fiscal year beginning January 1, 2017 and recorded a cumulative adjustment of approximately $657,000 to retained earnings to properly reflect the adjustment to stock compensation expense to reduce the forfeiture rate to 0%. Leases. In February 2016, the FASB issued updated guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and enhance disclosures regarding key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a lease liability and a right-of-use asset for all leases. The new lease guidance also simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. The amendments in this update are effective beginning on January 1, 2019 and should be applied through a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Early adoption is permitted. The Company has begun analyzing its lease contracts but has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Income Taxes. In November 2015, the FASB issued updated guidance as part of its simplification initiative for the presentation of deferred taxes. Current U.S. GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position where such classification generally does not align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position and apply to all entities that present a classified statement of financial position, resulting in the alignment of the presentation of deferred income tax assets and liabilities with International Financial Reporting Standards, International Accounting Standard 1, . This updated guidance is effective for public business entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company has adopted this guidance prospectively and such adoption did not have an impact on its consolidated financial statements. Revenue Recognition. The Company has completed its scoping and assessment of impact of the new revenue recognition standard. The Company has evaluated a representative sample of revenue contracts related to its oil, natural gas and NGLs revenues. For these contracts, the Company has reviewed the contract provisions and evaluated the contracts under the new standard to assess the impact on the quantum and timing of revenue recognition and presentation of revenues on adoption of the new guidance. The Company believes that it has identified all material contract types and contractual features that represent the Company’s revenue. While the Company does not currently expect that the adoption of this standard will have a material impact on net profit, some reclassifications between revenue and expenses in relation to certain post-production expenses will be required based upon its assessment of i) where control passes to the customer and ii) whether the Company represents the principal or agent in certain of its revenue contracts. Beginning in 2018, the Company will record transportation, treating and gathering expenses as a direct reduction to oil, condensate, natural gas and NGLs revenues rather than as expenses. In addition, the Company’s disclosures surrounding revenue recognition will be more substantial upon adoption. The Company adopted this standard on January 1, 2018 using the modified retrospective method, in which the standard will be applied to all existing contracts as of the date of initial application with the cumulative effect of applying the standard recognized in retained earnings (the adoption date adjustments). Based on initial adoption, no adjustment to retained earnings is required. |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Property Plant And Equipment [Abstract] | |
Property, Plant and Equipment | 3. Property, Plant and Equipment The amount capitalized as oil and natural gas properties was incurred for the purchase and development of various properties in the U.S., specifically the states of Oklahoma, Pennsylvania and West Virginia. On April 8, 2016, the Company sold substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in Pennsylvania and West Virginia comprising the Company’s assets in the Appalachian Basin. On January 20, 2017, the Company sold its remaining interest in producing wells and undeveloped acreage in West Virginia, effective January 1, 2017, for $200,000 before fees and expenses. The Company’s total property, plant and equipment consists of the following: December 31, 2017 2016 (in thousands) Oil and natural gas properties, full cost method of accounting: Unproved properties $ 131,955 $ 67,333 Proved properties 1,344,329 1,253,061 Total oil and natural gas properties 1,476,284 1,320,394 Furniture and equipment 3,838 2,622 Total property and equipment 1,480,122 1,323,016 Impairment of proved natural gas and oil properties (813,314 ) (813,314 ) Accumulated depreciation, depletion and amortization (341,713 ) (317,698 ) Total accumulated depreciation, depletion and amortization (1,155,027 ) (1,131,012 ) Total property and equipment, net $ 325,095 $ 192,004 The following table summarizes the components of unproved properties excluded from amortization for the periods indicated: December 31, 2017 2016 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 4,772 $ 1,100 Acreage acquisition costs 113,191 58,857 Capitalized interest 13,992 7,376 Total unproved properties excluded from amortization $ 131,955 $ 67,333 The full cost method of accounting for oil and natural gas properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the present value of estimated future cash flow from proved oil, condensate, natural gas and NGLs reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage) to the extent not included in oil and natural gas properties pursuant to authoritative guidance and estimated future income taxes thereon. To the extent that the Company’s capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense for such period. Once incurred, this impairment of oil and natural gas properties is not reversible at a later date even if oil and natural gas prices increase. The ceiling calculation is determined using a mandatory trailing 12-month unweighted arithmetic average of the first-day-of-the-month commodities pricing and costs in effect at the end of the period, each of which are held constant indefinitely (absent specific contracts with respect to future prices and costs) with respect to valuing future net cash flows from proved reserves for this purpose. The 12-month unweighted arithmetic average of the first-day-of-the-month commodities prices are adjusted for basis and quality differentials in determining the present value of the proved reserves. The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials: 2017 Total December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.98 $ 3.00 $ 3.01 $ 2.73 West Texas Intermediate oil price (per Bbl) (1) $ 51.34 $ 49.81 $ 48.95 $ 47.61 Impairment recorded (pre-tax) (in thousands) $ — $ — $ — $ — $ — 2016 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.48 $ 2.28 $ 2.24 $ 2.40 West Texas Intermediate oil price (per Bbl) (1) $ 42.75 $ 41.68 $ 43.12 $ 46.26 Impairment recorded (pre-tax) (in thousands) $ 48,497 $ — $ — $ — $ 48,497 2015 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.59 $ 3.06 $ 3.39 $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 50.28 $ 59.21 $ 71.68 $ 82.72 Impairment recorded (pre-tax) (in thousands) $ 426,878 $ 144,760 $ 181,966 $ 100,152 $ — (1) For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub spot natural gas prices and West Texas Intermediate spot oil prices. The Company could potentially incur ceiling test impairments in the future should commodities prices decline. However, it is difficult to project future impairment charges in light of numerous variables involved. The Company’s proved reserves estimates and their estimated discounted value and standardized measure will also be impacted by changes in lease operating costs, future development costs, production, exploration and development activities. The ceiling limitation calculation is not intended to be indicative of the fair market value of the Company’s proved reserves or future results. WEHLU Sale On January 23, 2018, the Company entered into the Sale Agreement to divest its interest in WEHLU and adjacent undeveloped acreage to Revolution Resources, LLC, for $107.5 million, subject to, among other customary adjustments, adjustments for a property sale effective date of October 1, 2017 (the “WEHLU Sale”). The Company received a deposit of $10.7 million into an escrow account on January 25, 2018. Pursuant to the Sale Agreement, the WEHLU Sale closed on February 28, 2018. After effective date and other adjustments of approximately $8.7 million primarily related to revenues and direct operating expenses, net cash proceeds from the WEHLU Sale were approximately $98.8 million, subject to certain additional adjustments for final closing. The WEHLU Sale will be reflected as a reduction to the full cost pool and the Company will not record a gain or loss related to the divestiture as such divestiture did not result in a significant change to the depletion rate. STACK Leasehold Acquisition On March 22, 2017, the Company completed the acquisition of additional working and net revenue interests in approximately 66 gross (9.5 net) producing wells and 5,670 net acres of additional undeveloped STACK Play leasehold in Kingfisher County, Oklahoma, effective March 1, 2017, for $51.4 million (the “STACK Leasehold Acquisition”). Prior to the completion of the STACK Leasehold Acquisition, the Company held an interest in the majority of acquired producing wells and acreage. The Company accounted for the STACK Leasehold Acquisition as an asset acquisition. Development Agreement On October 14, 2016, the Company executed an agreement with STACK Exploration LLC (the “Investor”) (the “Development Agreement”) to jointly develop up to 60 Gastar operated wells in the STACK Play in Kingfisher County, Oklahoma (the “Drilling Program”). The Drilling Program targeted the Meramec and Osage formations within the Mississippi Lime in a contract area within three townships covering approximately 32,900 gross (21,200 net) undeveloped mineral acres under leases held by the Company. The Company serves as operator of all Drilling Program wells. Under the Development Agreement, the Investor funded 90% of the Company’s working interest portion of drilling and completion costs to initially earn 80% of the Company’s working interest in each new well (in each case, proportionately reduced by other participating working interests in the well). As a result, the Company paid 10% of its working interest portion of such costs for 20% of its original working interest. The proposed Drilling Program wells were to be mutually developed in three tranches of 20 wells each. The locations of the first 20 wells, comprised of 18 Meramec formation wells and two Osage formation wells, were mutually agreed upon by the Company and the Investor. Participation in the second tranche of 20 Drilling Program wells was to be at the election of the Investor and the third tranche of 20 wells would require mutual consent. On July 31, 2017, the Investor elected not to participate in the second tranche of wells. With respect to each 20-well tranche, when the Investor has achieved an aggregate 15% internal rate of return for its investment in the tranche, Investor’s interest will be reduced from 80% to 40% of the Company’s original working interest and the Company’s working interest increases from 20% to 60% of the its original working interest. When a tranche internal rate of return of 20% is achieved by the Investor, Investor’s working interest decreases to 10% and the Company’s working interest increases to 90% of the working interest originally owned by the Company. If and when the final reversion of working interest in the completed 20 well tranche should occur, the Investor has the right, but not the obligation, for a period of six months to cause the Company to purchase the Investor’s remaining interest in the 20 wells in the Drilling Program (the “WI Tail”) for such tranche (the “Investor Put Right”) for fair market value by applying the methodology to determine a 15% discounted present value as defined by the Development Agreement. If the Investor fails to exercise the Investor Put Right within the six-month period after achieving final reversion, then for a period of six months thereafter, the Company shall have the right, but not the obligation, to purchase the WI Tail from the Investor on the same fair market value approach of the Investor Put Right. If final reversion has not been achieved by August 19, 2024, Investor will, for a period of six months thereafter, have the right to cause the Company to buy Investor’s then-current interest in the Drilling Program wells at an agreed upon valuation. Based on current commodity prices, well cost and production performance of the completed wells drilled in the first tranche, the 15% internal rate of return is not anticipated to be achieved. By December 31, 2017, the Company and the Investor had completed all 20 gross (15.8 net; 3.2 net to the Company) wells within the first tranche of the Drilling Program. Canadian County Property Sale On October 19, 2016, the Company entered into a purchase and sale agreement to sell certain non-core leasehold interests in approximately 25,300 net acres of which only 19,100 net acres was ascribed allocated value and interests in 25 gross (11.2 net) wells primarily in northeast Canadian County and also in southeast Kingfisher County, Oklahoma to Red Bluff Resources Operating, LLC (“Red Bluff”) for approximately $71.0 million (of which up to $10.0 million was contingent upon the satisfaction of certain conditions), subject to certain adjustments and with a property sale effective date of August 1, 2016 (“South STACK Play Acreage Sale”). On November 18, 2016, the Company and Red Bluff executed and delivered two amendments to the sale agreement and entered into a relating closing agreement, which, among other things, allocated $1.4 million of the purchase price to producing properties with the remainder of the purchase price to non-producing properties. As of December 31, 2016, the Company had received approximately $48.6 million of sales proceeds from the South STACK Play Acreage Sale. As of September 30, 2017, the sale was completed and the Company had received approximately $69.5 million of total sales proceeds from the South STACK Play Acreage Sale. The sale was reflected as a reduction to the full cost pool and no adjustment to the income statement was necessary as it was determined not to be significant. Appalachian Basin Sale On February 19, 2016, the Company entered into an agreement to sell substantially all of its producing assets and proved reserves and a significant portion of its undeveloped acreage in the Appalachian Basin Sale for $80.0 million, subject to customary closing adjustments. Pursuant to the agreement, on April 8, 2016, the Company completed the Appalachian Basin Sale for an adjusted sales price of $75.7 million, net of $3.5 million of suspense liability transferred to the buyer. The Appalachian Basin Sale was reflected as a reduction to the full cost pool and no adjustment to the income statement was necessary as it was determined not to be significant. Appalachian Basin Sale Pro Forma Operating Results The following unaudited pro forma results for the years ended December 31, 2016 and 2015 show the effect on the Company’s consolidated results of operations as if the Appalachian Basin Sale had occurred at the beginning of the periods presented. The pro forma results are the result of excluding from the statement of operations of the Company the revenues and direct operating expenses for the properties divested adjusted for (1) the reduction in asset retirement obligation (“ARO”) liabilities and accretion expense for the properties divested, (2) the reduction in depreciation, depletion and amortization expense as a result of the divestiture and (3) the reduction in interest expense as a result of the pay down of debt under the Revolving Credit Facility (as defined below) in conjunction with the closing of the Appalachian Basin Sale. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Years Ended December 31, 2016 2015 (in thousands, except (Unaudited) Revenues $ 55,177 $ 93,783 Net loss $ (98,459 ) $ (464,788 ) Loss per share: Basic $ (0.88 ) $ (6.00 ) Diluted $ (0.88 ) $ (6.00 ) The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Appalachian Basin Sale occurred as presented. In addition, future results may vary significantly from the results reflected in such pro forma information. Husky Acquisition On December 16, 2015, the Company completed the acquisition of additional working and net revenue interests in 103 gross (10.2 net) producing wells and certain undeveloped acreage in the STACK Play and Hunton Limestone formations in its existing AMI from its AMI co-participant Husky Ventures, Inc. (“Husky”) and certain affiliates for an adjusted purchase price of approximately $42.7 million, net of $358,000 of revenue suspense liability assumed by the Company (the “Husky Acquisition”). The adjusted purchase price reflected an adjustment for an acquisition effective date of July 1, 2015 and included a $4.3 million deposit into escrow pending the resolution of title defects by the seller and the purchase of overrides recorded in other assets at December 31, 2015. Additionally, the Company conveyed approximately 11,000 net non-core, non-producing acres in Blaine, Major and Kingfisher Counties, Oklahoma to the sellers. As of December 31, 2016, all title defects had been resolved by the seller and the escrow funds had been released. In connection with the acquisition, the AMI participation agreements with the Company’s AMI co-participant were dissolved. The Company accounted for the acquisition as a business combination and therefore, recorded the assets acquired at their estimated acquisition date fair values. The Company incurred $1.5 million of transaction and integration costs associated with the acquisition and expensed these costs as incurred as general and administrative expenses. The Company utilized relevant market assumptions to determine fair value and allocate the purchase price, such as future commodity prices, projections of estimated natural gas and oil reserves, expectations for future development and operating costs, projections of future rates of production, expected recovery rates and market multiples for similar transactions. Many of the assumptions used are unobservable and as such, represent Level 3 inputs under the fair value hierarchy as described in Note 6, “Fair Value Measurements.” The Company’s assessment of the fair value of the Husky Acquisition assets resulted in a fair market valuation of $44.6 million. As the fair market valuation varied less than 6% from the purchase price allocation recorded, no adjustment was made to the purchase price allocation. The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Husky Acquisition (in thousands): Consideration: Cash consideration $ 42,085 Conveyance of undeveloped acreage — Total purchase price $ 42,085 Estimated Fair Value of Assets Acquired: Unproved properties $ 27,875 Proved properties 15,592 Other (1,382 ) Total assets acquired $ 42,085 Husky Acquisition Unaudited Pro Forma Operating Results The following unaudited pro forma results for the year ended December 31, 2015 shows the effect on the Company’s consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired and (2) additional depreciation, depletion and amortization expense as a result of the Company’s increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Husky Acquisition assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Year Ended December 31, 2015 (in thousands, except (Unaudited) Revenues $ 115,147 Net loss $ (470,874 ) Loss per share: Basic $ (6.07 ) Diluted $ (6.07 ) The pro forma information above includes numerous assumptions, is presented for illustrative purposes only and may not be indicative of the future results or results of operations that would have actually occurred had the Husky Acquisition occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information. |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Debt Disclosure [Abstract] | |
Long-Term Debt | 4. Long-Term Debt The table below provides a reconciliation of the Company’s long-term debt balance as presented in the consolidated balance sheets for the periods presented: December 31, 2017 2016 (in thousands) Term Loan, principal balance (1) $ 256,599 $ — Less: Unamortized deferred financing costs (2) (4,724 ) — Unamortized debt discount (2) (22,464 ) — Term Loan, net $ 229,411 $ — Notes, principal balance $ 162,500 $ — Less: Unamortized deferred financing costs (2) (2,631 ) — Unamortized debt discount (2) (46,328 ) — Notes, net $ 113,541 $ — Revolving credit facility $ — $ 84,630 Former senior secured notes $ — $ 325,000 Less: Unamortized deferred financing costs — (795 ) Unamortized debt discount (4,342 ) Former senior secured notes, net $ — $ 319,863 Total long-term debt $ 342,952 $ 404,493 (1) Pursuant to Amendment No. 2 (as defined below), on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan (as defined below) to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. (2) The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan and Notes (as defined below), respectively, based on the effective interest method. Ares Investment Transactions On March 3, 2017, certain funds (the “Purchasers”) managed indirectly by Ares Management LLC (“Ares”) purchased from the Company for cash (i) $125.0 million aggregate principal amount of Notes sold at par, which Notes, subject to the receipt of approval of the Company’s stockholders which was obtained on May 2, 2017, are convertible into common stock or, in certain circumstances, cash in lieu of common stock or a combination of cash and shares of common stock as described below and (ii) 29,408,305 shares of common stock for a purchase price of $50.0 million. In addition, an affiliate of Ares concurrently loaned the Company $250.0 million pursuant to the Term Loan, as further described below. The proceeds from the sale of the Notes, the common stock and the Term Loan were used to fully repay and redeem the Company’s prior Revolving Credit Facility and to satisfy and discharge its $325.0 million of 8.625% senior secured notes due May 2018, which were satisfied and discharged on March 3, 2017 by irrevocably calling for redemption and depositing with the indenture trustee cash in the amount of the redemption price of 102.156% of their principal amount plus accrued and unpaid interest to the redemption date of March 24, 2017, and to pay the expenses from the Ares transactions. In order to provide funding for the STACK Leasehold Acquisition and a portion of the Company’s 2017 capital budget, on March 21, 2017, the Purchasers purchased from the Company for cash an additional $75.0 million aggregate principal amount of its Notes sold at par (the “Additional Notes”). The Notes, including the Additional Notes, were issued with conversion rights that were subject to the approval of holders of issued and outstanding common stock (other than the Purchasers), which approval was obtained May 2, 2017 (the “Requisite Stockholder Approval”). Pursuant to the purchase agreement for the Additional Notes, upon receipt of Requisite Stockholder Approval, Purchasers and the Company exchanged $37.5 million principal amount of the Additional Notes for (a) 25,456,521 newly issued shares of common stock (the “Repurchase Shares”) and (b) 2,000 shares of the Company’s Special Voting Preferred Stock, par value $0.01 per share (the “Mandatory Repurchase”). The terms of the Mandatory Repurchase, which was effected May 5, 2017, provided for one Repurchase Share issued for each $1.4731 of outstanding principal of the repurchased Notes, which was based on the 10-day volume weighted average trading price (“VWAP”) of the common stock for the period ended March 17, 2017. The exchange reduced the aggregate principal amount of issued and outstanding Notes from $200.0 million to $162.5 million at June 30, 2017, which principal amount remains outstanding at December 31, 2017. Term Loan On March 3, 2017, the Company entered into a credit agreement for the Term Loan. The Term Loan bears interest at a per annum rate equal to 8.5%, payable on a quarterly basis on each March 31, June 30, September 30 and December 31 of each year, commencing March 31, 2017. The Term Loan has a scheduled maturity of March 3, 2022. In addition, the Term Loan is subject to an interest “make-whole” and repayment premium, such that any repayment or prepayment of the loans thereunder prior to the stated maturity date shall be subject to the payment of a repayment premium, and depending on the date of such repayment or prepayment, the applicable interest “make-whole” amount, with the amount of such repayment premium decreasing over the life of the Term Loan. The Term Loan is guaranteed by the Company’s sole domestic subsidiary and will be guaranteed by all of the Company's future domestic subsidiaries formed during the term of the Term Loan. The Term Loan is secured by a first-priority lien on substantially all of the assets of the Company and its subsidiaries, excluding certain assets as customary exceptions. The Term Loan contains various customary covenants for credit facilities of this type, including, among others, restrictions on granting liens, incurrence of other indebtedness, payments of certain dividends and other restricted payments, engaging in transactions with affiliates, dispositions of assets and other, in each case subject to certain baskets and exceptions. At December 31, 2017, the Company was in compliance with such covenants. All outstanding amounts owed become due and payable upon the occurrence of certain usual and customary events of default, including among others (i) failure to make payments; (ii) non-performance of covenants and obligations continuing beyond any applicable grace period; and (iii) the occurrence of a change in control of the Company, as defined in the Term Loan. The Company accounted for the Term Loan in accordance with guidance relating to “ Debt with Conversion and Other Options On March 20, 2017, the Company, together with the parties thereto, entered into an Amendment No. 1 to the Term Loan which amendment permitted the issuance of the Additional Notes. On August 2, 2017, the Company, together with the parties thereto, entered into an Amendment No. 2 to Term Loan (“Amendment No. 2”). Amendment No. 2 amended the Term Loan, to among other things, (i) allow for the payment of pay in kind (“PIK”) interest on the Term Loan at the applicable PIK percentage and (ii) increased the applicable rate for periods ending after June 30, 2017 from 8.5% per annum to 10.25% per annum. Amendment No. 2 allows the Company to elect to PIK upon proper notice 100% of interest payments due after June 30, 2017 and prior to December 31, 2018 and at the Company’s election, PIK between 0% and 50% of any interest payments occurring after December 31, 2018 (other than interest due on the maturity date or the date of any repayment or prepayment). The Term Loan interest rate increased to 10.25% for all interest periods post June 30, 2017 and the PIK interest shall be payable by capitalizing and adding such amounts to the outstanding principal amount of the Term Loan on the applicable interest payment date. On September 18, 2017, the Company, together with the parties thereto, entered into an Amendment No. 3 to the Term Loan (“Amendment No. 3”). Amendment No. 3 amended the Term Loan to, among other things, expressly provide that certain assignments of oil and natural gas properties made or to be made by the Company to Red Bluff, pursuant to the Red Bluff Purchase and Sale Agreement, are permitted by the Term Loan and are not subject to the mandatory prepayment provisions applicable to “Asset Sales” under the Term Loan. A carrying amount of the Term Loan for the period indicated is as follows: December 31, 2017 (in thousands) Term Loan, principal balance (1) $ 256,599 Less: Unamortized deferred financing costs (2) (4,724 ) Unamortized debt discount (2) (22,464 ) Term loan, net $ 229,411 (1) Pursuant to Amendment No. 2, on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. (2) The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan based on the effective interest method. Indenture and Notes On March 3, 2017, the Company entered into an indenture (the “Indenture”) by and among the Company, the subsidiary guarantor named therein, and Wilmington Trust, National Association, as trustee (the “Trustee”) and collateral trustee, with respect to the Notes. The principal terms of the Notes are governed by the Indenture. Pursuant to the Indenture, the Notes were issued for cash at par, bear interest at 6.0% per annum and will mature on March 1, 2022, unless earlier repurchased, redeemed or converted in accordance with the terms of the Indenture. Interest is payable on the Notes on each March 1, June 1, September 1 and December 1 of each year, commencing on June 1, 2017. Pursuant to the Indenture, Requisite Stockholder Approval was required on or before July 3, 2017 to approve the conversion rights of the Notes (including the Additional Notes) to be convertible at the option of the holder into shares of common stock based on the terms of the Indenture. Requisite Stockholder Approval was obtained on May 2, 2017 at a special meeting of stockholders. The interest rate on the Notes was subject to an increase in certain circumstances if the Company fails to comply with certain obligations under a Registration Rights Agreement described in “Note 7 – Capital Stock” below, and on the Notes in the case of certain issuances of common stock by the Company at a price below $1.7002 per share (subject to adjustment). The Notes are secured by a second-priority lien on substantially all of the assets of the Company and its sole subsidiary. If at least a majority of the Notes issued pursuant to the Securities Purchase Agreement dated February 16, 2017 (the “Purchase Agreement”) cease to be held by affiliates of Ares as provided in the Indenture, the liens securing the Notes will be released and substantially all of the restrictive covenants in the Indenture will terminate. The Indenture restricts the ability of the Company and certain of its subsidiaries to, among other things: (i) pay dividends or make other distributions in respect of the Company’s capital stock or make other restricted payments; (ii) incur additional indebtedness and issue preferred stock; (iii) make certain dispositions and transfers of assets; (iv) engage in transactions with affiliates; (v) create liens; (vi) engage in certain business activities that are not related to oil and gas; and (vii) impair any security interest. These covenants are subject to a number of exceptions and qualifications. The Indenture provides that a number of events will constitute an Event of Default (as defined in the Indenture), including, among other things: (i) a failure to pay the Notes when due at maturity, upon redemption or repurchase; (ii) failure to pay interest for 30 days; (iii) the Company’s failure to deliver certain notices; (iv) a default in the Company’s obligation to convert the Notes; (v) the Company’s failure to comply with certain covenants