Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2016 | Aug. 03, 2016 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2016 | |
Document Fiscal Year Focus | 2,016 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | ECR | |
Entity Registrant Name | Eclipse Resources Corp | |
Entity Central Index Key | 1,600,470 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 260,591,893 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
REVENUES | ||||
Oil and natural gas sales | $ 45,901 | $ 64,984 | $ 86,389 | $ 111,598 |
Brokered natural gas and marketing revenue | 1,165 | 9,469 | 10,283 | 6,669 |
Total revenues | 47,066 | 74,453 | 96,672 | 118,267 |
OPERATING EXPENSES | ||||
Lease operating | 2,248 | 3,589 | 4,925 | 6,935 |
Transportation, gathering and compression | 28,254 | 22,634 | 51,391 | 35,085 |
Production and ad valorem taxes | 2,051 | 3,078 | (233) | 5,178 |
Brokered natural gas and marketing expense | 2,160 | 10,795 | 11,562 | 10,795 |
Depreciation, depletion and amortization | 20,949 | 60,641 | 36,062 | 103,073 |
Exploration | 17,444 | 6,243 | 33,100 | 19,696 |
General and administrative | 10,402 | 12,717 | 21,676 | 24,660 |
Rig termination and standby | 1,292 | 366 | 3,955 | 7,423 |
Impairment of proved oil and gas properties | 17,665 | 0 | ||
Accretion of asset retirement obligations | 89 | 399 | 175 | 785 |
(Gain) loss on sale of assets | (1,024) | (5,553) | (1,046) | (5,473) |
Total operating expenses | 83,865 | 114,909 | 179,232 | 208,157 |
OPERATING LOSS | (36,799) | (40,456) | (82,560) | (89,890) |
OTHER INCOME (EXPENSE) | ||||
Gain (loss) on derivative instruments | (29,596) | (3,523) | (19,046) | 7,848 |
Interest expense, net | (12,439) | (14,401) | (25,900) | (28,422) |
Gain on early extinguishment of debt | 5,825 | 14,489 | 0 | |
Other income (expense) | (2) | (2) | (141) | 400 |
Total other expense, net | (36,212) | (17,926) | (30,598) | (20,174) |
LOSS BEFORE INCOME TAXES | (73,011) | (58,382) | (113,158) | (110,064) |
INCOME TAX BENEFIT (EXPENSE) | 16,412 | (540) | 33,991 | |
NET LOSS | $ (73,011) | $ (41,970) | $ (113,698) | $ (76,073) |
NET LOSS PER COMMON SHARE | ||||
Basic and diluted | $ (0.33) | $ (0.19) | $ (0.51) | $ (0.36) |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING | ||||
Basic and diluted | 223,013 | 222,502 | 222,898 | 213,178 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 114,056 | $ 184,405 |
Accounts receivable | 25,485 | 27,476 |
Assets held for sale | 184 | 21,971 |
Other current assets | 4,981 | 35,532 |
Total current assets | 144,706 | 269,384 |
Oil and natural gas properties, successful efforts method: | ||
Unproved properties | 684,383 | 720,159 |
Proved oil and gas properties, net | 263,069 | 265,838 |
Other property and equipment, net | 7,423 | 7,971 |
Total property and equipment, net | 954,875 | 993,968 |
OTHER NONCURRENT ASSETS | ||
Other assets | 1,009 | 2,520 |
Deferred taxes | 540 | |
TOTAL ASSETS | 1,100,590 | 1,266,412 |
CURRENT LIABILITIES | ||
Accounts payable | 34,753 | 34,717 |
Accrued capital expenditures | 7,880 | 10,956 |
Accrued liabilities | 21,781 | 25,462 |
Accrued interest payable | 20,919 | 23,809 |
Liabilities held for sale | 18,898 | |
Total current liabilities | 85,333 | 113,842 |
NONCURRENT LIABILITIES | ||
Debt, net of unamortized discount and debt issuance costs | 490,990 | 527,248 |
Asset retirement obligations | 3,639 | 3,401 |
Other liabilities | 10,409 | 1,367 |
Total liabilities | 590,371 | 645,858 |
COMMITMENTS AND CONTINGENCIES | ||
STOCKHOLDERS' EQUITY | ||
Preferred stock, 50,000,000 authorized, no shares issued and outstanding | ||
Common stock, $0.01 par value, 1,000,000,000 authorized, 223,091,686 and 222,674,270 shares issued and outstanding, respectively | 2,232 | 2,227 |
Additional paid in capital | 1,832,501 | 1,829,082 |
Treasury stock, shares at cost; 72,590 at June 30, 2016 | (61) | |
Accumulated deficit | (1,324,453) | (1,210,755) |
Total stockholders' equity | 510,219 | 620,554 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ 1,100,590 | $ 1,266,412 |
Condensed Consolidated Balance4
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares | Jun. 30, 2016 | Dec. 31, 2015 |
Statement Of Financial Position [Abstract] | ||
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 1,000,000,000 | 1,000,000,000 |
Common stock, shares issued | 223,091,686 | 222,674,270 |
Common stock, shares outstanding | 223,091,686 | 222,674,270 |
Treasury stock, shares | 72,590 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Comprehensive Loss (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Statement Of Income And Comprehensive Income [Abstract] | ||||
NET LOSS | $ (73,011) | $ (41,970) | $ (113,698) | $ (76,073) |
Other comprehensive income (loss): | ||||
Pension obligation adjustment, net of tax | 192 | (18) | ||
TOTAL COMPREHENSIVE LOSS | $ (73,011) | $ (41,778) | $ (113,698) | $ (76,091) |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - 6 months ended Jun. 30, 2016 - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Treasury Stock [Member] | Accumulated Deficit [Member] |
Beginning Balances at Dec. 31, 2015 | $ 620,554 | $ 2,227 | $ 1,829,082 | $ (1,210,755) | |
Beginning Balance, shares at Dec. 31, 2015 | 222,674,270 | ||||
Stock-based compensation | 3,701 | 3,701 | |||
Equity issuance costs | (277) | (277) | |||
Issuance of restricted stock | $ 2 | (2) | |||
Issuance of restricted stock, shares | 149,448 | ||||
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings | (61) | $ 3 | (3) | $ (61) | |
Issuance of common stock upon vesting of equity-based compensation awards, net of shares withheld for income tax withholdings, shares | 267,968 | ||||
Repurchase of common stock, shares | (72,590) | ||||
Net loss | (113,698) | (113,698) | |||
Ending Balances at Jun. 30, 2016 | $ 510,219 | $ 2,232 | $ 1,832,501 | $ (61) | $ (1,324,453) |
Ending Balance, shares at Jun. 30, 2016 | 223,091,686 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net loss | $ (113,698) | $ (76,073) |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities | ||
Depreciation, depletion and amortization | 36,062 | 103,073 |
Exploration expense | 18,722 | 6,073 |
Pension benefit costs | 0 | 101 |
Stock-based compensation | 3,701 | 2,157 |
Impairment of proved oil and gas properties | 17,665 | 0 |
Accretion of asset retirement obligations | 175 | 785 |
(Gain) loss on derivative instruments | 19,046 | (7,848) |
Net cash receipts (payments) on settled derivatives | 31,258 | 14,422 |
(Gain) loss on sale of assets | (1,046) | (5,473) |
Gain on early extinguishment of debt | (14,489) | 0 |
Deferred income taxes | 540 | (34,107) |
Interest not paid in cash | 0 | 1,232 |
Amortization of deferred financing costs | 972 | 1,018 |
Amortization of debt discount | 691 | 1,193 |
Changes in operating assets and liabilities, net of acquisitions: | ||
Accounts receivable | (1,238) | 13,007 |
Other assets | (2,586) | 225 |
Accounts payable and accrued liabilities | (13,026) | 29,724 |
Net cash provided by (used in) operating activities | (17,251) | 49,509 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures for oil and gas properties | (42,913) | (327,856) |
Capital expenditures for other property and equipment | (416) | (1,284) |
Proceeds from sale of assets | 14,094 | 37,287 |
Net cash used in investing activities | (29,235) | (291,853) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Debt issuance costs | 261 | (1,577) |
Repayments of long-term debt | (23,786) | (207) |
Proceeds from issuance of common stock | 0 | 440,000 |
Equity issuance costs | (277) | (5,767) |
Employee tax withholding for settlement of equity compensation awards | (61) | 0 |
Net cash provided by (used in) financing activities | (23,863) | 432,449 |
Net increase (decrease) in cash and cash equivalents | (70,349) | 190,105 |
Cash and cash equivalents at beginning of period | 184,405 | 67,517 |
Cash and cash equivalents at end of period | 114,056 | 257,622 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||
Cash paid for interest | 25,175 | 13,080 |
Cash paid for income taxes | 0 | 37 |
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES: | ||
Asset retirement obligations incurred, including changes in estimate | 63 | 303 |
Additions of other property through debt financing | 0 | 888 |
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures | 123 | (88,418) |
Interest paid-in-kind | $ 0 | $ 14,786 |
