Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | ||
In Millions, except Share data, unless otherwise specified | Dec. 31, 2014 | Mar. 06, 2015 | Jun. 30, 2014 |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | FALSE | ||
Document Period End Date | 31-Dec-14 | ||
Document Fiscal Year Focus | 2014 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | ECR | ||
Entity Registrant Name | Eclipse Resources Corp | ||
Entity Central Index Key | 1600470 | ||
Current Fiscal Year End Date | -19 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 222,531,115 | ||
Entity Public Float | $761 |
Consolidated_Balance_Sheets
Consolidated Balance Sheets (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | |
In Thousands, unless otherwise specified | |||
CURRENT ASSETS | |||
Cash and cash equivalents | $67,517 | $109,509 | |
Accounts receivable | 46,378 | 8,678 | |
Assets held for sale | 20,673 | ||
Other current assets | 19,711 | 594 | |
Total current assets | 154,279 | 118,781 | |
Oil and natural gas properties, successful efforts method | |||
Unproved properties | 1,044,469 | 926,812 | |
Proved properties, net | 670,255 | 88,932 | |
Other property and equipment, net | 8,103 | 2,340 | |
Total property and equipment, net | 1,722,827 | 1,018,084 | |
OTHER NONCURRENT ASSETS | |||
Debt issuance costs, net of $2.5 million and $0.8 million of amortization, respectively | 6,058 | 6,570 | |
Other assets | 1,782 | 88 | |
Total other noncurrent assets | 7,840 | 6,658 | |
TOTAL ASSETS | 1,884,946 | 1,143,523 | |
CURRENT LIABILITIES | |||
Accounts payable | 137,415 | 29,368 | |
Accrued capital expenditures | 51,360 | 19,200 | |
Accrued liabilities | 13,576 | 4,940 | |
Accrued interest payable | 25,187 | 20,294 | |
Deferred income taxes | 5,246 | [1] | |
Accrued liabilities-related party | 1,951 | ||
Total current liabilities | 232,784 | 75,753 | |
NONCURRENT LIABILITIES | |||
Debt, net of unamortized discount of $8.5 million and $10.8 million, respectively | 414,016 | 389,247 | |
Pension obligations | 1,321 | 1,497 | |
Asset retirement obligations | 17,400 | 9,055 | |
Deferred income taxes | 66,714 | [1] | |
Total noncurrent liabilities | 499,451 | 399,799 | |
COMMITMENTS AND CONTINGENCIES | |||
STOCKHOLDERS' EQUITY | |||
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 160,031,115 and 121,533,408 shares issued and outstanding | 1,600 | 1,215 | |
Additional paid in capital | 1,391,004 | 721,757 | |
Accumulated deficit | -239,345 | -56,169 | |
Accumulated other comprehensive income (loss) | -548 | 1,168 | |
Total stockholders' equity | 1,152,711 | 667,971 | |
Preferred stock, 50,000 shares authorized, no shares issued and outstanding | |||
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $1,884,946 | $1,143,523 | |
[1] | For the 2014 and 2013 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. |
Consolidated_Balance_Sheets_Pa
Consolidated Balance Sheets (Parenthetical) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Millions, except Share data, unless otherwise specified | ||
Statement of Financial Position [Abstract] | ||
Debt issuance costs, amortization | $2.50 | $0.80 |
Debt, unamortized discount | $8.50 | $10.80 |
Preferred stock shares authorized | 50,000 | 50,000 |
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 | 160,031,115 | 121,533,408 |
Common Stock Shares Outstanding | 160,031,115 | 121,533,408 |
Consolidated_Statements_of_Ope
Consolidated Statements of Operations (USD $) | 12 Months Ended | |||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
REVENUES | ||||
Oil and natural gas sales | $137,816 | $12,935 | $370 | |
Total revenues | 137,816 | 12,935 | 370 | |
OPERATING EXPENSES | ||||
Lease operating | 8,518 | 2,576 | 16 | |
Transportation, gathering and compression | 18,114 | 67 | ||
Production and ad valorem taxes | 7,084 | 77 | 1 | |
Depreciation, depletion and amortization | 89,218 | 6,163 | 404 | |
Exploration | 21,186 | 3,022 | 4,692 | |
General and administrative | 45,392 | 21,276 | 4,425 | |
Accretion of asset retirement obligations | 791 | 364 | ||
Impairment of proved oil and gas properties | 34,855 | 2,081 | ||
Gain on sale of assets | -960 | -372 | ||
Gain on reduction of pension obligations | -2,208 | 0 | ||
Total operating expenses | 221,990 | 35,626 | 9,166 | |
OPERATING LOSS | -84,174 | -22,691 | -8,796 | |
OTHER INCOME (EXPENSE) | ||||
Gain on derivative instruments | 20,791 | |||
Interest income (expense), net | -48,347 | -20,850 | 37 | |
Other income | 353 | |||
Total other income (expense), net | -27,203 | -20,850 | 37 | |
LOSS BEFORE INCOME TAXES | -111,377 | [1] | -43,541 | -8,759 |
INCOME TAX EXPENSE | 71,799 | [1] | ||
NET LOSS | ($183,176) | ($43,541) | ($8,759) | |
NET LOSS PER COMMON SHARE | ||||
Basic and diluted | ($1.27) | ($0.58) | ($0.63) | |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING | ||||
Basic and diluted | 144,369 | 75,261 | 13,880 | |
[1] | For the 2014 and 2013 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Loss (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Statement of Comprehensive Income [Abstract] | |||
Net loss | ($183,176) | ($43,541) | ($8,759) |
Other comprehensive loss: | |||
Pension obligation adjustment | -1,716 | 1,168 | |
TOTAL COMPREHENSIVE LOSS | ($184,892) | ($42,373) | ($8,759) |
Consolidated_Statements_of_Sto
Consolidated Statements of Stockholders' Equity and Partners' Capital (USD $) | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Accumulated Deficit [Member] | Accumulated Other Comprehensive Income (Loss) [Member] |
In Thousands, except Share data | |||||
Beginning Balances at Dec. 31, 2011 | $66,544 | $95 | $70,318 | ($3,869) | |
Beginning Balance, shares at Dec. 31, 2011 | 9,583,090 | ||||
Capital contributions | 69,554 | 95 | 69,459 | ||
Capital contributions, shares | 9,466,359 | ||||
Share-based compensation | 3 | 3 | |||
Distributions | -638 | -638 | |||
Net loss | -8,759 | -8,759 | |||
Ending Balances at Dec. 31, 2012 | 126,704 | 190 | 139,142 | -12,628 | |
Ending Balance, shares at Dec. 31, 2012 | 19,049,449 | ||||
Capital contributions | 583,597 | 1,025 | 582,572 | ||
Capital contributions, shares | 102,483,959 | ||||
Share-based compensation | 43 | 43 | |||
Pension obligation adjustment | 1,168 | ||||
Change in accumulated other comprehensive income | 1,168 | 1,168 | |||
Net loss | -43,541 | -43,541 | |||
Ending Balances at Dec. 31, 2013 | 667,971 | 1,215 | 721,757 | -56,169 | 1,168 |
Ending Balance, shares at Dec. 31, 2013 | 121,533,408 | ||||
Capital contributions | 124,667 | 170 | 124,497 | ||
Capital contributions, shares | 16,966,592 | ||||
Issuance of restricted stock | 0 | 0 | 0 | 0 | 0 |
Issuance of restricted stock, shares | 31,115 | ||||
Share-based compensation | 256 | 256 | |||
Pension obligation adjustment | -1,716 | -1,716 | |||
Shares of common stock issued in initial public offering | 550,025 | 215 | 549,810 | ||
Shares of common stock issued in initial public offering, shares | 21,500,000 | ||||
Costs related to initial public offering | -5,316 | -5,316 | |||
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 |
Consolidated_Statements_of_Sto1
Consolidated Statements of Stockholders' Equity and Partners' Capital (Parenthetical) (USD $) | Dec. 31, 2014 | Jun. 25, 2014 | Dec. 31, 2013 |
Statement of Stockholders' Equity [Abstract] | |||
Common stock, par value | $0.01 | $0.01 | $0.01 |
Consolidated_Statements_of_Cas
Consolidated Statements of Cash Flows (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||||
Net loss | ($183,176) | ($43,541) | ($8,759) | |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities | ||||
Depreciation, depletion and amortization | 89,218 | 6,163 | 404 | |
Exploration expense | 21,186 | 3,022 | 4,692 | |
Pension benefit costs | 56 | 575 | ||
Incentive unit compensation | 256 | 43 | 3 | |
Impairment of proved oil and gas properties | 34,855 | 2,081 | ||
Accretion of asset retirement obligations | 791 | 364 | ||
Gain on reduction of pension liability | -2,208 | 0 | ||
Gain on derivative instruments | -20,791 | |||
Net cash receipts on settled derivatives | 564 | |||
Net cash payments on option premiums | -385 | |||
Gain on sale of assets | -960 | -372 | ||
Gain on business acquisition | -353 | |||
Deferred income taxes | 71,667 | [1] | ||
Interest not paid in cash | 15,721 | 20,294 | ||
Amortization of deferred financing costs | 1,744 | 739 | ||
Amortization of debt discount | 2,308 | 1,247 | ||
Changes in operating assets and liabilities, net of acquisitions: | ||||
Accounts receivable | -33,605 | -5,971 | -172 | |
Other assets | -1,188 | 1,389 | 50 | |
Accounts payable and accrued liabilities | 29,517 | 27,276 | 747 | |
Accrued liabilities-affiliate | -1,951 | 1,569 | 26 | |
Net cash provided by (used in) operating activities | 23,266 | 15,250 | -3,381 | |
CASH FLOWS FROM INVESTING ACTIVITIES | ||||
Capital expenditures for oil and natural gas properties | -745,766 | -252,844 | -179,209 | |
Additions to other property and equipment | -3,637 | -892 | ||
Proceeds from the sale of oil and gas properties | 15,460 | 8,497 | 131,674 | |
Acquisition of business, net of cash acquired | 754 | -651,847 | ||
Net cash used in investing activities | -733,189 | -897,086 | -47,535 | |
CASH FLOWS FROM FINANCING ACTIVITIES | ||||
Proceeds from issuance of long-term debt | 388,000 | |||
Debt issuance costs | -1,232 | -7,309 | ||
Repayments of long-term debt | -213 | |||
Repayments (borrowings) under revolving credit facility | 0 | 0 | 0 | |
Capital contributions | 124,667 | 583,597 | 69,554 | |
Distributions | -638 | |||
Proceeds from issuance of common stock, net of underwriting fees | 550,025 | |||
Initial public offering costs | -5,316 | |||
Net cash provided by financing activities | 667,931 | 964,288 | 68,916 | |
Net increase (decrease) in cash and cash equivalents | -41,992 | 82,452 | 18,000 | |
Cash and cash equivalents at beginning of period | 109,509 | 27,057 | 9,057 | |
Cash and cash equivalents at end of period | 67,517 | 109,509 | 27,057 | |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||||
Cash paid for interest | 26,020 | |||
Cash paid for income taxes | 0 | 0 | 0 | |
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES: | ||||
Asset retirement obligations incurred, including changes in estimate | 7,554 | 300 | ||
Additions of other property through debt financing | 945 | |||
Additions to oil and natural gas properties-changes in accounts payable, accrued liabilities, and accrued capital expenditures | 126,656 | 17,537 | 1,663 | |
Assets and liabilities assumed in acquisition of Eclipse Resources-Ohio, LLC | 5,102 | |||
Assets held for sale associated with central gathering facility | 20,673 | |||
Interest paid-in-kind | $22,461 | |||
[1] | For the 2014 and 2013 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. |
Organization_and_Nature_of_Ope
Organization and Nature of Operations | 12 Months Ended | |||
Dec. 31, 2014 | ||||
Accounting Policies [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, 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 expects to use the remaining net proceeds to fund a portion of the capital expenditure plan. |
Basis_of_Presentation
Basis of Presentation | 12 Months Ended | |||
Dec. 31, 2014 | ||||
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 and as of December 31, 2013, and the years ended December 31, 2013 and 2012 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” describes our significant accounting policies. The Company’s management believes the major estimates and assumptions impacting the consolidated financial statements are the following: | ||||
• | estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion and amortization and impairment of capitalized costs of oil and natural gas properties; | |||
• | estimates of asset retirement obligations; | |||
• | estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells; | |||
• | impairment of undeveloped properties and other assets; and | |||
• | depreciation and depletion of property and equipment. | |||
Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions. |
Summary_of_Significant_Account
Summary of Significant Accounting Policies | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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, 2014 or December 31, 2013. | |||||||||||||
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 $24.1 million and $4.1 million of accrued revenues, net of expenses at December 31, 2014 and December 31, 2013, 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” below). | |||||||||||||
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. 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, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Oil and natural gas properties: | |||||||||||||
Unproved | $ | 1,044,469 | $ | 926,812 | |||||||||
Proved | 802,112 | 97,528 | |||||||||||
Gross oil and natural gas properties | 1,846,581 | 1,024,340 | |||||||||||
Less accumulated depreciation, depletion and amortization | (131,857 | ) | (8,596 | ) | |||||||||
Oil and natural gas properties, net | 1,714,724 | 1,015,744 | |||||||||||
Other property and equipment | 8,912 | 2,392 | |||||||||||
Less accumulated depreciation | (809 | ) | (52 | ) | |||||||||
Other property and equipment, net | 8,103 | 2,340 | |||||||||||
Property and equipment, net | $ | 1,722,827 | $ | 1,018,084 | |||||||||
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. | |||||||||||||
Other Property and Equipment | |||||||||||||
Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. | |||||||||||||
(d) Revenue Recognition | |||||||||||||
Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil 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, 2014 and December 31, 2013. | |||||||||||||
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. | |||||||||||||
(e) Major Customers | |||||||||||||
The Company sells production volumes to various purchasers. For the years ended December 31, 2014, 2013 and 2012, there were two, four, and one customer that accounted for 10% or more of the total natural gas, NGLs and oil sales. Management believes that the loss of any one customer would not have an adverse effect on the Company’s ability to sell natural gas, NGLs and oil production. 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, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Purchaser | |||||||||||||
Antero Resources Corporation | 47 | % | 38 | % | 100 | % | |||||||
Devco Oil Inc. | — | 24 | % | — | |||||||||
Dominion Resources Inc. | — | 13 | % | — | |||||||||
ARM Energy Management | 25 | % | — | — | |||||||||
Ergon | — | 12 | % | — | |||||||||
Total | 72 | % | 87 | % | 100 | % | |||||||
Management believes that there are potential alternative purchasers and that 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. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company’s purchasers are credit worthy. | |||||||||||||
(f) Concentration of Credit Risk | |||||||||||||
The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Receivables by product or service: | |||||||||||||
Sale of oil and natural gas and related products and services | $ | 22,777 | $ | 4,092 | |||||||||
Joint interest owners | 20,666 | 4,586 | |||||||||||
Miscellaneous other | 2,935 | — | |||||||||||
Total | $ | 46,378 | $ | 8,678 | |||||||||
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 derivative contracts is a net asset position of $19.0 million at December 31, 2014. 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, 2014, the Company did not have past-due receivables from or payables to any of the counterparties. | |||||||||||||
(g) Accumulated Other Comprehensive Income (Loss) | |||||||||||||
Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include a pension benefit plan that requires the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was underfunded by $1.3 million and $1.5 million at December 31, 2014 and December 31, 2013, respectively. 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. No such gain was recorded for the year ended December 31, 2013. | |||||||||||||
(h) 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, 2014, 2013 and 2012 totaled approximately $88.4 million, $5.9 million and $0.2 million, respectively. | |||||||||||||
Through September 30, 2014, the Company calculated depletion of proved properties at the individual unit level. Effective October 1, 2015, 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. As a result of this change, DD&A expense recorded by the Company for the year ended December 31, 2014 was $1.3 million lower than it would have been if the Company had not made this change. | |||||||||||||
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, 2014, 2013, and 2012 totaled approximately $0.8 million, $0.3 million and $0.2 million, respectively. This amount is included in DD&A expense in the consolidated statements of operations. | |||||||||||||
(i) 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 consists of three fields, including Conventional production, 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 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. The Company recognized impairment expenses relating to proved properties of $34.9 million and $2.1 million for the years ended December 31, 2014 and 2013, respectively. Approximately $30.9 million of the impairment recorded for the year ended December 31, 2014 was recorded during the fourth quarter of 2014 as a result of the significant decline in oil and natural gas commodity prices during the quarter related to the conventional properties acquired during the Oxford Acquisition. The remaining $4.0 million related to unconventional properties in the Utica Shale. There were no impairments of proved properties for the year ended December 31, 2012. | |||||||||||||
