Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016 | Mar. 03, 2017 | Jun. 30, 2016 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | ECR | ||
Entity Registrant Name | Eclipse Resources Corp | ||
Entity Central Index Key | 1,600,470 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 262,239,559 | ||
Entity Public Float | $ 162 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 201,229 | $ 184,405 |
Accounts receivable | 43,638 | 27,476 |
Assets held for sale | 468 | 21,971 |
Other current assets | 4,295 | 35,532 |
Total current assets | 249,630 | 269,384 |
Oil and natural gas properties, successful efforts method: | ||
Unproved properties | 526,270 | 720,159 |
Proved oil and gas properties, net | 414,482 | 265,838 |
Other property and equipment, net | 6,748 | 7,971 |
Total property and equipment, net | 947,500 | 993,968 |
OTHER NONCURRENT ASSETS | ||
Other assets | 729 | 2,520 |
Deferred taxes | 540 | |
TOTAL ASSETS | 1,197,859 | 1,266,412 |
CURRENT LIABILITIES | ||
Accounts payable | 44,049 | 34,717 |
Accrued capital expenditures | 11,083 | 10,956 |
Accrued liabilities | 64,150 | 25,462 |
Accrued interest payable | 21,098 | 23,809 |
Liabilities held for sale | 245 | 18,898 |
Total current liabilities | 140,625 | 113,842 |
NONCURRENT LIABILITIES | ||
Debt, net of unamortized discount and debt issuance costs | 492,278 | 527,248 |
Asset retirement obligations | 4,806 | 3,401 |
Other liabilities | 13,434 | 1,367 |
Total liabilities | 651,143 | 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, 260,591,893 and 222,674,270 shares issued and outstanding, respectively | 2,607 | 2,227 |
Additional paid in capital | 1,958,731 | 1,829,082 |
Treasury stock, shares at cost; 72,704 shares at December 31, 2016 | (61) | |
Accumulated deficit | (1,414,561) | (1,210,755) |
Total stockholders' equity | 546,716 | 620,554 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ 1,197,859 | $ 1,266,412 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 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 | 260,591,893 | 222,674,270 |
Common stock, shares outstanding | 260,591,893 | 222,674,270 |
Treasury stock, shares | 72,704 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
REVENUES | |||
Natural gas, oil and natural gas liquids sales | $ 223,015 | $ 234,601 | $ 137,816 |
Brokered natural gas and marketing revenue | 12,019 | 20,720 | |
Total revenues | 235,034 | 255,321 | 137,816 |
OPERATING EXPENSES | |||
Lease operating | 9,023 | 13,904 | 8,518 |
Transportation, gathering and compression | 109,226 | 85,846 | 18,114 |
Production and ad valorem taxes | 4,998 | 11,621 | 7,084 |
Brokered natural gas and marketing expense | 12,268 | 26,173 | |
Depreciation, depletion and amortization | 92,948 | 244,750 | 89,218 |
Exploration | 52,775 | 116,211 | 21,186 |
General and administrative | 39,431 | 46,409 | 42,109 |
Rig termination and standby | 3,846 | 9,672 | 3,283 |
Impairment of proved oil and gas properties | 17,665 | 691,334 | 34,855 |
Accretion of asset retirement obligations | 391 | 1,623 | 791 |
(Gain) loss on sale of assets | 6,936 | (4,737) | (960) |
Gain on reduction of pension obligations | (2,208) | ||
Total operating expenses | 349,507 | 1,242,806 | 221,990 |
OPERATING LOSS | (114,473) | (987,485) | (84,174) |
OTHER INCOME (EXPENSE) | |||
Gain (loss) on derivative instruments | (52,338) | 56,021 | 20,791 |
Interest expense, net | (50,789) | (53,400) | (48,347) |
Gain (loss) on early extinguishment of debt | 14,489 | (59,392) | |
Other income (expense) | (149) | 400 | 353 |
Total other expense, net | (88,787) | (56,371) | (27,203) |
LOSS BEFORE INCOME TAXES | (203,260) | (1,043,856) | (111,377) |
INCOME TAX BENEFIT (EXPENSE) | (546) | 72,446 | (71,799) |
NET LOSS | $ (203,806) | $ (971,410) | $ (183,176) |
NET LOSS PER COMMON SHARE | |||
Basic and diluted | $ (0.84) | $ (4.46) | $ (1.27) |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING | |||
Basic and diluted | 241,434 | 217,897 | 144,369 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Loss - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Statement Of Income And Comprehensive Income [Abstract] | |||
NET LOSS | $ (203,806) | $ (971,410) | $ (183,176) |
Other comprehensive income (loss): | |||
Pension obligation adjustment, net of tax | 548 | (1,716) | |
TOTAL COMPREHENSIVE LOSS | $ (203,806) | $ (970,862) | $ (184,892) |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands | Total | IPO [Member] | Private Placement [Member] | Public Offering [Member] | Common Stock [Member] | Common Stock [Member]IPO [Member] | Common Stock [Member]Private Placement [Member] | Common Stock [Member]Public Offering [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member]IPO [Member] | Additional Paid-in Capital [Member]Private Placement [Member] | Additional Paid-in Capital [Member]Public Offering [Member] | Treasury Stock [Member] | Accumulated Deficit [Member] | Accumulated Other Comprehensive Income (Loss) [Member] |
Beginning Balances at Dec. 31, 2013 | $ 667,971 | $ 1,215 | $ 721,757 | $ (56,169) | $ 1,168 | ||||||||||
Beginning Balance, shares at Dec. 31, 2013 | 121,533,408 | ||||||||||||||
Capital contributions | 124,667 | $ 170 | 124,497 | ||||||||||||
Capital Contributions, shares | 16,966,592 | ||||||||||||||
Stock-based compensation | 256 | 256 | |||||||||||||
Shares of common stock issued, value | $ 544,709 | $ 215 | $ 544,494 | ||||||||||||
Shares of common stock issued, shares | 21,500,000 | ||||||||||||||
Issuance of restricted stock, shares | 31,115 | ||||||||||||||
Pension obligation adjustment, net of tax | (1,716) | (1,716) | |||||||||||||
Net loss | (183,176) | (183,176) | |||||||||||||
Ending Balances at Dec. 31, 2014 | 1,152,711 | $ 1,600 | 1,391,004 | (239,345) | (548) | ||||||||||
Ending Balance, shares at Dec. 31, 2014 | 160,031,115 | ||||||||||||||
Stock-based compensation | 4,635 | 4,635 | |||||||||||||
Shares of common stock issued, value | $ 434,070 | $ 625 | $ 433,445 | ||||||||||||
Shares of common stock issued, shares | 62,500,000 | ||||||||||||||
Issuance of restricted stock | $ 2 | (2) | |||||||||||||
Issuance of restricted stock, shares | 143,155 | ||||||||||||||
Pension obligation adjustment, net of tax | 548 | $ 548 | |||||||||||||
Net loss | (971,410) | (971,410) | |||||||||||||
Ending Balances at Dec. 31, 2015 | 620,554 | $ 2,227 | 1,829,082 | (1,210,755) | |||||||||||
Ending Balance, shares at Dec. 31, 2015 | 222,674,270 | ||||||||||||||
Stock-based compensation | 6,216 | 6,216 | |||||||||||||
Shares of common stock issued, value | $ 123,813 | $ 375 | $ 123,438 | ||||||||||||
Shares of common stock issued, shares | 37,500,000 | ||||||||||||||
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 | 268,175 | ||||||||||||||
Net loss | (203,806) | (203,806) | |||||||||||||
Ending Balances at Dec. 31, 2016 | $ 546,716 | $ 2,607 | $ 1,958,731 | $ (61) | $ (1,414,561) | ||||||||||
Ending Balance, shares at Dec. 31, 2016 | 260,591,893 |
Consolidated Statements of Sto7
Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Jun. 25, 2014 |
Statement Of Stockholders Equity [Abstract] | ||||
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Net loss | $ (203,806) | $ (971,410) | $ (183,176) |
Adjustments to reconcile net loss to net cash provided by operating activities | |||
Depreciation, depletion and amortization | 92,948 | 244,750 | 89,218 |
Exploration expense | 30,853 | 95,849 | 6,433 |
Pension benefit costs | 259 | 56 | |
Stock-based compensation | 6,216 | 4,635 | 256 |
Impairment of proved oil and gas properties | 17,665 | 691,334 | 34,855 |
Accretion of asset retirement obligations | 391 | 1,623 | 791 |
Gain on reduction of pension obligations | (2,208) | ||
(Gain) loss on derivative instruments | 52,338 | (56,021) | (20,791) |
Net cash receipts (payments) on settled derivatives | 38,696 | 37,074 | 564 |
Net cash payments on option premiums | (385) | ||
(Gain) loss on sale of assets | 6,936 | (4,737) | (960) |
Gain on sale of business | (400) | (353) | |
(Gain) loss on early extinguishment of debt | (14,489) | 59,392 | |
Deferred income taxes | 540 | (72,761) | 71,667 |
Interest not paid in cash | 1,232 | 15,721 | |
Amortization of deferred financing costs | 1,962 | 1,991 | 1,744 |
Amortization of debt discount | 1,362 | 1,886 | 2,308 |
Changes in operating assets and liabilities: | |||
Accounts receivable | (20,563) | 20,437 | (33,605) |
Other assets | (1,795) | 445 | (1,188) |
Accounts payable and accrued liabilities | (2,849) | 24,721 | 29,517 |
Accrued liabilities - affiliate | (1,951) | ||
Net cash provided by operating activities | 6,405 | 80,299 | 8,513 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Capital expenditures for oil and gas properties | (167,355) | (475,659) | (731,013) |
Capital expenditures for other property and equipment | (1,164) | (1,748) | (3,637) |
Proceeds from sale of assets | 79,201 | 40,139 | 15,460 |
Acquisition of business, net of cash acquired | 754 | ||
Net cash used in investing activities | (89,318) | (437,268) | (718,436) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Proceeds from issuance of long-term debt | 538,466 | ||
Debt issuance costs | 30 | (13,362) | (1,232) |
Repayments of long-term debt | (24,045) | (485,317) | (213) |
Capital contributions | 124,667 | ||
Proceeds from issuance of common stock | 124,361 | 440,000 | 550,025 |
Equity issuance costs | (548) | (5,930) | (5,316) |
Employee tax withholding for settlement of equity compensation awards | (61) | ||
Net cash provided by financing activities | 99,737 | 473,857 | 667,931 |
Net increase (decrease) in cash and cash equivalents | 16,824 | 116,888 | (41,992) |
Cash and cash equivalents at beginning of period | 184,405 | 67,517 | 109,509 |
Cash and cash equivalents at end of period | 201,229 | 184,405 | 67,517 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION | |||
Cash paid for interest | 48,483 | 39,808 | 26,020 |
Cash paid for income taxes | 505 | ||
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES | |||
Asset retirement obligations incurred, including changes in estimate | 1,014 | 3,435 | 7,554 |
Additions of other property through debt financing | 888 | 945 | |
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures | $ 8,583 | (142,665) | 126,656 |
Assets held for sale | (35,289) | 20,673 | |
Interest paid-in-kind | $ 14,786 | $ 22,461 |
Organization and Nature of Oper
Organization and Nature of Operations | 12 Months Ended |
Dec. 31, 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”) was formed on February 13, 2014, pursuant to the laws of the State of Delaware to become a holding company for Eclipse Resources I, LP (“Eclipse I”). Eclipse I is 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. On June 24, 2014, prior to the completion of the IPO (as such term is defined below), a corporate reorganization was completed. As a part of this corporate reorganization, the following transactions occurred (collectively, the “Corporate Reorganization”): • the acquisition by Eclipse I of all of the outstanding equity interests in Eclipse Resources Operating, LLC (“Eclipse Operating”); • the contribution of equity interests in Eclipse I to Eclipse Resources Holdings, L.P. (“Eclipse Holdings”) by its then limited partners in exchange for similar equity interests in Eclipse Holdings; • the transfer of the outstanding equity interests in Eclipse I GP, the general partner of Eclipse I, to Eclipse Holdings; and • the contribution of equity interests in Eclipse I and the outstanding equity interests in Eclipse I GP, LLC, to the Company by Eclipse Holdings in exchange for 138,500,000 shares of common stock. As a result of the Corporate Reorganization, the Company became a majority controlled direct subsidiary of Eclipse Holdings, and Eclipse I became a direct subsidiary of the Company. Each of the transactions that occurred as part of the Corporate Reorganization have been accounted for as a reorganization of entities under common control, with the exception of the acquisition of the outstanding equity interests of Eclipse Operating by Eclipse I, which has been accounted for as a business combination using the acquisition method (See “Note 4 —Acquisitions” On June 25, 2014, the Company completed the initial public offering (“IPO”) of 30,300,000 shares of $0.01 par value common stock, which included 21,500,000 shares sold by the Company and 8,800,000 shares sold by certain selling stockholders. The gross proceeds to the Company and selling stockholders were approximately $818.1 million, which resulted in net proceeds to the Company of approximately $544.7 million after deducting expenses and underwriting discounts and commissions of approximately $35.8 million. The Company did not receive any proceeds from the sale of the shares by the certain selling stockholders. The net proceeds from the IPO were used to repay all of the then outstanding borrowings under the revolving credit facility and the Company used the remaining net proceeds to fund a portion of the capital expenditure plan and general corporate matters. |
Basis of Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Note 2—Basis of Presentation The accompanying consolidated financial statements of Eclipse Resources Corporation for the period from January 1, 2014 through June 23, 2014, as contained within the year ended December 31, 2014 pertain to the historical financial statements and results of operations of Eclipse Resources I, LP, our accounting predecessor. In February 2014, Eclipse Resources Corporation was formed as a Delaware corporation for the purpose of becoming a publicly traded company and the holding company of Eclipse I. The historical financial information contained in this report relates to periods that ended prior to the completion of the IPO of Eclipse Resources Corporation. In connection with the completion of the corporate reorganization on June 24, 2014, Eclipse Resources Corporation became a holding company whose sole material asset consists of a 100% indirect ownership interest in Eclipse I. As the sole managing member of Eclipse I, Eclipse Resources Corporation is responsible for all operational, management and administrative decisions relating to Eclipse I. Accordingly, this reorganization constituted a common control transaction and the accompanying consolidated financial statements are presented as though this reorganization had occurred for the earliest period presented herein. The accompanying consolidated financial statements are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”). All significant intercompany accounts have been eliminated in consolidation. 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. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 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 party. The Company did not deem any of its accounts receivables to be uncollectable as of December 31, 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 which are, in turn, based upon applicable product prices. The Company had $41.4 million and $19.9 million of accrued revenues, net of expenses at December 31, 2016 and December 31, 2015, respectively, which were included in accounts receivable within the Company’s 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 consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s 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 consolidated statements of operations. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s consolidated statements of operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. 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): December 31, 2016 December 31, 2015 Oil and natural gas properties: Unproved $ 526,270 $ 720,159 Proved 1,545,860 1,288,609 Gross oil and natural gas properties 2,072,130 2,008,768 Less accumulated depreciation depletion and amortization (1,131,378 ) (1,022,771 ) Oil and natural gas properties, net 940,752 985,997 Other property and equipment 11,447 10,753 Less accumulated depreciation (4,699 ) (2,782 ) Other property and equipment, net 6,748 7,971 Property and equipment, net $ 947,500 $ 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 $1.1 million, $2.8 million and $9.1 million for the years ended December 31, 2016, 2015, and 2014, 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) Accrued Liabilities A summary of accrued liabilities is as follows (in thousands): December 31, 2016 December 31, 2015 Ad valorem and production taxes $ 13,625 $ 14,231 Employee compensation 4,257 6,628 Royalties 8,557 3,196 Short term derivatives 35,409 — Other 2,302 1,407 Total accrued liabilities $ 64,150 $ 25,462 (e) 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 or 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 had no material imbalances as of December 31, 2016 and 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 report them within one operating segment. (f) Major Customers The Company sells production volumes to various purchasers. For the years ended December 31, 2016, 2015, and 2014, there were four, four and two customers, respectively, that accounted for 10% or more of the total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the Year Ended December 31, 2016 2015 2014 Purchaser Antero Resources Corporation 14 % 19 % 47 % ARM Energy Management — 11 % 25 % Concord Energy, LLC 12 % — — Enlink Midstream Operating 17 % 21 % — Sequent Energy Management 20 % 19 % — Total 63 % 70 % 72 % Management believes that the loss of any one customer would not have a material adverse effect on the Company’s ability to sell natural gas, NGLs and oil production because it believes that there are potential alternative purchasers although it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers. (g) Concentration of Credit Risk The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2016 and December 31, 2015 (in thousands): December 31, 2016 December 31, 2015 Receivables by product or service: Sale of oil and natural gas and related products and services $ 41,398 $ 19,858 Joint interest owners 2,065 3,095 Derivatives 122 4,523 Other 53 — Total $ 43,638 $ 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, it is the Company’s policy 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 commodity unsettled derivative contracts was a net liability position of ($48.1) million and a net asset position of $34.4 million at December 31, 2016 and 2015, respectively. Other than as provided by the 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 they required to provide credit support to the Company. As of December 31, 2016, the Company did not have past-due receivables from or payables to any of the counterparties. (h) 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 included a pension benefit plan that required the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension liability of $2.2 million for the year ended December 31, 2014. The Company’s pension plan was terminated in October 2015 and lump sum payments were made in final settlement to all remaining participants. (i) 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 for the years ended December 31, 2016, 2015, and 2014 totaled approximately $91.0 million, $242.9 million and $88.4 million, respectively. Through September 30, 2014, the Company calculated depletion of proved properties at the individual unit level. Effective October 1, 2014, the Company changed its estimate for calculating depletion expense of proved properties to be performed at the field level consistent with the assessment for impairment of proved property costs. 