Derivative Instruments
Derivative Instruments | 6 Months Ended |
Jun. 30, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | ERROR: Could not retrieve Word content for note block |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | ERROR: Could not retrieve Word content for note block |
Debt
Debt | 6 Months Ended |
Jun. 30, 2016 | |
Debt Disclosure [Abstract] | |
Debt | ERROR: Could not retrieve Word content for note block |
Benefit Plans
Benefit Plans | 6 Months Ended |
Jun. 30, 2016 | |
Compensation And Retirement Disclosure [Abstract] | |
Benefit Plans | ERROR: Could not retrieve Word content for note block |
Stock-Based Compensation
Stock-Based Compensation | 6 Months Ended |
Jun. 30, 2016 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Stock-Based Compensation | ERROR: Could not retrieve Word content for note block |
Equity
Equity | 6 Months Ended |
Jun. 30, 2016 | |
Equity [Abstract] | |
Equity | ERROR: Could not retrieve Word content for note block |
Related Party Transactions
Related Party Transactions | 6 Months Ended |
Jun. 30, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | ERROR: Could not retrieve Word content for note block |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | ERROR: Could not retrieve Word content for note block |
Income Tax
Income Tax | 6 Months Ended |
Jun. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Tax | ERROR: Could not retrieve Word content for note block |
Subsidiary Guarantors
Subsidiary Guarantors | 6 Months Ended |
Jun. 30, 2016 | |
Text Block [Abstract] | |
Subsidiary Guarantors | ERROR: Could not retrieve Word content for note block |
Subsequent Events
Subsequent Events | 6 Months Ended |
Jun. 30, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | ERROR: Could not retrieve Word content for note block |
Organization and Nature of Oper
Organization and Nature of Operations | 6 Months Ended |
Jun. 30, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Organization and Nature of Operations | Note 1—Organization and Nature of Operations Eclipse Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas. |
Basis of Presentation
Basis of Presentation | 6 Months Ended |
Jun. 30, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Note 2—Basis of Presentation The accompanying condensed consolidated financial statements are unaudited except the condensed consolidated balance sheet at December 31, 2015, which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements, and the notes to those statements, which are included in the Company’s Annual Report on Form 10-K filed with the SEC on March 4, 2016. Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2016 or any other future periods. Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. Note 3— Summary of Significant Accounting Policies · estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion and amortization and impairment of capitalized costs of oil and natural gas properties; · estimates of asset retirement obligations; · estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells; · impairment of undeveloped properties and other assets; and · depreciation and depletion of property and equipment. Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 3—Summary of Significant Accounting Policies (a) Cash and Cash Equivalents Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits. (b) Accounts Receivable Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of June 30, 2016 or December 31, 2015. The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $21.6 million and $19.9 million of accrued revenues, net of certain expenses at June 30, 2016 and December 31, 2015, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets. (c) Property and Equipment Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, Depletion and Amortization Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. A summary of property and equipment including oil and natural gas properties is as follows (in thousands): June 30, 2016 December 31, 2015 Oil and natural gas properties: Unproved $ 684,383 $ 720,159 Proved 1,338,546 1,288,609 Gross oil and natural gas properties 2,022,929 2,008,768 Less accumulated depreciation depletion and amortization (1,075,477 ) (1,022,771 ) Oil and natural gas properties, net 947,452 985,997 Other property and equipment 11,169 10,753 Less accumulated depreciation (3,746 ) (2,782 ) Other property and equipment, net 7,423 7,971 Property and equipment, net $ 954,875 $ 993,968 Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. The Company capitalized interest expense totaling $0.3 million and $1.1 million for the three months ended June 30, 2016 and 2015, respectively. The Company capitalized interest expense totaling $0.5 million and $2.6 million for the six months ended June 30, 2016 and 2015, respectively. Other Property and Equipment Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. (d) Revenue Recognition Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of June 30, 2016 or December 31, 2015. In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense. Brokered natural gas and marketing revenues include revenues from brokered gas or revenue the Company receives as a result of selling and buying natural gas that is not related to its production and revenue from the release of transportation capacity. The Company realizes brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. The Company considers these activities as ancillary to its natural gas sales and thus, reports them within one operating segment. (e) Concentration of Credit Risk The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of June 30, 2016 and December 31, 2015 (in thousands): June 30, 2016 December 31, 2015 Receivables by product or service: Sale of oil and natural gas and related products and services $ 21,625 $ 19,858 Joint interest owners 2,493 3,095 Derivatives 1,294 4,523 Miscellaneous other 73 — Total $ 25,485 $ 27,476 Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s unsettled commodity derivative contracts was a net liability position of ($12.6) million and a net asset position of $34.4 million at June 30, 2016 and December 31, 2015, respectively. Other than as provided by the its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are such counterparties required to provide credit support to the Company. As of June 30, 2016 and December 31, 2015, the Company did not have past-due receivables from or payables to any of such counterparties. (f) Accumulated Other Comprehensive Income (Loss) Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include a pension benefit plan that requires the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its consolidated balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was terminated in October 2015 and lump sum payments were made in final settlement to all remaining participants. (g) Depreciation, Depletion and Amortization Oil and Natural Gas Properties Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties totaled approximately $20.4 million and $60.1 million for the three months ended June 30, 2016 and 2015, respectively, and $35.0 million and $102.2 million for the six months ended June 30, 2016 and 2015, respectively. Other Property and Equipment Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation totaled approximately $0.5 million and $0.5 million for the three months ended June 30, 2016 and 2015, respectively, and $1.0 million and $0.8 million for the six months ended June 30, 2016 and 2015, respectively. This amount is included in DD&A expense in the condensed consolidated statements of operations. (h) Impairment of Long-Lived Assets The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value. The review for impairment of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the six months ended June 30, 2016 relating to proved properties in the Marcellus Shale. There were no impairments of proved properties for the three or six months ended June 30, 2015 or the three months ended June 30, 2016. The aforementioned impairment charge represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $9.4 million and $4.4 million for the three months ended June 30, 2016 and 2015, respectively, and approximately $18.7 million and $6.0 million for the six months ended June 30, 2016 and 2015, respectively. The increase in impairment charges during the three and six months ended June 30, 2016 is the result of an increase in expected lease expirations due to the reduction in the Company’s planned future drilling activity due to the current commodity pricing environment. These costs are included in exploration expense in the condensed consolidated statements of operations. (i) Income Taxes The Company accounts for income taxes, as required, under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” 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 and 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. