Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2015 | Aug. 14, 2015 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Jun. 30, 2015 | |
Document Fiscal Year Focus | 2,015 | |
Document Fiscal Period Focus | Q2 | |
Trading Symbol | ECR | |
Entity Registrant Name | Eclipse Resources Corp | |
Entity Central Index Key | 1,600,470 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 222,668,788 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 257,622 | $ 67,517 |
Accounts receivable | 32,962 | 46,378 |
Assets held for sale | 3,618 | 20,673 |
Other current assets | 12,309 | 19,711 |
Total current assets | 306,511 | 154,279 |
Oil and natural gas properties, successful efforts method | ||
Unproved properties | 1,003,018 | 1,044,469 |
Proved properties, net | 827,480 | 670,255 |
Other property and equipment, net | 8,836 | 8,103 |
Total property and equipment, net | 1,839,334 | 1,722,827 |
OTHER NONCURRENT ASSETS | ||
Debt issuance costs, net of $3.5 million and $2.5 million of amortization, respectively | 6,617 | 6,058 |
Other assets | 1,436 | 1,782 |
TOTAL ASSETS | 2,153,898 | 1,884,946 |
CURRENT LIABILITIES | ||
Accounts payable | 82,282 | 137,415 |
Accrued capital expenditures | 20,470 | 51,360 |
Accrued liabilities | 21,525 | 13,576 |
Accrued interest payable | 26,266 | 25,187 |
Deferred income taxes | 3,624 | 5,246 |
Total current liabilities | 154,167 | 232,784 |
NONCURRENT LIABILITIES | ||
Debt, net of unamortized discount of $7.4 million and $8.5 million, respectively | 429,995 | 414,016 |
Pension obligations | 1,449 | 1,321 |
Asset retirement obligations | 18,488 | 17,400 |
Other liabilities | 2,560 | |
Deferred income taxes | 34,229 | 66,714 |
Total liabilities | $ 640,888 | $ 732,235 |
COMMITMENTS AND CONTINGENCIES | ||
STOCKHOLDERS' EQUITY | ||
Preferred stock, 50,000,000 shares authorized, no shares issued and outstanding | ||
Common stock, $0.01 par value, 1,000,000,000 shares authorized, 222,663,611 and 160,031,115 shares issued and outstanding, respectively | $ 2,226 | $ 1,600 |
Additional paid in capital | 1,826,768 | 1,391,004 |
Accumulated deficit | (315,418) | (239,345) |
Accumulated other comprehensive loss | (566) | (548) |
Total stockholders' equity | 1,513,010 | 1,152,711 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ 2,153,898 | $ 1,884,946 |
Condensed Consolidated Balance3
Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions | Jun. 30, 2015 | Dec. 31, 2014 |
Statement of Financial Position [Abstract] | ||
Debt issuance costs, amortization | $ 3.5 | $ 2.5 |
Debt, unamortized discount | $ 7.4 | $ 8.5 |
Preferred stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Common Stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 1,000,000,000 | 1,000,000,000 |
Common stock, shares issued | 222,663,611 | 160,031,115 |
Common stock, shares outstanding | 222,663,611 | 160,031,115 |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
REVENUES | ||||
Oil and natural gas sales | $ 64,984 | $ 26,955 | $ 111,598 | $ 51,743 |
Brokered natural gas and marketing | 9,469 | 6,669 | ||
Total revenues | 74,453 | 26,955 | 118,267 | 51,743 |
OPERATING EXPENSES | ||||
Lease operating | 3,589 | 2,643 | 6,935 | 4,434 |
Transportation, gathering and compression | 22,634 | 2,949 | 35,085 | 3,853 |
Production and ad valorem taxes | 3,078 | 702 | 5,178 | 1,055 |
Brokered natural gas and marketing | 10,795 | 10,795 | ||
Depreciation, depletion and amortization | 60,641 | 9,957 | 103,073 | 21,984 |
Exploration | 6,243 | 9,295 | 19,696 | 13,840 |
General and administrative | 12,717 | 8,429 | 24,660 | 16,823 |
Rig termination | 366 | 7,423 | ||
Accretion of asset retirement obligations | 399 | 191 | 785 | 377 |
Gain on sale of assets | (5,553) | (5,473) | (1,585) | |
Gain on reduction of pension obligations | (2,208) | |||
Total operating expenses | 114,909 | 34,166 | 208,157 | 60,158 |
OPERATING LOSS | (40,456) | (7,211) | (89,890) | (8,415) |
OTHER INCOME (EXPENSE) | ||||
Gain (loss) on derivative instruments | (3,523) | (863) | 7,848 | (4,474) |
Interest expense, net | (14,401) | (11,618) | (28,422) | (25,254) |
Other income (expense) | (2) | 1,585 | 400 | 1,585 |
Total other expense, net | (17,926) | (10,896) | (20,174) | (28,143) |
LOSS BEFORE INCOME TAXES | (58,382) | (18,107) | (110,064) | (36,558) |
INCOME TAX BENEFIT (EXPENSE) | 16,412 | (94,541) | 33,991 | (94,541) |
NET LOSS | $ (41,970) | $ (112,648) | $ (76,073) | $ (131,099) |
NET LOSS PER COMMON SHARE | ||||
Basic and diluted | $ (0.19) | $ (0.84) | $ (0.36) | $ (1.02) |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING | ||||
Basic and diluted | 222,502 | 134,309 | 213,178 | 128,480 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Comprehensive Loss (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Statement of Comprehensive Income [Abstract] | ||||
Net loss | $ (41,970) | $ (112,648) | $ (76,073) | $ (131,099) |
Other comprehensive income (loss): | ||||
Pension obligation adjustment, net of tax | 192 | (371) | (18) | (1,233) |
TOTAL COMPREHENSIVE LOSS | $ (41,778) | $ (113,019) | $ (76,091) | $ (132,332) |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-in Capital [Member] | Accumulated Deficit [Member] | Accumulated Other Comprehensive Income (Loss) [Member] |
Beginning Balances at Dec. 31, 2014 | $ 1,152,711 | $ 1,600 | $ 1,391,004 | $ (239,345) | $ (548) |
Beginning Balance, shares at Dec. 31, 2014 | 160,031,115 | ||||
Shares of common stock issued in private placement, net of offering costs | 434,233 | $ 625 | 433,608 | ||
Shares of common stock issued in private placement, net of offering costs, shares | 62,500,000 | ||||
Stock-based compensation | 2,157 | 2,157 | |||
Issuance of restricted stock | $ 1 | (1) | |||
Issuance of restricted stock, shares | 132,496 | ||||
Pension obligation adjustment, net of tax | (18) | (18) | |||
Net loss | (76,073) | (76,073) | |||
Ending Balances at Jun. 30, 2015 | $ 1,513,010 | $ 2,226 | $ 1,826,768 | $ (315,418) | $ (566) |
Ending Balance, shares at Jun. 30, 2015 | 222,663,611 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Stockholders' Equity (Unaudited) (Parenthetical) - $ / shares | Jun. 30, 2015 | Dec. 31, 2014 |
Statement of Stockholders' Equity [Abstract] | ||
Common Stock, par value | $ 0.01 | $ 0.01 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2014 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net loss | $ (76,073) | $ (131,099) |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | ||
Depreciation, depletion and amortization | 103,073 | 21,984 |
Exploration expense | 6,073 | 3,795 |
Pension benefit costs | 101 | 111 |
Stock-based compensation | 2,157 | 56 |
Accretion of asset retirement obligations | 785 | 377 |
Gain on reduction of pension obligation | (2,208) | |
Loss (gain) on derivative instruments | (7,848) | 4,474 |
Net cash received (paid) on settled derivatives | 14,422 | (2,231) |
Net cash paid for option premium | (141) | |
Gain on sale of assets | (5,473) | (1,585) |
Deferred income taxes | (34,107) | 94,541 |
Interest not paid in cash | 1,232 | 2,166 |
Amortization of deferred financing costs | 1,018 | 885 |
Amortization of debt discount | 1,193 | 1,115 |
Changes in operating assets and liabilities, net of acquisitions: | ||
Accounts receivable | 13,007 | (31,795) |
Other assets | 225 | (883) |
Accounts payable and accrued liabilities | 29,724 | 26,294 |
Accrued liabilities-related parties | (1,951) | |
Net cash provided by (used in) operating activities | 49,509 | (16,095) |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures on oil and natural gas properties | (327,856) | (268,205) |
Additions to other property and equipment | (1,284) | (1,454) |
Acquisition of business, net of cash acquired | 754 | |
Proceeds from the sale of assets | 37,287 | |
Net cash used in investing activities | (291,853) | (268,905) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Debt issuance costs | (1,577) | (1,122) |
Repayments of long-term debt | (207) | (62) |
Capital contributions | 124,667 | |
Proceeds from issuance of common stock, net of underwriting fees | 440,000 | 550,025 |
Equity issuance costs | (5,767) | (4,597) |
Net cash provided by financing activities | 432,449 | 668,911 |
Net increase in cash and cash equivalents | 190,105 | 383,911 |
Cash and cash equivalents at beginning of period | 67,517 | 109,509 |
Cash and cash equivalents at end of period | 257,622 | 493,420 |
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | ||
Cash paid for interest | 13,080 | 448 |
Cash paid for income taxes | 37 | |
SUPPLEMENTAL DISCLOSURE OF NON-CASH ACTIVITIES: | ||
Asset retirement obligations incurred, including changes in estimate | 303 | 102 |
Additions of other property through debt financing | 888 | 507 |
Additions to oil and natural gas properties - changes in accounts payable, accrued liabilities, and accrued capital expenditures | (88,418) | 78,890 |
Interest paid-in-kind | $ 14,786 | $ 22,461 |
Organization and Nature of Oper
Organization and Nature of Operations | 6 Months Ended |
Jun. 30, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Nature of Operations | Note 1—Organization and Nature of Operations Eclipse Resources Corporation (the “Company”) is an independent exploration and production company engaged in the acquisition and development of oil and natural gas properties in the Appalachian Basin of the United States, which encompasses the Utica Shale and Marcellus Shale prospective areas. |
Basis of Presentation
Basis of Presentation | 6 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