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 for the years ended December 31, 2016, 2015, and 2014 totaled approximately $1.9 million, $1.8 million and $0.8 million, respectively. This amount is included in DD&A expense in the consolidated statements of operations. (j) 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. During the year ended December 31, 2014, the Company changed its estimate for assessing impairment of proved property costs. Through September 30, 2014, such assessments were performed at the individual unit level. Effective October 1, 2014, assessment for impairment of proved properties is performed at the field level, which for the Company currently consists of two fields, including the Utica Shale and the Marcellus Shale. With the increase in the Company’s activity level, this change will result in a more appropriate identification of cash flows utilized in the assessment of recoverability of proved properties as additional units are placed into production, resulting in increased sharing of revenues and costs across units related to infrastructure, equipment, and fulfillment of sales and transportation contracts. The review 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 year ended December 31, 2016 relating to proved properties in the Marcellus Shale, $691.3 million for the year ended December 31, 2015 relating to proved properties in the Utica Shale, and $34.9 million for the year ended December 31, 2014, of which approximately $30.9 million related to the Company’s Conventional properties. As discussed in Note 5, the Company completed the sale of its Conventional properties during the year ended December 31, 2016. The aforementioned impairment charges 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 oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. 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 $29.8 million, $95.6 million, and $5.7 million for the years ended December 31, 2016, 2015, and 2014, respectively. These costs are included in exploration expense in the consolidated statements of operations. (k) Income Taxes The Company accounts for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases 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. Upon the closing of the Corporate Reorganization, the Company owns 100% of Eclipse I, Eclipse Resources-Ohio, LLC and Eclipse Operating. Eclipse I was a limited partnership not subject to federal income taxes before the Corporate Reorganization. However, in connection with the closing of the Corporate Reorganization, the Company became a corporation subject to federal and state income tax and, as such, the Company’s future income taxes will be dependent upon its future taxable income. The change in tax status requires the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately $97.6 million was recorded as income tax expense in the consolidated statements of operations for the year ended December 31, 2014. ASC Topic 740 “ Income Taxes (l) 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. (m) 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 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 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 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. (n) Asset Retirement Obligation The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 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 period indicated (in thousands): Year Ended December 31, 2016 December 31, 2015 December 31, 2014 Asset retirement obligations, beginning of period $ 3,401 $ 17,400 $ 9,055 Liabilities associated with assets held for sale — (19,057 ) — Revisions of prior estimates — 2,913 6,470 Additional liabilities incurred 1,014 522 1,084 Accretion 391 1,623 791 Asset retirement obligations, end of period $ 4,806 $ 3,401 $ 17,400 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. (o) Lease Obligations The Company leases office space under an operating lease that expires in 2024. 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. (p) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. (q) 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. (r) 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. (s) Recent Accounting Pronouncements Recently Adopted In August 2014, the FASB issued Accounting Standards Update No. 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 and interim periods ending after December 15, 2016, with early adoption permitted. The Company adopted this standard for the year ended December 31, 2016 with no significant impact on the Company’s financial statement 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 with early adoption permitted. The Company adopted this standard for the year ended December 31, 2016 with no significant impact on the Company’s financial position, results of operation, or related disclosures. Accounting Pronouncements Not Yet Adopted The FASB issued ASU 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 with early adoption permitted. The Company plans to adopt this standard effective January 1, 2018 and is currently evaluating its transition method. As part of the implementation process, the Company is currently assessing the impact of the new requirements on its internal systems and policies, which involves reviewing all existing contracts. The Company does not expect this standard to have a significant impact on its financial position or results of operations but will require that the Company’s revenue recognition policy disclosures include further detail regarding its performance obligations as to the nature, amount, timing and estimates of revenue and cash flows generated from the Company’s contracts with customers. The Company continues to monitor relevant industry guidance regarding implementation of the standard and adjust its implementation strategies as necessary. 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 with early adoption permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. (t) Cash Flow Revision The Company previously revised the presentation of delay rentals and geological and geophysical costs within the consolidated statements of cash flows for the year ended December 31, 2014. Previously, such costs had been presented as cash outflows from investing activities; however, U.S. GAAP requires such costs to be presented as cash outflows from operating activities. This revision resulted in a reduction to cash flows provided by operating activities and a corresponding reduction to cash flows used in investing activities of approximately $14.8 million for the year ended December 31, 2014, compared to the previously reported amount. The Company evaluated the materiality of this revision on both a quantitative and qualitative basis under the guidance of ASC 250—Accounting Changes and Error Corrections and determined that it did not have a material impact to previously issued financial statements. (u) Change in Estimates During the year ended December 31, 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 a |
Acquisition
Acquisition | 12 Months Ended |
Dec. 31, 2016 | |
Business Combinations [Abstract] | |
Acquisition | Note 4—Acquisition Eclipse Resources Operating, LLC Acquisition On June 24, 2014, prior to the closing of the IPO, the Company acquired all of the outstanding equity interests of Eclipse Operating for total consideration of $0.1 million. The fair value of the net assets acquired, consisting primarily of cash, accounts receivable, property and equipment, accounts payable and accrued liabilities exceeded the purchase price paid. As a result, the Company recognized a gain of $0.4 million related to the purchase, which is included in other income on the consolidated statements of operations. |
Sale of Oil and Natural Gas Pro
Sale of Oil and Natural Gas Property Interests | 12 Months Ended |
Dec. 31, 2016 | |
Discontinued Operations And Disposal Groups [Abstract] | |
Sale of Oil and Natural Gas Property Interests | Note 5—Sale of Oil and Natural Gas Property Interests Asset Sales During the year ended December 31, 2014, the Company sold a central processing facility for proceeds of $16.8 million, of which $15.5 million had been received by December 31, 2014. The proceeds exceeded the Company’s cost basis in the facility, resulting in a gain of approximately $1.0 million during 2014. During the year ended December 31, 2015, the Company sold a second central processing facility and certain pipelines. The transaction resulted in proceeds of $36.0 million and a gain on sale of assets of $4.8 million, which was recorded during the year ended December 31, 2015. These assets were classified as assets held for sale as of December 31, 2014. Additional pipeline assets were sold during the year ended December 31, 2015, which resulted in proceeds of approximately $2.8 million and a loss on sale of assets of approximately $0.1 million. During the year ended December 31, 2016, the Company completed the sale of its Conventional oil and gas properties and related equipment for approximately $4.7 million. As of December 31, 2015, the Company was actively negotiating the sale of these assets and the costs related to these properties of approximately $21.8 million and corresponding asset retirement obligations of approximately $19.1 million were classified as held for sale in the consolidated balance sheets as of December 31, 2015. In addition, approximately $0.2 million of pipeline assets were classified as held for sale as of December 31, 2015. As a result of this sale, the Company recognized a gain of approximately $1.1 million. During the year ended December 31, 2016, the Company sold additional pipeline assets, which resulted in proceeds of approximately $0.4 million and a loss of less than $0.1 million. During the year ended December 31, 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 gas properties. During the year ended December 31, 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 gas properties. During the year ended December 31, 2016, the Company received approximately $63.8 million from a completed asset sale with a third party totaling approximately 9,900 acres. As a result of this sale, the Company recognized a loss of approximately $7.6 million. Acreage Trades During the year ended December 31, 2015, the Company completed acreage trades with various working interest owners totaling approximately 10,500 acres. The exchanges were accounted for at net book value, with no gain or loss recognized. One of the trades involved the exchange of approximately 7,000 acres and the Company received a credit of $17.5 million related to reimbursement of capital expenditures, which was recorded as a reduction of oil and natural gas properties. No other trades involved more than 1,500 acres and no significant cash was paid or received related to these other trades. During the year ended December 31, 2016, the Company received approximately $1.6 million from completed acreage trades with various working interest owners totaling approximately 249.5 acres. No gain or loss was recognized for this transaction, which was recorded as a reduction of oil and gas properties. |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Note 6—Derivative Instruments Commodity derivatives The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter (“OTC”) fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes. The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of December 31, 2016, the Company’s derivative instruments were with Bank of Montreal, Citibank, N.A., Key Bank, N.A, Morgan Stanley and Goldman Sachs. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of December 31, 2016, for future production periods: Natural Gas Derivatives Description Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Swaps: 10,000 January 2017 – December 2017 $ 2.98 10,000 March 2017 – December 2017 $ 3.21 Natural Gas Collars: Floor purchase price (put) 130,000 January 2017 – December 2017 $ 2.85 Ceiling sold price (call) 130,000 January 2017 – December 2017 $ 3.24 Floor purchase price (put) 20,000 January 2017 – December 2018 $ 2.90 Ceiling sold price (call) 20,000 January 2017 – December 2018 $ 3.25 Floor purchase price (put) 40,000 January 2018 – December 2018 $ 2.75 Ceiling sold price (call) 40,000 January 2018 – December 2018 $ 3.27 Natural Gas Three-way Collars: Floor purchase price (put) 30,000 January 2017 – December 2017 $ 2.75 Ceiling sold price (call) 30,000 January 2017 – December 2017 $ 3.57 Floor sold price (put) 30,000 January 2017 – December 2017 $ 2.25 Floor purchase price (put) 30,000 April 2017 – March 2019 $ 3.00 Ceiling sold price (call) 30,000 April 2017 – March 2019 $ 3.40 Floor sold price (put) 30,000 April 2017 – March 2019 $ 2.20 Floor purchase price (put) 80,000 January 2018 – December 2018 $ 2.90 Ceiling sold price (call) 80,000 January 2018 – December 2018 $ 3.31 Floor sold price (put) 80,000 January 2018 – December 2018 $ 2.12 Floor purchase price (put) 20,000 October 2017 – December 2018 $ 2.90 Ceiling sold price (call) 20,000 October 2017 – December 2018 $ 3.50 Floor sold price (put) 20,000 October 2017 – December 2018 $ 2.20 Natural Gas Call/Put Options: Call sold 40,000 January 2018 – December 2018 $ 3.75 Call sold 10,000 January 2019 – December 2019 $ 4.75 Basis Swaps: TCO - Columbia 20,000 January 2017 – December 2017 $ (0.19 ) Oil Derivatives Description Volume (Bbls/d) Production Period Weighted Price Oil Swaps: Floor purchase price (put) 2,000 January 2017 – September 2017 $ 46.00 Ceiling sold price (call) 2,000 January 2017 – September 2017 $ 59.50 Floor sold price (put) 2,000 January 2017 – September 2017 $ 38.00 Floor purchase price (put) 2,000 January 2017 – December 2017 $ 46.00 Ceiling sold price (call) 2,000 January 2017 – December 2017 $ 60.00 Floor sold price (put) 2,000 January 2017 – December 2017 $ 38.00 Oil Call/Put Options: Call sold 1,000 January 2018 – December 2018 $ 50.00 NGL Derivatives Description Volume (Gal/d) Production Period Weighted Average Price ($/Gal) Propane Swaps: 84,000 January 2017 – December 2017 $ 0.60 Fair values and gains (losses) The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes. As of December 31, 2016 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 50 $ (50 ) $ — Commodity derivatives - noncurrent — — — Total assets $ 50 $ (50 ) $ — Liabilities Commodity derivatives - current $ (35,459 ) $ 50 $ (35,409 ) Accrued liabilities Commodity derivatives - noncurrent (12,673 ) — (12,673 ) Other liabilities Total liabilities $ (48,132 ) $ 50 $ (48,082 ) As of December 31, 2015 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 41,199 $ (8,158 ) $ 33,041 Other current assets Commodity derivatives - noncurrent 4,594 (3,194 ) 1,400 Other assets Total assets $ 45,793 $ (11,352 ) $ 34,441 Liabilities Commodity derivatives - current $ (8,158 ) $ 8,158 $ — Commodity derivatives - noncurrent (3,194 ) 3,194 — Total liabilities $ (11,352 ) $ 11,352 $ — (a) 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. The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the consolidated statements of operations for the periods presented (in thousands): Years Ended December 31, Location of Gain (Loss) 2016 2015 2014 Commodity derivatives Gain (Loss) on derivative instruments $ (52,338 ) $ 56,021 $ 20,791 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 7—Fair Value Measurements Fair Value Measurement on a Recurring Basis The following table presents, by level within the fair value hierarchy, the Company’s assets and liabilities that are measured at fair value on a recurring basis. The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the nature of the instrument and/or the short-term maturity of these instruments. The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are readily available in the public market, such as natural gas forward curves. These values are compared to the values given by counterparties for reasonableness. Since natural gas swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. Level 1 Level 2 Level 3 Total As of December 31, 2016: (in thousands) Commodity derivative instruments $ — $ (48,082 ) $ — $ (48,082 ) Total $ — $ (48,082 ) $ — $ (48,082 ) As of December 31, 2015: (in thousands) Commodity derivative instruments $ — $ 34,441 $ — $ 34,441 Total $ — $ 34,441 $ — $ 34,441 Nonfinancial Assets and Liabilities Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and natural gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s AROs. 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 the Company’s ARO represent a nonrecurring Level 3 measurement. (See Note 3(n)). The Company reviews its proved oil and natural gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates and other relevant data. As such, the fair value of oil and natural gas properties used in estimating impairment represents a nonrecurring Level 3 measurement. (See Note 3(j)). The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See “Note 8— Debt |
Debt