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date. (j) Fair Value of Financial Instruments The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value: Level 1 —Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 —Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability. Level 3 —Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. (k) Derivative Financial Instruments The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells. Derivatives are recorded at fair value and are included on the condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities. The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy. (l) Asset Retirement Obligation The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “ Asset Retirement and Environmental Obligations Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset. The following table sets forth the changes in the Company’s ARO liability for the six months ended June 30, 2016 (in thousands): Six Months Ended June 30, 2016 Asset retirement obligations, beginning of period $ 3,401 Additional liabilities incurred 63 Accretion 175 Asset retirement obligations, end of period $ 3,639 The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement. (m) Lease Obligations The Company leases office space under operating leases that expire between the years 2016 to 2025. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception. (n) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. (o) Segment Reporting The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States. (p) Debt Issuance Costs The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. (q) Recent Accounting Pronouncements The FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”)”, which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. In August 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” The new standard provides guidance on determining when and how to disclose going concern uncertainties in the financial statements. Management will be required to perform interim and annual assessments of the Company’s ability to continue as a going concern within one year of the date and financial statements are issued. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have a significant impact on the Company’s financial statement disclosures. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity will be required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-02 on its financial position, results of operations and related disclosures. In March 2016, the FASB issued ASU 2016-09, “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The new standard provides guidance involving several aspects of the accounting for share-based payments transactions, including income tax consequences, award classification as liabilities or equity, and cash flow statements classifications. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-09 on its financial position, results of operations and related disclosures. (r) Change in estimates During the three months ended June 30, 2016, the Company reduced its estimate of amounts due from a non-operated partner related to the sale of natural gas and NGLs, net of associated costs, based on revised information received from the non-operated partner during the period. As a result, the Company decreased accounts receivable by approximately $4 million, increased revenue from oil and natural gas sales by approximately $1.5 million, and increased transportation, gathering and compression expense by approximately $5.8 million, which increased the net loss for the three and six months ended June 30, 2016 by approximately $4 million, or $0.02 per common share. During the six months ended June 30, 2016, the Company reduced its estimate for production and ad valorem tax expense based on recent historical experience and additional information received during the period. As a result, the Company decreased the accrual for production and ad valorem taxes to be paid by approximately $4 million, which decreased the net loss for the six months ended June 30, 2016 by a corresponding amount, or $0.02 per common share. |
Sale of Oil and Natural Gas Pro
Sale of Oil and Natural Gas Property Interests | 6 Months Ended |
Jun. 30, 2016 | |
Discontinued Operations And Disposal Groups [Abstract] | |
Sale of Oil and Natural Gas Property Interests | Note 4—Sale of Oil and Natural Gas Property Interests During the three and six months ended June 30, 2016 , the Company completed the sale of its Conventional oil and gas properties and related equipment for approximately $4.7 million. As a result of this sale, the Company recognized a gain of approximately $1.0 million . During the three and six months ended June 30, 2016 , the Company received $3.9 million from the sale of mineral interests related primarily to unproved properties to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties. During the six months ended June 30, 2016, the Company received $4.8 million from the sale of unproved leases to a third party. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and natural gas properties. |
Summary of Significant Accoun23
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2016 | |
Accounting Policies [Abstract] | |
Cash and Cash Equivalents | (a) Cash and Cash Equivalents Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits. |
Accounts Receivable | (b) Accounts Receivable Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of June 30, 2016 or December 31, 2015. The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $21.6 million and $19.9 million of accrued revenues, net of certain expenses at June 30, 2016 and December 31, 2015, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets. |
Property and Equipment | (c) Property and Equipment Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “Depreciation, Depletion and Amortization Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. A summary of property and equipment including oil and natural gas properties is as follows (in thousands): June 30, 2016 December 31, 2015 Oil and natural gas properties: Unproved $ 684,383 $ 720,159 Proved 1,338,546 1,288,609 Gross oil and natural gas properties 2,022,929 2,008,768 Less accumulated depreciation depletion and amortization (1,075,477 ) (1,022,771 ) Oil and natural gas properties, net 947,452 985,997 Other property and equipment 11,169 10,753 Less accumulated depreciation (3,746 ) (2,782 ) Other property and equipment, net 7,423 7,971 Property and equipment, net $ 954,875 $ 993,968 Exploration expenses, including geological and geophysical expenses and delay rentals for unevaluated oil and gas properties are charged to expense as incurred. Exploratory drilling costs are initially capitalized as unproved property, not subject to depletion, but charged to expense if and when the well is determined not to have found proved oil and gas reserves. The Company capitalized interest expense totaling $0.3 million and $1.1 million for the three months ended June 30, 2016 and 2015, respectively. The Company capitalized interest expense totaling $0.5 million and $2.6 million for the six months ended June 30, 2016 and 2015, respectively. Other Property and Equipment Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. |
Revenue Recognition | (d) Revenue Recognition Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of June 30, 2016 or December 31, 2015. In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense. Brokered natural gas and marketing revenues include revenues from brokered gas or revenue the Company receives as a result of selling and buying natural gas that is not related to its production and revenue from the release of transportation capacity. The Company realizes brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. The Company considers these activities as ancillary to its natural gas sales and thus, reports them within one operating segment. |
