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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

(Mark One)

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2014
	For the fiscal year ended December 31, 2015
	or
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to

Commission File Number: 01-13515

SABINE OIL & GAS CORPORATION

(Exact name of registrant as specified in its charter)

New York	25-0484900
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1415 Louisiana Street, Suite 1600Houston, Texas 77002
(Address of principal executive offices, including zip code)
Registrant’s telephone number, including area code: (832) 242-9600
Securities registered pursuant to Section 12 (b) of the Act:
Title of class	Name of each exchange on which registered
Common Stock, Par Value $0.10 Per Share	~~OTCQB~~OTC Pink Marketplace
Securities registered pursuant to Section 12 (g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐ Accelerated filer ☒☐ Non-accelerated filer (Do not check if a smaller reporting company) ☐ Smaller reporting company ☐☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, ~~2014~~2015 was approximately $~~268~~14 million, based upon the closing price of $20.2807 per share as reported by the New York Stock Exchange on such date.

~~214~~211,~~669~~693,~~984~~364 shares of our $0.10 par value common stock were outstanding on March 1521, ~~2015~~2016.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s notice of annual meeting of shareholders and proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A within 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Form 10-KNone.

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EXPLANATORY NOTE

As discussed in “Items 1 and 2. Business and Properties” below, on December 16, 2014, Sabine Oil & Gas LLC, a Delaware limited liability company (“Sabine O&G”), and Forest Oil Corporation, a New York corporation, completed the combination of their respective businesses through a series of transactions (“the Combination”) whereby certain indirect equity holders of Sabine O&G contributed the equity interests in Sabine O&G to Forest Oil Corporation. In exchange for this contribution, the equity holders of Sabine O&G received shares of Sabine Oil & Gas Corporation (“Sabine”) common stock and Series A senior non-voting equity-equivalent preferred stock collectively representing approximately a 73.5% economic interest in Sabine and 40% of the total voting power in Sabine (the “Combination”). On December 19, 2014, Forest Oil Corporation changed its name to “Sabine Oil & Gas Corporation.” Because Sabine O&G was considered the accounting acquirer in the Combination under US GAAP, Sabine O&G is also considered the accounting predecessor of Sabine Oil & Gas Corporation. Accordingly, the historical financial and operating data 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 predecessor to Sabine Oil & Gas Corporation, and do not reflect the assets, liabilities and operations of Sabine Oil & Gas Corporation (which was then known as “Forest Oil Corporation”) prior to the Combination. References in this Annual Report on Form 10-K to “Sabine,” “the Company,” “we,” “us” and “our” refer (i) with respect to the period from and after December 16, 2014, to the group of entities within the consolidated group of Sabine Oil & Gas Corporation, and (ii) with respect to the period prior to December 16, 2014, to the group of entities within the consolidated group of Sabine O&G, the predecessor, unless, in each case, otherwise indicated or the context otherwise requires. References in this Annual Report on Form 10-K to “Forest” refer to Sabine Oil & Gas Corporation prior to the Combination, when it was known as “Forest Oil Corporation.” For more information regarding Forest’s historical operating data, please see the Company’s prior Annual Reports on Form 10-K and Quarterly Reports on Form 10-Q.

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PART I		10
Items 1 and 2.	Business and Properties	10
Item 1A.	Risk Factors	3032
Item 1B.	Unresolved Staff Comments	52
Item 3.	Legal Proceedings	53
Item 4.	Mine Safety Disclosures	5657
PART II		5758
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	5758
Item 6.	Selected Financial Data	61
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	60
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	64
Item 8.	Financial Statements and Supplementary Data	86
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	91
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	148
Item 8.	Financial Statements and Supplementary Data	93
Item 9A.	Controls and Procedures	148
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	139
PART III		150
Item 9A.	Controls and Procedures	139
Item 10.	Directors, Executive Officers and Corporate Governance	150
Item 9B.	Other Information	142
Item 11.	Executive Compensation	157
PART III		142
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	167
Item 10.	Directors, Executive Officers and Corporate Governance	142
Item 13.	Certain Relationships and Related Transactions, and Director Independence	169
Item 11.	Executive Compensation	142
Item 14.	Principal Accounting Fees and Services	169
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	142
PART IV		171
Item 13.	Certain Relationships and Related Transactions, and Director Independence	142
Item 15.	Exhibits, Financial Statement Schedules	171
Item 14.	Principal Accounting Fees and Services	142
PART IV		143
Item 15.	Exhibits, Financial Statement Schedules	143

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Certain Terms Used in this Annual Report on Form 10-K

Unless the context otherwise requires, references in this Annual Report on Form 10-K to the following terms have the meanings set forth below:

“Bankruptcy Code” refers to title 11 of the United States Code.

“Bankruptcy Court” refers to the United States Bankruptcy Court for the Southern District of New York.

“Bar Dates” means the deadlines for filing certain proofs of claims in the Debtors’ Chapter 11 cases, which deadline is December 22, 2015 for general claims and January 11, 2016 for governmental claims.

“Combination” refers to the consummation of a series of transactions whereby certain indirect equity holders of Sabine O&G contributed the equity interests in Sabine O&G to Sabine Oil & Gas Corporation (which was then known as “Forest Oil Corporation”). In exchange for this contribution, the equity holders of Sabine O&G received shares of Sabine common stock and Series A senior non-voting equity-equivalent preferred stock (“Sabine Series A preferred stock”) collectively representing approximately a 73.5% economic interest in Sabine and 40% of the total voting power in Sabine. The Combination was completed on December 16, 2014.

“Chapter 11” refers to chapter 11 of the Bankruptcy Code which may also be referred to herein as “Chapter 11 Cases” or “Chapter 11 Proceedings”.

“Debtors” refers to the Company and certain of its subsidiaries, including Giant Gas Gathering LLC, Sabine Bear Paw Basin LLC, Sabine East Texas Basin LLC, Sabine Mid-Continent Gathering LLC, Sabine Mid-Continent LLC, Sabine Oil & Gas Finance Corp., Sabine South Texas Gathering LLC, Sabine South Texas LLC and Sabine Williston Basin LLC.

“Forest” refers to Sabine Oil & Gas Corporation, a New York corporation, prior to the Combination, which was then known as “Forest Oil Corporation.” Forest changed its name to “Sabine Oil & Gas Corporation” on December 19, 2014.

“Sabine,” “we,” “us” or the “Company” refers (i) with respect to the period from and after December 16, 2014, the date of the Combination, to the group of entities within the consolidated group of Sabine Oil & Gas Corporation, a New York corporation and the entity which survived the Combination and (ii) with respect to the period prior to December 16, 2014, to the group of entities within the consolidated group of Sabine O&G.

“Sabine Investor Holdings” refers to Sabine Investor Holdings LLC, a Delaware limited liability company, of which the common equity interests are owned by affiliates of First Reserve, certain members of the Company’s management and board of directors.

“Sabine O&G” refers to Sabine Oil & Gas LLC, a Delaware limited liability company and the accounting predecessor of Sabine.

“Sabine O&G Properties” refer to the oil and natural gas properties historically owned by Sabine O&G prior to the Combination.

“Sabine Oil & Gas Corporation” refers to Sabine Oil & Gas Corporation, a New York corporation.

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Glossary of Oil and Gas Terms

The terms defined in this section are used throughout this Annual Report on Form 10-K. Certain definitions, including the definitions of proved reserves, proved developed reserves, and proved undeveloped reserves, have been abbreviated from the applicable definitions contained in Rule 4-10 (a) of Regulation S-X under the Securities Exchange Act of 1934.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.

Bbtu. One billion British Thermal Units.

Boe. Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil. This ratio does not assume price equivalency and, given price differentials, the price for a barrel of oil equivalent for natural gas may differ significantly from the price for a barrel of oil.

Btu. A British Thermal Unit, or the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface temperature and pressure.

Developed acreage. Acreage that is held by producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole; dry well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Also referred to as a non-productive well.

Equivalent volumes. Equivalent volumes are computed with oil and natural gas liquid quantities converted to Mcf on an energy equivalent ratio of one barrel to six Mcf.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location or the undertaking of other work obligations.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Full cost pool. The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration, and development activities are included. Any costs related to production, general and administrative expense, or similar activities are not included.

Gas. Natural Gas.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

HH or Henry Hub. Henry Hub is the major exchange for pricing natural gas futures on the NYMEX.

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Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

Liquids. Oil, condensate, and natural gas liquids.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

MBoe. Thousand barrels of crude oil equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.

MMBoe. One million barrels of oil equivalent.

Mcf. Thousand cubic feet of natural gas.

Mcfe. Thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.

MMbtu. One million British Thermal Units. One British thermal unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

MMcf. Million cubic feet of natural gas.

MMcfe. Million cubic feet equivalent determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate, or natural gas liquids.

MMcfe/d. One million cubic feet of gas equivalent per day.

NGL or natural gas liquids. Liquid hydrocarbons found in natural gas which may be extracted as separate components, including ethane, propane, butanes, and natural gasoline.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.

Net revenue interest. An owner's share of petroleum after satisfaction of all royalty and other non-cost bearing interests.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

Operator. The individual or company responsible for the exploration and/or exploitation and/or production of an oil or gas well or lease.

Productive wells. Producing wells and wells that are mechanically capable of production.

Proved developed reserves. Estimated proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. Quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under

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existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs t which economic ~~producibility~~productability from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the end of the reporting period, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves or PUDs. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Spot market price. The price for a one-time open market transaction for immediate delivery of a specific quantity of product at a specific location where the commodity is purchased “on the spot” at current market rates.

Tcfe. One trillion cubic feet of gas equivalent.

Standardized measure or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and property taxes, future capital costs, operating expenses, and estimated future income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s requirements, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the estimation date in accordance with the SEC’s regulations and are held constant for the life of the reserves.

Undeveloped acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

Working interest. An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property, and to receive a share of production.

Workover. A series of operations on a producing well to restore or increase production.

WTI or West Texas Intermediate. A grade of crude oil used as a benchmark in oil pricing.

3-D Seismic. Advanced technology method of detecting accumulations of hydrocarbons identified through a three-dimensional picture of the subsurface created by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K and the documents referred to in this Annual Report on Form 10-K contain “forward-looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 (as amended, the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are statements that are not statements of historical fact, including statements about beliefs, opinions and expectations. Forward-looking statements are based on, and include statements about, our plans, prospects, expected future financial condition, results of operations, cash flows, dividends and dividend plans, objectives, beliefs, financing plans, business strategies, budgets, goals, future events, future revenues or performance, financing needs, outcomes of litigation, projected costs, operating metrics, capital expenditures, competitive positions, acquisitions, investment opportunities, integration, cost savings, synergies, growth opportunities, dispositions, plans and objectives of management for future operations and any other information that is not historical information. These statements, which may include statements regarding the period following completion of the reincorporation merger and the related transactions, include, without limitation, words such as “may,” “will,” “could,” “should,” “would,” “expect,” “plan,” “project,” “forecast,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “suggest,” “view,” “potential,” “pursue,” “target,” “continue” and similar expressions and variations as well as the negative of these terms. These statements involve risks, uncertainties, assumptions and other factors that are difficult to predict and that could cause actual results to differ materially from those expressed in them or indicated by them.

