3.Significant Accounting Policies

Basis of Presentation

The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (GAAP). The accompanying consolidated financial statements include Sabine and its wholly owned subsidiaries. All intercompany transactions have been eliminated. Certain other reclassifications have been made to prior periods in order to conform to current period presentation.

Sabine O&G is considered the accounting predecessor of Sabine Oil & Gas Corporation. Accordingly, the historical financial information of Sabine Oil & Gas Corporation included in this Annual Report on Form 10-K which cover periods prior to the completion of the Combination, reflect the assets, liabilities and operations of Sabine O&G, the accounting predecessor to Sabine Oil & Gas Corporation, and do not reflect the assets, liabilities and operations of Sabine Oil & Gas Corporation. The assets acquired and liabilities assumed in the Combination were recognized in the consolidated balance sheet at their preliminary fair value as of December 16, 2014 and the operating results of the acquired properties are included in the consolidated financial statements for the period beginning thereafter. See Note 6 for details of the Combination.

Cash and Cash Equivalents

All highly liquid investments purchased with an initial maturity of three months or less are considered to be cash equivalents.

Concentration of Credit Risk

The Company’s significant receivables are comprised of oil and natural gas revenue receivables. The amounts are due from a limited number of entities; therefore, the collectability is dependent upon the general economic conditions of a few purchasers. The Company regularly reviews collectability and establishes the allowance for doubtful accounts as necessary using the specific identification method. The receivables are not collateralized (see Note 4).

Derivative instruments subject the Company to a concentration of credit risk (see Note 11).

Oil and Natural Gas Properties and Equipment

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method, the Company capitalizes all acquisition, exploration, and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits, and other internal costs directly attributable to these activities. The Company capitalized $10.1 million, $6.6 million and $2.7 million of internal costs during the years ended December 31, 2014, 2013 and 2012, respectively. Costs associated with production and general corporate activities are expensed in the period incurred. The Company also includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and natural gas property balance (see “Asset Retirement Obligations” below). Unless a significant portion of the Company’s proved reserve quantities is sold (greater than 25%), proceeds from the sale of oil and natural gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

Depletion of proved oil and natural gas properties is computed using the units-of-production method based upon estimated proved oil and natural gas reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. Unproved properties are reviewed on a quarterly basis for impairment, and if impaired, are reclassified to proved properties and included in the depletion base.

Under the full cost method of accounting, a ceiling test is performed on a quarterly basis. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated depletion in the Company’s Consolidated Balance Sheets, may not exceed the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued in the Company’s Consolidated Balance Sheets, using the unweighted average first day of the month commodity sales prices for the previous twelve months (adjusted for quality and basis differentials), held constant for the life of production, discounted at 10%, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as accumulated depletion.

For the years ended December 31, 2014, 2013 and 2012, the Company recognized an impairment of $247.7 million, zero and $641.8 million, respectively, for the carrying value of proved oil and natural gas properties in excess of the ceiling limitation. The average of the historical unweighted first day of the month prices for the prior twelve month periods ended December 31, 2014, 2013 and 2012 were $4.35, $3.67 and $2.76, respectively, for natural gas. The average of the historical unweighted first day of the month prices for the prior twelve month periods ended December 31, 2014, 2013 and 2012 were $94.99, $96.78 and $94.71, respectively, for oil.

The Company’s depletion expense on oil and natural gas properties is calculated each quarter utilizing period end proved reserve quantities. The Company recorded $186.8 million, $134.2 million and $87.6 million of depletion on oil and natural gas properties for the years ended December 31, 2014, 2013 and 2012, respectively. As a rate of production, depletion was $2.49 per Mcfe, $2.10 per Mcfe and $1.80 per Mcfe for the years ended December 31, 2014, 2013 and 2012, respectively.

Gathering assets and related facilities, certain other property and equipment, and furniture and fixtures are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from 3 to 30 years. These assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is then recognized if the carrying amount is not recoverable and exceeds fair value. For the years ended December 31, 2014, 2013 and 2012, the Company recorded impairment charges for gas gathering and processing equipment of $1.7 million, zero and $21.4 million, respectively, utilized based on expected present value and estimated future cash flows using current volume throughput and pricing assumptions. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.

No insurance proceeds were received during the year ended December 31, 2014. For the years ended December 31, 2013 and 2012, the Company received insurance proceeds of $0.6 million and $12.7 million, respectively, which were netted with the replacement costs recognized in oil and natural gas properties. Insurance proceeds were received as a result of control of well events during drilling or completion operations in East Texas.

Capitalized Interest

The Company capitalizes interest costs to oil and natural gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. The Company capitalized $6.5 million, $13.0 million and $4.3 million of interest during the years ended December 31, 2014, 2013 and 2012, respectively.

Derivative Instruments and Hedging Activities

The Company uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. Such derivative instruments, which are placed with major financial institutions who are participants in the Company’s New Revolving Credit Facility (see Note 7) that the Company believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps, options, or basis swaps.