Debt | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Debt | Note 8—Debt 12.0% Senior Unsecured PIK Notes Due 2018 On June 26, 2013, the Company completed a private placement offering of an initial aggregate principal amount of $300 million, with an additional $100 million notes option, at the discretion of the Company, of 12% Senior Unsecured PIK notes due in 2018 (the “12.0% Senior PIK notes”). The 12.0% Senior PIK notes were issued at 96% of par and the Company received $280.7 million of net cash proceeds, after deducting the discount to initial purchasers of $12 million and offering expenses of $7.3 million. In December 2013, the Company exercised its option and issued an additional $100 million of 12.0% Senior PIK notes with the same terms, at par. The Company received $100 million net cash proceeds, as no discounts and $0.2 million of offering expenses were incurred in connection with the exercise of the option. The Company redeemed all of the outstanding balance of the 12.0% Senior PIK notes on July 13, 2015 for approximately $510.7 million, including outstanding principal balance of $437.3 million, a make-whole premium of $47.6 million, and accrued interest of $25.8 million. The make-whole premium plus unamortized discount and deferred financing costs of $11.8 million were charged to loss on early extinguishment of debt, totaling $59.4 million. The amount paid for the make-whole premium has been included as a financing activity in the consolidated statement of cash flows. Prior to the redemption of these notes, the Company amortized $1.9 million and $4.1 million of deferred financing costs and debt discount to interest expense using the effective interest method for the years ended December 31, 2015 and 2014, respectively. 8.875% Senior Unsecured Notes Due 2023 On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% Senior Unsecured Notes due 2023 at an issue price of 97.903% of principal amount of the notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the senior unsecured notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside of the United States in compliance with Rule S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers discounts and offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding 12.0% Senior PIK notes. The Company used the remaining proceeds to fund its capital expenditure plan and for general corporate purposes. The fair value of the senior unsecured notes at December 31, 2016 was approximately $533.1 million. During the years ended December 31, 2016 and December 31, 2015, the Company amortized $3.3 million and $1.5 million, respectively, of deferred financing costs and debt discount to interest expense using the effective interest method. The indenture governing the senior unsecured notes 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. These covenants are subject to a number of important exceptions and qualifications set forth in the indenture. In addition, if the senior unsecured notes achieve an investment grade rating from either Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services, and no default under the indenture has then occurred and is continuing, many of such covenants will be suspended. The indenture also contains events of default, which include, among others and subject in certain cases to grace and cure periods, nonpayment of principal or interest, failure by the Company to comply with its other obligations under the indenture, payment defaults and accelerations with respect to certain other indebtedness of the Company and its restricted subsidiaries, failure of any guarantee on the senior unsecured notes to be enforceable, and certain events of bankruptcy or insolvency. The Company was in compliance with all applicable covenants in the indenture at December 31, 2016. During the year ended December 31, 2016, the Company repurchased $39.5 million of the outstanding senior unsecured notes in open market purchases for $23.4 million. The principal of the outstanding senior unsecured notes that were repurchased less cash proceeds and unamortized debt discount and deferred financing costs were charged to gain on early extinguishment of debt, totaling $14.5 million for the year ended December 31, 2016. The Company repurchased all such senior unsecured notes with cash on hand. Revolving Credit Facility During the first quarter of 2014, the Company entered into a $500 million senior secured revolving bank credit facility (the “revolving credit facility”) that matures in 2018. Borrowings under the revolving credit facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations (April and October). The revolving credit facility was amended and restated on January 12, 2015. The primary change effected by the Amendment was to add Eclipse Resources Corporation as a party to the revolving credit facility and thereby subject the Company to the representations, warranties, covenants and events of default provisions thereof. Relative to the Eclipse I’s previous credit agreement, the Credit Agreement also (i) requires financial reporting regarding, and tests financial covenants with respect to, Eclipse Resources Corporation rather than Eclipse I, (ii) increases the basket sizes under certain of the negative covenants, and (iii) includes certain other changes favorable to Eclipse I. Other terms of the Credit Agreement remain generally consistent with Eclipse I’s previous credit agreement. On February 24, 2016, the Company amended its revolving credit facility to, among other things, adjust the 10Q quarterly minimum interest coverage ratio, which is the ratio of EBITDAX to Cash Interest Expense, and to a leverage ratio of Net Debt to EBITDAX and to permit the sale of certain conventional properties. The amendment to the revolving credit facility also increases the Applicable Margin (as defined in the Credit Agreement) applicable to loans and letter of credit participation fees under the Credit Agreement by 0.5% and requires the Company to, within 60 days of the effectiveness of the amendment, execute and deliver additional mortgages on the oil and gas properties that include at least 90% of the proved reserves. At December 31, 2016, the borrowing base was $125 million and the Company had no outstanding borrowings. After giving effect to outstanding letters of credit issued by the Company totaling $34.5 million, the Company had available borrowing capacity under the revolving credit facility of $90.5 million at December 31, 2016. On February 24, 2017, the borrowing base was redetermined, which increased the borrowing base to $175 million, while extending the maturity of the credit facility to January of 2020. The Company’s available borrowing capacity under the revolving credit facility is now $140.5 million. The Company’s next scheduled borrowing base redetermination is expected to be completed by October 2017. The revolving credit facility is secured by mortgages on substantially all of the Company’s properties and guarantees from the Company’s operating subsidiaries. The revolving credit facility contains certain covenants, including restrictions on indebtedness and dividends, and requirements with respect to working capital and interest coverage ratios. Interest is payable at a variable rate based on LIBOR or the prime rate based on the Company’s election at the time of borrowing. The Company was in compliance with all applicable covenants under the revolving credit facility as of December 31, 2016. Commitment fees on the unused portion of the revolving credit facility are due quarterly at 0.05% of the unused facility based on utilization. |
Benefit Plans
Benefit Plans | 12 Months Ended |
Dec. 31, 2016 | |
Compensation And Retirement Disclosure [Abstract] | |
Benefit Plans | Note 9—Benefit Plans Defined Contribution Plan The Company currently maintains a retirement plan intended to provide benefits under section 401(K) of the Internal Revenue Code, under which employees are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under the 401(K) plan, the Company provides matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan. The Company recorded compensation expense of $0.7 million, $0.9 million and $0.4 million related to matching contributions, classified under general and administrative, for the years ended December 31, 2016, 2015, and 2014, respectively. Defined Benefit Plan The Company maintained a defined benefit pension plan until October 2015. The plan covered 28 employees, of which two were retired, four had deferred vested termination, and one was a survivor. Benefits were based on the employees’ years of service and compensation. As a result of the Oxford Acquisition (refer to “Note 4” above) on June 26, 2013, the Company assumed the defined benefit pension plan, and therefore, no pension benefit plan was in effect prior to such date. Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension liability of $2.2 million for the year ended December 31, 2014. The plan was terminated during October 2015 and lump sum payments were made to the remaining participants. The authoritative guidance for defined benefit pension plans requires an employer to recognize the overfunded or underfunded status as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income. A summary of the pension benefit obligation as of the year ended December 31, 2015 is set forth in the below tables (in thousands): 2015 Change in benefit obligation Benefit obligation at beginning of year $ 6,800 Service cost — Interest cost 239 Gain on reduction of pension liability — Actuarial (gain) loss (775 ) Benefits paid (6,264 ) Benefit obligation at end of period $ — Change in plan assets Fair value of plan assets at beginning of year $ 5,479 Actual return on plan assets 14 Employer contributions 771 Benefit paid (6,264 ) Fair value of plan assets at end of period $ — The funding level of the qualified pension plan was in compliance with standards set by applicable law or regulation. The plan was terminated during October 2015. 2015 Beginning amount recorded in other accumulated comprehensive income (loss) $ (548 ) Amounts recorded in accumulated other comprehensive income (loss) consist of: Pension obligation adjustment, net of tax 548 Total recorded in accumulated other comprehensive income $ — The long-term expected rate of return on funded assets shown below was established for the benefit plan by developing a forward-looking, long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return was then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. The discount rate was determined by constructing a portfolio of high-quality, noncallable bonds with cash flows that match estimated outflows for benefit payments. For the Year Ended December 31, 2015 2014 Components of net periodic benefit cost (in thousands) Service cost $ — $ 70 Interest cost 239 335 Expected return on plan assets (246 ) (448 ) Amortization of transition obligation — 70 Amortization of net (gain) loss 42 29 Effect of settlement 224 — Net period benefit cost $ 259 $ 56 |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Stock-Based Compensation | Note 10—Stock-Based Compensation The Company is authorized to grant up to 16,000,000 shares of common stock under its 2014 Long-Term Incentive Plan (the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 8,019,938 shares are available for future grant under the Plan as of December 31, 2016. Our stock based compensation expense is as follows for the years ended December 31, 2016, 2015, and 2014 (in thousands): Year Ended December 31, 2016 2015 2014 Restricted stock units $ 4,006 $ 2,408 $ — Performance units 1,922 1,297 — Restricted stock issued to directors 556 827 138 Incentive units (268 ) 103 118 Total expense $ 6,216 $ 4,635 $ 256 Restricted Stock Units Restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock and restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of December 31, 2016, there was $5.0 million of total unrecognized compensation cost related to restricted stock units. The weighted average period for the shares to vest is approximately 1 year. A summary of restricted stock unit awards activity during the year ended December 31, 2016 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2015 1,000,052 $ 7.07 $ 1,820 Granted 3,751,931 1.36 Vested (340,879 ) 7.13 Forfeited (67,522 ) 7.13 Total awarded and unvested, December 31, 2016 4,343,582 $ 2.14 $ 11,597 Performance Units Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of December 31, 2016, there was $3.1 million of total unrecognized compensation cost related to performance units. The weighted average period for the shares to vest is approximately 2 years. A summary of performance stock unit awards activity during the year ended December 31, 2016 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2015 458,656 $ 8.77 $ 417 Granted 1,469,346 1.60 Vested — — Forfeited — — Total awarded and unvested, December 31, 2016 1,928,002 $ 3.31 $ 5,148 The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s public peer group. Restricted Stock Issued to Directors On October 7, 2014, the Company issued an aggregate of 31,115 restricted shares of common stock to its seven non-employee members of its Board of Directors, which became fully vested on June 25, 2015. For the years ended December 31, 2015 and 2014, the Company recognized expense of approximately $0.3 million and $0.1 million, respectively, related to these awards. On May 11, 2015, the Company issued an aggregate of 132,496 restricted shares of common stock to its seven non-employee members of its Board of Directors, which became fully vested on May 11, 2016. For the years ended December 31, 2016 and 2015, the Company recognized expense of approximately $0.3 million and $0.6 million, respectively, related to these awards. On May 18, 2016, the Company issued an aggregate of 149,448 restricted shares of common stock to its three non-employee members of its Board of Directors that are not affiliated with the Company’s controlling stockholder, which are scheduled to fully vest on May 18, 2017. For the year ended December 31, 2016, the Company recognized expense of approximately $0.3 million related to these awards. As of December 31, 2016, there was approximately $0.2 million of total unrecognized compensation cost related to outstanding restricted stock issued to the Company’s Directors. |
Equity
Equity | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Equity | Note 11—Equity Initial Public Offering On June 25, 2014, the Company completed its initial public offering (“IPO”) of 30,300,000 shares of common stock, which included 21,500,000 shares sold by the Company and 8,800,000 shares sold by certain stockholders. The net proceeds from the IPO were approximately $544.7 million, after deducting underwriting discounts and commissions and the offering expenses payable by the Company of approximately $35.8 million. The Company used a portion of the net proceeds received from the IPO to repay the then-outstanding borrowings under Eclipse I’s revolving credit facility and to fund the Company’s capital expenditure plan. Private Placement of Common Stock On December 27, 2014, the Company entered into a Securities Purchase Agreement with private equity funds managed by EnCap Investments L.P., entities controlled by certain members of the Company’s management team and certain other institutional investors pursuant to which the Company issued and sold to such purchasers an aggregate of 62,500,000 shares of common stock at a price of $7.04 per share pursuant to the exemptions from registration provided in Rule 506 of Regulation D promulgated under Section 4(2) of the Securities Act (the “Private Placement”). On January 28, 2015, the Company closed the Private Placement and received net proceeds of approximately $434 million (after deducting placement agent commissions and estimated expenses), which the Company intends to use to fund its capital expenditure plan and for general corporate purposes. Upon the closing of the Private Placement, the Company amended and restated the existing registration rights agreement that was entered into upon the closing of its IPO in order to provide the purchasers with certain registration rights with respect to the stock they purchased in the Private Placement. The Company completed the registration of the shares during the third quarter of 2015. Public Offering of Common Stock On June 28, 2016, the Company commenced an underwritten public offering of 37,500,000 shares of common stock, which was priced at $3.50 per share. The Company closed the offering on July 5, 2016 and received net proceeds of approximately $123.8 million (after deducting underwriting discounts and commissions and estimated expenses), which the Company used to fund its capital expenditure plan and for general corporate purposes. |
Earnings (Loss) Per Share