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 properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $5.7 million and $0.8 million for the years ended December 31, 2014 and 2012, respectively. These costs are included in exploration expense in the consolidated statements of operations. No such impairments were recorded for year ended December 31, 2013. | |||||||||||||
(j) 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. | |||||||||||||
The FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company recognizes fines and penalties as income tax expense. | |||||||||||||
(k) 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. | |||||||||||||
(l) 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. | |||||||||||||
(m) 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,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 9.89% and 8.96% for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||
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. As of December 31, 2014, management revised its assumptions relating to certain wells including useful lives, working interest, and abandonment costs. These revisions increased the asset retirement obligation for the wells, and as a result, the Company recorded an incremental layer of approximately $6.5 million. | |||||||||||||
The following table sets forth the changes in the Company’s ARO liability for the period indicated (in thousands): | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Asset retirement obligations, beginning of period | $ | 9,055 | $ | 13 | $ | — | |||||||
Revisions of prior estimates | 6,470 | — | — | ||||||||||
Additional liabilities incurred | 1,084 | 300 | 13 | ||||||||||
Assumption of Oxford asset retirement obligations | — | 8,378 | — | ||||||||||
Accretion | 791 | 364 | — | ||||||||||
Asset retirement obligations, end of period | $ | 17,400 | $ | 9,055 | $ | 13 | |||||||
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. | |||||||||||||
(n) Lease Obligations | |||||||||||||
The Company leases office space under operating leases that expire between the years 2015—2025. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception. | |||||||||||||
(o) Off-Balance Sheet Arrangements | |||||||||||||
The Company does not have any off-balance sheet arrangements. | |||||||||||||
(p) 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. | |||||||||||||
(q) Debt Issuance Costs | |||||||||||||
The expenditures related to issuing debt are capitalized and included in other assets 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. | |||||||||||||
(r) Recent Accounting Pronouncements | |||||||||||||
The FASB issued ASU 2013-11, “Income Taxes (Topic 740)—Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” in December 2013. These amendments provide that an unrecognized tax benefit, or a portion thereof, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except to the extent that a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from disallowance of a tax position, or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, then the unrecognized tax benefit should be presented as a liability. These requirements were effective for annual reporting periods beginning after December 15, 2013, including interim periods within that reporting period. The adoption of this ASU did not impact the Company’s financial position, results of operations or liquidity. | |||||||||||||
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, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. | |||||||||||||
In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period, be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. | |||||||||||||
In April 2014, the FASB issued ASU 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360)”: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”. The objective of the amendments in this update is to change the criteria for reporting discontinued operations and enhance convergence of the FASB’s and the International Accounting Standard Board’s (IASB) reporting requirements for discontinued operations. The amendments in this update change the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity, or a business or nonprofit activity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update require an entity to present, for each comparative period, the assets and liabilities of a disposal group that includes a discontinued operation separately in the asset and liability sections, respectively, of the statement of financial position. The amendments in this update also require additional disclosures about discontinued operations. Public business entities must apply the amendments in this update prospectively to both of the following: (1) All disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years; (2) All businesses or nonprofit activities that, on acquisition, are classified as held for sale that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. | |||||||||||||
In August 2014, the FASB issued 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 periods ending after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have an impact on the Company’s financial statement disclosures. |
Acquisition
Acquisition | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
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. | |||||||||
The Eclipse Resources-Ohio, LLC Acquisition | |||||||||
On June 26, 2013, Eclipse I acquired (the “Oxford Acquisition”) 100% of the outstanding equity interests of Oxford. Oxford held interests in approximately 181,000 net acres of Utica Shale leaseholds, and related producing properties located primarily in Belmont, Guersney, Monroe, Noble, and Harrison Counties in Ohio along with various other related rights, permits, contracts, equipment and other assets. The aggregate purchase price totaled $652.5 million in cash. The acquisition provided strategic additions adjacent to the Company’s core project area. | |||||||||
The Purchase and Sales Agreement (“PSA”) for the Oxford Acquisition contained customary closing conditions and a $32.5 million escrow which was withheld from the initial purchase price to provide for certain contingencies. The notice period for any claims related to these contingencies expired June 25, 2014 and all amounts were released from escrow to the seller. The acquisition is accounted for using the acquisition method under ASC Topic 805, “Business Combinations” which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of July 26, 2013. The following table summarizes the purchase price allocation and the values of assets acquired and liabilities assumed (in thousands): | |||||||||
Purchase Price | June 26, 2013 | ||||||||
Consideration Given | |||||||||
Cash | $ | 652,500 | |||||||
Allocation of Purchase Price | |||||||||
Unproved properties | 621,039 | ||||||||
Proved properties | 40,914 | ||||||||
Cash | 653 | ||||||||
Building and land | 1,500 | ||||||||
Total assets | 664,106 | ||||||||
Asset retirement obligations | (8,378 | ) | |||||||
Pension obligation | (2,522 | ) | |||||||
Other working capital | (706 | ) | |||||||
Fair value of net assets acquired | $ | 652,500 | |||||||
The purchase price allocation set forth above represented a significant Level 3 measurement in the fair value hierarchy and was derived in accordance with ASC 805 by an outside third party. The inputs used in such determination were forecasted cash flows, market comparisons, actuarial studies and Oxford’s historical accounting records. | |||||||||
Immediately prior to the completion of the Oxford Acquisition, Oxford merged into Eclipse Resources—Ohio, LLC (“Eclipse Ohio”). Eclipse Ohio is party to various lawsuits, primarily related to the validity of certain oil and gas leases (see “Note 13—Commitments and Contingencies”). | |||||||||
Pro Forma Financial Information (unaudited) | |||||||||
The following unaudited pro forma financial information represents the combined results for the Company and Oxford for the years ended December 31, 2013 and 2012 as if the acquisition had occurred on January 1, 2012. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $3.4 million and $0.8 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of adjustments for amortization of financing costs of $0.7 million and $1.5 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of the amortization of debt discount of $1.2 million and $2.4 million for the years ended December 31, 2013 and 2012, respectively. The pro forma information includes the effects of the incremental interest expense on acquisition financing of $26.9 million and $53.9 million for the years ended December 31, 2013 and 2012, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of January 1, 2012, nor are they necessarily indicative of future results (in thousands). | |||||||||
For the Year Ended | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
Oil and natural gas sales | $ | 20,638 | $ | 13,936 | |||||
Net loss | $ | (71,131 | ) | $ | (56,065 | ) |
Sale_of_Oil_and_Natural_Gas_Pr
Sale of Oil and Natural Gas Property Interests | 12 Months Ended |
Dec. 31, 2014 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Sale of Oil and Natural Gas Property Interests | Note 5—Sale of Oil and Natural Gas Property Interests |
Effective March 16, 2012, the Partnership entered into a Purchase and Exploration Agreement (“PEA”) to sell 70% of its interests in certain unproved oil and gas properties. During 2012, the Partnership completed the sale of 21,114 net acres under the PEA for net proceeds of $126.5 million. The cumulative proceeds of the sale did not exceed the Partnership’s cost basis in the properties; therefore, no gain was recognized on the sale. | |
During the year ended December 31, 2012, the Partnership sold 70% of its interest in a proved oil and gas property for $5.2 million, before customary purchase price adjustments. The proceeds included $2.4 million for the sale of 70% of its net acreage in the unit and $2.8 million for the reimbursement of 70% of the Partnership’s net drilling costs incurred. The sales proceeds exceeded the Partnership’s cost basis in the unit, resulting in a gain of $0.4 million during 2012. | |
During the year ended December 31, 2013, the Partnership sold an additional 1,220 acres for net proceeds of $8.5 million. The cumulative proceeds of the sale did not exceed the Partnership’s cost basis in the properties; therefore, no gain was recognized on the sale. | |
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. | |
As of December 31, 2014, the Company was actively negotiating the sale of a second central processing facility, which is expected to close during 2015. As a result, costs related to this facility of approximately $20.7 million are classified as assets held for sale in the consolidated balances sheets as of December 31, 2014. | |
Derivative_Instruments
Derivative Instruments | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||
Derivative Instruments | Note 6—Derivative Instruments | ||||||||||||||||
Commodity derivatives | |||||||||||||||||
The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas. The Company currently uses a mix of over-the-counter (“OTC”) natural gas fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to natural gas price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes. | |||||||||||||||||
The Company is exposed to credit risk in the event of non-performance by counterparties. The creditworthiness of counterparties is subject to continuing review. The Company has not experienced any issues of non-performance by derivative counterparties. | |||||||||||||||||
Below is summary of the Company’s derivative instrument positions, as of December 31, 2014, for future production periods: | |||||||||||||||||
Description | Volume | Production Period | Weighted Average | ||||||||||||||
(MMBtu/d) | Price ($/MMBtu) | ||||||||||||||||
Natural Gas Swaps: | |||||||||||||||||
66,219 | January 2015—December 2015 | $ | 3.797 | ||||||||||||||
25,000 | January 2016—December 2016 | $ | 3.66 | ||||||||||||||
Natural Gas Three-way Collar: | |||||||||||||||||
Floor purchase price (put) | 15,000 | January 2015—December 2015 | $ | 3.6 | |||||||||||||
Ceiling sold price (call) | 15,000 | January 2015—December 2015 | $ | 3.8 | |||||||||||||
Floor sold price (put) | 15,000 | January 2015—December 2015 | $ | 3 | |||||||||||||
Natural Gas Put Sale: | |||||||||||||||||
Put sold | 16,800 | January 2015—December 2015 | $ | 3.35 | |||||||||||||
Natural Gas Collar: | |||||||||||||||||
Purchased put | 5,000 | January 2015—March 2015 | $ | 4 | |||||||||||||
Call sold | 5,000 | January 2015—March 2015 | $ | 4.75 | |||||||||||||
Basis Swaps: | |||||||||||||||||
25,000 | January 2015—March 2015 | $ | (1.067 | ) | |||||||||||||
25,000 | April 2015—October 2015 | $ | (1.208 | ) | |||||||||||||
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. | |||||||||||||||||
Derivatives not designated as hedging | Gross Amount | Netting | Net Amount | Balance Sheet | |||||||||||||
Adjustments(a) | Presented in the | Location | |||||||||||||||
instruments under ASC 815 | Balance Sheets | ||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Assets | |||||||||||||||||
Commodity derivatives—current | $ | 22,349 | $ | (5,012 | ) | $ | 17,337 | Other current assets | |||||||||
Commodity derivatives—noncurrent | 1,741 | (44 | ) | 1,697 | Other assets | ||||||||||||
Total assets | $ | 24,090 | $ | (5,056 | ) | $ | 19,034 | ||||||||||
Liabilities | |||||||||||||||||
Commodity derivatives—current | $ | (5,012 | ) | $ | 5,012 | $ | — | ||||||||||
Commodity derivatives—noncurrent | (44 | ) | 44 | — | |||||||||||||
Total liabilities | $ | (5,056 | ) | $ | 5,056 | $ | — | ||||||||||
(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. | ||||||||||||||||
At December 31, 2013, the Company did not have any derivative instruments in place. | |||||||||||||||||
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): | |||||||||||||||||
Location of Gain (Loss) | Years Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Commodity derivatives | Gain on derivative instruments | $ | 20,791 | $ | — | $ | — | ||||||||||
Fair_Value_Measurements
Fair Value Measurements | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
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 Fair Value | ||||||||||||||
As of December 31, 2014: (in thousands) | |||||||||||||||||
Commodity derivative instruments | $ | — | $ | 19,034 | $ | — | $ | 19,034 | |||||||||
Total | $ | — | $ | 19,034 | $ | — | $ | 19,034 | |||||||||
The Company did not have any assets or liabilities that were measured at fair value on a recurring basis as of December 31, 2013, except for pension assets as described in Note 9. | |||||||||||||||||
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(m)). | |||||||||||||||||
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(i)). | |||||||||||||||||
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, 2014 | |||||
Debt Disclosure [Abstract] | |||||
Debt | Note 8—Debt | ||||
12% Senior Unsecured PIK Notes Due 2018 | |||||
On June 26, 2013, Eclipse I 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 Eclipse I, of 12% Senior Unsecured PIK Notes due in 2018 (the “Senior Unsecured Notes”). The Senior Unsecured Notes were issued at 96% of par and Eclipse I 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, Eclipse I exercised its option and issued an additional $100 million of Senior Unsecured Notes with the same terms, at par. Eclipse I 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. During the year ended December 31, 2014, the Company amortized $4.1 of deferred financing costs and debt discount to interest expense using the effective interest method. | |||||
The Company has the right to redeem all or a portion of the Senior Unsecured Notes prior to the 2-year anniversary of the final funding date, which the Company refers to as the Non-Call Period, by paying a redemption price equal to 100.0% times a “make whole premium” equal to the greater of 106.0% or an amount computed under the Indenture governing the Senior Unsecured Notes (the “Indenture”) plus accrued and unpaid interest. After the Non-Call Period, the Company may redeem all or a part of the Senior Unsecured Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest: | |||||
Year following expiration of the Non-Call Period | Redemption Price | ||||
Year 1 | 106 | % | |||
Year 2 | 103 | % | |||
Year 3 and thereafter | 100 | % | |||
At the Company’s option, for the first 2 semi-annual interest payments following the issue date, interest may be payable by increasing the principal amount of the Senior Unsecured Notes or by issuing payment in kind (“PIK”) securities. Interest paid by issuing PIK securities accrues at 13%, interest paid by cash accrues at 12%. At the Company’s option, for the subsequent four semi-annual interest payments thereafter, interest may be payable in the form of 6.0% per annum in cash and 7.0% per annum in PIK securities. Thereafter, interest can only be paid as cash interest. Interest is payable on July 15 and January 15 each year, beginning in January 2014. The Company elected to settle its accrued interest payable on January 15, 2014 by issuing PIK securities of $22.5 million and settle its accrued interest payable on July 15, 2014 with a cash payment of $25.3 million. The Company elected to settle its accrued interest payable on January 15, 2015 by issuing PIK securities of $14.8 million and a cash payment of $12.7 million. | |||||