relating to merger, consolidation or sale of assets; (vi) the Company’s failure to comply, for 60 days following notice, with any of the other covenants or agreements in the Indenture; (vii) a default, which is not cured within 30 days, by the Company or any Restricted Subsidiaries (as defined in the Indenture) with respect to any mortgages or any indebtedness for money borrowed of at least $15 million; (viii) one or more final judgments against the Company or any of its Restricted Subsidiaries for the payment of at least $15 million; (ix) the Company’s failure to make any payments required under that certain development agreement, which is not cured within 30 days; (x) causing any Guarantee (as defined in the Indenture) to cease to be in full force and effect; (xi) the cessation to be in full force and effect of any of the collateral agreements entered into with respect to the Notes; and (xii) certain events of bankruptcy or insolvency. In the case of an Event of Default arising from certain events of bankruptcy or insolvency with respect to the Company, all outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. At December 31, 2017, no Event of Default had occurred. In accordance with accounting guidance relating to “ Debt with Conversion and Other Options” The carrying amount of the liability component of the Notes for the period indicated is as follows: December 31, 2017 (in thousands) Notes, principal balance $ 162,500 Less: Unamortized deferred financing costs (1) (2,631 ) Unamortized debt discount (1) (46,328 ) Notes, net $ 113,541 (1) The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Notes based on the effective interest method. The carrying amount of the equity components of the Notes recorded in additional paid in capital for the period indicated is as follows: December 31, 2017 (in thousands) Value of conversion option $ 77,626 Debt issuance costs attributable to conversion option $ (2,164 ) Total $ 75,462 Second Amended and Restated Revolving Credit Facility On June 7, 2013, the Company entered into the Second Amended and Restated Credit Agreement among the Company, Wells Fargo Bank, National Association, as Administrative Agent, Collateral Agent, Swing Line Lender and Issuing Lender and the lenders named therein (the “Revolving Credit Facility”). The Revolving Credit Facility had a scheduled maturity of November 14, 2017. On January 10, 2017, the Company, together with the parties thereto, entered into an amendment to the Revolving Credit Facility (“Amendment No. 10”), which amended the Revolving Credit Facility to, among other things, permit the payment of certain cash dividends on its preferred stock, including the dividends declared payable on January 31, 2017, provided that (i) the Company’s borrowing base was correspondingly reduced in the amount of any such dividend payment and (ii) the Company paid down its outstanding indebtedness under the Revolving Credit Facility in the amount of any resulting borrowing base deficiency. Under Amendment No. 10, payment of the declared January 2017 dividend and monthly preferred stock cash dividends through May 2017 was permitted contingent upon the satisfaction of certain conditions, including but not limited to, (i) the absence of any defaults or borrowing base deficiency, (ii) for any dividends declared and paid in respect of April 2017 and May 2017, having cash liquidity (including any available borrowings under the Revolving Credit Facility) of more than $30.0 million and (iii) paying any permitted dividends solely from proceeds received by the Company from sales of equity since November 30, 2016 (including through the Company’s at-the-market issuance sales agreement with a third-party sales agent to sell, from time to time, shares of the Company’s common stock (the “ATM Program”). Under Amendment No. 10, the Company also agreed to pay down indebtedness under its Revolving Credit Facility by at least an additional $8.1 million by April 30, 2017. On March 3, 2017, the Company used a portion of the net proceeds from the transactions described in this Note 4 under the caption “Ares Investment Transactions” to fully repay all of the $69.2 million borrowings outstanding under the Revolving Credit Facility (which was terminated on such date). Senior Secured Notes At December 31, 2016, the Company had $325.0 million aggregate principal amount of 8 5/8% Senior Secured Notes due May 15, 2018 (the “Former Notes”) outstanding under an indenture by and among the Company, the Guarantors named therein (the “Guarantors”), Wells Fargo Bank, National Association, as Trustee (in such capacity, the “Trustee”) and Collateral Agent. The Notes bore interest at a rate of 8.625% per year, payable semi-annually in arrears on May 15 and November 15 of each year. Effective May 17, 2016, Wells Fargo Bank, National Association resigned as Trustee and Collateral Agent and Wilmington Trust was appointed Trustee and Collateral Agent pursuant to the Indenture. On March 3, 2017, the redemption price plus interest on all of the Company’s outstanding $325.0 million principal of the Former Notes was funded to satisfy and discharge the Former Notes from a portion of the net proceeds from the transactions described in this Note 4 under the caption “Ares Investment Transactions.” All of the Former Notes were satisfied and discharged on March 3, 2017 by irrevocably calling for redemption and depositing with the indenture trustee cash in the amount of the redemption price of 102.156% of the principal amount, or principal plus an additional $7.0 million, plus accrued and unpaid interest to the redemption date of March 24, 2017. Additionally, the Company wrote-off $5.2 million of remaining unamortized deferred financing costs related to the Former Notes upon redemption. |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation | 5. Asset Retirement Obligation A summary of the activity related to the asset retirement obligation is as follows: For the Years Ended December 31, 2017 2016 (in thousands) Asset retirement obligation, beginning of year $ 5,532 $ 6,086 Liabilities incurred during period 383 196 Liabilities settled during period — (90 ) Accretion expense 237 368 Revision in previous estimates and other 222 17 Deletions related to property disposals (1,533 ) (1,045 ) Asset retirement obligation, end of year $ 4,841 $ 5,532 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | 6. The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations, unproved properties and other property and equipment, at fair value on a non-recurring basis. For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The Company assesses its unproved properties for impairment whenever events or circumstances indicate the carrying value of those properties may not be recoverable. The fair value of the unproved properties is measured using an income approach based upon internal estimates of future production levels, current and future prices, drilling and operating costs, discount rates, current drilling plans and favorable and unfavorable drilling activity on the properties being evaluated and/or adjacent properties, which are Level 3 (as defined below) inputs. Should an impairment of unproved properties occur, the value of the impaired properties would be reclassified into proved properties in the full cost pool subject to depletion. As no other fair value measurements are required to be recognized on a non-recurring basis at December 31, 2017, no additional disclosures are provided. As defined in the guidance, fair value is the amount 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 (an exit price). To estimate fair value, 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 guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (“Level 1”) and the lowest priority to unobservable inputs (“Level 3”). The three levels of the fair value hierarchy are as follows: • Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities. The Company’s cash equivalents consist of short-term, highly liquid investments, which have maturities of 90 days or less, including sweep investments and money market funds. • Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument. • Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. These inputs may be used with internally developed methodologies or third party broker quotes that result in management’s best estimate of fair value. The Company’s valuation models consider various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Level 3 instruments are commodity costless collars, index swaps, basis and fixed price swaps and put and call options to hedge oil, natural gas and NGLs price risk. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs. The fair values derived from counterparties and third-party brokers are verified by the Company using publicly available values for relevant NYMEX futures contracts and exchange traded contracts for each derivative settlement location. Although such counterparty and third-party broker quotes are used to assess the fair value of its commodity derivative instruments, the Company does not have access to the specific assumptions used in its counterparties valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided and the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments. As required, financial assets and liabilities are classified in their entirety 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. The determination of the fair values below incorporates various factors, including the impact of the counterparty’s non-performance risk with respect to the Company’s financial assets and the Company’s non-performance risk with respect to the Company’s financial liabilities. The Company has not elected to offset the fair value amounts recognized for multiple derivative instruments executed with the same counterparty, but reports them gross on its consolidated balance sheets. Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the 2017 and 2016 periods. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016: Fair value as of December 31, 2017 Level 1 Level 2 Level 3 Total (in thousands) Assets: Commodity derivative contracts — — 1,370 1,370 Liabilities: Commodity derivative contracts — — (6,988 ) (6,988 ) Total $ — $ — $ (5,618 ) $ (5,618 ) Fair value as of December 31, 2016 Level 1 Level 2 Level 3 Total (in thousands) Assets: Commodity derivative contracts — — 7,850 7,850 Liabilities: Commodity derivative contracts — — (338 ) (338 ) Total $ — $ — $ 7,512 $ 7,512 The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2017 and 2016. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2017 and 2016. For the Years Ended December 31, 2017 2016 (in thousands) Balance at beginning of period $ 7,512 $ 24,418 Total losses, net included in earnings (4,457 ) (2,863 ) Purchases 1,888 565 Issuances — (165 ) Settlements (1) (10,561 ) (14,443 ) Balance at end of period $ (5,618 ) $ 7,512 The amount of total losses for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2017 and 2016 $ (11,875 ) $ (13,622 ) (1) Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations. At December 31, 2017, the estimated fair value of accounts receivable and accounts and revenue payables approximates their carrying value due to their short-term nature. The estimated fair value of the Notes excluding the conversion feature at December 31, 2017 was $108.2 million calculated based on the fair market value of similar non-convertible debt instruments (Level 2) since an observable quoted price of the Notes or a similar asset or liability is not readily available. The estimated fair value of the Term Loan at December 31, 2017 was $234.9 million calculated based on the fair value of similar debt instruments (Level 2) since an observable price of the Term Loan or a similar asset or liability is not readily available. The estimated fair value of the Company’s long-term debt at December 31, 2016 was $403.1 million based on quoted market prices of the Notes (Level 1) and the respective carrying value of the Revolving Credit Facility because the interest rate approximated the current market rate (Level 2). The Company has consistently applied the valuation techniques discussed above in all periods presented. The fair value guidance, as amended, establishes that every derivative instrument is to be recorded on the balance sheet as either an asset or liability measured at fair value. See Note 7, “Derivative Instruments and Hedging Activity.” |
Derivative Instruments and Hedg
Derivative Instruments and Hedging Activity | 12 Months Ended |
Dec. 31, 2017 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activity | 7. The Company maintains a commodity price risk management strategy that uses derivative instruments to minimize significant, unanticipated earnings fluctuations that may arise from volatility in commodity prices. The Company uses costless collars, index, basis and fixed price swaps and put and call options to hedge oil, condensate, natural gas and NGLs price risk. All derivative contracts are carried at their fair value on the balance sheet and all changes in value are recorded in the consolidated statement of operations in (loss) gain on commodity derivatives contracts. For the years ended December 31, 2017, 2016 and 2015, the Company reported a loss of $4.5 million, a loss of $2.9 million and a gain of $24.6 million, respectively, on commodity derivatives contracts in the consolidated statement of operations which included losses related to the change in the fair value of commodity derivative instruments held of $11.9 million, $13.6 million and $1.9 million, respectively. As of December 31, 2017, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume (1) Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in Bbls) January to December 2018 Costless three-way collar 500 182,500 $ — $ 50.00 $ 40.00 $ 61.60 January to March 2018 Costless three-way collar 1,800 162,000 $ — $ 47.50 $ 37.50 $ 57.85 April to June 2018 Costless three-way collar 1,700 154,700 $ — $ 47.50 $ 37.50 $ 57.85 July to September 2018 Costless three-way collar 1,600 147,200 $ — $ 47.50 $ 37.50 $ 57.85 October to December 2018 Costless three-way collar 1,700 156,400 $ — $ 47.50 $ 37.50 $ 57.85 January to June 2018 Fixed price swap 200 36,200 $ 50.11 $ — $ — $ — January to June 2018 Fixed price swap 600 108,600 $ 51.20 $ — $ — $ — January to August 2018 Fixed price swap 425 103,275 $ 66.45 $ — $ — $ — July to September 2018 Fixed price swap 500 46,000 $ 51.20 $ — $ — $ — October to December 2018 Fixed price swap 600 55,200 $ 51.20 $ — $ — $ — January to September 2019 Costless three-way collar 2,000 546,000 $ — $ 47.50 $ 37.50 $ 59.70 October to December 2019 Costless three-way collar 1,900 174,800 $ — $ 47.50 $ 37.50 $ 59.70 January to September 2019 Fixed price swap 700 191,100 $ 50.40 $ — $ — $ — October to December 2019 Fixed price swap 600 55,200 $ 50.40 $ — $ — $ — (1) Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production. As of December 31, 2017, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in MMBtu’s) February to December 2018 Costless three-way collar 5,000 1,670,000 $ — $ 3.00 $ 2.35 $ 4.00 February to March 2018 Costless Collar 5,800 342,200 $ — $ 3.00 $ — $ 4.28 April to December 2018 Fixed price swap 1,550 426,250 $ 3.01 $ — $ — $ — As of December 31, 2017, all of the Company’s economic derivative hedge positions were with large institutions, which are not known to the Company to be in default on their derivative positions. The Company is exposed to credit risk to the extent of non-performance by the counterparties in the derivative contracts discussed above; however, the Company does not anticipate non-performance by such counterparties. None of the Company’s derivative instruments contains credit-risk related contingent features. In conjunction with certain derivative hedging activity, the Company deferred the payment of certain put premiums for the production month period January 2018 through December 2018. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. The following table provides information regarding the deferred put premium liabilities for the periods indicated: December 31, 2017 2016 (in thousands) Current commodity derivative premium put payable $ 135 $ 1,654 Long-term commodity derivative premium payable — 969 Total unamortized put premium liabilities $ 135 $ 2,623 For the Years Ended December 31, 2017 2016 (in thousands) Put premium liabilities, beginning balance $ 2,623 $ 5,982 Settlement of put premium liabilities (2,958 ) (3,194 ) Additional put premium liabilities 470 (165 ) Put premium liabilities, ending balance $ 135 $ 2,623 Additional Disclosures about Derivative Instruments and Hedging Activities The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments: Fair Values of Derivative Instruments Derivative Assets (Liabilities) Fair Value December 31, Balance Sheet Location 2017 2016 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 1,370 $ 6,212 Commodity derivative contracts Other assets — 1,638 Commodity derivative contracts Current liabilities (4,416 ) (338 ) Commodity derivative contracts Long-term liabilities (2,572 ) — Total derivatives not designated as hedging instruments $ (5,618 ) $ 7,512 Amount of (Loss) Gain Recognized in Income on Derivatives For the Years Ended December 31, Location of (Loss) Gain Recognized in Income on Derivatives 2017 2016 2015 (in thousands) Derivatives Commodity derivative contracts (Loss) gain on commodity derivatives contracts $ (4,457 ) $ (2,863 ) $ 24,589 Total $ (4,457 ) $ (2,863 ) $ 24,589 |
Capital Stock
Capital Stock | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders Equity Note [Abstract] | |
Capital Stock | 8. Capital Stock Common Stock On May 7, 2015, the Company entered into the ATM Program. The shares were issued pursuant to the Company’s then-existing effective shelf registration statement on Form S-3, as amended (Registration No. 333-193832). The Company registered shares having an aggregate offering price of up to $50.0 million. During the year ended December 31, 2016, 18,606,943 shares were sold through the ATM Program for net proceeds of $24.4 million. For the period January 1, 2017 to February 20, 2017, the Company sold 5,447,919 shares through the ATM program for net proceeds of $8.3 million. The ATM Program expired on February 24, 2017. On May 12, 2016, the Company sold 50,000,000 shares of its common stock in an underwritten public offering at a price of $0.95 per share, or $47.5 million before offering costs and expenses. The Company received approximately $44.8 million of proceeds from the offering, net of offering costs and expenses of approximately $2.7 million. On June 14, 2016, the Company’s stockholders approved an amendment to the Company’s certificate of incorporation to increase the number of authorized shares of common stock from 275,000,000 to 550,000,000, which amendment became effective on July 5, 2016. On March 3, 2017, the Purchasers purchased for cash (i) $125.0 million aggregate principal amount of Notes sold at par and (ii) 29,408,305 shares of common stock for a purchase price of $50.0 million before offering costs and expenses. The common stock sale was priced based on a 30-trading day VWAP of $1.7002 determined on February 15, 2017 the date immediately prior to the signing date of the Purchase Agreement with Purchasers in respect to such sale. On March 21, 2017, the Company sold to the Purchasers an additional $75.0 million aggregate principal amount of Notes. Pursuant to the purchase agreement for the Additional Notes, after obtaining the Requisite Stockholder Approval, on May 5, 2017, the Company and the Purchasers exchanged $37.5 million aggregate principal amount of the outstanding Additional Notes for the issuance of 25,456,521 shares of common stock to Purchasers of the Mandatory Repurchase. The Notes are convertible into shares of common stock as described in more detail in Note 4. On June 27, 2017, the Company’s stockholders approved an amendment to the Company’s certificate of incorporation to increase the number of authorized shares of common stock from 550,000,000 to 800,000,000, which amendment became effective on July 24, 2017. Stockholder Rights Agreement On January 18, 2016, the Company’s board of directors adopted the Rights Agreement dated as of January 18, 2016, between the Company and American Stock Transfer & Trust Company, LLC (“AST”) (the “2016 Rights Agreement”) pursuant to which the Company declared a dividend of one right (a “2016 Right”) for each of the Company’s issued and outstanding shares of common stock. The dividend was paid to stockholders of record on January 28, 2016. Each 2016 Right entitled the holder, subject to the terms of the 2016 Rights Agreement, to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $6.96, subject to certain adjustments. The purpose of the 2016 Rights Agreement was to diminish the risk that the Company’s ability to reduce potential future federal income tax obligations would become subject to limitations by reason of an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”). The 2016 Rights and the 2016 Rights Agreement expired on January 18, 2017. On January 27, 2017, the Company’s board of directors adopted the Rights Agreement dated as of January 27, 2017, between the Company and AST (the “2017 Rights Agreement”) pursuant to which the Company declared a dividend of one right (a “Right”) for each of the Company’s issued and outstanding shares of common stock. The dividend was paid to stockholders of record on February 10, 2017. Each Right entitled the holder, subject to the terms of the 2017 Rights Agreement, to purchase one one-thousandth of a share of Series C Preferred Stock at a price of $10.74, subject to certain adjustments. The purpose of the 2017 Rights Agreement was to diminish the risk that the Company’s ability to reduce potential future federal income tax obligations would become subject to limitations by reason of an “ownership change,” as defined in Section 382 of the Internal Revenue Code. In connection with entering into the recent equity and convertible debt transactions with funds managed directly by Ares, the Company determined that the value of the U.S. federal income tax benefits in the form of net operating losses have substantially been diminished by reason of an “ownership change,” as defined under Section 382 of the Internal Revenue Code, in 2017. As a result, the Company decided to terminate the Rights. On April 6, 2017, the Company amended the 2017 Rights Agreement to accelerate the expiration of the Rights to 5:00 P.M., New York City time on April 6, 2017, which had the effect of terminating the Rights and the 2017 Rights Agreement on that date. Preferred Stock Pursuant to the Company’s certificate of incorporation, the Company has 40,000,000 shares of preferred stock authorized with a par value of $0.01 per share. The Company has designated 10,000,000 of such shares to constitute its 8.625% Series A Cumulative Preferred Stock (the “Series A Preferred Stock”) and 10,000,000 of such shares to constitute its 10.75% Series B Cumulative Preferred Stock (the “Series B Preferred Stock”). The Series A Preferred Stock and the Series B Preferred Stock each have a liquidation preference of $25.00 per share. On March 22, 2017, the Company designated 2,000 of such shares as Special Voting Preferred Stock with a liquidation preference of $0.01 for each share, which is junior and subordinate to the right of the holders of any shares of any other existing or future series of preferred stock. Series A Preferred Stock At December 31, 2017, there were 4,045,000 shares of Series A Preferred Stock issued and outstanding with a $25.00 per share liquidation preference. The Series A Preferred Stock ranks senior to the Company’s common stock and on parity with the Series B Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series A Preferred Stock is subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series A Preferred Stock. The Series A Preferred Stock cannot be converted into common stock, but may be redeemed, at the Company’s option for $25.00 per share plus any accrued and unpaid dividends. There is no mandatory redemption of the Series A Preferred Stock. The Company paid monthly dividends on the Series A Preferred Stock at a fixed rate of 8.625% per annum of the $25.00 per share liquidation preference through March 2016. Effective March 9, 2016, the Revolving Credit Facility prohibited the payment of cash dividends on the Company’s preferred stock commencing April 2016. Pursuant to Amendment No. 10 to the Company’s Revolving Credit Facility, on January 10, 2017, the Company declared a special cash dividend on the Series A Preferred Stock to pay in full all accumulated and unpaid cash dividends accrued since April 1, 2016 at an annualized 8.625% through the payment date. The Series A Preferred Stock January 2017 dividend of $7.3 million was paid on January 31, 2017 to holders of record at the close of business on January 20, 2017, which paid all unpaid dividends that accumulated in respect to the Series A Preferred Stock at such time. Thereafter, all monthly cash dividends on the Series A Preferred Stock were paid for each month through July 2017. On August 1, 2017, primarily in response to the decline in oil prices and to preserve liquidity, the Company elected to suspend Series A Preferred Stock dividends commencing August 2017, which suspension remained in effect throughout the remainder of 2017. Dividends on the Series A Preferred Stock accumulate regardless of whether any such dividends are declared. If the Company has accumulated, accrued and unpaid cash dividends in any calendar month within four calendar quarters, then commencing in the calendar month following the first month in such fourth calendar quarter in which cash dividends are not paid in full, and until accumulated dividends are paid in full for four calendar quarters with the last two calendar quarters’ dividends paid in cash, (i) the fixed dividend rate of Series A Preferred Stock each increases by 2.00% per annum, (ii) the Company will be required to issue a dividend of common stock to pay accrued and unpaid dividends based on then current market value determined in accordance with the certificate of designations applicable to the Series A Preferred Stock, if such dividends are not paid in cash, provided it has sufficient capital surplus to pay such a dividend and can otherwise pay a dividend under state law, and (iii) the holders of Series A Preferred Stock and Series B Preferred Stock, voting as a single class, will have the right to elect up to two additional directors to the board of directors of the Company. If the Company’s common stock ceases to be listed on a national securities exchange or a national securities market, “pay in kind” dividends of additional shares of Series A Preferred Stock may be payable in lieu of cash or common stock dividends. For the years ended December 31, 2017, 2016 and 2015, the Company paid cash dividends of $11.6 million (including $6.5 million of 2016 undeclared dividends), $2.2 million and $8.7 million, respectively, for the Series A Preferred Stock. At December 31, 2017 and 2016, the Company reported undeclared cumulative dividends of $3.6 million and $6.5 million, respectively, for the Series A Preferred Stock. As of December 31, 2017, accumulated and unpaid dividends on the outstanding Series A Preferred Stock aggregated to $3.6 million, or $0.89844 per share. Series B Preferred Stock At December 31, 2017, there were 2,140,000 shares of the Series B Preferred Stock issued and outstanding with a $25.00 per share liquidation preference. The Series B Preferred Stock ranks senior (to the extent of its stated liquidation preference and any accumulated and unpaid dividends) to the Company’s common stock and on parity with Series A Preferred Stock with respect to the payment of dividends and distribution of assets upon liquidation, dissolution or winding up. The Series B Preferred Stock are subordinated to all of the Company’s existing and future debt and all future capital stock designated as senior to the Series B Preferred Stock. Except upon a change in ownership or control, the Series B Preferred Stock may not be redeemed before November 15, 2018, at or after which time it may be redeemed at the Company’s option for $25.00 per share in cash. Following a change in ownership or control, the Company will have the option to redeem the Series B Preferred Stock within 90 days of the occurrence of the change in control, in whole but not in part for $25.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), up to, but not including the redemption date. If the Company does not exercise its option to redeem the Series B Preferred Stock upon a change of ownership or control, the holders of the Series B Preferred Stock have the option to convert the shares of Series B Preferred Stock into the Company's common stock based upon on an average common stock trading price then in effect but limited to an aggregate of 11.5207 shares of the Company’s common stock per share of Series B Preferred Stock, subject to certain adjustments. If the Company exercises any of its redemption rights relating to shares of Series B Preferred Stock, the holders of Series B Preferred Stock will not have the conversion right described above with respect to the shares of Series B Preferred Stock called for redemption. There is no mandatory redemption of the Series B Preferred Stock. The Company paid monthly dividends on the Series B Preferred Stock at a fixed rate of 10.75% per annum of the $25.00 per share liquidation preference through March 2016. Effective March 9, 2016, the Revolving Credit Facility prohibited the payment of cash dividends on the Company’s preferred stock commencing April 2016. Pursuant to Amendment No. 10 to the Company’s Revolving Credit Facility, on January 10, 2017, the Company declared a special cash dividend on the Series B Preferred Stock to pay in full all accumulated and unpaid cash dividends since April 1, 2016 at an annualized 10.75% through the payment date. The Series B Preferred Stock January 2017 dividend in the amount of $4.8 million was paid on January 31, 2017 to holders of record at the close of business on January 20, 2017, which paid all unpaid dividends that accumulated in respect to the Series B Preferred Stock at such time. Thereafter, all monthly cash dividends on the Series B Preferred Stock were paid for each month through July 2017. On August 1, 2017, primarily in response to the decline in oil prices and to preserve liquidity, the Company elected to suspend Series B Preferred Stock dividends commencing August 2017, which suspension remained in effect throughout the remainder of 2017. Dividends on the Series B Preferred Stock will accumulate regardless of whether any such dividends are declared. If the Company has accumulated, accrued and unpaid cash dividends in any calendar month within four calendar quarters, then commencing in the calendar month following the first month in such fourth calendar quarter in which cash dividends are not paid in full, and until accumulated dividends are paid in full for four calendar quarters with the last two calendar quarters’ dividends paid in cash, (i) the fixed dividend rate of Series B Preferred Stock each increases by 2.00% per annum, (ii) the Company will be required to issue a dividend of common stock to pay accrued and unpaid dividends, based on then current market value determined in accordance with the certificate of designations applicable to the Series B Preferred Stock if such dividends are not paid in cash, provided it has sufficient capital surplus to pay such a dividend and can otherwise pay a dividend under state law, and (iii) the holders of Series A Preferred Stock and Series B Preferred Stock, voting as a single class, will have the right to elect up to two additional directors to the board of directors of the Company. If the Company’s common stock ceases to be listed on a national securities exchange or a national securities market, “pay in kind” dividends of additional shares of Series B Preferred Stock may be payable in lieu of cash or common stock dividends. For the years ended December 31, 2017, 2016 and 2015, the Company paid cash dividends of $7.7 million (including $4.3 million of 2016 undeclared dividends), $1.4 million and $5.8 million, respectively, for the Series B Preferred Stock. At December 31, 2017 and 2016, the Company reported undeclared cumulative dividends of $2.4 million and $4.4 million, respectively, for the Series B Preferred Stock. As of December 31, 2017, accumulated and unpaid dividends on the outstanding Series B Preferred Stock aggregated to $2.4 million, or $1.11979 per share. If a full catch up dividend is not declared and paid in cash in April 2018 for the Series A and Series B Preferred Stock to pay all of the accumulated, accrued and unpaid dividends (including April 2018) a fourth unpaid Quarterly Dividend Default will be deemed to occur and, as a result, starting May 1, 2018: (i) the fixed dividend rate of Series A and B Preferred Stock each increases by 2.00% per annum; (ii) if such dividends are not paid in cash, the Company will be required to issue a dividend of common stock to pay all accrued and unpaid dividends based on then current market value determined in accordance with the applicable certificate of designations for each of the Series A and B Preferred Stock provided (iii) the holders of Series A Preferred Stock and Series B Preferred Stock, voting as a single class, will have the right to elect up to two additional directors to the board of directors of the Company; and (iv) the foregoing rights would continue until the Company has paid a least two full calendar quarters of monthly cash dividends on the respective series. Other Share Issuances The following table provides information regarding the issuances and forfeitures of the Company’s common stock pursuant to the Gastar Exploration Inc. Long-Term Incentive Plan for the periods indicated: For 2017 2016 Other stock issuances: Shares of restricted common stock granted 8,649,343 1,764,645 Shares of restricted common stock vested 1,270,171 1,487,269 Shares of common stock issued pursuant to PBUs vested, net of forfeitures of 207,891 shares — 502,593 Shares of restricted common stock surrendered upon vesting/exercise (1) 373,741 392,094 Shares of restricted common stock forfeited 91,801 128,435 (1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period. In connection with the merger, Parent’s 2006 Long-Term Stock Incentive Plan was assumed by Gastar Exploration Inc. and, effective as of the merger, was amended, restated and renamed the “Gastar Exploration Inc. Long-Term Incentive Plan” (as amended, the “LTIP”). Shares Reserved At December 31, 2017, the Company had 164,400 shares of common stock reserved for the exercise of stock options and 2,226,906 shares reserved for the settlement of PBUs. |