Earnings (Loss) Per Share | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Earnings (Loss) Per Share | Note 12—Earnings (Loss) Per Share Earnings (Loss) Per Share Basic earnings (loss) per share (“EPS”) is computed by dividing net income (loss) by the weighted-average number of shares of common stock outstanding during the period. Diluted EPS takes into account the dilutive effect of potential common stock that could be issued by the Company in conjunction with any stock awards that have been granted to directors and employees. In accordance with FASB ASC Topic 260, awards of non-vested shares shall be considered to be outstanding as of the grant date for purposes of computing diluted EPS even though their exercise is contingent upon vesting. During periods in which the Company incurs a net loss, diluted weighted-average shares outstanding are equal to basic weighted-average shares outstanding because the effect of all equity awards is antidilutive. The following is a calculation of the basic and diluted weighted-average number of shares of common stock outstanding and EPS for the years ended: (in thousands, except per share data) Year Ended December 31, 2016 2015 2014 Loss (numerator): Net loss $ (203,806 ) $ (971,410 ) $ (183,176 ) Weighted-average shares (denominator): Weighted-average number of shares of common stock—basic and diluted 241,434 217,897 144,369 Loss per share: Basic and diluted $ (0.84 ) $ (4.46 ) $ (1.27 ) |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 13—Related Party Transactions In December 2010, Eclipse Operating was formed by members of the Company’s management team for purposes of operating Eclipse I. The Company’s Chairman, President and Chief Executive Officer, Executive Vice President, Secretary and General Counsel and Executive Vice President and Chief Operating Officer each owned 33% of the membership units of Eclipse Operating. Eclipse Operating provided administrative and management services to Eclipse I under the terms of an Administrative Services Agreement. In connection with the Corporate Reorganization, Eclipse I acquired of all the outstanding equity interests of Eclipse Operating for $0.1 million, which is the amount of the aggregate capital contributions made to Eclipse Operating by its members. As a result, Eclipse Operating became a wholly owned subsidiary of Eclipse I. Under the terms of the Administrative Services Agreement, Eclipse I paid Eclipse Operating a monthly management fee equal to the sum of all general and administrative expenditures incurred in the management and administration of Eclipse I’s operations. These costs included salaries, wages and benefits, rent, insurance, and other expenses and costs required to operate Eclipse I. These expenses were billed in arrears at the actual cost to Eclipse Operating. During the period from January 1, 2014 to June 23, 2014, the Company’s management fee to Eclipse Operating was $15.6 million. These expenses are classified within “Operating expenses—General and administrative” in the consolidated statements of operations. As of December 31, 2014, the Company had recorded an accrued liability of approximately $1.0 million related to an estimated final distribution of the assets of Eclipse Operating. The actual distribution of approximately $0.6 million was distributed equally among the three former shareholders during 2015 and the remaining $0.4 million reflected as a reduction of initial gain recorded on the acquisition of Eclipse Operating, which is classified within “Other income” in the consolidated statements of operations. During the years ended December 31, 2016, 2015, and 2014, the Company incurred approximately $0.6 million, $0.3 million and $0.2 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which are owned by the Company’s Chairman, President and Chief Executive Officer. The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 14—Commitments and Contingencies (a) Legal Matters Prior to the Company’s acquisition of the Oxford Oil Company (“Oxford”), which was completed in June 2013, Oxford commenced a lawsuit on October 24, 2011 in the Common Pleas Court of Belmont County, Ohio against Mr. Barry West, a lessor under an Oxford oil and gas lease, to enforce its rights to access and drill a well pursuant to the lease during its initial 5-year primary term. The lessor counterclaimed, alleging, among other things, that the challenged Oxford lease constituted a lease in perpetuity and, accordingly, should be deemed void and contrary to public policy in the State of Ohio. On October 4, 2013, the Belmont County trial court granted a motion for summary judgment in favor of the lessor and ruled that the lease is a “no term” perpetual lease and, as such, is void as a matter of Ohio law. On October 8, 2013, the Company appealed the trial court’s decision in the West On September 26, 2014, the Ohio Court of Appeals for the Seventh Appellate District issued its decision in the case of State ex rel. Claugus Family Farm, L.P. v. Beck Energy Corporation (formerly entitled, Hupp v. Beck Energy Corporation) West West Claugus Family v. Beck Energy Claugus Family v. Beck Energy West On September 6, 2016, the Ohio Court of Appeals for the Seventh Appellate District issued its decision in the West West West The Company was a party to one other lawsuit that claimed the Oxford oil and gas lease was void as a perpetual lease in reliance upon the trial court’s decision in the West West Other Matters From time to time, the Company may be a party to legal proceedings arising in the ordinary course of business. Management does not believe that a material loss is probable as a result of such proceedings. (b) Environmental Matters The Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected. (c) Leases The development of the Company’s oil and natural gas properties under their related leases will require a significant amount of capital. The timing of those expenditures will be determined by the lease provisions, the term of the lease and other factors associated with unproved leasehold acreage. To the extent that the Company is not the operator of oil and natural gas properties that it owns an interest in, the timing, and to some degree the amount, of capital expenditures will be controlled by the operator of such properties. The Company leases office space under an operating lease that expires in 2024. Rent expense related to lease agreements for the years ended December 31, 2016, 2015, and 2014 was $0.9 million, $1.1 million and $0.3 million, respectively. The following is a schedule by year, of the future minimum lease payments required under the lease agreements as of December 31, 2016 (in thousands). 2017 $ 637 2018 637 2019 637 2020 690 2021 684 Thereafter 2,052 Total minimum lease payments $ 5,337 (d) Other Commitments (in thousands) Drilling rig commitments (i) Firm transportation (ii) Gas processing, gathering, and compression services (iii) Total Year Ending December 31: 2017 $ 8,937 $ 49,748 $ 9,430 $ 68,115 2018 — 118,316 15,919 134,235 2019 — 111,787 17,140 128,927 2020 — 109,593 7,721 117,314 2021 — 105,391 — 105,391 Thereafter — 205,766 — 205,766 Total $ 8,937 $ 700,601 $ 50,210 $ 759,748 (i) Drilling rig commitments - The Company had contracts for the service of two rigs, which one expires in August 2017 with the option to extend and one expires in September 2017. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest, as applicable. (ii) Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas or NGL volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest. (iii) Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements its proportionate share of costs based on the Company’s working interest.” |
Income Tax
Income Tax | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Note 15—Income Tax For the year ended December 31, 2016, the Company’s annual effective tax rate is approximately 0.27%. The Company incurred a tax loss in the current year (due principally to pre-tax loss) and thus, no current federal income taxes will be due. This tax loss results in a net operating loss carryforward at December 31, 2016. Management assessed the realizability of the Company’s deferred tax assets based on the more likely than not standard. Management considered several factors such as: (i) the Company’s short tax history, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net federal tax attribute carryforwards are realizable. As such, the Company has provided a valuation allowance of $363 million as of December 31, 2016. For the Year Ended December 31, 2016 2015 2014 Current Federal $ — $ — $ — State 6 315 132 Total current 6 315 132 Deferred Federal — (72,413 ) 71,838 State 540 (348 ) (171 ) Total deferred 540 (72,761 ) 71,667 Total income tax expense (benefit) $ 546 $ (72,446 ) $ 71,799 The Company’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items (in thousands): For the Year Ended December 31, 2016 2015 2014 Loss before income taxes $ (203,260 ) $ (1,043,856 ) $ (111,377 ) Statutory rate 35 % 35 % 35 % Income tax benefit computed at statutory rate (71,141 ) (365,350 ) (38,982 ) Reconciling items: Non-deductible pre-IPO loss — — 13,264 State income taxes 546 (21 ) (39 ) Other, net 854 795 71 Change in tax status — — 97,609 Gain on acquisition of Eclipse Operating — (141 ) (124 ) Change in valuation allowance 70,287 292,271 — Income tax expense (benefit) $ 546 $ (72,446 ) $ 71,799 Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands): For the Year Ended December 31, 2016 2015 Deferred tax asset: Oil and gas properties and equipment $ 193,095 $ 235,884 Federal tax loss carryforwards 149,088 65,491 Derivative instruments and other 16,829 — State effect of deferreds — 540 Other, net 4,259 3,434 Deferred tax asset 363,271 305,349 Valuation allowance (362,558 ) (292,271 ) Net deferred tax assets $ 713 $ 13,078 Deferred tax liability: Oil and gas properties and equipment $ — $ — Derivative instruments and other — 12,054 Other, net 713 484 Net deferred tax liability $ 713 $ 12,538 Reflected in the accompanying consolidated balance sheet as: Net deferred tax asset $ — $ 540 Net deferred tax liability $ — $ — The Company has U.S. federal tax loss carryforwards (“NOL”) of approximately $426 million as of December 31, 2016. The NOL carryforwards will begin to expire in 2034. The tax years ended December 31, 2015 and 2014 will remain open to examination under the applicable statute of limitations in the U.S. and other jurisdictions in which the Company and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not commence until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. Tax returns for predecessor entities for 2012 tax year and prior are generally not subject to examination. During the second quarter of 2016, the Internal Revenue Service notified the Company that it would examine the federal income tax return of Eclipse Resources Corporation and Subsidiaries for its 2014 tax year. The Company does not anticipate any material adjustments to its provision for income taxes as a result of the examination, as such no reserve has been recorded at this time. As of December 31, 2016, 2015, and 2014 the Company has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods. |
Subsidiary Guarantors
Subsidiary Guarantors | 12 Months Ended |
Dec. 31, 2016 | |
Text Block [Abstract] | |
Subsidiary Guarantors | Note 16—Subsidiary Guarantors The Company’s wholly-owned subsidiaries each have fully and unconditionally, joint and severally, guaranteed the Company’s 8.875% Senior Unsecured Notes (See Note 8— Debt A subsidiary guarantor may be released from its obligations under the guarantee: • in the event of a sale or other disposition of all or substantially all of the assets of the subsidiary guarantor or a sale or other disposition of all the capital stock of the subsidiary guarantor, to any corporation or other person by way of merger, consolidation, or otherwise; or • if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the terms of the indenture. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 17—Subsequent Events Management has evaluated subsequent events and believes that there are no events that would have a material impact on the aforementioned financial statements and related disclosures, except for the amendment to the revolving credit facility and redetermination of the borrowing base in February 2017 (See Note 8 — Debt Commitments and Contingencies |
Quarterly Financial Information
Quarterly Financial Information (unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Financial Information (unaudited) | Note 18—Quarterly Financial Information (unaudited) Summarized quarterly financial data for the years ended December 31, 2016 and 2015 are presented in the following table. In the following table, the sum of basic and diluted “Loss per common share” for the four quarters may differ from the annual amounts due to the required method of computing weighted average number of shares in the respective periods. Additionally, due to the effect of rounding, the sum of the individual quarterly loss per share amounts may not equal the calculated year loss per share amount (in thousands, except per share data). First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2016 Total operating revenues $ 49,606 $ 47,066 $ 54,479 $ 83,883 Total operating expenses 95,367 83,865 79,530 90,745 Operating loss (45,761 ) (36,799 ) (25,051 ) (6,862 ) Net loss (40,687 ) (73,011 ) (26,801 ) (63,307 ) Loss per common share: Basic and diluted $ (0.18 ) $ (0.33 ) $ (0.10 ) $ (0.23 ) First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2015 Total operating revenues $ 43,814 $ 74,453 $ 71,172 $ 65,882 Total operating expenses 93,248 114,909 123,462 911,187 Operating loss (49,434 ) (40,456 ) (52,290 ) (845,305 ) Net loss (34,103 ) (41,970 ) (81,468 ) (813,869 ) Loss per common share: Basic and diluted $ (0.17 ) $ (0.19 ) $ (0.37 ) $ (3.66 ) |
Supplemental Oil and Natural Ga
Supplemental Oil and Natural Gas Information (unaudited) | 12 Months Ended |
Dec. 31, 2016 | |
Text Block [Abstract] | |
Supplemental Oil and Natural Gas Information (unaudited) | Note 19—Supplemental Oil and Natural Gas Information (unaudited) (a) Capitalized Costs A summary of the Company’s capitalized costs are contained in the table below (in thousands): December 31, 2016 2015 Oil and natural gas properties: Unproved properties $ 526,270 $ 720,159 Proved properties 1,545,860 1,288,609 Total oil and natural gas properties 2,072,130 2,008,768 Less accumulated depreciation, depletion and amortization (1,131,378 ) (1,022,771 ) Net oil and natural gas properties $ 940,752 $ 985,997 (b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands): December 31, 2016 2015 2014 Acquisition costs: Unproved properties $ 24,764 $ 24,722 $ 134,156 Proved properties — — — Development cost 150,778 259,655 714,796 Exploration cost 20,127 20,530 21,186 Total acquisition, development and exploration costs $ 195,669 $ 304,907 $ 870,138 (c) Reserve Quantity Information The following information represents estimates of the Company’s proved reserves as of December 31, 2016 and December 31, 2015, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2016, 2015, and 2014 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs and a Henry Hub spot natural gas price per MMBtu for natural gas. Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Appalachian Basin of Ohio. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more. The Company’s proved oil and natural gas reserves are all located in the United States, within the State of Ohio. All of the estimates of the proved reserves at December 31, 2016, 2015, and 2014, were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB. Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2016, 2015, and 2014 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Natural Gas (Bcf) Natural Gas Liquids (MBbl) Oil (MBbl) TOTAL (Bcfe) End of year, December 31, 2013 52.3 1,938.4 2,417.4 78.5 Revisions (12.1 ) (739.7 ) (462.6 ) (19.3 ) Extensions and discoveries 235.8 10,216.3 4,337.5 323.1 Production (19.8 ) (536.0 ) (594.9 ) (26.5 ) End of year, December 31, 2014 256.3 10,879.0 5,697.4 355.8 Revisions (115.3 ) (4,705.7 ) (1,550.1 ) (152.9 ) Extensions and discoveries 182.6 4,035.7 2,496.3 221.7 Production (49.5 ) (2,450.3 ) (1,950.5 ) (75.9 ) End of year, December 31, 2015 274.1 7,758.7 4,693.1 348.8 Revisions (0.1 ) 1,273.7 1,196.8 14.8 Extensions and discoveries 175.4 2,156.0 1,300.2 196.1 Acquisitions 3.8 24.8 15.1 4.1 Divestitures (5.9 ) (91.5 ) (703.7 ) (10.7 ) Production (60.9 ) (2,446.2 ) (1,343.8 ) (83.7 ) End of year, December 31, 2016 386.4 8,675.5 5,157.7 469.4 Proved developed reserves: December 31, 2014 133.0 6,758.6 3,880.9 196.8 December 31, 2015 209.5 7,245.7 4,239.2 278.4 December 31, 2016 226.1 7,520.0 4,439.5 297.8 Proved undeveloped reserves: December 31, 2014 123.4 4,120.4 1,816.4 159.0 December 31, 2015 64.5 513.0 453.9 70.3 December 31, 2016 160.4 1,155.5 718.1 171.6 Extensions and discoveries of 196.1 Bcfe and 221.7 Bcfe during the years ended December 31, 2016 and December 31, 2015, respectively, resulted primarily from the drilling of new wells during each year and from new proved undeveloped locations added during each year. (d) Standardized Measure of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2016 and 2015 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2016, 2015, and 2014 (in thousands): December 31, 2016 2015 2014 Future cash inflows (total revenues) $ 1,143,142 $ 975,664 $ 1,870,319 Future production costs (725,724 ) (592,073 ) (728,041 ) Future development costs (capital costs) (116,988 ) (83,532 ) (350,187 ) Future income tax expense — — (277,500 ) Future net cash flows 300,430 300,059 514,591 10% annual discount for estimated timing of cash flows (94,449 ) (87,194 ) (183,934 ) Standardized measure of Discounted Future Net Cash Flow $ 205,981 $ 212,865 $ 330,657 It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves. (e) Changes in the Standardized Measure of Discounted Future Net Cash Flows A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands): December 31, 2016 2015 2014 Standardized Measure, beginning of the year $ 212,865 $ 330,657 $ 155,295 Net change in prices and production costs (33,507 ) (372,664 ) (52,642 ) Net change in future development costs 1,552 79,244 (2,122 ) Sales, less production costs (99,768 ) (121,646 ) (104,099 ) Extensions 79,941 107,749 491,067 Acquisitions 1,045 — — Divestitures (5,231 ) — — Revisions of previous quantity estimates 15,754 (97,210 ) (38,201 ) Previously estimated development costs incurred 4,886 62,906 16,807 Accretion of discount 21,287 50,939 15,529 Net change in taxes — 178,732 (178,732 ) Changes in timing and other 7,157 (5,842 ) 27,755 Standardized Measure, end of year $ 205,981 $ 212,865 $ 330,657 |
Summary of Significant Accoun28
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 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 party. The Company did not deem any of its accounts receivables to be uncollectable as of December 31, 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 which are, in turn, based upon applicable product prices. The Company had $41.4 million and $19.9 million of accrued revenues, net of expenses at December 31, 2016 and December 31, 2015, respectively, which were included in accounts receivable within the Company’s 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 consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s 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 consolidated statements of operations. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment on a group basis, no gain or loss is recognized in the Company’s consolidated statements of operations unless the proceeds exceed the original cost of the property, in which case a gain is recognized in the amount of such excess. 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): December 31, 2016 December 31, 2015 Oil and natural gas properties: Unproved $ 526,270 $ 720,159 Proved 1,545,860 1,288,609 Gross oil and natural gas properties 2,072,130 2,008,768 Less accumulated depreciation depletion and amortization (1,131,378 ) (1,022,771 ) Oil and natural gas properties, net 940,752 985,997 Other property and equipment 11,447 10,753 Less accumulated depreciation (4,699 ) (2,782 ) Other property and equipment, net 6,748 7,971 Property and equipment, net $ 947,500 $ 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 $1.1 million, $2.8 million and $9.1 million for the years ended December 31, 2016, 2015, and 2014, 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. |