Basis of Presentation | Note 2—Basis of Presentation The accompanying condensed consolidated financial statements, which are unaudited except the condensed consolidated balance sheet at December 31, 2014 which is derived from the Company’s audited financial statements, and are presented in accordance with the requirements of accounting principles generally accepted in the United States (“U.S. GAAP”) for interim reporting. They do not include all disclosures normally made and contained in annual financial statements. In management’s opinion, all adjustments necessary for a fair presentation of the Company’s financial position, results of operations and cash flows for the periods disclosed have been made. These interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements, and notes to those statements, included in the Company’s Annual Report on Form 10-K filed with the SEC on March 9, 2015. Operating results for interim periods may not necessarily be indicative of the results of operations for the full year ending December 31, 2015 or any other future periods. Preparation in accordance with U.S. GAAP requires the Company to (1) adopt accounting policies within accounting rules set by the Financial Accounting Standards Board (“FASB”) and (2) make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and other disclosed amounts. “Note 3— Summary of Significant Accounting Policies” • estimates of proved reserves of oil and natural gas, which affect the calculations of depreciation, depletion and amortization and impairment of capitalized costs of oil and natural gas properties; • estimates of asset retirement obligations; • estimates of the fair value of oil and natural gas properties the Company owns, particularly properties that the Company has not yet explored, or fully explored, by drilling and completing wells; • impairment of undeveloped properties and other assets; and • depreciation and depletion of property and equipment. Actual results may differ from estimates and assumptions of future events and these revisions could be material. Future production may vary materially from estimated oil and natural gas proved reserves. Actual future prices may vary significantly from price assumptions. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 6 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Note 3—Summary of Significant Accounting Policies (a) Cash and Cash Equivalents Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits. (b) Accounts Receivable Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of June 30, 2015 or December 31, 2014. The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $27.5 million and $24.1 million of accrued revenues, net of certain expenses at June 30, 2015 and December 31, 2014, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets. (c) Property and Equipment Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “ Depreciation, Depletion and Amortization Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. A summary of property and equipment including oil and natural gas properties is as follows (in thousands): June 30, December 31, Oil and natural gas properties: Unproved $ 1,003,018 $ 1,044,469 Proved 1,060,823 802,112 Gross oil and natural gas properties 2,063,841 1,846,581 Less accumulated depreciation, depletion and amortization (233,343 ) (131,857 ) Oil and natural gas properties, net 1,830,498 1,714,724 Other property and equipment 11,991 8,912 Less accumulated depreciation (3,155 ) (809 ) Other property and equipment, net 8,836 8,103 Property and equipment, net $ 1,839,334 $ 1,722,827 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 and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of June 30, 2015 or December 31, 2014. In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense. Brokered natural gas and marketing revenues include revenues from brokered gas or revenue we receive as a result of selling and buying natural gas that is not related to our production and revenue from the release of transportation capacity. We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. We consider these activities as ancillary to our natural gas sales and thus report them within one operating segment. (e) Major Customers The Company sells production volumes to various purchasers. For the three and six months ended June 30, 2015, there were three and four customers, respectively, that, on an individual basis, accounted for 10% or more of the Company’s natural gas, NGLs and oil sales. For the three and six months ended June 30, 2014, there was one customer that accounted for 10% or more of the Company’s total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the three months ended For the six months ended 2015 2014 2015 2014 Purchaser Antero Resources Corporation 19 % 73 % 20 % 63 % ARM Energy Management — — 13 % — Enlink Midstream 34 % — 30 % — Sequent Energy Management 22 % — 13 % — Total 75 % 73 % 76 % 63 % 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 because it 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. (f) Concentration of Credit Risk Although the Company is exposed to a concentration of credit risk due to the fact that several customers account for a significant portion of its total natural gas, NGLs and oil sales, management believes that all of the Company’s purchasers are credit worthy. The following table summarizes concentration of receivables, net of allowances, by product or service as of June 30, 2015 and December 31, 2014 (in thousands): June 30, December 31, Receivables by product or service: Sale of oil and natural gas and related products and services $ 25,645 $ 22,777 Joint interest owners 5,019 20,666 Miscellaneous other 2,298 2,935 Total $ 32,962 $ 46,378 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 $11.5 million at June 30, 2015 and a net asset position $19.0 million as 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 June 30, 2015 and 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 consolidated balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was underfunded by $1.4 million and $1.3 million at June 30, 2015 and December 31, 2014, respectively. Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension obligations of $2.2 million for the six months ended June 30, 2014. (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 three months ended June 30, 2015 and 2014 totaled approximately $60.1 million and $9.9 million, respectively; and for the six months ended June 30, 2015 and 2014 totaled approximately $102.2 million and $21.8 million, respectively. Through September 30, 2014, the Company calculated depletion of proved properties at the individual unit level. Effective October 1, 2014, the Company changed its estimate for calculating depletion expense of proved properties to be performed at the field level consistent with the assessment for impairment of proved property costs. Other Property and Equipment Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the three months ended June 30, 2015 and 2014 totaled approximately $0.5 million and less than $0.1 million, respectively; and for the six months ended June 30, 2015 and 2014 totaled approximately $0.8 million and $0.2 million, respectively. This amount is included in DD&A expense in the condensed 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 for impairment 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. There were no impairments of proved properties for the three or six months ended June 30, 2015 and 2014. 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 $4.4 million and $6.0 million for the three and six months ended June 30, 2015, respectively. The Company recorded $3.7 million to impairment of unproved oil and gas properties related to lease expirations for each of the three and six months ended June 30, 2014. These costs are included in exploration expense in the condensed consolidated statements of operations. (j) Income Taxes The Company accounts for income taxes under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and other tax attribute 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. The Company recognizes fines and penalties as income tax expense. Upon the closing of the Corporate Reorganization, the Company acquired 100% of Eclipse I, Eclipse Resources-Ohio, LLC and Eclipse Operating. Eclipse I was a limited partnership not subject to federal income taxes before the Corporate Reorganization. However, in connection with the closing of the Corporate Reorganization, the Company became a corporation subject to federal and state income tax and, as such, the Company’s future income taxes will be dependent upon its future taxable income. The change in tax status requires the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately $97.6 million was recorded as income tax expense in the consolidated statements of operations for the year ended December 31, 2014. ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date. (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 Level 2 Level 3 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 condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities. The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy. (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 Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset. The following table sets forth the changes in the Company’s ARO liability for the six months ended June 30, 2015 (in thousands): Six Months Ended Asset retirement obligations, beginning of period $ 17,400 Additional liabilities incurred 303 Accretion 785 Asset retirement obligations, end of period $ 18,488 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 condensed consolidated 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 2014-09, “Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”)”, which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. In 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” In April 2015, the FASB issued ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs,” which expands upon the guidance on the presentation of debt issuance costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. This guidance requires retrospective application and is effective for fiscal years beginning after December 15, 2015 and for interim periods within those fiscal years, with early adoption permitted. (s) Cash Flow Revision The Company revised the presentation of delay rentals and geological and geophysical costs within the condensed consolidated statement of cash flows for the six months ended June 30, 2014, to conform to the current period presentation. Previously, such costs had been presented as cash outflows from investing activities; however, U.S. GAAP requires such costs to be presented as cash outflows from operating activities. This revision resulted in a reduction to cash flows provided by operating activities and a corresponding reduction to cash flows used in investing activities of approximately $10 million compared to the previously reported amounts. The Company evaluated the materiality of this error on both a quantitative and qualitative basis under the guidance of ASC 250 - Accounting Changes and Error Corrections and determined that it did not have a material impact to previously issued financial statements. |
Sale of Oil and Natural Gas Pro
Sale of Oil and Natural Gas Property Interests | 6 Months Ended |
Jun. 30, 2015 | |
Discontinued Operations and Disposal Groups [Abstract] | |
Sale of Oil and Natural Gas Property Interests | Note 4—Sale of Oil and Natural Gas Property Interests During the three months ended June 30, 2015, the Company completed the sale of a central processing facility and certain pipelines. The transaction resulted in proceeds of $37.3 million and a gain on sale of assets of $5.6 million, which was recorded during the three months ended June 30, 2015. Approximately $3.6 million of costs related to other pipelines were classified as assets held for sale in the condensed consolidated balance sheets as of June 30, 2015. |
Derivative Instruments