Equity Compensation Plans
Equity Compensation Plans | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Equity Compensation Plans | 9. Equity Compensation Plans Share-Based Compensation Plan The vesting period for recent restricted common stock grants has typically been one year for directors and three years for employees, with the exception of a special grant made to certain executives and employees in August 2017 that vests over five years, vesting annually from the date of grant in equal proportions. On June 27, 2017, the Company’s stockholders approved an amendment to the LTIP, effective May 2, 2017, to, among other things, increase the number of shares of common stock reserved for issuance under the LTIP by 14,000,000 shares of common stock. The LTIP permits the Company to issue stock options, stock appreciation rights, bonus stock awards and any other type of award (including PBUs, which are consistent with the LTIP’s purpose) to directors, officers and employees of the Company and its subsidiaries. At December 31, 2017, 6,637,433 shares of common stock were available for future stock-based compensation grants under the LTIP. All shares of common stock issued upon the exercise of stock option grants or vesting of restricted stock awards and PBUs are authorized, issued by the Company and are fully paid and non-assessable. Stock Options There were no stock options granted during the years ended December 31, 2017, 2016 and 2015. However, in prior years, the Company issued stock options as a component of its equity compensation program and the fair value of such stock options grants were estimated using the Black-Scholes Merton valuation model. At December 31, 2017, all outstanding stock options were fully vested. The following tables summarize certain information related to outstanding stock options under the LTIP as of and for the year ended December 31, 2017: Shares Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding at December 31, 2016 214,600 $ 4.87 Granted — — Exercised — — Canceled/Expired (50,200 ) 10.95 Forfeited — — Outstanding at December 31, 2017 164,400 $ 3.01 Options vested and exercisable at December 31, 2017 164,400 $ 3.01 1.42 $ — There was no unrecognized expense as of December 31, 2017 for outstanding stock options. Restricted Shares The Company has granted restricted shares of common stock which vest based upon continued service or certain other events. The vesting period for recent restricted common stock grants has typically been from one to three years, but generally has been over three years, except for grants to Company directors that vest in one year and a special grant made to certain executives and employees in August 2017 that vests over five years, vesting annually from the date of grant in equal proportions. The following table summarizes information related to restricted shares at December 31, 2017: Shares Weighted Fair Value per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding non-vested restricted shares at December 31, 2016 2,445,290 $ 1.79 Granted 8,649,343 1.09 Vested (1,270,171 ) 2.07 Forfeited (91,801 ) 1.65 Outstanding non-vested restricted shares at December 31, 2017 9,732,661 $ 1.13 3.39 $ 10,219 The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated: For the Years Ended December 31, 2017 2016 2015 (in thousands, except per share data) Weighted average grant date fair value per restricted share $ 1.09 $ 1.19 $ 2.40 Total fair value of restricted shares vested $ 2,627 $ 3,530 $ 3,794 For the year ended December 31, 2017, the Company recognized $4.3 million of compensation expense associated with restricted share awards. Unrecognized compensation expense as of December 31, 2017 for all outstanding restricted share awards totaled $6.1 million and will be recognized over a weighted average period of 2.23 years. Performance Based Units Commencing 2013, a portion of long-term incentive grants to Company management were in the form of PBUs. The PBUs represent a contractual right to receive shares of the Company’s common stock, an amount of cash equal to the fair market value of a share of the Company’s common stock, or a combination of shares of the Company’s common stock and cash as of the date of settlement based on the number of PBUs to be settled. The settlement of PBUs may range from 0% to 200% of the targeted number of PBUs stated in the agreement contingent upon the achievement of certain share price appreciation targets as compared to a peer group index. The PBUs granted prior to 2015 vested equally and settlement was determined annually over a three-year period. The PBUs granted in 2017, 2016 and 2015 cliff vest at the end of a three-year period. Any PBUs not vested at each measurement date will expire. Compensation expense associated with PBUs is based on the grant date fair value of a single PBU as determined using a Monte Carlo Simulation model which utilizes a stochastic process to create a range of potential future outcomes given a variety of inputs. As the Compensation Committee intends to settle the PBUs with shares of the Company's common stock at each measurement date, the PBU awards are accounted for as equity awards and the expense is calculated on the grant date assuming a 100% target payout and amortized over the life of the PBU award. The table below provides a summary of PBUs as of the date indicated: PBUs Weighted Average Fair per Unit Unvested PBUs at December 31, 2016 1,475,730 $ 2.49 Granted 830,196 2.38 Vested (79,020 ) 7.34 Forfeited — — Unvested PBUs at December 31, 2017 2,226,906 $ 2.27 For the year ended December 31, 2017, the Company recognized $1.6 million of compensation expense associated with the PBUs. As of December 31, 2017, the Company had $1.9 million of total unrecognized expense for the PBUs to be recognized over a weighted average period of 1.93 years. Stock-Based Compensation Expense For the years ended December 31, 2017, 2016 and 2015, the Company recorded stock-based compensation expense using the fair-value method of $5.9 million, $3.9 million and $5.0 million, respectively. All stock-based compensation costs were expensed and not tax affected, as the Company currently records no U.S. income tax expense. As of December 31, 2017, the Company had approximately $8.0 million of total unrecognized compensation cost related to unvested restricted shares and PBUs, which is expected to be amortized over the following periods: Amount (in thousands) 2018 $ 4,558 2019 2,290 2020 725 2021 297 2022 100 Total $ 7,970 |
Interest Expense
Interest Expense | 12 Months Ended |
Dec. 31, 2017 | |
Interest Expense [Abstract] | |
Interest Expense | 10. The following tables summarize the components of the Company’s interest expense for the periods indicated: For the Years Ended December 31, 2017 2016 2015 (in thousands) Interest expense: Cash and accrued $ 35,185 $ 33,368 $ 30,981 Amortization of deferred financing costs (1) 10,977 4,980 3,584 Capitalized interest (7,207 ) (3,102 ) (3,879 ) Total interest expense $ 38,955 $ 35,246 $ 30,686 (1) |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 11. Income Taxes On December 22, 2017, the President of the United States signed Public Law 115-97, commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act, among other things, (i) permanently reduces the U.S. federal corporate income tax rate from 35% to 21%, (ii) repeals the corporate alternative minimum tax, (iii) imposes new limitations on the utilization of net operating losses, (iv) limits deductibility of interest expense and (v) changes the cost recovery rules. In December 2017, the SEC issued Staff Accounting Bulletin No. 118 “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”) which allows a company up to one year to finalize and record the tax effects of the Tax Act and The Company is currently in the process of finalizing and quantifying the tax effects of the Tax Act, but has recorded provisional amounts based on reasonable estimates for the measurement and accounting of certain effects of the Tax Act in our Consolidated Financial Statements for the year ended December 31, 2017. Under SAB 118, the Company will complete the required analyses and accounting during the year ended December 31, 2018. The Company does not expect that a material adjustment to its deferred tax position will result from the completion of its computations. The following table summarizes the components of the Company’s (loss) income before income taxes for the periods indicated: For the Years Ended December 31, 2017 2016 2015 (in thousands) United States $ (46,755 ) $ (89,061 ) $ (459,507 ) Total income (loss) before income taxes $ (46,755 ) $ (89,061 ) $ (459,507 ) The Company did not report any current provision for income taxes for the years ended December 31, 2017, 2016 and 2015 as the Company has a full valuation allowance against assets created by net operating losses generated. The Company believes that it is more likely than not that the assets will not be utilized. The Company had no deferred income tax expense (benefit) for the years ended December 31, 2017, 2016 and 2015. Pursuant to the Tax Act, the U.S. federal corporate income tax rate was reduced from 35% to 21% effective for tax years beginning after December 31, 2017. As a result, the Company was required to restate its deferred tax assets and liabilities at the rate expected at the time of reversal. The Company has determined that the rate to apply to its deferred tax assets and liabilities, including expected state taxes net of federal benefit, is 24.6%. The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for 2017, 2016 and 2015. Additionally, the table reflects the impact of the rate change from 38% to 24.6% on the net deferred tax asset for the year ended December 31, 2017 pursuant to the Tax Act as well as the estimated effect of limitations on available net operating loss and tax credit carry forwards by reason of an ownership change (discussed below). For the Years Ended December 31, 2017 2016 2015 (in thousands) Expected income tax benefit at statutory rate $ (16,364 ) $ (31,172 ) $ (160,827 ) State tax, tax effected (1,085 ) (1,408 ) (7,799 ) Non-deductible convertible debt discount 3,092 — — Stock-based compensation expense 523 1,995 255 Non-deductible compensation 63 178 — Effect of rate change on net deferred tax asset 64,515 — — Effect of ownership change on estimated realization of net operating loss and tax credit carry forwards 119,654 — — State tax rate change and other 3,101 693 17 Other changes in valuation allowance (173,499 ) 29,714 168,354 Actual income tax provision $ — $ — $ — Year-end deferred taxes are presented in the table below. As a result of the recent Tax Act, deferred taxes as of December 31, 2017 are based on the newly enacted U.S. statutory federal income tax rate of 21%. Deferred taxes as of December 31, 2016 are based on the previous U.S. statutory federal income tax rate of 35%. The components of the Company’s U.S. deferred taxes are as follows for the periods presented: As of December 31, 2017 2016 (in thousands) Deferred tax asset: Capital assets $ 27,137 $ 33,131 Stock-based compensation 2,390 2,499 Net operating loss carry forwards 80,060 196,775 Foreign tax credit carry forwards — 50,681 Valuation allowance (109,587 ) (283,086 ) Net deferred tax asset $ — $ — In connection with the Company’s recent equity and convertible debt transactions during 2017, the Company determined that the utilization of net operating losses in future years may be subject to limitations by reason of an “ownership change” as defined under Section 382 of the Internal Revenue Code (“Section 382 Limitation”). As a result of the Section 382 Limitation, the Company may not be able to fully utilize its net operating loss carry forwards and other tax credit carry forwards. For U.S. federal income tax purposes, as of December 31, 2017, the Company has net operating loss carry forwards of approximately $550.0 million, which, if not utilized, will expire between 2030 and 2037. As of December 31, 2017, the Company also has foreign tax credit carry forwards of $50.7 million, which, if not utilized, will expire in 2019. Based on the Company’s estimate of the impact of the ownership change and Section 382 Limitation, the net operating loss reflected in the table above has been reduced to $353.0 million and the foreign tax credits have been reduced to zero. The estimate of the available net operating loss after the ownership change will be adjusted in future periods as actual drilling and production results are evaluated under the provisions of Section 382 of the Internal Revenue Code. The utilization of the remaining net operating loss carry forwards are dependent on the Company generating future taxable income and U.S. tax liability, as well as other factors. Current authoritative guidance requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For a tax position meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. At December 31, 2017, the Company did not have any material unrecognized tax benefits that, if recognized, would affect the effective tax rate. The Company is subject to examination of income tax filings in the U.S. and various state jurisdictions for the periods 2010 and Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of general and administrative expense in the consolidated statement of operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits. |
Earnings per Share
Earnings per Share | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Earnings per Share | 12. Earnings per Share In accordance with the provisions of current authoritative guidance, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. For the Years Ended December 31, 2017 2016 2015 (in thousands, except per share and share data) Net loss attributable to common stockholders $ (61,228 ) $ (103,534 ) $ (473,980 ) Weighted average shares of common stock outstanding - basic 195,369,489 111,367,452 77,511,677 Weighted average shares of common stock outstanding - diluted 195,369,489 111,367,452 77,511,677 Net (loss) income per share of common stock attributable to common stockholders: Basic $ (0.31 ) $ (0.93 ) $ (6.11 ) Diluted $ (0.31 ) $ (0.93 ) $ (6.11 ) Shares of common stock excluded from denominator as anti-dilutive: Unvested restricted shares 821,710 438,948 177,663 Unvested PBUs 427,382 487,995 17,589 Convertible Notes 65,488,114 — — Total 66,737,206 926,943 195,252 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 13. Commitments and Contingencies Contractual Obligations The Notes and Term Loan have scheduled maturities of March 1, 2022 and March 3, 2022, respectively. The Company leases its office facilities and certain office equipment under non-cancelable operating lease agreements with various termination dates, the latest of which is September 2022. For the years ended December 31, 2017, 2016 and 2015, office lease expense totaled approximately $375,000, $524,000 and $687,000, respectively. As of December 31, 2017, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows: 2018 $ 977 2019 971 2020 979 2021 971 2022 and thereafter 322 $ 4,220 Litigation PennMarc Resources II, LP, et al v. Gastar Exploration USA, Inc., et al, (Civil Action No. 17-C-214) Circuit Court of Marshall County, West Virginia. PennMarc Resources II, LP and others filed suit against the Company on October 23, 2017 in the Circuit Court of Marshall County, West Virginia. The plaintiffs are royalty owners under various leases taken by or assigned to the Company. The leases cover property in Marshall County, West Virginia. The leases are among other assets that were assigned to THQ Appalachia, LLC pursuant to a purchase and sale agreement dated February 12, 2016. The plaintiffs allege that the Company breached the leases by making deductions for post-production costs that were not authorized by the terms of the leases. The plaintiffs also allege that the unauthorized deductions were not shown on the monthly royalty statements and the failure to detail the deduction of these costs was a further breach of the leases and fraud. The plaintiffs claim of breach of contract, breach of fiduciary duty and fraudulent concealment. The plaintiffs seek compensatory damages and punitive damages. The Company is still assessing this claim and has not yet filed a response. The Company has moved to dismiss the plaintiffs’ claims and has requested that discovery be stayed until the motion is ruled on. The motion to dismiss is set for hearing on March 23, 2018. Torchlight Energy Resources, Inc., Torchlight Energy, Inc. v. Husky Ventures, Inc., et al., (Cause No. 429-01961-2016) 429th Judicial District Court in Collin County, Texas. Torchlight Energy Resources, Inc. and Torchlight Energy, Inc. (collectively “Torchlight”) brought a lawsuit against the Company, two of its executive officers, its chairman of the board of directors and a former director of the Company on May 3, 2016 in Collin County, Texas (the “Torchlight Lawsuit”). The Torchlight Lawsuit arises primarily out of Torchlight’s business dealings with Husky in Oklahoma. Husky and several of its employees and affiliates are also defendants in the Torchlight Lawsuit. As part of settlement negotiations between Husky and the Company in a separate lawsuit, Husky informed the Company that it had agreed to repurchase assets from Torchlight that Husky had previously sold to Torchlight (the “Torchlight Assets”). Husky offered to sell those Torchlight Assets to the Company. In the Purchase and Sale Agreement between Torchlight and Husky (the “Purchase and Sale Agreement”), Torchlight expressly acknowledged that the Torchlight Assets were to be sold to the Company and released the Company from any claims arising out of the sale of the Torchlight Assets. Despite this release, Torchlight alleged multiple causes of action against the Company and its officers and directors arising out of the sale of the Torchlight Assets and Torchlight’s other business dealings it had with Husky. On August 17, 2016, plaintiffs nonsuited, without prejudice, their claims against the former chairman of the board. On May 22, 2017, the court granted the Company’s motion for summary judgment and dismissed all of the plaintiffs’ claims against the Company and the Company’s other officers and directors in their entirety. The Company has also filed a counterclaim against Torchlight for breach of the release in the Purchase and Sale Agreement which is still pending. Gastar Exploration Ltd vs U.S. Specialty Ins. Co. and Axis Ins. Co. (Cause No. 2010-11236) District Court of Harris County, Texas 190th Judicial District. On February 19, 2010, the Company filed a lawsuit claiming that the Company was due reimbursement of qualifying claims related to the settlement and associated legal defense costs under the Company's directors and officers liability insurance policies related to the ClassicStar Mare Lease Litigation settled on December 17, 2010 for $21.2 million. The combined coverage limits under the directors and officers liability coverage was $20.0 million. On August 10, 2016, Gastar and the insurers settled their coverage dispute for $10.1 million. Insurers’ settlement payments to Gastar were paid in September 2016 and were recorded as litigation settlement benefit in the statement of operations for the year ended December 31, 2016. Gastar Exploration Inc. v. Christopher McArthur (Cause No.: 2015-77605) 157th Judicial District Court, Harris County, Texas . On December 29, 2015, Gastar filed suit against Christopher McArthur (“McArthur”) in the District Court of Harris County, Texas. The lawsuit arises from a demand letter sent by McArthur to Gastar in which he claimed to be party to an agreement with Gastar that entitled him to be paid $2.75 million for services rendered. In August 2016, McArthur filed an amended answer admitting he had no agreement with the Company. As a result, Gastar believes McArthur’s claim has been effectively resolved. Gastar has continued to pursue a counterclaim in this action against McArthur for tortious interference with an existing contract. McArthur has filed a general denial. Eagle Natrium LLC v. Gastar Exploration USA, Inc., Cause No. GD-14-7208, In the Court of Common Pleas of Allegheny County, Pennsylvania. On April 22, 2014, Eagle Natrium LLC (“Eagle”), a wholly-owned subsidiary of Axiall Corporation, filed a complaint against the Company in the Court of Common Pleas of Allegheny County, Pennsylvania seeking to enjoin Gastar’s hydraulic fracturing and completion operations on three wells drilled from Gastar’s Goudy pad in Marshall County, West Virginia, or conducting any activity that poses a substantial risk of harm to Eagle’s brine operations. Gastar was the operator of approximately 16,000 acres in Marshall County, West Virginia, including a 3,300 gross acre oil and gas lease adjacent to Eagle’s facilities. Eagle asserted its right to relief based on certain of the lessor’s rights which were assigned to Eagle by the lessor solely as they relate to the brine and related facilities. A hearing on the request for preliminary injunction was held in the summer of 2014. After considering the evidence presented at the hearing and the party’s briefing, the court issued an order on October 21, 2014 denying the request for a preliminary injunction. In January 2015, Gastar began completion operations and has since completed the three wells drilled from its Goudy pad that formed the basis of Eagle’s complaint. In 2016, the Company amended its answer and has added counterclaims seeking damages from Eagle as a result of the proceedings. Specifically, Gastar has asserted a breach of contract claim, seeking damages for lost revenues, rig up and rig down costs and attorney’s fees relating to the Pennsylvania lawsuit filed by Eagle. Eagle maintains that it has a breach of contract claim against the Company, but has not articulated any damages. The parties are currently engaged in discovery. The Court bifurcated liability and damages and the liability trial is scheduled to begin on June 20, 2018. The Company has been expensing legal costs on these proceedings as they are incurred. The Company is party to various legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Commitments Drilling Program Repurchase Obligation Under the Development Agreement, an investor has the right in the future to put interests in 20 wells jointly drilled by the Company and the investor to the Company for repurchase. If final reversion of the investor’s working interest is achieved under the Development Agreement for the 20 wells tranche drilled by the Company under the Drilling Program, the Investor has the right, but not the obligation, for a period of six months to cause the Company to purchase the Investor’s remaining working interest in the Drilling Program wells for fair market value by applying the methodology to determine a 15% discounted present value as defined by the Development Agreement. If the Investor fails to exercise the investor put right within the six-month period after achieving final reversion, then for a period of six months thereafter, the Company shall have the right, but not the obligation, to purchase the remaining working interest from the Investor on the same fair market value approach of the investor put right. Based on current commodity prices, well cost and production performance of the wells in the first tranche, the final reversion is not anticipated to be achieved on the 20 well tranche. If final reversion has not been achieved by August 19, 2024, Investor will, for a period of six months thereafter, have the right to cause the Company to buy Investor’s then-current interest in such tranche at an agreed upon valuation. Restoration, Removal and Environmental Liabilities The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the present value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement obligation cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any quarter or year. At December 31, 2017, the Company had total liabilities of $4.8 million related to asset retirement obligations all of which is recorded as long-term liabilities. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. See Note 5, “Asset Retirement Obligation.” Indemnifications Indemnifications in the ordinary course of business have been provided pursuant to provisions of purchase and sale contracts, service agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company may indemnify counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment, if any, is difficult to predict. Employment Agreements The Company entered into employment agreements with its Chief Executive Officer and its Chief Financial Officer, effective February 24, 2005 (as amended July 25, 2008 and February 3, 2011) and May 17, 2005 (as amended July 25, 2008 and April 10, 2012), respectively. The agreements set forth, among other things, annual compensation, and adjustments thereto, bonus payments, fringe benefits, termination and severance provisions. The Company also has entered into agreements with these executives, who are acting at the Company’s request to be officers of the Company, to indemnify them to the fullest extent permitted by law against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individuals as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable estimate of the maximum potential amount it could be required to pay to the beneficiary of such indemnification agreements. |
Concentration of Risk and Signi
Concentration of Risk and Significant Customers | 12 Months Ended |
Dec. 31, 2017 | |
Risks And Uncertainties [Abstract] | |
Concentration of Risk and Significant Customers | 14. Concentration of Risk and Significant Customers The following table provides information regarding the approximate percentages of the Company’s oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated: For the Years Ended December 31, 2017 2016 2015 Appalachian Basin 0 % 5 % 17 % Mid-Continent 100 % 95 % 83 % The following table provides information regarding the Company’s significant customers whom accounted for more than 10% of the Company’s oil, condensate, natural gas and NGLs revenues, excluding hedge impact, for the periods indicated: For the Years Ended December 31, 2017 2016 2015 Sunoco 61 % 67 % 62 % Superior 14 % 12 % 6 % SEI (1) 0 % 5 % 22 % (1) SEI filed for Chapter 7 bankruptcy on June 3, 2016. Sunoco Logistics Partners L.P. (“Sunoco”) purchases the majority of the Company’s Mid-Continent oil production. Superior Pipeline Company (“Superior”) purchases the majority of the Company’s Mid-Continent natural gas and NGLs production. There are numerous purchase and transportation alternatives currently available in the Mid-Continent so in the event that Sunoco were to cease purchasing and transporting our oil and condensate production and/or Superior were to cease purchasing and transporting our natural gas and NGLs production, the Company’s ability to conduct normal operations would not be significantly restricted. Prior to the Appalachian Basin Sale, SEI purchased the majority of the Company’s Appalachian Basin production. |
Statement of Cash Flows - Suppl
Statement of Cash Flows - Supplemental Information | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Statement of Cash Flows - Supplemental Information | 15. Statement of Cash Flows – Supplemental Information The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements: For the Years Ended December 31, 2017 2016 2015 (in thousands) Cash paid for interest, net of capitalized amounts $ 17,596 $ 30,480 $ 26,859 Non-cash transactions: Capital expenditures included in (excluded from) accounts payable and accrued drilling costs $ 23,215 $ (82 ) $ (26,228 ) Capital expenditures included in accounts receivable 76 409 — Asset retirement obligation included in oil and natural gas properties 605 432 526 Asset retirement obligation for property disposals (1,533 ) (1,045 ) (416 ) Application of advances to operators 64 (347 ) 11,445 Undeclared cumulative dividends on preferred stock 6,030 10,855 — Conversion of convertible debt to equity 37,500 — — Other — — 5 |