Accrued Liabilities | (d) Accrued Liabilities A summary of accrued liabilities is as follows (in thousands): December 31, 2016 December 31, 2015 Ad valorem and production taxes $ 13,625 $ 14,231 Employee compensation 4,257 6,628 Royalties 8,557 3,196 Short term derivatives 35,409 — Other 2,302 1,407 Total accrued liabilities $ 64,150 $ 25,462 |
Revenue Recognition | (e) 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 or 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 had no material imbalances as of December 31, 2016 and 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 report them within one operating segment. |
Major Customers | (f) Major Customers The Company sells production volumes to various purchasers. For the years ended December 31, 2016, 2015, and 2014, there were four, four and two customers, respectively, that accounted for 10% or more of the total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the Year Ended December 31, 2016 2015 2014 Purchaser Antero Resources Corporation 14 % 19 % 47 % ARM Energy Management — 11 % 25 % Concord Energy, LLC 12 % — — Enlink Midstream Operating 17 % 21 % — Sequent Energy Management 20 % 19 % — Total 63 % 70 % 72 % Management believes that the loss of any one customer would not have a material adverse effect on the Company’s ability to sell natural gas, NGLs and oil production because it believes that there are potential alternative purchasers although it may be necessary to establish relationships with new purchasers. However, there can be no assurance that the Company can establish such relationships or that those relationships will result in an increased number of purchasers. |
Concentration of Credit Risk | (g) Concentration of Credit Risk The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2016 and December 31, 2015 (in thousands): December 31, 2016 December 31, 2015 Receivables by product or service: Sale of oil and natural gas and related products and services $ 41,398 $ 19,858 Joint interest owners 2,065 3,095 Derivatives 122 4,523 Other 53 — Total $ 43,638 $ 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, it is the Company’s policy 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 commodity unsettled derivative contracts was a net liability position of ($48.1) million and a net asset position of $34.4 million at December 31, 2016 and 2015, respectively. Other than as provided by the 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 they required to provide credit support to the Company. As of December 31, 2016, the Company did not have past-due receivables from or payables to any of the counterparties. |
Accumulated Other Comprehensive Income (Loss) | (h) 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 included a pension benefit plan that required the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension liability of $2.2 million for the year ended December 31, 2014. 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 | (i) 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 for the years ended December 31, 2016, 2015, and 2014 totaled approximately $91.0 million, $242.9 million and $88.4 million, respectively. Through September 30, 2014, the Company calculated depletion of proved properties at the individual unit level. Effective October 1, 2014, the Company changed its estimate for calculating depletion expense of proved properties to be performed at the field level consistent with the assessment for impairment of proved property costs. 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 for the years ended December 31, 2016, 2015, and 2014 totaled approximately $1.9 million, $1.8 million and $0.8 million, respectively. This amount is included in DD&A expense in the consolidated statements of operations. |
Impairment of Long-Lived Assets | (j) 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. During the year ended December 31, 2014, the Company changed its estimate for assessing impairment of proved property costs. Through September 30, 2014, such assessments were performed at the individual unit level. Effective October 1, 2014, assessment for impairment of proved properties is performed at the field level, which for the Company currently consists of two fields, including the Utica Shale and the Marcellus Shale. With the increase in the Company’s activity level, this change will result in a more appropriate identification of cash flows utilized in the assessment of recoverability of proved properties as additional units are placed into production, resulting in increased sharing of revenues and costs across units related to infrastructure, equipment, and fulfillment of sales and transportation contracts. The review 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 year ended December 31, 2016 relating to proved properties in the Marcellus Shale, $691.3 million for the year ended December 31, 2015 relating to proved properties in the Utica Shale, and $34.9 million for the year ended December 31, 2014, of which approximately $30.9 million related to the Company’s Conventional properties. As discussed in Note 5, the Company completed the sale of its Conventional properties during the year ended December 31, 2016. The aforementioned impairment charges 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 oil and natural gas properties are periodically assessed for impairment by considering future drilling and exploration plans, results of exploration activities, commodity price outlooks, planned future sales and expiration of all or a portion of the properties. 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 $29.8 million, $95.6 million, and $5.7 million for the years ended December 31, 2016, 2015, and 2014, respectively. These costs are included in exploration expense in the consolidated statements of operations. |
Income Taxes | (k) Income Taxes The Company accounts for income taxes, as required, under the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases 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. Upon the closing of the Corporate Reorganization, the Company owns 100% of Eclipse I, Eclipse Resources-Ohio, LLC and Eclipse Operating. Eclipse I was a limited partnership not subject to federal income taxes before the Corporate Reorganization. However, in connection with the closing of the Corporate Reorganization, the Company became a corporation subject to federal and state income tax and, as such, the Company’s future income taxes will be dependent upon its future taxable income. The change in tax status requires the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately $97.6 million was recorded as income tax expense in the consolidated statements of operations for the year ended December 31, 2014. ASC Topic 740 “ Income Taxes |
Fair Value of Financial Instruments | (l) 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 | (m) 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 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 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 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 | (n) Asset Retirement Obligation The Company recognizes a legal liability for its asset retirement obligations (“ARO”) in accordance with Topic ASC 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 period indicated (in thousands): Year Ended December 31, 2016 December 31, 2015 December 31, 2014 Asset retirement obligations, beginning of period $ 3,401 $ 17,400 $ 9,055 Liabilities associated with assets held for sale — (19,057 ) — Revisions of prior estimates — 2,913 6,470 Additional liabilities incurred 1,014 522 1,084 Accretion 391 1,623 791 Asset retirement obligations, end of period $ 4,806 $ 3,401 $ 17,400 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 | (o) Lease Obligations The Company leases office space under an operating lease that expires in 2024. 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 | (p) Off-Balance Sheet Arrangements The Company does not have any off-balance sheet arrangements. |
Segment Reporting | (q) 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 | (r) 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 | (s) Recent Accounting Pronouncements Recently Adopted In August 2014, the FASB issued Accounting Standards Update No. 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 and interim periods ending after December 15, 2016, with early adoption permitted. The Company adopted this standard for the year ended December 31, 2016 with no significant impact on the Company’s financial statement 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 with early adoption permitted. The Company adopted this standard for the year ended December 31, 2016 with no significant impact on the Company’s financial position, results of operation, or related disclosures. Accounting Pronouncements Not Yet Adopted The FASB issued ASU 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 with early adoption permitted. The Company plans to adopt this standard effective January 1, 2018 and is currently evaluating its transition method. As part of the implementation process, the Company is currently assessing the impact of the new requirements on its internal systems and policies, which involves reviewing all existing contracts. The Company does not expect this standard to have a significant impact on its financial position or results of operations but will require that the Company’s revenue recognition policy disclosures include further detail regarding its performance obligations as to the nature, amount, timing and estimates of revenue and cash flows generated from the Company’s contracts with customers. The Company continues to monitor relevant industry guidance regarding implementation of the standard and adjust its implementation strategies as necessary. 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 with early adoption permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments.” The new standard provides guidance on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. |
Cash Flow Revision | (t) Cash Flow Revision The Company previously revised the presentation of delay rentals and geological and geophysical costs within the consolidated statements of cash flows for the year ended December 31, 2014. Previously, such costs had been presented as cash outflows from investing activities; however, U.S. GAAP requires such costs to be presented as cash outflows from operating activities. This revision resulted in a reduction to cash flows provided by operating activities and a corresponding reduction to cash flows used in investing activities of approximately $14.8 million for the year ended December 31, 2014, compared to the previously reported amount. The Company evaluated the materiality of this revision on both a quantitative and qualitative basis under the guidance of ASC 250—Accounting Changes and Error Corrections and determined that it did not have a material impact to previously issued financial statements. |
Change in Estimates | (u) Change in Estimates During the year ended December 31, 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 year ended December 31, 2016 by approximately $4 million, or $0.02 per common share. During the year ended December 31, 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 year ended December 31, 2016 by a corresponding amount, or $0.02 per common share. |
Summary of Significant Accoun29
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 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): December 31, 2016 December 31, 2015 Oil and natural gas properties: Unproved $ 526,270 $ 720,159 Proved 1,545,860 1,288,609 Gross oil and natural gas properties 2,072,130 2,008,768 Less accumulated depreciation depletion and amortization (1,131,378 ) (1,022,771 ) Oil and natural gas properties, net 940,752 985,997 Other property and equipment 11,447 10,753 Less accumulated depreciation (4,699 ) (2,782 ) Other property and equipment, net 6,748 7,971 Property and equipment, net $ 947,500 $ 993,968 |
Summary of Accrued Liabilities | A summary of accrued liabilities is as follows (in thousands): December 31, 2016 December 31, 2015 Ad valorem and production taxes $ 13,625 $ 14,231 Employee compensation 4,257 6,628 Royalties 8,557 3,196 Short term derivatives 35,409 — Other 2,302 1,407 Total accrued liabilities $ 64,150 $ 25,462 |
Changes in Company's Asset Retirement Obligation Liability | The following table sets forth the changes in the Company’s ARO liability for the period indicated (in thousands): Year Ended December 31, 2016 December 31, 2015 December 31, 2014 Asset retirement obligations, beginning of period $ 3,401 $ 17,400 $ 9,055 Liabilities associated with assets held for sale — (19,057 ) — Revisions of prior estimates — 2,913 6,470 Additional liabilities incurred 1,014 522 1,084 Accretion 391 1,623 791 Asset retirement obligations, end of period $ 4,806 $ 3,401 $ 17,400 |
Sales Revenue, Services, Net [Member] | Customer Concentration Risk [Member] | |
Concentration Risk | The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the Year Ended December 31, 2016 2015 2014 Purchaser Antero Resources Corporation 14 % 19 % 47 % ARM Energy Management — 11 % 25 % Concord Energy, LLC 12 % — — Enlink Midstream Operating 17 % 21 % — Sequent Energy Management 20 % 19 % — Total 63 % 70 % 72 % |
Accounts Receivable [Member] | Product Concentration Risk [Member] | |
Concentration Risk | The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2016 and December 31, 2015 (in thousands): December 31, 2016 December 31, 2015 Receivables by product or service: Sale of oil and natural gas and related products and services $ 41,398 $ 19,858 Joint interest owners 2,065 3,095 Derivatives 122 4,523 Other 53 — Total $ 43,638 $ 27,476 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of Derivative Instrument Positions for Future Production Periods | Below is a summary of the Company’s derivative instrument positions, as of December 31, 2016, for future production periods: Natural Gas Derivatives Description Volume (MMBtu/d) Production Period Weighted Average Price ($/MMBtu) Natural Gas Swaps: 10,000 January 2017 – December 2017 $ 2.98 10,000 March 2017 – December 2017 $ 3.21 Natural Gas Collars: Floor purchase price (put) 130,000 January 2017 – December 2017 $ 2.85 Ceiling sold price (call) 130,000 January 2017 – December 2017 $ 3.24 Floor purchase price (put) 20,000 January 2017 – December 2018 $ 2.90 Ceiling sold price (call) 20,000 January 2017 – December 2018 $ 3.25 Floor purchase price (put) 40,000 January 2018 – December 2018 $ 2.75 Ceiling sold price (call) 40,000 January 2018 – December 2018 $ 3.27 Natural Gas Three-way Collars: Floor purchase price (put) 30,000 January 2017 – December 2017 $ 2.75 Ceiling sold price (call) 30,000 January 2017 – December 2017 $ 3.57 Floor sold price (put) 30,000 January 2017 – December 2017 $ 2.25 Floor purchase price (put) 30,000 April 2017 – March 2019 $ 3.00 Ceiling sold price (call) 30,000 April 2017 – March 2019 $ 3.40 Floor sold price (put) 30,000 April 2017 – March 2019 $ 2.20 Floor purchase price (put) 80,000 January 2018 – December 2018 $ 2.90 Ceiling sold price (call) 80,000 January 2018 – December 2018 $ 3.31 Floor sold price (put) 80,000 January 2018 – December 2018 $ 2.12 Floor purchase price (put) 20,000 October 2017 – December 2018 $ 2.90 Ceiling sold price (call) 20,000 October 2017 – December 2018 $ 3.50 Floor sold price (put) 20,000 October 2017 – December 2018 $ 2.20 Natural Gas Call/Put Options: Call sold 40,000 January 2018 – December 2018 $ 3.75 Call sold 10,000 January 2019 – December 2019 $ 4.75 Basis Swaps: TCO - Columbia 20,000 January 2017 – December 2017 $ (0.19 ) Oil Derivatives Description Volume (Bbls/d) Production Period Weighted Price Oil Swaps: Floor purchase price (put) 2,000 January 2017 – September 2017 $ 46.00 Ceiling sold price (call) 2,000 January 2017 – September 2017 $ 59.50 Floor sold price (put) 2,000 January 2017 – September 2017 $ 38.00 Floor purchase price (put) 2,000 January 2017 – December 2017 $ 46.00 Ceiling sold price (call) 2,000 January 2017 – December 2017 $ 60.00 Floor sold price (put) 2,000 January 2017 – December 2017 $ 38.00 Oil Call/Put Options: Call sold 1,000 January 2018 – December 2018 $ 50.00 NGL Derivatives Description Volume (Gal/d) Production Period Weighted Average Price ($/Gal) Propane Swaps: 84,000 January 2017 – December 2017 $ 0.60 |
Fair Value of Derivative Instruments on a Gross Basis and on a Net basis as Presented in Consolidated Balance Sheets | The following table summarizes the fair value of the Company’s derivative instruments on a gross basis and on a net basis as presented in the consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes. As of December 31, 2016 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 50 $ (50 ) $ — Commodity derivatives - noncurrent — — — Total assets $ 50 $ (50 ) $ — Liabilities Commodity derivatives - current $ (35,459 ) $ 50 $ (35,409 ) Accrued liabilities Commodity derivatives - noncurrent (12,673 ) — (12,673 ) Other liabilities Total liabilities $ (48,132 ) $ 50 $ (48,082 ) As of December 31, 2015 Gross Amount Netting Adjustments(a) Net Amount Presented in Balance Sheets Balance Sheet Location Assets Commodity derivatives - current $ 41,199 $ (8,158 ) $ 33,041 Other current assets Commodity derivatives - noncurrent 4,594 (3,194 ) 1,400 Other assets Total assets $ 45,793 $ (11,352 ) $ 34,441 Liabilities Commodity derivatives - current $ (8,158 ) $ 8,158 $ — Commodity derivatives - noncurrent (3,194 ) 3,194 — Total liabilities $ (11,352 ) $ 11,352 $ — (a) 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. |