The Company’s obligations under the Senior Unsecured Notes are guaranteed by its 100% owned subsidiaries. The Company may not among other things, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not the Company is the survivor), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or more than 50% of its properties or assets, in one or more related transactions, to another Person, unless in each case certain restrictive conditions contained in the Indenture are met. | |||||
The Indenture requires the Company to be in compliance with certain other covenants, including the prompt payment of interest, including PIK interest, and any and all material taxes, assessments and government levies imposed; timely submission of quarterly and audited annual financial statements, reserve reports, budgets and other notices, and other recurring obligations. The Indenture places restrictions on the Company and its subsidiaries with respect to additional indebtedness, liens, dividends and other payments, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, change of control and other matters. The Company was in compliance with all applicable covenants in the Indenture at December 31, 2014. | |||||
The Senior Unsecured Notes are subject to certain events of default. If an event of default occurs and is continuing, the outstanding Senior Notes may, and under certain circumstances, will be accelerated. The purchasers of the Senior Notes are entitled to the benefits of a registration rights agreement pursuant to which the Company agreed to file a registration statement with the Securities and Exchange Commission to allow for the resale of the Notes under the Securities Act. | |||||
As of December 31, 2014, the principal amount outstanding related to the Senior Unsecured Notes was $422.5 million. The fair value of the Senior Unsecured Notes as of December 31, 2014 was $482.8 million. This fair value estimate is classified as Level 2 in the fair value hierarchy. The valuation techniques used are industry-standard models that consider various assumptions, including quoted forward rates, time value, volatility factors and current market and contractual rates, as well as other relevant economic measures. Substantially all of the assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. | |||||
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 quarterly redeterminations through April 1, 2015 and semiannual redeterminations thereafter. At December 31, 2014, the borrowing base was $100 million and the Company had no outstanding borrowings. After considering outstanding letters of credit issued by the Company, totaling $26.9 million, the Company had available capacity on the Revolving Credit Facility of $73.1 million at December 31, 2014. In March 2015, the borrowing base of the Revolving Credit Facility was redetermined, resulting in an increase in the borrowing base to $125 million. | |||||
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. | |||||
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, 2014. Commitment fees on the unused portion of the Revolving Credit Facility are due quarterly at rates ranging from 0.375% to 0.50% of the unused facility based on utilization. |
Benefit_Plans
Benefit Plans | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
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 contributed $0.4 million, $0.2 million and $0.1 million in matching contributions for the years ended December 31, 2014, 2013 and 2012, respectively. | |||||||||||||||||
Defined Benefit Plan | |||||||||||||||||
The Company maintains a defined benefit pension plan covering 28 of its employees, of which two are retired, four have deferred vested termination, and one is a survivor. Benefits are based on the employee’s years of service and compensation. The Partnership’s plans are funded in conformity with the funding requirements of ASC 715 as of December 31, 2014. As a result of the Oxford acquisition (refer to “Note 4” above) on June 26, 2013, the Partnership 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 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 as of the years ended December 31, 2014 and 2013 is set forth in the below tables (in thousands): | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Change in benefit obligation | |||||||||||||||||
Benefit obligation at beginning of year | $ | 9,018 | $ | — | |||||||||||||
Oxford assumed benefit obligations | — | 9,045 | |||||||||||||||
Service cost | 70 | 144 | |||||||||||||||
Interest cost | 335 | 203 | |||||||||||||||
Gain on reduction of pension liability | (2,208 | ) | — | ||||||||||||||
Actuarial loss | 1,616 | (350 | ) | ||||||||||||||
Benefits paid | (2,031 | ) | (24 | ) | |||||||||||||
Benefit obligation at end of period | $ | 6,800 | $ | 9,018 | |||||||||||||
Change in plan assets | |||||||||||||||||
Fair value of plan assets at beginning of year | $ | 7,521 | $ | — | |||||||||||||
Oxford assumed plan assets | — | 6,523 | |||||||||||||||
Actual return on plan assets | (11 | ) | 1,012 | ||||||||||||||
Employer contributions | — | 10 | |||||||||||||||
Benefit paid | (2,031 | ) | (24 | ) | |||||||||||||
Fair value of plan assets at December 31, 2014 | $ | 5,479 | $ | 7,521 | |||||||||||||
The funding level of the qualified pension plan is in compliance with standards set by applicable law or regulation. As shown in the table below, the current pension plan is underfunded. All defined benefit pension obligations, regardless of the funding status of the plan, are fully supported by the financial strength of the Company. | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Assets in excess of (less than) benefit obligation at December 31, | |||||||||||||||||
Vested amount | $ | (6,800 | ) | $ | (7,039 | ) | |||||||||||
Additional benefits required | — | (1,979 | ) | ||||||||||||||
Projected benefit obligation | (6,800 | ) | (9,018 | ) | |||||||||||||
Funded amount | 5,479 | 7,521 | |||||||||||||||
Unfunded amount | $ | (1,321 | ) | $ | (1,497 | ) | |||||||||||
Other amounts recognized in other comprehensive loss during the year ended December 31, | |||||||||||||||||
Assets in excess of (less than) benefit obligation at end of period | $ | (1,321 | ) | $ | (1,497 | ) | |||||||||||
Amounts recorded in the consolidated balance sheet consist of: | |||||||||||||||||
Accrued benefit liability | (1,321 | ) | (1,497 | ) | |||||||||||||
Total recorded | $ | (1,321 | ) | $ | (1,497 | ) | |||||||||||
Beginning amount recorded in other accumulated comprehensive income | $ | 1,168 | $ | — | |||||||||||||
Amounts recorded in accumulated other comprehensive loss consist of: | |||||||||||||||||
Pension obligation adjustment, net of tax | (1,716 | ) | 1,168 | ||||||||||||||
Total recorded in accumulated other comprehensive income | $ | (548 | ) | $ | 1,168 | ||||||||||||
The long-term expected rate of return on funded assets shown below is established for each 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 is 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 is 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, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Weighted average assumptions to determine benefit obligation | |||||||||||||||||
Discount rate | 3.75 | % | 4.75 | % | |||||||||||||
Expected rate of return | 6 | % | 6 | % | |||||||||||||
Rate of compensation increase | 4 | % | 4 | % | |||||||||||||
Inflation | 3 | % | 3 | % | |||||||||||||
Components of net periodic benefit cost (in thousands) | |||||||||||||||||
Service cost | $ | 70 | $ | 144 | |||||||||||||
Interest cost | 335 | 203 | |||||||||||||||
Expected return on plan assets | (448 | ) | (195 | ) | |||||||||||||
Amortization of transition obligation | 70 | 140 | |||||||||||||||
Amortization of net (gain) loss | 29 | — | |||||||||||||||
Net period benefit cost | $ | 56 | $ | 292 | |||||||||||||
The following benefit payments are expected to be paid over the next ten years (in thousands): | |||||||||||||||||
2015 | $ | 8 | |||||||||||||||
2016 | 9 | ||||||||||||||||
2017 | 25 | ||||||||||||||||
2018 | 68 | ||||||||||||||||
2019 | 106 | ||||||||||||||||
2020-2024 | 1,798 | ||||||||||||||||
The Company’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. The Company, along with its investment manager, determines the investment policies and strategies for the plan assets to determine the allocations to the various asset classes based on the results of the studies targeted percentages. The following tables below set forth the breakout of asset categories as of December 31, 2014 and 2013 (in thousands): | |||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Plan assets by category | |||||||||||||||||
Equity securities | $ | — | $ | 7,397 | |||||||||||||
Debt securities | 5,392 | 117 | |||||||||||||||
Cash | 87 | 6 | |||||||||||||||
Total Assets | $ | 5,479 | $ | 7,520 | |||||||||||||
Plan assets by category | |||||||||||||||||
Equity securities | N/A | 98.3 | % | ||||||||||||||
Debt securities | 98.4 | % | 1.6 | % | |||||||||||||
Cash | 1.6 | % | 0.1 | % | |||||||||||||
Total Assets | 100 | % | 100 | % | |||||||||||||
The following tables set forth by level, within the fair value hierarchy, the fair value of pension assets as of December 31, 2014 and 2013 (in thousands): | |||||||||||||||||
December 31, 2014 | |||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
Pension assets | $ | 5,206 | 273 | — | $ | 5,479 | |||||||||||
December 31, 2013 | |||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
Pension assets | $ | 7,403 | 117 | — | $ | 7,520 | |||||||||||
The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment. |
Equity
Equity | 12 Months Ended |
Dec. 31, 2014 | |
Equity [Abstract] | |
Equity | Note 10—Equity |
Initial Public Offering | |
On June 25, 2014, the Company completed its initial public offering (“IPO”) of 30,300,000 shares of our 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. | |
Incentive Units | |
Eclipse Holdings has a total of 1,000 Class C-1 units and 1,000 Class C-2 units authorized to be issued to employees (“Incentive Units”). The Series C-1 and C-2 Incentive Units are non-voting with respect to partnership matters, and the holder thereof will begin to participate in distributions from Eclipse Holdings after distributions have been made to the holders of the Series A-1 and A-2 units that satisfy a specified hurdle rate and return on investment factor, with the level of participation in distributions adjusting upwards as distributions to the holders of the Series A-1 and A-2 units satisfy additional specified hurdle rates and return on investment factors. | |
Total compensation cost related to the Incentive Units was less than $0.1 million for each of the years ended December 31, 2014, 2013 and 2012. As of December 31, 2014, there was $0.7 million of total unrecognized compensation cost related to Incentive Units, which is expected to be recognized over a weighted-average period of 6.34 years. | |
The determination of the fair value of the awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of an Exit Event, forfeitures, the risk free rate and a volatility estimate tied to the Company’s public peer group. | |
Restricted Stock Issued to Directors | |
The Company has 16,000,000 shares of common stock authorized to be issued in accordance with its 2014 Long-Term Incentive Plan. On October 7, 2014, the Company issued 31,115 restricted shares of common stock, par value $0.01, to seven non-employee members of its Board of Directors. As of December 31, 2014 the Company recognized expense of approximately $0.1 million and expects to recognize $0.3 million during 2015 until the restricted shares become fully vested on June 25, 2015. | |
Private Placement of Common Stock | |
On December 27, 2014, the Company entered into a Securities Purchase Agreement with the EnCap Funds, the Management Funds and the other stockholders pursuant to which was agreed to issue and sell 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, such transaction referred to herein as the “private placement.” | |
On January 28, 2015, the Company closed the private placement and received net proceeds from the issuance of the shares to the purchasers 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 the IPO to give the stockholders certain registration rights with respect to the stock purchased in the private placement. |
Earnings_Loss_Per_Share
Earnings (Loss) Per Share | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Earnings Per Share [Abstract] | |||||||||||||
Earnings (Loss) Per Share | Note 11—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. 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, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Loss (numerator): | |||||||||||||
Net loss | (183,176 | ) | (43,541 | ) | (8,759 | ) | |||||||
Weighted-average shares (denominator): | |||||||||||||
Weighted-average number of shares of common stock—basic and diluted | 144,369 | 75,261 | 13,880 | ||||||||||
Loss per share: | |||||||||||||
Basic and diluted | $ | (1.27 | ) | $ | (0.58 | ) | $ | (0.63 | ) |
Related_Party_Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2014 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 12—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 provide 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. The Company’s management fee to Eclipse Operating was $14.7 million, and $4.2 million for the years ending December 31, 2013 and 2012, respectively. These expenses are classified within “Operating expenses—General and administrative” in the consolidated statements of operations. | |
As of December 31, 2014, the Company has recorded an accrued liability of $972,000 related to a final distribution of the assets of Eclipse Operating. This amount will be distributed equally among the three former shareholders during 2015 and is 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 year ended December 31, 2014 the Company incurred approximately $0.2 million 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, 2014 | |||||
Commitments and Contingencies Disclosure [Abstract] | |||||
Commitments and Contingencies | Note 13—Commitments and Contingencies | ||||
(a) Legal Matters | |||||
Prior to the Oxford Acquisition, 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. | |||||
The Company has appealed the trial court’s decision in the West case to the Ohio Court of Appeals for the Seventh Appellate District, arguing, among other things, that the Belmont County trial court erred in finding that the lease is a “no term” perpetual lease, by ruling that perpetual leases are void as a matter of Ohio law and by invalidating such leases. The Company cannot predict the outcome of this lawsuit or the amount of time and expense that will be required to resolve the lawsuit. | |||||
In addition, many of the Company’s other oil and gas leases in Ohio contain provisions identical or similar to those found in the challenged Oxford lease. As of March 6, 2015, we are a party to one other lawsuit that makes allegations similar to those made by the lessor in theWest lawsuit. This lawsuit, together with the West case, affect approximately 157 gross (157 net) leasehold acres and were capitalized on our balance sheet as of December 31, 2014 at $0.6 million. | |||||
The Company has undertaken efforts to amend the other leases acquired within the Utica Core Area in the Oxford Acquisition to address the issues raised by the trial court’s ruling in the West case. These efforts have resulted in modifications to leases covering approximately 34,256 net acres out of the approximately 46,549 net acres. The Company’s offer may require modification to address the issues raised by the trial court while the Company’s appeal is pending; however, the Company cannot predict whether the Company will be able to obtain modifications of the leases covering the remaining 12,293 net acres to effectively resolve issues related to the West trial court’s ruling or the amount of time and expense that will be required to amend these leases. | |||||
In light of the foregoing, if the appeals court affirms the trial court ruling in the West case, and if other courts in Ohio adopt a similar interpretation of the provisions in other oil and gas leases the Company acquired in the Oxford Acquisition, other lessors may challenge the validity of such leases and those challenged leases may be declared void. Consequently, this could result in a loss of the mineral rights and an impairment of the related assets which could have a material adverse impact on the Company’s financial statements. These costs could potentially be impaired if it was determined that the West lawsuit leases are invalid. Other than this potential impairment, the Company is not able to estimate the range of other potential losses related to this matter. | |||||
On September 26, 2014, the Ohio Court of Appeals for the Seventh Appellate District, the same appellate court that will decide the Company’s appeal in the West case, issued its decision in the case of Clyde Hupp et al. v. Beck Energy Corporation, an appeal of a Monroe County trial court decision upon which the trial court in West based its decision. The appellate court held that while Ohio law disfavors perpetual leases, courts in Ohio have not found them to be per se illegal or void from their inception. The appellate court further held that the trial court misinterpreted both the pertinent lease provisions and Ohio law on the subject and erred in concluding that the Beck Energy lease is a no-term, perpetual lease that is void ab initio as against public policy. On November 7, 2014, the plaintiff landowners filed an appeal of the appellate court’s decision with the Supreme Court of Ohio, which was accepted by the Supreme Court of Ohio on January 28, 2015. On March 2, 2015, the Ohio Court of Appeals for the Seventh Appellate District stayed all proceedings in the Company’s appeal in the West case pending a decision by the Supreme Court of Ohio in the Hupp v. Beck Energy appeal. | |||||