Derivative Instruments | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Note 5—Derivative Instruments Commodity Derivatives The Company is exposed to market risk from changes in energy commodity prices within its operations. The Company utilizes derivatives to manage exposure to the variability in expected future cash flows from forecasted sales of natural gas and oil. The Company currently uses a mix of over-the-counter (“OTC”) fixed price swaps, basis swaps and put options spreads and collars to manage its exposure to commodity price fluctuations. All of the Company’s derivative instruments are used for risk management purposes and none are held for trading or speculative purposes. The Company is exposed to credit risk in the event of non-performance by counterparties. To mitigate this risk, the Company enters into derivative contracts only with counterparties that are rated “A” or higher by S&P or Moody’s. The creditworthiness of counterparties is subject to periodic review. As of June 30, 2015, the Company’s derivative instruments were with Bank of Montreal and Key Bank, N.A. The Company has not experienced any issues of non-performance by derivative counterparties. Below is a summary of the Company’s derivative instrument positions, as of June 30, 2015, for future production periods: Natural Gas Derivatives Description Volume Production Period Weighted Average Natural Gas Swaps: 62,500 July 2015—December 2015 $ 3.78 25,000 January 2016—December 2016 $ 3.66 7,000 July 2015—October 2015 $ 2.84 Natural Gas Three-way Collar: Floor purchase price (put) 15,000 July 2015—December 2015 $ 3.60 Ceiling sold price (call) 15,000 July 2015—December 2015 $ 3.80 Floor sold price (put) 15,000 July 2015—December 2015 $ 3.00 Natural Gas Put Options: Put sold 16,800 July 2015—December 2015 $ 3.35 Put sold 16,800 July 2015—October 2015 $ 2.87 Put purchased 16,800 July 2015—October 2015 $ 3.35 Put sold 16,800 January 2016—December 2016 $ 2.75 Basis Swaps: 25,000 July 2015—October 2015 $ (1.21 ) Oil Derivatives Description Volume Production Period Weighted Average Oil Collar: Floor purchase price (put) 3,000 July 2015—February 2016 $ 55.00 Ceiling sold price (call) 3,000 July 2015—February 2016 $ 61.40 Oil Three-way Collar: Floor purchase price (put) 1,000 March 2016—December 2016 $ 60.00 Ceiling sold price (call) 1,000 March 2016—December 2016 $ 70.10 Floor sold price (put) 1,000 March 2016—December 2016 $ 45.00 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 condensed consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes. Derivatives not designated as hedging instruments under Gross Amount Netting Net Amount Presented in the Balance Sheets Balance Sheet Location As of June 30, 2015 Assets Commodity derivatives—current $ 16,742 $ (6,549 ) $ 10,193 Other current assets Commodity derivatives—noncurrent 2,859 (1,541 ) 1,318 Other assets Total assets $ 19,601 $ (8,090 ) $ 11,511 Liabilities Commodity derivatives—current $ (6,549 ) $ 6,549 $ — Commodity derivatives—noncurrent (1,541 ) 1,541 — Total liabilities $ (8,090 ) $ 8,090 $ — Derivatives not designated as hedging instruments under Gross Amount Netting Net Amount Presented in the Balance Sheets Balance Sheet Location 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. The following table presents the Company’s reported gains and losses on derivative instruments and where such values are recorded in the condensed consolidated statements of operations for the periods presented (in thousands): Amount of Gain (Loss) Recognized in Income Derivatives not designated as hedging instruments under ASC 815 Location of Gain (Loss) Three months ended Six months ended 2015 2014 2015 2014 Commodity derivatives Gain (loss) on $ (3,523 ) $ (863 ) $ 7,848 $ (4,474 ) |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Note 6—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 condensed 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 the Company’s derivative instruments 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 June 30, 2015: (in thousands) Commodity derivative instruments $ — $ 11,511 $ — $ 11,511 Total $ — $ 11,511 $ — $ 11,511 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 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— Summary of Significant Accounting Policies” 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— Summary of Significant Accounting Policies” The estimated fair values of the Company’s financial instruments closely approximate the carrying amounts due, except for long-term debt. (See “Note 7— Debt |
Debt
Debt | 6 Months Ended |
Jun. 30, 2015 | |
Debt Disclosure [Abstract] | |
Debt | Note 7—Debt 12% Senior Unsecured PIK Notes Due 2018 As of June 30, 2015, the Company had a principal amount of $437.3 million, compared to $422.5 million as of December 31, 2014, related to the Senior Unsecured PIK Notes due in 2018 (the “Senior PIK Notes”). 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. During the three months ended June 30, 2015 and 2014, the Company amortized $0.5 million and $0.6 million of deferred financing costs and debt discount to interest expense, respectively, using the effective interest method. During the six months ended June 30, 2015 and 2014, the Company amortized $2.2 million and $2.0 million of deferred financing costs and debt discount to interest expense, respectively, using the effective interest method. The Company redeemed all of the outstanding balance of the 12% Senior PIK Notes on July 13, 2015 for approximately $510.7 million, including outstanding principal balance, a make-whole premium, and accrued interest. The Indenture governing the Senior PIK Notes required 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 placed 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 June 30, 2015 and December 31, 2014. 8.875% Senior Unsecured Notes Due 2023 On July 6, 2015, the Company issued $550 million in aggregate principal amount of 8.875% senior notes due 2023 (“the Notes”) at an issue price of 97.903% of the principal amount of the Notes, plus accrued and unpaid interest, if any, to Deutsche Bank Securities Inc. and other initial purchasers. In this private offering, the Notes were sold for cash to qualified institutional buyers in the United States pursuant to Rule 144A of the Securities Act and to persons outside the United States in compliance with Regulation S under the Securities Act. Upon closing, the Company received proceeds of approximately $525.5 million, after deducting original issue discount, the initial purchasers’ discounts and estimated offering expenses, of which the Company used approximately $510.7 million to finance the redemption of all of its outstanding Senior PIK Notes. The Company intends to use the remaining net proceeds to fund its capital expenditure plan and for general corporate purposes. Revolving Credit Facility During the first quarter of 2014, the Company entered into a $500 million senior secured revolving bank credit facility (the “Revolving Credit Facility”) that matures in 2018. Borrowings under the Revolving Credit Facility are subject to borrowing base limitations based on the collateral value of the Company’s proved properties and commodity hedge positions and are subject to semiannual redeterminations. At June 30, 2015, the borrowing base was $125 million and the Company had no outstanding borrowings. After giving effect to outstanding letters of credit issued by the Company totaling $27.8 million, the Company had available borrowing capacity under the Revolving Credit Facility of $97.2 million at June 30, 2015. 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 was further amended and restated on June 11, 2015 and became effective upon the issuance of the Notes. Among other things, pursuant to the Amended Credit Agreement, the Company assumed all of the rights and obligations of Eclipse I as the borrower under the Existing Credit Agreement. Furthermore, the Amended Credit Agreement allowed for the issuance of the Notes and provided that the Company would not incur an immediate reduction in borrowing base under its Revolving Credit Facility as a result of the issuance of the Notes. Accordingly, the borrowing base under the Company’s revolving credit facility immediately following the issuance of the Notes remained at $125.0 million until the next redetermination date (which is scheduled to occur by October 2015). 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. 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. The Company was in compliance with all applicable covenants under the Revolving Credit Facility as of June 30, 2015 and December 31, 2014. |
Benefit Plans
Benefit Plans | 6 Months Ended |
Jun. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Benefit Plans | Note 8—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 recognized expense of $0.3 million and $0.5 million for the three and six months ended June 30, 2015, respectively. The Company recognized expense of $0.1 million and $0.2 million for the three and six months ended June 30, 2014, respectively. Defined Benefit Plan The Company maintains a defined benefit plan covering certain employees of a previously acquired company. Benefits are based on the employees’ years of service and compensation. The following table details the components of pension benefit cost (in thousands): For the three months ended For the six months ended 2015 2014 2015 2014 Service cost $ — $ — $ — $ 70 Interest cost 62 85 126 192 Expected return on plan assets (82 ) (112 ) (164 ) (224 ) Amortization of transition obligation — — — 70 Amortization of net (gain) loss 25 11 43 3 Settlement costs 96 — 96 — Net periodic benefit cost (benefit) $ 101 $ (16 ) $ 101 $ 111 There were no employer contributions made during the three and six months ended June 30, 2015. As of March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension obligations of $2.2 million for the six months ended June 30, 2014. |
Stock-Based Compensation
Stock-Based Compensation | 6 Months Ended |
