4.Significant Accounting Policies

Basis of Presentation

The Company presents its consolidated financial statements in accordance with U.S. generally accepted accounting principles (“US GAAP”). The accompanying consolidated financial statements include Sabine and its wholly owned subsidiaries. All intercompany transactions have been eliminated.

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 the Consolidated Financial Statements 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 7 herein for details of the Combination.

As a result of sustained losses and our Chapter 11 proceedings, the realization of assets and satisfaction of liabilities, without substantial adjustments and/or changes in ownership, are subject to uncertainty. Given uncertainty surrounding Chapter 11 proceedings, there is substantial doubt about our ability to continue as a going concern.

The accompanying consolidated financial statements do not purport to reflect or provide for the consequences of our Chapter 11 proceedings. In particular, the consolidated financial statements do not purport to show (i) as to assets, their realizable value on a liquidation basis or their availability to satisfy liabilities; (ii) as to pre-petition liabilities, the amounts that may be allowed for claims or contingencies, or the status and priority thereof; (iii) as to shareholders’ equity accounts, the effect of any changes that may be made in our capitalization; or (iv) as to operations, the effect of any changes that may be made to our business.

We have applied ASC 852 “Reorganizations,” in preparing our consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain revenues, expenses, realized gains and losses and provisions for losses that are realized or incurred in the bankruptcy proceedings are recorded in “Reorganization Items, net” in the accompanying Consolidated Statements of Operations. In addition, pre-petition obligations that may be impacted by the bankruptcy reorganization process have been classified on our Consolidated Balance Sheets at December 31, 2015 in “Liabilities Subject to Compromise”. These liabilities include unsecured and under secured obligations which are reported at the amounts expected to be allowed as claims by the Bankruptcy Court, even if they may be settled for lesser amounts.

While operating as debtors in possession under Chapter 11 of the Bankruptcy Code, the U.S. Debtors may sell or otherwise dispose of or liquidate assets or settle liabilities in amounts other than those reflected in our consolidated financial statements, subject to the approval of the Bankruptcy Court or otherwise as permitted in the ordinary course of business.

Liabilities Subject to Compromise

The following table summarizes the components of liabilities subject to compromise (herein referred to as the “Liabilities Subject to Compromise”) included in our Consolidated Balance Sheets as of December 31, 2015:


	December 31, 2015
	(in thousands)
Accounts payable	$	23,655
Accrued liabilities		12,108
Accrued interest payable		74,222
Debt		2,752,149
Other short-term liabilities		9,400
Legal and terminated contracts		36,596
Liabilities subject to compromise	$	2,908,130

Liabilities Subject to Compromise refers to pre-petition obligations that may be impacted by the Chapter 11 reorganization process. The amounts represent our current estimate of known or potential obligations to be resolved in connection with our Chapter 11 proceedings.

Differences between liabilities we have estimated and the claims filed, or to be filed, will be investigated and resolved in connection with the claims resolution process. We will continue to evaluate these liabilities throughout the Chapter 11 process and adjust amounts prospectively as necessary. Such adjustments may be material.

Reorganization Items, net

The following table summarizes the components included in “Reorganization Items, net” in our Consolidated Statements of Operations for the year ended December 31, 2015:


	For the Year Ended
	December 31, 2015
	(in thousands)
Professional fees		46,117
Deferred financing costs and unamortized discounts		378,705
Terminated contracts		33,197
Interest		(157)
Other		976
Total Reorganization items, net	$	458,838

The company uses this category to reflect the net revenues, expenses, gains and losses that are the result of the reorganization and restructuring of the business.

Professional fees included in Reorganization items, net represent professional fees for post-petition expenses. Deferred financing costs and unamortized discounts are related to the New Revolving Credit Facility, Term Loan Facility, 2017 Notes, 2019 Notes and 2020 Notes and are included in Reorganization items, net as we believe these debt instruments may be impacted by the bankruptcy reorganization process. Terminated contracts are primarily related to the Company’s rig and servicing contracts rejected on August 10, 2015 by the Court, effective July 15, 2015, as well as other office lease and software agreements. The terminated contracts represent the estimated claims related to rejection of approved contracts that were not previously included in the Consolidated Balance Sheet as the liability was contingent or an executory contract previously reported as commitments and contingencies. Expenses for terminated contracts were based on pre-petition general unsecured claims for damages caused by the Company’s breach of contract.

During the pendency of the bankruptcy proceedings, the Company will operate their businesses as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. ASC 852 applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities, as well as expenses and income directly associated with the Chapter 11 Cases.