Concentration of Credit Risk | (e) Concentration of Credit Risk The Company’s principal exposures to credit risk are through the sale of its oil and natural gas production and related products and services, joint interest owner receivables and receivables resulting from commodity derivative contracts. The inability or failure of the Company’s significant customers or counterparties to meet their obligations or their insolvency or liquidation may adversely affect the Company’s financial results. The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of June 30, 2016 and December 31, 2015 (in thousands): June 30, 2016 December 31, 2015 Receivables by product or service: Sale of oil and natural gas and related products and services $ 21,625 $ 19,858 Joint interest owners 2,493 3,095 Derivatives 1,294 4,523 Miscellaneous other 73 — Total $ 25,485 $ 27,476 Oil and natural gas customers include pipelines, distribution companies, producers, gas marketers and industrial users primarily located in the State of Ohio. As a general policy, collateral is not required for receivables, but customers’ financial condition and credit worthiness are evaluated regularly. By using derivative instruments that are not traded on an exchange to hedge exposures to changes in commodity prices, the Company exposes itself to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, the Company’s policy is to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market-makers. Additionally, the Company uses master netting agreements to minimize credit-risk exposure. The creditworthiness of the Company’s counterparties is subject to periodic review. The fair value of the Company’s unsettled commodity derivative contracts was a net liability position of ($12.6) million and a net asset position of $34.4 million at June 30, 2016 and December 31, 2015, respectively. Other than as provided by the its revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under the Company’s contracts, nor are such counterparties required to provide credit support to the Company. As of June 30, 2016 and December 31, 2015, the Company did not have past-due receivables from or payables to any of such counterparties. |
Accumulated Other Comprehensive Income (Loss) | (f) Accumulated Other Comprehensive Income (Loss) Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include a pension benefit plan that requires the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its consolidated balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was terminated in October 2015 and lump sum payments were made in final settlement to all remaining participants. |
Depreciation, Depletion and Amortization | (g) Depreciation, Depletion and Amortization Oil and Natural Gas Properties Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method on a field level basis using total estimated proved reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for drilling, completion and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves. DD&A expense relating to proved oil and natural gas properties totaled approximately $20.4 million and $60.1 million for the three months ended June 30, 2016 and 2015, respectively, and $35.0 million and $102.2 million for the six months ended June 30, 2016 and 2015, respectively. Other Property and Equipment Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation totaled approximately $0.5 million and $0.5 million for the three months ended June 30, 2016 and 2015, respectively, and $1.0 million and $0.8 million for the six months ended June 30, 2016 and 2015, respectively. This amount is included in DD&A expense in the condensed consolidated statements of operations. |
Impairment of Long-Lived Assets | (h) Impairment of Long-Lived Assets The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset’s estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value if such carrying amount exceeds the fair value. The review for impairment of the Company’s oil and gas properties is done by determining if the historical cost of proved and unproved properties less the applicable accumulated DD&A and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves and a risk-adjusted portion of probable reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon current contracts in place, adjusted for basis differentials and market-related information, including published futures prices. The estimated future level of production is based on assumptions surrounding future prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. If the carrying value exceeds the expected future cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows) and the carrying value of the assets. As a result of the decline in commodity prices, the Company recognized impairment expenses of approximately $17.7 million for the six months ended June 30, 2016 relating to proved properties in the Marcellus Shale. There were no impairments of proved properties for the three or six months ended June 30, 2015 or the three months ended June 30, 2016. The aforementioned impairment charge represented a significant Level 3 measurement in the fair value hierarchy. The primary input used was the Company’s forecasted discount net cash flows. The determination of oil and natural gas reserve estimates is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. Unproved properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of approximately $9.4 million and $4.4 million for the three months ended June 30, 2016 and 2015, respectively, and approximately $18.7 million and $6.0 million for the six months ended June 30, 2016 and 2015, respectively. The increase in impairment charges during the three and six months ended June 30, 2016 is the result of an increase in expected lease expirations due to the reduction in the Company’s planned future drilling activity due to the current commodity pricing environment. These costs are included in exploration expense in the condensed consolidated statements of operations. |
Income Taxes | (i) Income Taxes The Company accounts for income taxes, as required, under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” 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 and 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. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date. |
Fair Value of Financial Instruments | (j) Fair Value of Financial Instruments The Company has established a hierarchy to measure its financial instruments at fair value which requires it to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The hierarchy defines three levels of inputs that may be used to measure fair value: Level 1 —Unadjusted quoted prices in active markets for identical, unrestricted assets and liabilities that the reporting entity has the ability to access at the measurement date. Level 2 —Inputs other than quoted prices included within Level 1 that are observable for the asset and liability or can be corroborated with observable market date for substantially the entire contractual term of the asset or liability. Level 3 —Unobservable inputs that reflect the entity’s own assumptions about the assumption market participants would use in the pricing of the asset or liability and are consequently not based on market activity but rather through particular valuation techniques. Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. |
Derivative Financial Instruments | (k) Derivative Financial Instruments The Company uses derivative financial instruments to reduce exposure to fluctuations in the prices of the energy commodities it sells. Derivatives are recorded at fair value and are included on the condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities. The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy. |
Asset Retirement Obligation | (l) Asset Retirement Obligation The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with ASC Topic 410, “ Asset Retirement and Environmental Obligations Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset. The following table sets forth the changes in the Company’s ARO liability for the six months ended June 30, 2016 (in thousands): Six Months Ended June 30, 2016 Asset retirement obligations, beginning of period $ 3,401 Additional liabilities incurred 63 Accretion 175 Asset retirement obligations, end of period $ 3,639 The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to ARO represent a significant nonrecurring Level 3 measurement. |