Jun. 30, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Note 9—Stock-Based Compensation The Company is authorized to grant up to 16,000,000 shares of common stock under its 2014 Long-Term Incentive Plan (the “Plan”). The Plan allows stock-based compensation awards to be granted in a variety of forms, including stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, dividend equivalent rights, qualified performance-based awards and other types of awards. The terms and conditions of the awards granted are established by the Compensation Committee of the Company’s Board of Directors. A total of 14,169,746 shares are available for future grant under the Plan as of June 30, 2015. Our stock based compensation expense is as follows for the three and six months ended June 30, 2015 (in thousands): For the three months ended For the six months ended 2015 2014 2015 2014 Restricted stock units $ 748 $ — $ 1,171 $ — Performance units 376 — 528 — Restricted stock issued to directors 255 — 400 — Incentive units 31 27 58 56 Total expense $ 1,410 $ 27 $ 2,157 $ 56 Restricted Stock Units Restricted stock and restricted stock unit awards vest subject to the satisfaction of service requirements. The Company recognizes expense related to restricted stock and restricted stock unit awards on a straight-line basis over the requisite service period, which is three years. The grant date fair values of these awards are determined based on the closing price of the Company’s common stock on the date of the grant. As of June 30, 2015, there was $6.5 million of total unrecognized compensation cost related to restricted stock units. A summary of restricted stock unit awards activity during the six months ended June 30, 2015 is as follows: Number of Weighted Aggregate Total awarded and unvested, December 31, 2014 — $ — $ — Granted 1,247,197 7.01 Vested — — Forfeited (39,210 ) 7.13 Total awarded and unvested, June 30, 2015 1,207,987 $ 6.78 $ 6,354 Performance Units Performance unit awards vest subject to the satisfaction of a three-year service requirement and based on Total Shareholder Return (“TSR”), as compared to an industry peer group over that same period. The performance unit awards are measured at the grant date at fair value using a Monte Carlo valuation method. As of June 30, 2015, there was $3.8 million of total unrecognized compensation cost related to performance units. A summary of performance stock unit awards activity during the six months ended June 30, 2015 is as follows: Number of Weighted Aggregate Total awarded and unvested, December 31, 2014 — $ — $ — Granted 469,368 8.77 Vested — — Forfeited (10,712 ) 8.77 Total awarded and unvested, June 30, 2015 458,656 $ 8.77 $ — The determination of the fair value of the performance unit awards noted above uses significant Level 3 assumptions in the fair value hierarchy including an estimate of the timing of forfeitures, the risk free rate and a volatility estimate tied to the Company’s public peer group. Restricted Stock Issued to Directors On October 7, 2014, the Company issued an aggregate of 31,115 restricted shares of common stock to its seven non-employee members of its Board of Directors. For the six months ended June 30, 2015, the Company recognized expense of approximately $0.2 million related to these awards. These awards became fully vested on June 25, 2015. On May 11, 2015, the Company issued an aggregate of 132,496 restricted shares of common stock to its seven non-employee members of its Board of Directors. For the six months ended June 30, 2015, the Company recognized expense of approximately $0.1 million related to these awards. As of June 30, 2015, there was $0.7 million of total unrecognized compensation cost related to restricted stock issued to Directors. These awards are scheduled to become fully vested on May 11, 2016. 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 three months ended June 30, 2015 and 2014; and $0.1 million for each of the six months ended June 30, 2015 and 2014. As of June 30, 2015, there was $0.6 million of total unrecognized compensation cost related to Incentive Units, which is expected to be recognized over a weighted-average period of approximately 6 years. The determination of the fair value of the incentive unit 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. |
Equity
Equity | 6 Months Ended |
Jun. 30, 2015 | |
Equity [Abstract] | |
Equity | Note 10—Equity Private Placement of Common Stock On December 27, 2014, the Company entered into a Securities Purchase Agreement with private equity funds managed by EnCap Investments L.P., entities controlled by certain shareholders of the Company management team and certain other institutional investors pursuant to which the Company issued and sold to such purchasers an aggregate of 62,500,000 shares of common stock at a price of $7.04 per share pursuant to the exemptions from registration provided in Rule 506 of Regulation D promulgated under Section 4(2) of the Securities Act, 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 its initial public offering in order to provide the purchasers with certain registration rights with respect to the stock they purchased in the private placement. |
Related Party Transactions
Related Party Transactions | 6 Months Ended |
Jun. 30, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Note 11—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 provides 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 expenses are classified within “ Operating expenses—General and administrative During the three months ended June 30, 2015, the Company paid $0.6 million related to a final distribution of the assets of Eclipse Operating. This amount was distributed equally among the three former members of Eclipse Operating. During the three and six months ended June 30, 2015, the Company incurred approximately $0.1 million and $0.2 million, respectively, related to flight charter services provided by BWH Air, LLC and BWH Air II, LLC, which are owned by the Company’s Chairman, President and Chief Executive Officer. The fees are paid in accordance with a standard service contract that does not obligate the Company to any minimum terms. |
Commitments and Contingencies
Commitments and Contingencies | 6 Months Ended |
Jun. 30, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 12—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 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 August 14, 2015, we are a party to one other lawsuit that makes allegations similar to those made by the lessor in the West West 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 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 West West Hupp v. Beck Energy The Company believes that there are strong grounds for appeal of the West Hupp v. Beck Energy 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. The Company recognized rent expense of $0.2 million and $0.1 million for the three months ended June 30, 2015 and 2014, respectively, and rent expense of $0.4 million and $0.1 million for the six months ended June 30, 2015 and 2014, respectively. |
Income Tax
Income Tax | 6 Months Ended |
Jun. 30, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Tax | Note 13—Income Tax For 2015, the Company’s annual estimated effective tax rate is forecasted to be a benefit of 30.83%, exclusive of discrete items. The Company expects to incur both a book and tax loss in fiscal year 2015, and thus, no current federal income taxes are anticipated to be paid. We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective tax rate to our year-to-date income, except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. For the quarter ended June 30, 2015, our overall effective tax rate on operations was different than the federal statutory rate of 35% due primarily to state income taxes, valuation allowances and other permanent differences. In forecasting the 2015 annual estimated effective tax rate, management believes that it should limit any tax benefit suggested by the tax effect of the forecasted book loss such that no net deferred tax asset is recorded in 2015. Management reached this conclusion considering several factors such as: (i) the Company’s short tax history, (ii) the lack of carryback potential resulting in a tax refund, and (iii) in light of current commodity pricing uncertainty, there is insufficient external evidence to suggest that net tax attribute carryforwards are collectible beyond offsetting existing deferred tax liabilities inherent in our balance sheet (which are primarily related to the excess of book carrying value of properties over their respective tax bases). At this time, the estimated valuation allowance to be recorded in 2015 (there was no valuation allowance recorded during 2014) would be $9.7 million. |
Subsequent Events
Subsequent Events | 6 Months Ended |
Jun. 30, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 14—Subsequent Events The Company redeemed all of the outstanding Senior PIK Notes on July 13, 2015 for approximately $510.7 million, including outstanding principal balance, a make-whole premium and accrued interest. (See Note 7— Debt |
Summary of Significant Accoun23
Summary of Significant Accounting Policies (Policies) | 6 Months Ended |
Jun. 30, 2015 | |
Accounting Policies [Abstract] | |
Cash and Cash Equivalents | (a) Cash and Cash Equivalents Cash and cash equivalents are comprised of cash in banks and highly liquid instruments with original maturities of three months or less, primarily consisting of bank time deposits and investments in institutional money market funds. The carrying amounts approximate fair value due to the short-term nature of these items. Cash in bank accounts at times may exceed federally insured limits. |
Accounts Receivable | (b) Accounts Receivable Accounts receivable are carried at estimated net realizable value. Receivables deemed uncollectible are charged directly to expense. Trade credit is generally extended on a short-term basis, and therefore, accounts receivable do not bear interest, although a finance charge may be applied to such receivables that are past due. A valuation allowance is provided for those accounts for which collection is estimated as doubtful and uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the counterparty. The Company did not deem any of its accounts receivables to be uncollectible as of June 30, 2015 or December 31, 2014. The Company accrues revenue due to timing differences between the delivery of natural gas, natural gas liquids (NGLs), and crude oil and the receipt of a delivery statement. These revenues are recorded based upon volumetric data from the Company’s records and management’s estimates of the related commodity sales and transportation and compression fees. The Company had $27.5 million and $24.1 million of accrued revenues, net of certain expenses at June 30, 2015 and December 31, 2014, respectively, which were included in accounts receivable within the Company’s condensed consolidated balance sheets. |