The Company believes that there are strong grounds for appeal of the West decision, and therefore, the Company intends to pursue all available appellate rights, and to vigorously defend against the claims in this lawsuit. Based on the merits of the Company’s appeal and the favorable holdings in the Hupp v. Beck Energy appellate decision described above, the Company believes that it is not probable that trial court’s decision in West will be upheld in the appeal or that the Company will incur a material loss in the lawsuit. The Company has not recorded an accrual for the potential losses attributable to this lawsuit. | |||||
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 operating leases that expire between the years 2015 to 2025. Rent expense related to the lease agreements for the years-ended December 31, 2014 and 2013 was $0.3 million and $0.1 million. No rent expense was incurred for the year ended December 31, 2012. | |||||
The following is a schedule by year, of the future minimum lease payments required under the lease agreements as of December 31, 2014 (in thousands). | |||||
2015 | $ | 773 | |||
2016 | 749 | ||||
2017 | 753 | ||||
2018 | 756 | ||||
2019 | 756 | ||||
Thereafter | 3,494 | ||||
Total minimum lease payments | $ | 7,281 | |||
Income_Tax
Income Tax | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Income Tax Disclosure [Abstract] | |||||
Income Tax | Note 14—Income Tax | ||||
For 2014, the Company’s annual effective tax rate is an expense of approximately 64.47%, inclusive of the “Change in Tax Status” charge (see “Note 3—Summary of Significant Accounting Policies”) and the gain on acquisition of Eclipse Operating (see “Note 4—Acquisitions”). The Company incurred a tax loss in the current year (due principally to the ability to expense certain intangible drilling and development costs under current law) and thus, no current federal income taxes will be due. This tax loss results in a net operating loss carryforward at year-end; however, no valuation allowance has been recorded as management believes that there is sufficient future taxable income to fully utilize all tax attributes. This future taxable income arises from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax bases. Management is not relying on other sources of taxable income in concluding that no valuation allowance is needed. | |||||
Year Ended | |||||
December 31, 2014(1) | |||||
(in thousands) | |||||
Current | |||||
Federal | $ | — | |||
State | 132 | ||||
Total current | 132 | ||||
Deferred | |||||
Federal | 71,838 | ||||
State | (171 | ) | |||
Total deferred | 71,667 | ||||
Total income tax expense | $ | 71,799 | |||
-1 | For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. | ||||
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): | |||||
Year Ended | |||||
December 31, 2014(1) | |||||
Loss before income taxes | $ | (111,377 | ) | ||
Statutory rate | 35 | % | |||
Income tax benefit computed at statutory rate | (38,982 | ) | |||
Reconciling items: | |||||
Non-deductible pre-IPO loss | 13,264 | ||||
State income taxes | (39 | ) | |||
Other, net | 71 | ||||
Change in tax status | 97,609 | ||||
Gain on acquisition of Eclipse Operating | (124 | ) | |||
Income tax expense | $ | 71,799 | |||
-1 | For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. | ||||
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): | |||||
Year Ended | |||||
December 31, 2014(1) | |||||
Current deferred tax asset: | |||||
State effect of current deferreds | $ | 104 | |||
Other, net | 2,140 | ||||
Net current deferred tax asset | $ | 2,244 | |||
Non-current deferred tax asset: | |||||
Federal tax loss carryforwards | $ | 127,497 | |||
State effect of non-current deferreds | 21 | ||||
Other, net | 668 | ||||
Net non-current deferred tax asset | $ | 128,186 | |||
Current deferred tax liability: | |||||
Derivative instruments and other | $ | 6,966 | |||
Other, net | 524 | ||||
Net current deferred tax liability | $ | 7,490 | |||
Non-current deferred tax liability: | |||||
Oil and gas properties and equipment | $ | 194,900 | |||
Other, net | — | ||||
Net non-current deferred tax liability | $ | 194,900 | |||
Reflected in the accompanying balance sheet as: | |||||
Net deferred tax liability—current | $ | 5,246 | |||
Net deferred tax liability—noncurrent | $ | 66,714 | |||
-1 | For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. | ||||
The Company has a U.S. federal tax loss carryforward (“NOL”) of approximately $364 million as of December 31, 2014. This NOL was generated in tax year 2014 and will generally be available for use through tax year 2034. The Company expects to file initial corporate tax returns for federal and various state jurisdictions for the tax year ended December 31, 2014 prior to the extended due dates. Upon filing, the tax year ended December 31, 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 prior to 2011 are generally not subject to examination. | |||||
As of December 31, 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. | |||||
On September 13, 2013, the US Treasury and IRS issued final Tangible Property Regulations (“TPR”) under IRC Section 162 and IRC Section 263(a) for tax years beginning on or after January 1, 2014. The Company analyzed the TPR and concluded there is minimal impact for the tax year ended December 31,2014. The Company will continue to monitor the impact of any future changes to the TPR on the Company prospectively. |
Subsequent_Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2014 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 15—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 in January 2015 and redetermination of the borrowing base in March 2015 (refer Note 8—Debt) and the Private Placement of Common Stock that closed in January 2015 (refer Note 10—Equity). |
Quarterly_Financial_Informatio
Quarterly Financial Information (unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Quarterly Financial Information (unaudited) | Note 16—Quarterly Financial Information (unaudited) | ||||||||||||||||
Summarized quarterly financial data for the years ended December 31, 2014 and 2013 are presented in the following table. In the following table, the sum of basic and diluted “Earnings (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 earnings (loss) per share amounts may not equal the calculated year earnings (loss) per share amount (in thousands, except per share data). | |||||||||||||||||
First | Second | Third | Fourth | ||||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||
Year ended December 13, 2014 | |||||||||||||||||
Total operating revenues | 24,788 | 26,955 | 35,702 | 50,371 | |||||||||||||
Total operating expenses | 25,992 | 34,166 | 60,806 | 101,026 | |||||||||||||
Operating loss | (1,204 | ) | (7,211 | ) | (25,104 | ) | (50,655 | ) | |||||||||
Net loss | (18,451 | ) | (112,648 | ) | (19,054 | ) | (33,023 | ) | |||||||||
Loss per common share: | |||||||||||||||||
Basic and diluted | $ | (0.15 | ) | $ | (0.84 | ) | $ | (0.12 | ) | $ | (0.21 | ) | |||||
First | Second | Third | Fourth | ||||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||
Year ended December 13, 2013 | |||||||||||||||||
Total operating revenues | 288 | 570 | 4,510 | 7,567 | |||||||||||||
Total operating expenses | 2,052 | 5,766 | 10,055 | 17,753 | |||||||||||||
Operating loss | (1,764 | ) | (5,196 | ) | (5,545 | ) | (10,186 | ) | |||||||||
Net loss | (1,759 | ) | (5,740 | ) | (16,484 | ) | (19,558 | ) | |||||||||
Loss per common share: | |||||||||||||||||
Basic and diluted. | $ | (0.10 | ) | $ | (0.10 | ) | $ | (0.14 | ) | $ | (0.16 | ) |
Supplemental_Oil_and_Natural_G
Supplemental Oil and Natural Gas Information (unaudited) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Text Block [Abstract] | |||||||||||||||||
Supplemental Oil and Natural Gas Information (unaudited) | Note 17—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, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Oil and natural gas properties: | |||||||||||||||||
Proved properties | $ | 1,044,469 | $ | 926,812 | |||||||||||||
Unproved properties | 802,112 | 97,528 | |||||||||||||||
Total oil and natural gas properties | 1,846,581 | 1,024,340 | |||||||||||||||
Less accumulated depreciation, depletion and amortization | (131,857 | ) | (8,596 | ) | |||||||||||||
Net oil and natural gas properties | $ | 1,714,724 | $ | 1,015,744 | |||||||||||||
(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, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Acquisition costs: | |||||||||||||||||
Proved properties | $ | — | $ | 40,914 | $ | 2,498 | |||||||||||
Unproved properties | 134,156 | 621,039 | 158,131 | ||||||||||||||
Development cost | 714,796 | 258,825 | 16,344 | ||||||||||||||
Exploration cost | 21,186 | 3,022 | 3,899 | ||||||||||||||
Total acquisition, development and exploration costs | $ | 870,138 | $ | 923,800 | $ | 180,872 | |||||||||||
(c) Reserve Quantity Information | |||||||||||||||||
The following information represents estimates of the Company’s proved reserves as of December 31, 2014 and December 31, 2013, 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, 2014 and December 31, 2013 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, 2014 and December 31, 2013, 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, 2014, 2013, and 2012 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: | |||||||||||||||||
Natural Gas | Natural Gas | Oil (MBbl) | TOTAL | ||||||||||||||
(MMCF) | Liquids | (MMcfe) | |||||||||||||||
(MBbl) | |||||||||||||||||
End of year, December 31, 2011 | — | — | — | — | |||||||||||||
Extensions and discoveries | 2,963.80 | 177 | 390.5 | 6,368.90 | |||||||||||||
Production | (7.7 | ) | — | (4.5 | ) | (34.7 | ) | ||||||||||
End of year, December 31, 2012 | 2,956.10 | 177 | 386 | 6,334.20 | |||||||||||||
Revisions | 2,645.00 | 52.1 | (163.2 | ) | 1,978.40 | ||||||||||||
Extensions and discoveries | 41,215.50 | 1,710.60 | 1,323.30 | 59,419.00 | |||||||||||||
Acquisition of reserves | 6,646.60 | — | 958.5 | 12,397.60 | |||||||||||||
Production | (1,118.8 | ) | (1.3 | ) | (87.2 | ) | (1,650.2 | ) | |||||||||
End of year, December 31, 2013 | 52,344.40 | 1,938.40 | 2,417.40 | 78,478.60 | |||||||||||||
Revisions | (12,091.2 | ) | (739.7 | ) | (462.6 | ) | (19,305.3 | ) | |||||||||
Extensions and discoveries | 235,816.90 | 10,216.30 | 4,337.50 | 323,140.10 | |||||||||||||
Production | (19,760.2 | ) | (536.0 | ) | (594.9 | ) | (26,545.5 | ) | |||||||||
End of year, December 31, 2014 | 256,309.90 | 10,879.00 | 5,697.40 | 355,767.90 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
December 31, 2012 | 1,289.60 | 64.6 | 174.5 | 2,724.00 | |||||||||||||
December 31, 2013 | 27,880.30 | 1,056.20 | 1,708.10 | 44,466.60 | |||||||||||||
December 31, 2014 | 132,959.50 | 6,758.60 | 3,880.90 | 196,796.40 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
December 31, 2012 | 1,666.60 | 112.4 | 211.5 | 3,610.10 | |||||||||||||
December 31, 2013 | 24,464.10 | 882.2 | 709.2 | 34,012.00 | |||||||||||||
December 31, 2014 | 123,350.40 | 4,120.40 | 1,816.40 | 158,971.50 | |||||||||||||
Extensions and discoveries of 323,140.1 MMCFE and 59,419 MMCFE during the years ended December 31, 2014 and December 31, 2013, 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, 2014 and 2013 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, 2014 and 2013 (in thousands): | |||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Future cash inflows (total revenues) | $ | 1,870,319 | $ | 479,527 | $ | 50,614 | |||||||||||
Future production costs (severance and ad valorem taxes plus LOE) | (728,041 | ) | (116,161 | ) | (6,448 | ) | |||||||||||
Future development costs (capital costs) | (350,187 | ) | (76,511 | ) | (8,015 | ) | |||||||||||
Future income tax expense | (277,500 | ) | — | — | |||||||||||||
Future net cash flows | 514,591 | 286,855 | 36,151 | ||||||||||||||
10% annual discount for estimated timing of cash flows | (183,934 | ) | (131,560 | ) | (14,257 | ) | |||||||||||
Standardized measure of Discounted Future Net Cash Flow | $ | 330,657 | $ | 155,295 | $ | 21,894 | |||||||||||
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, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Standardized Measure, beginning of the year | $ | 155,295 | $ | 21,894 | $ | — | |||||||||||
Net change in prices and production costs | (52,642 | ) | (5,354 | ) | 354 | ||||||||||||
Net change in future development costs | (2,122 | ) | (1,148 | ) | — | ||||||||||||
Sales, Less production costs | (104,099 | ) | (10,281 | ) | (354 | ) | |||||||||||
Extensions | 491,067 | 106,720 | 21,894 | ||||||||||||||
Acquisitions | — | 28,984 | — | ||||||||||||||
Revisions of previous quantity estimates | (38,201 | ) | 8,354 | — | |||||||||||||
Previously estimated development costs incurred | 16,807 | — | — | ||||||||||||||
Accretion of discount | 15,529 | 2,189 | — | ||||||||||||||
Net change in taxes | (178,732 | ) | — | — | |||||||||||||
Changes in timing and other | 27,755 | 3,937 | — | ||||||||||||||
Period Balance | $ | 330,657 | $ | 155,295 | $ | 21,894 | |||||||||||
Summary_of_Significant_Account1
Summary of Significant Accounting Policies (Policies) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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, 2014 or December 31, 2013. | |||||||||||||
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 $24.1 million and $4.1 million of accrued revenues, net of expenses at December 31, 2014 and December 31, 2013, 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” below). | |||||||||||||
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. 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, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Oil and natural gas properties: | |||||||||||||
Unproved | $ | 1,044,469 | $ | 926,812 | |||||||||
Proved | 802,112 | 97,528 | |||||||||||
Gross oil and natural gas properties | 1,846,581 | 1,024,340 | |||||||||||
Less accumulated depreciation, depletion and amortization | (131,857 | ) | (8,596 | ) | |||||||||
Oil and natural gas properties, net | 1,714,724 | 1,015,744 | |||||||||||
Other property and equipment | 8,912 | 2,392 | |||||||||||
Less accumulated depreciation | (809 | ) | (52 | ) | |||||||||
Other property and equipment, net | 8,103 | 2,340 | |||||||||||
Property and equipment, net | $ | 1,722,827 | $ | 1,018,084 | |||||||||
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. | |||||||||||||
Other Property and Equipment | |||||||||||||
Other property and equipment include land, buildings, leasehold improvements, vehicles, computer equipment and software, telecommunications equipment, and furniture and fixtures. These items are recorded at cost, or fair value if acquired through a business acquisition. | |||||||||||||
Revenue Recognition | (d) Revenue Recognition | ||||||||||||
Oil and natural gas sales revenue is recognized when produced quantities of oil and natural gas are delivered to a custody transfer point such as a pipeline, processing facility or a tank lifting has occurred, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sales is reasonably assured and the sales price is fixed or determinable. Revenues from the sales of natural gas, crude oil 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, 2014 and December 31, 2013. | |||||||||||||
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. | |||||||||||||
Major Customers | (e) Major Customers | ||||||||||||
The Company sells production volumes to various purchasers. For the years ended December 31, 2014, 2013 and 2012, there were two, four, and one customer that accounted for 10% or more of the total natural gas, NGLs and oil sales. Management believes that the loss of any one customer would not have an adverse effect on the Company’s ability to sell natural gas, NGLs and oil production. 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, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Purchaser | |||||||||||||
Antero Resources Corporation | 47 | % | 38 | % | 100 | % | |||||||
Devco Oil Inc. | — | 24 | % | — | |||||||||
Dominion Resources Inc. | — | 13 | % | — | |||||||||
ARM Energy Management | 25 | % | — | — | |||||||||
Ergon | — | 12 | % | — | |||||||||
Total | 72 | % | 87 | % | 100 | % | |||||||
Management believes that there are potential alternative purchasers and that 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. Although the Company is exposed to a concentration of credit risk, management believes that all of the Company’s purchasers are credit worthy. | |||||||||||||
Concentration of Credit Risk | (f) Concentration of Credit Risk | ||||||||||||
The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2014 and December 31, 2013 (in thousands): | |||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Receivables by product or service: | |||||||||||||
Sale of oil and natural gas and related products and services | $ | 22,777 | $ | 4,092 | |||||||||
Joint interest owners | 20,666 | 4,586 | |||||||||||
Miscellaneous other | 2,935 | — | |||||||||||
Total | $ | 46,378 | $ | 8,678 | |||||||||
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 derivative contracts is a net asset position of $19.0 million at December 31, 2014. 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, 2014, the Company did not have past-due receivables from or payables to any of the counterparties. | |||||||||||||