Quarterly Consolidated Financia
Quarterly Consolidated Financial Data - Unaudited | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Consolidated Financial Data - Unaudited | 16. Quarterly Consolidated Financial Data – Unaudited The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2017 and 2016: 2017 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 18,669 $ 22,646 $ 15,332 $ 15,483 Income (loss) from operations 4,274 5,891 (2,191 ) (3,777 ) Loss before provision for income taxes (1) (18,698 ) (2,779 ) (12,299 ) (12,979 ) Net loss (1) (18,698 ) (2,779 ) (12,299 ) (12,979 ) Dividends on preferred stock 3,618 3,619 1,206 — Undeclared cumulative dividends on preferred stock — — 2,412 3,618 Net loss attributable to common stockholders (1) (22,316 ) (6,398 ) (15,917 ) (16,597 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.14 ) $ (0.03 ) $ (0.08 ) $ (0.08 ) Diluted $ (0.14 ) $ (0.03 ) $ (0.08 ) $ (0.08 ) Weighted average shares of common stock outstanding: Basic 162,829,221 199,547,446 209,072,232 209,089,468 Diluted 162,829,221 199,547,446 209,072,232 209,089,468 (1) The first quarter includes a $12.2 million loss on early extinguishment of debt. 2016 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 14,811 $ 12,153 $ 13,003 $ 18,287 Income (loss) from operations (1) (60,592 ) (5,142 ) 7,959 3,929 Income (loss) before provision for income taxes (1) (69,857 ) (14,481 ) (178 ) (4,545 ) Net income (loss) (1) (69,857 ) (14,481 ) (178 ) (4,545 ) Dividends on preferred stock 3,618 — — — Undeclared cumulative dividends on preferred stock — 3,619 3,618 3,618 Net loss attributable to common stockholders (1) (73,475 ) (18,100 ) (3,796 ) (8,163 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.93 ) $ (0.17 ) $ (0.03 ) $ (0.06 ) Diluted $ (0.93 ) $ (0.17 ) $ (0.03 ) $ (0.06 ) Weighted average shares of common stock outstanding: Basic 78,788,133 104,009,337 129,301,817 132,936,419 Diluted 78,788,133 104,009,337 129,301,817 132,936,419 (1) The first quarter includes impairment of oil and natural gas properties of $48.5 million and the third quarter includes $10.1 million of litigation settlement benefit. |
Supplemental Oil and Gas Disclo
Supplemental Oil and Gas Disclosures - Unaudited | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Supplemental Oil and Disclosures - Unaudited | 17. Supplemental Oil and Gas Disclosures – Unaudited Capitalized Costs Relating to Oil and Natural Gas Producing Activities The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities in the U.S. for the periods indicated: As of December 31, 2017 2016 2015 (in thousands) Proved properties $ 1,344,329 $ 1,253,061 $ 1,286,373 Unproved properties 131,955 67,333 92,609 Total oil and natural gas properties 1,476,284 1,320,394 1,378,982 Less: Impairment of proved oil and natural gas properties (813,314 ) (813,314 ) (764,817 ) Accumulated depreciation, depletion and amortization (339,043 ) (315,373 ) (286,020 ) Net capitalized costs $ 323,927 $ 191,707 $ 328,145 Pursuant to authoritative guidance for accounting for asset retirement obligations, net capitalized costs include related asset retirement costs of approximately $586,000 million, $1.5 million and $2.4 million at December 31, 2017, 2016 and 2015, respectively. Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the periods indicated: For the Years Ended December 31, 2017 2016 2015 (in thousands) Property acquisition Proved $ 6,059 $ 570 $ 15,615 Unproved 91,266 38,941 50,434 Exploration 59,771 19,761 53,290 Development 29,103 3,810 54,316 Total costs incurred $ 186,199 $ 63,082 $ 173,655 Results of Operations for Oil and Natural Gas Producing Activities The following table sets forth the Company’s results of operations for oil and natural gas producing activities for the periods indicated: For the Year Ended December 31, 2017 2016 2015 (in thousands, except per Mcfe data) Oil, condensate, natural gas and NGLs sales, including commodity derivatives $ 72,130 $ 58,254 $ 107,294 Production expenses (26,839 ) (24,217 ) (28,792 ) Impairment of oil and natural gas properties — (48,497 ) (426,878 ) Depreciation, depletion and amortization (23,670 ) (29,353 ) (62,465 ) Results of producing activities $ 21,621 $ (43,813 ) $ (410,841 ) The results of producing activities exclude interest charges and general corporate expenses. Net Proved and Proved Developed Reserve Summary Reserve Estimation. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2017, 2016, and 2015. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e., prices and costs as of the date the estimate is made). Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic productivity at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. The Company’s proved developed and proved undeveloped reserves are located only in the U.S. The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2017, 2016 and 2015: Change in Proved Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) Proved reserves as of December 31, 2014 28,636 287,005 25,593 102,063 2015 Activity: Extensions and discoveries (4) 4,777 14,114 2,244 9,374 Revisions of previous estimates (5) (8,962 ) (182,600 ) (13,873 ) (53,268 ) Production (1,425 ) (13,759 ) (1,212 ) (4,931 ) Purchases in place 1,270 4,965 873 2,971 Sales in place (94 ) (1,274 ) (26 ) (332 ) Proved reserves as of December 31, 2015 24,202 108,451 13,599 55,877 2016 Activity: Extensions and discoveries 1,582 7,213 898 3,681 Revisions of previous estimates (6) (9,890 ) (17,825 ) (3,317 ) (16,177 ) Production (1,105 ) (6,145 ) (739 ) (2,869 ) Sales in place (1,033 ) (53,841 ) (4,929 ) (14,935 ) Proved reserves as of December 31, 2016 13,756 37,853 5,512 25,577 2017 Activity: Extensions and discoveries (7) 8,787 26,065 3,243 16,374 Revisions of previous estimates 1,373 4,295 798 2,887 Production (1,118 ) (3,795 ) (527 ) (2,278 ) Purchases in place 182 1,391 198 612 Sales in place (124 ) (444 ) (47 ) (245 ) Proved reserves as of December 31, 2017 22,856 65,365 9,177 42,927 (1) Thousand barrels (2) Million cubic feet (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. (4) All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations. ( 5 ) The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. (6) The 2016 revisions of previous estimates resulted primarily from the removal of Hunton PUD locations as the Company now focuses its capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate its STACK Play position. ( 7 ) All of the 2017 extensions and discoveries resulted from the Company’s successful STACK Play drilling operations. Proved Developed and Undeveloped Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) December 31, 2015 Proved developed reserves 7,181 77,966 8,240 28,415 Proved undeveloped reserves 17,021 30,485 5,359 27,462 Total 24,202 108,451 13,599 55,877 December 31, 2016 Proved developed reserves 6,037 22,786 3,181 13,015 Proved undeveloped reserves 7,719 15,067 2,331 12,562 Total 13,756 37,853 5,512 25,577 December 31, 2017 Proved developed reserves 8,140 31,723 4,600 18,027 Proved undeveloped reserves 14,716 33,642 4,577 24,900 Total 22,856 65,365 9,177 42,927 (1) Thousand barrels (2) Million cubic feet (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes that such information is essential for a proper understanding and assessment of the data presented. For the years ended December 31, 2017, 2016 and 2015 future cash inflows were computed using the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil (the “benchmark base prices”). For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations: For the Years Ended December 31, 2017 2016 2015 Natural gas, per MMBtu Henry Hub $ 2.98 $ 2.48 $ 2.59 Oil, per barrel: WTI spot $ 51.34 $ 42.75 $ 50.28 These benchmark base prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve report but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. The Company also includes its standard overhead charges pursuant to the respective property joint operating agreements in the calculation of its future cash flows. The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate could also result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or changes in regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized. A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves in the U.S. is presented below (in thousands): December 31, 2015: Future cash inflows $ 1,425,734 Future production costs (547,484 ) Future development costs (365,123 ) Future income taxes (1) — Future net cash flows 513,127 10% annual discount for estimated timing of cash flows (283,324 ) Standardized measure of discounted future cash flows $ 229,803 December 31, 2016: Future cash inflows $ 710,370 Future production costs (328,010 ) Future development costs (123,214 ) Future income taxes (1) — Future net cash flows 259,146 10% annual discount for estimated timing of cash flows (117,815 ) Standardized measure of discounted future cash flows $ 141,331 December 31, 2017: Future cash inflows $ 1,491,158 Future production costs (645,891 ) Future development costs (295,212 ) Future income taxes (1,768 ) Future net cash flows 548,287 10% annual discount for estimated timing of cash flows (261,645 ) Standardized measure of discounted future cash flows $ 286,642 (1) No future taxes payable has been included in the determination of discounted future net cash flows for 2015 and 2016 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows. Changes in Standardized Measure of Discounted Future Net Cash Flows The principal sources of changes in the standardized measure of future net cash flows are as follows (in thousands): December 31, 2014 $ 816,739 Extensions and discoveries, less related costs 71,547 Sale of natural gas and oil, net of production costs (53,914 ) Purchases of reserves in place 9,937 Sales of reserves in place (4,853 ) Revisions of previous quantity estimates (324,036 ) Net change in income tax 171,946 Net change in prices and production costs (604,074 ) Accretion of discount 98,869 Development costs incurred 10,500 Net change in estimated future development costs 31,131 Change in production rates (timing) and other 6,011 December 31, 2015 $ 229,803 Extensions and discoveries, less related costs 19,270 Sale of natural gas and oil, net of production costs (36,900 ) Sales of reserves in place (16,023 ) Revisions of previous quantity estimates (115,785 ) Net change in income tax — Net change in prices and production costs (43,270 ) Accretion of discount (16,461 ) Net change in estimated future development costs 119,531 Change in production rates (timing) and other 1,166 December 31, 2016 $ 141,331 Extensions and discoveries, less related costs 100,746 Sale of natural gas and oil, net of production costs (49,746 ) Purchases of reserves in place 5,493 Sales of reserves in place (2,051 ) Revisions of previous quantity estimates 29,694 Net change in income tax (1,768 ) Net change in prices and production costs 78,978 Accretion of discount (14,133 ) Development costs incurred 385 Net change in estimated future development costs (8,595 ) Change in production rates (timing) and other 6,308 December 31, 2017 $ 286,642 |
Summary of Significant Accoun25
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation The consolidated financial statements of the Company are stated in U.S. dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). The preparation of these financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, related disclosure of contingent assets and liabilities, proved oil and natural gas reserves and the related disclosures in the accompanying consolidated financial statements. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved oil and natural gas reserve quantities and the related present value of estimated future net cash flows. See Note 17. “Supplemental Oil and Gas Disclosures.” |
Subsequent Events | Subsequent Events In preparing these financial statements, the Company has evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued and has disclosed certain subsequent events in these consolidated financial statements, as appropriate. WEHLU Sale On January 23, 2018, the Company entered into a definitive agreement of sale and purchase (the “Sale Agreement”) to divest its interest in the West Edmund Hunton Lime Unit (“WEHLU”) and adjacent undeveloped acreage to Revolution Resources, LLC, for $107.5 million, subject to, among other customary adjustments, adjustments for a property sale effective date of October 1, 2017 (the “WEHLU Sale”). Pursuant to the Sale Agreement, the WEHLU Sale closed on February 28, 2018. After effective date and other adjustments of approximately $8.7 million primarily related to revenues and direct operating expenses, net cash proceeds from the WEHLU Sale were approximately $98.8 million, subject to certain additional adjustments for final closing. The WEHLU Sale will be reflected as a reduction to the full cost pool and the Company will not record a gain or loss related to the divestiture as such divestiture did not result in a significant change to the depletion rate. CEO Resignation On February 26 Mr. Porter will remain employed by the Company until March 31, 2018 to assist with transitional matters. Mr. Porter’s resignation did not result from any disagreement with the Company regarding any matter related to the Company’s operations, policies or practices. In connection with the departure, on February 26, 2018, Mr. Porter entered into a Separation and Release Agreement with the Company, whereby (i) Mr. Porter immediately resigned from all positions, offices and directorships with the Company and any affiliates or subsidiaries, (ii) Mr. Porter’s employment with the Company is terminated effective March 31, 2018 (the “Termination Date”); (iii) Mr. Porter agreed to enter into a release of claims (the “Release”) in favor of the Company no earlier than the Termination Date and no later than the 21 st |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements of the Company include the consolidated accounts of all its subsidiaries. All significant inter-company accounts and transactions have been eliminated in consolidation. |
Use of estimates in Preparation of Financial Statements | Use of estimates in Preparation of Financial Statements The preparation of the consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements. The most significant estimates with regard to these financial statements relate to the provision for income taxes including uncertain tax positions, stock-based compensation, valuation of commodity derivatives contracts, future development and abandonment costs, estimates related to certain oil, condensate, natural gas and NGLs revenues and operating expenses, and the estimates of proved oil, condensate, natural gas and NGLs reserve quantities that are used to calculate depletion and impairment of proved oil and natural gas properties. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company’s cash and cash equivalents, which includes short-term investments such as money market deposits with a maturity of three months or less when purchased, amounted to $13.3 million and $71.5 million as of December 31, 2017 and 2016, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss. |
Accounts Receivable | Accounts Receivable Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible. During 2016, the Company determined that a receivable account from a third-party natural gas and NGLs purchaser would no longer be collectible as a result of the third-party purchaser filing for bankruptcy. A summary of the activity related to the allowance for doubtful accounts is as follows: For the Years Ended December 31, 2017 2016 2015 (in thousands) Allowance for doubtful accounts, beginning of year $ 1,953 $ — $ — Expense — 1,953 — Reductions/write-offs — — — Allowance for doubtful accounts, end of year $ 1,953 $ 1,953 $ — |
Oil and Natural Gas Properties | Oil and Natural Gas Properties The Company follows the full cost method of accounting for oil and natural gas operations, whereby all costs incurred in the acquisition, exploration and development of oil and natural gas reserves are initially capitalized into cost centers on a country-by-country basis and are amortized as reserves are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. Capitalized costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities. The U.S. is the Company’s only cost center. Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers. Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether an impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations. In applying the full cost method of accounting, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of oil and natural gas properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from the Company’s proved reserves using prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month price for oil and natural gas prices held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in oil and natural gas properties and as additional depletion expense. Proceeds from a sale of oil and natural gas properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization. The Company’s estimate of proved reserves is based on the quantities of oil, condensate, natural gas and NGLs that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. As discussed below, the estimate of the Company’s proved reserves as of December 31, 2017 and 2016 have been prepared and presented in accordance with current rules and accounting standards promulgated by the Securities and Exchange Commission (the “SEC”). These rules require SEC reporting companies to prepare their reserve estimates using reserve definitions and pricing based on a 12-month unweighted arithmetic average of the first-day-of-the-month price. Reserves and their relation to estimated future net cash flows impact the Company’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The Company prepares its reserve estimates and the projected cash flows derived from these reserve estimates in accordance with SEC guidelines. The accuracy of the Company’s reserve estimates is a function of many factors, including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, condensate, natural gas and NGLs eventually recovered. The Company assesses unproved properties for impairment periodically and recognizes a loss where circumstances indicate impairment in value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current drilling plans, favorable or unfavorable activity on the properties being evaluated and/or adjacent properties and current market conditions. In the event that factors indicate an impairment in value, unproved properties leasehold costs are reclassified to proved properties and depleted. |
Asset Retirement Obligation | Asset Retirement Obligation Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost, through depreciation, depletion and amortization, are recognized in the results of operations. |
Furniture and Equipment | Furniture and Equipment Furniture and equipment are recorded at historical cost and are depreciated on a straight-line basis over their estimated useful lives, which range from three to seven years. |
Capitalized Interest | Capitalized Interest The Company capitalizes interest on assets not being amortized, such as our unproved oil and natural gas properties. The interest to be capitalized for any period is derived by multiplying the average rate of interest times the average qualifying assets during the period, not to exceed the total interest on the qualifying debt instruments. To qualify for interest capitalization, the Company must continue to make progress on the development of the assets. Capitalized interest costs were approximately $7.2 million, $3.1 million and $3.9 million for 2017, 2016 and 2015, respectively. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments The fair value of financial instruments is determined at discrete points in time based on relevant market information. Such estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, and accounts and revenue payables approximates their carrying value due to their short-term nature. Derivative instruments are also recorded on the balance sheet at fair value. |
Deferred Financing Costs and Debt Discounts | Deferred Financing Costs and Debt Discounts Deferred financing costs include costs of debt financings undertaken by the Company, including commissions, legal fees and other direct costs of financing paid to creditors. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument to interest expense. Deferred financing costs are presented as a direct reduction to the carrying amount of the related debt liability where the debt liability is not a line-of-credit arrangement. Debt discounts are recorded when it is determined that the fair value of the debt instrument at issuance is less than the face value of such instrument. The debt discounts are presented as a direct reduction to the carrying amount of the related debt liability and are amortized over the life of the debt instrument using the effective interest method. |
Derivative Instruments and Hedging Activity | Derivative Instruments and Hedging Activity The Company uses derivative instruments in the form of commodity costless collars, index swaps, basis and fixed price swaps and put and call options to manage price risks resulting from fluctuations in commodity prices of oil, condensate, natural gas and NGLs associated with future production. Derivative instruments are recorded on the balance sheet at fair value, and changes in the fair value of derivatives are recorded each period in current earnings. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and, as necessary, estimated volatility factors. The fair values that the Company reports in its consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond the Company’s control. Gains and losses on derivatives are included in total revenue within the period in which they occur. The resulting cash flows from derivatives are reported as cash flows from operating activities. See Note 7, “Derivative Instruments and Hedging Activity.” The Company has elected not to designate derivative contracts as cash flow hedges. As a result, any changes in the fair values of derivative contracts for future production are recognized in gain (loss) on commodity derivatives contracts within the Company’s consolidated statements of operations. Gains or losses from the settlement of matured commodity derivatives contracts are included in gain (loss) on commodity derivatives contracts in the Company’s consolidated statement of operations. |
Stock-Based Compensation | Stock-Based Compensation The Company reports compensation expense for restricted common stock and performance based units (“PBUs”) granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period. Stock-based compensation expense is recognized using the “graded-vesting method,” which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards. Stock-based compensation cost for restricted shares is estimated at the grant date based on the award’s fair value, which is equal to the prior day’s closing stock price. Such fair value is recognized as expense over the requisite service period. Stock-based compensation cost for PBUs is estimated at the grant date based on the award’s fair value, which is calculated using a Monte Carlo Simulation model. The Monte Carlo Simulation model uses a stochastic process to create a range of potential future outcomes given a variety of inputs, including expected future stock price based on predictive assumptions of volatility, risk free rate, random numbers, the current stock price and forecast period. Such fair value is recognized as expense over the requisite service period. Prior to 2017, forfeitures of unvested stock options and restricted common shares historically were calculated at the beginning of the year as a percentage of all stock option and restricted common share grants. Beginning in 2017, the Company no longer applies a forfeiture rate at grant and accounts for forfeitures as they occur. For 2016 and 2015, the Company used forfeiture rates in determining compensation expense of 19.1% and 17.5%, respectively. |
Revenue Recognition | Revenue Recognition The Company uses the sales method of accounting for the sale of its oil, condensate, natural gas and NGLs and records revenues from the sale of such products when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when oil, condensate, natural gas or NGLs have been delivered to a pipeline or a tank lifting has occurred. The Company’s NGLs are sold as part of the wet gas subject to an incremental NGLs pricing formula based upon a percentage of NGLs extracted from the Company’s wet gas production. Under the sales method, revenues are recorded based on the Company’s net revenue interest, as delivered. When actual natural gas sales volumes exceed our delivered share of sales volumes, an over-produced imbalance occurs. To the extent an over-produced imbalance exceeds our share of the remaining estimated proved natural gas reserves for a given property, the Company records a liability. The Company had no material gas imbalances at December 31, 2017, 2016 and 2015. The Company records its share of revenues based on production volumes and contracted sales prices. The sales price for oil, condensate, natural gas and NGLs are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. The Company calculates and pays royalties on oil, condensate, natural gas and NGLs in accordance with the particular contractual provisions of the lease. Royalty liabilities are recorded in conjunction with the cash receipts for oil, condensate, natural gas and NGLs revenues and are included in revenue payable on the Company’s consolidated balance sheet. |
Deferred Income Taxes | Deferred Income Taxes Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carry-forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Deferred tax assets are routinely evaluated to determine the likelihood of realization and the Company must estimate its expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events such as future operating conditions, particularly related to prevailing oil, condensate, natural gas and NGLs prices, and future financial conditions. The estimates or assumptions used in determining future taxable income are consistent with those used in internal budgets and forecasts. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation allowance to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time. |
Earnings or Loss per Share | Earnings or Loss per Share Basic earnings or loss per share is computed by dividing net income (loss) available to common stockholders, net of accumulated paid and unpaid dividends, by the weighted average number of shares of common stock outstanding. Diluted earnings or loss per share is computed by dividing net income (loss) available to common stockholders, net of accumulated and unpaid dividends, by the weighted average number of shares of common stock outstanding plus the incremental effect of the assumed issuance of common stock for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common stock are exercised or converted to common stock. The treasury stock method is used to determine the dilutive effect of unvested restricted shares and PBUs. |
Co-participation Operations | Co-participation Operations The majority of the Company’s oil and natural gas exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities. |
Industry Segment and Geographic Information | Industry Segment and Geographic Information The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long-lived assets located outside the U.S. |