These risks and uncertainties are not exhaustive. Other sections of this Annual Report on Form 10-K describe additional factors that could adversely affect our business and financial performance. Moreover, we operate in a very competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and it is not possible to predict all risks and uncertainties, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

Although we believe the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, level of activity, performance or achievements. Moreover, neither we nor any other person assumes responsibility for the accuracy or completeness of any of these forward-looking statements. You should not rely upon forward-looking statements as predictions of future events. We are under no duty to update any of these forward-looking statements after the date of this Annual Report on Form 10-K to conform our prior statements to actual results or revised expectations and we do not intend to do so.

These forward-looking statements appear in a number of places and include statements with respect to, among other things:

risks and uncertainties associated with the Chapter 11 process, including our inability to develop, confirm and consummate a plan under Chapter 11 of the Bankruptcy Code or an alternative restructuring transaction, including a sale of all or substantially all of our assets, which may be necessary to continue as a going concern;

inability to maintain our relationship with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;

failure to satisfy our short- or long-term liquidity needs, including our inability to generate sufficient cash flow from operations or to obtain adequate financing to fund our capital expenditures and meet working capital needs and our ability to continue as a going concern;

estimates of our oil and natural gas reserves;

our future financial condition, results of operations, revenues, cash flows, and expenses;

our future levels of indebtedness, liquidity, and compliance with debt covenants;

our ability to access the capital markets and the terms on which capital may be available to us;

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our ability to fund our operations and capital expenditures;

our future business strategy and other plans and objectives for future operations;

our ability to integrate the historical Forest and Sabine O&G businesses and achieve synergies related to the Combination;

our business’ competitive position;

our outlook on oil and natural gas prices;

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the amount, nature, and timing of our future capital expenditures, including future development costs;

our potential future asset dispositions and other transactions, the timing of closing of such transactions and the use of proceeds, if any, from such transactions;

the risks associated with potential acquisitions or alliances by us;

the recruitment and retention of our officers and employees;

our expected levels of compensation;

the likelihood of success of and impact of litigation on us;

our assessment of our counterparty risk and the ability of our counterparties to perform their future obligations; and

the impact of federal, state, and local political, regulatory, and environmental developments in the United States where we conduct business operations.

We expressly qualify in its entirety each forward-looking statement attributable to us or any person acting on our behalf by the cautionary statements contained or referred to in this section. Except to the extent required by applicable law or regulation, we do not undertake any obligation to update forward-looking statements to reflect events or circumstances after the date of this Annual Report on Form 10-K or to reflect the occurrence of unanticipated events.

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PART I

You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this Annual Report on Form 10-K. For the reasons discussed in the Explanatory Note to this Annual Report on Form 10-K, references in this Annual Report on Form 10-K to “Sabine,” “the Company,” “we,” “us” and “our” refer (i) with respect to the period from and after December 16, 2014, to the group of entities within the consolidated group of Sabine Oil & Gas Corporation, and (ii) with respect to the period prior to December 16, 2014, to the group of entities within the consolidated group of Sabine O&G, the accounting predecessor, unless, in each case, otherwise indicated or the context otherwise requires. References in this Annual Report on Form 10-K to “Forest” refer to Sabine Oil & Gas Corporation prior to the Combination, when it was known as “Forest Oil Corporation.”

Items 1 and 2.Business and Properties

General

We are an independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of oil and natural gas properties onshore in the United States.

On December 16, 2014, pursuant to a series of transaction agreements, certain indirect equity holders of Sabine O&G (such indirect equity holders are referred to as the “Legacy Sabine Investors”) contributed the equity interests in Sabine O&G to us (we were then known as “Forest Oil Corporation”). In exchange for this contribution, the Legacy Sabine Investors received shares of our common stock and our Series A preferred stock collectively representing approximately a 73.5% economic interest in us and 40% of the total voting power in us. Holders of our common stock immediately prior to the closing of the Combination continued to hold their common stock following the closing, which immediately following the closing represented approximately a 26.5% economic interest in us and 60% of the total voting power in us.

On December 19, 2014, we filed a certificate of amendment with the New York Secretary of State to change our name from “Forest Oil Corporation” to “Sabine Oil & Gas Corporation.” Our principal executive offices and corporate headquarters are located at 1415 Louisiana Street, Suite 1600, Houston, Texas 77002. Our telephone number at that address is (832) 242-9600.

Chapter 11 Filings

On July 15, 2015, we and certain of our subsidiaries, including Giant Gas Gathering LLC, Sabine Bear Paw Basin LLC, Sabine East Texas Basin LLC, Sabine Mid-Continent Gathering LLC, Sabine Mid-Continent LLC, Sabine Oil & Gas Finance Corp., Sabine South Texas Gathering LLC, Sabine South Texas LLC and Sabine Williston Basin LLC (collectively, the “Filing Subsidiaries” and, together with us, the “Debtors”), filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The Debtors Chapter 11 cases (the “Chapter 11 Cases”) are being jointly administered under the case styled In re Sabine Oil & Gas Corporation, et al, Case No. 15-11835. The Debtors will continue to 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 and orders of the Bankruptcy Court.

By certain “first day” motions filed in the Chapter 11 Cases, we obtained Bankruptcy Court approval to, among other things and subject to the terms of the orders entered by the Bankruptcy Court, pay certain employee wages, health benefits and certain other employee obligations, pay certain lienholders and forward funds to third parties, including royalty holders and other partners.

For the duration of our Chapter 11 proceedings, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process. For example, negative events associated with our Chapter 11 proceedings could adversely affect our relationships with our suppliers, service providers, customers, and other third parties and our ability to retain employees, which in turn could adversely affect our operations and financial condition. For a description of these and other risks, please see “Part I, Item 1A. Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and shareholders, assets, liabilities, officers and/or

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directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

In particular, subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable debtor’s estate for such damages. The assumption of an executory contract or unexpired lease generally requires the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Debtors in this Annual Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the Debtors, is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Debtors expressly preserve all of their rights with respect thereto.

Our filing of the Bankruptcy Petitions described above constitutes an event of default that accelerated our obligations under the New Revolving Credit Facility, the Term Loan Facility, the 2017 Notes and the Legacy Forest Notes. We have classified all debt as “Liabilities Subject to Compromise” in the Consolidated Balance Sheet at December 31, 2015. This debt includes 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. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported income and expenses could be required and could be material. For additional description of the defaults present under our debt obligations, please see Note 8 within “Part II, Item 8. Financial Statements and Supplementary Data”.

We are making adequate protection payments to the lenders under the New Revolving Credit Facility in an amount equal to the non-default rate of interest, fees and costs due and payable on a monthly basis under the New Revolving Credit Facility, in accordance with the cash collateral order filed with the Bankruptcy Court. Additionally, cash generated by the Company deemed to be proceeds of the oil and gas properties that represent prepetition collateral is deposited into a segregated account, which is reflected as Cash in the Consolidated Balance Sheet as of December 31, 2015, and is used solely to pay for the operations of the prepetition collateral properties.

On October 21, 2015 the Debtors filed a motion to set a bar date to assist with the claims reconciliation process. On January 26, 2016, the Debtors filed with the Bankruptcy Court a joint plan of reorganization (the “Plan of Reorganization”) for the resolution of the outstanding claims against and interests in the Debtors and a disclosure statement (the “Disclosure Statement”) related thereto. The Plan of Reorganization, if implemented as proposed by the Debtors, would significantly reduce our outstanding long-term debt and annual interest payments. The Disclosure Statement has not yet been approved by the Bankruptcy Court. Although the Debtors currently have the exclusive right to file a plan and solicit the appropriate votes thereon, such rights expire on February 10, 2016 and April 11, 2016, respectively. Accordingly, the Debtors have filed a motion to further extend their exclusive right to file and solicit acceptance of the Plan of Reorganization, or any other plan, through June 9, 2016 and August 9, 2016, respectively. A hearing on that motion will be held before the US Bankruptcy Court on April 7, 2016 and April 11, 2016. There can be no assurances regarding our ability to successfully develop, confirm or consummate the Plan of Reorganization, an alternative plan or reorganization or another alternative restructuring transactions, including a sale of all or substantially all of our assets, which satisfies the conditions of the Bankruptcy Code and is authorized by the Bankruptcy Court.

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Our Properties

Overview

Our properties are primarily focused in three core geographic areas:

· East Texas, targeting the Cotton Valley Sand, and Haynesville Shale ~~and Pettet~~ formations;

South Texas, targeting the Eagle Ford Shale formation; and

North Texas, targeting the Granite Wash formation.

As of December 31, ~~2014~~ 2015, we held interests in approximately ~~278~~272,~~500~~100 gross (~~219~~217,~~200~~000 net) acres in East Texas, 8882,~~100~~900 gross (5853,~~700~~400 net) acres in South Texas and 5133,~~400~~900 gross (3625,~~900~~300 net) acres in North Texas. As of December 31, ~~2014~~ 2015, we were the operator on 8990%, 99% and 99% of our net acreage positions in East Texas, South Texas and North Texas, respectively.

The hydrocarbon content of our drilling inventory ranges from predominantly oil to entirely natural gas, providing significant optionality for our capital allocation to maximize returns in a wide variety of commodity price environments. In the near term, our capital program is expected to be focused primarily in the Cotton Valley Sand and Haynesville formations, where we have a history of development activities with consistent and reliable economic results. Our acreage in the Haynesville Shale in East Texas and our acreage in the Eagleville area in South Texas are primarily held by production.

10The 2015 drilling and completion capital program associated with our properties was focused on projects that exhibited the most attractive economics based on commodity prices at that time. Full year 2015 capital expenditures were approximately $197 million, including approximately $203 million on drilling and completion activities, offset by approximately $6 million on acquisitions and other activities. Drilling and completion expenditures included approximately $144 million for the development of proved undeveloped reserves and approximately $59 million for the development of unproved reserves. Our 2016 capital expenditures are forecasted to total approximately $18 million.

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The 2014 drilling and completion capital program associated with our properties was focused on projects that exhibited the most attractive economics based on commodity prices at that time. Full year 2014 capital expenditures were approximately $562 million, including approximately $512 million on drilling and completion activities and approximately $50 million on leasing and other activities. Drilling and completion expenditures included approximately $149 million for the development of proved undeveloped reserves and approximately $363 million for the development of unproved reserves. Our full year 2015 capital expenditures are forecasted to total approximately $230 million to $275 million.

Our Acquisition History

During ~~2012~~2013 through ~~2014~~2015, we successfully completed four significant transactions, including the Combination, asunder ~~well~~which aswe combined the respective businesses of Sabine O&G and Forest. Additionally, we purchased additional ~~acquisitions~~working ~~that~~interests in properties. In prior periods, ~~coupled~~the ~~with~~Company has executed farm out agreements, which established our positions in the Eagle Ford Shale in South Texas and in the Granite Wash area in North Texas, and expanded our positions in the Cotton Valley Sand and Haynesville Shale areas in East Texas. ~~Our key acquisitions and development activities during such period were as follows:~~

· We established our initial position in the Eagle Ford Shale in South Texas in 2012 through a farm-out agreement, which obligated us to drill and complete two wells in the play to earn approximately 15,500 net acres. Subsequently, we have grown our position in the Eagle Ford Shale to approximately 34,800 net acres as of December 31, 2014, excluding the effects of the Combination, via four additional transactions and grass roots leasing.