Summary of Gains and Losses on Derivative Instruments | The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the consolidated statements of operations for the periods presented (in thousands): Years Ended December 31, Location of Gain (Loss) 2016 2015 2014 Commodity derivatives Gain (Loss) on derivative instruments $ (52,338 ) $ 56,021 $ 20,791 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Fair Value Disclosures [Abstract] | |
Assets and Liabilities that are Measured at Fair Value on a Recurring Basis | The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are readily available in the public market, such as natural gas forward curves. These values are compared to the values given by counterparties for reasonableness. Since natural gas swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. Level 1 Level 2 Level 3 Total As of December 31, 2016: (in thousands) Commodity derivative instruments $ — $ (48,082 ) $ — $ (48,082 ) Total $ — $ (48,082 ) $ — $ (48,082 ) As of December 31, 2015: (in thousands) Commodity derivative instruments $ — $ 34,441 $ — $ 34,441 Total $ — $ 34,441 $ — $ 34,441 |
Benefit Plans (Tables)
Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Compensation And Retirement Disclosure [Abstract] | |
Summary of Pension Benefit Obligation | A summary of the pension benefit obligation as of the year ended December 31, 2015 is set forth in the below tables (in thousands): 2015 Change in benefit obligation Benefit obligation at beginning of year $ 6,800 Service cost — Interest cost 239 Gain on reduction of pension liability — Actuarial (gain) loss (775 ) Benefits paid (6,264 ) Benefit obligation at end of period $ — Change in plan assets Fair value of plan assets at beginning of year $ 5,479 Actual return on plan assets 14 Employer contributions 771 Benefit paid (6,264 ) Fair value of plan assets at end of period $ — |
Schedule of Defined Benefit Plan in Accumulated Other Comprehensive Income | 2015 Beginning amount recorded in other accumulated comprehensive income (loss) $ (548 ) Amounts recorded in accumulated other comprehensive income (loss) consist of: Pension obligation adjustment, net of tax 548 Total recorded in accumulated other comprehensive income $ — |
Components of Net Periodic Benefit Cost | For the Year Ended December 31, 2015 2014 Components of net periodic benefit cost (in thousands) Service cost $ — $ 70 Interest cost 239 335 Expected return on plan assets (246 ) (448 ) Amortization of transition obligation — 70 Amortization of net (gain) loss 42 29 Effect of settlement 224 — Net period benefit cost $ 259 $ 56 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract] | |
Schedule of Stock Based Compensation Expense | Our stock based compensation expense is as follows for the years ended December 31, 2016, 2015, and 2014 (in thousands): Year Ended December 31, 2016 2015 2014 Restricted stock units $ 4,006 $ 2,408 $ — Performance units 1,922 1,297 — Restricted stock issued to directors 556 827 138 Incentive units (268 ) 103 118 Total expense $ 6,216 $ 4,635 $ 256 |
Summary of Restricted Stock Unit Awards Activity | A summary of restricted stock unit awards activity during the year ended December 31, 2016 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2015 1,000,052 $ 7.07 $ 1,820 Granted 3,751,931 1.36 Vested (340,879 ) 7.13 Forfeited (67,522 ) 7.13 Total awarded and unvested, December 31, 2016 4,343,582 $ 2.14 $ 11,597 |
Summary of Performance Stock Unit Awards Activity | A summary of performance stock unit awards activity during the year ended December 31, 2016 is as follows: Number of shares Weighted average grant date fair value Aggregate intrinsic value (in thousands) Total awarded and unvested, December 31, 2015 458,656 $ 8.77 $ 417 Granted 1,469,346 1.60 Vested — — Forfeited — — Total awarded and unvested, December 31, 2016 1,928,002 $ 3.31 $ 5,148 |
Earnings (Loss) Per Share (Tabl
Earnings (Loss) Per Share (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Schedule of Earnings Per Share | The following is a calculation of the basic and diluted weighted-average number of shares of common stock outstanding and EPS for the years ended: (in thousands, except per share data) Year Ended December 31, 2016 2015 2014 Loss (numerator): Net loss $ (203,806 ) $ (971,410 ) $ (183,176 ) Weighted-average shares (denominator): Weighted-average number of shares of common stock—basic and diluted 241,434 217,897 144,369 Loss per share: Basic and diluted $ (0.84 ) $ (4.46 ) $ (1.27 ) |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Commitments And Contingencies Disclosure [Abstract] | |
Future Minimum Lease Payments Required Under Lease Agreements | The following is a schedule by year, of the future minimum lease payments required under the lease agreements as of December 31, 2016 (in thousands). 2017 $ 637 2018 637 2019 637 2020 690 2021 684 Thereafter 2,052 Total minimum lease payments $ 5,337 |
Other Commitments | (d) Other Commitments (in thousands) Drilling rig commitments (i) Firm transportation (ii) Gas processing, gathering, and compression services (iii) Total Year Ending December 31: 2017 $ 8,937 $ 49,748 $ 9,430 $ 68,115 2018 — 118,316 15,919 134,235 2019 — 111,787 17,140 128,927 2020 — 109,593 7,721 117,314 2021 — 105,391 — 105,391 Thereafter — 205,766 — 205,766 Total $ 8,937 $ 700,601 $ 50,210 $ 759,748 (i) Drilling rig commitments - The Company had contracts for the service of two rigs, which one expires in August 2017 with the option to extend and one expires in September 2017. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest, as applicable. (ii) Firm transportation - The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas or NGL volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest. (iii) Gas processing, gathering, and compression services - Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements its proportionate share of costs based on the Company’s working interest.” |
Income Tax (Tables)
Income Tax (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Segregation of Income Tax Provision Based on Location of Operations | For the Year Ended December 31, 2016 2015 2014 Current Federal $ — $ — $ — State 6 315 132 Total current 6 315 132 Deferred Federal — (72,413 ) 71,838 State 540 (348 ) (171 ) Total deferred 540 (72,761 ) 71,667 Total income tax expense (benefit) $ 546 $ (72,446 ) $ 71,799 |
Schedule of Effective Income Tax Rate Reconciliation | The Company’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items (in thousands): For the Year Ended December 31, 2016 2015 2014 Loss before income taxes $ (203,260 ) $ (1,043,856 ) $ (111,377 ) Statutory rate 35 % 35 % 35 % Income tax benefit computed at statutory rate (71,141 ) (365,350 ) (38,982 ) Reconciling items: Non-deductible pre-IPO loss — — 13,264 State income taxes 546 (21 ) (39 ) Other, net 854 795 71 Change in tax status — — 97,609 Gain on acquisition of Eclipse Operating — (141 ) (124 ) Change in valuation allowance 70,287 292,271 — Income tax expense (benefit) $ 546 $ (72,446 ) $ 71,799 |
Components of Deferred Tax Assets and Liabilities | The components of our deferred taxes are detailed in the table below (in thousands): For the Year Ended December 31, 2016 2015 Deferred tax asset: Oil and gas properties and equipment $ 193,095 $ 235,884 Federal tax loss carryforwards 149,088 65,491 Derivative instruments and other 16,829 — State effect of deferreds — 540 Other, net 4,259 3,434 Deferred tax asset 363,271 305,349 Valuation allowance (362,558 ) (292,271 ) Net deferred tax assets $ 713 $ 13,078 Deferred tax liability: Oil and gas properties and equipment $ — $ — Derivative instruments and other — 12,054 Other, net 713 484 Net deferred tax liability $ 713 $ 12,538 Reflected in the accompanying consolidated balance sheet as: Net deferred tax asset $ — $ 540 Net deferred tax liability $ — $ — |
Quarterly Financial Informati37
Quarterly Financial Information (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Quarterly Financial Information | Summarized quarterly financial data for the years ended December 31, 2016 and 2015 are presented in the following table. In the following table, the sum of basic and diluted “Loss per common share” for the four quarters may differ from the annual amounts due to the required method of computing weighted average number of shares in the respective periods. Additionally, due to the effect of rounding, the sum of the individual quarterly loss per share amounts may not equal the calculated year loss per share amount (in thousands, except per share data). First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2016 Total operating revenues $ 49,606 $ 47,066 $ 54,479 $ 83,883 Total operating expenses 95,367 83,865 79,530 90,745 Operating loss (45,761 ) (36,799 ) (25,051 ) (6,862 ) Net loss (40,687 ) (73,011 ) (26,801 ) (63,307 ) Loss per common share: Basic and diluted $ (0.18 ) $ (0.33 ) $ (0.10 ) $ (0.23 ) First Quarter Second Quarter Third Quarter Fourth Quarter Year ended December 31, 2015 Total operating revenues $ 43,814 $ 74,453 $ 71,172 $ 65,882 Total operating expenses 93,248 114,909 123,462 911,187 Operating loss (49,434 ) (40,456 ) (52,290 ) (845,305 ) Net loss (34,103 ) (41,970 ) (81,468 ) (813,869 ) Loss per common share: Basic and diluted $ (0.17 ) $ (0.19 ) $ (0.37 ) $ (3.66 ) |
Supplemental Oil and Natural 38
Supplemental Oil and Natural Gas Information (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Text Block [Abstract] | |
Summary of Capitalized Costs | A summary of the Company’s capitalized costs are contained in the table below (in thousands): December 31, 2016 2015 Oil and natural gas properties: Unproved properties $ 526,270 $ 720,159 Proved properties 1,545,860 1,288,609 Total oil and natural gas properties 2,072,130 2,008,768 Less accumulated depreciation, depletion and amortization (1,131,378 ) (1,022,771 ) Net oil and natural gas properties $ 940,752 $ 985,997 |
Summary of Oil and Gas Property Acquisition and Development | A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands): December 31, 2016 2015 2014 Acquisition costs: Unproved properties $ 24,764 $ 24,722 $ 134,156 Proved properties — — — Development cost 150,778 259,655 714,796 Exploration cost 20,127 20,530 21,186 Total acquisition, development and exploration costs $ 195,669 $ 304,907 $ 870,138 |
Proved Developed and Proved Undeveloped Reserves | The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2016, 2015, and 2014 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: Natural Gas (Bcf) Natural Gas Liquids (MBbl) Oil (MBbl) TOTAL (Bcfe) End of year, December 31, 2013 52.3 1,938.4 2,417.4 78.5 Revisions (12.1 ) (739.7 ) (462.6 ) (19.3 ) Extensions and discoveries 235.8 10,216.3 4,337.5 323.1 Production (19.8 ) (536.0 ) (594.9 ) (26.5 ) End of year, December 31, 2014 256.3 10,879.0 5,697.4 355.8 Revisions (115.3 ) (4,705.7 ) (1,550.1 ) (152.9 ) Extensions and discoveries 182.6 4,035.7 2,496.3 221.7 Production (49.5 ) (2,450.3 ) (1,950.5 ) (75.9 ) End of year, December 31, 2015 274.1 7,758.7 4,693.1 348.8 Revisions (0.1 ) 1,273.7 1,196.8 14.8 Extensions and discoveries 175.4 2,156.0 1,300.2 196.1 Acquisitions 3.8 24.8 15.1 4.1 Divestitures (5.9 ) (91.5 ) (703.7 ) (10.7 ) Production (60.9 ) (2,446.2 ) (1,343.8 ) (83.7 ) End of year, December 31, 2016 386.4 8,675.5 5,157.7 469.4 Proved developed reserves: December 31, 2014 133.0 6,758.6 3,880.9 196.8 December 31, 2015 209.5 7,245.7 4,239.2 278.4 December 31, 2016 226.1 7,520.0 4,439.5 297.8 Proved undeveloped reserves: December 31, 2014 123.4 4,120.4 1,816.4 159.0 December 31, 2015 64.5 513.0 453.9 70.3 December 31, 2016 160.4 1,155.5 718.1 171.6 |
Standard Measure of Discounted Future Net Cash Flows | The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2016, 2015, and 2014 (in thousands): December 31, 2016 2015 2014 Future cash inflows (total revenues) $ 1,143,142 $ 975,664 $ 1,870,319 Future production costs (725,724 ) (592,073 ) (728,041 ) Future development costs (capital costs) (116,988 ) (83,532 ) (350,187 ) Future income tax expense — — (277,500 ) Future net cash flows 300,430 300,059 514,591 10% annual discount for estimated timing of cash flows (94,449 ) (87,194 ) (183,934 ) Standardized measure of Discounted Future Net Cash Flow $ 205,981 $ 212,865 $ 330,657 |
Summary of Changes in Standardized Measure of Discounted Net Cash Flows | A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands): December 31, 2016 2015 2014 Standardized Measure, beginning of the year $ 212,865 $ 330,657 $ 155,295 Net change in prices and production costs (33,507 ) (372,664 ) (52,642 ) Net change in future development costs 1,552 79,244 (2,122 ) Sales, less production costs (99,768 ) (121,646 ) (104,099 ) Extensions 79,941 107,749 491,067 Acquisitions 1,045 — — Divestitures (5,231 ) — — Revisions of previous quantity estimates 15,754 (97,210 ) (38,201 ) Previously estimated development costs incurred 4,886 62,906 16,807 Accretion of discount 21,287 50,939 15,529 Net change in taxes — 178,732 (178,732 ) Changes in timing and other 7,157 (5,842 ) 27,755 Standardized Measure, end of year $ 205,981 $ 212,865 $ 330,657 |
Organization and Nature of Op39
Organization and Nature of Operations - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions | Jul. 05, 2016 | Jun. 28, 2016 | Jun. 25, 2014 | Jun. 24, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Business Acquisition [Line Items] | |||||||
Non cash exchange of common share | 138,500,000 | ||||||
Shares Issued | 37,500,000 | 30,300,000 | |||||
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 | $ 0.01 | |||
Proceeds from initial public offering | $ 123.8 | $ 544.7 | |||||
Company and Selling Stockholders [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Proceeds from initial public offering | $ 818.1 | ||||||
IPO [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Shares Issued | 21,500,000 | ||||||
Underwriting discount and commissions | $ 35.8 | ||||||
IPO [Member] | Company and Selling Stockholders [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Shares Issued | 30,300,000 | ||||||
IPO [Member] | Stock Sold by Selling Stockholders [Member] | |||||||
Business Acquisition [Line Items] | |||||||
Shares Issued | 8,800,000 |
Basis of Presentation - Additio
Basis of Presentation - Additional Information (Detail) | 12 Months Ended |
Dec. 31, 2016 | |
Organization Consolidation And Presentation Of Financial Statements [Abstract] | |
Ownership interest in predecessor | 100.00% |
Summary of Significant Accoun41
Summary of Significant Accounting Policies - Additional Information (Detail) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016USD ($)Field$ / shares | Sep. 30, 2016$ / shares | Jun. 30, 2016$ / shares | Mar. 31, 2016$ / shares | Dec. 31, 2015USD ($)$ / shares | Sep. 30, 2015$ / shares | Jun. 30, 2015$ / shares | Mar. 31, 2015$ / shares | Dec. 31, 2016USD ($)CustomerFieldSegment$ / shares | Dec. 31, 2015USD ($)Customer$ / shares | Dec. 31, 2014USD ($)Customer$ / shares | |
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Accounts receivable | $ 43,638 | $ 27,476 | $ 43,638 | $ 27,476 | |||||||
Capitalized interest expense | $ 1,100 | 2,800 | $ 9,100 | ||||||||
Gain on reduction of pension liability | 2,208 | ||||||||||
Pension plan termination date | 2015-10 | ||||||||||
Depreciation, depletion and amortization | $ 92,948 | 244,750 | 89,218 | ||||||||
Number of field included in assessment of impairment | Field | 2 | 2 | |||||||||
Impairment of oil and gas properties | $ 17,665 | $ 691,334 | 34,855 | ||||||||
Deferred tax liability | 97,600 | ||||||||||
Asset retirement obligations credit adjusted discount rates | 10.33% | 10.33% | |||||||||
Operating lease expiration year | 2,024 | ||||||||||
Number of operating segment | Segment | 1 | ||||||||||
Prior period adjustment in cash flows | 14,800 | ||||||||||
Decrease in accounts receivable | $ 20,563 | $ (20,437) | $ 33,605 | ||||||||
Increase of net loss, per common share | $ / shares | $ (0.23) | $ (0.10) | $ (0.33) | $ (0.18) | $ (3.66) | $ (0.37) | $ (0.19) | $ (0.17) | $ (0.84) | $ (4.46) | $ (1.27) |
Decrease in accrual for production and ad valorem taxes to be paid | $ 4,000 | ||||||||||
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) | ||||||||||
Increase in revenue from oil and natural gas | 1,500 | ||||||||||
Increase in transportation, gathering and compression expense | 5,800 | ||||||||||
Increase in net loss | $ 4,000 | ||||||||||
Increase of net loss, per common share | $ / shares | $ 0.02 | ||||||||||
Eclipse I [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Ownership percentage | 100.00% | ||||||||||
Eclipse Resources Ohio LLC [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Ownership percentage | 100.00% | ||||||||||
Eclipse Resources Operating, LLC ("Eclipse Operating") [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Ownership percentage | 100.00% | ||||||||||
Oil and Gas Properties [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Depreciation, depletion and amortization | $ 91,000 | $ 242,900 | $ 88,400 | ||||||||
Other property and equipment [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Depreciation | $ 1,900 | 1,800 | 800 | ||||||||
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 | $ 17,700 | 691,300 | 34,900 | ||||||||
Conventional Properties [Member] | Utica Shale [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Impairment of oil and gas properties | 30,900 | ||||||||||
Unproved Oil And Gas Properties [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Impairment of oil and gas properties | 29,800 | 95,600 | $ 5,700 | ||||||||
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Fair value of commodity derivative contracts | $ (48,100) | $ 34,441 | $ (48,100) | $ 34,441 | |||||||
Sales Revenue, Net [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Number of customers | Customer | 4 | 4 | 2 | ||||||||
Unbilled Revenues [Member] | |||||||||||
Summary Of Significant Accounting Policies [Line Items] | |||||||||||
Accounts receivable | $ 41,400 | $ 19,900 | $ 41,400 | $ 19,900 |
Summary of Significant Accoun42
Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Oil and natural gas properties: | ||