Lease Obligations | (m) Lease Obligations The Company leases office space under operating leases that expire between the years 2016 to 2025. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception. |
Off-Balance Sheet Arrangements | (n) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. |
Segment Reporting | (o) Segment Reporting The Company operates in one industry segment: the oil and natural gas exploration and production industry in the United States. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States. |
Debt Issuance Costs | (p) Debt Issuance Costs The expenditures related to issuing debt are capitalized and reported as a reduction of the Company’s debt balance in the accompanying balance sheets. These costs are amortized over the expected life of the related instruments using the effective interest rate method. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. |
Recent Accounting Pronouncements | (q) Recent Accounting Pronouncements The FASB issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“Update 2014-09”)”, which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, “Property, Plant and Equipment”, and intangible assets within the scope of Topic 350, “Intangibles—Goodwill and Other”) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. In August 2014, the FASB issued ASU 2014-15, “Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” The new standard provides guidance on determining when and how to disclose going concern uncertainties in the financial statements. Management will be required to perform interim and annual assessments of the Company’s ability to continue as a going concern within one year of the date and financial statements are issued. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have a significant impact on the Company’s financial statement disclosures. In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842).” The new standard provides guidance to increase transparency and comparability among organizations and industries by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. An entity will be required to recognize all leases in the statement of financial position as assets and liabilities regardless of the leases classification. These requirements are effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-02 on its financial position, results of operations and related disclosures. In March 2016, the FASB issued ASU 2016-09, “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The new standard provides guidance involving several aspects of the accounting for share-based payments transactions, including income tax consequences, award classification as liabilities or equity, and cash flow statements classifications. These requirements are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. The Company is evaluating the impact of the adoption of ASU 2016-09 on its financial position, results of operations and related disclosures. |
Change In Estimates | (r) Change in estimates During the three months ended June 30, 2016, the Company reduced its estimate of amounts due from a non-operated partner related to the sale of natural gas and NGLs, net of associated costs, based on revised information received from the non-operated partner during the period. As a result, the Company decreased accounts receivable by approximately $4 million, increased revenue from oil and natural gas sales by approximately $1.5 million, and increased transportation, gathering and compression expense by approximately $5.8 million, which increased the net loss for the three and six months ended June 30, 2016 by approximately $4 million, or $0.02 per common share. During the six months ended June 30, 2016, the Company reduced its estimate for production and ad valorem tax expense based on recent historical experience and additional information received during the period. As a result, the Company decreased the accrual for production and ad valorem taxes to be paid by approximately $4 million, which decreased the net loss for the six months ended June 30, 2016 by a corresponding amount, or $0.02 per common share. |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Derivative Instrument Positions for Future Production Periods | ERROR: Could not retrieve Word content for note block |
Fair Value of Derivative Instruments on a Gross Basis and on a Net basis as Presented in Consolidated Balance Sheets | ERROR: Could not retrieve Word content for note block |
Summary of Gains and Losses on Derivative Instruments | ERROR: Could not retrieve Word content for note block |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities that are Measured at Fair Value on a Recurring Basis | ERROR: Could not retrieve Word content for note block |
Benefit Plans (Tables)
Benefit Plans (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Compensation And Retirement Disclosure [Abstract] | |
Components of Pension Benefit Cost | ERROR: Could not retrieve Word content for note block |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Summary of Restricted Stock Unit Awards Activity | ERROR: Could not retrieve Word content for note block |
Summary of Performance Stock Unit Awards Activity | ERROR: Could not retrieve Word content for note block |
Schedule of Stock Based Compensation Expense | Our stock-based compensation expense is as follows for the three and six months ended June 30, 2016 and 2015 (in thousands): For the Three Months Ended June 30, For the Six Months Ended June 30, 2016 2015 2016 2015 Restricted stock units $ 1,388 $ 748 $ 2,243 $ 1,171 Performance units 677 376 1,057 528 Restricted stock issued to directors 142 255 353 400 Incentive units 19 31 48 58 Total expense $ 2,226 $ 1,410 $ 3,701 $ 2,157 |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2016 | |
Summary of Property and Equipment Including Oil and Natural Gas Properties | A summary of property and equipment including oil and natural gas properties is as follows (in thousands): June 30, 2016 December 31, 2015 Oil and natural gas properties: Unproved $ 684,383 $ 720,159 Proved 1,338,546 1,288,609 Gross oil and natural gas properties 2,022,929 2,008,768 Less accumulated depreciation depletion and amortization (1,075,477 ) (1,022,771 ) Oil and natural gas properties, net 947,452 985,997 Other property and equipment 11,169 10,753 Less accumulated depreciation (3,746 ) (2,782 ) Other property and equipment, net 7,423 7,971 Property and equipment, net $ 954,875 $ 993,968 |
Changes in Company's Asset Retirement Obligation Liability | The following table sets forth the changes in the Company’s ARO liability for the six months ended June 30, 2016 (in thousands): Six Months Ended June 30, 2016 Asset retirement obligations, beginning of period $ 3,401 Additional liabilities incurred 63 Accretion 175 Asset retirement obligations, end of period $ 3,639 |
Accounts Receivable [Member] | Product Concentration Risk [Member] | |
Concentration Risk | The following table summarizes the Company’s concentration of receivables, net of allowances, by product or service as of June 30, 2016 and December 31, 2015 (in thousands): June 30, 2016 December 31, 2015 Receivables by product or service: Sale of oil and natural gas and related products and services $ 21,625 $ 19,858 Joint interest owners 2,493 3,095 Derivatives 1,294 4,523 Miscellaneous other 73 — Total $ 25,485 $ 27,476 |
Sale of Oil and Natural Gas P29
Sale of Oil and Natural Gas Property Interests - Additional Information (Detail) - USD ($) | 3 Months Ended | 6 Months Ended |
Jun. 30, 2016 | Jun. 30, 2016 | |
Discontinued Operations And Disposal Groups [Abstract] | ||
Proceeds from sale of unproved lease properties | $ 4,800,000 | |
Gain or Loss on sale of oil and natural gas properties | 0 | |
Sale of conventional oil and gas properties and related equipment | $ 4,700,000 | 4,700,000 |
Gain on sale of conventional oil and gas properties and related equipment | 1,000,000 | 1,000,000 |
Proceeds from sale of unproved lease properties | 3,900,000 | 3,900,000 |
Gain or Loss on sale of oil and natural gas properties | $ 0 | $ 0 |
Derivative Instruments - Summar
Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail) | 6 Months Ended |
Jun. 30, 2016MMBTU$ / MMBTU$ / galbblgal | |
Natural Gas Derivatives Production Period July 2016 – December 2016 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 65,000 |