· In December 2012, we acquired interests in over 60,000 net leasehold acres with then-current net production of approximately 6,500 Boe/d, which established our position in the Granite Wash and Cleveland Sand in North Texas. We have since divested the Cleveland Sand assets. Our remaining net acres in the Granite Wash were approximately 36,900 net acres as of December 31, 2014, which includes the acquisitions of additional interests through two 2014 transactions.

· In December 2014, we completed the Combination, under which we combined the respective businesses of Sabine O&G and Forest.

Operating Regions Associated with Our Properties

East Texas

The East Texas portion of our properties is characterized by several productive horizons, such as the Cotton Valley Sand, Haynesville Shale, Haynesville Lime, Pettet, Bossier Shale, Travis Peak and other formations. Currently, our primary operational focus in this area is directed at the Cotton Valley Sand and Haynesville Shale formations. We believe the Cotton Valley Sand formation is a well-understood play given its history of extensive vertical development, making it a predictable and repeatable development opportunity. Geologically, the Cotton Valley Sand formation is a thick, consolidated sand formation at depths ranging from approximately 7,800 feet to 10,800 feet, and has had over 400 horizontal wells drilled in the play in our properties’ core operating area.

Our other primary target in East Texas, the Haynesville Shale, lies approximately 1,500 feet below the Cotton Valley Sand formation. The Haynesville Shale is a Jurassic age reservoir, which is as much as 300 feet thick, is composed of organic-rich black shale and is found under much of the East Texas acreage position associated with our properties at depths ranging from approximately 11,000 feet to 12,000 feet. We believe this Haynesville Shale position ~~represents a large gas resource, which is strategically positioned geographically to benefit from a growing foreign demand for domestic natural gas.~~

Our East Texas properties are primarily located in Harrison, Panola and Rusk Counties in Texas and Red River Parish in Northern Louisiana with estimated proved reserves of 1,197 Bcfe as of December 31, 2014, of which 78% is natural gas and 51% is developed. As of December 31, 2014, our properties were producing from 1,282 wells in East Texas, and we operated 1,125, or 88%, of those wells. Average net daily production in East Texas from our properties for the three months ended December 31, 2014 was 170 MMcfe/d, on a pro forma basis after giving effect to the Combination.12

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represents a large gas resource, which is strategically positioned geographically to benefit from a growing demand for domestic natural gas.

Our East Texas properties are primarily located in Harrison, Panola and Rusk Counties in Texas and Red River Parish in Northern Louisiana with estimated proved reserves of 623 Bcfe as of December 31, 2015, of which 78% is natural gas and 74% is developed. As of December 31, 2015 our properties were producing from 1,462 wells in East Texas, and we operated 1,251, or 86%, of those wells. Average net daily production in East Texas from our properties for the three months ended December 31, 2015 was 194 MMcfe/d.

Primary operations are in the following areas for which a significant portion of our Cotton Valley Sand and Haynesville Shale acreage overlaps geographically, representing two distinct targets and development opportunities:

· Cotton Valley Sand—As of December 31, ~~2014~~2015, approximately ~~182~~151,~~200~~000 gross (~~145~~101,~~500~~300 net) acres of this East Texas position was prospective for the liquids-rich Cotton Valley Sand formation, 8996% of which was held by production. As of December 31, ~~2014~~2015, our properties produced from ~~101~~110 horizontal and ~~1,099~~972 vertical wells in the Cotton Valley Sand, and we operated 1947,~~056,~~ or 88%, of those wells.

· Haynesville Shale—As of December 31, ~~2014~~2015, approximately 8698,~~100~~900 gross (7071,~~000~~800 net) acres of our East Texas position was prospective for the Haynesville Shale, 8184% of which was held by production. Approximately 98,~~900~~000 gross (97,~~400~~900 net) of this acreage is located in Red River Parish, Louisiana. As of December 31, ~~2014~~2015, we produced from 73132 ~~horizontal~~ wells in the Haynesville Shale, and we operated 69110, or 8483%, of those wells.

· Other—As of December 31, 2014, approximately 60,100 gross (46,600 net) of our East Texas position represents acreage located primarily in Cherokee, Leon, Angelina, Freestone, Wood and Bowie Counties, 67% of which is held by production.

South Texas

The South Texas assets associated with our properties are primarily prospective for the Eagle Ford Shale formation. The first horizontal wells in the Eagle Ford Shale were drilled in 2008, and the play has become one of the largest unconventional oil producing plays in North America. The formation is characterized as having low geologic risks and repeatable drilling opportunities. Geologically, the Eagle Ford Shale is a thick, organic-rich, carbonaceous shale reservoir found at depths ranging from 4,000 feet to 13,000 feet, and in much of the deeper portions of the play is over-pressurized, enhancing well performance.

In South Texas, as of December 31, ~~2014~~ 2015, our properties represented interests in approximately 8882,~~100~~900 gross (5853,~~700~~400 net) acres in DeWitt, Lavaca and Gonzales Counties prospective for the Eagle Ford Shale, approximately 5969% of which was held by production. This area had estimated proved reserves of ~~106~~62 Bcfe as of December 31, ~~2014~~ 2015, of which 6764% was oil or NGLs and 92100% was developed. As of December 31, ~~2014~~ 2015, our properties were producing from 186 wells in South Texas, and we operated ~~184~~183, or 9998%, of those wells. Average net daily production associated with our properties in South Texas for the three months ended December 31, 2015 ~~2014~~ was 7836 MMcfe/d~~, on a pro forma basis after giving effect to the Combination~~.

Primary operations are in the following areas:

· Sugarkane Area—As of December 31, ~~2014~~2015, the Sugarkane area included approximately 32,~~000~~800 gross (2,~~700~~500 net) acres, 9399% of which was held by production. As of December 31, ~~2014~~2015, our properties were producing from 20 horizontal wells, 19 of which we operated. ~~The shape of this acreage block makes it well-suited for full field pad development, and we are the operator for all of our identified drilling locations.~~

· Shiner Area—As of December 31, ~~2014~~2015, the Shiner area included- approximately 3832,~~500~~400 gross (3227,~~000~~500 net) acres, 3240% of which was held by production. As of December 31, ~~2014~~2015, our properties were producing from 48 horizontal wells, 47 of which we operated.

· Eagleville Area—As of December 31, ~~2014~~2015, the Eagleville area included approximately 4647,~~600~~700 gross (2423,~~000~~300 net) acres, 9299% of which was held by production. As of December 31, ~~2014~~2015, our properties were producing from ~~118~~115 horizontal wells, all ~~118~~115 of which we operated.

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North Texas

The North Texas properties are located in the Anadarko Basin with the Granite Wash as the target horizon. The Granite Wash is a series of stacked, silty-sandy deposits found at depths of 8,500 feet to 11,000 feet that were laid down throughout the Pennsylvanian era and into early Permian time, and is over 3,000 feet thick.

12In North Texas, as of December 31, 2015, we held rights to develop approximately 33,900 gross (25,300 net) acres primarily in Roberts County in Texas, approximately 23% of which was held by production. The North Texas acreage as of December 31, 2015 includes approximately 18,850 net acres that are subject to a continuous drilling clause which requires us to drill one gross well every 180 days to hold the entire approximately 18,850 net acre position.

~~Table~~This area has estimated proved reserves of ~~Contents~~17 Bcfe as of December 31, 2015, of which 59% was oil or NGLs and 84% was developed. As of December 31, 2015, our properties were producing from 44 wells in North Texas, and we operated 40, or 91% of those wells. Average net daily production in North Texas for the three months ended December 31, 2015 was 20 MMcfe/d.

In North Texas, as of December 31, 2014, we held rights to develop approximately 51,400 gross (36,900 net) acres primarily in Roberts County in Texas, approximately 13% of which was held by production. The North Texas acreage as of December 31, 2014 includes approximately 32,200 net acres that are subject to a continuous drilling clause which requires us to drill one gross well every 180 days to hold the entire approximately 32,200 net acre position.

This area has estimated proved reserves of 43 Bcfe as of December 31, 2014, of which 71% was oil or NGLs and 62% was developed. As of December 31, 2014, our properties were producing from 49 wells in North Texas, 92% of which we operated. Average net daily production in North Texas for the three months ended December 31, 2014 was 27 MMcfe/d on a pro forma basis after giving effect to the Combination.

Other

As of December 31, ~~2014~~ 2015, our position outside of our three core geographic areas included approximately 7723,~~800~~900 gross (3511,~~300~~200 net) acres primarily in North Dakota, ~~South Dakota,~~ Mississippi and Wyoming.

Estimated Proved Reserves

The information with respect to our estimated proved reserves as of December 31, 2015 ~~2014~~ and December 31, 2014 ~~2013~~ presented below has been prepared by our independent petroleum engineering firm, Ryder Scott Company, L.P. (“Ryder Scott”), in accordance with rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in oil and natural gas producing activities in effect at the applicable time. The reports of Ryder Scott are dated ~~January~~February 205, ~~2015~~2016 and January 2420, ~~2014~~2015. The reports of Ryder Scott are filed as Exhibits 99.1 and 99.2 to this Annual Report on Form 10-K. These proved reserve estimates as of December 31, 2015 ~~2014~~ and December 31, 2014 ~~2013~~ were prepared using the unweighted average of the historical first-day-of-the-month prices for the prior twelve months. It should not be assumed that the present value of future net revenues from our proved reserves is the current market value of our estimated reserves. Actual future prices and costs may differ materially from those used in the present value estimates.

The following table sets forth information regarding ~~the~~our estimated ~~present value of our~~ proved reserves, by region, for the periods indicated. The information in the table does not give any effect to or reflect commodity hedges. Although the SEC’s rules also permit the presentation of estimated “probable” or “possible” reserves, we have limited our presentation to estimated proved reserves.

	At December 31,
	2014 (1)	2013 (2) (3)
	2015 (1)	2014 (2)
	Proved reserves	Proved reserves
	(Bcfe)	(Bcfe)
Operating area
East Texas (4)	1,198	596
East Texas (3)	623	1,198
South Texas	~~106~~62	~~182~~106
North Texas	4317	6143
Other (5)	10	—
Other (4)	0	10
Total	~~1,357~~702	~~839~~1,357

(1) Data for December 31, ~~2014~~2015 is based on the unweighted average of the first-day-of-the-month (a) West Texas Intermediate posted prices for the prior 12twelve months of $9450.9928 per Bbl for oil and (b) Henry Hub spot market prices for the prior 12twelve months of $42.3558 per MMbtu for natural gas.