Unproved properties | $ 526,270 | $ 720,159 |
Proved properties | 1,545,860 | 1,288,609 |
Gross oil and natural gas properties | 2,072,130 | 2,008,768 |
Less accumulated depreciation depletion and amortization | (1,131,378) | (1,022,771) |
Total oil and natural gas properties, net | 940,752 | 985,997 |
Other property and equipment | 11,447 | 10,753 |
Less accumulated depreciation | (4,699) | (2,782) |
Other property and equipment, net | 6,748 | 7,971 |
Total property and equipment, net | $ 947,500 | $ 993,968 |
Summary of Significant Accoun43
Summary of Significant Accounting Policies - Summary of Accrued Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Accrued Liabilities Current [Abstract] | ||
Ad valorem and production taxes | $ 13,625 | $ 14,231 |
Employee compensation | 4,257 | 6,628 |
Royalties | 8,557 | 3,196 |
Short term derivatives | 35,409 | |
Other | 2,302 | 1,407 |
Total accrued liabilities | $ 64,150 | $ 25,462 |
Summary of Significant Accoun44
Summary of Significant Accounting Policies - Major Customers and Associated Percentage of Revenue (Detail) - Sales Revenue, Net [Member] - Customer Concentration Risk [Member] | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 63.00% | 70.00% | 72.00% |
Antero Resources Corporation [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 14.00% | 19.00% | 47.00% |
ARM Energy Management [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 11.00% | 25.00% | |
Concord Energy, LLC [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 12.00% | ||
Enlink Midstream Operating [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 17.00% | 21.00% | |
Sequent Energy Management [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 20.00% | 19.00% |
Summary of Significant Accoun45
Summary of Significant Accounting Policies - Summary for Concentration of Receivables, Net of Allowances, By Product or Service (Detail) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $ 43,638 | $ 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 | 41,398 | 19,858 |
Product Concentration Risk [Member] | Joint Interest Owners [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 2,065 | 3,095 |
Product Concentration Risk [Member] | Derivatives [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 122 | $ 4,523 |
Product Concentration Risk [Member] | Other [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $ 53 |
Summary of Significant Accoun46
Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Asset Retirement Obligation [Abstract] | |||
Asset retirement obligations, beginning of period | $ 3,401 | $ 17,400 | $ 9,055 |
Liabilities associated with assets held for sale | (19,057) | ||
Revisions of prior estimates | 2,913 | 6,470 | |
Additional liabilities incurred | 1,014 | 522 | 1,084 |
Accretion | 391 | 1,623 | 791 |
Asset retirement obligations, end of period | $ 4,806 | $ 3,401 | $ 17,400 |
Acquisition - Additional Inform
Acquisition - Additional Information (Detail) - Eclipse Resources Operating, LLC ("Eclipse Operating") [Member] $ in Millions | Jun. 24, 2014USD ($) |
Business Acquisition [Line Items] | |
Total consideration | $ 0.1 |
Recognized gain on bargain purchase | $ 0.4 |
Sale of Oil and Natural Gas P48
Sale of Oil and Natural Gas Property Interests - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2016USD ($)a | Dec. 31, 2015USD ($)a | Dec. 31, 2014USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Proceeds from the sale of central processing facility | $ 79,201,000 | $ 40,139,000 | $ 15,460,000 |
Sale of conventional oil and gas properties and related equipment | 4,700,000 | ||
Gain on sale of assets | (6,936,000) | 4,737,000 | 960,000 |
Assets held for sale | 468,000 | 21,971,000 | |
Gain or loss on sale of conventional oil and gas properties and related equipment | 1,100,000 | ||
Proceeds from sale of unproved lease properties | 3,900,000 | ||
Gain or Loss on sale of oil and natural gas properties | 0 | ||
Proceeds from sale of unproved lease properties | 4,800,000 | ||
Gain or Loss on sale of oil and natural gas properties | 0 | ||
Acreage Trades [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Gain or loss on sale of conventional oil and gas properties and related equipment | 0 | $ 0 | |
Proceeds from sale of asset | $ 1,600,000 | ||
Area of land | a | 249.5 | 10,500 | |
Acres exchange in first trade | a | 7,000 | ||
Credit related to reimbursement of capital expenditures | $ 17,500,000 | ||
Maximum [Member] | Acreage Trades [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Acres exchange in trade | a | 1,500 | ||
Assets Held for Sale [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Cost related to sale of oil and gas properties | $ 21,800,000 | ||
Asset retirement obligations related to sale of oil and gas properties | 19,100,000 | ||
Asset Sale [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Gain on sale of assets | $ (7,600,000) | ||
Proceeds from sale of asset | $ 63,800,000 | ||
Area of land | a | 9,900 | ||
Facility And Pipeline Sales [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Proceeds from the sale of central processing facility | 16,800,000 | ||
Proceeds received from sale of central processing facility | 15,500,000 | ||
Gain sale of central processing facility | $ 1,000,000 | ||
Sale of conventional oil and gas properties and related equipment | 2,800,000 | ||
Gain on sale of assets | (100,000) | ||
Central Processing Facility and Certain Pipelines [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Sale of conventional oil and gas properties and related equipment | 36,000,000 | ||
Gain on sale of assets | 4,800,000 | ||
Pipelines [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Sale of conventional oil and gas properties and related equipment | $ 400,000 | ||
Assets held for sale | $ 200,000 | ||
Pipelines [Member] | Maximum [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Gain on sale of assets | $ (100,000) |
Derivative Instruments - Summar
Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail) | 12 Months Ended |
Dec. 31, 2016MMBTU$ / MMBTU$ / galbblgal | |
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 ($/MMBtu) | 2.98 |
Natural Gas Derivatives Production Period March 2017 – December 2017 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 10,000 |
Weighted Average Price ($/MMBtu) | 3.21 |
NGL Derivatives Production Period January 2017 – December 2017 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (Gal/d) | gal | 84,000 |
Weighted Average Price ($/Gal) | $ / gal | 0.60 |
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 | 130,000 |
Weighted Average Price ($/MMBtu) | 2.85 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Purchased [Member] | Floor Three [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/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 ($/MMBtu) | 2.25 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2018 [Member] | Put Purchased [Member] | Floor One [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price ($/MMBtu) | 2.90 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2018 – December 2018 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 80,000 |
Weighted Average Price ($/MMBtu) | 2.90 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2018 – December 2018 [Member] | Put Purchased [Member] | Floor Two [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 40,000 |
Weighted Average Price ($/MMBtu) | 2.75 |
Put Option [Member] | Natural Gas Derivatives Production Period January 2018 – December 2018 [Member] | Put Sold [Member] | Floor Three [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 80,000 |
Weighted Average Price ($/MMBtu) | 2.12 |
Put Option [Member] | Natural Gas Derivatives Production Period April 2017 – March 2019 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 3 |
Put Option [Member] | Natural Gas Derivatives Production Period April 2017 – March 2019 [Member] | Put Sold [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 2.20 |
Put Option [Member] | Natural Gas Derivatives Production Period October 2017 – December 2018 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price ($/MMBtu) | 2.90 |
Put Option [Member] | Natural Gas Derivatives Production Period October 2017 – December 2018 [Member] | Put Sold [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price ($/MMBtu) | 2.20 |
Put Option [Member] | Oil Derivatives Production Period January 2017 – September 2017 [Member] | Put Purchased [Member] | Floor [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/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 ($/MMBtu) | 38 |
Volume (Bbls/d) | bbl | 2,000 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Put Sold [Member] | Ceiling One [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 130,000 |
Weighted Average Price ($/MMBtu) | 3.24 |
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 ($/MMBtu) | 3.57 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2017 – December 2018 [Member] | Put Sold [Member] | Ceiling Two [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price ($/MMBtu) | 3.25 |
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 ($/MMBtu) | 3.75 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2018 – December 2018 [Member] | Put Sold [Member] | Ceiling Three [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 40,000 |
Weighted Average Price ($/MMBtu) | 3.27 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2018 – December 2018 [Member] | Put Sold [Member] | Ceiling [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 80,000 |
Weighted Average Price ($/MMBtu) | 3.31 |
Call Option [Member] | Natural Gas Derivatives Production Period April 2017 – March 2019 [Member] | Put Sold [Member] | Ceiling [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 30,000 |
Weighted Average Price ($/MMBtu) | 3.40 |
Call Option [Member] | Natural Gas Derivatives Production Period October 2017 – December 2018 [Member] | Put Sold [Member] | Ceiling [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
Weighted Average Price ($/MMBtu) | 3.50 |
Call Option [Member] | Natural Gas Derivatives Production Period January 2019 – December 2019 [Member] | Put Sold [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 10,000 |
Weighted Average Price ($/MMBtu) | 4.75 |
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 ($/MMBtu) | 59.50 |
Volume (Bbls/d) | bbl | 2,000 |
Call Option [Member] | Oil Derivatives Production Period January 2017 – December 2017 [Member] | Put Sold [Member] | Ceiling [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | 60 |
Volume (Bbls/d) | bbl | 2,000 |
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 ($/MMBtu) | 50 |
Volume (Bbls/d) | bbl | 1,000 |
TCO [Member] | Columbia [Member] | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Swap [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | MMBTU | 20,000 |
TCO [Member] | COLOMBIA | Natural Gas Derivatives Production Period January 2017 – December 2017 [Member] | Swap [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Weighted Average Price ($/MMBtu) | (0.19) |
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 | Dec. 31, 2016 | Dec. 31, 2015 | |
Derivatives, Fair Value [Line Items] | |||
Gross Amount | $ 50 | $ 45,793 | |
Netting Adjustments | [1] | (50) | (11,352) |
Net Amount Presented in Balance Sheets | 34,441 | ||
Gross Amount | (48,132) | (11,352) | |
Netting Adjustments | [1] | 50 | 11,352 |
Net Amount Presented in Balance Sheets | (48,082) | ||
Other Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 50 | 41,199 | |
Netting Adjustments | [1] | (50) | (8,158) |
Net Amount Presented in Balance Sheets | 33,041 | ||
Other Noncurrent Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 4,594 | ||
Netting Adjustments | [1] | (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 | (35,459) | ||
Netting Adjustments | [1] | 50 | |
Net Amount Presented in Balance Sheets | (35,409) | ||
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (12,673) | (3,194) | |
Netting Adjustments | [1] | $ 3,194 | |
Net Amount Presented in Balance Sheets | $ (12,673) | ||
[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 - Summ51
Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments | $ (52,338) | $ 56,021 | $ 20,791 |
Commodity Contract [Member] | Gain (Loss) on Derivative Instruments [Member] | |||
Derivative Instruments, Gain (Loss) [Line Items] | |||
Gain (loss) on derivative instruments | $ (52,338) | $ 56,021 | $ 20,791 |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Fair Value Measured on a Recurring Basis (Detail) - Fair Value, Measurements, Recurring - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | $ (48,082) | $ 34,441 |
Commodity Contract [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | (48,082) | 34,441 |
Level 2 [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | (48,082) | 34,441 |
Level 2 [Member] | Commodity Contract [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | $ (48,082) | $ 34,441 |
Debt - Additional Information (
Debt - Additional Information (Detail) - USD ($) | Feb. 24, 2016 | Jul. 06, 2015 | Jun. 26, 2013 | Dec. 31, 2013 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Feb. 24, 2017 | Jul. 13, 2015 | Mar. 31, 2014 |
Debt Instrument [Line Items] | ||||||||||
Debt instrument interest rate | 8.875% | |||||||||
Gain (loss) on early extinguishment of debt | $ 14,489,000 | $ (59,392,000) | ||||||||
Debt instrument, covenant description | The indenture governing the senior unsecured notes 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 | $ 34,500,000 | |||||||||
Outstanding borrowings | 0 | |||||||||
Revolving Credit Facility [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Revolving credit facility | $ 500,000,000 | |||||||||
Applicable Margin | 0.50% | |||||||||
Percentage of additional mortgage to be delivered | 90.00% | |||||||||
Additional Period for the effectiveness of amendment | 60 days | |||||||||
Borrowing base | 125,000,000 | |||||||||
Available capacity on the Revolving Credit Facility | $ 90,500,000 | |||||||||
Credit facility, extended maturity month and year | 2020-01 | |||||||||
Commitment fees on unused portion of revolving credit facility | 0.05% | |||||||||
Revolving Credit Facility [Member] | Subsequent Event [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Borrowing base | $ 175,000,000 | |||||||||
Available capacity on the Revolving Credit Facility | $ 140,500,000 | |||||||||
12.0% Senior Unsecured PIK Notes Due 2018 [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, outstanding principal balance amount | $ 300,000,000 | $ 100,000,000 | $ 437,300,000 | |||||||
Debt instrument interest rate | 12.00% | 12.00% | ||||||||
Notes issued percentage price | 96.00% | |||||||||
Proceeds from debt instrument | $ 280,700,000 | 100,000,000 | ||||||||
Debt discount | 12,000,000 | 0 | ||||||||
Offering expenses | 7,300,000 | $ 200,000 | ||||||||
Debt instrument repurchased amount | $ 510,700,000 | |||||||||
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 (loss) on early extinguishment of debt | (59,400,000) | |||||||||
Amortization of deferred financing costs and debt discount | 1,900,000 | $ 4,100,000 | ||||||||
12.0% Senior Unsecured PIK Notes Due 2018 [Member] | Additional Notes Option [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, outstanding principal balance amount | $ 100,000,000 | |||||||||
8.875% Senior Unsecured Notes Due 2023 [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, outstanding principal balance amount | $ 550,000,000 | |||||||||
Debt instrument interest rate | 8.875% | |||||||||
Notes issued percentage price | 97.903% | |||||||||
Gain (loss) on early extinguishment of debt | 14,500,000 | |||||||||
Amortization of deferred financing costs and debt discount | 3,300,000 | $ 1,500,000 | ||||||||
Issuance date | Jul. 6, 2015 | |||||||||
Debt instrument, proceeds | $ 525,500,000 | |||||||||
Debt instrument, fair value | 533,100,000 | |||||||||
Principal amount outstanding | 39,500,000 | |||||||||
8.875% Senior Unsecured Notes Due 2023 [Member] | Open Market [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument repurchased amount | $ 23,400,000 |
Benefit Plans - Additional Info
Benefit Plans - Additional Information (Detail) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016USD ($)Employee | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Defined Benefit Plan Disclosure [Line Items] | |||
Gain on reduction of pension liability | $ | $ 2,208 | ||
Defined Benefit Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Matching contribution by the company to the plan | 100.00% | ||
Percentage of employees' eligible compensation | 6.00% | ||
Defined contribution plan, general and administrative expenses | $ | $ 700 | $ 900 | 400 |
Number of employees covered under defined benefit pension plan | 28 | ||
Gain on reduction of pension liability | $ | $ 2,200 | ||
Defined Benefit Pension Plan [Member] | Retired Employee [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Number of employees covered under defined benefit pension plan | 2 | ||
Defined Benefit Pension Plan [Member] | Deferred Vested Termination [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Number of employees covered under defined benefit pension plan | 4 | ||
Defined Benefit Pension Plan [Member] | Survivor [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Number of employees covered under defined benefit pension plan | 1 |
Benefit Plan - Summary of Pensi
Benefit Plan - Summary of Pension Benefit Obligation (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Change in benefit obligation | ||
Benefit obligation at beginning of year | $ 6,800 | |
Service cost | $ 70 | |
Interest cost | 239 | 335 |
Gain on reduction of pension liability | (2,208) | |
Actuarial (gain) loss | (775) | |
Benefits paid | (6,264) | |
Benefit obligation at end of period | 6,800 | |
Change in plan assets | ||
Fair value of plan assets at beginning of year | 5,479 | |
Actual return on plan assets | 14 | |
Employer contributions | 771 | |
Benefit paid | $ (6,264) | |
Fair value of plan assets at end of period | $ 5,479 |
Benefit Plans - Schedule of Def
Benefit Plans - Schedule of Defined Benefit Plan in Accumulated Other Comprehensive Income (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Accumulated Other Comprehensive Income Loss Net Of Tax [Abstract] | ||