Recent Accounting Developments | Recent Accounting Developments Business Combinations. In January 2017, the Financial Accounting Standards Board (“FASB”) issued updated guidance to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments in this update provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments in this update (1) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments in this update affect all reporting entities that must determine whether they have acquired or sold a business and are effective for public business entities for annual reporting periods beginning after December 15, 2017, including interim periods within those periods. The amendments should be applied prospectively on or after the effective date and no disclosures are required at transition. Early application is allowed as follows (1) for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance and (2) for transactions in which a subsidiary is deconsolidated or a group of assets is derecognized that occur before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance. The application of this guidance to future acquisitions and disposals could have an immediate effect on the Company’s financial position or results of operations. Statement of Cash Flows. In August 2016, the FASB issued updated guidance associated with the classification of certain cash receipts and cash payments on the statement of cash flows. The amended guidance addresses specific cash flow issues with the objective of reducing existing diversity in practice. The amendment provides guidance on the following eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The amendments in this update apply to all entities required to present a statement of cash flows. The amendments in this update are effective for public business entities for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. Amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. The Company adopted this update guidance for the fiscal year beginning January 1, 2018 and has determined that such adoption does not have a material effect on its statement of cash flows nor does it affect the Company’s financial position or results of operations. Compensation – Stock Compensation. In March 2016, the FASB issued updated guidance as part of its simplification initiative which is intended to simplify several aspects of the accounting for stock-based compensation transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. For public business entities, the amendments in this update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Amendments related to the timing of when excess tax benefits are recognized, minimum statutory withholding requirements, forfeitures, and intrinsic value should be applied using a modified retrospective transition method by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. Amendments related to the presentation of employee taxes paid on the statement of cash flows when an employer withholds shares to meet the minimum statutory withholding requirement should be applied retrospectively. Amendments requiring recognition of excess tax benefits and tax deficiencies in the income statement and the practical expedient for estimating expected term should be applied prospectively. An entity may elect to apply the amendments related to the presentation of excess tax benefits on the statement of cash flows using either a prospective transition method or a retrospective transition method. The Company adopted this updated guidance for the fiscal year beginning January 1, 2017 and recorded a cumulative adjustment of approximately $657,000 to retained earnings to properly reflect the adjustment to stock compensation expense to reduce the forfeiture rate to 0%. Leases. In February 2016, the FASB issued updated guidance to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and enhance disclosures regarding key information about leasing arrangements. Under the new guidance, lessees will be required to recognize a lease liability and a right-of-use asset for all leases. The new lease guidance also simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. The amendments in this update are effective beginning on January 1, 2019 and should be applied through a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Early adoption is permitted. The Company has begun analyzing its lease contracts but has not yet determined what the effects of adopting this updated guidance will be on its consolidated financial statements. Income Taxes. In November 2015, the FASB issued updated guidance as part of its simplification initiative for the presentation of deferred taxes. Current U.S. GAAP requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified statement of financial position where such classification generally does not align with the time period in which the recognized deferred tax amounts are expected to be recovered or settled. To simplify the presentation of deferred income taxes, the amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position and apply to all entities that present a classified statement of financial position, resulting in the alignment of the presentation of deferred income tax assets and liabilities with International Financial Reporting Standards, International Accounting Standard 1, . This updated guidance is effective for public business entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company has adopted this guidance prospectively and such adoption did not have an impact on its consolidated financial statements. Revenue Recognition. The Company has completed its scoping and assessment of impact of the new revenue recognition standard. The Company has evaluated a representative sample of revenue contracts related to its oil, natural gas and NGLs revenues. For these contracts, the Company has reviewed the contract provisions and evaluated the contracts under the new standard to assess the impact on the quantum and timing of revenue recognition and presentation of revenues on adoption of the new guidance. The Company believes that it has identified all material contract types and contractual features that represent the Company’s revenue. While the Company does not currently expect that the adoption of this standard will have a material impact on net profit, some reclassifications between revenue and expenses in relation to certain post-production expenses will be required based upon its assessment of i) where control passes to the customer and ii) whether the Company represents the principal or agent in certain of its revenue contracts. Beginning in 2018, the Company will record transportation, treating and gathering expenses as a direct reduction to oil, condensate, natural gas and NGLs revenues rather than as expenses. In addition, the Company’s disclosures surrounding revenue recognition will be more substantial upon adoption. The Company adopted this standard on January 1, 2018 using the modified retrospective method, in which the standard will be applied to all existing contracts as of the date of initial application with the cumulative effect of applying the standard recognized in retained earnings (the adoption date adjustments). Based on initial adoption, no adjustment to retained earnings is required. |
Summary of Significant Accoun26
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Summary of the activity related to the allowance for doubtful accounts | A summary of the activity related to the allowance for doubtful accounts is as follows: For the Years Ended December 31, 2017 2016 2015 (in thousands) Allowance for doubtful accounts, beginning of year $ 1,953 $ — $ — Expense — 1,953 — Reductions/write-offs — — — Allowance for doubtful accounts, end of year $ 1,953 $ 1,953 $ — |
Property, Plant And Equipment (
Property, Plant And Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Business Acquisition [Line Items] | |
Property, Plant and Equipment | The Company’s total property, plant and equipment consists of the following: December 31, 2017 2016 (in thousands) Oil and natural gas properties, full cost method of accounting: Unproved properties $ 131,955 $ 67,333 Proved properties 1,344,329 1,253,061 Total oil and natural gas properties 1,476,284 1,320,394 Furniture and equipment 3,838 2,622 Total property and equipment 1,480,122 1,323,016 Impairment of proved natural gas and oil properties (813,314 ) (813,314 ) Accumulated depreciation, depletion and amortization (341,713 ) (317,698 ) Total accumulated depreciation, depletion and amortization (1,155,027 ) (1,131,012 ) Total property and equipment, net $ 325,095 $ 192,004 |
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization | The following table summarizes the components of unproved properties excluded from amortization for the periods indicated: December 31, 2017 2016 (in thousands) Unproved properties, excluded from amortization: Drilling in progress costs $ 4,772 $ 1,100 Acreage acquisition costs 113,191 58,857 Capitalized interest 13,992 7,376 Total unproved properties excluded from amortization $ 131,955 $ 67,333 |
Schedule Of Relevant Assumptions Used In Ceiling Test Computations | The table below sets forth relevant pricing assumptions utilized in the quarterly ceiling test computations for the respective periods noted before adjustment for basis and quality differentials: 2017 Total December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.98 $ 3.00 $ 3.01 $ 2.73 West Texas Intermediate oil price (per Bbl) (1) $ 51.34 $ 49.81 $ 48.95 $ 47.61 Impairment recorded (pre-tax) (in thousands) $ — $ — $ — $ — $ — 2016 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.48 $ 2.28 $ 2.24 $ 2.40 West Texas Intermediate oil price (per Bbl) (1) $ 42.75 $ 41.68 $ 43.12 $ 46.26 Impairment recorded (pre-tax) (in thousands) $ 48,497 $ — $ — $ — $ 48,497 2015 Total Impairment December 31 September 30 June 30 March 31 Henry Hub natural gas price (per MMBtu) (1) $ 2.59 $ 3.06 $ 3.39 $ 3.88 West Texas Intermediate oil price (per Bbl) (1) $ 50.28 $ 59.21 $ 71.68 $ 82.72 Impairment recorded (pre-tax) (in thousands) $ 426,878 $ 144,760 $ 181,966 $ 100,152 $ — (1) For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub spot natural gas prices and West Texas Intermediate spot oil prices. |
Husky Acquisition | |
Business Acquisition [Line Items] | |
Business Acquisition, Pro Forma Information | The following unaudited pro forma results for the year ended December 31, 2015 shows the effect on the Company’s consolidated results of operations as if the Husky Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statements of revenues and direct operating expenses for the properties acquired from Husky adjusted for (1) assumption of ARO liabilities and accretion expense for the properties acquired and (2) additional depreciation, depletion and amortization expense as a result of the Company’s increased ownership in the acquired properties. The statements of revenues and direct operating expenses for the Husky Acquisition assets exclude all other historical expenses of Husky. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Year Ended December 31, 2015 (in thousands, except (Unaudited) Revenues $ 115,147 Net loss $ (470,874 ) Loss per share: Basic $ (6.07 ) Diluted $ (6.07 ) |
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table summarizes the fair value of the assets acquired and liabilities assumed in connection with the Husky Acquisition (in thousands): Consideration: Cash consideration $ 42,085 Conveyance of undeveloped acreage — Total purchase price $ 42,085 Estimated Fair Value of Assets Acquired: Unproved properties $ 27,875 Proved properties 15,592 Other (1,382 ) Total assets acquired $ 42,085 |
Appalachian Basin | |
Business Acquisition [Line Items] | |
Business Acquisition, Pro Forma Information | The following unaudited pro forma results for the years ended December 31, 2016 and 2015 show the effect on the Company’s consolidated results of operations as if the Appalachian Basin Sale had occurred at the beginning of the periods presented. The pro forma results are the result of excluding from the statement of operations of the Company the revenues and direct operating expenses for the properties divested adjusted for (1) the reduction in asset retirement obligation (“ARO”) liabilities and accretion expense for the properties divested, (2) the reduction in depreciation, depletion and amortization expense as a result of the divestiture and (3) the reduction in interest expense as a result of the pay down of debt under the Revolving Credit Facility (as defined below) in conjunction with the closing of the Appalachian Basin Sale. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. For the Years Ended December 31, 2016 2015 (in thousands, except (Unaudited) Revenues $ 55,177 $ 93,783 Net loss $ (98,459 ) $ (464,788 ) Loss per share: Basic $ (0.88 ) $ (6.00 ) Diluted $ (0.88 ) $ (6.00 ) |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Summary of Reconciliation of Long-Term Debt Balance | The table below provides a reconciliation of the Company’s long-term debt balance as presented in the consolidated balance sheets for the periods presented: December 31, 2017 2016 (in thousands) Term Loan, principal balance (1) $ 256,599 $ — Less: Unamortized deferred financing costs (2) (4,724 ) — Unamortized debt discount (2) (22,464 ) — Term Loan, net $ 229,411 $ — Notes, principal balance $ 162,500 $ — Less: Unamortized deferred financing costs (2) (2,631 ) — Unamortized debt discount (2) (46,328 ) — Notes, net $ 113,541 $ — Revolving credit facility $ — $ 84,630 Former senior secured notes $ — $ 325,000 Less: Unamortized deferred financing costs — (795 ) Unamortized debt discount (4,342 ) Former senior secured notes, net $ — $ 319,863 Total long-term debt $ 342,952 $ 404,493 (1) Pursuant to Amendment No. 2 (as defined below), on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan (as defined below) to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. (2) The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan and Notes (as defined below), respectively, based on the effective interest method. |
Summary of Carrying Amount of Equity Components of Notes Recorded in Additional Paid in Capital | The carrying amount of the equity components of the Notes recorded in additional paid in capital for the period indicated is as follows: December 31, 2017 (in thousands) Value of conversion option $ 77,626 Debt issuance costs attributable to conversion option $ (2,164 ) Total $ 75,462 |
Notes | |
Summary of Carrying Amount of Long-Term debt | The carrying amount of the liability component of the Notes for the period indicated is as follows: December 31, 2017 (in thousands) Notes, principal balance $ 162,500 Less: Unamortized deferred financing costs (1) (2,631 ) Unamortized debt discount (1) (46,328 ) Notes, net $ 113,541 (1) The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Notes based on the effective interest method. |
Term Loan | |
Summary of Carrying Amount of Long-Term debt | A carrying amount of the Term Loan for the period indicated is as follows: December 31, 2017 (in thousands) Term Loan, principal balance (1) $ 256,599 Less: Unamortized deferred financing costs (2) (4,724 ) Unamortized debt discount (2) (22,464 ) Term loan, net $ 229,411 (1) Pursuant to Amendment No. 2, on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. (2) The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan based on the effective interest method. |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations | A summary of the activity related to the asset retirement obligation is as follows: For the Years Ended December 31, 2017 2016 (in thousands) Asset retirement obligation, beginning of year $ 5,532 $ 6,086 Liabilities incurred during period 383 196 Liabilities settled during period — (90 ) Accretion expense 237 368 Revision in previous estimates and other 222 17 Deletions related to property disposals (1,533 ) (1,045 ) Asset retirement obligation, end of year $ 4,841 $ 5,532 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements, Recurring and Nonrecurring | The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 2016: Fair value as of December 31, 2017 Level 1 Level 2 Level 3 Total (in thousands) Assets: Commodity derivative contracts — — 1,370 1,370 Liabilities: Commodity derivative contracts — — (6,988 ) (6,988 ) Total $ — $ — $ (5,618 ) $ (5,618 ) Fair value as of December 31, 2016 Level 1 Level 2 Level 3 Total (in thousands) Assets: Commodity derivative contracts — — 7,850 7,850 Liabilities: Commodity derivative contracts — — (338 ) (338 ) Total $ — $ — $ 7,512 $ 7,512 |
Fair Value Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation | The table below presents a reconciliation of the assets and liabilities classified as Level 3 in the fair value hierarchy for the years ended December 31, 2017 and 2016. Level 3 instruments presented in the table consist of net derivatives that, in management’s opinion, reflect the assumptions a marketplace participant would have used at December 31, 2017 and 2016. For the Years Ended December 31, 2017 2016 (in thousands) Balance at beginning of period $ 7,512 $ 24,418 Total losses, net included in earnings (4,457 ) (2,863 ) Purchases 1,888 565 Issuances — (165 ) Settlements (1) (10,561 ) (14,443 ) Balance at end of period $ (5,618 ) $ 7,512 The amount of total losses for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2017 and 2016 $ (11,875 ) $ (13,622 ) (1) Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations. |
Derivative Instruments and He31
Derivative Instruments and Hedging Activity (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative [Line Items] | |
Summary of Information Regarding Deferred Put Premium Liabilities | The following table provides information regarding the deferred put premium liabilities for the periods indicated: December 31, 2017 2016 (in thousands) Current commodity derivative premium put payable $ 135 $ 1,654 Long-term commodity derivative premium payable — 969 Total unamortized put premium liabilities $ 135 $ 2,623 For the Years Ended December 31, 2017 2016 (in thousands) Put premium liabilities, beginning balance $ 2,623 $ 5,982 Settlement of put premium liabilities (2,958 ) (3,194 ) Additional put premium liabilities 470 (165 ) Put premium liabilities, ending balance $ 135 $ 2,623 |
Summary of Information on the Location and Amounts of Commodity Derivative Fair Values and Commodity Derivative Gains and Losses | The tables below provide information on the location and amounts of commodity derivative fair values in the consolidated statement of financial position and commodity derivative gains and losses in the consolidated statement of operations for derivative instruments that are not designated as hedging instruments: Fair Values of Derivative Instruments Derivative Assets (Liabilities) Fair Value December 31, Balance Sheet Location 2017 2016 (in thousands) Derivatives not designated as hedging instruments Commodity derivative contracts Current assets $ 1,370 $ 6,212 Commodity derivative contracts Other assets — 1,638 Commodity derivative contracts Current liabilities (4,416 ) (338 ) Commodity derivative contracts Long-term liabilities (2,572 ) — Total derivatives not designated as hedging instruments $ (5,618 ) $ 7,512 Amount of (Loss) Gain Recognized in Income on Derivatives For the Years Ended December 31, Location of (Loss) Gain Recognized in Income on Derivatives 2017 2016 2015 (in thousands) Derivatives Commodity derivative contracts (Loss) gain on commodity derivatives contracts $ (4,457 ) $ (2,863 ) $ 24,589 Total $ (4,457 ) $ (2,863 ) $ 24,589 |
Natural Gas | |
Derivative [Line Items] | |
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions | As of December 31, 2017, the following natural gas derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in MMBtu’s) February to December 2018 Costless three-way collar 5,000 1,670,000 $ — $ 3.00 $ 2.35 $ 4.00 February to March 2018 Costless Collar 5,800 342,200 $ — $ 3.00 $ — $ 4.28 April to December 2018 Fixed price swap 1,550 426,250 $ 3.01 $ — $ — $ — |
Crude Oil | |
Derivative [Line Items] | |
Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions | As of December 31, 2017, the following crude derivative transactions were outstanding with the associated notional volumes and weighted average underlying hedge prices: Settlement Period Derivative Instrument Average Daily Volume (1) Total of Notional Volume Base Fixed Price Floor (Long) Short Put Ceiling (Short) (in Bbls) January to December 2018 Costless three-way collar 500 182,500 $ — $ 50.00 $ 40.00 $ 61.60 January to March 2018 Costless three-way collar 1,800 162,000 $ — $ 47.50 $ 37.50 $ 57.85 April to June 2018 Costless three-way collar 1,700 154,700 $ — $ 47.50 $ 37.50 $ 57.85 July to September 2018 Costless three-way collar 1,600 147,200 $ — $ 47.50 $ 37.50 $ 57.85 October to December 2018 Costless three-way collar 1,700 156,400 $ — $ 47.50 $ 37.50 $ 57.85 January to June 2018 Fixed price swap 200 36,200 $ 50.11 $ — $ — $ — January to June 2018 Fixed price swap 600 108,600 $ 51.20 $ — $ — $ — January to August 2018 Fixed price swap 425 103,275 $ 66.45 $ — $ — $ — July to September 2018 Fixed price swap 500 46,000 $ 51.20 $ — $ — $ — October to December 2018 Fixed price swap 600 55,200 $ 51.20 $ — $ — $ — January to September 2019 Costless three-way collar 2,000 546,000 $ — $ 47.50 $ 37.50 $ 59.70 October to December 2019 Costless three-way collar 1,900 174,800 $ — $ 47.50 $ 37.50 $ 59.70 January to September 2019 Fixed price swap 700 191,100 $ 50.40 $ — $ — $ — October to December 2019 Fixed price swap 600 55,200 $ 50.40 $ — $ — $ — (1) Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production. |
Capital Stock (Tables)
Capital Stock (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Stockholders Equity Note [Abstract] | |
Schedule of Issuances And Forfeitures Of Common Shares | The following table provides information regarding the issuances and forfeitures of the Company’s common stock pursuant to the Gastar Exploration Inc. Long-Term Incentive Plan for the periods indicated: For 2017 2016 Other stock issuances: Shares of restricted common stock granted 8,649,343 1,764,645 Shares of restricted common stock vested 1,270,171 1,487,269 Shares of common stock issued pursuant to PBUs vested, net of forfeitures of 207,891 shares — 502,593 Shares of restricted common stock surrendered upon vesting/exercise (1) 373,741 392,094 Shares of restricted common stock forfeited 91,801 128,435 (1) Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period. |
Equity Compensation Plans (Tabl
Equity Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable | The following tables summarize certain information related to outstanding stock options under the LTIP as of and for the year ended December 31, 2017: Shares Weighted Average Exercise Price per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding at December 31, 2016 214,600 $ 4.87 Granted — — Exercised — — Canceled/Expired (50,200 ) 10.95 Forfeited — — Outstanding at December 31, 2017 164,400 $ 3.01 Options vested and exercisable at December 31, 2017 164,400 $ 3.01 1.42 $ — |
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity | The following table summarizes information related to restricted shares at December 31, 2017: Shares Weighted Fair Value per Share Weighted Average Remaining Contractual Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding non-vested restricted shares at December 31, 2016 2,445,290 $ 1.79 Granted 8,649,343 1.09 Vested (1,270,171 ) 2.07 Forfeited (91,801 ) 1.65 Outstanding non-vested restricted shares at December 31, 2017 9,732,661 $ 1.13 3.39 $ 10,219 |
Schedule of Share-based Compensation, Stock Options, Activity | The table below provides a summary of PBUs as of the date indicated: PBUs Weighted Average Fair per Unit Unvested PBUs at December 31, 2016 1,475,730 $ 2.49 Granted 830,196 2.38 Vested (79,020 ) 7.34 Forfeited — — Unvested PBUs at December 31, 2017 2,226,906 $ 2.27 |
Schedule of Unrecognized Compensation Cost, Nonvested Awards | As of December 31, 2017, the Company had approximately $8.0 million of total unrecognized compensation cost related to unvested restricted shares and PBUs, which is expected to be amortized over the following periods: Amount (in thousands) 2018 $ 4,558 2019 2,290 2020 725 2021 297 2022 100 Total $ 7,970 |
Unvested restricted shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value | The following table summarizes the weighted average grant date fair value of restricted shares granted and the total fair value of shares vested for the periods indicated: For the Years Ended December 31, 2017 2016 2015 (in thousands, except per share data) Weighted average grant date fair value per restricted share $ 1.09 $ 1.19 $ 2.40 Total fair value of restricted shares vested $ 2,627 $ 3,530 $ 3,794 |
Interest Expense (Tables)
Interest Expense (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Interest Expense [Abstract] | |
Schedule Of Components Of Interest Expense | The following tables summarize the components of the Company’s interest expense for the periods indicated: For the Years Ended December 31, 2017 2016 2015 (in thousands) Interest expense: Cash and accrued $ 35,185 $ 33,368 $ 30,981 Amortization of deferred financing costs (1) 10,977 4,980 3,584 Capitalized interest (7,207 ) (3,102 ) (3,879 ) Total interest expense $ 38,955 $ 35,246 $ 30,686 (1) |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Income Tax Disclosure [Abstract] | |
Schedule of (Loss) Income before Income Taxes | The following table summarizes the components of the Company’s (loss) income before income taxes for the periods indicated: For the Years Ended December 31, 2017 2016 2015 (in thousands) United States $ (46,755 ) $ (89,061 ) $ (459,507 ) Total income (loss) before income taxes $ (46,755 ) $ (89,061 ) $ (459,507 ) |
Schedule of Effective Income Tax Rate Reconciliation | The following table provides a reconciliation of the Company’s effective tax rate from the U.S. 35% statutory rate for 2017, 2016 and 2015. Additionally, the table reflects the impact of the rate change from 38% to 24.6% on the net deferred tax asset for the year ended December 31, 2017 pursuant to the Tax Act as well as the estimated effect of limitations on available net operating loss and tax credit carry forwards by reason of an ownership change (discussed below). For the Years Ended December 31, 2017 2016 2015 (in thousands) Expected income tax benefit at statutory rate $ (16,364 ) $ (31,172 ) $ (160,827 ) State tax, tax effected (1,085 ) (1,408 ) (7,799 ) Non-deductible convertible debt discount 3,092 — — Stock-based compensation expense 523 1,995 255 Non-deductible compensation 63 178 — Effect of rate change on net deferred tax asset 64,515 — — Effect of ownership change on estimated realization of net operating loss and tax credit carry forwards 119,654 — — State tax rate change and other 3,101 693 17 Other changes in valuation allowance (173,499 ) 29,714 168,354 Actual income tax provision $ — $ — $ — |
Schedule of Deferred Tax Assets and Liabilities | The components of the Company’s U.S. deferred taxes are as follows for the periods presented: As of December 31, 2017 2016 (in thousands) Deferred tax asset: Capital assets $ 27,137 $ 33,131 Stock-based compensation 2,390 2,499 Net operating loss carry forwards 80,060 196,775 Foreign tax credit carry forwards — 50,681 Valuation allowance (109,587 ) (283,086 ) Net deferred tax asset $ — $ — |
Earnings per Share (Tables)
Earnings per Share (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share, Basic and Diluted | For the Years Ended December 31, 2017 2016 2015 (in thousands, except per share and share data) Net loss attributable to common stockholders $ (61,228 ) $ (103,534 ) $ (473,980 ) Weighted average shares of common stock outstanding - basic 195,369,489 111,367,452 77,511,677 Weighted average shares of common stock outstanding - diluted 195,369,489 111,367,452 77,511,677 Net (loss) income per share of common stock attributable to common stockholders: Basic $ (0.31 ) $ (0.93 ) $ (6.11 ) Diluted $ (0.31 ) $ (0.93 ) $ (6.11 ) Shares of common stock excluded from denominator as anti-dilutive: Unvested restricted shares 821,710 438,948 177,663 Unvested PBUs 427,382 487,995 17,589 Convertible Notes 65,488,114 — — Total 66,737,206 926,943 195,252 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Commitments And Contingencies Disclosure [Abstract] | |
Schedule of future minimum annual rental commitments | As of December 31, 2017, the Company’s aggregate future minimum annual rental commitments under the non-cancelable leases for the next five years are as follows: 2018 $ 977 2019 971 2020 979 2021 971 2022 and thereafter 322 $ 4,220 |
Concentration of Risk and Sig38
Concentration of Risk and Significant Customers (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Risks And Uncertainties [Abstract] | |
Schedules of Concentration of Risk, by Risk Factor | The following table provides information regarding the approximate percentages of the Company’s oil, condensate, natural gas and NGLs revenues excluding hedge impact by area derived from production from producing wells for the periods indicated: For the Years Ended December 31, 2017 2016 2015 Appalachian Basin 0 % 5 % 17 % Mid-Continent 100 % 95 % 83 % The following table provides information regarding the Company’s significant customers whom accounted for more than 10% of the Company’s oil, condensate, natural gas and NGLs revenues, excluding hedge impact, for the periods indicated: For the Years Ended December 31, 2017 2016 2015 Sunoco 61 % 67 % 62 % Superior 14 % 12 % 6 % SEI (1) 0 % 5 % 22 % (1) SEI filed for Chapter 7 bankruptcy on June 3, 2016. |
Statement of Cash Flows - Sup39
Statement of Cash Flows - Supplemental Information (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Cash Flow Information [Abstract] | |
Statement of Cash Flows Supplemental Information | The following is a summary of the Company's supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements: For the Years Ended December 31, 2017 2016 2015 (in thousands) Cash paid for interest, net of capitalized amounts $ 17,596 $ 30,480 $ 26,859 Non-cash transactions: Capital expenditures included in (excluded from) accounts payable and accrued drilling costs $ 23,215 $ (82 ) $ (26,228 ) Capital expenditures included in accounts receivable 76 409 — Asset retirement obligation included in oil and natural gas properties 605 432 526 Asset retirement obligation for property disposals (1,533 ) (1,045 ) (416 ) Application of advances to operators 64 (347 ) 11,445 Undeclared cumulative dividends on preferred stock 6,030 10,855 — Conversion of convertible debt to equity 37,500 — — Other — — 5 |
Quarterly Consolidated Financ40
Quarterly Consolidated Financial Data - Unaudited (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule Of Quarterly Financial Information | The following tables summarize the Company’s results of operations by quarter for the years ended December 31, 2017 and 2016: 2017 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 18,669 $ 22,646 $ 15,332 $ 15,483 Income (loss) from operations 4,274 5,891 (2,191 ) (3,777 ) Loss before provision for income taxes (1) (18,698 ) (2,779 ) (12,299 ) (12,979 ) Net loss (1) (18,698 ) (2,779 ) (12,299 ) (12,979 ) Dividends on preferred stock 3,618 3,619 1,206 — Undeclared cumulative dividends on preferred stock — — 2,412 3,618 Net loss attributable to common stockholders (1) (22,316 ) (6,398 ) (15,917 ) (16,597 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.14 ) $ (0.03 ) $ (0.08 ) $ (0.08 ) Diluted $ (0.14 ) $ (0.03 ) $ (0.08 ) $ (0.08 ) Weighted average shares of common stock outstanding: Basic 162,829,221 199,547,446 209,072,232 209,089,468 Diluted 162,829,221 199,547,446 209,072,232 209,089,468 (1) The first quarter includes a $12.2 million loss on early extinguishment of debt. 2016 First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except share and per share data) Revenues $ 14,811 $ 12,153 $ 13,003 $ 18,287 Income (loss) from operations (1) (60,592 ) (5,142 ) 7,959 3,929 Income (loss) before provision for income taxes (1) (69,857 ) (14,481 ) (178 ) (4,545 ) Net income (loss) (1) (69,857 ) (14,481 ) (178 ) (4,545 ) Dividends on preferred stock 3,618 — — — Undeclared cumulative dividends on preferred stock — 3,619 3,618 3,618 Net loss attributable to common stockholders (1) (73,475 ) (18,100 ) (3,796 ) (8,163 ) Net loss per share of common stock attributable to common stockholders: Basic $ (0.93 ) $ (0.17 ) $ (0.03 ) $ (0.06 ) Diluted $ (0.93 ) $ (0.17 ) $ (0.03 ) $ (0.06 ) Weighted average shares of common stock outstanding: Basic 78,788,133 104,009,337 129,301,817 132,936,419 Diluted 78,788,133 104,009,337 129,301,817 132,936,419 (1) The first quarter includes impairment of oil and natural gas properties of $48.5 million and the third quarter includes $10.1 million of litigation settlement benefit. |
Supplemental Oil and Gas Disc41
Supplemental Oil and Gas Disclosures - Unaudited (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Extractive Industries [Abstract] | |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure | The following table presents the Company’s aggregate capitalized costs relating to oil and natural gas producing activities in the U.S. for the periods indicated: As of December 31, 2017 2016 2015 (in thousands) Proved properties $ 1,344,329 $ 1,253,061 $ 1,286,373 Unproved properties 131,955 67,333 92,609 Total oil and natural gas properties 1,476,284 1,320,394 1,378,982 Less: Impairment of proved oil and natural gas properties (813,314 ) (813,314 ) (764,817 ) Accumulated depreciation, depletion and amortization (339,043 ) (315,373 ) (286,020 ) Net capitalized costs $ 323,927 $ 191,707 $ 328,145 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure | The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the periods indicated: For the Years Ended December 31, 2017 2016 2015 (in thousands) Property acquisition Proved $ 6,059 $ 570 $ 15,615 Unproved 91,266 38,941 50,434 Exploration 59,771 19,761 53,290 Development 29,103 3,810 54,316 Total costs incurred $ 186,199 $ 63,082 $ 173,655 |