Accumulated Other Comprehensive Income (Loss) | (g) Accumulated Other Comprehensive Income (Loss) | ||||||||||||
Comprehensive loss includes net loss and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources that, under U.S. GAAP, have not been recognized in the calculation of net loss. These changes, other than net loss, are referred to as “other comprehensive loss” and for the Company they include a pension benefit plan that requires the Company to (i) recognize the overfunded or underfunded status of a defined benefit retirement plan as an asset or liability in its balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was underfunded by $1.3 million and $1.5 million at December 31, 2014 and December 31, 2013, respectively. 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. No such gain was recorded for the year ended December 31, 2013. | |||||||||||||
Depreciation, Depletion and Amortization | (h) 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, 2014, 2013 and 2012 totaled approximately $88.4 million, $5.9 million and $0.2 million, respectively. | |||||||||||||
Through September 30, 2014, the Company calculated depletion of proved properties at the individual unit level. Effective October 1, 2015, 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. As a result of this change, DD&A expense recorded by the Company for the year ended December 31, 2014 was $1.3 million lower than it would have been if the Company had not made this change. | |||||||||||||
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, 2014, 2013, and 2012 totaled approximately $0.8 million, $0.3 million and $0.2 million, respectively. This amount is included in DD&A expense in the consolidated statements of operations. | |||||||||||||
Impairment of Long-Lived Assets | (i) 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 consists of three fields, including Conventional production, 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 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. The Company recognized impairment expenses relating to proved properties of $34.9 million and $2.1 million for the years ended December 31, 2014 and 2013, respectively. Approximately $30.9 million of the impairment recorded for the year ended December 31, 2014 was recorded during the fourth quarter of 2014 as a result of the significant decline in oil and natural gas commodity prices during the quarter related to the conventional properties acquired during the Oxford Acquisition. The remaining $4.0 million related to unconventional properties in the Utica Shale. There were no impairments of proved properties for the year ended December 31, 2012. | |||||||||||||
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 properties are reviewed annually for impairment or whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment charge is recorded if conditions indicate the Company will not explore the acreage prior to expiration of the applicable leases. The Company recorded impairment charges of unproved oil and gas properties related to lease expirations of $5.7 million and $0.8 million for the years ended December 31, 2014 and 2012, respectively. These costs are included in exploration expense in the consolidated statements of operations. No such impairments were recorded for year ended December 31, 2013. | |||||||||||||
Income Taxes | (j) 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. | |||||||||||||
The FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes” provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company recognizes fines and penalties as income tax expense. | |||||||||||||
Fair Value of Financial Instruments | (k) 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 | (l) 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 | (m) 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,” associated with the retirement of a tangible long-lived asset, in the period in which it is incurred or becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The Company measures the fair value of its ARO using expected future cash outflows for abandonment discounted back to the date that the abandonment obligation was measured using an estimated credit adjusted rate, which was 9.89% and 8.96% for the years ended December 31, 2014 and 2013, respectively. | |||||||||||||
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. As of December 31, 2014, management revised its assumptions relating to certain wells including useful lives, working interest, and abandonment costs. These revisions increased the asset retirement obligation for the wells, and as a result, the Company recorded an incremental layer of approximately $6.5 million. | |||||||||||||
The following table sets forth the changes in the Company’s ARO liability for the period indicated (in thousands): | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Asset retirement obligations, beginning of period | $ | 9,055 | $ | 13 | $ | — | |||||||
Revisions of prior estimates | 6,470 | — | — | ||||||||||
Additional liabilities incurred | 1,084 | 300 | 13 | ||||||||||
Assumption of Oxford asset retirement obligations | — | 8,378 | — | ||||||||||
Accretion | 791 | 364 | — | ||||||||||
Asset retirement obligations, end of period | $ | 17,400 | $ | 9,055 | $ | 13 | |||||||
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 | (n) Lease Obligations | ||||||||||||
The Company leases office space under operating leases that expire between the years 2015—2025. The lease terms begin on the date of initial possession of the leased property for purposes of recognizing lease expense on a straight-line basis over the term of the lease. The Company does not assume renewals in its determination of the lease terms unless the renewals are deemed to be reasonably assured at lease inception. | |||||||||||||
Off-Balance Sheet Arrangements | (o) Off-Balance Sheet Arrangements | ||||||||||||
The Company does not have any off-balance sheet arrangements. | |||||||||||||
Segment Reporting | (p) 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 | (q) Debt Issuance Costs | ||||||||||||
The expenditures related to issuing debt are capitalized and included in other assets 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 | (r) Recent Accounting Pronouncements | ||||||||||||
The FASB issued ASU 2013-11, “Income Taxes (Topic 740)—Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” in December 2013. These amendments provide that an unrecognized tax benefit, or a portion thereof, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except to the extent that a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date to settle any additional income taxes that would result from disallowance of a tax position, or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose, then the unrecognized tax benefit should be presented as a liability. These requirements were effective for annual reporting periods beginning after December 15, 2013, including interim periods within that reporting period. The adoption of this ASU did not impact the Company’s financial position, results of operations or liquidity. | |||||||||||||
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, 2016, including interim periods within that reporting period. Early adoption is not permitted. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. | |||||||||||||
In June 2014, the FASB issued ASU 2014-12, Compensation—Stock Compensation (Topic 718) (“Update 2014-12”). The amendments in Update 2014-12 require that a performance target that affects vesting and that could be achieved after the requisite service period, be treated as a performance condition. As such, the performance target should not be reflected in estimating the grant date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the period(s) for which the requisite service has already been rendered. If the performance target becomes probable of being achieved before the end of the requisite service period, the remaining unrecognized compensation cost should be recognized prospectively over the remaining requisite service period. The total amount of compensation cost recognized during and after the requisite service period should reflect the number of awards that are expected to vest and should be adjusted to reflect those awards that ultimately vest. The requisite service period ends when the employee can cease rendering service and still be eligible to vest in the award if the performance target is achieved. The amendments in Update 2014-12 are effective for annual periods and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. Entities may apply the amendments in Update 2014-12 either (a) prospectively to all awards granted or modified after the effective date, or (b) retrospectively to all awards with performance targets that are outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. The Company will adopt the requirements of Update 2014-12 upon its effective date of January 1, 2016, and is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. | |||||||||||||
In April 2014, the FASB issued ASU 2014-08, “Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360)”: Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”. The objective of the amendments in this update is to change the criteria for reporting discontinued operations and enhance convergence of the FASB’s and the International Accounting Standard Board’s (IASB) reporting requirements for discontinued operations. The amendments in this update change the requirements for reporting discontinued operations in Subtopic 205-20. A discontinued operation may include a component of an entity or a group of components of an entity, or a business or nonprofit activity. A disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The amendments in this update require an entity to present, for each comparative period, the assets and liabilities of a disposal group that includes a discontinued operation separately in the asset and liability sections, respectively, of the statement of financial position. The amendments in this update also require additional disclosures about discontinued operations. Public business entities must apply the amendments in this update prospectively to both of the following: (1) All disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years; (2) All businesses or nonprofit activities that, on acquisition, are classified as held for sale that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. | |||||||||||||
In August 2014, the FASB issued 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 periods ending after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have an impact on the Company’s financial statement disclosures. |
Summary_of_Significant_Account2
Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Oil and natural gas properties: | |||||||||||||
Unproved | $ | 1,044,469 | $ | 926,812 | |||||||||
Proved | 802,112 | 97,528 | |||||||||||
Gross oil and natural gas properties | 1,846,581 | 1,024,340 | |||||||||||
Less accumulated depreciation, depletion and amortization | (131,857 | ) | (8,596 | ) | |||||||||
Oil and natural gas properties, net | 1,714,724 | 1,015,744 | |||||||||||
Other property and equipment | 8,912 | 2,392 | |||||||||||
Less accumulated depreciation | (809 | ) | (52 | ) | |||||||||
Other property and equipment, net | 8,103 | 2,340 | |||||||||||
Property and equipment, net | $ | 1,722,827 | $ | 1,018,084 | |||||||||
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): | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Asset retirement obligations, beginning of period | $ | 9,055 | $ | 13 | $ | — | |||||||
Revisions of prior estimates | 6,470 | — | — | ||||||||||
Additional liabilities incurred | 1,084 | 300 | 13 | ||||||||||
Assumption of Oxford asset retirement obligations | — | 8,378 | — | ||||||||||
Accretion | 791 | 364 | — | ||||||||||
Asset retirement obligations, end of period | $ | 17,400 | $ | 9,055 | $ | 13 | |||||||
Product Concentration Risk [Member] | Accounts Receivable [Member] | |||||||||||||
Concentration Risk | The following table summarizes concentration of receivables, net of allowances, by product or service as of December 31, 2014 and December 31, 2013 (in thousands): | ||||||||||||
December 31, | December 31, | ||||||||||||
2014 | 2013 | ||||||||||||
Receivables by product or service: | |||||||||||||
Sale of oil and natural gas and related products and services | $ | 22,777 | $ | 4,092 | |||||||||
Joint interest owners | 20,666 | 4,586 | |||||||||||
Miscellaneous other | 2,935 | — | |||||||||||
Total | $ | 46,378 | $ | 8,678 | |||||||||
Customer Concentration Risk [Member] | Sales Revenue, Net [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, | |||||||||||||
2014 | 2013 | 2012 | |||||||||||
Purchaser | |||||||||||||
Antero Resources Corporation | 47 | % | 38 | % | 100 | % | |||||||
Devco Oil Inc. | — | 24 | % | — | |||||||||
Dominion Resources Inc. | — | 13 | % | — | |||||||||
ARM Energy Management | 25 | % | — | — | |||||||||
Ergon | — | 12 | % | — | |||||||||
Total | 72 | % | 87 | % | 100 | % | |||||||
Acquisition_Tables
Acquisition (Tables) | 12 Months Ended | ||||||||
Dec. 31, 2014 | |||||||||
Business Combinations [Abstract] | |||||||||
Summary of Purchase Price Allocation of Assets Acquired and Liabilities Assumed | The following table summarizes the purchase price allocation and the values of assets acquired and liabilities assumed (in thousands): | ||||||||
Purchase Price | June 26, 2013 | ||||||||
Consideration Given | |||||||||
Cash | $ | 652,500 | |||||||
Allocation of Purchase Price | |||||||||
Unproved properties | 621,039 | ||||||||
Proved properties | 40,914 | ||||||||
Cash | 653 | ||||||||
Building and land | 1,500 | ||||||||
Total assets | 664,106 | ||||||||
Asset retirement obligations | (8,378 | ) | |||||||
Pension obligation | (2,522 | ) | |||||||
Other working capital | (706 | ) | |||||||
Fair value of net assets acquired | $ | 652,500 | |||||||
Summary of Pro Forma Financial Information | The pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of January 1, 2012, nor are they necessarily indicative of future results (in thousands). | ||||||||
For the Year Ended | |||||||||
December 31, | |||||||||
2013 | 2012 | ||||||||
Oil and natural gas sales | $ | 20,638 | $ | 13,936 | |||||
Net loss | $ | (71,131 | ) | $ | (56,065 | ) |
Derivative_Instruments_Tables
Derivative Instruments (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||
Summary of Derivative Instrument Positions for Future Production Periods | Below is summary of the Company’s derivative instrument positions, as of December 31, 2014, for future production periods: | ||||||||||||||||
Description | Volume | Production Period | Weighted Average | ||||||||||||||
(MMBtu/d) | Price ($/MMBtu) | ||||||||||||||||
Natural Gas Swaps: | |||||||||||||||||
66,219 | January 2015—December 2015 | $ | 3.797 | ||||||||||||||
25,000 | January 2016—December 2016 | $ | 3.66 | ||||||||||||||
Natural Gas Three-way Collar: | |||||||||||||||||
Floor purchase price (put) | 15,000 | January 2015—December 2015 | $ | 3.6 | |||||||||||||
Ceiling sold price (call) | 15,000 | January 2015—December 2015 | $ | 3.8 | |||||||||||||
Floor sold price (put) | 15,000 | January 2015—December 2015 | $ | 3 | |||||||||||||
Natural Gas Put Sale: | |||||||||||||||||
Put sold | 16,800 | January 2015—December 2015 | $ | 3.35 | |||||||||||||
Natural Gas Collar: | |||||||||||||||||
Purchased put | 5,000 | January 2015—March 2015 | $ | 4 | |||||||||||||
Call sold | 5,000 | January 2015—March 2015 | $ | 4.75 | |||||||||||||
Basis Swaps: | |||||||||||||||||
25,000 | January 2015—March 2015 | $ | (1.067 | ) | |||||||||||||
25,000 | April 2015—October 2015 | $ | (1.208 | ) | |||||||||||||
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. | ||||||||||||||||
Derivatives not designated as hedging | Gross Amount | Netting | Net Amount | Balance Sheet | |||||||||||||
Adjustments(a) | Presented in the | Location | |||||||||||||||
instruments under ASC 815 | Balance Sheets | ||||||||||||||||
As of December 31, 2014 | |||||||||||||||||
Assets | |||||||||||||||||
Commodity derivatives—current | $ | 22,349 | $ | (5,012 | ) | $ | 17,337 | Other current assets | |||||||||
Commodity derivatives—noncurrent | 1,741 | (44 | ) | 1,697 | Other assets | ||||||||||||
Total assets | $ | 24,090 | $ | (5,056 | ) | $ | 19,034 | ||||||||||
Liabilities | |||||||||||||||||
Commodity derivatives—current | $ | (5,012 | ) | $ | 5,012 | $ | — | ||||||||||
Commodity derivatives—noncurrent | (44 | ) | 44 | — | |||||||||||||
Total liabilities | $ | (5,056 | ) | $ | 5,056 | $ | — | ||||||||||
(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): | ||||||||||||||||
Location of Gain (Loss) | Years Ended December 31, | ||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Commodity derivatives | Gain on derivative instruments | $ | 20,791 | $ | — | $ | — |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||
Assets and Liabilities that are Measured at Fair Value 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 Fair Value | ||||||||||||||
As of December 31, 2014: (in thousands) | |||||||||||||||||
Commodity derivative instruments | $ | — | $ | 19,034 | $ | — | $ | 19,034 | |||||||||
Total | $ | — | $ | 19,034 | $ | — | $ | 19,034 | |||||||||
Debt_Tables
Debt (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Debt Disclosure [Abstract] | |||||
Summary of Senior Unsecured Notes Redemption Prices | After the Non-Call Period, the Company may redeem all or a part of the Senior Unsecured Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest: | ||||
Year following expiration of the Non-Call Period | Redemption Price | ||||