(2) Data for December 31, 2013 is based on the unweighted average of the first-day-of-the-month (a) West Texas Intermediate posted prices for the prior 12 months of $96.78 per Bbl for oil and (b) Henry Hub spot market prices for the prior 12 months of $3.67 per MMbtu for natural gas. 14

(3) Estimates of proved reserves relate only to those associated with the Sabine O&G Properties at December 31, 2013.

(4) Includes Northern Louisiana.

(5) Includes Wyoming, North Dakota and the Permian Basin.

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(2)

Data for December 31, 2014 is based on the unweighted average of the first-day-of-the-month (a) West Texas Intermediate posted prices for the prior twelve months of $94.99 per Bbl for oil and (b) Henry Hub spot market prices for the prior twelve months of $4.35 per MMbtu for natural gas.

(3)

Includes Northern Louisiana.

(4)

Includes Wyoming, North Dakota and the Permian Basin.

The following table sets forth additional information regarding our estimated proved reserves at the dates indicated.

	At December 31,
	2014 (1)		2013 (2) (3)
	2015 (1)		2014 (2)
Estimated proved reserves:
Oil (MMBbl)	209.12		1620.91
NGLs (MMBbl)	4122.10		2541.1
Natural gas (Bcf)	~~989~~514.83		~~588~~989.18
Total estimated proved reserves (Bcfe)	~~1,357~~701.28		~~839~~1,357.31
Proved developed producing reserves:
Oil (MMBbl)	137.27		513.52
NGLs (MMBbl)	2316.0		1123.0
Natural gas (Bcf)	~~498~~391.14		~~348~~498.31
Total proved developed producing reserves (Bcfe)	~~715~~533.5		~~447~~715.74
Proved developed non-producing:
Oil (MMBbl)	0.51		0.5
NGLs (MMBbl)	0.82		0.68
Natural gas (Bcf)	224.38		1222.3
Total proved developed non-producing reserves (Bcfe)	306.04		1830.40
Total proved undeveloped:
Oil (MMBbl)	61.5		106.95
NGLs (MMBbl)	175.28		1317.42
Natural gas (Bcf)	~~469~~118.40		~~227~~469.54
Total proved undeveloped reserves (Bcfe)	~~611~~161.79		~~373~~611.27
Percent developed	5476.9	%	5554.59	%

(2) Data for December 31, ~~2013~~2014 is based on the unweighted average of the first-day-of-the-month (a) West Texas Intermediate posted prices for the prior 12twelve months of $9694.7899 per Bbl for oil and (b) Henry Hub spot market prices for the prior 12twelve months of $34.6735 per MMbtu for natural gas.

(3) The additional information regarding our estimates of proved reserves relate only to those associated with the Sabine O&G Properties at December 31, 2013.

Controls and Qualifications of Technical Persons

In accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and guidelines established by the SEC, Ryder Scott, independent reserve engineers, estimated 100% of our proved reserve information as of December 31, 2014 ~~2013~~ and December 31, ~~2014~~ 2015. The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs.

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periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and natural gas production, well test data, commodity prices and operating and development costs.

The preparation of proved reserve estimates was completed in accordance with our procedures, which are intended to ensure reliability of reserve estimations, include the following:

review and verification of historical production data, which data is based on actual production as reported by us;

preparation of reserve estimates by our Vice President—Corporate Engineering or under his direct supervision;

review by our Vice President—Corporate Engineering of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

direct reporting responsibilities by our Vice President—Corporate Engineering to our Chief Operating Officer; and

verification of property ownership by our land department.

~~Barrett~~Tim ~~Frizzell~~Pownell, Vice President—Corporate Engineering, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mr. ~~Frizzell~~Pownell is a graduate of ~~Montana~~Texas ~~Tech~~A&M University with a Bachelor of Science degree in ~~Petroleum~~Chemical Engineering, and obtained his MBA from the UCLA Anderson School of Management. Mr. ~~Frizzell~~Pownell has 1525 years of energy experience and our ~~geoscience~~petrotechnical staff has an average of more than 19 years of industry experience per person.

The reserves estimates shown herein have been independently estimated by Ryder Scott, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Ryder Scott was founded in 1937 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-1580. Within Ryder Scott, the technical person primarily responsible for overseeing the estimates set forth in the Ryder Scott evaluation letters incorporated herein is Mr. Joseph E. Blankenship. Mr. Blankenship has been practicing consulting petroleum engineering at Ryder Scott since 1982. Mr. Blankenship is a Licensed Professional Engineer in the State of Texas (No. 62093) and has over 30 years of experience in petroleum engineering and in the estimation and evaluation of reserves. Mr. Blankenship graduated from the University of Alabama in 1977 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Blankenship is a member of the Society of Petroleum Engineers (“SPE”) and a member of the Society of Petroleum Evaluation Engineers (“SPEE”). Mr. Blankenship exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPE. Mr. Blankenship is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Technology Used to Establish Proved Reserves

Under the SEC rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

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To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineers, Ryder Scott, employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, open hole logs, core analyses, geologic maps, available downhole and production data and seismic data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves, material balance calculations or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using pore volume calculations and performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

Proved Undeveloped Reserves (PUDs)

Year Ended December 31, ~~2014~~2015

As of December 31, ~~2014~~ 2015, our proved undeveloped reserves totaled 61.5 MMBbls of oil, 175.8 MMBbls of NGLs and ~~469~~118.0 Bcf of natural gas, for a total of ~~612~~161.9 Bcfe. There were a total of ~~121~~21 PUDs booked with 9318, ~~14,~~2 ~~8, 3~~ and 31 wells booked in the Cotton Valley Sand, Granite Wash, and Haynesville Shale, ~~Eagle Ford and Pettet formations,~~ respectively.

Changes in PUDs that occurred during ~~2014~~2015 were primarily due to:

· ~~additions~~negative revisions of ~~129~~341,~~105~~156 MMcfe ~~attributable~~primarily due to ~~historical~~reduced ~~Forest~~rig ~~properties~~activity asdue ato ~~result~~low ~~of the Combination and two other acquisitions~~prices;

· ~~additions~~the conversion of ~~161~~approximately 142,~~717~~287 MMcfe attributable to ~~extensions~~PUDs ~~resulting~~into ~~from~~proved ~~strategic~~developed ~~drilling~~reserves net of ~~wells~~revisions, bya us23% toconversion ~~delineate~~rate ~~our~~of ~~acreage~~2014 ~~position~~PUD volumes; and

· ~~the~~additions ~~conversion~~ of approximately 4433,~~168~~640 MMcfe ~~attributable~~in PUDs due to ~~PUDs~~a ~~into~~combination ~~proved~~of ~~developed~~adjustments ~~reserves~~in ~~net~~PUD ofworking interest, performance revisions; and optimized well lengths.

· Costs ~~negative~~incurred ~~revisions~~relating ofto ~~approximately~~the ~~8,146~~development ~~MMcfe~~of in PUDs ~~due~~were toapproximately a$144 ~~combination~~million ofduring ~~adjustments~~the intwelve ~~PUD~~months ~~working~~ended ~~interest~~December 31, ~~performance revisions and pricing~~ 2015.

~~Costs~~As ~~incurred~~of ~~relating~~December 31, 2015, to1% ~~the development~~ of ~~PUDs~~our ~~were~~total ~~approximately~~proved ~~$149~~reserves ~~million~~were ~~during~~classified ~~the~~as ~~twelve~~proved ~~months~~developed ~~ended December 31, 2014~~non-producing.

As of December 31, 2014, 2% of our total proved reserves were classified as proved developed non-producing.

Productive Wells

~~Our~~Productive ~~principal~~wells ~~properties~~ consist of ~~developed~~producing ~~and~~wells ~~undeveloped oil~~ and ~~natural~~wells ~~gas~~mechanically ~~leases~~capable inof ~~the operating areas described above and the reserves associated with these leases. Generally~~production, ~~developed~~including ~~oil and~~ natural gas ~~leases~~wells ~~remain~~awaiting inpipeline ~~force~~connections asto ~~long~~commence asdeliveries ~~production is maintained. Undeveloped oil~~ and ~~natural gas leaseholds are generally for a primary term of three to five years. In most cases, the terms of our undeveloped leases can be extended by paying delay rentals or by producing~~ oil ~~and natural gas reserves that are discovered under those leases. The following table sets forth the number of productive~~ wells inawaiting ~~which~~connection weto ~~owned~~production ~~a working interest at December 31, 2014~~facilities. ~~Productive wells consist of producing wells identified as proved developed producing (“PDP”) per the December~~ ~~31, 2014 reserve report prepared by Ryder Scott.~~ Gross wells are the total number of productive wells in which we have working interests, and net wells are the sum of our fractional working interests owned in gross wells. ~~Approximately~~The ~~73%~~following oftable ~~future~~sets ~~net~~forth ~~revenue~~the ~~associated~~number ~~with~~of ~~our~~productive ~~properties~~wells isin ~~from~~which ~~natural~~we ~~gas~~owned ~~while~~a ~~the~~working ~~remaining~~interest ~~27%~~at ~~is from oil and NGLs~~December 31, 2015.

	Oil		Gas
	Gross Wells	Net Wells	Gross Wells	Net Wells
East Texas	3670	2465	1,~~255~~392	1,~~030~~168
South Texas	~~153~~124	9580	1862	1748
North Texas	3441	2126	23	—1
Total	~~223~~235	~~140~~171	1,~~275~~457	1,~~047~~217

Drilling Activities

The table below sets forth the results of our drilling activities for the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a

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~~produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a~~ reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

	For the Year Ended December 31,
	2014 (1)		2013 (2)		2012 (2)
	2015		2014 (1)		2013 (2)
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells:
Productive (3)	0.0	0.0	20.0	10.30	32.0	21.53
Dry	01.0	0.08	—0.0	—0.0	—	—
Total Exploratory	01.0	0.08	20.0	10.30	32.0	21.53
Development Wells:
Productive (3)	6535.0	4930.1	4365.0	3049.81	743.0	730.08
Dry	01.0	01.0	10.0	0.40	—1.0	—0.4
Total Development	6536.0	4931.1	4465.0	3149.21	744.0	731.02
Total Wells:
Productive (3)	6535.0	4930.1	4565.0	3249.1	1045.0	932.51
Dry	02.0	02.0	10.0	0.40	—1.0	—0.4
Total	6537.0	4932.1	4665.0	3249.51	1046.0	932.5

(1)

Drilling activities for the year ended December 31, 2014 include the results of Forest for the period beginning December 16, 2014 and ending December 31, 2014. For the period from January 1, 2014 through December 15, 2014, Forest drilled a total of 18 gross (16.3 net) productive wells.

(2) The drilling activities for the ~~years~~year ended December 31, 2013 ~~and December 31, 2012~~ relate only to those associated with the Sabine O&G Properties.

(3)

Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.