Results of Operations for Oil and Gas Producing Activities Disclosure | The following table sets forth the Company’s results of operations for oil and natural gas producing activities for the periods indicated: For the Year Ended December 31, 2017 2016 2015 (in thousands, except per Mcfe data) Oil, condensate, natural gas and NGLs sales, including commodity derivatives $ 72,130 $ 58,254 $ 107,294 Production expenses (26,839 ) (24,217 ) (28,792 ) Impairment of oil and natural gas properties — (48,497 ) (426,878 ) Depreciation, depletion and amortization (23,670 ) (29,353 ) (62,465 ) Results of producing activities $ 21,621 $ (43,813 ) $ (410,841 ) |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities | The following tables set forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2017, 2016 and 2015: Change in Proved Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) Proved reserves as of December 31, 2014 28,636 287,005 25,593 102,063 2015 Activity: Extensions and discoveries (4) 4,777 14,114 2,244 9,374 Revisions of previous estimates (5) (8,962 ) (182,600 ) (13,873 ) (53,268 ) Production (1,425 ) (13,759 ) (1,212 ) (4,931 ) Purchases in place 1,270 4,965 873 2,971 Sales in place (94 ) (1,274 ) (26 ) (332 ) Proved reserves as of December 31, 2015 24,202 108,451 13,599 55,877 2016 Activity: Extensions and discoveries 1,582 7,213 898 3,681 Revisions of previous estimates (6) (9,890 ) (17,825 ) (3,317 ) (16,177 ) Production (1,105 ) (6,145 ) (739 ) (2,869 ) Sales in place (1,033 ) (53,841 ) (4,929 ) (14,935 ) Proved reserves as of December 31, 2016 13,756 37,853 5,512 25,577 2017 Activity: Extensions and discoveries (7) 8,787 26,065 3,243 16,374 Revisions of previous estimates 1,373 4,295 798 2,887 Production (1,118 ) (3,795 ) (527 ) (2,278 ) Purchases in place 182 1,391 198 612 Sales in place (124 ) (444 ) (47 ) (245 ) Proved reserves as of December 31, 2017 22,856 65,365 9,177 42,927 (1) Thousand barrels (2) Million cubic feet (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. (4) All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations. ( 5 ) The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. (6) The 2016 revisions of previous estimates resulted primarily from the removal of Hunton PUD locations as the Company now focuses its capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate its STACK Play position. ( 7 ) All of the 2017 extensions and discoveries resulted from the Company’s successful STACK Play drilling operations. Proved Developed and Undeveloped Reserves Condensate and Oil (MBbl) (1) Natural Gas (MMcf) (2) NGLs (MBbl) (1) MBoe Equivalents (3) December 31, 2015 Proved developed reserves 7,181 77,966 8,240 28,415 Proved undeveloped reserves 17,021 30,485 5,359 27,462 Total 24,202 108,451 13,599 55,877 December 31, 2016 Proved developed reserves 6,037 22,786 3,181 13,015 Proved undeveloped reserves 7,719 15,067 2,331 12,562 Total 13,756 37,853 5,512 25,577 December 31, 2017 Proved developed reserves 8,140 31,723 4,600 18,027 Proved undeveloped reserves 14,716 33,642 4,577 24,900 Total 22,856 65,365 9,177 42,927 (1) Thousand barrels (2) Million cubic feet (3) Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. |
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure | For the periods indicated, the following benchmark base prices for natural gas and oil, before lease adjustments, were used in the calculations: For the Years Ended December 31, 2017 2016 2015 Natural gas, per MMBtu Henry Hub $ 2.98 $ 2.48 $ 2.59 Oil, per barrel: WTI spot $ 51.34 $ 42.75 $ 50.28 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure | The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves in the U.S. is presented below (in thousands): December 31, 2015: Future cash inflows $ 1,425,734 Future production costs (547,484 ) Future development costs (365,123 ) Future income taxes (1) — Future net cash flows 513,127 10% annual discount for estimated timing of cash flows (283,324 ) Standardized measure of discounted future cash flows $ 229,803 December 31, 2016: Future cash inflows $ 710,370 Future production costs (328,010 ) Future development costs (123,214 ) Future income taxes (1) — Future net cash flows 259,146 10% annual discount for estimated timing of cash flows (117,815 ) Standardized measure of discounted future cash flows $ 141,331 December 31, 2017: Future cash inflows $ 1,491,158 Future production costs (645,891 ) Future development costs (295,212 ) Future income taxes (1,768 ) Future net cash flows 548,287 10% annual discount for estimated timing of cash flows (261,645 ) Standardized measure of discounted future cash flows $ 286,642 (1) No future taxes payable has been included in the determination of discounted future net cash flows for 2015 and 2016 due to existing tax loss carry forwards and property tax basis exceeding future net cash flows. |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows | The principal sources of changes in the standardized measure of future net cash flows are as follows (in thousands): December 31, 2014 $ 816,739 Extensions and discoveries, less related costs 71,547 Sale of natural gas and oil, net of production costs (53,914 ) Purchases of reserves in place 9,937 Sales of reserves in place (4,853 ) Revisions of previous quantity estimates (324,036 ) Net change in income tax 171,946 Net change in prices and production costs (604,074 ) Accretion of discount 98,869 Development costs incurred 10,500 Net change in estimated future development costs 31,131 Change in production rates (timing) and other 6,011 December 31, 2015 $ 229,803 Extensions and discoveries, less related costs 19,270 Sale of natural gas and oil, net of production costs (36,900 ) Sales of reserves in place (16,023 ) Revisions of previous quantity estimates (115,785 ) Net change in income tax — Net change in prices and production costs (43,270 ) Accretion of discount (16,461 ) Net change in estimated future development costs 119,531 Change in production rates (timing) and other 1,166 December 31, 2016 $ 141,331 Extensions and discoveries, less related costs 100,746 Sale of natural gas and oil, net of production costs (49,746 ) Purchases of reserves in place 5,493 Sales of reserves in place (2,051 ) Revisions of previous quantity estimates 29,694 Net change in income tax (1,768 ) Net change in prices and production costs 78,978 Accretion of discount (14,133 ) Development costs incurred 385 Net change in estimated future development costs (8,595 ) Change in production rates (timing) and other 6,308 December 31, 2017 $ 286,642 |
Description of Business (Narrat
Description of Business (Narrative) (Details) - USD ($) $ in Thousands | Jan. 20, 2017 | Apr. 08, 2016 | Feb. 19, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Exploratory Wells Drilled [Line Items] | ||||||
Proceeds from sale of oil and natural gas properties | $ 28,781 | $ 121,273 | $ 47,314 | |||
Appalachian Basin | ||||||
Exploratory Wells Drilled [Line Items] | ||||||
Proceeds from sale of oil and natural gas properties | $ 75,700 | $ 80,000 | ||||
Suspense liability transferred to buyer | $ 3,500 | |||||
Consideration on sale of remaining ownership interest | $ 200,000 |
Summary of Significant Accoun43
Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) | Feb. 26, 2018 | Jan. 23, 2018 | Oct. 02, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Accounting Policies [Line Items] | |||||||
Proceeds from sale of oil and natural gas properties | $ 28,781,000 | $ 121,273,000 | $ 47,314,000 | ||||
Resignation description | In connection with the departure, on February 26, 2018, Mr. Porter entered into a Separation and Release Agreement with the Company, whereby (i) Mr. Porter immediately resigned from all positions, offices and directorships with the Company and any affiliates or subsidiaries, (ii) Mr. Porter’s employment with the Company is terminated effective March 31, 2018 (the “Termination Date”); (iii) Mr. Porter agreed to enter into a release of claims (the “Release”) in favor of the Company no earlier than the Termination Date and no later than the 21st day following the Termination Date; (iv) subject to execution and delivery and continued effectiveness of the Release, a total of 2,583,298 shares of restricted stock held by Mr. Porter will vest; (v) subject to execution and delivery and continued effectiveness of the Release, Mr. Porter will receive approximately $3.5 million as a severance payment, which represents amounts he was entitled to receive pursuant to his employment agreement with the Company (including payment for accrued and unused vacation), plus a supplemental amount as consideration for his willingness to make himself available in a consulting capacity for a period of time following his separation; (vi) additional services as a consultant following the Termination Date will be paid to Mr. Porter at an hourly rate; (vii) the Company will reimburse (or pay on his behalf) Mr. Porter’s COBRA insurance premiums through the eighteenth month anniversary of the termination, in accordance with the terms of his employment agreement with the Company; and (viii) Mr. Porter will remain subject to certain noncompetition, noninterference and nonsolicitation covenants. | ||||||
Cash and cash equivalents | $ 13,266,000 | 71,529,000 | 50,074,000 | $ 11,008,000 | |||
Discount rate for oil and natural gas prices held constant | 10.00% | ||||||
Capitalized interest | $ 7,200,000 | $ 3,100,000 | $ 3,900,000 | ||||
Expected Forfeitures (percentage) | 19.10% | 17.50% | |||||
Cumulative adjustment to retained earnings | $ 657,000 | ||||||
Adjustment to reduce forfeiture rate | 0.00% | ||||||
Minimum | Furniture and equipment | |||||||
Accounting Policies [Line Items] | |||||||
Estimated useful lives | 3 years | ||||||
Maximum | Furniture and equipment | |||||||
Accounting Policies [Line Items] | |||||||
Estimated useful lives | 7 years | ||||||
Sale Agreement | |||||||
Accounting Policies [Line Items] | |||||||
Proceeds from sale of oil and natural gas properties | $ 98,800,000 | ||||||
Sale Agreement | Revenues and Direct Operating Expenses | |||||||
Accounting Policies [Line Items] | |||||||
Adjustments related to revenues and direct operating expenses | $ 8,700,000 | ||||||
Subsequent Event | Sale Agreement | |||||||
Accounting Policies [Line Items] | |||||||
Consideration on sale of property | $ 107,500,000 | ||||||
Subsequent Event | Separation and Release Agreement | President, Chief Executive Officer and Director | |||||||
Accounting Policies [Line Items] | |||||||
Termination Date | Mar. 31, 2018 | ||||||
Subsequent Event | Separation and Release Agreement | President, Chief Executive Officer and Director | Employee Severance | |||||||
Accounting Policies [Line Items] | |||||||
Severance payment expected to be paid | $ 3,500,000 | ||||||
Subsequent Event | Separation and Release Agreement | President, Chief Executive Officer and Director | Restricted Stock | |||||||
Accounting Policies [Line Items] | |||||||
Shares expected to vest | 2,583,298 |
Summary of Significant Accoun44
Summary of Significant Accounting Policies (Schedule of Allowance for Doubtful Accounts) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Allowance for Doubtful Accounts Receivable [Roll Forward] | |||
Allowance for doubtful accounts, beginning of year | $ 1,953 | $ 0 | $ 0 |
Expense | 0 | 1,953 | 0 |
Reductions/write-offs | 0 | 0 | 0 |
Allowance for doubtful accounts, end of year | $ 1,953 | $ 1,953 | $ 0 |
Property, Plant and Equipment45
Property, Plant and Equipment (Narrative) (Details) | Jan. 23, 2018USD ($) | Oct. 02, 2017USD ($) | Sep. 30, 2017USD ($) | Mar. 22, 2017USD ($)awell | Jan. 20, 2017USD ($) | Dec. 31, 2016USD ($) | Nov. 18, 2016USD ($) | Oct. 19, 2016USD ($)awell | Oct. 14, 2016awellTownshipTranche | Apr. 08, 2016USD ($) | Feb. 19, 2016USD ($) | Dec. 16, 2015USD ($)awell | Dec. 31, 2017USD ($)well | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Jan. 25, 2018USD ($) |
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Proceeds from sale of natural gas and oil properties | $ 28,781,000 | $ 121,273,000 | $ 47,314,000 | |||||||||||||
Fair market value, discounted present rate | 10.00% | |||||||||||||||
Percentage difference of fair value to purchase price | 6.00% | |||||||||||||||
Assets, fair value adjustment | $ 0 | |||||||||||||||
Appalachian Basin | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Consideration on sale of property | $ 200,000,000 | |||||||||||||||
Proceeds from sale of natural gas and oil properties | $ 75,700,000 | $ 80,000,000 | ||||||||||||||
Suspense liability transferred to buyer | $ 3,500,000 | |||||||||||||||
STACK Leasehold Acquisition | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Gross wells | well | 66 | |||||||||||||||
Net wells | well | 9.5 | |||||||||||||||
Net acres | a | 5,670 | |||||||||||||||
Acquisition of oil and natural gas properties | $ 51,400,000 | |||||||||||||||
Husky Acquisition | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Escrow deposit | $ 4,300,000 | |||||||||||||||
Gross wells | well | 103 | |||||||||||||||
Net wells | well | 10.2 | |||||||||||||||
Net acres | a | 11,000 | |||||||||||||||
Acquisition of oil and natural gas properties | $ 42,700,000 | |||||||||||||||
Revenue suspense liability assumed | 358,000 | |||||||||||||||
Fair market valuation amount | 44,600,000 | |||||||||||||||
Sale Agreement | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Proceeds from sale of natural gas and oil properties | $ 98,800,000 | |||||||||||||||
Development Agreement | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Number of wells completed | well | 20 | |||||||||||||||
Number of wells completed, net | well | 15.8 | |||||||||||||||
Development Agreement | Parent Company | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Number of wells completed, net | well | 3.2 | |||||||||||||||
Development Agreement | Investor | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Fair market value, discounted present rate | 15.00% | |||||||||||||||
Revenues and Direct Operating Expenses | Sale Agreement | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Adjustments related to revenues and direct operating expenses | $ 8,700,000 | |||||||||||||||
General and Administrative Expense | Husky Acquisition | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Transaction and integration costs | $ 1,500,000 | |||||||||||||||
Subsequent Event | Sale Agreement | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Consideration on sale of property | $ 107,500,000 | |||||||||||||||
Escrow deposit | $ 10,700,000 | |||||||||||||||
West Virginia | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Consideration on sale of property | $ 200,000 | |||||||||||||||
Oklahoma | Red Bluff | Canadian County Property | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Consideration on sale of property | $ 71,000,000 | |||||||||||||||
Net acres to be sold | a | 25,300 | |||||||||||||||
Net acres allocated | a | 19,100 | |||||||||||||||
Gross wells to be sold | well | 25 | |||||||||||||||
Net wells to be sold | well | 11.2 | |||||||||||||||
Contingent consideration on sale of property | $ 10,000,000 | |||||||||||||||
Purchase price allocated to producing properties | $ 1,400,000 | |||||||||||||||
Consideration on sale of property received | $ 69,500,000 | $ 48,600,000 | ||||||||||||||
Oklahoma | Development Agreement | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Investor funding percentage on working interest portion of drilling and completion cost | 90.00% | |||||||||||||||
Investors percentage of Gastar's working interest in each new well | 80.00% | |||||||||||||||
Percentage of costs paid to obtain 20% working interest | 10.00% | |||||||||||||||
Percentage on working interest in each new well | 20.00% | |||||||||||||||
Number of tranches | Tranche | 3 | |||||||||||||||
Number of wells in each tranche | well | 20 | |||||||||||||||
Number of wells in Meramec formation | well | 18 | |||||||||||||||
Number of wells in Osage formation | well | 2 | |||||||||||||||
Percentage of internal rate of return one | 15.00% | |||||||||||||||
Percentage of working interest on achievement of 15% internal rate of return | 60.00% | |||||||||||||||
Percentage of internal rate of return two | 20.00% | |||||||||||||||
Percentage of working interest on achievement of 20% internal rate of return | 90.00% | |||||||||||||||
Description of working interest on achievement of internal rate of returns | With respect to each 20-well tranche, when the Investor has achieved an aggregate 15% internal rate of return for its investment in the tranche, Investor’s interest will be reduced from 80% to 40% of the Company’s original working interest and the Company’s working interest increases from 20% to 60% of the its original working interest. When a tranche internal rate of return of 20% is achieved by the Investor, Investor’s working interest decreases to 10% and the Company’s working interest increases to 90% of the working interest originally owned by the Company. | |||||||||||||||
Oklahoma | Development Agreement | Investor | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Net acres | a | 21,200 | |||||||||||||||
Number of townships covered | Township | 3 | |||||||||||||||
Gross acres | a | 32,900 | |||||||||||||||
Percentage of working interest on achievement of 15% internal rate of return | 40.00% | |||||||||||||||
Percentage of working interest on achievement of 20% internal rate of return | 10.00% | |||||||||||||||
Oklahoma | Development Agreement | Investor | Maximum | ||||||||||||||||
Property, Plant and Equipment [Line Items] | ||||||||||||||||
Number of operated wells | well | 60 |
Property, Plant And Equipment46
Property, Plant And Equipment (Schedule of Property Plant and Equipment) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment [Line Items] | ||
Unproved properties | $ 131,955 | $ 67,333 |
Proved properties | 1,344,329 | 1,253,061 |
Total oil and natural gas properties | 1,476,284 | 1,320,394 |
Total property and equipment | 1,480,122 | 1,323,016 |
Impairment of proved natural gas and oil properties | (813,314) | (813,314) |
Accumulated depreciation, depletion and amortization | (341,713) | (317,698) |
Total accumulated depreciation, depletion and amortization | (1,155,027) | (1,131,012) |
Total property, plant and equipment, net | 325,095 | 192,004 |
Total oil and natural gas properties | ||
Property, Plant and Equipment [Line Items] | ||
Unproved properties | 131,955 | 67,333 |
Proved properties | 1,344,329 | 1,253,061 |
Total oil and natural gas properties | 1,476,284 | 1,320,394 |
Furniture and equipment | ||
Property, Plant and Equipment [Line Items] | ||
Total property and equipment | $ 3,838 | $ 2,622 |
Property, Plant and Equipment47
Property, Plant and Equipment (Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Unproved properties, excluded from amortization: | ||
Drilling in progress costs | $ 4,772 | $ 1,100 |
Acreage acquisition costs | 113,191 | 58,857 |
Capitalized interest | 13,992 | 7,376 |
Total unproved properties excluded from amortization | $ 131,955 | $ 67,333 |
Property, Plant and Equipment48
Property, Plant and Equipment (Average Sales Price and Production Costs Per Unit of Production) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2017$ / MMBTU$ / bbl | Sep. 30, 2017$ / MMBTU$ / bbl | Jun. 30, 2017$ / MMBTU$ / bbl | Mar. 31, 2017$ / MMBTU$ / bbl | Dec. 31, 2016$ / MMBTU$ / bbl | Sep. 30, 2016$ / MMBTU$ / bbl | Jun. 30, 2016$ / MMBTU$ / bbl | Mar. 31, 2016USD ($)$ / MMBTU$ / bbl | Dec. 31, 2015USD ($)$ / MMBTU$ / bbl | Sep. 30, 2015USD ($)$ / MMBTU$ / bbl | Jun. 30, 2015USD ($)$ / MMBTU$ / bbl | Mar. 31, 2015$ / MMBTU$ / bbl | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | ||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Impairment recorded (pre-tax) (in thousands) | $ | $ 48,497 | $ 144,760 | $ 181,966 | $ 100,152 | $ 0 | $ 48,497 | $ 426,878 | |||||||||
Natural Gas Per Thousand Cubic Feet | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Average price per Mcfe | $ / MMBTU | [1] | 2.98 | 3 | 3.01 | 2.73 | 2.48 | 2.28 | 2.24 | 2.40 | 2.59 | 3.06 | 3.39 | 3.88 | |||
Crude Oil And N G L Per Barrel | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Average price per Mcfe | $ / bbl | [1] | 51.34 | 49.81 | 48.95 | 47.61 | 42.75 | 41.68 | 43.12 | 46.26 | 50.28 | 59.21 | 71.68 | 82.72 | |||
[1] | For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub spot natural gas prices and West Texas Intermediate spot oil prices. |
Property, Plant And Equipment49
Property, Plant And Equipment (Schedule of Pro Forma Information) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Husky Acquisition | ||
Business Acquisition [Line Items] | ||
Revenues | $ 115,147 | |
Net loss | $ (470,874) | |
Loss per share, Basic | $ (6.07) | |
Loss per share, Diluted | $ (6.07) | |
Appalachian Basin | ||
Business Acquisition [Line Items] | ||
Revenues | $ 55,177 | $ 93,783 |
Net loss | $ (98,459) | $ (464,788) |
Loss per share, Basic | $ (0.88) | $ (6) |
Loss per share, Diluted | $ (0.88) | $ (6) |
Property, Plant And Equipment50
Property, Plant And Equipment (Schedule of Assets Acquired) (Details) - Husky Acquisition $ in Thousands | Dec. 16, 2015USD ($) |
Business Acquisition [Line Items] | |
Cash consideration | $ 42,085 |
Total purchase price | 42,085 |
Unproved properties | 27,875 |
Proved properties | 15,592 |
Other | (1,382) |
Total assets acquired | $ 42,085 |
Long-Term Debt - Reconciliation
Long-Term Debt - Reconciliation of Long-Term Debt Balance (Details) - USD ($) | Dec. 31, 2017 | Mar. 03, 2017 | Dec. 31, 2016 | ||
Line of Credit Facility [Line Items] | |||||
Total long-term debt | $ 342,952,000 | $ 404,493,000 | |||
Notes | |||||
Line of Credit Facility [Line Items] | |||||
Principal balance | 162,500,000 | ||||
Unamortized deferred financing costs | (2,631,000) | [1],[2] | $ (5,400,000) | ||
Unamortized debt discount | (46,328,000) | [1],[2] | (52,400,000) | ||
Long term loan, net | 113,541,000 | ||||
Former Senior Secured Notes | |||||
Line of Credit Facility [Line Items] | |||||
Principal balance | 325,000,000 | ||||
Unamortized deferred financing costs | (795,000) | ||||
Unamortized debt discount | (4,342,000) | ||||
Long term loan, net | 319,863,000 | ||||
Term Loan | |||||
Line of Credit Facility [Line Items] | |||||
Principal balance | [3],[4] | 256,599,000 | |||
Unamortized deferred financing costs | (4,724,000) | [2] | (5,500,000) | ||
Unamortized debt discount | (22,464,000) | [2] | $ (25,200,000) | ||
Long term loan, net | $ 229,411,000 | ||||
Revolving Credit Facility | |||||
Line of Credit Facility [Line Items] | |||||
Revolving credit facility | $ 84,630,000 | ||||
[1] | The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Notes based on the effective interest method. | ||||
[2] | The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan and Notes (as defined below), respectively, based on the effective interest method. | ||||
[3] | Pursuant to Amendment No. 2 (as defined below), on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan (as defined below) to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. | ||||
[4] | Pursuant to Amendment No. 2, on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. |
Long-Term Debt - Reconciliati52
Long-Term Debt - Reconciliation of Long-Term Debt Balance (Parenthetical) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Jan. 02, 2018 | Oct. 02, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Line of Credit Facility [Line Items] | ||||||
Kind interest due, amount | $ 6,599 | $ 0 | $ 0 | |||
Term Loan | ||||||
Line of Credit Facility [Line Items] | ||||||
Principal balance | [1],[2] | $ 256,599 | ||||
Term Loan | Amendment No. 2 | ||||||
Line of Credit Facility [Line Items] | ||||||
Percentage of interest pay in kind | 100.00% | |||||
Kind interest due, amount | $ 6,600 | |||||
Principal balance | $ 256,600 | |||||
Term Loan | Amendment No. 2 | Subsequent Event | ||||||
Line of Credit Facility [Line Items] | ||||||
Percentage of interest pay in kind | 100.00% | |||||
Kind interest due, amount | $ 6,600 | |||||
[1] | Pursuant to Amendment No. 2 (as defined below), on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan (as defined below) to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. | |||||
[2] | Pursuant to Amendment No. 2, on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. |
Long-Term Debt (Narrative) (Det
Long-Term Debt (Narrative) (Details) - USD ($) | Aug. 02, 2017 | May 05, 2017 | May 02, 2017 | Mar. 03, 2017 | Oct. 02, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Jun. 30, 2017 | May 04, 2017 | Apr. 30, 2017 | Mar. 21, 2017 | Feb. 15, 2017 | Jan. 10, 2017 | ||
Line of Credit Facility [Line Items] | ||||||||||||||||
Proceeds from issuance of common stock, net of issuance costs | $ 56,366,000 | $ 69,224,000 | $ 0 | |||||||||||||
Common stock volume weighted average trading price per share | $ 1.7002 | |||||||||||||||
Revolving Credit Facility | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Repayment of debt | $ 69,200,000 | |||||||||||||||
Common Stock | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Issuance of common shares - cash, net of offering costs (shares) | 29,408,305 | 50,000,000 | ||||||||||||||
Convertible Notes due 2022 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Aggregate principal amount | $ 162,500,000 | |||||||||||||||
Term loan amount | $ 113,541,000 | |||||||||||||||
Interest rate | 6.00% | |||||||||||||||
Debt instrument maturity date | Mar. 1, 2022 | |||||||||||||||
Debt instrument fair value | $ 147,800,000 | |||||||||||||||
Debt discount | 52,400,000 | $ 46,328,000 | [1],[2] | |||||||||||||
Debt issuance costs | 5,400,000 | $ 2,631,000 | [1],[2] | |||||||||||||
Debt instrument, default, description | The Indenture provides that a number of events will constitute an Event of Default (as defined in the Indenture), including, among other things: (i) a failure to pay the Notes when due at maturity, upon redemption or repurchase; (ii) failure to pay interest for 30 days; (iii) the Company’s failure to deliver certain notices; (iv) a default in the Company’s obligation to convert the Notes; (v) the Company’s failure to comply with certain covenants relating to merger, consolidation or sale of assets; (vi) the Company’s failure to comply, for 60 days following notice, with any of the other covenants or agreements in the Indenture; (vii) a default, which is not cured within 30 days, by the Company or any Restricted Subsidiaries (as defined in the Indenture) with respect to any mortgages or any indebtedness for money borrowed of at least $15 million; (viii) one or more final judgments against the Company or any of its Restricted Subsidiaries for the payment of at least $15 million; (ix) the Company’s failure to make any payments required under that certain development agreement, which is not cured within 30 days; (x) causing any Guarantee (as defined in the Indenture) to cease to be in full force and effect; (xi) the cessation to be in full force and effect of any of the collateral agreements entered into with respect to the Notes; and (xii) certain events of bankruptcy or insolvency. | |||||||||||||||
Debt instrument, debt default, amount | $ 15,000,000 | |||||||||||||||
Aggregate principal amount of the then outstanding notes, percentage | 25.00% | |||||||||||||||
Value of conversion option | $ 77,600,000 | $ 77,626,000 | ||||||||||||||
Debt issuance costs related to liability component notes | 3,200,000 | |||||||||||||||
Debt issuance costs related to equity component notes | $ 2,200,000 | $ 2,164,000 | ||||||||||||||
Amortization of debt issuance costs percentage | 16.00% | |||||||||||||||
Senior Secured Notes Due 2018 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Aggregate principal amount | $ 325,000,000 | |||||||||||||||
Term loan amount | $ 319,863,000 | |||||||||||||||
Interest rate | 8.625% | |||||||||||||||
Debt instrument redemption price percentage | 102.156% | |||||||||||||||
Redemption date | Mar. 24, 2017 | |||||||||||||||
Debt instrument maturity date | May 15, 2018 | |||||||||||||||
Debt discount | $ 4,342,000 | |||||||||||||||
Debt issuance costs | $ 795,000 | |||||||||||||||
Debt instrument interest rate description | The Notes bore interest at a rate of 8.625% per year, payable semi-annually in arrears on May 15 and November 15 of each year. | |||||||||||||||
Additional amount paid on redemption over principle | $ 7,000,000 | |||||||||||||||
Wrote-off of remaining unamortized deferred financing costs | $ 5,200,000 | |||||||||||||||
Second Amended and Restated Revolving Credit Facility | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Revolving credit facility scheduled maturity date | Nov. 14, 2017 | |||||||||||||||
Amendment No. 10 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Preferred dividends payment, minimum required cash liquidity | $ 30,000,000 | |||||||||||||||
Agreed additional indebtedness to pay down | $ 8,100,000 | |||||||||||||||
First Lien Secured Term Loan | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Aggregate principal amount | [3],[4] | $ 256,599,000 | ||||||||||||||
Term loan amount | $ 229,411,000 | |||||||||||||||
Interest rate | 8.50% | |||||||||||||||
Frequency of interest payment | quarterly | |||||||||||||||
Debt instrument maturity date | Mar. 3, 2022 | Mar. 3, 2022 | ||||||||||||||
Debt instrument fair value | $ 224,800,000 | |||||||||||||||
Debt discount | 25,200,000 | $ 22,464,000 | [2] | |||||||||||||
Debt issuance costs | $ 5,500,000 | $ 4,724,000 | [2] | |||||||||||||
Debt instrument effective interest rate percentage | 13.00% | |||||||||||||||
First Lien Secured Term Loan | Amendment No. 2 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Aggregate principal amount | $ 256,600,000 | |||||||||||||||
Interest rate | 10.25% | 8.50% | ||||||||||||||
Debt instrument, payment terms | Amendment No. 2 amended the Term Loan, to among other things, (i) allow for the payment of pay in kind (“PIK”) interest on the Term Loan at the applicable PIK percentage and (ii) increased the applicable rate for periods ending after June 30, 2017 from 8.5% per annum to 10.25% per annum. Amendment No. 2 allows the Company to elect to PIK upon proper notice 100% of interest payments due after June 30, 2017 and prior to December 31, 2018 and at the Company’s election, PIK between 0% and 50% of any interest payments occurring after December 31, 2018 (other than interest due on the maturity date or the date of any repayment or prepayment). | |||||||||||||||
Percentage of interest pay in kind | 100.00% | |||||||||||||||
First Lien Secured Term Loan | Amendment No. 2 | June 30, 2017 to December 31, 2018 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Percentage of interest pay in kind | 100.00% | |||||||||||||||
First Lien Secured Term Loan | Amendment No. 2 | Minimum | After December 31, 2018 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Percentage of interest pay in kind | 0.00% | |||||||||||||||
First Lien Secured Term Loan | Amendment No. 2 | Maximum | After December 31, 2018 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Percentage of interest pay in kind | 50.00% | |||||||||||||||
Securities Purchase Agreement | Common Stock | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Issuance of common shares - cash, net of offering costs (shares) | 25,456,521 | |||||||||||||||
Ares Management, LLC | Senior Secured Notes Due 2018 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Aggregate principal amount | $ 325,000,000 | |||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Aggregate principal amount | $ 75,000,000 | |||||||||||||||
Interest rate | 8.625% | |||||||||||||||