Beginning amount recorded in other accumulated comprehensive income (loss) | $ (548) | |
Amounts recorded in accumulated other comprehensive income (loss) consist of: | ||
Pension obligation adjustment, net of tax | 548 | $ (1,716) |
Total recorded in accumulated other comprehensive income | $ (548) |
Benefit Plans - Components of N
Benefit Plans - Components of Net Periodic Benefit Cost (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Defined Benefit Plan Net Periodic Benefit Cost [Abstract] | ||
Service cost | $ 70 | |
Interest cost | $ 239 | 335 |
Expected return on plan assets | (246) | (448) |
Amortization of transition obligation | 70 | |
Amortization of net (gain) loss | 42 | 29 |
Effect of settlement | 224 | |
Net period benefit cost | $ 259 | $ 56 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) $ in Millions | May 18, 2016Directorshares | May 11, 2015Directorshares | Oct. 07, 2014Directorshares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) |
May Two Thousand Fifteen [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Restricted stock expense | $ 0.3 | $ 0.6 | ||||
May Two Thousand Sixteen [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Restricted stock expense | $ 0.3 | |||||
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 | $ 0.3 | $ 0.1 | ||||
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 | $ 5 | |||||
Weighted average period for shares to vest | 1 year | |||||
Performance Units [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Unrecognized compensation cost | $ 3.1 | |||||
Weighted average period for shares to vest | 2 years | |||||
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 | $ 0.2 | |||||
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 | |||||
Number of shares are available for future grant | shares | 8,019,938 |
Stock-Based Compensation - Sche
Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | $ 6,216 | $ 4,635 | $ 256 |
Restricted Stock Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | 4,006 | 2,408 | 0 |
Performance Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | 1,922 | 1,297 | 0 |
Restricted Stock Issued to Directors [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | 556 | 827 | 138 |
Incentive Units [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock based compensation expense | $ (268) | $ 103 | $ 118 |
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 | 12 Months Ended |
Dec. 31, 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 | 3,751,931 |
Number of shares, Vested | shares | (340,879) |
Number of shares, Forfeited | shares | (67,522) |
Number of shares, Ending Balance | shares | 4,343,582 |
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 | $ | $ 11,597 |
Stock-Based Compensation - Su61
Stock-Based Compensation - Summary of Performance Stock Unit Awards Activity (Detail) - Performance Units [Member] $ / shares in Units, $ in Thousands | 12 Months Ended |
Dec. 31, 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 | $ | $ 5,148 |
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 | Jun. 25, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||
Shares Issued | 37,500,000 | 30,300,000 | |||
Proceeds from initial public offering | $ 123.8 | $ 544.7 | |||
Number of shares issued and sold | 62,500,000 | ||||
Stock price, per share | $ 3.50 | ||||
Proceeds from issuance of Common Stock | $ 434 | ||||
Stock Sold by Company [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||
Shares Issued | 21,500,000 | ||||
Stock Sold by Selling Stockholders [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||
Shares Issued | 8,800,000 | ||||
IPO [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||
Shares Issued | 21,500,000 | ||||
Offering expense | $ 35.8 | ||||
Private Placement [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||
Stock price, per share | $ 7.04 |
Earnings (Loss) Per Share - Sch
Earnings (Loss) Per Share - Schedule of Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Loss (numerator): | |||||||||||
Net loss | $ (63,307) | $ (26,801) | $ (73,011) | $ (40,687) | $ (813,869) | $ (81,468) | $ (41,970) | $ (34,103) | $ (203,806) | $ (971,410) | $ (183,176) |
Weighted-average shares (denominator): | |||||||||||
Weighted-average number of shares of common stock—basic and diluted | 241,434 | 217,897 | 144,369 | ||||||||
Loss per share: | |||||||||||
Basic and diluted | $ (0.23) | $ (0.10) | $ (0.33) | $ (0.18) | $ (3.66) | $ (0.37) | $ (0.19) | $ (0.17) | $ (0.84) | $ (4.46) | $ (1.27) |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions | 6 Months Ended | 12 Months Ended | |||
Jun. 23, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2010 | |
Related Party Transaction [Line Items] | |||||
Accrued liability | $ 1 | ||||
Actual distribution of accrued liabilities to former shareholders | 0.6 | ||||
Reduction of initial gain recorded on acquisition | 0.4 | ||||
Administrative and Management Services [Member] | |||||
Related Party Transaction [Line Items] | |||||
Management fee expense | $ 15.6 | ||||
President and Chief Executive Officer of Eclipse I, its Executive Vice President, Secretary, and General Counsel and its Executive Vice President and Chief Operating Officer [Member] | |||||
Related Party Transaction [Line Items] | |||||
Percentage of membership units owned by related party | 33.00% | ||||
Chairman President and Chief Executive Officer [Member] | |||||
Related Party Transaction [Line Items] | |||||
Flight charter services fees | $ 0.6 | $ 0.3 | $ 0.2 | ||
Eclipse Resources Operating, LLC ("Eclipse Operating") [Member] | Administrative and Management Services [Member] | |||||
Related Party Transaction [Line Items] | |||||
Total consideration | $ 0.1 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) $ in Millions | 12 Months Ended | ||
Dec. 31, 2016USD ($)a | Dec. 31, 2015USD ($) | Dec. 31, 2014USD ($) | |
Loss Contingencies [Line Items] | |||
Lease agreement period | 5 years | ||
Capitalized leasehold costs | $ 0.7 | ||
Lease agreement, term | The Company leases office space under an operating lease that expires in 2024. | ||
Rent expense | $ 0.9 | $ 1.1 | $ 0.3 |
Other Lawsuit [Member] | |||
Loss Contingencies [Line Items] | |||
Area of leasehold property held | a | 60 |
Commitments and Contingencies66
Commitments and Contingencies - Future Minimum Lease Payments Required Under Lease Agreements (Detail) $ in Thousands | Dec. 31, 2016USD ($) |
Commitments And Contingencies Disclosure [Abstract] | |
2,017 | $ 637 |
2,018 | 637 |
2,019 | 637 |
2,020 | 690 |
2,021 | 684 |
Thereafter | 2,052 |
Total minimum lease payments | $ 5,337 |
Commitments and Contingencies67
Commitments and Contingencies - Other Commitments (Detail) $ in Thousands | Dec. 31, 2016USD ($) | |
Other Commitments [Line Items] | ||
2,017 | $ 68,115 | |
2,018 | 134,235 | |
2,019 | 128,927 | |
2,020 | 117,314 | |
2,021 | 105,391 | |
Thereafter | 205,766 | |
Total | 759,748 | |
Drilling Rig Commitments [Member] | ||
Other Commitments [Line Items] | ||
2,017 | 8,937 | [1] |
Total | 8,937 | [1] |
Firm Transportation [Member] | ||
Other Commitments [Line Items] | ||
2,017 | 49,748 | [2] |
2,018 | 118,316 | [2] |
2,019 | 111,787 | [2] |
2,020 | 109,593 | [2] |
2,021 | 105,391 | [2] |
Thereafter | 205,766 | [2] |
Total | 700,601 | [2] |
Gas Processing, Gathering, and Compression Services [Member] | ||
Other Commitments [Line Items] | ||
2,017 | 9,430 | [3] |
2,018 | 15,919 | [3] |
2,019 | 17,140 | [3] |
2,020 | 7,721 | [3] |
Total | $ 50,210 | [3] |
[1] | Drilling rig commitments -The Company had contracts for the service of two rigs, which one expires in August 2017 with the option to extend and one expires in September 2017. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest, as applicable. | |
[2] | Firm transportation -The Company has entered into firm transportation agreements with various pipelines in order to facilitate the delivery of production to market. These contracts commit the Company to transport minimum daily natural gas or NGL volumes at a negotiated rate, or pay for any deficiencies at a specified reservation fee rate. The amounts in this table represent the minimum daily volumes at the reservation fee rate. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements the Company’s proportionate share of costs based on its working interest. | |
[3] | Gas processing, gathering, and compression services -Contractual commitments for gas processing, gathering and compression service agreements represent minimum commitments under long-term gas processing agreements as well as various gas compression agreements. The values in the table represent the gross amounts that the Company is committed to pay and does not deduct amounts that other parties are responsible for as a result of cost sharing arrangements with working interest partners. The Company will record in its consolidated financial statements its proportionate share of costs based on the Company’s working interest.” |
Commitments and Contingencies68
Commitments and Contingencies - Other Commitments (Parenthetical) (Detail) | 12 Months Ended |
Dec. 31, 2016Rig | |
Other Commitments [Line Items] | |
Number of drilling rigs under service contract | 2 |
Rig Expires in September 2017 [Member] | |
Other Commitments [Line Items] | |
Drilling rig commitments, contract expiration year and month | 2017-08 |
Number of drilling rigs | 1 |
Rig Expires in April 2018 [Member] | |
Other Commitments [Line Items] | |
Drilling rig commitments, contract expiration year and month | 2017-09 |
Number of drilling rigs | 1 |
Income Tax - Additional Informa
Income Tax - Additional Information (Detail) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |||
Percentage of annual effective income tax rate | 0.27% | ||
Valuation allowance | $ 362,558,000 | $ 292,271,000 | |
U.S. federal tax loss carryforwards ("NOL") | $ 426,000,000 | ||
Tax loss carryforwards expiration year | 2,034 | ||
Reserve for uncertain tax positions | $ 0 | $ 0 | $ 0 |
Income Tax - Segregation of Inc
Income Tax - Segregation of Income Tax Provision Based on Location of Operations (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Current | |||
Federal | $ 0 | $ 0 | $ 0 |
State | 6 | 315 | 132 |
Total current | 6 | 315 | 132 |
Deferred | |||
Federal | (72,413) | 71,838 | |
State | 540 | (348) | (171) |
Total deferred | 540 | (72,761) | 71,667 |
Total income tax expense (benefit) | $ 546 | $ (72,446) | $ 71,799 |
Income Tax - Schedule of Effect
Income Tax - Schedule of Effective Income Tax Rate Reconciliation (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |||
Loss before income taxes | $ (203,260) | $ (1,043,856) | $ (111,377) |
Statutory rate | 35.00% | 35.00% | 35.00% |
Income tax benefit computed at statutory rate | $ (71,141) | $ (365,350) | $ (38,982) |
Reconciling items: | |||
Non-deductible pre-IPO loss | 13,264 | ||
State income taxes | 546 | (21) | (39) |
Other, net | 854 | 795 | 71 |
Change in tax status | 97,609 | ||
Gain on acquisition of Eclipse Operating | (141) | (124) | |
Change in valuation allowance | 70,287 | 292,271 | |
Total income tax expense (benefit) | $ 546 | $ (72,446) | $ 71,799 |
Income Tax - Components of Defe
Income Tax - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred tax asset: | ||
Oil and gas properties and equipment | $ 193,095 | $ 235,884 |
Federal tax loss carryforwards | 149,088 | 65,491 |
Derivative instruments and other | 16,829 | |
State effect of deferreds | 540 | |
Other, net | 4,259 | 3,434 |
Deferred tax asset | 363,271 | 305,349 |
Valuation allowance | (362,558) | (292,271) |
Net deferred tax assets | 713 | 13,078 |
Deferred tax liability: | ||
Derivative instruments and other | 12,054 | |
Other, net | 713 | 484 |
Net deferred tax liability | $ 713 | 12,538 |
Net deferred tax asset | $ 540 |
Subsidiary Guarantors - Additio
Subsidiary Guarantors - Additional Information (Detail) | Dec. 31, 2016 |
Guarantees [Abstract] | |
Debt instrument interest rate | 8.875% |
Quarterly Financial Informati74
Quarterly Financial Information (unaudited) (Detail) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total operating revenues | $ 83,883 | $ 54,479 | $ 47,066 | $ 49,606 | $ 65,882 | $ 71,172 | $ 74,453 | $ 43,814 | $ 235,034 | $ 255,321 | $ 137,816 |
Total operating expenses | 90,745 | 79,530 | 83,865 | 95,367 | 911,187 | 123,462 | 114,909 | 93,248 | 349,507 | 1,242,806 | 221,990 |
Operating loss | (6,862) | (25,051) | (36,799) | (45,761) | (845,305) | (52,290) | (40,456) | (49,434) | (114,473) | (987,485) | (84,174) |
Net loss | $ (63,307) | $ (26,801) | $ (73,011) | $ (40,687) | $ (813,869) | $ (81,468) | $ (41,970) | $ (34,103) | $ (203,806) | $ (971,410) | $ (183,176) |
Loss per share: | |||||||||||
Basic and diluted | $ (0.23) | $ (0.10) | $ (0.33) | $ (0.18) | $ (3.66) | $ (0.37) | $ (0.19) | $ (0.17) | $ (0.84) | $ (4.46) | $ (1.27) |
Supplemental Oil and Natural 75
Supplemental Oil and Natural Gas Information - Summary of Capitalized Costs (Detail) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Oil and natural gas properties: | ||
Unproved properties | $ 526,270 | $ 720,159 |
Proved properties | 1,545,860 | 1,288,609 |
Total oil and natural gas properties | 2,072,130 | 2,008,768 |
Less accumulated depreciation, depletion and amortization | (1,131,378) | (1,022,771) |
Net oil and natural gas properties | $ 940,752 | $ 985,997 |
Supplemental Oil and Natural 76
Supplemental Oil and Natural Gas Information - Summary of Costs Incurred in Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Acquisition costs: | |||
Unproved properties | $ 24,764 | $ 24,722 | $ 134,156 |
Development cost | 150,778 | 259,655 | 714,796 |
Exploration cost | 20,127 | 20,530 | 21,186 |
Total acquisition, development and exploration costs | $ 195,669 | $ 304,907 | $ 870,138 |
Supplemental Oil and Natural 77
Supplemental Oil and Natural Gas Information - Proved Developed and Proved Undeveloped Reserves (Detail) | 12 Months Ended | ||
Dec. 31, 2016BcfeBcfMBbls | Dec. 31, 2015BcfeBcfMBbls | Dec. 31, 2014BcfeBcfMBbls | |
Reserve Quantities [Line Items] | |||
Proved Developed and Undeveloped Reserves (energy), beginning balance | Bcfe | 348.8 | 355.8 | 78.5 |
Revisions (energy) | Bcfe | 14.8 | (152.9) | (19.3) |
Extensions and discoveries (energy) | Bcfe | 196.1 | 221.7 | 323.1 |
Production (energy) | Bcfe | (83.7) | (75.9) | (26.5) |
Proved Developed and Undeveloped Reserves (energy), ending balance | Bcfe | 469.4 | 348.8 | 355.8 |
Acquisitions (energy) | Bcfe | 4.1 | ||
Divestitures (energy) | Bcfe | (10.7) | ||
Proved developed reserves (energy) | Bcfe | 297.8 | 278.4 | 196.8 |
Proved undeveloped reserves (energy) | Bcfe | 171.6 | 70.3 | 159 |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed and Undeveloped Reserves, beginning balance | Bcf | 274.1 | 256.3 | 52.3 |
Revisions | Bcf | (0.1) | (115.3) | (12.1) |
Extensions and discoveries | Bcf | 175.4 | 182.6 | 235.8 |
Acquisitions | Bcf | 3.8 | ||
Divestitures | Bcf | (5.9) | ||
Production | Bcf | (60.9) | (49.5) | (19.8) |
Proved Developed and Undeveloped Reserves, ending balance | Bcf | 386.4 | 274.1 | 256.3 |
Proved developed reserves | Bcf | 226.1 | 209.5 | 133 |
Proved undeveloped reserves | Bcf | 160.4 | 64.5 | 123.4 |
Natural Gas Liquids [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed and Undeveloped Reserves, beginning balance | 7,758.7 | 10,879 | 1,938.4 |
Revisions | 1,273.7 | (4,705.7) | (739.7) |
Extensions and discoveries | 2,156 | 4,035.7 | 10,216.3 |
Acquisitions | 24.8 | ||
Divestitures | (91.5) | ||
Production | (2,446.2) | (2,450.3) | (536) |
Proved Developed and Undeveloped Reserves, ending balance | 8,675.5 | 7,758.7 | 10,879 |
Proved developed reserves | 7,520 | 7,245.7 | 6,758.6 |
Proved undeveloped reserves | 1,155.5 | 513 | 4,120.4 |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed and Undeveloped Reserves, beginning balance | 4,693.1 | 5,697.4 | 2,417.4 |
Revisions | 1,196.8 | (1,550.1) | (462.6) |
Extensions and discoveries | 1,300.2 | 2,496.3 | 4,337.5 |
Acquisitions | 15.1 | ||
Divestitures | (703.7) | ||
Production | (1,343.8) | (1,950.5) | (594.9) |
Proved Developed and Undeveloped Reserves, ending balance | 5,157.7 | 4,693.1 | 5,697.4 |
Proved developed reserves | 4,439.5 | 4,239.2 | 3,880.9 |
Proved undeveloped reserves | 718.1 | 453.9 | 1,816.4 |
Supplemental Oil And Natural 78
Supplemental Oil And Natural Gas Information - Additional Information (Detail) - Bcfe | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Extractive Industries [Abstract] | |||
Extension and discoveries | 196.1 | 221.7 | 323.1 |
Discount rate | 10.00% |
Supplemental Oil and Natural 79
Supplemental Oil and Natural Gas Information - Standardized Measure of Discounted Net Future Cash Flows (Detail) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 |
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract] | ||||
Future cash inflows (total revenues) | $ 1,143,142 | $ 975,664 | $ 1,870,319 | |
Future production costs | (725,724) | (592,073) | (728,041) | |
Future development costs (capital costs) | (116,988) | (83,532) | (350,187) | |
Future income tax expense | (277,500) | |||
Future net cash flows | 300,430 | 300,059 | 514,591 | |
10% annual discount for estimated timing of cash flows | (94,449) | (87,194) | (183,934) | |
Standardized measure of Discounted Future Net Cash Flow | $ 205,981 | $ 212,865 | $ 330,657 | $ 155,295 |
Supplemental Oil and Natural 80
Supplemental Oil and Natural Gas Information - Changes in Standardized Measure of Discounted Net Cash Flows (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized Measure, beginning of the year | $ 212,865 | $ 330,657 | $ 155,295 |
Net change in prices and production costs | (33,507) | (372,664) | (52,642) |
Net change in future development costs | 1,552 | 79,244 | (2,122) |
Sales, less production costs | (99,768) | (121,646) | (104,099) |
Extensions | 79,941 | 107,749 | 491,067 |
Acquisitions | 1,045 | ||
Divestitures | (5,231) | ||
Revisions of previous quantity estimates | 15,754 | (97,210) | (38,201) |
Previously estimated development costs incurred | 4,886 | 62,906 | 16,807 |
Accretion of discount | 21,287 | 50,939 | 15,529 |
Net change in taxes | 178,732 | (178,732) | |
Changes in timing and other | 7,157 | (5,842) | 27,755 |
Standardized Measure, end of year | $ 205,981 | $ 212,865 | $ 330,657 |