Weighted Average Price ($/MMBtu) | 3.28 |
Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 10,000 |
Weighted Average Price ($/MMBtu) | 2.98 |
Oil Derivatives Production Period July 2016 - December 2016 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 45.55 |
Volume (Bbls/d) | bbl | 850 |
NGL Derivatives Production Period July 2016 – December 2016 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (Gal/d) | gal | 42,000 |
Weighted Average Price ($/Gal) | $ / gal | 0.46 |
Production Period July 2016 – September 2016 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (Gal/d) | gal | 10,500 |
Weighted Average Price ($/Gal) | $ / gal | 0.46 |
Put Option [Member] | Natural Gas Derivatives Production Period July 2016 – December 2016 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 40,000 |
Weighted Average Price ($/MMBtu) | 2.90 |
Put Option [Member] | Natural Gas Derivatives Production Period July 2016 – December 2016 [Member] | Put Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 16,800 |
Weighted Average Price ($/MMBtu) | 2.75 |
Put Option [Member] | Natural Gas Derivatives Production Period July 2016 – December 2016 [Member] | Put Sold [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 40,000 |
Weighted Average Price ($/MMBtu) | 2.35 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price ($/MMBtu) | 3 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Purchased [Member] | Floor One [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price ($/MMBtu) | 2.75 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Purchased [Member] | Floor Two [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 2.50 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Purchased [Member] | Floor Three [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 2.75 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Sold [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 2.25 |
Put Option [Member] | Natural Gas Derivatives Production Period July 2016 – December 2017 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 3 |
Put Option [Member] | Oil Derivatives Production Period July 2016 - December 2016 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 60 |
Volume (Bbls/d) | bbl | 1,000 |
Put Option [Member] | Oil Derivatives Production Period July 2016 - December 2016 [Member] | Put Sold [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 45 |
Volume (Bbls/d) | bbl | 1,000 |
Put Option [Member] | Oil Derivatives Production Period January 2017 - September 2017 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 46 |
Volume (Bbls/d) | bbl | 2,000 |
Put Option [Member] | Oil Derivatives Production Period January 2017 - September 2017 [Member] | Put Sold [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 38 |
Volume (Bbls/d) | bbl | 2,000 |
Put Option [Member] | Oil Derivatives Production Period January 2017 - December 2017 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 46 |
Volume (Bbls/d) | bbl | 2,000 |
Put Option [Member] | Oil Derivatives Production Period January 2017 - December 2017 [Member] | Put Sold [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 38 |
Volume (Bbls/d) | bbl | 2,000 |
Call Option [Member] | Natural Gas Derivatives Production Period July 2016 – December 2016 [Member] | Put Sold [Member] | Ceiling One [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 40,000 |
Weighted Average Price ($/MMBtu) | 3.24 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Sold [Member] | Ceiling One [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 50,000 |
Weighted Average Price ($/MMBtu) | 3.20 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Sold [Member] | Ceiling Two [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price ($/MMBtu) | 3.29 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Sold [Member] | Ceiling Three [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 3.03 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Sold [Member] | Ceiling Four [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 3.57 |
Call Option [Member] | Natural Gas Derivatives Production Period July 2016 – December 2017 [Member] | Put Sold [Member] | Ceiling [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 3.50 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2018 - December 2018 [Member] | Put Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 40,000 |
Weighted Average Price ($/MMBtu) | 3.75 |
Call Option [Member] | Oil Derivatives Production Period July 2016 - December 2016 [Member] | Put Sold [Member] | Ceiling [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 70.10 |
Volume (Bbls/d) | bbl | 1,000 |
Call Option [Member] | Oil Derivatives Production Period January 2017 - September 2017 [Member] | Put Sold [Member] | Ceiling [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 59.50 |
Volume (Bbls/d) | bbl | 2,000 |
Call Option [Member] | Oil Derivatives Production Period January 2018 - December 2018 [Member] | Put Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 50 |
Volume (Bbls/d) | bbl | 1,000 |
Call Option [Member] | Oil Derivatives Production Period January 2017 - December 2017 [Member] | Put Sold [Member] | Ceiling [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 60 |
Volume (Bbls/d) | bbl | 2,000 |
Derivative Instruments - Fair V
Derivative Instruments - Fair Value of Derivative Instruments on a Gross basis and on a Net Basis as Presented in Consolidated Balance Sheets (Detail) - Commodity Contract [Member] - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 | |
Derivatives, Fair Value [Line Items] | |||
Gross Amount | $ 4,822 | $ 45,793 | |
Netting Adjustments | [1] | (4,822) | (11,352) |
Net Amount Presented in Balance Sheets | 34,441 | ||
Gross Amount | (17,455) | (11,352) | |
Netting Adjustments | [1] | 4,822 | 11,352 |
Net Amount Presented in Balance Sheets | (12,633) | ||
Other Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 4,501 | 41,199 | |
Netting Adjustments | [1] | (4,501) | (8,158) |
Net Amount Presented in Balance Sheets | 33,041 | ||
Other Noncurrent Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 321 | 4,594 | |
Netting Adjustments | [1] | (321) | (3,194) |
Net Amount Presented in Balance Sheets | 1,400 | ||
Current Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (8,158) | ||
Netting Adjustments | [1] | 8,158 | |
Current Liabilities [Member] | Accrued Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (7,703) | ||
Netting Adjustments | [1] | 4,501 | |
Net Amount Presented in Balance Sheets | (3,202) | ||
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (9,752) | (3,194) | |
Netting Adjustments | [1] | 321 | $ 3,194 |
Net Amount Presented in Balance Sheets | $ (9,431) | ||
[1] | The Company has agreements in place that allow for the financial right to offset for derivative assets and derivative liabilities at settlement or in the event of a default under the agreements. |
Derivative Instruments - Summ32
Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on derivative instruments | $ (29,596) | $ (3,523) | $ (19,046) | $ 7,848 |
Commodity Contract [Member] | Gain (Loss) on Derivative Instruments [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain (loss) on derivative instruments | $ (29,596) | $ (3,523) | $ (19,046) | $ 7,848 |
Debt - Additional Information (
Debt - Additional Information (Detail) - USD ($) | Feb. 24, 2016 | Jul. 06, 2015 | Jun. 30, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jul. 13, 2015 | Mar. 31, 2014 |
Debt Instrument [Line Items] | |||||||
Debt instrument interest rate | 8.875% | 8.875% | |||||
Gain on early extinguishment of debt | $ 5,825,000 | $ 14,489,000 | $ 0 | ||||
Debt instrument, covenant description | The Indenture governing the Notes (the “Indenture”) contains covenants that, among other things, limit the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness, (ii) pay dividends on capital stock or redeem, repurchase or retire the Company’s capital stock or subordinated indebtedness, (iii) transfer or sell assets, (iv) make investments, (v) create certain liens, (vi) enter into agreements that restrict dividends or other payments to the Company from its restricted subsidiaries, (vii) consolidate, merge or transfer all or substantially all of the assets of the Company and its restricted subsidiaries, taken as a whole, (viii) engage in transactions with affiliates, and (ix) create unrestricted subsidiaries. | ||||||