Developed and Undeveloped Acreage

Our properties include interests in developed and undeveloped oil and natural gas acreage in the regions set forth in the table below. Also set forth in the table below, is the percentage of acreage held by production (“HBP”). These interests generally take the form of working interests in oil and natural gas leases or licenses that have varying terms. The following table presents a summary of our acreage interests as of December 31, ~~2014~~ 2015:

Developed acreage

Undeveloped acreage

Total acreage

HBP

Gross

Net

Gross

Net

Gross

Net

East Texas

~~216~~219,~~080~~469

~~179~~183,~~386~~828

6252,~~413~~585

3933,~~769~~182

~~278~~272,~~493~~054

~~219~~217,~~155~~010

8285

South Texas

6065,~~221~~130

3436,~~675~~715

2717,~~832~~815

2416,~~067~~715

8882,~~053~~945

5853,~~742~~430

5969

North Texas

89,~~140~~433

45,~~621~~925

4324,~~242~~508

3219,~~231~~402

5133,~~382~~941

3625,~~852~~327

1323

Total Acreage

~~284~~294,~~441~~032

~~218~~226,~~682~~468

~~133~~94,~~487~~908

9669,~~067~~299

~~417~~388,~~928~~940

~~314~~295,~~749~~767

8277

Our inventory of undeveloped oil and natural gas leaseholds is comprised of three to five year term leases and leases that are held by production beyond their primary term. In most cases, the terms of the undeveloped leases can be extended by paying delay rentals or by producing oil and natural gas reserves that are discovered under those leases, however undeveloped acreage could expire subject to development requirements.

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Undeveloped Acreage Expirations

The following table sets forth the number of total net undeveloped acres as of December 31, 2015 ~~2014~~ that will expire in ~~2015~~2016, ~~2016~~2017 and ~~2017~~2018 unless production is established within the spacing units covering the acreage prior to the expiration dates or unless such leasehold rights are extended or renewed.

	2015	2016	2017	Total
	2016	2017	2018	Total
East Texas(1)	17,889	7,454	1,566	26,909
East Texas	7,812	5,386	1,350	14,548
South Texas	2711,~~250~~246	134,~~454~~709	~~4,836~~189	4516,~~540~~144
North Texas	42,~~281~~162	~~2,040~~199	—31	62,~~321~~392
Total	4921,~~420~~220	2210,~~948~~294	61,~~402~~570	7833,~~770~~084

Production, Revenues and Price History

Oil and natural gas are commodities. The prices we receive for the oil, natural gas and NGLs we produce are largely a function of market supply and demand. We are not committed to provide any material fixed or determinable quantities of oil or natural gas under any existing contracts or agreements. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. Oil and natural gas prices declined significantly in the last half of 2014 with continued weakness in 2015. A further decline or sustained depression in oil or natural gas prices could have a material adverse effect on our business, results of operations, financial condition, access to capital and ability to meet our financial commitments and other obligations. For additional information on commodity price volatility and related risks, see “Part I, Item 1A. Risk Factors.” For a description of our working capital policy, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Working Capital.” See “Part II, Item 8. Financial Statements and Supplementary Data” for information regarding our profits, losses and total assets relating to our production, revenues and price history.

1819

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The following table sets forth information regarding oil and natural gas production, revenues and realized prices and production costs for the years ended December 31, 2015, 2014, ~~2013~~ and ~~2012~~2013. For additional information on price calculations, see information set forth in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

	For the Years Ended December 31,
	2014 (1)		2013 (2)		2012 (2)
	2015		2014 (1)		2013 (2)
Oil, NGLs and natural gas sales by product (in thousands):
Oil	$	~~181~~120,~~313~~996	$	~~132~~181,~~513~~313	$	30132,~~343~~513
NGL		6241,~~420~~610		5962,~~772~~420		3659,~~957~~772
Natural gas		~~218~~172,~~630~~378		~~161~~218,~~938~~630		~~110~~161,~~122~~938
Total	$	~~462~~334,~~363~~984	$	~~354~~462,~~223~~363	$	~~177~~354,~~422~~223
Production data:
Oil (MBbl)		2,~~169~~786.5240		12,~~403~~169.6252		~~317~~1,403.0762
NGL (MBbl))		23,~~120~~168.5698		12,~~842~~120.4756		~~931~~1,842.2647
Natural gas (Bcf)		4966.22		4449.2922		4144.1229
Combined (Bcfe) (3)		74101.9695		6374.7796		4863.6177
Average prices before effects of economic hedges (4):
Oil (per Bbl)	$	8343.5742	$	9483.4157	$	9594.7041
NGL (per Bbl)	$	2913.4413	$	3229.44	$	3932.6844
Natural gas (per Mcf)	$	42.4460	$	34.6644	$	23.6866
Combined (per Mcfe) (3)	$	63.1729	$	56.5517	$	35.6555
Average realized prices after effects of economic hedges (4):
Oil (per Bbl)	$	8160.7983	$	9081.5979	$	9590.7949
NGL (per Bbl)	$	2913.4413	$	3229.44	$	3932.6844
Natural gas (per Mcf)	$	43.3026	$	4.8230	$	54.1782
Combined (per Mcfe) (3)	$	64.0219	$	6.2802	$	56.8128
Average costs (per Mcfe) (3):
Lease operating expenses	$	0.6887	$	0.7068	$	0.9070
Marketing, gathering, transportation and other	$	0.3233	$	0.2832	$	0.3628
Production and ad valorem taxes	$	0.2417	$	0.2824	$	0.0928
General and administrative expenses	$	0.4142	$	0.4341	$	0.4443
Depletion, depreciation and amortization	$	21.5379	$	2.1553	$	12.8815

(1)

Production data for the year ended December 31, 2014 include the results of Forest for the period beginning December 16, 2014 and ending December 31, 2014.

(2) Production data for the ~~years~~year ended December 31, 2013 ~~and December 31, 2012~~ relate only to those associated with the Sabine O&G Properties.

(3)

Oil and NGL production was converted at 6 Mcf per Bbl to calculate combined production and per Mcfe amounts.

(4)

Average prices shown in the table reflect prices both before and after the effects of our realized commodity derivative transactions. Our calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions.

Risk Management

We have designed a risk management strategy using derivative instruments in an attempt to provide partial protection against declines in oil and natural gas prices by reducing the risk of price volatility and the effect it could have on our operations and our ability to finance our capital budget and operations. Our decision on the quantity and price at which we choose to hedge our production is based on our view of existing and forecasted production volumes, budgeted drilling projects and current and future market conditions. While there are many different types of derivatives available, we typically use oil and natural gas price collars and swap agreements to attempt to manage price risk more effectively. The collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period. Periodically, we may pay a fixed premium to increase the floor price above the existing market value at the time we enter into the arrangement. All collar agreements provide for payments to

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counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price is below the floor. The price swaps call for payments to, or receipts from, counterparties based on whether the market price of oil and natural gas for the period is greater or less than the fixed price established for that period when the swap is put in place. Additionally, we have purchased natural gas puts and sold oil and natural gas calls. 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 purchased and sold natural gas puts, the counterparty (sold) or we (purchased) have the option to sell a contracted volume of the commodity at a contracted price on a contracted date in future.

We enter into derivatives arrangements only with counterparties within the Second Amended and Restated Credit Agreement, dated as of December 16, 2014, a $2,000,000,000 reserve based revolving credit facility with an initial borrowing base of $1,000,000,000 (the “New Revolving Credit Facility”), which amended and restated the Amended and Restated Credit Agreement, dated as of April 28, 2009, maturing on April 7, 2016, by and among Sabine O&G, Wells Fargo Bank, National Association, as administrative agent, and the lenders and other parties party thereto (the “Former Revolving Credit Facility”). The New Revolving Credit Facility allows us to hedge up to 100% of current production for 24 months, 75% of current production for months 25 through 36, and 50% of current production for months 37 through 60. For this purpose, “current production” refers to our latest monthly production total. For additional information on our hedging position, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commodity Hedging Activities.”

Competitive Conditions in the Business

The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater financial and other resources than we do. Many of these companies explore for, produce and market oil and natural gas, as well as carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and natural gas properties, obtaining sufficient rig availability, obtaining purchasers and transporters of the oil and natural gas we produce and hiring and retaining key employees. Our larger competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Also, our level of indebtedness may adversely affect our ability to raise additional capital to fund operations and limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt. This could limit our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploring.

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properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Also, our level of indebtedness may adversely affect our ability to raise additional capital to fund operations and limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt. This could limit our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploring.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Marketing and Significant Customers

We market the majority of the natural gas residue, crude oil, and natural gas liquids from properties we operate for both our account and the account of the other working interest owners in these properties.

20In East Texas, we have approximately 85% of our NGL’s under three to five year gathering and processing contracts to a variety of midstream companies. The remainder of our NGL’s are being sold under gathering and processing contracts which are past their primary term with a 30 day evergreen. We sell approximately 45% of our residue under NAESB contracts on a year to year term ending October 31, 2016 at competitive market prices. The remainder of the residue is sold in conjunction with the NGL sale to the midstream companies processing our NGL’s. In East Texas, our oil is sold to one purchaser under a short-term contract which is month-to-month.

~~Table~~In ofSouth ~~Contents~~Texas, we sell our Sugarkane NGL’s under two five-year gathering and processing contracts. Our N. Shiner NGL’s are sold under a five year gas services agreement. Our S. Shiner NGL’s are sold under two separate five year gathering and processing agreements. We sell all our STX residue under NAESB contracts on a year-to-year term ending October 31, 2016. In South Texas, our oil is sold to two separate purchasers under short-term contracts which are month-to-month.

In East Texas, we have approximately 85% of our NGL’s under three to five year gathering and processing contracts to a variety of midstream companies. The remainder of our NGL’s are being sold under gathering and processing contracts which are past their primary term with a 30 day evergreen. We sell approximately 60% of our residue under NAESB contracts on a year to year term ending October 31, 2015 at competitive market prices. The remainder of the residue is sold in conjunction with the NGL sale to the midstream companies processing our NGL’s. In East Texas, our oil is sold to one purchaser under a short-term contract which is month-to-month.

In South Texas, we sell our Sugarkane NGL’s under two five-year gathering and processing contracts. Our N. Shiner NGL’s are sold under a five year gas services agreement. Our N. Shiner NGL’s are sold under a five year gathering and processing agreement. We sell all our STX residue under NAESB contracts on a year-to-year term ending October 31, 2015. In South Texas, our oil is sold to various purchasers under short-term contracts which are month-to-month.

In North Texas, we sell our natural gas residue and NGLs production under a long-term contract to one midstream company, through an acreage dedication. Our oil is sold under a three year contract which allows us to offtake to a dedicated lease automatic custody transfer unit.