Property and Equipment | (c) Property and Equipment Oil and Natural Gas Properties The Company follows the successful efforts method of accounting for its oil and natural gas operations. Acquisition costs for oil and natural gas properties, costs of drilling and equipping productive wells, and costs of unsuccessful development wells are capitalized and amortized on an equivalent unit-of-production basis over the life of the remaining related oil and gas reserves. The estimated future costs of dismantlement, restoration, plugging and abandonment of oil and gas properties and related disposal are capitalized when asset retirement obligations are incurred and amortized as part of depreciation, depletion and amortization expense (see “ Depreciation, Depletion and Amortization Costs incurred to acquire producing and non-producing leaseholds are capitalized. All unproved leasehold acquisition costs are initially capitalized, including the cost of leasing agents, title work and due diligence. If the Company acquires leases in a prospective area, these costs are capitalized as unproved leasehold costs. If no leases are acquired by the Company with respect to the initial costs incurred or the Company discontinues leasing in a prospective area, the costs are charged to exploration expense. Unproved leasehold costs that are determined to have proved oil and gas reserves are transferred to proved leasehold costs. Upon the sale or retirement of a complete field of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to the Company’s condensed consolidated statements of operations. Upon the sale of an individual well, the proceeds are credited to accumulated depreciation and depletion within the Company’s condensed consolidated balance sheets. Upon sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the Company’s condensed consolidated statements of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. A summary of property and equipment including oil and natural gas properties is as follows (in thousands): June 30, December 31, Oil and natural gas properties: Unproved $ 1,003,018 $ 1,044,469 Proved 1,060,823 802,112 Gross oil and natural gas properties 2,063,841 1,846,581 Less accumulated depreciation, depletion and amortization (233,343 ) (131,857 ) Oil and natural gas properties, net 1,830,498 1,714,724 Other property and equipment 11,991 8,912 Less accumulated depreciation (3,155 ) (809 ) Other property and equipment, net 8,836 8,103 Property and equipment, net $ 1,839,334 $ 1,722,827 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 and NGLs in which the Company has an interest with other producers are recognized using the sales method on the basis of the Company’s net revenue interest. The Company did not have any material imbalances as of June 30, 2015 or December 31, 2014. In accordance with the terms of joint operating agreements, from time to time, the Company may be paid monthly fees for operating or drilling wells for outside owners. The fees are meant to recoup some of the operator’s general and administrative costs in connection with well and drilling operations and are accounted for as credits to general and administrative expense. Brokered natural gas and marketing revenues include revenues from brokered gas or revenue we receive as a result of selling and buying natural gas that is not related to our production and revenue from the release of transportation capacity. We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties, whereby the Company or the counterparty takes title to the natural gas purchased or sold. Revenues and expenses related to brokering natural gas are reported gross as part of revenue and expense in accordance with U.S. GAAP. We consider these activities as ancillary to our natural gas sales and thus report them within one operating segment. |
Major Customers | (e) Major Customers The Company sells production volumes to various purchasers. For the three and six months ended June 30, 2015, there were three and four customers, respectively, that, on an individual basis, accounted for 10% or more of the Company’s natural gas, NGLs and oil sales. For the three and six months ended June 30, 2014, there was one customer that accounted for 10% or more of the Company’s total natural gas, NGLs and oil sales. The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the three months ended For the six months ended 2015 2014 2015 2014 Purchaser Antero Resources Corporation 19 % 73 % 20 % 63 % ARM Energy Management — — 13 % — Enlink Midstream 34 % — 30 % — Sequent Energy Management 22 % — 13 % — Total 75 % 73 % 76 % 63 % 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 because it 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. |
Concentration of Credit Risk | (f) Concentration of Credit Risk Although the Company is exposed to a concentration of credit risk due to the fact that several customers account for a significant portion of its total natural gas, NGLs and oil sales, management believes that all of the Company’s purchasers are credit worthy. The following table summarizes concentration of receivables, net of allowances, by product or service as of June 30, 2015 and December 31, 2014 (in thousands): June 30, December 31, Receivables by product or service: Sale of oil and natural gas and related products and services $ 25,645 $ 22,777 Joint interest owners 5,019 20,666 Miscellaneous other 2,298 2,935 Total $ 32,962 $ 46,378 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 $11.5 million at June 30, 2015 and a net asset position $19.0 million as 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 June 30, 2015 and 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 consolidated balance sheet and (ii) recognize changes in that funded status in the year in which the changes occur through other comprehensive loss. The Company’s pension plan was underfunded by $1.4 million and $1.3 million at June 30, 2015 and December 31, 2014, respectively. Effective March 31, 2014, benefit accruals in the plan were frozen resulting in a gain on reduction of pension obligations of $2.2 million for the six months ended June 30, 2014. |
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 three months ended June 30, 2015 and 2014 totaled approximately $60.1 million and $9.9 million, respectively; and for the six months ended June 30, 2015 and 2014 totaled approximately $102.2 million and $21.8 million, respectively. Through September 30, 2014, the Company calculated depletion of proved properties at the individual unit level. Effective October 1, 2014, the Company changed its estimate for calculating depletion expense of proved properties to be performed at the field level consistent with the assessment for impairment of proved property costs. Other Property and Equipment Depreciation with respect to other property and equipment is calculated using straight-line methods based on expected lives of the individual assets or groups of assets ranging from 5 to 40 years. Depreciation for the three months ended June 30, 2015 and 2014 totaled approximately $0.5 million and less than $0.1 million, respectively; and for the six months ended June 30, 2015 and 2014 totaled approximately $0.8 million and $0.2 million, respectively. This amount is included in DD&A expense in the condensed 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 for impairment 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. There were no impairments of proved properties for the three or six months ended June 30, 2015 and 2014. 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 $4.4 million and $6.0 million for the three and six months ended June 30, 2015, respectively. The Company recorded $3.7 million to impairment of unproved oil and gas properties related to lease expirations for each of the three and six months ended June 30, 2014. These costs are included in exploration expense in the condensed consolidated statements of operations. |
Income Taxes | (j) Income Taxes The Company accounts for income taxes under the liability method as set out in the FASB’s Accounting Standards Codification (“ASC”) Topic 740 “Income Taxes.” Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating losses and other tax attribute 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. The Company recognizes fines and penalties as income tax expense. Upon the closing of the Corporate Reorganization, the Company acquired 100% of Eclipse I, Eclipse Resources-Ohio, LLC and Eclipse Operating. Eclipse I was a limited partnership not subject to federal income taxes before the Corporate Reorganization. However, in connection with the closing of the Corporate Reorganization, the Company became a corporation subject to federal and state income tax and, as such, the Company’s future income taxes will be dependent upon its future taxable income. The change in tax status requires the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting net deferred tax liability of approximately $97.6 million was recorded as income tax expense in the consolidated statements of operations for the year ended December 31, 2014. ASC Topic 740 further provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of the uncertain tax position guidance and in subsequent periods. This interpretation also provides guidance on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company has not recorded a reserve for any uncertain tax positions to date. |
Fair Value of Financial Instruments | (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 Level 2 Level 3 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 condensed consolidated balance sheets as current and noncurrent assets and liabilities. Derivatives are classified as current or noncurrent based on the contractual expiration date. Derivatives with expiration dates within the next 12 months are classified as current. The Company netted the fair value of derivatives by counterparty in the accompanying condensed consolidated balance sheets where the right to offset exists. The Company’s derivative instruments were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the condensed consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. Premiums for options are included in cash flows from operating activities. The valuation of the Company’s derivative financial instruments represents a Level 2 measurement in the fair value hierarchy. |
Asset Retirement Obligation | (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 Estimating the future ARO requires management to make estimates and judgments based on historical estimates regarding timing and existence of a liability, as well as what constitutes adequate restoration, inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset. The following table sets forth the changes in the Company’s ARO liability for the six months ended June 30, 2015 (in thousands): Six Months Ended Asset retirement obligations, beginning of period $ 17,400 Additional liabilities incurred 303 Accretion 785 Asset retirement obligations, end of period $ 18,488 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 condensed consolidated 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 2014-09, “Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”)”, which supersedes the revenue recognition requirements (and some cost guidance) in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the industry topics of the Accounting Standards Codification. In addition, the existing requirements for the recognition of a gain or loss on the transfer of nonfinancial assets that are not in a contract with a customer (for example, assets within the scope of Topic 360, Property, Plant and Equipment, and intangible assets within the scope of Topic 350, Intangibles—Goodwill and Other) are amended to be consistent with the guidance on recognition and measurement (including the constraint on revenue) in Update 2014-09. Topic 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this, an entity should identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract and recognize revenue when (or as) the entity satisfies the performance obligations. These requirements are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is evaluating the impact of the adoption on its financial position, results of operations and related disclosures. In 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” In April 2015, the FASB issued ASU 2015-03, “Simplifying the Presentation of Debt Issuance Costs,” which expands upon the guidance on the presentation of debt issuance costs. The ASU requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with debt discounts. This guidance requires retrospective application and is effective for fiscal years beginning after December 15, 2015 and for interim periods within those fiscal years, with early adoption permitted. |