Outstanding letters of credit | 27,800,000 | $ 27,800,000 | |||||
Outstanding borrowings | 0 | 0 | |||||
Revolving Credit Facility [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Revolving credit facility | $ 500,000,000 | ||||||
Borrowing base | 125,000,000 | 125,000,000 | |||||
Available capacity on the Revolving Credit Facility | 97,200,000 | $ 97,200,000 | |||||
Applicable Margin | 0.50% | ||||||
Percentage of additional mortgage to be delivered | 90.00% | ||||||
Additional Period for the effectiveness of amendment | 60 days | ||||||
Revolving Credit Facility [Member] | Minimum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fees on unused portion of revolving credit facility | 0.375% | ||||||
Revolving Credit Facility [Member] | Maximum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fees on unused portion of revolving credit facility | 0.50% | ||||||
12.0% Senior Unsecured PIK Notes Due 2018 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument interest rate | 12.00% | ||||||
Debt instrument repurchased amount | $ 510,700,000 | ||||||
Debt instrument, outstanding principal balance amount | 437,300,000 | ||||||
Debt instrument, premium amount | 47,600,000 | ||||||
Debt instrument, accrued interest amount | $ 25,800,000 | ||||||
Debt instrument, unamortized discount and deferred financing costs | $ 11,800,000 | ||||||
Gain on early extinguishment of debt | 59,400,000 | ||||||
Amortization of deferred financing costs and debt discount | 500,000 | 2,200,000 | |||||
8.875% Senior Unsecured Notes Due 2023 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument interest rate | 8.875% | ||||||
Debt instrument, outstanding principal balance amount | $ 550,000,000 | ||||||
Gain on early extinguishment of debt | 5,800,000 | 14,500,000 | |||||
Amortization of deferred financing costs and debt discount | 800,000 | 1,700,000 | |||||
Issuance date | Jul. 6, 2015 | ||||||
Notes issued percentage price | 97.903% | ||||||
Debt instrument, proceeds | $ 525,500,000 | ||||||
Debt instrument, fair value | 482,400,000 | 482,400,000 | |||||
Principal amount outstanding | 39,500,000 | 39,500,000 | |||||
8.875% Senior Unsecured Notes Due 2023 [Member] | Open Market [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument repurchased amount | 14,300,000 | 23,400,000 | |||||
8.875% Senior Unsecured Notes Due 2023 [Member] | Notes repurchased during 3 months ended June 30, 2016 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Principal amount outstanding | $ 21,000,000 | $ 21,000,000 |
Benefit Plans - Additional Info
Benefit Plans - Additional Information (Detail) - Defined Benefit Pension Plan [Member] $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | Jun. 30, 2016USD ($)Employee | Jun. 30, 2015USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Matching contribution by the company to the plan | 100.00% | |||
Percentage of employees' eligible compensation | 6.00% | |||
Company contribution to defined benefit plan recorded as compensation expense | $ | $ 0.1 | $ 0.3 | $ 0.4 | $ 0.5 |
Number of employees covered under defined benefit pension plan | 28 | |||
Retired Employee [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Number of employees covered under defined benefit pension plan | 2 | |||
Deferred Vested Termination [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Number of employees covered under defined benefit pension plan | 4 | |||
Survivor [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Number of employees covered under defined benefit pension plan | 1 |
Benefit Plans - Components of P
Benefit Plans - Components of Pension Benefit Cost (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended |
Jun. 30, 2015 | Jun. 30, 2015 | |
Defined Benefit Plan Net Periodic Benefit Cost [Abstract] | ||
Interest cost | $ 62 | $ 126 |
Expected return on plan assets | (82) | (164) |
Amortization of net loss | 25 | 43 |
Settlement costs | 96 | 96 |
Net periodic benefit cost | $ 101 | $ 101 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) $ in Millions | May 18, 2016Directorshares | May 11, 2015Directorshares | Oct. 07, 2014Directorshares | Jun. 30, 2016USD ($)shares | Jun. 30, 2015USD ($) | Jun. 30, 2016USD ($)shares | Jun. 30, 2015USD ($) |
May Two Thousand Fifteen [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted stock expense | $ 0.1 | $ 0.1 | $ 0.3 | $ 0.1 | |||
May Two Thousand Sixteen [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted stock expense | 0.1 | $ 0.1 | |||||
Restricted Stock [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Stock-based compensation awards, requisite service period | 3 years | ||||||
Restricted Stock [Member] | October Two Thousand Fourteen [Member] | Board of Directors [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted shares of common stock issued | shares | 31,115 | ||||||
Number of non employee directors | Director | 7 | ||||||
Stock based compensation expense | $ 0.1 | $ 0.2 | |||||
Restricted Stock [Member] | May Two Thousand Fifteen [Member] | Board of Directors [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted shares of common stock issued | shares | 132,496 | ||||||
Number of non employee directors | Director | 7 | ||||||
Restricted Stock [Member] | May Two Thousand Sixteen [Member] | Board of Directors [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Restricted shares of common stock issued | shares | 149,448 | ||||||
Number of non employee directors | Director | 3 | ||||||
Restricted Stock Units [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Stock-based compensation awards, requisite service period | 3 years | ||||||
Unrecognized compensation cost | 7.7 | $ 7.7 | |||||
Performance Units [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation cost | 4.3 | 4.3 | |||||
Restricted Stock Issued to Directors [Member] | May Two Thousand Sixteen [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Unrecognized compensation cost | $ 0.4 | $ 0.4 | |||||
2014 Long-Term Incentive Plan [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Number of shares authorized to be issue | shares | 16,000,000 | 16,000,000 | |||||
Number of shares are available for future grants | shares | 8,024,622 | 8,024,622 |
Stock-Based Compensation - Sche
Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | $ 2,226 | $ 1,410 | $ 3,701 | $ 2,157 |
Restricted Stock Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | 1,388 | 748 | 2,243 | 1,171 |
Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | 677 | 376 | 1,057 | 528 |
Restricted Stock Issued to Directors [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | 142 | 255 | 353 | 400 |
Incentive Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | $ 19 | $ 31 | $ 48 | $ 58 |
Stock-Based Compensation - Summ
Stock-Based Compensation - Summary of Restricted Stock and Restricted Stock Unit Awards Activity (Detail) - Restricted Stock Units [Member] $ / shares in Units, $ in Thousands | 6 Months Ended |
Jun. 30, 2016USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares, Beginning Balance | shares | 1,000,052 |
Number of shares, Granted | shares | 3,742,985 |
Number of shares, Vested | shares | (340,558) |
Number of shares, Forfeited | shares | (63,259) |
Number of shares, Ending Balance | shares | 4,339,220 |
Weighted average grant date fair value, Beginning Balance | $ / shares | $ 7.07 |
Weighted average grant date fair value, Granted | $ / shares | 1.36 |
Weighted average grant date fair value, Vested | $ / shares | 7.13 |
Weighted average grant date fair value, Forfeited | $ / shares | 7.13 |
Weighted average grant date fair value, Ending Balance | $ / shares | $ 2.14 |
Aggregate intrinsic value, Beginning Balance | $ | $ 1,820 |
Aggregate intrinsic value, Granted | $ | 0 |
Aggregate intrinsic value, Vested | $ | 0 |
Aggregate intrinsic value, Forfeited | $ | 0 |
Aggregate intrinsic value, Ending Balance | $ | $ 14,493 |
Stock-Based Compensation - Su39
Stock-Based Compensation - Summary of Performance Stock Unit Awards Activity (Detail) - Performance Units [Member] $ / shares in Units, $ in Thousands | 6 Months Ended |
Jun. 30, 2016USD ($)$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares, Beginning Balance | shares | 458,656 |
Number of shares, Granted | shares | 1,469,346 |
Number of shares, Vested | shares | 0 |