Debt instrument redemption price percentage | 102.156% | |||||||||||||||
Redemption date | Mar. 24, 2017 | |||||||||||||||
Aggregate principal amount, exchanged | $ 37,500,000 | |||||||||||||||
Preferred stock, par value | $ 0.01 | |||||||||||||||
Repurchase share, issued | $ 1.4731 | |||||||||||||||
Aggregate principle amount of issued and outstanding notes | $ 162,500,000 | $ 200,000,000 | ||||||||||||||
Common stock volume weighted average trading price per share | $ 1.7002 | |||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | Common Stock | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Issuance of common shares - cash, net of offering costs (shares) | 25,456,521 | 29,408,305 | ||||||||||||||
Proceeds from issuance of common stock, net of issuance costs | $ 50,000,000 | |||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | Special Voting Preferred Stock | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Issuance of common shares - cash, net of offering costs (shares) | 2,000 | |||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | Convertible Notes due 2022 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Aggregate principal amount | 125,000,000 | |||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | Senior Secured Notes Due 2018 | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Repayment of debt | 325,000,000 | |||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | First Lien Secured Term Loan | ||||||||||||||||
Line of Credit Facility [Line Items] | ||||||||||||||||
Term loan amount | $ 250,000,000 | |||||||||||||||
[1] | The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Notes based on the effective interest method. | |||||||||||||||
[2] | The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan and Notes (as defined below), respectively, based on the effective interest method. | |||||||||||||||
[3] | Pursuant to Amendment No. 2 (as defined below), on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan (as defined below) to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. | |||||||||||||||
[4] | Pursuant to Amendment No. 2, on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. |
Long-Term Debt - Summary of Car
Long-Term Debt - Summary of Carrying Amount of Term Loan (Details) - Term Loan - USD ($) $ in Thousands | Dec. 31, 2017 | Mar. 03, 2017 | ||
Line of Credit Facility [Line Items] | ||||
Principal balance | [1],[2] | $ 256,599 | ||
Unamortized deferred financing costs | (4,724) | [3] | $ (5,500) | |
Unamortized debt discount | (22,464) | [3] | $ (25,200) | |
Long term loan, net | $ 229,411 | |||
[1] | Pursuant to Amendment No. 2 (as defined below), on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan (as defined below) to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. | |||
[2] | Pursuant to Amendment No. 2, on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. | |||
[3] | The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan and Notes (as defined below), respectively, based on the effective interest method. |
Long-Term Debt - Summary of C55
Long-Term Debt - Summary of Carrying Amount of Term Loan (Parenthetical) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||
Jan. 02, 2018 | Oct. 02, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Line of Credit Facility [Line Items] | ||||||
Kind interest due, amount | $ 6,599 | $ 0 | $ 0 | |||
Term Loan | ||||||
Line of Credit Facility [Line Items] | ||||||
Principal balance | [1],[2] | $ 256,599 | ||||
Term Loan | Amendment No. 2 | ||||||
Line of Credit Facility [Line Items] | ||||||
Percentage of interest pay in kind | 100.00% | |||||
Kind interest due, amount | $ 6,600 | |||||
Principal balance | $ 256,600 | |||||
Term Loan | Amendment No. 2 | Subsequent Event | ||||||
Line of Credit Facility [Line Items] | ||||||
Percentage of interest pay in kind | 100.00% | |||||
Kind interest due, amount | $ 6,600 | |||||
[1] | Pursuant to Amendment No. 2 (as defined below), on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan (as defined below) to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. | |||||
[2] | Pursuant to Amendment No. 2, on October 2, 2017, the Company elected to pay in kind 100% of the interest due for the period June 30, 2017 to October 1, 2017 in the amount of $6.6 million, thus increasing the outstanding principal balance of the Term Loan to $256.6 million at such time. The Company elected to pay in kind 100% of the interest for the period October 2, 2017 to January 1, 2018 in the amount of $6.6 million and such was accrued at December 31, 2017 due to the interest payment date falling on a weekend outside of year end. |
Long-Term Debt - Summary of C56
Long-Term Debt - Summary of Carrying Amount of Liability Component of Notes (Details) - Notes - USD ($) $ in Thousands | Dec. 31, 2017 | Mar. 03, 2017 | |
Line of Credit Facility [Line Items] | |||
Principal balance | $ 162,500 | ||
Unamortized deferred financing costs | (2,631) | [1],[2] | $ (5,400) |
Unamortized debt discount | (46,328) | [1],[2] | $ (52,400) |
Long term loan, net | $ 113,541 | ||
[1] | The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Notes based on the effective interest method. | ||
[2] | The unamortized deferred financing costs and debt discount will be amortized over the remaining life of the Term Loan and Notes (as defined below), respectively, based on the effective interest method. |
Long-Term Debt - Summary of C57
Long-Term Debt - Summary of Carrying Amount of Equity Components of Notes Recorded in Additional Paid in Capital (Details) - Notes - USD ($) $ in Thousands | Dec. 31, 2017 | Mar. 03, 2017 |
Line of Credit Facility [Line Items] | ||
Value of conversion option | $ 77,626 | $ 77,600 |
Debt issuance costs attributable to conversion option | (2,164) | $ (2,200) |
Fair value of conversion option, net | $ 75,462 |
Asset Retirement Obligation (De
Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |||
Asset retirement obligation, beginning of year | $ 5,532 | $ 6,086 | |
Liabilities incurred during period | 383 | 196 | |
Liabilities settled during period | (90) | ||
Accretion expense | 237 | 368 | $ 502 |
Revision in previous estimates and other | 222 | 17 | |
Deletions related to property disposals | (1,533) | (1,045) | |
Asset retirement obligation, end of year | $ 4,841 | $ 5,532 | $ 6,086 |
Fair Value Measurements (Fair V
Fair Value Measurements (Fair Value Measurements, Recurring and Nonrecurring) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Assets: | ||
Assets, Commodity derivative contracts | $ 1,370 | $ 7,850 |
Liabilities: | ||
Liabilities, Commodity derivative contracts | (6,988) | (338) |
Total | (5,618) | 7,512 |
Level 3 | ||
Assets: | ||
Assets, Commodity derivative contracts | 1,370 | 7,850 |
Liabilities: | ||
Liabilities, Commodity derivative contracts | (6,988) | (338) |
Total | $ (5,618) | $ 7,512 |
Fair Value Measurements (Net Ch
Fair Value Measurements (Net Change in Assets and Liabilities Measured at Fair Value on a Recurring Basis and Included in the Level 3 Fair Value Category) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
The amount of total losses for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2017 and 2016 | $ (11,900) | $ (13,600) | $ (1,900) | |
Fair Value, Measurements, Recurring | ||||
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | ||||
Balance at beginning of period | 7,512 | 24,418 | ||
Total losses, net included in earnings | (4,457) | (2,863) | ||
Purchases | 1,888 | 565 | ||
Issuances | (165) | |||
Settlements | [1] | (10,561) | (14,443) | |
Balance at end of period | (5,618) | 7,512 | $ 24,418 | |
The amount of total losses for the period included in earnings attributable to the change in the mark to market of commodity derivatives contracts still held at December 31, 2017 and 2016 | $ (11,875) | $ (13,622) | ||
[1] | Included in (loss) gain on commodity derivatives contracts on the consolidated statement of operations. |
Fair Value Measurements (Narrat
Fair Value Measurements (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Fair value of notes excluding conversion feature | $ 108.2 | |
Fair value of term loan | $ 234.9 | |
Level 1 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Fair value of long-term debt | $ 403.1 |
Derivative Instruments and He62
Derivative Instruments and Hedging Activity (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |||
(Loss) gain on commodity derivatives contracts | $ (4,457) | $ (2,863) | $ 24,589 |
Losses related to change in fair value of commodity derivative contracts | $ (11,900) | $ (13,600) | $ (1,900) |
Derivative Instruments and He63
Derivative Instruments and Hedging Activity (Schedule of Notional Amounts and Weighted Average Underlying Hedge Prices of Outstanding Derivative Positions) (Details) | 12 Months Ended | |
Dec. 31, 2017MMBTU$ / MMBTU$ / bblbbl | ||
Costless Three-Way Collar - February to December 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | MMBTU | 5,000 | |
Total of Notional Volume (MMBtu) | MMBTU | 1,670,000 | |
Costless Three-Way Collar - February to December 2018 | Long | Natural Gas | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3 | |
Costless Three-Way Collar - February to December 2018 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Put (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 2.35 | |
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4 | |
Costless Collar - February to March 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | MMBTU | 5,800 | |
Total of Notional Volume (MMBtu) | MMBTU | 342,200 | |
Costless Collar - February to March 2018 | Long | Natural Gas | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / MMBTU | 3 | |
Costless Collar - February to March 2018 | Short | Natural Gas | ||
Derivative [Line Items] | ||
Ceiling (Short) (Price per MMBtu or Bbl) | $ / MMBTU | 4.28 | |
Fixed Price Swap - April to December 2018 | Natural Gas | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | MMBTU | 1,550 | |
Total of Notional Volume (MMBtu) | MMBTU | 426,250 | |
Base Fixed Price (Price per MMBtu or Bbl) | $ / MMBTU | 3.01 | |
Crude Oil | Costless Three-Way Collar - January to December 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 500 | [1] |
Total of Notional Volume (Bbl) | bbl | 182,500 | |
Crude Oil | Costless Three-Way Collar - January to December 2018 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl | 50 | |
Crude Oil | Costless Three-Way Collar - January to December 2018 | Short | ||
Derivative [Line Items] | ||
Put (Short) (Price per MMBtu or Bbl) | $ / bbl | 40 | |
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl | 61.60 | |
Crude Oil | Costless Three-Way Collar - January to March 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 1,800 | [1] |
Total of Notional Volume (Bbl) | bbl | 162,000 | |
Crude Oil | Costless Three-Way Collar - January to March 2018 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl | 47.50 | |
Crude Oil | Costless Three-Way Collar - January to March 2018 | Short | ||
Derivative [Line Items] | ||
Put (Short) (Price per MMBtu or Bbl) | $ / bbl | 37.50 | |
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl | 57.85 | |
Crude Oil | Costless Three-Way Collar - April to June 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 1,700 | [1] |
Total of Notional Volume (Bbl) | bbl | 154,700 | |
Crude Oil | Costless Three-Way Collar - April to June 2018 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl | 47.50 | |
Crude Oil | Costless Three-Way Collar - April to June 2018 | Short | ||
Derivative [Line Items] | ||
Put (Short) (Price per MMBtu or Bbl) | $ / bbl | 37.50 | |
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl | 57.85 | |
Crude Oil | Costless Three-Way Collar - July to September 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 1,600 | [1] |
Total of Notional Volume (Bbl) | bbl | 147,200 | |
Crude Oil | Costless Three-Way Collar - July to September 2018 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl | 47.50 | |
Crude Oil | Costless Three-Way Collar - July to September 2018 | Short | ||
Derivative [Line Items] | ||
Put (Short) (Price per MMBtu or Bbl) | $ / bbl | 37.50 | |
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl | 57.85 | |
Crude Oil | Costless Three-Way Collar - October to December 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 1,700 | [1] |
Total of Notional Volume (Bbl) | bbl | 156,400 | |
Crude Oil | Costless Three-Way Collar - October to December 2018 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl | 47.50 | |
Crude Oil | Costless Three-Way Collar - October to December 2018 | Short | ||
Derivative [Line Items] | ||
Put (Short) (Price per MMBtu or Bbl) | $ / bbl | 37.50 | |
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl | 57.85 | |
Crude Oil | Fixed Price Swap One - January to June 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 200 | [1] |
Total of Notional Volume (Bbl) | bbl | 36,200 | |
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl | 50.11 | |
Crude Oil | Fixed Price Swap Two - January to June 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 600 | [1] |
Total of Notional Volume (Bbl) | bbl | 108,600 | |
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl | 51.20 | |
Crude Oil | Fixed Price Swap - January to August 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 425 | [1] |
Total of Notional Volume (Bbl) | bbl | 103,275 | |
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl | 66.45 | |
Crude Oil | Fixed Price Swap - July to September 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 500 | [1] |
Total of Notional Volume (Bbl) | bbl | 46,000 | |
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl | 51.20 | |
Crude Oil | Fixed Price Swap - October to December 2018 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 600 | [1] |
Total of Notional Volume (Bbl) | bbl | 55,200 | |
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl | 51.20 | |
Crude Oil | Costless Three-Way Collar - January to September 2019 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 2,000 | [1] |
Total of Notional Volume (Bbl) | bbl | 546,000 | |
Crude Oil | Costless Three-Way Collar - January to September 2019 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl | 47.50 | |
Crude Oil | Costless Three-Way Collar - January to September 2019 | Short | ||
Derivative [Line Items] | ||
Put (Short) (Price per MMBtu or Bbl) | $ / bbl | 37.50 | |
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl | 59.70 | |
Crude Oil | Costless Three-Way Collar - October to December 2019 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 1,900 | [1] |
Total of Notional Volume (Bbl) | bbl | 174,800 | |
Crude Oil | Costless Three-Way Collar - October to December 2019 | Long | ||
Derivative [Line Items] | ||
Floor (Long) (Price per MMBtu or Bbl) | $ / bbl | 47.50 | |
Crude Oil | Costless Three-Way Collar - October to December 2019 | Short | ||
Derivative [Line Items] | ||
Put (Short) (Price per MMBtu or Bbl) | $ / bbl | 37.50 | |
Ceiling (Short) (Price per MMBtu or Bbl) | $ / bbl | 59.70 | |
Crude Oil | Fixed Price Swap - January to September 2019 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 700 | [1] |
Total of Notional Volume (Bbl) | bbl | 191,100 | |
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl | 50.40 | |
Crude Oil | Fixed Price Swap - October to December 2019 | ||
Derivative [Line Items] | ||
Average Daily Volume (MMBtu or Bbl) | bbl | 600 | [1] |
Total of Notional Volume (Bbl) | bbl | 55,200 | |
Base Fixed Price (Price per MMBtu or Bbl) | $ / bbl | 50.40 | |
[1] | Crude volumes hedged include oil, condensate and certain components of the Company’s NGLs production. |
Derivative Instruments and He64
Derivative Instruments and Hedging Activity (Summary of Information Regarding Deferred Put Premium Liabilities) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | ||||
Current commodity derivative premium put payable | $ 135 | $ 1,654 | ||
Long-term commodity derivative premium payable | 0 | 969 | ||
Total unamortized put premium liabilities | $ 135 | $ 2,623 | $ 135 | $ 2,623 |
Put Premium Liabilities [Roll Forward] | ||||
Put premium liabilities, beginning balance | 2,623 | 5,982 | ||
Settlement of put premium liabilities | (2,958) | (3,194) | ||
Additional put premium liabilities | 470 | (165) | ||
Put premium liabilities, ending balance | $ 135 | $ 2,623 |
Derivative Instruments and He65
Derivative Instruments and Hedging Activity (Summary of Information on the Location and Amounts of Commodity Derivative Fair Values and Commodity Derivative Gains and Losses) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivatives, Fair Value [Line Items] | |||
(Loss) gain on commodity derivatives contracts | $ (4,457) | $ (2,863) | $ 24,589 |
Commodity Contract | |||
Derivatives, Fair Value [Line Items] | |||
(Loss) gain on commodity derivatives contracts | (4,457) | (2,863) | 24,589 |
Commodity Contract | (Loss) gain on commodity derivatives contracts | |||
Derivatives, Fair Value [Line Items] | |||
(Loss) gain on commodity derivatives contracts | (4,457) | (2,863) | $ 24,589 |
Commodity Contract | Derivatives not designated as hedging instruments | |||
Derivatives, Fair Value [Line Items] | |||
Total derivatives not designated as hedging instruments | (5,618) | 7,512 | |
Commodity Contract | Derivatives not designated as hedging instruments | Current assets | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Assets | 1,370 | 6,212 | |
Commodity Contract | Derivatives not designated as hedging instruments | Other assets | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Assets | 0 | 1,638 | |
Commodity Contract | Derivatives not designated as hedging instruments | Current liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Liabilities | (4,416) | (338) | |
Commodity Contract | Derivatives not designated as hedging instruments | Long-term liabilities | |||
Derivatives, Fair Value [Line Items] | |||
Commodity derivative contracts, Liabilities | $ (2,572) | $ 0 |
Capital Stock (Narrative) (Deta
Capital Stock (Narrative) (Details) | May 01, 2018USD ($) | May 05, 2017USD ($)shares | May 02, 2017USD ($)$ / sharesshares | Mar. 03, 2017USD ($)$ / sharesshares | Feb. 15, 2017$ / shares | Jan. 31, 2017USD ($) | Jan. 27, 2017Right$ / shares | May 12, 2016USD ($)$ / sharesshares | Mar. 09, 2016 | Jan. 18, 2016Right$ / shares | Apr. 30, 2016USD ($) | Feb. 20, 2017USD ($)shares | Dec. 31, 2017USD ($)$ / sharesshares | Sep. 30, 2017USD ($) | Dec. 31, 2016USD ($)$ / sharesshares | Sep. 30, 2016USD ($) | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($)$ / sharesshares | Dec. 31, 2016USD ($)$ / sharesshares | Dec. 31, 2015USD ($)shares | Jul. 24, 2017shares | Mar. 22, 2017$ / sharesshares | Mar. 21, 2017USD ($) | Jul. 05, 2016shares | May 07, 2015USD ($) |
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Aggregate offering price | $ 50,000,000 | ||||||||||||||||||||||||
Proceeds from issuance of common stock, net of issuance costs | $ 56,366,000 | $ 69,224,000 | $ 0 | ||||||||||||||||||||||
Common stock, shares authorized | shares | 800,000,000 | 550,000,000 | 800,000,000 | 550,000,000 | 275,000,000 | 800,000,000 | 550,000,000 | ||||||||||||||||||
Volume-weighted average trading price of the common shares | $ / shares | $ 1.7002 | ||||||||||||||||||||||||
Preferred stock, shares authorized | shares | 40,000,000 | 40,000,000 | 40,000,000 | 40,000,000 | |||||||||||||||||||||
Cash dividends on preferred stock | $ 19,298,000 | $ 3,618,000 | $ 14,473,000 | ||||||||||||||||||||||
Undeclared cumulative dividends on preferred stock | $ 3,618,000 | $ 2,412,000 | $ 3,618,000 | $ 3,618,000 | $ 3,619,000 | $ 6,030,000 | $ 10,855,000 | 0 | |||||||||||||||||
Preferred stock dividends payment conditions applied commencement period | 2016-04 | ||||||||||||||||||||||||
Preferred stock, if a full catch up dividend is not declared and paid, description | If a full catch up dividend is not declared and paid in cash in April 2018 for the Series A and Series B Preferred Stock to pay all of the accumulated, accrued and unpaid dividends (including April 2018) a fourth unpaid Quarterly Dividend Default will be deemed to occur and, as a result, starting May 1, 2018: (i) the fixed dividend rate of Series A and B Preferred Stock each increases by 2.00% per annum; (ii) if such dividends are not paid in cash, the Company will be required to issue a dividend of common stock to pay all accrued and unpaid dividends based on then current market value determined in accordance with the applicable certificate of designations for each of the Series A and B Preferred Stock provided the Company has sufficient legal surplus to pay such a stock dividend and can otherwise pay the dividend under state law; (iii) the holders of Series A Preferred Stock and Series B Preferred Stock, voting as a single class, will have the right to elect up to two additional directors to the board of directors of the Company; and (iv) the foregoing rights would continue until the Company has paid a least two full calendar quarters of monthly cash dividends on the respective series. | ||||||||||||||||||||||||
Stock options | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Common shares reserved for future issuance | shares | 164,400 | 164,400 | |||||||||||||||||||||||
PBUs | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Common shares reserved for future issuance | shares | 2,226,906 | 2,226,906 | |||||||||||||||||||||||
Series A Preferred Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Preferred stock, shares authorized | shares | 10,000,000 | 10,000,000 | 10,000,000 | 10,000,000 | |||||||||||||||||||||
Preferred stock, dividend rate, percentage (percentage) | 8.625% | ||||||||||||||||||||||||
Preferred stock, par value | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | |||||||||||||||||||||
Redemption price | $ / shares | $ 25 | $ 25 | $ 25 | $ 25 | |||||||||||||||||||||
Preferred stock, shares issued | shares | 4,045,000 | 4,045,000 | 4,045,000 | 4,045,000 | |||||||||||||||||||||
Preferred stock, shares outstanding | shares | 4,045,000 | 4,045,000 | 4,045,000 | 4,045,000 | |||||||||||||||||||||
Cash dividends on preferred stock | $ 11,600,000 | $ 2,200,000 | 8,700,000 | ||||||||||||||||||||||
Fixed rate preferred dividend increases percentage if suspension more than one year | 2.00% | ||||||||||||||||||||||||
Undeclared dividends paid | $ 6,500,000 | ||||||||||||||||||||||||
Undeclared cumulative dividends on preferred stock | 3,600,000 | $ 6,500,000 | |||||||||||||||||||||||
Accumulated and unpaid dividends on preferred stock transferred to liquidation preference | $ 3,600,000 | $ 3,600,000 | |||||||||||||||||||||||
Accumulated and unpaid dividends on preferred stock transferred to liquidation preference per share | $ / shares | $ 0.89844 | $ 0.89844 | |||||||||||||||||||||||
Preferred stock, dividend rate, percentage (percentage) | 8.625% | ||||||||||||||||||||||||
Series A Preferred Stock | Scenario Forecast | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Dividend declared or paid | $ 0 | ||||||||||||||||||||||||
Preferred stock, increase in fixed dividend rate if catch up dividend not declared and paid, percentage | 2.00% | ||||||||||||||||||||||||
Series B Preferred Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Preferred stock, shares authorized | shares | 10,000,000 | 10,000,000 | 10,000,000 | 10,000,000 | |||||||||||||||||||||
Preferred stock, dividend rate, percentage (percentage) | 10.75% | ||||||||||||||||||||||||
Preferred stock, par value | $ / shares | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | |||||||||||||||||||||
Redemption price | $ / shares | $ 25 | $ 25 | $ 25 | $ 25 | |||||||||||||||||||||
Preferred stock, shares issued | shares | 2,140,000 | 2,140,000 | 2,140,000 | 2,140,000 | |||||||||||||||||||||
Preferred stock, shares outstanding | shares | 2,140,000 | 2,140,000 | 2,140,000 | 2,140,000 | |||||||||||||||||||||
Cash dividends on preferred stock | $ 4,800,000 | $ 7,700,000 | $ 1,400,000 | $ 5,800,000 | |||||||||||||||||||||
Fixed rate preferred dividend increases percentage if suspension more than one year | 2.00% | ||||||||||||||||||||||||
Undeclared dividends paid | $ 4,300,000 | ||||||||||||||||||||||||
Undeclared cumulative dividends on preferred stock | 2,400,000 | $ 4,400,000 | |||||||||||||||||||||||
Accumulated and unpaid dividends on preferred stock transferred to liquidation preference | $ 2,400,000 | $ 2,400,000 | |||||||||||||||||||||||
Accumulated and unpaid dividends on preferred stock transferred to liquidation preference per share | $ / shares | $ 1.11979 | $ 1.11979 | |||||||||||||||||||||||
Preferred stock redemption price per share | $ / shares | 25 | $ 25 | |||||||||||||||||||||||
Period after change in control to redeem preferred stock | 90 days | ||||||||||||||||||||||||
Option to convert shares of Series B Preferred Stock | $ / shares | $ 11.5207 | $ 11.5207 | |||||||||||||||||||||||
Preferred stock, dividend rate, percentage (percentage) | 10.75% | ||||||||||||||||||||||||
Dividend declared or paid | $ 0 | ||||||||||||||||||||||||
Series B Preferred Stock | Scenario Forecast | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Dividend declared or paid | $ 0 | ||||||||||||||||||||||||
Preferred stock, increase in fixed dividend rate if catch up dividend not declared and paid, percentage | 2.00% | ||||||||||||||||||||||||
Special Voting Preferred Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Preferred stock, shares authorized | shares | 2,000 | ||||||||||||||||||||||||
Redemption price | $ / shares | $ 0.01 | ||||||||||||||||||||||||
Convertible Notes due 2022 | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Aggregate principal amount | $ 162,500,000 | $ 162,500,000 | |||||||||||||||||||||||
Amendment No. 10 | Series A Preferred Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Dividends payable record date | Jan. 20, 2017 | ||||||||||||||||||||||||
Dividends payable, date declared | Jan. 10, 2017 | ||||||||||||||||||||||||
Dividends payable, date paid | Jan. 31, 2017 | ||||||||||||||||||||||||
Cash dividends on preferred stock | $ 7,300,000 | ||||||||||||||||||||||||
Amendment No. 10 | Series B Preferred Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Dividends payable record date | Jan. 20, 2017 | ||||||||||||||||||||||||
Dividends payable, date declared | Jan. 10, 2017 | ||||||||||||||||||||||||
Dividends payable, date paid | Jan. 31, 2017 | ||||||||||||||||||||||||
Common Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Issuance of common shares - cash, net of offering costs (shares) | shares | 29,408,305 | 50,000,000 | |||||||||||||||||||||||
Securities Purchase Agreement | Additional Notes | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Aggregate principal amount | $ 75,000,000 | ||||||||||||||||||||||||
Aggregate principal amount, exchanged | $ 37,500,000 | ||||||||||||||||||||||||
Securities Purchase Agreement | Common Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Issuance of common shares - cash, net of offering costs (shares) | shares | 25,456,521 | ||||||||||||||||||||||||
2016 Rights Agreement | Series C Preferred Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Number of rights issued on dividend declared | Right | 1 | ||||||||||||||||||||||||
Dividend payment terms | The dividend was paid to stockholders of record on January 28, 2016. Each 2016 Right entitled the holder, subject to the terms of the 2016 Rights Agreement, to purchase one one-thousandth of a share of the Company’s Series C Junior Participating Preferred Stock (the “Series C Preferred Stock”) at a price of $6.96, subject to certain adjustments. | ||||||||||||||||||||||||
Preferred stock, dividend rate, per share | $ / shares | $ 6.96 | ||||||||||||||||||||||||
Dividends payable record date | Jan. 28, 2016 | ||||||||||||||||||||||||
Expiration date of rights | Jan. 18, 2017 | ||||||||||||||||||||||||
2017 Rights Agreement | Series C Preferred Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Number of rights issued on dividend declared | Right | 1 | ||||||||||||||||||||||||
Dividend payment terms | The dividend was paid to stockholders of record on February 10, 2017. Each Right entitled the holder, subject to the terms of the 2017 Rights Agreement, to purchase one one-thousandth of a share of Series C Preferred Stock at a price of $10.74, subject to certain adjustments. | ||||||||||||||||||||||||
Preferred stock, dividend rate, per share | $ / shares | $ 10.74 | ||||||||||||||||||||||||
Dividends payable record date | Feb. 10, 2017 | ||||||||||||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Aggregate principal amount | $ 75,000,000 | ||||||||||||||||||||||||
Number of consecutive trading days used in volume-weighted average trading price | 30 days | ||||||||||||||||||||||||
Volume-weighted average trading price of the common shares | $ / shares | $ 1.7002 | ||||||||||||||||||||||||
Aggregate principal amount, exchanged | $ 37,500,000 | ||||||||||||||||||||||||
Preferred stock, par value | $ / shares | $ 0.01 | ||||||||||||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | Convertible Notes due 2022 | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Aggregate principal amount | $ 125,000,000 | ||||||||||||||||||||||||
Ares Management, LLC | Securities Purchase Agreement | Common Stock | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Issuance of common shares - cash, net of offering costs (shares) | shares | 25,456,521 | 29,408,305 | |||||||||||||||||||||||
Proceeds from issuance of common stock, net of issuance costs | $ 50,000,000 | ||||||||||||||||||||||||
Sales price of underwritten public offering before offering costs and expenses | $ 50,000,000 | ||||||||||||||||||||||||
Gastar Exploration USA | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Proceeds from issuance of common stock, net of issuance costs | $ 44,800,000 | ||||||||||||||||||||||||
Shares of common stock in underwritten public offering | shares | 50,000,000 | ||||||||||||||||||||||||
Price per share of underwritten public offering | $ / shares | $ 0.95 | ||||||||||||||||||||||||
Sales price of underwritten public offering before offering costs and expenses | $ 47,500,000 | ||||||||||||||||||||||||
Estimated offering costs and expenses | $ 2,700,000 | ||||||||||||||||||||||||
ATM Program | |||||||||||||||||||||||||
Class Of Stock [Line Items] | |||||||||||||||||||||||||
Issuance of common shares - cash, net of offering costs (shares) | shares | 5,447,919 | 18,606,943 | |||||||||||||||||||||||
Proceeds from issuance of common stock, net of issuance costs | $ 8,300,000 | $ 24,400,000 | |||||||||||||||||||||||
Expiration date | Feb. 24, 2017 |
Capital Stock (Schedule of Issu
Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Details) - shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares of common stock issued pursuant to PBUs vested, net of forfeitures of 207,891 shares | 0 | 502,593 | |
Restricted Stock | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares of restricted common stock granted | 8,649,343 | 1,764,645 | |
Shares of restricted common stock vested | 1,270,171 | 1,487,269 | |
Shares of restricted common stock surrendered upon vesting/exercise | [1] | 373,741 | 392,094 |
Shares of restricted common stock forfeited | 91,801 | 128,435 | |