Cash Flow Revision | (s) Cash Flow Revision The Company revised the presentation of delay rentals and geological and geophysical costs within the condensed consolidated statement of cash flows for the six months ended June 30, 2014, to conform to the current period presentation. Previously, such costs had been presented as cash outflows from investing activities; however, U.S. GAAP requires such costs to be presented as cash outflows from operating activities. This revision resulted in a reduction to cash flows provided by operating activities and a corresponding reduction to cash flows used in investing activities of approximately $10 million compared to the previously reported amounts. The Company evaluated the materiality of this error on both a quantitative and qualitative basis under the guidance of ASC 250 - Accounting Changes and Error Corrections and determined that it did not have a material impact to previously issued financial statements. |
Summary of Significant Accoun24
Summary of Significant Accounting Policies (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Summary of Property and Equipment Including Oil and Natural Gas Properties | A summary of property and equipment including oil and natural gas properties is as follows (in thousands): June 30, December 31, Oil and natural gas properties: Unproved $ 1,003,018 $ 1,044,469 Proved 1,060,823 802,112 Gross oil and natural gas properties 2,063,841 1,846,581 Less accumulated depreciation, depletion and amortization (233,343 ) (131,857 ) Oil and natural gas properties, net 1,830,498 1,714,724 Other property and equipment 11,991 8,912 Less accumulated depreciation (3,155 ) (809 ) Other property and equipment, net 8,836 8,103 Property and equipment, net $ 1,839,334 $ 1,722,827 |
Changes in Company's Asset Retirement Obligation Liability | The following table sets forth the changes in the Company’s ARO liability for the six months ended June 30, 2015 (in thousands): Six Months Ended Asset retirement obligations, beginning of period $ 17,400 Additional liabilities incurred 303 Accretion 785 Asset retirement obligations, end of period $ 18,488 |
Accounts Receivable [Member] | Product Concentration Risk [Member] | |
Concentration Risk | The following table summarizes concentration of receivables, net of allowances, by product or service as of June 30, 2015 and December 31, 2014 (in thousands): June 30, December 31, Receivables by product or service: Sale of oil and natural gas and related products and services $ 25,645 $ 22,777 Joint interest owners 5,019 20,666 Miscellaneous other 2,298 2,935 Total $ 32,962 $ 46,378 |
Sales Revenue, Services, Net [Member] | Customer Concentration Risk [Member] | |
Concentration Risk | The following table sets forth the Company’s major customers and associated percentage of revenue for the periods indicated: For the three months ended For the six months ended 2015 2014 2015 2014 Purchaser Antero Resources Corporation 19 % 73 % 20 % 63 % ARM Energy Management — — 13 % — Enlink Midstream 34 % — 30 % — Sequent Energy Management 22 % — 13 % — Total 75 % 73 % 76 % 63 % |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Summary of Derivative Instrument Positions for Future Production Periods | Below is a summary of the Company’s derivative instrument positions, as of June 30, 2015, for future production periods: Natural Gas Derivatives Description Volume Production Period Weighted Average Natural Gas Swaps: 62,500 July 2015—December 2015 $ 3.78 25,000 January 2016—December 2016 $ 3.66 7,000 July 2015—October 2015 $ 2.84 Natural Gas Three-way Collar: Floor purchase price (put) 15,000 July 2015—December 2015 $ 3.60 Ceiling sold price (call) 15,000 July 2015—December 2015 $ 3.80 Floor sold price (put) 15,000 July 2015—December 2015 $ 3.00 Natural Gas Put Options: Put sold 16,800 July 2015—December 2015 $ 3.35 Put sold 16,800 July 2015—October 2015 $ 2.87 Put purchased 16,800 July 2015—October 2015 $ 3.35 Put sold 16,800 January 2016—December 2016 $ 2.75 Basis Swaps: 25,000 July 2015—October 2015 $ (1.21 ) Oil Derivatives Description Volume Production Period Weighted Average Oil Collar: Floor purchase price (put) 3,000 July 2015—February 2016 $ 55.00 Ceiling sold price (call) 3,000 July 2015—February 2016 $ 61.40 Oil Three-way Collar: Floor purchase price (put) 1,000 March 2016—December 2016 $ 60.00 Ceiling sold price (call) 1,000 March 2016—December 2016 $ 70.10 Floor sold price (put) 1,000 March 2016—December 2016 $ 45.00 |
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 condensed consolidated balance sheets (in thousands). None of the derivative instruments are designated as hedges for accounting purposes. Derivatives not designated as hedging instruments under Gross Amount Netting Net Amount Presented in the Balance Sheets Balance Sheet Location As of June 30, 2015 Assets Commodity derivatives—current $ 16,742 $ (6,549 ) $ 10,193 Other current assets Commodity derivatives—noncurrent 2,859 (1,541 ) 1,318 Other assets Total assets $ 19,601 $ (8,090 ) $ 11,511 Liabilities Commodity derivatives—current $ (6,549 ) $ 6,549 $ — Commodity derivatives—noncurrent (1,541 ) 1,541 — Total liabilities $ (8,090 ) $ 8,090 $ — Derivatives not designated as hedging instruments under Gross Amount Netting Net Amount Presented in the Balance Sheets Balance Sheet Location 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 condensed consolidated statements of operations for the periods presented (in thousands): Amount of Gain (Loss) Recognized in Income Derivatives not designated as hedging instruments under ASC 815 Location of Gain (Loss) Three months ended Six months ended 2015 2014 2015 2014 Commodity derivatives Gain (loss) on $ (3,523 ) $ (863 ) $ 7,848 $ (4,474 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
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 condensed 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 the Company’s derivative instruments 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 June 30, 2015: (in thousands) Commodity derivative instruments $ — $ 11,511 $ — $ 11,511 Total $ — $ 11,511 $ — $ 11,511 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 |
Benefit Plans (Tables)
Benefit Plans (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Compensation and Retirement Disclosure [Abstract] | |
Components of Pension Benefit Cost | The following table details the components of pension benefit cost (in thousands): For the three months ended For the six months ended 2015 2014 2015 2014 Service cost $ — $ — $ — $ 70 Interest cost 62 85 126 192 Expected return on plan assets (82 ) (112 ) (164 ) (224 ) Amortization of transition obligation — — — 70 Amortization of net (gain) loss 25 11 43 3 Settlement costs 96 — 96 — Net periodic benefit cost (benefit) $ 101 $ (16 ) $ 101 $ 111 |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 6 Months Ended |
Jun. 30, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Schedule of Stock Based Compensation Expense | Our stock based compensation expense is as follows for the three and six months ended June 30, 2015 (in thousands): For the three months ended For the six months ended 2015 2014 2015 2014 Restricted stock units $ 748 $ — $ 1,171 $ — Performance units 376 — 528 — Restricted stock issued to directors 255 — 400 — Incentive units 31 27 58 56 Total expense $ 1,410 $ 27 $ 2,157 $ 56 |
Summary of Restricted Stock Unit Awards Activity | A summary of restricted stock unit awards activity during the six months ended June 30, 2015 is as follows: Number of Weighted Aggregate Total awarded and unvested, December 31, 2014 — $ — $ — Granted 1,247,197 7.01 Vested — — Forfeited (39,210 ) 7.13 Total awarded and unvested, June 30, 2015 1,207,987 $ 6.78 $ 6,354 |
Summary of Performance Stock Unit Awards Activity | A summary of performance stock unit awards activity during the six months ended June 30, 2015 is as follows: Number of Weighted Aggregate Total awarded and unvested, December 31, 2014 — $ — $ — Granted 469,368 8.77 Vested — — Forfeited (10,712 ) 8.77 Total awarded and unvested, June 30, 2015 458,656 $ 8.77 $ — |
Summary of Significant Accoun29
Summary of Significant Accounting Policies - Additional Information (Detail) | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2015USD ($)FieldsCustomer | Jun. 30, 2014USD ($)Customer | Jun. 30, 2015USD ($)FieldsCustomerSegment | Jun. 30, 2014USD ($)Customer | Dec. 31, 2014USD ($) | |
Summary Of Significant Accounting Policies [Line Items] | |||||
Accounts receivable | $ 32,962,000 | $ 32,962,000 | $ 46,378,000 | ||
Pension obligations | 1,449,000 | 1,449,000 | 1,321,000 | ||
Gain on reduction of pension obligations | $ 2,208,000 | ||||
Depreciation, depletion and amortization | $ 60,641,000 | $ 9,957,000 | $ 103,073,000 | $ 21,984,000 | |
Number of field included in assessment of impairment | Fields | 3 | 3 | |||
Deferred tax liability | 97,600,000 | ||||
Asset retirement obligations credit adjusted discount rates | 10.45% | 8.96% | |||
Number of operating segment | Segment | 1 | ||||
Prior period adjustment in cash flows | $ 10,000,000 | ||||
Eclipse I [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Ownership percentage | 100.00% | 100.00% | |||
Eclipse Resources Ohio LLC [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Ownership percentage | 100.00% | 100.00% | |||
Eclipse Resources Operating, LLC ("Eclipse Operating") [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Ownership percentage | 100.00% | 100.00% | |||
Commodity Contract [Member] | Not Designated as Hedging Instrument [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Fair value of commodity derivative contracts | $ 11,511,000 | $ 11,511,000 | 19,034,000 | ||
Sales Revenue, Net [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Number of customers | Customer | 3 | 1 | 4 | 1 | |