At December 31, 2014 and 2013, substantially all of Sabine’s oil and natural gas derivative contracts are settled based upon reported New York Mercantile Exchange (“NYMEX”) prices. The Company’s derivative contracts are with multiple counterparties to minimize the Company’s exposure to any individual counterparty, and the Company has netting arrangements with all of its counterparties that provide for offsetting payables against receivables from separate hedging arrangements with that counterparty. The oil and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a generally high degree of historical correlation with actual prices received by the Company for its oil and natural gas production. The Company’s fixed-price swap and option agreements are used to fix the sales price for the Company’s anticipated future oil and natural gas production. Upon settlement, the Company receives a fixed price for the hedged commodity and receives or pays the counterparty a floating market price, as defined in each instrument. The instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, the Company pays the counterparty. When the fixed price exceeds the floating price, the counterparty is required to make a payment to the Company.

The Company’s derivatives instruments at December 31, 2014 and 2013 included fixed price oil and natural gas options in addition to fixed price swaps. The Company has bought and sold natural gas puts, bought and sold oil and natural gas calls, sold oil puts and sold oil swaptions in 2014, while in 2013 the Company has bought and sold natural gas puts, bought and sold oil and natural gas calls, and sold oil puts. For the oil and natural gas calls, the counterparty has the option to purchase a set volume of the contracted commodity at a contracted price on a contracted date in the future. For the oil and natural gas puts, the counterparty has the option to sell a contracted volume of the commodity at a contracted price on a contracted date in future.

The Company records balances resulting from commodity risk management activities in the Consolidated Balance Sheets as either assets or liabilities measured at fair value. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented within “Gain on derivative instruments” located in Other income (expenses) in the Consolidated Statements of Operations.

Deferred Financing Costs

Deferred financing costs of approximately $19.7 million and $6.3 million were incurred during 2014 and 2013, respectively, and include costs associated with the Company’s term loan agreement (“Term Loan Facility”), the Former Revolving Credit Facility and the New Revolving Credit Facility (see Note 7). Deferred financing costs associated with the Term Loan Facility, New Revolving Credit Facility and 9.75% senior unsecured notes due 2017 (the “2017 Notes”) are being amortized over the life of the respective obligations with $9.5 million, $9.0 million and $3.2 million included in interest expense during 2014, 2013 and 2012, respectively.

Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s New Revolving Credit Facility and Term Loan Facility are reported at carrying value which approximates fair value based on current rates available to the Company for similar instruments. Since considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the purchase or refinancing of such instruments. The Company’s derivative instruments are reported at fair value based on Level 2 fair value methodologies. The 2017 Notes, the 2019 Notes and 2020 Notes are carried at nominal value, net of unamortized discount. See footnote 12 for fair value measurements related to these instruments.

Goodwill

Goodwill is tested for impairment on an annual basis as of October 1 of each year and more frequently if changes in circumstances warrant.

The testing of goodwill for impairment is done via a two-step process. The first step of the process compares the fair value of the country-wide cost center, which Sabine has determined to be its one reportable geographical business segment, with its carrying amount including goodwill. The fair value of the country-wide cost center will be determined by using a discounted cash flows model which relies primarily on Sabine’s reserve data which include significant assumptions, judgments and estimates, as well as a calculated weighted average cost of capital (“WACC”), derived through analysis of the capital structures of selected peer companies and relevant statistical market data. When the fair value derived exceeds the carrying amount, no impairment is present and the test is concluded.

When the carrying amount exceeds the fair value derived, the second step of the impairment test is performed to compare the implied fair value of goodwill with the carrying amount of goodwill. The implied fair value of goodwill is determined by assigning the fair value of a reporting unit to all of the assets and liabilities of the reporting unit as if the unit had been acquired in a business combination. The excess of fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. Impairment is recognized for the amount of carrying value in excess of implied fair value, limited to the total carrying value of goodwill.

Factors, such as significant decreases in commodity prices and unfavorable changes in the significant assumptions, judgments and estimates used to estimate reserves could result in a goodwill impairment charge. A goodwill impairment charge would have no effect on Sabine’s liquidity or capital resources. However, it would adversely affect Sabine’s results of operations in that period.

Goodwill totaled $173.5 million at December 31, 2013 and no impairment was recognized for the year ended December 31, 2013. The October 1, 2014 impairment test did not yield impairment; however, due to the drop in commodity prices during the fourth quarter of 2014 and the $247.7 million ceiling test impairment on December 31, 2014, the Company performed an additional impairment test as of December 31, 2014. As a result of this impairment test, the Company recognized a $173.5 million impairment of goodwill for the year ended December 31, 2014. No goodwill remained as of December 31, 2014.

Asset Retirement Obligations

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, the Company records an “Asset retirement obligation” (“ARO”) as a liability and capitalizes the present value of the asset retirement cost in “Oil and natural gas properties” on the Consolidated Balance Sheets in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for the Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and the additional capitalized costs are depleted on a unit‑of‑production basis within the related full cost pool.