Year 1 | 106 | % | |||
Year 2 | 103 | % | |||
Year 3 and thereafter | 100 | % |
Benefit_Plans_Tables
Benefit Plans (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Summary of Pension Benefit | A summary of the pension benefit as of the years ended December 31, 2014 and 2013 is set forth in the below tables (in thousands): | ||||||||||||||||
2014 | 2013 | ||||||||||||||||
Change in benefit obligation | |||||||||||||||||
Benefit obligation at beginning of year | $ | 9,018 | $ | — | |||||||||||||
Oxford assumed benefit obligations | — | 9,045 | |||||||||||||||
Service cost | 70 | 144 | |||||||||||||||
Interest cost | 335 | 203 | |||||||||||||||
Gain on reduction of pension liability | (2,208 | ) | — | ||||||||||||||
Actuarial loss | 1,616 | (350 | ) | ||||||||||||||
Benefits paid | (2,031 | ) | (24 | ) | |||||||||||||
Benefit obligation at end of period | $ | 6,800 | $ | 9,018 | |||||||||||||
Change in plan assets | |||||||||||||||||
Fair value of plan assets at beginning of year | $ | 7,521 | $ | — | |||||||||||||
Oxford assumed plan assets | — | 6,523 | |||||||||||||||
Actual return on plan assets | (11 | ) | 1,012 | ||||||||||||||
Employer contributions | — | 10 | |||||||||||||||
Benefit paid | (2,031 | ) | (24 | ) | |||||||||||||
Fair value of plan assets at December 31, 2014 | $ | 5,479 | $ | 7,521 | |||||||||||||
Summary Of Defined Benefit Pension Obligations | As shown in the table below, the current pension plan is underfunded. All defined benefit pension obligations, regardless of the funding status of the plan, are fully supported by the financial strength of the Company. | ||||||||||||||||
2014 | 2013 | ||||||||||||||||
(in thousands) | |||||||||||||||||
Assets in excess of (less than) benefit obligation at December 31, | |||||||||||||||||
Vested amount | $ | (6,800 | ) | $ | (7,039 | ) | |||||||||||
Additional benefits required | — | (1,979 | ) | ||||||||||||||
Projected benefit obligation | (6,800 | ) | (9,018 | ) | |||||||||||||
Funded amount | 5,479 | 7,521 | |||||||||||||||
Unfunded amount | $ | (1,321 | ) | $ | (1,497 | ) | |||||||||||
Other amounts recognized in other comprehensive loss during the year ended December 31, | |||||||||||||||||
Assets in excess of (less than) benefit obligation at end of period | $ | (1,321 | ) | $ | (1,497 | ) | |||||||||||
Amounts recorded in the consolidated balance sheet consist of: | |||||||||||||||||
Accrued benefit liability | (1,321 | ) | (1,497 | ) | |||||||||||||
Total recorded | $ | (1,321 | ) | $ | (1,497 | ) | |||||||||||
Beginning amount recorded in other accumulated comprehensive income | $ | 1,168 | $ | — | |||||||||||||
Amounts recorded in accumulated other comprehensive loss consist of: | |||||||||||||||||
Pension obligation adjustment, net of tax | (1,716 | ) | 1,168 | ||||||||||||||
Total recorded in accumulated other comprehensive income | $ | (548 | ) | $ | 1,168 | ||||||||||||
Weighted Average Assumptions to Determine Benefit Obligation | |||||||||||||||||
For the Year Ended | |||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Weighted average assumptions to determine benefit obligation | |||||||||||||||||
Discount rate | 3.75 | % | 4.75 | % | |||||||||||||
Expected rate of return | 6 | % | 6 | % | |||||||||||||
Rate of compensation increase | 4 | % | 4 | % | |||||||||||||
Inflation | 3 | % | 3 | % | |||||||||||||
Components of Net Periodic Benefit Cost | |||||||||||||||||
For the Year Ended | |||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Weighted average assumptions to determine benefit obligation | |||||||||||||||||
Discount rate | 3.75 | % | 4.75 | % | |||||||||||||
Expected rate of return | 6 | % | 6 | % | |||||||||||||
Rate of compensation increase | 4 | % | 4 | % | |||||||||||||
Inflation | 3 | % | 3 | % | |||||||||||||
Components of net periodic benefit cost (in thousands) | |||||||||||||||||
Service cost | $ | 70 | $ | 144 | |||||||||||||
Interest cost | 335 | 203 | |||||||||||||||
Expected return on plan assets | (448 | ) | (195 | ) | |||||||||||||
Amortization of transition obligation | 70 | 140 | |||||||||||||||
Amortization of net (gain) loss | 29 | — | |||||||||||||||
Net period benefit cost | $ | 56 | $ | 292 | |||||||||||||
Summary Of Expected Benefit Payments | The following benefit payments are expected to be paid over the next ten years (in thousands): | ||||||||||||||||
2015 | $ | 8 | |||||||||||||||
2016 | 9 | ||||||||||||||||
2017 | 25 | ||||||||||||||||
2018 | 68 | ||||||||||||||||
2019 | 106 | ||||||||||||||||
2020-2024 | 1,798 | ||||||||||||||||
Summary Of Investment Strategy For Benefit Plan | The following tables below set forth the breakout of asset categories as of December 31, 2014 and 2013 (in thousands): | ||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Plan assets by category | |||||||||||||||||
Equity securities | $ | — | $ | 7,397 | |||||||||||||
Debt securities | 5,392 | 117 | |||||||||||||||
Cash | 87 | 6 | |||||||||||||||
Total Assets | $ | 5,479 | $ | 7,520 | |||||||||||||
Plan assets by category | |||||||||||||||||
Equity securities | N/A | 98.3 | % | ||||||||||||||
Debt securities | 98.4 | % | 1.6 | % | |||||||||||||
Cash | 1.6 | % | 0.1 | % | |||||||||||||
Total Assets | 100 | % | 100 | % | |||||||||||||
Defined Benefit Pension Plan [Member] | |||||||||||||||||
Summary Of Fair Value Of Pension Assets Benefit Plan | The following tables set forth by level, within the fair value hierarchy, the fair value of pension assets as of December 31, 2014 and 2013 (in thousands): | ||||||||||||||||
December 31, 2014 | |||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
Pension assets | $ | 5,206 | 273 | — | $ | 5,479 | |||||||||||
December 31, 2013 | |||||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||||
Pension assets | $ | 7,403 | 117 | — | $ | 7,520 | |||||||||||
Earnings_Loss_Per_Share_Tables
Earnings (Loss) Per Share (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
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, | ||||||||||||
2014 | 2013 | 2012 | |||||||||||
Loss (numerator): | |||||||||||||
Net loss | (183,176 | ) | (43,541 | ) | (8,759 | ) | |||||||
Weighted-average shares (denominator): | |||||||||||||
Weighted-average number of shares of common stock—basic and diluted | 144,369 | 75,261 | 13,880 | ||||||||||
Loss per share: | |||||||||||||
Basic and diluted | $ | (1.27 | ) | $ | (0.58 | ) | $ | (0.63 | ) |
Commitments_and_Contingencies_
Commitments and Contingencies (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
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, 2014 (in thousands). | ||||
2015 | $ | 773 | |||
2016 | 749 | ||||
2017 | 753 | ||||
2018 | 756 | ||||
2019 | 756 | ||||
Thereafter | 3,494 | ||||
Total minimum lease payments | $ | 7,281 | |||
Income_Tax_Tables
Income Tax (Tables) | 12 Months Ended | ||||
Dec. 31, 2014 | |||||
Income Tax Disclosure [Abstract] | |||||
Segregation of Income Tax Provision Based on Location of Operations | This future taxable income arises from reversing temporary differences due to the excess of the book carrying value of oil and gas properties over their corresponding tax bases. Management is not relying on other sources of taxable income in concluding that no valuation allowance is needed. | ||||
Year Ended | |||||
December 31, 2014(1) | |||||
(in thousands) | |||||
Current | |||||
Federal | $ | — | |||
State | 132 | ||||
Total current | 132 | ||||
Deferred | |||||
Federal | 71,838 | ||||
State | (171 | ) | |||
Total deferred | 71,667 | ||||
Total income tax expense | $ | 71,799 | |||
-1 | For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. | ||||
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): | ||||
Year Ended | |||||
December 31, 2014(1) | |||||
Loss before income taxes | $ | (111,377 | ) | ||
Statutory rate | 35 | % | |||
Income tax benefit computed at statutory rate | (38,982 | ) | |||
Reconciling items: | |||||
Non-deductible pre-IPO loss | 13,264 | ||||
State income taxes | (39 | ) | |||
Other, net | 71 | ||||
Change in tax status | 97,609 | ||||
Gain on acquisition of Eclipse Operating | (124 | ) | |||
Income tax expense | $ | 71,799 | |||
-1 | For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. | ||||
Components of Deferred Tax Assets and Liabilities | The components of our deferred taxes are detailed in the table below (in thousands): | ||||
Year Ended | |||||
December 31, 2014(1) | |||||
Current deferred tax asset: | |||||
State effect of current deferreds | $ | 104 | |||
Other, net | 2,140 | ||||
Net current deferred tax asset | $ | 2,244 | |||
Non-current deferred tax asset: | |||||
Federal tax loss carryforwards | $ | 127,497 | |||
State effect of non-current deferreds | 21 | ||||
Other, net | 668 | ||||
Net non-current deferred tax asset | $ | 128,186 | |||
Current deferred tax liability: | |||||
Derivative instruments and other | $ | 6,966 | |||
Other, net | 524 | ||||
Net current deferred tax liability | $ | 7,490 | |||
Non-current deferred tax liability: | |||||
Oil and gas properties and equipment | $ | 194,900 | |||
Other, net | — | ||||
Net non-current deferred tax liability | $ | 194,900 | |||
Reflected in the accompanying balance sheet as: | |||||
Net deferred tax liability—current | $ | 5,246 | |||
Net deferred tax liability—noncurrent | $ | 66,714 | |||
-1 | For the 2013 and 2012 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. |
Quarterly_Financial_Informatio1
Quarterly Financial Information (unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||||
Schedule of Quarterly Financial Information | Summarized quarterly financial data for the years ended December 31, 2014 and 2013 are presented in the following table. In the following table, the sum of basic and diluted “Earnings (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 earnings (loss) per share amounts may not equal the calculated year earnings (loss) per share amount (in thousands, except per share data). | ||||||||||||||||
First | Second | Third | Fourth | ||||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||
Year ended December 13, 2014 | |||||||||||||||||
Total operating revenues | 24,788 | 26,955 | 35,702 | 50,371 | |||||||||||||
Total operating expenses | 25,992 | 34,166 | 60,806 | 101,026 | |||||||||||||
Operating loss | (1,204 | ) | (7,211 | ) | (25,104 | ) | (50,655 | ) | |||||||||
Net loss | (18,451 | ) | (112,648 | ) | (19,054 | ) | (33,023 | ) | |||||||||
Loss per common share: | |||||||||||||||||
Basic and diluted | $ | (0.15 | ) | $ | (0.84 | ) | $ | (0.12 | ) | $ | (0.21 | ) | |||||
First | Second | Third | Fourth | ||||||||||||||
Quarter | Quarter | Quarter | Quarter | ||||||||||||||
Year ended December 13, 2013 | |||||||||||||||||
Total operating revenues | 288 | 570 | 4,510 | 7,567 | |||||||||||||
Total operating expenses | 2,052 | 5,766 | 10,055 | 17,753 | |||||||||||||
Operating loss | (1,764 | ) | (5,196 | ) | (5,545 | ) | (10,186 | ) | |||||||||
Net loss | (1,759 | ) | (5,740 | ) | (16,484 | ) | (19,558 | ) | |||||||||
Loss per common share: | |||||||||||||||||
Basic and diluted. | $ | (0.10 | ) | $ | (0.10 | ) | $ | (0.14 | ) | $ | (0.16 | ) |
Supplemental_Oil_and_Natural_G1
Supplemental Oil and Natural Gas Information (unaudited) (Tables) | 12 Months Ended | ||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||
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, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Oil and natural gas properties: | |||||||||||||||||
Proved properties | $ | 1,044,469 | $ | 926,812 | |||||||||||||
Unproved properties | 802,112 | 97,528 | |||||||||||||||
Total oil and natural gas properties | 1,846,581 | 1,024,340 | |||||||||||||||
Less accumulated depreciation, depletion and amortization | (131,857 | ) | (8,596 | ) | |||||||||||||
Net oil and natural gas properties | $ | 1,714,724 | $ | 1,015,744 | |||||||||||||
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, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Acquisition costs: | |||||||||||||||||
Proved properties | $ | — | $ | 40,914 | $ | 2,498 | |||||||||||
Unproved properties | 134,156 | 621,039 | 158,131 | ||||||||||||||
Development cost | 714,796 | 258,825 | 16,344 | ||||||||||||||
Exploration cost | 21,186 | 3,022 | 3,899 | ||||||||||||||
Total acquisition, development and exploration costs | $ | 870,138 | $ | 923,800 | $ | 180,872 | |||||||||||
Proved Developed and Proved Undeveloped Reserves | The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2014, 2013, and 2012 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year: | ||||||||||||||||
Natural Gas | Natural Gas | Oil (MBbl) | TOTAL | ||||||||||||||
(MMCF) | Liquids | (MMcfe) | |||||||||||||||
(MBbl) | |||||||||||||||||
End of year, December 31, 2011 | — | — | — | — | |||||||||||||
Extensions and discoveries | 2,963.80 | 177 | 390.5 | 6,368.90 | |||||||||||||
Production | (7.7 | ) | — | (4.5 | ) | (34.7 | ) | ||||||||||
End of year, December 31, 2012 | 2,956.10 | 177 | 386 | 6,334.20 | |||||||||||||
Revisions | 2,645.00 | 52.1 | (163.2 | ) | 1,978.40 | ||||||||||||
Extensions and discoveries | 41,215.50 | 1,710.60 | 1,323.30 | 59,419.00 | |||||||||||||
Acquisition of reserves | 6,646.60 | — | 958.5 | 12,397.60 | |||||||||||||
Production | (1,118.8 | ) | (1.3 | ) | (87.2 | ) | (1,650.2 | ) | |||||||||
End of year, December 31, 2013 | 52,344.40 | 1,938.40 | 2,417.40 | 78,478.60 | |||||||||||||
Revisions | (12,091.2 | ) | (739.7 | ) | (462.6 | ) | (19,305.3 | ) | |||||||||
Extensions and discoveries | 235,816.90 | 10,216.30 | 4,337.50 | 323,140.10 | |||||||||||||
Production | (19,760.2 | ) | (536.0 | ) | (594.9 | ) | (26,545.5 | ) | |||||||||
End of year, December 31, 2014 | 256,309.90 | 10,879.00 | 5,697.40 | 355,767.90 | |||||||||||||
Proved developed reserves: | |||||||||||||||||
December 31, 2012 | 1,289.60 | 64.6 | 174.5 | 2,724.00 | |||||||||||||
December 31, 2013 | 27,880.30 | 1,056.20 | 1,708.10 | 44,466.60 | |||||||||||||
December 31, 2014 | 132,959.50 | 6,758.60 | 3,880.90 | 196,796.40 | |||||||||||||
Proved undeveloped reserves: | |||||||||||||||||
December 31, 2012 | 1,666.60 | 112.4 | 211.5 | 3,610.10 | |||||||||||||
December 31, 2013 | 24,464.10 | 882.2 | 709.2 | 34,012.00 | |||||||||||||
December 31, 2014 | 123,350.40 | 4,120.40 | 1,816.40 | 158,971.50 | |||||||||||||
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, 2014 and 2013 (in thousands): | ||||||||||||||||
December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Future cash inflows (total revenues) | $ | 1,870,319 | $ | 479,527 | $ | 50,614 | |||||||||||
Future production costs (severance and ad valorem taxes plus LOE) | (728,041 | ) | (116,161 | ) | (6,448 | ) | |||||||||||
Future development costs (capital costs) | (350,187 | ) | (76,511 | ) | (8,015 | ) | |||||||||||
Future income tax expense | (277,500 | ) | — | — | |||||||||||||
Future net cash flows | 514,591 | 286,855 | 36,151 | ||||||||||||||
10% annual discount for estimated timing of cash flows | (183,934 | ) | (131,560 | ) | (14,257 | ) | |||||||||||
Standardized measure of Discounted Future Net Cash Flow | $ | 330,657 | $ | 155,295 | $ | 21,894 | |||||||||||
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, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
Standardized Measure, beginning of the year | $ | 155,295 | $ | 21,894 | $ | — | |||||||||||
Net change in prices and production costs | (52,642 | ) | (5,354 | ) | 354 | ||||||||||||
Net change in future development costs | (2,122 | ) | (1,148 | ) | — | ||||||||||||
Sales, Less production costs | (104,099 | ) | (10,281 | ) | (354 | ) | |||||||||||
Extensions | 491,067 | 106,720 | 21,894 | ||||||||||||||
Acquisitions | — | 28,984 | — | ||||||||||||||
Revisions of previous quantity estimates | (38,201 | ) | 8,354 | — | |||||||||||||
Previously estimated development costs incurred | 16,807 | — | — | ||||||||||||||
Accretion of discount | 15,529 | 2,189 | — | ||||||||||||||
Net change in taxes | (178,732 | ) | — | — | |||||||||||||
Changes in timing and other | 27,755 | 3,937 | — | ||||||||||||||
Period Balance | $ | 330,657 | $ | 155,295 | $ | 21,894 | |||||||||||
Organization_and_Nature_of_Ope1
Organization and Nature of Operations - Additional information (Detail) (USD $) | 0 Months Ended | 12 Months Ended | |||
Jun. 25, 2014 | Jun. 24, 2014 | Dec. 31, 2014 | Jun. 25, 2014 | Dec. 31, 2013 | |
Business Acquisition [Line Items] | |||||
Non cash exchange of common share | 138,500,000 | ||||
Shares Issued | 30,300,000 | ||||
Common stock par value | $0.01 | $0.01 | $0.01 | $0.01 | |
Proceeds from initial public offering | $544,700,000 | ||||
Underwriting discount and commissions | 5,316,000 | ||||
Company and Selling Stockholders [Member] | |||||
Business Acquisition [Line Items] | |||||
Proceeds from initial public offering | 818,100,000 | ||||
IPO [Member] | |||||
Business Acquisition [Line Items] | |||||
Shares Issued | 21,500,000 | ||||
Underwriting discount and commissions | $35,800,000 | ||||
IPO [Member] | Stock Sold by Selling Stockholders [Member] | |||||
Business Acquisition [Line Items] | |||||
Shares Issued | 8,800,000 | ||||
IPO [Member] | Company and Selling Stockholders [Member] | |||||
Business Acquisition [Line Items] | |||||
Shares Issued | 30,300,000 |
Basis_of_Presentation_Detail
Basis of Presentation (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Ownership interest in predecessor | 100.00% |
Summary_of_Significant_Account3
Summary of Significant Accounting Policies - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Segment | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Accounts receivable | $46,378,000 | $8,678,000 | |
Pension liability | 1,321,000 | 1,497,000 | |
Gain on reduction of pension liability | 2,208,000 | 0 | |