During the year ended December 31, ~~2014~~ 2015, purchases by ~~four~~three companies exceeded 10% of our total oil, NGLs and natural gas sales. Purchases by Enbridge ~~Pipelines~~Pipeline (East Texas) LP, NGL Crude Logistics LLC, and Laclede Energy ~~and Eastex Crude Company~~ accounted for approximately 1328%, 1214%, ~~12%~~ and 10%. of our oil, NGLs and natural gas sales, respectively. During the year ended December 31, ~~2013~~ 2014, purchases by ~~three~~four companies exceeded 10% of our total oil, NGLs and natural gas sales. Purchases by ~~Eastex~~Enbridge ~~Crude Company~~Pipelines, ~~Enbridge~~NGL ~~Pipeline~~Crude ~~(East~~Logistics ~~Texas)~~LLC, LPLaclede Energy and CPEastex ~~Energy~~Crude ~~LLC~~Company accounted for approximately 1913%, 1612%, 12% and 1110% of our oil, NGLs and natural gas sales, respectively. During the year ended December 31, ~~2012~~ 2013, purchases by ~~four~~three companies exceeded 10% of our total oil, NGLs and natural gas sales. Purchases by Eastex Crude Company, Enbridge Pipeline (East Texas) LP, ~~Shell~~and ~~Trading~~CP ~~(US) Company, Texla~~ Energy ~~Management~~ LLC ~~and Eastex Crude Company~~ accounted for approximately 1719%, 1416%, ~~13%~~ and 1211% of our oil, NGLs and natural gas sales, respectively. We believe that the loss of any of the purchasers above would not result in a material adverse effect on our ability to competitively market future oil and natural gas production.

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Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), and the courts. We cannot predict when or whether any such proposals may become effective.

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affect the natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), and the courts. We cannot predict when or whether any such proposals may become effective.

We believe that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, results of operations or cash flows. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur, or past non-compliance with environmental laws or regulations may be discovered.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of Transportation of Oil

Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil by common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that allows a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of service filing. Every five years, FERC reviews the appropriateness of the index level in relation to changes in industry costs. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is generally governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Regulation of Transportation and Sales of Natural Gas

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~~regulatory~~transportation ~~framework~~rates ~~that~~under ~~puts~~the ~~natural~~Interstate ~~gas~~Commerce ~~sellers~~Act. ~~into~~In ~~direct~~general, ~~contractual~~interstate ~~relations~~oil ~~with~~pipeline ~~natural~~rates ~~gas~~must ~~buyers~~be bycost-based, ~~among~~although ~~other~~settlement ~~things~~rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, ~~ensuring~~1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil pipelines that ~~the~~allows ~~sale~~a pipeline to increase its rates annually up to a prescribed ceiling, without making a cost of ~~natural~~service ~~gas~~filing. isEvery ~~unbundled~~five ~~from~~years, FERC reviews the ~~sale~~appropriateness of the index level in relation to changes in industry costs. Intrastate oil pipeline transportation ~~and~~rates ~~storage~~are ~~services~~subject to regulation by state regulatory commissions. InThe ~~the~~basis ~~past~~for intrastate oil pipeline regulation, and the ~~federal~~degree ~~government~~of ~~has~~regulatory ~~regulated~~oversight ~~the~~and ~~prices~~scrutiny atgiven ~~which~~to ~~natural~~intrastate ~~gas~~oil ~~could~~pipeline berates, ~~sold~~varies from state to state. ~~While~~Insofar ~~sales~~as byeffective ~~producers~~interstate ofand ~~natural~~intrastate ~~gas~~rates ~~can~~are ~~currently~~equally beapplicable ~~made~~to atall ~~market~~comparable ~~prices~~shippers, ~~Congress~~we ~~could~~believe ~~reenact~~that ~~price~~the ~~controls~~regulation of oil transportation rates will not affect our operations in ~~the~~any ~~future~~way that is of material difference from those of our competitors who are similarly situated.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The open access policies implemented by FERC since the mid-1980s serve to enhance the competitive structure of the interstate natural gas pipeline industry and create a regulatory framework that puts natural gas sellers into direct contractual relations with natural gas buyers by, among other things, ensuring that the sale of natural gas is unbundled from the sale of transportation and storage services. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at market prices, Congress could reenact price controls in the future.

Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act (the “NGA”) and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

We cannot accurately predict how FERC’s actions will impact competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are regularly pending before FERC and the courts, as the natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that any of the measures established by FERC will continue in effect or that they will not be materially altered, potentially on short notice. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission (the “CFTC”) and the Federal Trade Commission. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

Gathering services, which occur upstream of FERC jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Pipeline Safety

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~~emergency procedures~~safety, asenvironmental ~~well as other matters intended to ensure adequate protection for the public~~ and ~~to prevent accidents and failures. Additionally~~, ~~PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that,~~ in ~~the~~some ~~event of a pipeline leak or rupture~~circumstances, ~~could~~nondiscriminatory ~~affect~~take “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areasrequirements. At ~~present,~~Although ~~our~~such ~~operations~~regulation ~~are~~has not ~~subject~~generally tobeen ~~PHMSA’s~~affirmatively ~~integrity~~applied ~~management~~by ~~regulations. We~~state ~~believe that our pipeline operations are in substantial compliance with applicable NGPSA and HLPSA requirements; however~~agencies, ~~due~~natural togas ~~the~~gathering ~~possibility~~may ofreceive ~~new~~greater orregulatory ~~amended~~scrutiny ~~laws~~in ~~and regulations or reinterpretation of existing laws and regulations, future compliance with~~ the ~~NGPSA and HLPSA could result in increased costs~~future.

Regulation of Pipeline Safety

Natural gas and crude oil pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. Both the NGPSA and the HLPSA were amended by the Pipeline Safety Improvement Act of 2002 (“PSI Act”) and the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 (“PIPES Act”). The NGPSA and HLPSA, as amended, govern the design, installation, testing, construction, operation, replacement and management of natural gas, crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing, among other things, pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. At present, our operations are not subject to PHMSA’s integrity management regulations. We believe that our pipeline operations are in substantial compliance with applicable NGPSA and HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA and HLPSA could result in increased costs.

We, or the entities in which we own an interest, inspect our pipelines regularly in compliance with state and federal maintenance requirements. Nonetheless, the adoption of new or amended regulations by PHMSA or the states that result in more stringent or costly pipeline integrity management or safety standards could have a significant adverse effect on us and similarly situated operators. For instance, in August 2011, PHMSA published an advance notice of proposed rulemaking and sought public comment on a number of proposed changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, revising the definitions of “high consequence areas” and “gathering lines” and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed. Most recently, in an August 2014 report to Congress from the U.S. Government Accountability Office (“GAO”), the GAO acknowledged PHMSA’s continued assessment of the safety risks posed by gathering lines and recommended that PHMSA move forward with rulemaking to address larger-diameter, higher-pressure gathering lines, including subjecting such pipelines to emergency response planning requirements that currently do not apply. Our gathering line assets only include small diameter, low-pressure pipelines. Based on current regulatory initiatives and statements made by PHMSA, we do not expect our gathering assets to become regulated as a result of any future rulemakings related to gathering lines. However, we cannot guarantee that PHMSA will not attempt to extend its jurisdiction over our assets at some point in the future.

Environmental Regulation

Our operations are subject to stringent federal, state and local laws and regulations regulating the discharge and disposal of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, issue regulations to implement and enforce these laws, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may result in the assessment of substantial administrative, civil and criminal penalties, as well as the issuance of injunctions limiting or prohibiting our activities. In addition, some laws and regulations relating to protection of the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of that person. Adherence to these regulatory requirements increases our cost of doing business and consequently affects our profitability.

Environmental regulatory programs typically regulate the permitting, construction and operations of a facility. Many factors can materially impact the ability to secure an environmental construction or operation permit. Enforcement actions brought by a regulatory agency can include significant civil penalties for regulatory violations regardless of intent and, under some circumstances, a regulatory agency can request an injunction prohibiting operations. In addition, in some cases private individuals can bring causes of action in court regarding compliance with environmental laws and regulations. New programs and changes in existing regulatory programs are anticipated, some of which include regulations related to the management of natural occurring radioactive materials, oil and natural gas exploration and production, waste management, and underground injection of waste material and the regulation of hydraulic fracturing. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations. From time to time, we may be involved in lawsuits related to alleged pollution or environmental damage. In addition, following the closing of the Combination, we inherited potential liability for several legacy lawsuits filed against Forest. Adverse judgments against us related to these matters could have a material impact on our business. Please see “Part I, Item 3. Legal Proceedings” for more information.

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~~The~~and ~~following~~natural isresources. aThese ~~summary~~laws and regulations may, among other things: (i) require the acquisition of ~~select~~permits ~~existing~~to ~~environmental~~conduct drilling and ~~occupational~~other ~~health~~regulated activities; (ii) restrict the types, quantities and ~~safety~~concentration ~~laws~~of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, aswetlands ~~amended~~and ~~from~~other ~~time~~protected areas; (iv) require remedial measures to ~~time~~clean up or mitigate pollution from former and ongoing operations, such as requirements to ~~which~~close ~~our~~waste ~~business~~pits ~~operations~~and ~~are~~plug ~~subject~~abandoned wells, or at off-site waste disposal locations; (v) impose specific safety and health criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies (and, in some cases, private individuals), enforce these laws and regulations, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may ~~have~~result ain ~~material~~the ~~adverse~~assessment ~~impact~~of onsubstantial administrative, civil and criminal penalties, the issuance of injunctions limiting or prohibiting our ~~capital~~activities, ~~expenditures~~or the imposition of remedial obligations. In addition, ~~results~~some laws and regulations relating to protection of ~~operations~~the environment may, in certain circumstances, impose strict liability for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or ~~financial~~fault ~~position~~on the part of that person. Adherence to these regulatory requirements increases our cost of doing business and consequently affects our profitability.

New programs and changes in existing regulatory programs are anticipated, some of which include regulations related to the management of natural occurring radioactive materials, oil and natural gas exploration and production, waste management, and underground injection of waste material and the regulation of hydraulic fracturing. Environmental laws and regulations have been subject to frequent changes over the years, and the trend has been the imposition of more stringent requirements. While we believe that we are in substantial compliance with current applicable environmental laws and regulations, changes in existing or new laws or regulations could have a material adverse effect on our financial condition and results of operations. From time to time, we may be involved in lawsuits related to alleged pollution or environmental damage. In addition, we cannot assure you that we will not incur significant costs as a result of releases or spills in the course of our operations. For example, following the closing of the Combination, we inherited potential liability for several legacy lawsuits filed against Forest. Adverse judgments against us related to these matters could have a material impact on our business. Please see “Part I, Item 3. Legal Proceedings” for more information.

The following is a summary of select existing and proposed environmental and occupational health and safety laws, as amended from time to time, to which our business operations are or may be subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Wastes

The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes and their implementing regulations, regulate the generation, storage, treatment, transportation, disposal and cleanup of certain hazardous and non-hazardous solid wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or natural gas, including naturally occurring radioactive material, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified by regulatory agencies as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in August 2015, nonprofit environmental groups filed a notice of intent to sue the EPA regarding its failure to review the exemption. A loss of the RCRA hazardous waste exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may become regulated as hazardous wastes if such wastes have hazardous characteristics.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of certain “hazardous substances” into the environment. These persons can include the current and past owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, neighboring landowners and other third-parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although petroleum, including crude oil or any fraction thereof, is not a CERCLA “hazardous substance,” we generate materials in the course of our operations that may be regulated as CERCLA hazardous substances if such wastes are determined to have hazardous characteristics.