The information below reconciles the recorded amount of the Company’s asset retirement obligations:


	For the Years Ended
	December 31,
	2014		2013
	(in thousands)
Beginning balance	$	13,798	$	13,580
Liabilities incurred (1)		34,048		993
Liabilities disposed		—		(1,678)
Liabilities settled		(111)		(49)
Revisions		89		—
Accretion expense		958		952
Ending balance	$	48,782	$	13,798

(1)

Includes approximately $33.3 million of liabilities assumed in the Combination with Forest Oil Corporation in December 2014, of which $9.4 million is included in “Other short-term obligations” in the Consolidated Balance Sheets.

Revenue Recognition

The Company records revenues from the sales of oil, natural gas liquids and natural gas when produced, sold and collectability is ensured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, oil, natural gas liquids and natural gas sales are not recognized for deliveries in excess of the Company’s net revenue interest, while oil, natural gas liquids and natural gas sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. The Company had no material overproduction or underproduction at December 31, 2014 and 2013.

Use of Estimates

The preparation of the consolidated financial statements for the Company in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

The Company’s consolidated financial statements are based on a number of significant estimates, including acquisition purchase price allocations, fair value of derivative instruments, oil, natural gas liquids and natural gas reserve quantities that are the basis for the calculation of DD&A and impairment of oil, natural gas liquids and natural gas properties, assumptions underlying the goodwill impairment calculation and timing and costs associated with its asset retirement obligations.

Income Taxes

The Company recognizes deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred tax benefits are recorded as an asset to the extent that management assesses the utilization of such assets to be more likely than not. When the future realization of some portion of the deferred tax asset is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax assets.

Earnings (Loss) per Share

Basic earnings (loss) per share is computed using the two-class method by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. The two-class method of computing earnings (loss) per share is required to be used because the Company has participating unvested restricted stock granted under the 2014 Long Term Incentive Plan (the “2014 LTIP”). The two-class method is an earnings allocation formula that determines earnings (loss) per share for each class of common stock and participating unvested restricted stock according to dividends declared (or accumulated) and participation rights in undistributed earnings. Holders of restricted stock issued under the Company’s 2014 LTIP have the right to receive non-forfeitable dividends if and when declared by the Company, participating on an equal basis with common stock issued and outstanding.

Diluted earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding, increasing the denominator to include the number of additional common shares that would have been outstanding if the dilutive potential common shares (including unvested common shares issued under the 2014 LTIP and additional common shares calculated by assuming that all Series A preferred shares were converted into common shares at the beginning of the period) had been issued. Diluted earnings per share is computed using the more dilutive of the treasury stock method or the two-class method. Under the treasury stock method, the dilutive effect of potential common shares is computed by assuming common shares are issued for these securities at the beginning of the period, with the assumed proceeds from exercise, which include average unamortized stock-based compensation costs, assumed to be used to purchase common shares at the average market price for the period, and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) included in the denominator of the diluted earnings per share computation. Under the two-class method, the dilutive effect of non-participating potential common shares is determined and undistributed earnings are reallocated between common shares and participating securities. No potential common shares are included in the computation of any diluted per share amount when a net loss exists because they would be deemed antidilutive, as was the case for the year ended December 31, 2014. The Company retroactively adjusted its earnings (loss) per share for 2013 and 2012. It was not necessary to include unvested restricted stock grants in the calculations of diluted shares for the years ended December 31, 2013 and 2012 as grants of restricted stock occurred in 2014, and thus there are no differences between basic and diluted shares in 2013 and 2012.

Industry Segment and Geographic Information

The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, NGLs and natural gas. The Company considers its gathering, processing and marketing functions as an ancillary to its oil and gas producing activities. All of the Company’s operations and assets are located in the United States, and substantially all of its revenues are attributable to United States customers.

Stock-Based Compensation

The Company accounts for its stock-based compensation including grants of restricted stock and management incentive units in the consolidated statements of operations based on their estimated fair values. The Company recognizes expense on a straight-line basis over the vesting period of the respective grant.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014‑09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under existing generally accepted accounting principles. This new standard is based upon the principal that revenue is recognized to depict the transfer of 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. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted and entities have the option of using either a retrospective or modified approach to adopt ASU 2014-09. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 provides guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and sets rules for how this information should be disclosed in the financial statements. ASU 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods thereafter. The Company plans to adopt ASU 2014-15 prospectively for the annual period ending December 31, 2016. Pursuant to ASU 2014-15, the Company is required to consider whether there are adverse conditions or events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued and the probability that management’s plans will mitigate the adverse conditions or events (if any). Adverse conditions or events would include, but not be limited to, negative financial trends (such as recurring operating losses, working capital deficiencies, or insufficient liquidity), a need to restructure outstanding debt to avoid default, and industry developments (for example commodity price declines and regulatory changes).