Depreciation, depletion, and amortization expense | 89,218,000 | 6,163,000 | 404,000 |
Change in DD&A expense as a result of change in depreciation method | 1,300,000 | ||
Impairment charge | 34,855,000 | 2,081,000 | |
Deferred tax liability | 97,600,000 | ||
Asset retirement obligations credit adjusted discount rates | 9.89% | 8.96% | |
Increase in asset retirement obligation | 6,470,000 | ||
Number of operating segment | 1 | ||
Oxford acquisition [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Impairment charge | 30,900,000 | ||
Utica Shale [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Impairment charge | 4,000,000 | ||
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Fair value of commodity derivative contracts | 19,034,000 | ||
Oil and Gas Properties [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Depreciation, depletion, and amortization expense | 88,400,000 | 5,900,000 | 200,000 |
Other property and equipment [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Depreciation | 800,000 | 300,000 | 200,000 |
Other property and equipment [Member] | Minimum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Property and equipment, expected lives | 5 years | ||
Other property and equipment [Member] | Maximum [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Property and equipment, expected lives | 40 years | ||
Proved Oil And Gas Properties [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Impairment charge | 34,900,000 | 2,100,000 | 0 |
Unproved Oil And Gas Properties [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Impairment charge | 5,700,000 | 0 | 800,000 |
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 | 10000.00% | ||
Eclipse Resources Operating, LLC ("Eclipse Operating") [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Ownership percentage | 10000.00% | ||
Sales Revenue, Net [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Number of customers | 2 | 4 | 1 |
Unbilled Revenues [Member] | |||
Summary Of Significant Accounting Policies [Line Items] | |||
Accounts receivable | $24,100,000 | $4,100,000 |
Summary_of_Significant_Account4
Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Oil and natural gas properties: | ||
Unproved properties | $1,044,469 | $926,812 |
Proved properties | 802,112 | 97,528 |
Gross oil and natural gas properties | 1,846,581 | 1,024,340 |
Less accumulated depreciation, depletion and amortization | -131,857 | -8,596 |
Total oil and natural gas properties, net | 1,714,724 | 1,015,744 |
Other property and equipment | 8,912 | 2,392 |
Less accumulated depreciation | -809 | -52 |
Other property and equipment, net | 8,103 | 2,340 |
Total property and equipment, net | $1,722,827 | $1,018,084 |
Summary_of_Significant_Account5
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, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 72.00% | 87.00% | 100.00% |
Antero Resources Corporation [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 47.00% | 38.00% | 100.00% |
Devco Oil Company [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 24.00% | ||
Dominion Resources Inc [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 13.00% | ||
ARM Energy Management [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 25.00% | ||
Ergon [Member] | |||
Revenue, Major Customer [Line Items] | |||
Major customers and associated percentage of revenue | 12.00% |
Summary_of_Significant_Account6
Summary of Significant Accounting Policies - Summary for Concentration of Receivables, Net Of Allowances, By Product or Service (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $46,378 | $8,678 |
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 | 22,777 | 4,092 |
Product Concentration Risk [Member] | Joint interest owners [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 20,666 | 4,586 |
Product Concentration Risk [Member] | Miscellaneous other [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $2,935 |
Summary_of_Significant_Account7
Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Asset Retirement Obligation [Abstract] | |||
Asset retirement obligations, beginning of period | $9,055 | $13 | |
Revisions of prior estimates | 6,470 | ||
Additional liabilities incurred | 1,084 | 300 | 13 |
Assumption of Oxford asset retirement obligations | 8,378 | ||
Accretion | 791 | 364 | |
Asset retirement obligations, end of period | $17,400 | $9,055 | $13 |
Acquisition_Additional_Informa
Acquisition - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 26, 2013 | Jun. 24, 2014 | |
Business Acquisition [Line Items] | |||||
Recognized gain on bargain purchase | $353,000 | ||||
Depletion, depreciation, amortization and accretion expense | 89,218,000 | 6,163,000 | 404,000 | ||
Amortization of financing costs | 1,744,000 | 739,000 | |||
Amortization of debt discount | 2,308,000 | 1,247,000 | |||
Oxford acquisition [Member] | |||||
Business Acquisition [Line Items] | |||||
Acquired percentage of outstanding equity interests | 100.00% | ||||
Area of leasehold property held | 46,549 | 181,000 | |||
Aggregate purchase price | 652,500,000 | ||||
Escrow withheld from initial purchase price | 32,500,000 | ||||
Eclipse Resources Operating, LLC ("Eclipse Operating") [Member] | |||||
Business Acquisition [Line Items] | |||||
Total consideration | 100,000 | 100,000 | |||
Recognized gain on bargain purchase | 400,000 | ||||
Pro Forma Financial Information [Member] | |||||
Business Acquisition [Line Items] | |||||
Depletion, depreciation, amortization and accretion expense | 3,400,000 | 800,000 | |||
Amortization of financing costs | 700,000 | 1,500,000 | |||
Amortization of debt discount | 1,200,000 | 2,400,000 | |||
Interest expense | $26,900,000 | $53,900,000 |
Acquisition_Summary_of_Purchas
Acquisition - Summary of Purchase Price Allocation of Assets Acquired and Liabilities Assumed (Detail) (Oxford acquisition [Member], USD $) | 0 Months Ended | |
In Thousands, unless otherwise specified | Jun. 26, 2013 | Jun. 26, 2013 |
Oxford acquisition [Member] | ||
Consideration Given | ||
Cash | $652,500 | |
Allocation of Purchase Price | ||
Unproved properties | 621,039 | 621,039 |
Proved properties | 40,914 | 40,914 |
Cash | 653 | 653 |
Building and land | 1,500 | 1,500 |
Total assets | 664,106 | 664,106 |
Asset retirement obligations | -8,378 | -8,378 |
Pension obligation | -2,522 | -2,522 |
Other working capital | -706 | -706 |
Fair value of net assets acquired | $652,500 | $652,500 |
Acquisition_Summary_of_Pro_For
Acquisition - Summary of Pro Forma Financial Information (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2013 | Dec. 31, 2012 |
Business Combination Increase Decrease To Reflect Liabilities Acquired At Fair Value [Abstract] | ||
Oil and natural gas sales | $20,638 | $13,936 |
Net loss | ($71,131) | ($56,065) |
Sale_of_Oil_and_Natural_Gas_Pr1
Sale of Oil and Natural Gas Property Interest - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
acre | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Gain on sale of land | $0 | ||
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 | ||
Assets held for sale | 20,700,000 | ||
Purchase and Exploration Agreement [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Area of land sold | 1,220 | ||
Proceeds from sale of land | 8,500,000 | ||
Oil and Gas Properties [Member] | Purchase and Exploration Agreement [Member] | |||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |||
Percentage of interest in unproved oil and gas properties, agreed to sell | 70.00% | ||
Area of land sold | 21,114 | ||
Proceeds from sale of land | 126,500,000 | ||
Gain on sale of land | 0 | ||
Percentage of interest in proved oil and gas properties, sold | 70.00% | ||
Proceeds from the sale of proved oil and gas properties | 5,200,000 | ||
Proceeds from sale of net acreage in unit | 2,400,000 | ||
Percentage of drilling costs | 70.00% | ||
Reimbursement of drilling costs | 2,800,000 | ||
Gain on sale of proved oil and gas properties | $400,000 |
Derivative_Instruments_Summary
Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail) | 12 Months Ended |
Dec. 31, 2014 | |
MMBTU | |
Production Period January 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 66,219 |
Weighted Average Price ($/MMBtu) | 3.797 |
Production Period January 2016 - December 2016 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 25,000 |
Weighted Average Price ($/MMBtu) | 3.66 |
Swap [Member] | Production Period January 2015 - March 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 25,000 |
Weighted Average Price ($/MMBtu) | -1.067 |
Swap [Member] | Production Period April 2015 - October 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 25,000 |
Weighted Average Price ($/MMBtu) | -1.208 |
Put Option [Member] | Purchased Put [Member] | Production Period January 2015 - March 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 5,000 |
Weighted Average Price ($/MMBtu) | 4 |
Put Option [Member] | Purchased Put [Member] | Floor [Member] | Production Period January 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 15,000 |
Weighted Average Price ($/MMBtu) | 3.6 |
Put Option [Member] | Sold Put [Member] | Production Period January 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 16,800 |
Weighted Average Price ($/MMBtu) | 3.35 |
Put Option [Member] | Sold Put [Member] | Floor [Member] | Production Period January 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 15,000 |
Weighted Average Price ($/MMBtu) | 3 |
Call Option [Member] | Sold Put [Member] | Production Period January 2015 - March 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 5,000 |
Weighted Average Price ($/MMBtu) | 4.75 |
Call Option [Member] | Sold Put [Member] | Ceiling [Member] | Production Period January 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 15,000 |
Weighted Average Price ($/MMBtu) | 3.8 |
Derivative_Instruments_Fair_Va
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 $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Derivatives, Fair Value [Line Items] | ||
Gross Amount | $24,090 | |
Netting Adjustments | -5,056 | [1] |
Net Amount Presented in the Balance Sheets | 19,034 | |
Gross Amount | -5,056 | |
Netting Adjustments | 5,056 | [1] |
Net Amount Presented in the Balance Sheets | 0 | |
Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Gross Amount | -5,012 | |
Netting Adjustments | 5,012 | [1] |
Net Amount Presented in the Balance Sheets | 0 | |
Noncurrent Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Gross Amount | -44 | |
Netting Adjustments | 44 | [1] |
Net Amount Presented in the Balance Sheets | 0 | |
Other Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Gross Amount | 22,349 | |
Netting Adjustments | -5,012 | [1] |
Net Amount Presented in the Balance Sheets | 17,337 | |
Other Noncurrent Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Gross Amount | 1,741 | |
Netting Adjustments | -44 | [1] |
Net Amount Presented in the Balance Sheets | $1,697 | |
[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_Summary1
Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) (USD $) | 12 Months Ended |
In Thousands, unless otherwise specified | Dec. 31, 2014 |
Derivative Instruments, Gain (Loss) [Line Items] | |
Amount of (Loss)/Gain Recognized in Income | $20,791 |
Commodity Contract [Member] | Gain on Derivative Instruments [Member] | |
Derivative Instruments, Gain (Loss) [Line Items] | |
Amount of (Loss)/Gain Recognized in Income | $20,791 |
Fair_Value_Measurements_Schedu
Fair Value Measurements - Schedule of Fair Value Measured on a Recurring Basis (Detail) (Fair Value, Measurements, Recurring [Member], USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | |
Total fair value | $19,034 |
Level 2 [Member] | |
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | |
Total fair value | 19,034 |
Commodity Contract [Member] | |
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | |
Total fair value | 19,034 |
Commodity Contract [Member] | Level 2 [Member] | |
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | |
Total fair value | $19,034 |
Debt_Additional_Information_De
Debt - Additional Information (Detail) (USD $) | 12 Months Ended | 1 Months Ended | 0 Months Ended | 1 Months Ended | |||
Dec. 31, 2014 | Mar. 31, 2015 | Jun. 26, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Jan. 15, 2014 | Jan. 15, 2015 | |
Debt Instrument [Line Items] | |||||||
Debt discount | 8,500,000 | $10,800,000 | |||||
Revolving credit facility | 500,000,000 | ||||||
Borrowing base | 100,000,000 | ||||||
Outstanding letters of credit | 26,900,000 | ||||||
Outstanding borrowings | 0 | ||||||
Available capacity on the Revolving Credit Facility | 73,100,000 | ||||||
Minimum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fees on unused portion of revolving credit facility | 0.38% | ||||||
Maximum [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Commitment fees on unused portion of revolving credit facility | 0.50% | ||||||
Scenario, Forecast [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Revolving credit facility, increase in borrowing base | 125,000,000 | ||||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Aggregate principal amount | 300,000,000 | 100,000,000 | |||||
Debt instrument interest rate | 12.00% | ||||||
Notes issued percentage of par | 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 | |||||
Amortization of deferred financing costs and debt discount | 4,100,000 | ||||||
Senior unsecured notes redemption price description | The Company has the right to redeem all or a portion of the Senior Unsecured Notes prior to the 2-year anniversary of the final funding date, which the Company refers to as the Non-Call Period, by paying a redemption price equal to 100.0% times a bmake whole premiumb equal to the greater of 106.0% or an amount computed under the Indenture governing the Senior Unsecured Notes (the bIndentureb) plus accrued and unpaid interest. | ||||||
Accrued interest | 25,300,000 | ||||||
Interest payments terms | Interest is payable on July 15 and January 15 each year, beginning in January 2014 | ||||||
Debt instrument, indenture description | The Company may not among other things, directly or indirectly (1) consolidate or merge with or into another Person (whether or not the Company is the survivor), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or more than 50% of its properties or assets, in one or more related transactions, to another Person, unless in each case certain restrictive conditions contained in the Indenture are met. | ||||||
Principal amount outstanding | 422,500,000 | ||||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | Level 2 [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Fair value | 482,800,000 | ||||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | Additional Notes Option [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Aggregate principal amount | 100,000,000 | ||||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | Interest Paid in Cash [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument interest rate | 12.00% | ||||||
Percentage of interest payments per annum | 6.00% | ||||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | Paid In Kind Interest [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Debt instrument interest rate | 13.00% | ||||||
Percentage of interest payments per annum | 7.00% | ||||||
Accrued interest | 22,500,000 | ||||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | Subsequent Event [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Accrued interest | 12,700,000 | ||||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | Subsequent Event [Member] | Paid In Kind Interest [Member] | |||||||
Debt Instrument [Line Items] | |||||||
Accrued interest | $14,800,000 |
Debt_Summary_of_Senior_Unsecur
Debt - Summary of Senior Unsecured Notes Redemption Prices (Detail) (12% Senior Unsecured PIK Notes Due 2018 [Member]) | 12 Months Ended |
Dec. 31, 2014 | |
Year 1 [Member] | |
Debt Instrument, Redemption [Line Items] | |
Senior unsecured notes redemption price, percentage | 106.00% |
Year 2 [Member] | |
Debt Instrument, Redemption [Line Items] | |
Senior unsecured notes redemption price, percentage | 103.00% |
Year 3 and thereafter [Member] | |
Debt Instrument, Redemption [Line Items] | |
Senior unsecured notes redemption price, percentage | 100.00% |
Benefit_Plans_Additional_Infor
Benefit Plans - Additional Information (Detail) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Employees | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Gain on reduction of pension liability | $2,208,000 | $0 | |
Defined Benefit Pension Plan [Member] | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Number of employees covered under defined benefit pension plan | 28 | ||
Gain on reduction of pension liability | -2,208,000 | ||
Matching contribution by the company to the plan | 100.00% | ||
Percentage of employees' eligible compensation | 6.00% | ||
Company contribution to defined benefit plan | $400,000 | $200,000 | $100,000 |
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_Pension_Benefit_P
Benefit Plan - Pension Benefit Plan (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Change in benefit obligation | ||
Benefit obligation at beginning of year | $9,018 | |
Oxford assumed benefit obligations | 9,045 | |
Service cost | 70 | 144 |
Interest cost | 335 | 203 |
Gain on reduction of pension liability | -2,208 | 0 |
Actuarial loss | 1,616 | -350 |
Benefits paid | -2,031 | -24 |
Benefit obligation at end of period | 6,800 | 9,018 |
Change in plan assets | ||
Fair value of plan assets at beginning of year | 7,521 | |
Oxford assumed plan assets | 6,523 | |
Actual return on plan assets | -11 | 1,012 |