We currently own, lease, operate and/or have acquired numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges and Releases

Our operations are also subject to the Clean Water Act (the “CWA”) and analogous state laws. The CWA and similar state laws regulate discharges of wastewater, oil, and other pollutants to certain surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. In addition, spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The CWA and analogous state laws also require individual permits or coverage

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~~under~~persons ~~general~~can ~~permits~~include ~~for~~the ~~discharges~~current and past owner or operator of ~~storm~~the ~~water~~site ~~runoff~~where ~~from~~the ~~certain~~release ~~types~~occurred and anyone who disposed or arranged for the disposal of ~~facilities~~a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and ~~also~~several, ~~prohibits~~strict liability for the ~~discharge~~costs of ~~dredge~~cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and ~~fill~~for ~~material~~the incosts ~~regulated~~of ~~waters~~certain health studies. CERCLA also authorizes the EPA and, ~~including~~in ~~wetlands~~some instances, ~~unless~~third ~~authorized~~parties byto ~~permit.~~act Wein ~~believe~~response ~~that~~to wethreats ~~will~~to bethe ~~able~~public health or the environment and to ~~obtain~~seek to recover from the responsible parties the costs they incur. In addition, orneighboring belandowners ~~included~~and ~~under~~other third-parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although petroleum, ~~these~~including ~~permits~~crude oil or any fraction thereof, ~~where~~is ~~necessary~~not a CERCLA “hazardous substance,” ~~and~~we ~~would~~generate bematerials ~~able~~in tothe ~~make~~course ~~whatever~~of ~~minor~~our ~~modifications~~operations tothat ~~existing~~may ~~facilities~~be regulated as CERCLA hazardous substances and ~~operations~~thus ~~are~~may ~~necessary~~be subject to ~~comply~~joint ~~with~~and ~~CWA~~several ~~requirements~~liability ~~and~~for ~~that~~the ~~such~~costs ~~modifications~~to ~~would~~clean ~~not~~up sites at which these hazardous substances have abeen ~~material~~released ~~effect~~into onthe usenvironment.

We currently own, lease, operate and/or have acquired, and have in the past owned, leased operated, numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges and Releases

Our operations are also subject to the Clean Water Act (the “CWA”) and analogous state laws. The CWA and similar state laws regulate discharges of wastewater, oil, and other pollutants to regulated water bodies, such as lakes, rivers, wetlands, and streams. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the analogous state agency. In addition, spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The CWA and analogous state laws also require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities, and also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. We believe that we will be able to obtain, or be included under, these permits, where necessary, and would be able to make whatever minor modifications to existing facilities and operations are necessary to comply with CWA requirements and that such modifications would not have a material effect on us. Failure to obtain or comply with permits or other CWA could result in administrative, civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages.

The Oil Pollution Act of 1990 (“OPA”), which amended the CWA, imposes ongoing requirements on owners and operators of facilities that handle certain quantities of oil, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental clean-up and restoration costs that could be incurred in connection with an oil spill. In addition, OPA establishes strict liability for owners and operators of facilities that are the site of a release of oil into regulated waters. If a release into regulated waters occurs, we could be liable for clean-up costs, natural resources damages and public and private damages.

Hydraulic Fracturing

Hydraulic fracturing is an essential and common practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the ~~wellbore~~well bore. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. While hydraulic fracturing ~~has~~is ~~historically~~generally ~~been~~exempt ~~regulated~~from byregulation ~~state oil and natural gas commissions,~~ the ~~EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the federal~~ Safe Drinking Water Act’s (“SDWA”) ~~involving~~Underground ~~the~~Injection use of diesel fuels and published revised permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. Also, in May 2014, the EPA published an advance notice of proposed rulemaking under the Toxic Substances Control ~~Act~~(“UIC”) ~~seeking stakeholder input on development of a requirement regarding disclosure of information on chemical substances~~ and ~~mixtures~~has ~~used~~historically inbeen ~~hydraulic~~regulated ~~fracturing. The~~by ~~public comment period on the EPA’s advance notice ended in September 2014, and the resultant proposed rule is expected in 2015.~~

On May 24, 2013, the federal Bureau of Land Management published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The revised proposed rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface; however, to date, no further action has been taken.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. A draft report concerning the potential impacts of hydraulic fracturing on drinking water resources is expected to be released sometime in the first half of 2015. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by early 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

Underground Injection Wells

Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The disposal of oil and natural gas wastes into underground injection wells are subject to the SDWA’s Underground Injection Control (“UIC”) program and analogous state programs. EPA directly administers the UIC program in some states and in others it delegates administration to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In response to recent seismic events near underground injection wells used for the disposal of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. In response to these concerns, regulators in some states are considering additional requirements related to seismic safety. For example, the Texas Railroad Commission (“RRC”) on October 28,

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~~2014,~~state ~~adopted new~~ oil and natural gas ~~permit~~commissions, ~~rules~~the ~~for~~EPA ~~wells~~has ~~used~~asserted tofederal ~~dispose~~regulatory ofauthority ~~saltwater~~over ~~and~~certain ~~other~~hydraulic-fracturing ~~fluids~~activities. ~~resulting~~For ~~from~~example, the ~~production~~EPA ofpublished ~~oil~~revised ~~and~~permitting ~~natural~~guidance ~~gas~~ in ~~order~~February to2014 ~~address~~addressing ~~these~~the ~~seismic~~performance ~~activity~~of ~~concerns~~such ~~within~~activities ~~the~~using ~~state~~diesel fuels. ~~Among~~Also, ~~other~~in ~~things~~May 2014, the ~~rules~~EPA ~~require~~published ~~companies~~an advance notice of proposed rulemaking under the Toxic Substances Control Act seeking ~~permits~~stakeholder ~~for~~input ~~disposal~~on ~~wells~~development toof ~~provide~~a ~~seismic~~requirement ~~activity~~regarding ~~data~~disclosure of information on chemical substances and mixtures used in ~~permit~~hydraulic ~~applications,~~fracturing. The ~~provide~~public ~~for~~comment ~~more~~period ~~frequent~~on ~~monitoring~~the ~~and~~EPA’s ~~reporting~~advance ~~for~~notice ~~certain~~ended ~~wells~~in September 2014, and ~~allow~~a ~~the~~final ~~RRC~~notice toof ~~modify~~proposed rulemaking is expected in 2016. In addition, ~~suspend~~in April 2015, orthe ~~terminate~~EPA ~~permits~~proposed onregulations ~~grounds~~under ~~that~~the aClean ~~disposal~~Water ~~well~~Act to regulate wastewater discharges from hydraulic fracturing to publicly-owned treatment works (the final rule is ~~likely~~expected to be, orissued ~~determined~~in 2016). In addition to berulemakings, ~~causing~~increased ~~seismic~~scrutiny ~~activity.~~of Ifthe ~~new~~oil ~~regulatory~~and ~~initiatives~~natural ~~are~~gas ~~implemented~~industry ~~that~~may ~~restrict~~occur oras ~~prohibit~~a result of the ~~use~~EPA’s ofFY2014-2016 ~~underground~~National ~~injection~~Enforcement ~~wells~~Initiative, in"Ensuring ~~areas~~Energy ~~where~~Extraction weActivities ~~rely~~Comply ~~upon~~with ~~the~~Environmental ~~use~~Laws," ofthrough ~~such~~which ~~wells~~the inEPA ~~our~~will ~~operations,~~address ~~our~~incidences ~~costs~~of tononcompliance ~~operate~~from ~~may~~natural ~~significantly~~gas ~~increase~~extraction and ~~our~~production ~~ability~~activities that may cause or contribute to ~~continue~~significant ~~production~~harm ~~may~~to bepublic ~~delayed~~health and/or ~~limited,~~the ~~which~~environment; ~~could~~starting ~~have~~October a1, ~~material~~2016, ~~adverse~~this ~~effect~~initiative onwill ~~our~~continue ~~results~~for ofthree ~~operations~~more ~~and~~fiscal ~~financial position~~years.

In March 2015, the federal Bureau of Land Management published a final rule governing hydraulic fracturing on federal and Indian lands that replaces a prior draft of proposed rulemaking issued by the agency in May 2012. The rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. However, a federal judge has granted a preliminary injunction preventing enforcement of the rules.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater in 2011 and issued a draft assessment for public comment and peer review in June 2015; the assessment is expected to be finalized in 2016. The draft assessment concluded that hydraulic fracturing has not led to widespread, systemic impacts on drinking water resources, but it does have the potential to impact drinking water resources; however, this conclusion has recently been criticized by the EPA’s Science Advisory Board. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

In addition, the U.S. Congress has from time to time considered the adoption of legislation to provide for federal regulation of the hydraulic fracturing or to require disclosure of the chemicals used in the hydraulic fracturing process. Furthermore, some states, including Texas, have adopted or are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities, or that ban hydraulic fracturing altogether. Some local governments have also adopted ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Any additional federal, state or local restrictions on hydraulic fracturing that may be imposed in areas where we conduct business could result in substantial incremental operating, capital and compliance costs as well as delay our ability to develop oil and natural gas reserves.

Underground Injection Wells

Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The disposal of oil and natural gas wastes into underground injection wells are subject to the SDWA’s UIC program and analogous state programs. EPA directly administers the UIC program in some states and in others it delegates administration to the state. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In response to recent seismic events near underground injection wells used for the disposal

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of oil and gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity. For example, in 2015, a U.S. Geological Survey report identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In response to these concerns, regulators in some states have shut down or imposed moratoria on the use of such injection wells and are considering additional requirements related to seismic safety. For example, the Texas Railroad Commission (“RRC”) on October 28, 2014, adopted new oil and gas permit rules for wells used to dispose of saltwater and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.

Air Emissions

The federal Clean Air Act (the “CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. Our operations are in certain circumstances and locations be subject to permitting requirements and restrictions under these statutes for emissions of air pollutants.

Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in January 2013, the EPA published revised regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The revised rule requires management practices for all covered engines and requires the installation of oxidation catalysts or non-selective catalytic reduction equipment on larger equipment at sites that are not deemed “remote” under the rule. We believe our operations are in substantial compliance with the requirements of this rule.