Number of shares, Forfeited | shares | 0 |
Number of shares, Ending Balance | shares | 1,928,002 |
Weighted average grant date fair value, Beginning Balance | $ / shares | $ 8.77 |
Weighted average grant date fair value, Granted | $ / shares | 1.60 |
Weighted average grant date fair value, Vested | $ / shares | 0 |
Weighted average grant date fair value, Forfeited | $ / shares | 0 |
Weighted average grant date fair value, Ending Balance | $ / shares | $ 3.31 |
Aggregate intrinsic value, Beginning Balance | $ | $ 417 |
Aggregate intrinsic value, Granted | $ | 0 |
Aggregate intrinsic value, Vested | $ | 0 |
Aggregate intrinsic value, Forfeited | $ | 0 |
Aggregate intrinsic value, Ending Balance | $ | $ 9,356 |
Equity - Additional Information
Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions | Jul. 05, 2016 | Jun. 28, 2016 | Jan. 28, 2015 | Dec. 27, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Number of shares issued and sold | 62,500,000 | |||
Stock price, per share | $ 3.50 | |||
Proceeds from issuance of Common Stock | $ 434 | |||
Shares Issued | 37,500,000 | |||
Subsequent Event [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Proceeds from initial public offering | $ 123 | |||
Private Placement [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock price, per share | $ 7.04 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Chairman President and Chief Executive Officer [Member] | ||||
Related Party Transaction [Line Items] | ||||
Flight charter services fees | $ 0.1 | $ 0.1 | $ 0.3 | $ 0.3 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016USD ($)a | Jun. 30, 2015USD ($) | Jun. 30, 2016USD ($)a | Jun. 30, 2015USD ($) | |
Loss Contingencies [Line Items] | ||||
Lease agreement period | 5 years | |||
Capitalized leasehold costs | $ | $ 0.6 | $ 0.6 | ||
Lease agreement, term | The Company leases office space under operating leases that expire between the years 2016 to 2025. | |||
Rent expense | $ | $ 0.4 | $ 0.2 | $ 0.6 | $ 0.4 |
Oxford acquisition [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 46,549 | 46,549 | ||
Oxford acquisition [Member] | Modification to Lease [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 27,770 | 27,770 | ||
Oxford acquisition [Member] | Unpredicted Modification to Lease [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 18,779 | 18,779 | ||
Other Lawsuit [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 157 | 157 |
Income Tax - Additional Informa
Income Tax - Additional Information (Detail) - USD ($) | 3 Months Ended | 12 Months Ended |
Jun. 30, 2016 | Dec. 31, 2016 | |
Real Estate Acquired Through Foreclosure Under Forward Purchase Agreements [Line Items] | ||
Federal statutory rate | 35.00% | |
Income taxes paid | $ 0 | |
Scenario, Forecast [Member] | ||
Real Estate Acquired Through Foreclosure Under Forward Purchase Agreements [Line Items] | ||
Percentage of annual effective income tax rate | 0.00% | |
Estimated valuation allowance | $ 40,100,000 |
Subsidiary Guarantors - Additio
Subsidiary Guarantors - Additional Information (Detail) | Jun. 30, 2016 |
Guarantees [Abstract] | |
Debt instrument interest rate | 8.875% |
Summary of Significant Accoun45
Summary of Significant Accounting Policies - Additional Information (Detail) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2016USD ($)$ / shares | Jun. 30, 2015USD ($)$ / shares | Jun. 30, 2016USD ($)Segment$ / shares | Jun. 30, 2015USD ($)$ / shares | Dec. 31, 2015USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||||
Accounts receivable | $ 25,485,000 | $ 25,485,000 | $ 27,476,000 | ||
Capitalized interest expense | 300,000 | $ 1,100,000 | $ 500,000 | $ 2,600,000 | |
Pension plan termination date | 2015-10 | ||||
Depreciation, depletion and amortization | $ 20,949,000 | $ 60,641,000 | $ 36,062,000 | 103,073,000 | |
Impairment of oil and gas properties | $ 17,665,000 | $ 0 | |||
Asset retirement obligations credit adjusted discount rates | 10.33% | 10.45% | |||
Number of operating segment | Segment | 1 | ||||
Decrease in accounts receivable | $ (1,238,000) | $ 13,007,000 | |||
Increase of net loss, per common share | $ / shares | $ (0.33) | $ (0.19) | $ (0.51) | $ (0.36) | |
Decrease in accrual for production and ad valorem taxes to be paid | $ 4,000,000 | ||||
Decrease of net loss, per common share | $ / shares | $ 0.02 | ||||
Natural Gas and NGLs [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Decrease in accounts receivable | $ (4,000,000) | $ (4,000,000) | |||
Increase in revenue from oil and natural gas | 1,500,000 | ||||
Increase in transportation, gathering and compression expense | 5,800,000 | ||||
Increase in net loss | $ 4,000,000 | $ 4,000,000 | |||
Increase of net loss, per common share | $ / shares | $ 0.02 | $ 0.02 | |||
Oil and Gas Properties [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Depreciation, depletion and amortization | $ 20,400,000 | $ 60,100,000 | $ 35,000,000 | $ 102,200,000 | |
Other property and equipment [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Depreciation | 500,000 | 500,000 | $ 1,000,000 | 800,000 | |
Other property and equipment [Member] | Minimum [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Property and equipment, expected lives | 5 years | ||||
Other property and equipment [Member] | Maximum [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Property and equipment, expected lives | 40 years | ||||
Proved Oil And Gas Properties [Member] | Utica Shale [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Impairment of oil and gas properties | 0 | 0 | $ 17,700,000 | 0 | |
Unproved Oil And Gas Properties [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Impairment of oil and gas properties | 9,400,000 | $ 4,400,000 | 18,700,000 | $ 6,000,000 | |
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Fair value of commodity derivative contracts, assets (liabilities) | (12,600,000) | (12,600,000) | 34,400,000 | ||
Unbilled Revenues [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Accounts receivable | $ 21,600,000 | $ 21,600,000 | $ 19,900,000 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 |
Oil and natural gas properties: | ||
Unproved properties | $ 684,383 | $ 720,159 |
Proved properties | 1,338,546 | 1,288,609 |
Gross oil and natural gas properties | 2,022,929 | 2,008,768 |
Less accumulated depreciation depletion and amortization | (1,075,477) | (1,022,771) |
Total oil and natural gas properties, net | 947,452 | 985,997 |
Other property and equipment | 11,169 | 10,753 |
Less accumulated depreciation | (3,746) | (2,782) |
Other property and equipment, net | 7,423 | 7,971 |
Total property and equipment, net | $ 954,875 | $ 993,968 |
Summary of Significant Accoun47
Summary of Significant Accounting Policies - Summary for Concentration of Receivables, Net of Allowances, By Product or Service (Detail) - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 |
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $ 25,485 | $ 27,476 |
Product Concentration Risk [Member] | Oil and Natural Gas and Related Products and Services [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 21,625 | 19,858 |
Product Concentration Risk [Member] | Joint Interest Owners [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 2,493 | 3,095 |
Product Concentration Risk [Member] | Derivatives [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 1,294 | $ 4,523 |
Product Concentration Risk [Member] | Miscellaneous Other [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $ 73 |
Summary of Significant Accoun48
Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | |
Asset Retirement Obligation [Abstract] | ||||
Asset retirement obligations, beginning of period | $ 3,401 | |||
Additional liabilities incurred | 63 | |||
Accretion | $ 89 | $ 399 | 175 | $ 785 |
Asset retirement obligations, end of period | $ 3,639 | $ 3,639 |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Fair Value Measured on a Recurring Basis (Detail) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Jun. 30, 2016 | Dec. 31, 2015 |
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | $ (12,633) | $ 34,441 |
Commodity Contract [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | (12,633) | 34,441 |
Level 2 [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | (12,633) | 34,441 |
Level 2 [Member] | Commodity Contract [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | $ (12,633) | $ 34,441 |