Unbilled Revenues [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Accounts receivable | $ 27,500,000 | $ 27,500,000 | $ 24,100,000 | ||
Proved Oil And Gas Properties [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Impairment of oil and gas properties | 0 | $ 0 | 0 | $ 0 | |
Unproved Oil And Gas Properties [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Impairment of oil and gas properties | 4,400,000 | 3,700,000 | 6,000,000 | 3,700,000 | |
Oil and Gas Properties [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Depreciation, depletion and amortization | 60,100,000 | 9,900,000 | 102,200,000 | 21,800,000 | |
Other property and equipment [Member] | |||||
Summary Of Significant Accounting Policies [Line Items] | |||||
Depreciation | $ 500,000 | $ 800,000 | $ 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 | ||||
Depreciation | $ 100,000 |
Summary of Significant Accoun30
Summary of Significant Accounting Policies - Summary of Property and Equipment Including Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Oil and natural gas properties: | ||
Unproved properties | $ 1,003,018 | $ 1,044,469 |
Proved properties | 1,060,823 | 802,112 |
Gross oil and natural gas properties | 2,063,841 | 1,846,581 |
Less accumulated depreciation, depletion and amortization | (233,343) | (131,857) |
Total oil and natural gas properties, net | 1,830,498 | 1,714,724 |
Other property and equipment | 11,991 | 8,912 |
Less accumulated depreciation | (3,155) | (809) |
Other property and equipment, net | 8,836 | 8,103 |
Total property and equipment, net | $ 1,839,334 | $ 1,722,827 |
Summary of Significant Accoun31
Summary of Significant Accounting Policies - Major Customers and Associated Percentage of Revenue (Detail) - Sales Revenue, Net [Member] - Customer Concentration Risk [Member] | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Revenue, Major Customer [Line Items] | ||||
Major customers and associated percentage of revenue | 75.00% | 73.00% | 76.00% | 63.00% |
Antero Resources Corporation [Member] | ||||
Revenue, Major Customer [Line Items] | ||||
Major customers and associated percentage of revenue | 19.00% | 73.00% | 20.00% | 63.00% |
ARM Energy Management [Member] | ||||
Revenue, Major Customer [Line Items] | ||||
Major customers and associated percentage of revenue | 13.00% | |||
Enlink Midstream [Member] | ||||
Revenue, Major Customer [Line Items] | ||||
Major customers and associated percentage of revenue | 34.00% | 30.00% | ||
Sequent Energy Management [Member] | ||||
Revenue, Major Customer [Line Items] | ||||
Major customers and associated percentage of revenue | 22.00% | 13.00% |
Summary of Significant Accoun32
Summary of Significant Accounting Policies - Summary for Concentration of Receivables, Net Of Allowances, By Product or Service (Detail) - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $ 32,962 | $ 46,378 |
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 | 25,645 | 22,777 |
Product Concentration Risk [Member] | Joint Interest Owners [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | 5,019 | 20,666 |
Product Concentration Risk [Member] | Miscellaneous Other [Member] | ||
Revenue, Major Customer [Line Items] | ||
Concentration of receivables, net of allowances | $ 2,298 | $ 2,935 |
Summary of Significant Accoun33
Summary of Significant Accounting Policies - Changes in Company's Asset Retirement Obligation Liability (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Asset Retirement Obligation [Abstract] | ||||
Asset retirement obligations, beginning of period | $ 17,400 | |||
Additional liabilities incurred | 303 | |||
Accretion | $ 399 | $ 191 | 785 | $ 377 |
Asset retirement obligations, end of period | $ 18,488 | $ 18,488 |
Sale of Oil and Natural Gas P34
Sale of Oil and Natural Gas Property Interest - Additional Information (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2014 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Gain on sale of assets | $ 5,553 | $ 5,473 | $ 1,585 | |
Assets held for sale | 3,618 | $ 3,618 | $ 20,673 | |
Central Processing Facility and Certain Pipelines[Member] | ||||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||||
Sale proceeds of assets | 37,300 | |||
Gain on sale of assets | $ 5,600 |
Derivative Instruments - Summar
Derivative Instruments - Summary of Derivative Instrument Positions for Future Production Periods (Detail) - Jun. 30, 2015 | MMBTU$ / MMBTU$ / bblbbl |
Natural Gas Derivatives [Member] | Production Period July 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 62,500 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 3.78 |
Natural Gas Derivatives [Member] | Production Period January 2016 - December 2016 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 25,000 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 3.66 |
Natural Gas Derivatives [Member] | Production Period July 2015 - October 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 7,000 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 2.84 |
Swap [Member] | Natural Gas Derivatives [Member] | Production Period July 2015 - October 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 25,000 |
Weighted Average Price ($/Bbl) | $ / MMBTU | (1.21) |
Put Option [Member] | Put Purchased [Member] | Natural Gas Derivatives [Member] | Production Period July 2015 - October 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 16,800 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 3.35 |
Put Option [Member] | Put Purchased [Member] | Floor [Member] | Natural Gas Derivatives [Member] | Production Period July 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 15,000 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 3.60 |
Put Option [Member] | Put Purchased [Member] | Floor [Member] | Production Period July 2015 - February 2016 [Member] | Oil Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (Bbls/d) | bbl | 3,000 |
Weighted Average Price ($/Bbl) | $ / bbl | 55 |
Put Option [Member] | Put Purchased [Member] | Floor [Member] | Production Period March 2016 - December 2016 [Member] | Oil Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (Bbls/d) | bbl | 1,000 |
Weighted Average Price ($/Bbl) | $ / bbl | 60 |
Put Option [Member] | Put Sold [Member] | Natural Gas Derivatives [Member] | Production Period July 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 16,800 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 3.35 |
Put Option [Member] | Put Sold [Member] | Natural Gas Derivatives [Member] | Production Period January 2016 - December 2016 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 16,800 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 2.75 |
Put Option [Member] | Put Sold [Member] | Natural Gas Derivatives [Member] | Production Period July 2015 - October 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 16,800 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 2.87 |
Put Option [Member] | Put Sold [Member] | Floor [Member] | Natural Gas Derivatives [Member] | Production Period July 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 15,000 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 3 |
Put Option [Member] | Put Sold [Member] | Floor [Member] | Production Period March 2016 - December 2016 [Member] | Oil Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (Bbls/d) | bbl | 1,000 |
Weighted Average Price ($/Bbl) | $ / bbl | 45 |
Call Option [Member] | Put Sold [Member] | Ceiling [Member] | Natural Gas Derivatives [Member] | Production Period July 2015 - December 2015 [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (MMBtu/d) | 15,000 |
Weighted Average Price ($/Bbl) | $ / MMBTU | 3.80 |
Call Option [Member] | Put Sold [Member] | Ceiling [Member] | Production Period July 2015 - February 2016 [Member] | Oil Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (Bbls/d) | bbl | 3,000 |
Weighted Average Price ($/Bbl) | $ / bbl | 61.40 |
Call Option [Member] | Put Sold [Member] | Ceiling [Member] | Production Period March 2016 - December 2016 [Member] | Oil Derivatives [Member] | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Volume (Bbls/d) | bbl | 1,000 |
Weighted Average Price ($/Bbl) | $ / bbl | 70.10 |
Derivative Instruments - Fair V
Derivative Instruments - Fair Value of Derivative Instruments on a Gross basis and on a Net Basis as Presented in Consolidated Balance Sheets (Detail) - Commodity Contract [Member] - Not Designated as Hedging Instrument [Member] - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 | |
Derivatives, Fair Value [Line Items] | |||
Gross Amount | $ 19,601 | $ 24,090 | |
Netting Adjustments | [1] | (8,090) | (5,056) |
Net Amount Presented in the Balance Sheets | 11,511 | 19,034 | |
Gross Amount | (8,090) | (5,056) | |
Netting Adjustments | [1] | 8,090 | 5,056 |
Net Amount Presented in the Balance Sheets | 0 | 0 | |
Current Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (6,549) | (5,012) | |
Netting Adjustments | [1] | 6,549 | 5,012 |
Net Amount Presented in the Balance Sheets | 0 | 0 | |
Noncurrent Liabilities [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | (1,541) | (44) | |
Netting Adjustments | [1] | 1,541 | 44 |
Net Amount Presented in the Balance Sheets | 0 | 0 | |
Other Current Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 16,742 | 22,349 | |
Netting Adjustments | [1] | (6,549) | (5,012) |
Net Amount Presented in the Balance Sheets | 10,193 | 17,337 | |
Other Noncurrent Assets [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Gross Amount | 2,859 | 1,741 | |
Netting Adjustments | [1] | (1,541) | (44) |
Net Amount Presented in the Balance Sheets | $ 1,318 | $ 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 - Summ37
Derivative Instruments - Summary of Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain (Loss) Recognized in Income | $ (3,523) | $ (863) | $ 7,848 | $ (4,474) |
Commodity Contract [Member] | Gain (Loss) on Derivative Instruments [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Amount of Gain (Loss) Recognized in Income | $ (3,523) | $ (863) | $ 7,848 | $ (4,474) |
Fair Value Measurements - Sched
Fair Value Measurements - Schedule of Fair Value Measured on a Recurring Basis (Detail) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands | Jun. 30, 2015 | Dec. 31, 2014 |
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | $ 11,511 | $ 19,034 |
Level 2 [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | 11,511 | 19,034 |
Commodity Contract [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | 11,511 | 19,034 |
Commodity Contract [Member] | Level 2 [Member] | ||
Fair Value Of Assets And Liabilities Measured On Non Recurring Basis [Line Items] | ||
Total fair value | $ 11,511 | $ 19,034 |
Debt - Additional Information (
Debt - Additional Information (Detail) - USD ($) | Jul. 06, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | Jul. 13, 2015 | Dec. 31, 2014 | Mar. 31, 2014 |
Debt Instrument [Line Items] | ||||||||