[1] | Represents shares of common stock forfeited in connection with the payment of estimated withholding taxes on shares of restricted common stock that vested during the period. |
Capital Stock (Schedule of Is68
Capital Stock (Schedule of Issuances and Forfeitures of Common Shares) (Parenthetical) (Details) | 12 Months Ended |
Dec. 31, 2016shares | |
PBUs | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Forfeiture of common stock issued pursuant to PBUs vested | 207,891 |
Equity Compensation Plans (Narr
Equity Compensation Plans (Narrative) (Details) - USD ($) | May 02, 2017 | Aug. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Unrecognized expense for outstanding awards | $ 8,000,000 | |||||
Stock-based compensation expense | $ 5,900,000 | $ 3,900,000 | $ 5,000,000 | |||
Unvested restricted shares | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 3 years | |||||
Unrecognized expense for outstanding awards | $ 6,100,000 | |||||
Stock-based compensation expense | $ 4,300,000 | |||||
Weighted average period for recognition for unrecognized expense | 2 years 2 months 23 days | |||||
Unvested restricted shares | Minimum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 1 year | |||||
Unvested restricted shares | Maximum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 3 years | |||||
Unvested restricted shares | Director | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 1 year | |||||
Unvested restricted shares | Executives and employees | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 5 years | |||||
Stock options | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Granted | 0 | 0 | 0 | |||
Unrecognized expense for outstanding awards | $ 0 | |||||
PBUs | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock-based compensation expense | $ 1,600,000 | |||||
Weighted average period for recognition for unrecognized expense | 1 year 11 months 4 days | |||||
Total unrecognized expense for PBUs | $ 1,900,000 | |||||
2006 Long-Term Stock Incentive Plan | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares of common stock reserved for issuance under LTIP | 14,000,000 | |||||
Shares available for future issuance (no more than) (shares) | 6,637,433 | |||||
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Director | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 1 year | |||||
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Employee | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 3 years | |||||
2006 Long-Term Stock Incentive Plan | Unvested restricted shares | Executives and employees | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 5 years | |||||
2006 Long-Term Stock Incentive Plan | PBUs | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 3 years | |||||
Percentage settlement of targeted number of PBUs | 100.00% | |||||
2006 Long-Term Stock Incentive Plan | PBUs | Cliff Vest | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vesting term (years) | 3 years | 3 years | 3 years | |||
2006 Long-Term Stock Incentive Plan | PBUs | Minimum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Percentage settlement of targeted number of PBUs | 0.00% | |||||
2006 Long-Term Stock Incentive Plan | PBUs | Maximum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Percentage settlement of targeted number of PBUs | 200.00% |
Equity Compensation Plans (Shar
Equity Compensation Plans (Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding and Exercisable) (Details) - Stock options - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Outstanding at beginning of period | 214,600 | ||
Granted | 0 | 0 | 0 |
Exercised | 0 | ||
Canceled/Expired | (50,200) | ||
Forfeited | 0 | ||
Outstanding at end of period | 164,400 | 214,600 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Roll Forward] | |||
Weighted-Average Exercise Price, Outstanding at beginning of period | $ 4.87 | ||
Granted | 0 | ||
Exercised | 0 | ||
Canceled/Expired | 10.95 | ||
Forfeited | 0 | ||
Weighted-Average Exercise Price, Outstanding at end of period | $ 3.01 | $ 4.87 | |
Number of shares vested and exercisable | 164,400 | ||
Weighted Average Exercise Price per Share | $ 3.01 | ||
Weighted Average Remaining Contractual Term (in years) | 1 year 5 months 1 day | ||
Aggregate Intrinsic Value | $ 0 |
Equity Compensation Plans (Rest
Equity Compensation Plans (Restricted Stock Activity) (Details) - Unvested restricted shares $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 2017USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Unvested PBUs at December 31, 2016 | shares | 2,445,290 |
Granted | shares | 8,649,343 |
Vested | shares | (1,270,171) |
Forfeited | shares | (91,801) |
Unvested PBUs at December 31, 2017 | shares | 9,732,661 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |
Weighted-Average Grant Date Fair Value, Outstanding at beginning of period | $ / shares | $ 1.79 |
Granted | $ / shares | 1.09 |
Vested | $ / shares | 2.07 |
Forfeited | $ / shares | 1.65 |
Weighted-Average Grant Date Fair Value, Outstanding at end of period | $ / shares | $ 1.13 |
Weighted Average Remaining Contractual Term (in years) | 3 years 4 months 20 days |
Aggregate Intrinsic Value | $ | $ 10,219 |
Equity Compensation Plans (Sche
Equity Compensation Plans (Schedule of Weighted Average Grant Date Fair Value) (Details) - Unvested restricted shares - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Weighted average grant date fair value (in dollars per share) | $ 1.09 | $ 1.19 | $ 2.40 |
Grant date fair value of stock options vested | $ 2,627 | $ 3,530 | $ 3,794 |
Equity Compensation Plans (Summ
Equity Compensation Plans (Summary of PBUs) (Details) - PBUs | 12 Months Ended |
Dec. 31, 2017$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward] | |
Unvested PBUs at December 31, 2016 | shares | 1,475,730 |
Granted | shares | 830,196 |
Vested | shares | (79,020) |
Forfeited | shares | 0 |
Unvested PBUs at December 31, 2017 | shares | 2,226,906 |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward] | |
Unvested PBUs at December 31, 2016 | $ / shares | $ 2.49 |
Granted | $ / shares | 2.38 |
Vested | $ / shares | 7.34 |
Forfeited | $ / shares | 0 |
Unvested PBUs at December 31, 2017 | $ / shares | $ 2.27 |
Equity Compensation Plans (Sc74
Equity Compensation Plans (Schedule of Future Amortization of Unrecognized Compensation Cost) (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
2,018 | $ 4,558 |
2,019 | 2,290 |
2,020 | 725 |
2,021 | 297 |
2,022 | 100 |
Total | $ 7,970 |
Interest Expense (Schedule of C
Interest Expense (Schedule of Components of Interest Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Interest Expense [Abstract] | ||||
Cash and accrued | $ 35,185 | $ 33,368 | $ 30,981 | |
Amortization of deferred financing costs | [1] | 10,977 | 4,980 | 3,584 |
Capitalized interest | (7,207) | (3,102) | (3,879) | |
Total interest expense | $ 38,955 | $ 35,246 | $ 30,686 | |
[1] | The year ended December 31, 2017 includes $2.7 million and $6.1 million of debt discount accretion related to the Term Loan and Notes, respectively. The years ended December 31, 2017, 2016 and 2015 include $495,000, $2.8 million and $2.5 million, respectively, of debt discount accretion related to the Former Notes. |
Interest Expense (Schedule of76
Interest Expense (Schedule of Components of Interest Expense) (Parenthetical) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Notes | |||
Interest Expense [Line Items] | |||
Accretion of debt discount | $ 6,100,000 | ||
Former Senior Secured Notes | |||
Interest Expense [Line Items] | |||
Accretion of debt discount | 495,000 | $ 2,800,000 | $ 2,500,000 |
Term Loan | |||
Interest Expense [Line Items] | |||
Accretion of debt discount | $ 2,700,000 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Operating Loss Carryforwards [Line Items] | ||||
Federal statutory rate | 35.00% | 35.00% | 35.00% | |
Current provision for income taxes | $ 0 | $ 0 | $ 0 | |
Deferred income tax expense (benefit) | $ 0 | $ 0 | $ 0 | |
Tax Cuts and Jobs Act, rate to apply for deferred tax assets and liabilities | 24.60% | |||
Decrease in net operating loss carry forwards | $ 353,000,000 | |||
Decrease in foreign tax credit carry forwards | 0 | |||
Foreign | ||||
Operating Loss Carryforwards [Line Items] | ||||
Tax credit carry forwards | 50,700,000 | |||
US | ||||
Operating Loss Carryforwards [Line Items] | ||||
Net operating loss carry forwards | $ 550,000,000 | |||
Maximum | ||||
Operating Loss Carryforwards [Line Items] | ||||
Federal statutory rate | 38.00% | |||
Scenario Plan | ||||
Operating Loss Carryforwards [Line Items] | ||||
Federal statutory rate | 21.00% |
Income Taxes (Schedule of (Loss
Income Taxes (Schedule of (Loss) Income before Income Taxes) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
United States | $ (46,755) | $ (89,061) | $ (459,507) |
Total income (loss) before income taxes | $ (46,755) | $ (89,061) | $ (459,507) |
Income Taxes (Schedule of Effec
Income Taxes (Schedule of Effective Income Tax Rate Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Income Tax Disclosure [Abstract] | |||
Expected income tax benefit at statutory rate | $ (16,364) | $ (31,172) | $ (160,827) |
State tax, tax effected | (1,085) | (1,408) | (7,799) |
Non-deductible convertible debt discount | 3,092 | 0 | 0 |
Stock-based compensation expense | 523 | 1,995 | 255 |
Non-deductible compensation | 63 | 178 | 0 |
Effect of rate change on net deferred tax asset | 64,515 | 0 | 0 |
Effect of ownership change on estimated realization of net operating loss and tax credit carry forwards | 119,654 | 0 | 0 |
State tax rate change and other | 3,101 | 693 | 17 |
Other changes in valuation allowance | (173,499) | 29,714 | 168,354 |
Actual income tax provision | $ 0 | $ 0 | $ 0 |
Income Taxes (Schedule of Defer
Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred tax asset: | ||
Capital assets | $ 27,137 | $ 33,131 |
Stock-based compensation | 2,390 | 2,499 |
Net operating loss carry forwards | 80,060 | 196,775 |
Foreign tax credit carry forwards | 0 | 50,681 |
Valuation allowance | (109,587) | (283,086) |
Net deferred tax asset | $ 0 | $ 0 |
Earnings per Share (Schedule of
Earnings per Share (Schedule of Earnings per Share, Basic and Diluted, by Common Class, Including Two Class Method) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |||||||||
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||||||||||
Net loss attributable to common stockholders | $ (16,597) | [1] | $ (15,917) | [1] | $ (6,398) | [1] | $ (22,316) | [1] | $ (8,163) | [2] | $ (3,796) | [2] | $ (18,100) | [2] | $ (73,475) | [2] | $ (61,228) | $ (103,534) | $ (473,980) |
Weighted average shares of common stock outstanding basic (shares) | 209,089,468 | 209,072,232 | 199,547,446 | 162,829,221 | 132,936,419 | 129,301,817 | 104,009,337 | 78,788,133 | 195,369,489 | 111,367,452 | 77,511,677 | ||||||||
Weighted average shares of common stock outstanding diluted (shares) | 209,089,468 | 209,072,232 | 199,547,446 | 162,829,221 | 132,936,419 | 129,301,817 | 104,009,337 | 78,788,133 | 195,369,489 | 111,367,452 | 77,511,677 | ||||||||
Basic (dollars per share) | $ (0.08) | $ (0.08) | $ (0.03) | $ (0.14) | $ (0.06) | $ (0.03) | $ (0.17) | $ (0.93) | $ (0.31) | $ (0.93) | $ (6.11) | ||||||||
Diluted (dollars per share) | $ (0.08) | $ (0.08) | $ (0.03) | $ (0.14) | $ (0.06) | $ (0.03) | $ (0.17) | $ (0.93) | $ (0.31) | $ (0.93) | $ (6.11) | ||||||||
Common shares excluded from denominator as anti-dilutive (shares) | 66,737,206 | 926,943 | 195,252 | ||||||||||||||||
Convertible notes | |||||||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||||||||||
Common shares excluded from denominator as anti-dilutive (shares) | 65,488,114 | 0 | 0 | ||||||||||||||||
Unvested restricted shares | |||||||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||||||||||
Common shares excluded from denominator as anti-dilutive (shares) | 821,710 | 438,948 | 177,663 | ||||||||||||||||
Unvested PBUs | |||||||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted, by Common Class, Including Two Class Method [Line Items] | |||||||||||||||||||
Common shares excluded from denominator as anti-dilutive (shares) | 427,382 | 487,995 | 17,589 | ||||||||||||||||
[1] | The first quarter includes a $12.2 million loss on early extinguishment of debt. | ||||||||||||||||||
[2] | The first quarter includes impairment of oil and natural gas properties of $48.5 million and the third quarter includes $10.1 million of litigation settlement benefit. |
Commitments and Contingencies82
Commitments and Contingencies (Narrative) (Details) | Mar. 03, 2017 | Aug. 10, 2016USD ($) | May 03, 2016Officer | Dec. 17, 2010USD ($) | Dec. 31, 2017USD ($)well | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 29, 2015USD ($) | Apr. 22, 2014awell |
Loss Contingencies [Line Items] | |||||||||
Office lease expense | $ 375,000 | $ 524,000 | $ 687,000 | ||||||
Fair market value, discounted present rate | 10.00% | ||||||||
Asset retirement obligation | $ 4,841,000 | $ 5,443,000 | |||||||
Development Agreement | |||||||||
Loss Contingencies [Line Items] | |||||||||
Number of wells drilled | well | 20 | ||||||||
Development Agreement | Investor | |||||||||
Loss Contingencies [Line Items] | |||||||||
Fair market value, discounted present rate | 15.00% | ||||||||
PennMarc Resources II, Limited Partners and Others | |||||||||
Loss Contingencies [Line Items] | |||||||||
Loss contingency, date of lawsuit filed | October 23, 2017 | ||||||||
Torchlight Energy Resources, Inc., Torchlight Energy, Inc. v. Husky Ventures, Inc. | |||||||||
Loss Contingencies [Line Items] | |||||||||
Number of executive officers filed lawsuit | Officer | 2 | ||||||||
Loss contingency, actions taken by plaintiff | On August 17, 2016, plaintiffs nonsuited, without prejudice, their claims against the former chairman of the board. | ||||||||
Loss contingency, date of dismissal of plantiff claims | May 22, 2017 | ||||||||
Gastar Exploration Ltd vs US Specialty Ins Co and Axis Ins Co | |||||||||
Loss Contingencies [Line Items] | |||||||||
Settlement aggregate amount | $ 10,100,000 | $ 21,200,000 | |||||||
Directors and officers liability coverage limit | $ 20,000,000 | ||||||||
Eagle Natrium LLC In the Court of Common Pleas of Allegheny County Pennsylvania [Member] | |||||||||
Loss Contingencies [Line Items] | |||||||||
Number of wells drilled | well | 3 | ||||||||
Area of gastar operator | a | 16,000 | ||||||||
Gross area for oil and gas lease adjacent to eagles facilitties | a | 3,300 | ||||||||
Maximum | |||||||||
Loss Contingencies [Line Items] | |||||||||
Lease Expiration Date | 2022-09 | ||||||||
Maximum | Gastar Exploration Inc V Christopher Mc Arthur | |||||||||
Loss Contingencies [Line Items] | |||||||||
Damages sought in arbitration matter | $ 2,750,000 | ||||||||
Term Loan | |||||||||
Loss Contingencies [Line Items] | |||||||||
Debt instrument maturity date | Mar. 3, 2022 | Mar. 3, 2022 | |||||||
Notes | |||||||||
Loss Contingencies [Line Items] | |||||||||
Debt instrument maturity date | Mar. 1, 2022 |
Commitments and Contingencies83
Commitments and Contingencies (Schedule of Future Minimum Rental Commitments) (Details) $ in Thousands | Dec. 31, 2017USD ($) |
Commitments And Contingencies Disclosure [Abstract] | |
2,018 | $ 977 |
2,019 | 971 |
2,020 | 979 |
2,021 | 971 |
2022 and thereafter | 322 |
Total | $ 4,220 |
Concentration of Risk and Sig84
Concentration of Risk and Significant Customers (Schedule of Concentration Risk) (Details) - Natural gas, oil and NGLs revenues excluding realized hedge impact | 12 Months Ended | |||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | ||
Customer Concentration Risk | Sunoco | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | 61.00% | 67.00% | 62.00% | |
Customer Concentration Risk | Superior | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | 14.00% | 12.00% | 6.00% | |
Customer Concentration Risk | SEI | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | [1] | 0.00% | 5.00% | 22.00% |
Appalachian Basin | Geographic Concentration Risk | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | 0.00% | 5.00% | 17.00% | |
Mid-Continent | Geographic Concentration Risk | ||||
Concentration Risk [Line Items] | ||||
Concentration risk, percentage | 100.00% | 95.00% | 83.00% | |
[1] | SEI filed for Chapter 7 bankruptcy on June 3, 2016. |
Statement of Cash Flows - Sup85
Statement of Cash Flows - Supplemental Information (Schedule of Supplemental Cash Paid and Non-cash Transactions) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||
Dec. 31, 2017 | Sep. 30, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | ||||||||
Cash paid for interest, net of capitalized amounts | $ 17,596 | $ 30,480 | $ 26,859 | |||||
Non-cash transactions: | ||||||||
Capital expenditures included in (excluded from) accounts payable and accrued drilling costs | 23,215 | (82) | (26,228) | |||||
Capital expenditures included in accounts receivable | 76 | 409 | ||||||
Asset retirement obligation included in oil and natural gas properties | 605 | 432 | 526 | |||||
Asset retirement obligation for property disposals | (1,533) | (1,045) | (416) | |||||
Application of advances to operators | 64 | (347) | 11,445 | |||||
Undeclared cumulative dividends on preferred stock | $ 3,618 | $ 2,412 | $ 3,618 | $ 3,618 | $ 3,619 | 6,030 | $ 10,855 | 0 |
Conversion of convertible debt to equity | $ 37,500 | |||||||
Other | $ 5 |
Quarterly Consolidated Financ86
Quarterly Consolidated Financial Data - Unaudited (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||||||||||
Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||||
Revenues | $ 15,483 | $ 15,332 | $ 22,646 | $ 18,669 | $ 18,287 | $ 13,003 | $ 12,153 | $ 14,811 | |||||||||||
Income (loss) from operations | (3,777) | (2,191) | 5,891 | 4,274 | 3,929 | [1] | 7,959 | [1] | (5,142) | [1] | (60,592) | [1] | $ 4,197 | $ (53,846) | $ (428,834) | ||||
Income (loss) before provision for income taxes | (12,979) | [2] | (12,299) | [2] | (2,779) | [2] | (18,698) | [2] | (4,545) | [1] | (178) | [1] | (14,481) | [1] | (69,857) | [1] | |||
Net income (loss) | (12,979) | [2] | (12,299) | [2] | (2,779) | [2] | (18,698) | [2] | (4,545) | [1] | (178) | [1] | (14,481) | [1] | (69,857) | [1] | (46,755) | (89,061) | (459,507) |
Dividends on preferred stock | 1,206 | 3,619 | 3,618 | 3,618 | 8,443 | 3,618 | 14,473 | ||||||||||||
Undeclared cumulative dividends on preferred stock | 3,618 | 2,412 | 3,618 | 3,618 | 3,619 | 6,030 | 10,855 | 0 | |||||||||||
Net loss attributable to common stockholders | $ (16,597) | [2] | $ (15,917) | [2] | $ (6,398) | [2] | $ (22,316) | [2] | $ (8,163) | [1] | $ (3,796) | [1] | $ (18,100) | [1] | $ (73,475) | [1] | $ (61,228) | $ (103,534) | $ (473,980) |
Net loss per share of common stock attributable to common stockholders: | |||||||||||||||||||
Basic (in dollars per share) | $ (0.08) | $ (0.08) | $ (0.03) | $ (0.14) | $ (0.06) | $ (0.03) | $ (0.17) | $ (0.93) | $ (0.31) | $ (0.93) | $ (6.11) | ||||||||
Diluted (in dollars per share) | $ (0.08) | $ (0.08) | $ (0.03) | $ (0.14) | $ (0.06) | $ (0.03) | $ (0.17) | $ (0.93) | $ (0.31) | $ (0.93) | $ (6.11) | ||||||||
Weighted average shares of common stock outstanding: | |||||||||||||||||||
Basic (shares) | 209,089,468 | 209,072,232 | 199,547,446 | 162,829,221 | 132,936,419 | 129,301,817 | 104,009,337 | 78,788,133 | 195,369,489 | 111,367,452 | 77,511,677 | ||||||||
Diluted (shares) | 209,089,468 | 209,072,232 | 199,547,446 | 162,829,221 | 132,936,419 | 129,301,817 | 104,009,337 | 78,788,133 | 195,369,489 | 111,367,452 | 77,511,677 | ||||||||
[1] | The first quarter includes impairment of oil and natural gas properties of $48.5 million and the third quarter includes $10.1 million of litigation settlement benefit. | ||||||||||||||||||
[2] | The first quarter includes a $12.2 million loss on early extinguishment of debt. |
Quarterly Consolidated Financ87
Quarterly Consolidated Financial Data - Unaudited (Parenthetical) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||
Mar. 31, 2017 | Sep. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||
Loss on early extinguishment of debt | $ 12,200 | $ 12,172 | $ 0 | $ 0 | |||||
Impairment of natural gas and oil properties | $ 48,497 | $ 144,760 | $ 181,966 | $ 100,152 | 0 | 48,497 | 426,878 | ||
Litigation settlement benefit | $ 10,100 | $ 0 | $ 10,100 | $ 0 |
Supplemental Oil and Gas Disc88
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved properties | $ 1,344,329 | $ 1,253,061 | |
Unproved properties | 131,955 | 67,333 | |
Total natural gas and oil properties | 1,476,284 | 1,320,394 | |
Impairment of proved oil and natural gas properties | (813,314) | (813,314) | |
U S | |||
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items] | |||
Proved properties | 1,344,329 | 1,253,061 | $ 1,286,373 |
Unproved properties | 131,955 | 67,333 | 92,609 |
Total natural gas and oil properties | 1,476,284 | 1,320,394 | 1,378,982 |
Impairment of proved oil and natural gas properties | (813,314) | (813,314) | (764,817) |
Accumulated depreciation, depletion and amortization | (339,043) | (315,373) | (286,020) |
Net capitalized costs | $ 323,927 | $ 191,707 | $ 328,145 |
Supplemental Oil and Gas Disc89
Supplemental Oil and Gas Disclosures - Unaudited (Narrative) (Details) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Extractive Industries [Abstract] | |||
Asset retirement costs | $ 586,000 | $ 1.5 | $ 2.4 |
Supplemental Oil and Gas Disc90
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Extractive Industries [Abstract] | |||
Proved property acquisition | $ 6,059 | $ 570 | $ 15,615 |
Unproved property acquisition | 91,266 | 38,941 | 50,434 |
Exploration | 59,771 | 19,761 | 53,290 |
Development | 29,103 | 3,810 | 54,316 |
Total costs incurred | $ 186,199 | $ 63,082 | $ 173,655 |
Supplemental Oil and Gas Disc91
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Results of Operations for Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Extractive Industries [Abstract] | |||
Oil, condensate, natural gas and NGLs sales, including commodity derivatives | $ 72,130 | $ 58,254 | $ 107,294 |
Production expenses | (26,839) | (24,217) | (28,792) |
Impairment of oil and natural gas properties | 0 | (48,497) | (426,878) |
Depreciation, depletion and amortization | (23,670) | (29,353) | (62,465) |
Results of producing activities | $ 21,621 | $ (43,813) | $ (410,841) |
Supplemental Oil and Gas Disc92
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details) bbl in Thousands, MBoe in Thousands | 12 Months Ended | ||||||
Dec. 31, 2017MBoebblMMcf | Dec. 31, 2016MBoebblMMcf | Dec. 31, 2015MBoebblMMcf | |||||
Proved Developed And Undeveloped Reserves [Roll Forward] | |||||||
Proved reserves as of the beginning of the period, equivalents | MBoe | [1] | 25,577 | 55,877 | 102,063 | |||
Extensions and discoveries | MBoe | [1] | 16,374 | [2] | 3,681 | 9,374 | [3] | |
Revisions of previous estimates | MBoe | [1] | 2,887 | (16,177) | [4] | (53,268) | [5] | |
Production | MBoe | [1] | (2,278) | (2,869) | (4,931) | |||
Purchases in place | MBoe | [1] | 612 | 2,971 | ||||
Sales in place | MBoe | [1] | (245) | (14,935) | (332) | |||
Proved reserves at the end of the period. equivalents | MBoe | [1] | 42,927 | 25,577 | 55,877 | |||
Proved developed reserves | MBoe | [1] | 18,027 | 13,015 | 28,415 | |||
Proved undeveloped reserves | MBoe | [1] | 24,900 | 12,562 | 27,462 | |||
Total | MBoe | [1] | 42,927 | 25,577 | 55,877 | |||
Oil | |||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | |||||||
Proved reserves as of the beginning of the period | [6] | 13,756 | 24,202 | 28,636 | |||
Extensions and discoveries | [6] | 8,787 | [2] | 1,582 | 4,777 | [3] | |
Revisions of previous estimates | [6] | 1,373 | (9,890) | [4] | (8,962) | [5] | |
Production | [6] | (1,118) | (1,105) | (1,425) | |||
Purchases in place | [6] | 182 | 1,270 | ||||
Sales in place | [6] | (124) | (1,033) | (94) | |||
Proved reserves as of the end of the period | [6] | 22,856 | 13,756 | 24,202 | |||
Proved developed reserves | [6] | 8,140 | 6,037 | 7,181 | |||
Proved undeveloped reserves | [6] | 14,716 | 7,719 | 17,021 | |||
Total | [6] | 22,856 | 13,756 | 24,202 | |||
Natural Gas | |||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | |||||||
Proved reserves as of the beginning of the period | MMcf | [7] | 37,853 | 108,451 | 287,005 | |||
Extensions and discoveries | MMcf | [7] | 26,065 | [2] | 7,213 | 14,114 | [3] | |
Revisions of previous estimates | MMcf | [7] | 4,295 | (17,825) | [4] | (182,600) | [5] | |
Production | MMcf | [7] | (3,795) | (6,145) | (13,759) | |||
Purchases in place | MMcf | [7] | 1,391 | 4,965 | ||||
Sales in place | MMcf | [7] | (444) | (53,841) | (1,274) | |||
Proved reserves as of the end of the period | MMcf | [7] | 65,365 | 37,853 | 108,451 | |||
Proved developed reserves | MMcf | [7] | 31,723 | 22,786 | 77,966 | |||
Proved undeveloped reserves | MMcf | [7] | 33,642 | 15,067 | 30,485 | |||
Total | MMcf | [7] | 65,365 | 37,853 | 108,451 | |||
Natural Gas Liquids | |||||||
Proved Developed And Undeveloped Reserves [Roll Forward] | |||||||
Proved reserves as of the beginning of the period | [6] | 5,512 | 13,599 | 25,593 | |||
Extensions and discoveries | [6] | 3,243 | [2] | 898 | 2,244 | [3] | |
Revisions of previous estimates | [6] | 798 | (3,317) | [4] | (13,873) | [5] | |
Production | [6] | (527) | (739) | (1,212) | |||
Purchases in place | [6] | 198 | 873 | ||||
Sales in place | [6] | (47) | (4,929) | (26) | |||
Proved reserves as of the end of the period | [6] | 9,177 | 5,512 | 13,599 | |||
Proved developed reserves | [6] | 4,600 | 3,181 | 8,240 | |||
Proved undeveloped reserves | [6] | 4,577 | 2,331 | 5,359 | |||
Total | [6] | 9,177 | 5,512 | 13,599 | |||
[1] | Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. | ||||||
[2] | All of the 2017 extensions and discoveries resulted from the Company’s successful STACK Play drilling operations. | ||||||
[3] | All of the 2015 extensions and discoveries resulted from the Company’s Mid-Continent drilling operations. | ||||||
[4] | The 2016 revisions of previous estimates resulted primarily from the removal of Hunton PUD locations as the Company now focuses its capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate its STACK Play position. | ||||||
[5] | The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. | ||||||
[6] | Thousand barrels | ||||||
[7] | Million cubic feet |
Supplemental Oil and Gas Disc93
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Parenthetical) (Details) - MBoe MBoe in Thousands | 12 Months Ended | |||||
Dec. 31, 2017 | Dec. 31, 2016 | [2] | Dec. 31, 2015 | |||
Reserve Quantities [Line Items] | ||||||
Production, Barrels of Oil Equivalents | Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. | |||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease) | [1] | (2,887) | 16,177 | 53,268 | [3] | |
Appalachian Basin | ||||||
Reserve Quantities [Line Items] | ||||||
Proved Developed and Undeveloped Reserves, Net, Period Increase (Decrease) | (36,800) | |||||
[1] | Thousand barrels of oil, condensate or NGLs and natural gas equivalent. Natural gas volumes have been converted to equivalent oil, condensate and NGLs volumes using a conversion factor of one barrel of oil, condensate or NGLs to six cubic feet of natural gas. | |||||
[2] | The 2016 revisions of previous estimates resulted primarily from the removal of Hunton PUD locations as the Company now focuses its capital activity on drilling Meramec and Osage wells to hold acreage by production and delineate its STACK Play position. | |||||
[3] | The 2015 revisions of previous estimates resulted primarily from a 36.8 MMBoe decrease in Appalachian Basin reserves due to the suspension of the Marcellus and Utica Shale drilling programs in 2015 and the significant decrease in the 12-month unweighted arithmetic average of the first-day-of-the-month prices for oil and natural gas as of December 31, 2015 and 2014. |
Supplemental Oil and Gas Disc94
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Oil and Gas Net Production, Average Sales Price and Average Production Costs) (Details) | 3 Months Ended | 12 Months Ended | ||||||||||||||
Dec. 31, 2017$ / MMBTU$ / bbl | Sep. 30, 2017$ / MMBTU$ / bbl | Jun. 30, 2017$ / MMBTU$ / bbl | Mar. 31, 2017$ / MMBTU$ / bbl | Dec. 31, 2016$ / MMBTU$ / bbl | Sep. 30, 2016$ / MMBTU$ / bbl | Jun. 30, 2016$ / MMBTU$ / bbl | Mar. 31, 2016$ / MMBTU$ / bbl | Dec. 31, 2015$ / MMBTU$ / bbl | Sep. 30, 2015$ / MMBTU$ / bbl | Jun. 30, 2015$ / MMBTU$ / bbl | Mar. 31, 2015$ / MMBTU$ / bbl | Dec. 31, 2017$ / MMBTU$ / bbl | Dec. 31, 2016$ / MMBTU$ / bbl | Dec. 31, 2015$ / MMBTU$ / bbl | ||
Natural gas (per MMBtu): | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Key natural gas and oil prices | $ / MMBTU | [1] | 2.98 | 3 | 3.01 | 2.73 | 2.48 | 2.28 | 2.24 | 2.40 | 2.59 | 3.06 | 3.39 | 3.88 | |||
Oil (per Bbl): | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Key natural gas and oil prices | $ / bbl | [1] | 51.34 | 49.81 | 48.95 | 47.61 | 42.75 | 41.68 | 43.12 | 46.26 | 50.28 | 59.21 | 71.68 | 82.72 | |||
Henry Hub | Natural gas (per MMBtu): | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Key natural gas and oil prices | $ / MMBTU | 2.98 | 2.48 | 2.59 | |||||||||||||
WTI spot | Oil (per Bbl): | ||||||||||||||||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | ||||||||||||||||
Key natural gas and oil prices | $ / bbl | 51.34 | 42.75 | 50.28 | |||||||||||||
[1] | For the respective periods, oil and natural gas prices are calculated using the trailing 12-month unweighted arithmetic average of the first-day-of-the-month prices based on Henry Hub spot natural gas prices and West Texas Intermediate spot oil prices. |
Supplemental Oil and Gas Disc95
Supplemental Oil and Gas Disclosures - Unaudited (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves) (Details) - U S - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | ||||
Future cash inflows | $ 1,491,158 | $ 710,370 | $ 1,425,734 | |
Future production costs | (645,891) | (328,010) | (547,484) | |
Future development costs | (295,212) | (123,214) | (365,123) | |
Future income taxes | (1,768) | 0 | ||
Future net cash flows | 548,287 | 259,146 | 513,127 | |
10% annual discount for estimated timing of cash flows | (261,645) | (117,815) | (283,324) | |
Standardized measure of discounted future cash flows | $ 286,642 | $ 141,331 | $ 229,803 | $ 816,739 |
Supplemental Oil and Gas Disc96
Supplemental Oil and Gas Disclosures - Unaudited (Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) - U S - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||
Beginning of period | $ 141,331 | $ 229,803 | $ 816,739 |
Extensions and discoveries, less related costs | 100,746 | 19,270 | 71,547 |
Sale of natural gas and oil, net of production costs | (49,746) | (36,900) | (53,914) |
Purchases of reserves in place | 5,493 | 9,937 | |
Sales of reserves in place | (2,051) | (16,023) | (4,853) |
Revisions of previous quantity estimates | 29,694 | (115,785) | (324,036) |
Net change in income tax | (1,768) | 171,946 | |
Net change in prices and production costs | 78,978 | (43,270) | (604,074) |
Accretion of discount | (14,133) | (16,461) | 98,869 |
Development costs incurred | 385 | 10,500 | |
Net change in estimated future development costs | (8,595) | 119,531 | 31,131 |
Change in production rates (timing) and other | 6,308 | 1,166 | 6,011 |
End of period | $ 286,642 | $ 141,331 | $ 229,803 |