Employer contributions | 10 | |
Benefit paid | -2,031 | -24 |
Fair value of plan assets at end of period | $5,479 | $7,521 |
Benefit_Plans_Assets_in_Excess
Benefit Plans - Assets in Excess of (Less than) Benefit Obligation , Other Amounts Recognized in Other Comprehensive Loss and Accumulated Other Comprehensive Income (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Assets in excess of (less than) benefit obligation | ||
Vested amount | ($6,800) | ($7,039) |
Additional benefits required | -1,979 | |
Projected benefit obligation | -6,800 | -9,018 |
Funded amount | 5,479 | 7,521 |
Unfunded amount | -1,321 | -1,497 |
Other amounts recognized in other comprehensive loss during the year ended December 31, 2014 | ||
Assets in excess of (less than) benefit obligation at end of period | -1,321 | -1,497 |
Amounts recorded in the consolidated balance sheet consist of: | ||
Accrued benefit liability | -1,321 | -1,497 |
Total recorded | -1,321 | -1,497 |
Beginning amount recorded in other accumulated comprehensive income | 1,168 | |
Amounts recorded in accumulated other comprehensive loss consist of: | ||
Pension obligation adjustment, net of tax | -1,716 | 1,168 |
Total recorded in accumulated other comprehensive income | ($548) | $1,168 |
Benefit_Plans_Summary_Of_Long_
Benefit Plans - Summary Of Long Term Expected Rate Of Return On Funded Assets Established Benefit Plan (Detail) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Weighted average assumptions to determine benefit obligation at December 31, 2014 | ||
Discount rate | 3.75% | 4.75% |
Expected rate of return | 6.00% | 6.00% |
Rate of compensation increase | 4.00% | 4.00% |
Inflation | 3.00% | 3.00% |
Benefit_Plans_Components_of_Pe
Benefit Plans - Components of Pension Benefit Cost (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||
Service cost | $70 | $144 |
Interest cost | 335 | 203 |
Expected return on plan assets | -448 | -195 |
Amortization of transition obligation | 70 | 140 |
Amortization of net (gain) loss | 29 | |
Net period benefit cost | $56 | $292 |
Benefit_Plans_Summary_Of_Expec
Benefit Plans - Summary Of Expected Benefit Payments (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Defined Benefit Plan, Expected Future Benefit Payments, Fiscal Year Maturity [Abstract] | |
Benefit payments 2015 | $8 |
Benefit payments 2016 | 9 |
Benefit payments 2017 | 25 |
Benefit payments 2018 | 68 |
Benefit payments 2019 | 106 |
Benefit payments 2020-2024 | $1,798 |
Benefit_Plans_Summary_Of_Inves
Benefit Plans - Summary Of Investment Strategy For Benefit Plan (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Plan assets by category | ||
Plan assets | $5,479 | $7,521 |
Plan assets, percentage | 100.00% | 100.00% |
Equity Securities [Member] | ||
Plan assets by category | ||
Plan assets | 7,398 | |
Plan assets, percentage | 98.30% | |
Debt Securities [Member] | ||
Plan assets by category | ||
Plan assets | 5,392 | 117 |
Plan assets, percentage | 98.40% | 1.60% |
Cash and Cash Equivalents [Member] | ||
Plan assets by category | ||
Plan assets | $87 | $6 |
Plan assets, percentage | 1.60% | 0.10% |
Benefit_Plans_Summary_of_Fair_
Benefit Plans - Summary of Fair Value Of Pension Assets Benefit Plan (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension assets | $5,479 | $7,521 |
Level 1 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension assets | 5,206 | 7,404 |
Level 2 [Member] | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Pension assets | $273 | $117 |
Equity_Additional_Information_
Equity - Additional Information (Detail) (USD $) | 0 Months Ended | 12 Months Ended | 0 Months Ended | 12 Months Ended | |||||
In Millions, except Share data, unless otherwise specified | Jun. 25, 2014 | Dec. 31, 2014 | Dec. 31, 2014 | Oct. 07, 2014 | Jun. 25, 2015 | Dec. 27, 2014 | Jan. 28, 2015 | Dec. 31, 2013 | Dec. 31, 2012 |
Director | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||||||
Shares Issued | 30,300,000 | ||||||||
Proceeds from initial public offering | $544.70 | ||||||||
Unrecognized compensation cost related to Incentive Units | 0.7 | 0.7 | |||||||
Unrecognized compensation cost related to Incentive Units, weighted-average recognition period | 6 years 4 months 2 days | ||||||||
Common Stock Shares Authorized | 1,000,000,000 | 1,000,000,000 | 1,000,000,000 | ||||||
Common stock, par value | $0.01 | $0.01 | $0.01 | $0.01 | |||||
Restricted Stock [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||||||
Common Stock Shares Authorized | 16,000,000 | 16,000,000 | |||||||
Restricted shares of common stock issued | 31,115 | ||||||||
Common stock, par value | $0.01 | ||||||||
Number of non employee directors | 7 | ||||||||
Restricted stock expense | 0.1 | ||||||||
Restricted Stock [Member] | Scenario, Forecast [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||||||
Restricted stock expense | 0.3 | ||||||||
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] | |||||||||
Number of shares agreed to issue and sell | 62,500,000 | ||||||||
Stock price, per share | $7.04 | ||||||||
Private Placement [Member] | Subsequent Event [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||||||
Proceeds from issuance of Common Stock | 434 | ||||||||
Maximum [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||||||
Total compensation cost related to the issuance of Incentive Units | $0.10 | $0.10 | $0.10 | ||||||
Common Class C-1 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||||||
Number of shares authorized to be issue | 1,000 | 1,000 | |||||||
Common Class C-2 [Member] | |||||||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||||||||
Number of shares authorized to be issue | 1,000 | 1,000 |
Earnings_Loss_Per_Share_Schedu
Earnings (Loss) Per Share - Schedule of Earnings Per Share (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Loss (numerator): | |||||||||||
Net loss | ($33,023) | ($19,054) | ($112,648) | ($18,451) | ($19,558) | ($16,484) | ($5,740) | ($1,759) | ($183,176) | ($43,541) | ($8,759) |
Weighted-average shares (denominator): | |||||||||||
Weighted-average number of shares of common stock-basic and diluted | 144,369 | 75,261 | 13,880 | ||||||||
Loss per common share: | |||||||||||
Basic and diluted | ($0.21) | ($0.12) | ($0.84) | ($0.15) | ($0.16) | ($0.14) | ($0.10) | ($0.10) | ($1.27) | ($0.58) | ($0.63) |
Related_Party_Transactions_Add
Related Party Transactions - Additional Information (Detail) (USD $) | 12 Months Ended | 0 Months Ended | |||
Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2010 | Dec. 31, 2014 | Jun. 24, 2014 | |
Related Party Transaction [Line Items] | |||||
Management fee for operation | $14,700,000 | $4,200,000 | |||
Accrued liability | 972,000 | ||||
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 | 200,000 | ||||
Eclipse Resources Operating, LLC ("Eclipse Operating") [Member] | |||||
Related Party Transaction [Line Items] | |||||
Total consideration | $100,000 | $100,000 |
Commitments_and_Contingencies_1
Commitments and Contingencies - Additional Information (Detail) (USD $) | 12 Months Ended | |||
In Millions, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Jun. 26, 2013 |
acre | ||||
Loss Contingencies [Line Items] | ||||
Capitalized leasehold costs | $0.60 | |||
Lease agreement period | 5 years | |||
Rent expense | $0.30 | $0.10 | $0 | |
Lease agreement, term | The Company leases office space under operating leases that expire between the years 2015 to 2025. | |||
Oxford acquisition [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 46,549 | 181,000 | ||
Oxford acquisition [Member] | Modification to Lease [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 34,256 | |||
Oxford acquisition [Member] | Unpredicted Modification to Lease [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 12,293 | |||
Other Lawsuit [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 157 |
Commitment_and_Contingencies_F
Commitment and Contingencies - Future Minimum Lease Payments Required Under Lease Agreements (Detail) (USD $) | Dec. 31, 2014 |
In Thousands, unless otherwise specified | |
Commitments and Contingencies Disclosure [Abstract] | |
2015 | $773 |
2016 | 749 |
2017 | 753 |
2018 | 756 |
2019 | 756 |
Thereafter | 3,494 |
Total minimum lease payments | $7,281 |
Income_Tax_Additional_Informat
Income Tax - Additional Information (Detail) (USD $) | 12 Months Ended |
Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |
Percentage of annual effective income tax expense | 64.47% |
Income taxes paid | $0 |
Valuation allowance | 0 |
Reserve for uncertain tax positions | 0 |
U.S. federal tax loss carryforward ("NOL") | $364,000,000 |
Tax loss carryforward expiration year | 2034 |
Income_Tax_Segregation_of_Inco
Income Tax - Segregation of Income Tax Provision Based on Location of Operations (Detail) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | |
Current | ||
Federal | $0 | [1] |
State | 132 | [1] |
Total current | 132 | [1] |
Deferred | ||
Federal | 71,838 | [1] |
State | -171 | [1] |
Total deferred | 71,667 | [1] |
Income tax expense | $71,799 | [1] |
[1] | For the 2014 and 2013 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. |
Income_Taxes_Schedule_of_Effec
Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Detail) (USD $) | 12 Months Ended | |||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Income Tax Disclosure [Abstract] | ||||
Loss before income taxes | ($111,377) | [1] | ($43,541) | ($8,759) |
Statutory rate | 35.00% | [1] | ||
Income tax benefit computed at statutory rate | -38,982 | [1] | ||
Reconciling items: | ||||
Non-deductible pre-IPO loss | 13,264 | [1] | ||
State income taxes | -39 | [1] | ||
Other, net | 71 | [1] | ||
Change in tax status | 97,609 | [1] | ||
Gain on acquisition of Eclipse Operating | -124 | [1] | ||
Income tax expense | $71,799 | [1] | ||
[1] | For the 2014 and 2013 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. |
Income_Taxes_Components_of_Def
Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) (USD $) | Dec. 31, 2014 | |
In Thousands, unless otherwise specified | ||
Deferred Tax Assets Liabilities [Line Items] | ||
Net current deferred tax asset | $2,244 | [1] |
Net non-current deferred tax asset | 128,186 | [1] |
Net current deferred tax liabilities | 7,490 | [1] |
Net non-current deferred tax liability | 194,900 | [1] |
Net deferred tax liability-current | 5,246 | [1] |
Net deferred tax liability-noncurrent | 66,714 | [1] |
Derivative Instruments and Other [Member] | ||
Deferred Tax Assets Liabilities [Line Items] | ||
Net current deferred tax liabilities | 6,966 | [1] |
Other Assets [Member] | ||
Deferred Tax Assets Liabilities [Line Items] | ||
Other, net | 2,140 | [1] |
Net non-current deferred tax asset | 668 | [1] |
Other Liabilities [Member] | ||
Deferred Tax Assets Liabilities [Line Items] | ||
Net current deferred tax liabilities | 524 | [1] |
Federal Tax Loss Carryforwards [Member] | ||
Deferred Tax Assets Liabilities [Line Items] | ||
State effect of current deferreds | 104 | [1] |
Net non-current deferred tax asset | 127,497 | [1] |
State Tax Effect [Member] | ||
Deferred Tax Assets Liabilities [Line Items] | ||
Net non-current deferred tax asset | 21 | [1] |
Oil and Gas Properties [Member] | ||
Deferred Tax Assets Liabilities [Line Items] | ||
Net non-current deferred tax liability | $194,900 | [1] |
[1] | For the 2014 and 2013 comparable periods, the calculation is not applicable as the Company was not a taxable entity until June 25, 2014. |
Quarterly_Financial_Informatio2
Quarterly Financial Information (unaudited) (Detail) (USD $) | 3 Months Ended | 12 Months Ended | |||||||||
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Sep. 30, 2013 | Jun. 30, 2013 | Mar. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Total operating revenues | $50,371 | $35,702 | $26,955 | $24,788 | $7,567 | $4,510 | $570 | $288 | $137,816 | $12,935 | $370 |
Total operating expenses | 101,026 | 60,806 | 34,166 | 25,992 | 17,753 | 10,055 | 5,766 | 2,052 | 221,990 | 35,626 | 9,166 |
Operating loss | -50,655 | -25,104 | -7,211 | -1,204 | -10,186 | -5,545 | -5,196 | -1,764 | -84,174 | -22,691 | -8,796 |
Net loss | ($33,023) | ($19,054) | ($112,648) | ($18,451) | ($19,558) | ($16,484) | ($5,740) | ($1,759) | ($183,176) | ($43,541) | ($8,759) |
Loss per common share: | |||||||||||
Basic and diluted | ($0.21) | ($0.12) | ($0.84) | ($0.15) | ($0.16) | ($0.14) | ($0.10) | ($0.10) | ($1.27) | ($0.58) | ($0.63) |
Supplemental_Oil_and_Natural_G2
Supplemental Oil and Natural Gas Information - Summary of Capitalized Costs (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Oil and natural gas properties: | ||
Proved properties | $1,044,469 | $926,812 |
Unproved properties | 802,112 | 97,528 |
Total oil and natural gas properties | 1,846,581 | 1,024,340 |
Less accumulated depreciation, depletion and amortization | -131,857 | -8,596 |
Net oil and natural gas properties | $1,714,724 | $1,015,744 |
Supplemental_Oil_and_Natural_G3
Supplemental Oil and Natural Gas Information - Summary of Costs Incurred in Oil and Natural Gas Properties (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
Acquisition costs: | |||
Proved properties | $40,914 | $2,498 | |
Unproved properties | 134,156 | 621,039 | 158,131 |
Development cost | 714,796 | 258,825 | 16,344 |
Exploration cost | 21,186 | 3,022 | 3,899 |
Total acquisition, development and exploration costs | $870,138 | $923,800 | $180,872 |
Supplemental_Oil_and_Natural_G4
Supplemental Oil and Natural Gas Information - Proved Developed and Proved Undeveloped Reserves (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
MMcfe | MMcfe | MMcfe | |
Reserve Quantities [Line Items] | |||
Revisions (energy) | -19,305.30 | 1,978.40 | |
Proved Developed and Undeveloped Reserves (energy), beginning balance | 78,478.60 | 6,334.20 | 0 |
Extensions and discoveries (energy) | 323,140.10 | 59,419 | 6,368.90 |
Acquisition of reserves (energy) | 12,397.60 | ||
Production (energy) | -26,545.50 | -1,650.20 | -34.7 |
Proved Developed and Undeveloped Reserves (energy), ending balance | 355,767.90 | 78,478.60 | 6,334.20 |
Proved developed reserves (energy) | 196,796.40 | 44,466.60 | 2,724 |
Proved undeveloped reserves (energy) | 158,971.50 | 34,012 | 3,610.10 |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed and Undeveloped Reserves, beginning balance | 52,344.40 | 2,956.10 | |
Revisions | -12,091.20 | 2,645 | |
Extensions and discoveries | 235,816.90 | 41,215.50 | 2,963.80 |
Acquisition of reserves | 6,646.60 | ||
Production | -19,760.20 | -1,118.80 | -7.7 |
Proved Developed and Undeveloped Reserves, ending balance | 256,309.90 | 52,344.40 | 2,956.10 |
Proved developed reserves | 132,959.50 | 27,880.30 | 1,289.60 |
Proved undeveloped reserves | 123,350.40 | 24,464.10 | 1,666.60 |
Natural Gas Liquids [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed and Undeveloped Reserves, beginning balance | 1,938.40 | 177 | |
Revisions | -739.7 | 52.1 | |
Extensions and discoveries | 10,216.30 | 1,710.60 | 177 |
Production | -536 | -1.3 | |
Proved Developed and Undeveloped Reserves, ending balance | 10,879 | 1,938.40 | 177 |
Proved developed reserves | 6,758.60 | 1,056.20 | 64.6 |
Proved undeveloped reserves | 4,120.40 | 882.2 | 112.4 |
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Proved Developed and Undeveloped Reserves, beginning balance | 2,417.40 | 386 | |
Revisions | -462.6 | -163.2 | |
Extensions and discoveries | 4,337.50 | 1,323.30 | 390.5 |
Acquisition of reserves | 958.5 | ||
Production | -594.9 | -87.2 | -4.5 |
Proved Developed and Undeveloped Reserves, ending balance | 5,697.40 | 2,417.40 | 386 |
Proved developed reserves | 3,880.90 | 1,708.10 | 174.5 |
Proved undeveloped reserves | 1,816.40 | 709.2 | 211.5 |
Recovered_Sheet1
Supplemental Oil And Natural Gas Information - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
MMcfe | MMcfe | MMcfe | |
Extractive Industries [Abstract] | |||
Extension and discoveries | 323,140.10 | 59,419 | 6,368.90 |
Discount rate | 10.00% |
Supplemental_Oil_and_Natural_G5
Supplemental Oil and Natural Gas Information - Standardized Measure of Discounted Net Future Cash Flows (Detail) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
In Thousands, unless otherwise specified | |||
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract] | |||
Future cash inflows (total revenues) | $1,870,319 | $479,527 | $50,614 |
Future production costs (severance and ad valorem taxes plus LOE) | -728,041 | -116,161 | -6,448 |
Future development costs (capital costs) | -350,187 | -76,511 | -8,015 |
Future income tax expense | -277,500 | ||
Future net cash flows | 514,591 | 286,855 | 36,151 |
10% annual discount for estimated timing of cash flows | -183,934 | -131,560 | -14,257 |
Standard measure of Discounted Future Net Cash Flow | $330,657 | $155,295 | $21,894 |
Supplemental_Oil_and_Natural_G6
Supplemental Oil and Natural Gas Information - Changes in Standardized Measure of Discounted Net Cash Flows (Detail) (USD $) | 12 Months Ended | ||
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 |
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 | $155,295 | $21,894 | |
Net change in prices and production costs | -52,642 | -5,354 | 354 |
Net change in future development costs | -2,122 | -1,148 | |
Sales, Less production costs | -104,099 | -10,281 | -354 |
Extensions | 491,067 | 106,720 | 21,894 |
Acquisitions | 28,984 | ||
Revisions of previous quantity estimates | -38,201 | 8,354 | |
Previously estimated development costs incurred | 16,807 | ||
Accretion of discount | 15,529 | 2,189 | |
Net change in taxes | -178,732 | ||
Changes in timing and other | 27,755 | 3,937 | |
Period Balance | $330,657 | $155,295 | $21,894 |