Outstanding letters of credit | $ 27,800,000 | $ 27,800,000 | ||||||
Outstanding borrowings | 0 | 0 | ||||||
Revolving Credit Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Revolving credit facility | $ 500,000,000 | |||||||
Borrowing base | 125,000,000 | 125,000,000 | ||||||
Available capacity on the Revolving Credit Facility | 97,200,000 | $ 97,200,000 | ||||||
Minimum [Member] | Revolving Credit Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Commitment fees on unused portion of revolving credit facility | 0.375% | |||||||
Maximum [Member] | Revolving Credit Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Commitment fees on unused portion of revolving credit facility | 0.50% | |||||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Principal amount | 437,300,000 | $ 437,300,000 | $ 422,500,000 | |||||
Accrued interest | 12,700,000 | 12,700,000 | ||||||
Amortization of deferred financing costs and debt discount | 500,000 | $ 600,000 | 2,200,000 | $ 2,000,000 | ||||
12% Senior Unsecured PIK Notes Due 2018 [Member] | Subsequent Event [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt instrument repurchased amount | $ 510,700,000 | |||||||
Debt instrument interest rate | 12.00% | |||||||
8.875% Senior Unsecured Notes Due 2023 [Member] | Subsequent Event [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt instrument interest rate | 8.875% | |||||||
Principal amount | $ 550,000,000 | |||||||
Issuance date | Jul. 6, 2015 | |||||||
Notes issued percentage price | 97.903% | |||||||
Debt instrument, proceeds | $ 525,500,000 | |||||||
PIK [Member] | 12% Senior Unsecured PIK Notes Due 2018 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Accrued interest | $ 14,800,000 | $ 14,800,000 |
Benefit Plans - Additional Info
Benefit Plans - Additional Information (Detail) - USD ($) | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Defined Benefit Plan Disclosure [Line Items] | ||||
Gain on reduction of pension obligations | $ 2,208,000 | |||
Defined benefit plan, employer contributions | $ 0 | $ 0 | ||
Defined Benefit Pension Plan [Member] | ||||
Defined Benefit Plan Disclosure [Line Items] | ||||
Matching contribution by the company to the plan | 100.00% | |||
Percentage of employees' eligible compensation | 6.00% | |||
Expense recognized | $ 300,000 | $ 100,000 | $ 500,000 | $ 200,000 |
Benefit Plans - Components of P
Benefit Plans - Components of Pension Benefit Cost (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract] | ||||
Service cost | $ 70 | |||
Interest cost | $ 62 | $ 85 | $ 126 | 192 |
Expected return on plan assets | (82) | (112) | (164) | (224) |
Amortization of transition obligation | 70 | |||
Amortization of net (gain) loss | 25 | 11 | 43 | 3 |
Settlement costs | 96 | 96 | ||
Net periodic benefit cost(benefit) | $ 101 | $ (16) | $ 101 | $ 111 |
Stock-Based Compensation - Addi
Stock-Based Compensation - Additional Information (Detail) | May. 11, 2015Directorshares | Oct. 07, 2014Directorshares | Jun. 30, 2015USD ($)shares | Jun. 30, 2014USD ($) | Jun. 30, 2015USD ($)shares | Jun. 30, 2014USD ($) |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock based compensation expense | $ 1,410,000 | $ 27,000 | $ 2,157,000 | $ 56,000 | ||
Unrecognized compensation cost related to Incentive Units | 600,000 | $ 600,000 | ||||
Unrecognized compensation cost related to Incentive Units, weighted-average recognition period | 6 years | |||||
Maximum [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Stock based compensation expense | $ 100,000 | $ 100,000 | $ 100,000 | $ 100,000 | ||
Common Class C-1 [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares authorized to be issue | shares | 1,000 | 1,000 | ||||
Common Class C-2 [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares authorized to be issue | shares | 1,000 | 1,000 | ||||
Restricted Stock Issued to Directors [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Unrecognized compensation cost | $ 700,000 | $ 700,000 | ||||
Stock based compensation expense | 255,000 | 400,000 | ||||
Restricted Stock Issued to Directors [Member] | October Two Thousand Fourteen [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Restricted shares of common stock issued | shares | 31,115 | |||||
Number of non employee directors | Director | 7 | |||||
Stock based compensation expense | 200,000 | |||||
Restricted Stock [Member] | May Two Thousand Fifteen [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Restricted shares of common stock issued | shares | 132,496 | |||||
Number of non employee directors | Director | 7 | |||||
Restricted stock expense | 100,000 | |||||
Restricted Stock Units [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Unrecognized compensation cost | 6,500,000 | 6,500,000 | ||||
Stock based compensation expense | 748,000 | 1,171,000 | ||||
Performance Units [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Unrecognized compensation cost | 3,800,000 | 3,800,000 | ||||
Stock based compensation expense | $ 376,000 | $ 528,000 | ||||
2014 Long-Term Incentive Plan [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares authorized to be issue | shares | 16,000,000 | 16,000,000 | ||||
Number of shares are available for future grant | shares | 14,169,746 | 14,169,746 |
Stock-Based Compensation - Sche
Stock-Based Compensation - Schedule of Stock Based Compensation Expense (Detail) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2015 | Jun. 30, 2014 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | $ 1,410 | $ 27 | $ 2,157 | $ 56 |
Restricted Stock Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | 748 | 1,171 | ||
Performance Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | 376 | 528 | ||
Restricted Stock Issued to Directors [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | 255 | 400 | ||
Incentive Units [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||||
Stock based compensation expense | $ 31 | $ 27 | $ 58 | $ 56 |
Stock-Based Compensation - Summ
Stock-Based Compensation - Summary of Restricted Stock and Restricted Stock Unit Awards Activity (Detail) - 6 months ended Jun. 30, 2015 - Restricted Stock Units [Member] - USD ($) $ / shares in Units, $ in Thousands | Total |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares, Granted | 1,247,197 |
Number of shares, Vested | 0 |
Number of shares, Forfeited | (39,210) |
Number of shares, Ending Balance | 1,207,987 |
Weighted average grant date fair value, Granted | $ 7.01 |
Weighted average grant date fair value, Vested | 0 |
Weighted average grant date fair value, Forfeited | 7.13 |
Weighted average grant date fair value, Ending Balance | $ 6.78 |
Aggregate intrinsic value, Granted | $ 0 |
Aggregate intrinsic value, Vested | 0 |
Aggregate intrinsic value, Forfeited | 0 |
Aggregate intrinsic value, Ending Balance | $ 6,354 |
Stock-Based Compensation - Su45
Stock-Based Compensation - Summary of Performance Stock Unit Awards Activity (Detail) - 6 months ended Jun. 30, 2015 - Performance Units [Member] - USD ($) $ / shares in Units, $ in Thousands | Total |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number of shares, Granted | 469,368 |
Number of shares, Vested | 0 |
Number of shares, Forfeited | (10,712) |
Number of shares, Ending Balance | 458,656 |
Weighted average grant date fair value, Granted | $ 8.77 |
Weighted average grant date fair value, Vested | 0 |
Weighted average grant date fair value, Forfeited | 8.77 |
Weighted average grant date fair value, Ending Balance | $ 8.77 |
Aggregate intrinsic value, Beginning Balance | $ 0 |
Aggregate intrinsic value, Granted | 0 |
Aggregate intrinsic value, Vested | 0 |
Aggregate intrinsic value, Forfeited | 0 |
Aggregate intrinsic value, Ending Balance | $ 0 |
Equity - Additional Information
Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions | Jan. 28, 2015 | Dec. 27, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||
Number of shares agreed to issue and sell | 62,500,000 | |
Proceeds from issuance of Common Stock | $ 434 | |
Private Placement [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | ||
Stock price, per share | $ 7.04 |
Related Party Transactions - Ad
Related Party Transactions - Additional Information (Detail) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | Dec. 31, 2010 | |
Administrative and Management Services [Member] | ||||
Related Party Transaction [Line Items] | ||||
Management fee expense | $ 15.6 | |||
Distribution of Assets [Member] | ||||
Related Party Transaction [Line Items] | ||||
Final distribution payment | $ 0.6 | $ 0.6 | ||
Eclipse Resources Operating, LLC ("Eclipse Operating") [Member] | Administrative and Management Services [Member] | ||||
Related Party Transaction [Line Items] | ||||
Total consideration | 0.1 | |||
President and Chief Executive Officer of Eclipse I, its Executive Vice President, Secretary, and General Counsel and its Executive Vice President and Chief Operating Officer [Member] | ||||
Related Party Transaction [Line Items] | ||||
Percentage of membership units owned by related party | 33.00% | |||
Chairman President And Chief Executive Officer [Member] | ||||
Related Party Transaction [Line Items] | ||||
Flight charter services fees | $ 0.1 | $ 0.2 |
Commitments and Contingencies -
Commitments and Contingencies - Additional Information (Detail) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2015USD ($)a | Jun. 30, 2014USD ($) | Jun. 30, 2015USD ($)a | Jun. 30, 2014USD ($) | |
Loss Contingencies [Line Items] | ||||
Lease agreement period | 5 years | |||
Capitalized leasehold costs | $ | $ 0.6 | $ 0.6 | ||
Lease agreement, term | The Company leases office space under operating leases that expire between the years 2015 to 2025. | |||
Rent expense | $ | $ 0.2 | $ 0.1 | $ 0.4 | $ 0.1 |
Oxford acquisition [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 38,555 | 38,555 | ||
Oxford acquisition [Member] | Modification to Lease [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 29,041 | 29,041 | ||
Oxford acquisition [Member] | Unpredicted Modification to Lease [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 9,514 | 9,514 | ||
Other Lawsuit [Member] | ||||
Loss Contingencies [Line Items] | ||||
Area of leasehold property held | 157 | 157 |
Income Tax - Additional Informa
Income Tax - Additional Information (Detail) - USD ($) | 3 Months Ended | 6 Months Ended | |
Jun. 30, 2015 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Tax Disclosure [Abstract] | |||
Percentage of annual effective income tax expense | 30.83% | ||
Income taxes paid | $ 0 | $ 0 | |
Valuation allowance | $ 9,700,000 | $ 9,700,000 | $ 0 |
Federal statutory rate | 35.00% |
Subsequent Event - Additional I
Subsequent Event - Additional Information (Detail) $ in Millions | Jul. 13, 2015USD ($) |
12% Senior Unsecured PIK Notes Due 2018 [Member] | Subsequent Event [Member] | |
Subsequent Event [Line Items] | |
Debt instrument repurchased amount | $ 510.7 |