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 herein for details.

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 $9.2 million, $10.1 million and $6.6 million of internal costs during the years ended December 31, 2015, 2014 and 2013, 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, 2015, 2014 and 2013, the Company recognized an impairment of $1.6 billion, $247.7 million and zero, 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, 2015, 2014 and 2013 were $2.58, $4.35 and $3.67, 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, 2015, 2014 and 2013 were $50.28, $94.99 and $96.78, 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 $178.8 million, $186.8 million and $134.2 million of depletion on oil and natural gas properties for the years ended December 31, 2015, 2014 and 2013, respectively. As a rate of production, depletion was $1.75 per Mcfe, $2.49 per Mcfe and $2.10 per Mcfe for the years ended December 31, 2015, 2014 and 2013, 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, 2015, 2014 and 2013, the Company recorded impairment charges for gas gathering and processing equipment of zero, $1.7 million and zero, 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.

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 $3.3 million, $6.5 million and $13.0 million of interest during the years ended December 31, 2015, 2014 and 2013, respectively.

Derivative Instruments and Hedging Activities

The Company has in the past used 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 have taken the form of forward contracts, futures contracts, swaps, options, or basis swaps.

During 2015 and 2014, substantially all of Sabine’s oil and natural gas derivative contracts were settled based upon reported New York Mercantile Exchange (“NYMEX”) prices. The Company’s derivative contracts were with multiple counterparties to minimize the Company’s exposure to any individual counterparty, and the Company had 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 were 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 were used to fix the sales price for the Company’s anticipated future oil and natural gas production. Upon settlement, the Company would receive a fixed price for the hedged commodity and receive or pay 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 utilized in 2015 and 2014 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 would have 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 would have the option to sell a contracted volume of the commodity at a contracted price on a contracted date in the 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.

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. 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 at December 31, 2014. The New Revolving Credit Facility is carried at face value as of December 31, 2015 and December 31, 2014. The Term Loan Facility, 2017 Notes, 2019 Notes and 2020 Notes are carried at face value as of December 31, 2015 and nominal value, net of unamortized discount as of December 31, 2014. See Note 13 for fair value measurements related to these instruments.

Goodwill

The Company performed an impairment test for goodwill as of December 31, 2014, and recognized $173.5 million impairment of goodwill for the year ended December 31, 2014. No goodwill remained as of December 31, 2014 and 2015.

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,
	2015		2014
	(in thousands)
Beginning balance	$	48,782	$	13,798
Liabilities incurred		468		34,048
Liabilities settled		(920)		(111)
Revisions		—		89
Accretion expense		1,930		958
Reclassification to Liabilities Subject to Compromise		(9,400)		—
Ending balance (1)	$	40,860	$	48,782

____________

(1) As of December 31, 2014 Company had AROs of approximately $48.8 million, of which $9.4 million was reported in “Other short-term liabilities” in the Consolidated Balance Sheet attributable to the plugging of abandoned wells.

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 sales 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, 2015 and 2014.

Use of Estimates

The preparation of the consolidated financial statements for the Company in conformity with US 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 for timing and costs associated with its asset retirement obligations and estimates for certain damages that may be accepted in the Chapter 11 process.

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. Refer to Note 6 for details regarding the adoption of ASU 2015-17.

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 years ended December 31, 2015 and 2014. It was not necessary to include unvested restricted stock grants in the calculations of diluted shares for the year ended December 31, 2013 as grants of restricted stock occurred in 2014, and thus there are no differences between basic and diluted shares in 2013.

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 November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). ASU 2015-17 requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent in the consolidated balance sheet. Sabine has elected to early adopt this guidance with retrospective presentation as of December 31, 2014. The impact of this resulted in netting current and long term deferred tax assets and liabilities and making the previously reported misstatement not effective. See Note 3 for additional details.

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) Simplifying the Accounting for Measurement Period Adjustments, eliminating the requirement for the acquirer in a business combination to account for measurement period adjustments retrospectively. ASU 2016-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this Update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date recognized. ASU 2015-16 is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. Early adoption is permitted. The Company elected to early adopt ASU 2015-16 in the fourth quarter of 2015 and applied the new guidance to the measurement period adjustments recognized during the fourth quarter of 2015. For more information see Note 7.

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).

In May 2014, the FASB issued ASU No. 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. In July 2015, the FASB elected to defer the effective date of ASU 2014-09 until annual and interim periods beginning after December 15, 2017. 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.