In addition, in 2012, the EPA ~~has~~ issued final rules under the ~~Clean~~CAA ~~Air Act~~ that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants programs. These rules restrict volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non‑wildcat and non‑delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. “Other” wells, however, must use reduced emission completions, also known as “green completions,” with or without combustion devices. The capture of flowback emissions is required only after the facility’s processing system can be brought to pressure. These regulations also establish specific requirements regarding emissions from production‑related wet seal and reciprocating compressors, pneumatic controllers, and storage vessels. The EPA received numerous requests for reconsideration of these rules, and court challenges to the rules were also filed. The EPA has issued, and will likely continue to issue, revised rules responsive to some of these requests. For example, on December 19, 2014, the EPA finalized amendments and clarifications to the NSPS rules, including, for example, updates and clarifications to requirements related to well completion activities, storage tanks, and leak detection. To date, our costs to comply with the NSPS have not been material. In ~~addition~~September 2015, the EPA ~~has~~proposed ~~announced~~updates to the NSPS rules that itwould ~~will~~impose ~~issue~~volatile ~~new~~organic ~~regulations~~compound inemissions ~~the~~limits ~~summer~~on ofcertain ~~2015~~oil toand ~~reduce~~natural gas operations that were previously unregulated, including hydraulically fractured oil wells, as well as methane emissions ~~from~~limits for certain new ~~and~~or modified oil and natural gas emissions sources (the rules are expected to be finalized in June 2016). In addition, the ~~oil~~EPA ~~and~~published ~~natural~~a ~~gas~~final ~~sector~~regulation byon upOctober 1, 2015 that reduces the National Ambient Air Quality Standard for ozone to 45between ~~percent~~65 ~~below~~to ~~2012~~70 ~~levels~~parts byper ~~2025~~billion (“ppb”) for both the 8 hour primary and secondary standards protective of public health and public welfare. These ~~standards~~regulations, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities, or utilize specific ~~equipment or technologies to control emissions. Compliance with these requirements could increase our costs of development and production, which costs could be significant.~~

~~Climate Change~~ 28

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~~natural~~equipment ~~gas~~or ~~production~~technologies ~~facilities~~to oncontrol anemissions. ~~annual~~Compliance ~~basis,~~with ~~which~~these ~~includes~~requirements ~~certain~~could ofincrease our ~~operations.~~costs ~~Further, the EPA recently proposed a rule that would require reporting~~ of ~~GHG~~development ~~emissions from gathering~~ and ~~boosting systems~~production, ~~oil~~which ~~well~~costs ~~completions and workovers using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The expansion of the EPA’s GHG reporting program~~ could ~~result~~be ~~in increased compliance costs~~significant.

Climate Change

The EPA has determined that emissions of greenhouses gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted various regulations regarding GHGs under existing provisions of the CAA. For example, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations. Further, in 2015, the EPA finalized a rule that requires reporting of GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The expansion of the EPA’s GHG reporting program could result in increased compliance costs.

The EPA also recently proposed new regulations that set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45% from 2012 levels by 2025; the regulations are expected to be finalized in 2016. To aid in these efforts, in January 2016, the federal Bureau of Land Management proposed rules to reduce methane emissions from venting, flaring and leaking on public lands. In addition, the Clean Power Plan, which was announced in August 2015, seeks to reduce carbon dioxide emissions by 32 percent from 2005 levels by 2030; however, on February 9, 2016, the U.S. Supreme Court stayed the implementation of the plan while it is being challenged in court. Furthermore, the U.S. is a party to the Paris Agreement adopted in December 2015 to reduce global greenhouse emissions.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Threatened and Endangered Species

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, ~~including~~as well as migratory birds. We may conduct operations in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered may exist. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. On February 11, 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the FWS is required to make a determination on listing of more than 250 species as endangered or threatened under the Endangered Species Act (“ESA”) by no later than completion of the agency’s 2017 fiscal year. For example, in March 2014, FWS listed the lesser prairie chicken as a threatened species under the ESA. The designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising ~~from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.~~

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from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce reserves.

OSHA

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens. In December 2015, the U.S. Departments of Justice and Labor announced a plan to more frequently and effectively prosecute worker health and safety violations, including enhanced penalties. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for ~~on-going~~ongoing operations. These permits are generally subject to protest, appeal, or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines, and other operations.

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Related Insurance

We maintain an insurance program designed to provide coverage for our property and casualty exposures. Our risk management program provides coverage types, limits, and deductibles commensurate with companies of comparable size and with similar risk profiles. As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a ~~materially~~material adverse effect on our financial position and results of operations. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover every claim made against us in the future. As hydraulic fracturing is a key component of our operational strategy, we maintain Claims Made Pollution Liability Insurance, which provides coverage for long-term gradual seepage pollution events. A loss in connection with our oil and natural gas operations could have a material adverse effect on our financial position and results of operations to the extent that the insurance coverage provided under our policies is inadequate to cover any such loss.

Employees

As of December 31, ~~2014~~ 2015, we had ~~289~~146 full-time employees. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with our employees. We believe that our employee relationships are satisfactory. In connection with our bankruptcy filing and liquidity constraints, we have performed layoffs throughout 2015 and into the first quarter of 2016. We continue to monitor the best allocation of our capital to promote enterprise value, including any cost-reducing cuts to our general and administrative expenses.

Geographical Data

We operate in one industry segment, oil and gas exploration and production, and have one reportable geographical business segment, the United States.

Available Information

We are required to file any annual, quarterly and current reports, proxy statements and certain other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1‑800‑SEC‑0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov.

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We also make available on our website (www.sabineoil.com) all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Financial Code of Ethics and Regulation FD Policy are also available on our website and in print free of charge to any stockholder who requests them. Requests should be sent by mail to 1415 Louisiana, Suite 1600, Houston, Texas 77002, attention Secretary. Information contained on our website is not incorporated by reference into this Annual Report on Form 10‑K.

Legal Proceedings

We are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuits with certainty, but our management team does not expect the outcome of pending or threatened legal matters to have a material adverse impact on our financial condition. Please see “Part I, Item 3. Legal Proceedings” for more information.

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Item 1A. Risk Factors

The following are certain risk factors that affect our business, financial condition, results of operations and cash flows. Many of these risks are beyond our control. These risk factors should be considered in connection with evaluating the forward-looking statements contained in this Annual Report on Form 10-K. The risks and uncertainties described below are not the only ones that we face. If any of the events described below were to actually occur, our business, financial condition, results of operations and cash flows could be adversely affected and our results could differ materially from expected and historical results, any of which may also adversely affect the holders of our stock.

~~Risks~~We ~~Relating~~have filed voluntary petitions for relief under the Bankruptcy Code and are subject to ~~Our~~the ~~Business~~risks and uncertainties associated with bankruptcy cases.

~~Due~~We tohave ~~our~~filed ~~substantial~~voluntary ~~liquidity~~petitions ~~concerns~~for relief under Chapter 11 of the Bankruptcy Code. For the duration of the Chapter 11 Cases, weour ~~may~~business and operations will be ~~unable~~subject to ~~continue~~various asrisks, aincluding ~~going~~but ~~concern.~~not limited to the following:

· Our ~~existing and future debt agreements could create issues as interest payments become due and the debt matures that will threaten our~~ ability to ~~continue as a going concern. For example~~develop, ~~absent~~file any action with respect to the repayment or refinancing of our existing indebtedness or any waivers or amendments to the agreements governing our existing indebtedness, our Term Loan will mature on November 16, 2016 and ~~our~~complete ~~New Revolving Credit Facility will mature on April 7, 2016. Additionally, the borrowing base under our New Revolving Credit Facility is subject to at least semi-annual redetermination and as~~ a ~~result,~~Chapter ~~availability~~11 ~~thereunder~~plan ~~could be reduced and advances in excess~~ of ~~the~~reorganization, ~~new~~particularly ~~availability would need to be repaid. We also have substantial interest payments due~~ during the ~~next~~exclusivity ~~twelve~~period ~~months on our 2017 Notes and Legacy Forest Notes~~(i. Ife. wein ~~fail~~general, ~~to satisfy our obligations with respect to our indebtedness or fail to comply with~~ the ~~financial~~period ~~and other restrictive covenants contained~~ in ~~the debt agreements governing our indebtedness, an event of default could result,~~ which would permit acceleration of such debt and which could result in an event of default under and acceleration of our other debt and could permit our secured lenders to foreclose on any of our assets securing such debt. Any accelerated debt would become immediately due and payable. While we ~~will~~have ~~attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend~~ the ~~maturity~~exclusive ~~dates,~~right ~~and~~ to ~~cure~~file ~~any~~a ~~potential~~Chapter ~~defaults,~~11 ~~there~~plan ~~is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the maturity~~ of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient. The uncertainty associated with our ability to repay our outstanding debt obligations as they become due raises substantial doubt about our ability to continue as a going concern. reorganization);

~~The~~· ~~report~~Our ofability ~~our~~to ~~independent~~obtain ~~registered~~Bankruptcy ~~public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31~~Court, ~~2014~~creditor ~~contains~~and anregulatory ~~explanatory~~approval ~~paragraph~~of ~~regarding the substantial doubt about our ability to continue as~~ a ~~going~~Chapter ~~concern. As~~11 aplan ~~result,~~of wereorganization ~~are~~ in ~~default~~a ~~under~~timely ~~our New Revolving Credit Facility and Term Loan Facility.~~ manner;

· Our New Revolving Credit Facility and Term Loan Facility require that our annual financial statements include a report from our independent registered public accounting firm with an unqualified opinion without an explanatory paragraph as to going concern. In consideration of the uncertainty mentioned above, the report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2014 contains an explanatory paragraph regarding the substantial doubt about our ability to ~~continue~~obtain asBankruptcy aCourt ~~going~~approval ~~concern. As a result, we are in default under our New Revolving Credit Facility and Term Loan Facility. We are currently in discussions~~ with ~~the~~respect lenders under our New Revolving Credit Facility regarding a waiver of this requirement. If we do not obtain a waiver of this requirement under within 30 days, there will exist an event of default under the New Revolving Credit Facility and the lenders under the New Revolving Credit Facility will be able to ~~accelerate~~motions ~~the~~in ~~debt. Similarly, if we do not obtain a waiver under~~ the ~~Term~~Chapter ~~Loan~~11 ~~Facility~~Cases ~~within 180 days, there will exist an event of default under the Term Loan Facility~~ and the ~~lenders~~outcomes ~~under the Term Loan Facility will be able to accelerate the debt. Any acceleration~~ of ~~the~~Bankruptcy ~~debt~~Court ~~obligations~~rulings ~~under the New Revolving Credit Facility or Term Loan Facility would result in a cross-default~~ and ~~potential acceleration~~ of the ~~maturity~~Chapter of11 ~~our~~Cases ~~other outstanding debt obligations. Therefore, all our outstanding debt obligations~~ in the amount of $2.0 billion (net of discount) are presented in current liabilities as of December 31, 2014. Additionally, the lenders under the Term Loan Facility are subject to a 180-day standstill before they are able to exercise remedies as a result of the uncured event of default. Following the expiration of the 180-day standstill, the lenders are permitted to foreclose on the collateral securing the Term Loan Facility. general;

30 · Risks associated with third party motions in the Chapter 11 Cases, which may interfere with our business operations or our ability to propose and/or complete a Chapter 11 plan of reorganization;

Increased costs related to the Chapter 11 Cases and related litigation;

A loss of, or a disruption in the materials or services received from, suppliers, contractors or service providers with whom we have commercial relationships;

Potential increased difficulty in retaining and motivating our key employees through the process of reorganization, and potential increased difficulty in attracting new employees;

Significant time and effort required to be spent by our senior management in dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations;

We are also subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in our Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may significantly increase the duration of the Chapter 11 Cases. Because of the risks and uncertainties associated with Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.

We believe it is highly likely that the shares of our existing common stock will be cancelled in our Chapter 11 proceedings.

We have a significant amount of indebtedness that is senior to our existing common stock in our capital structure. As a result, we believe that it is highly likely that the shares of our existing common stock will be cancelled in our Chapter 11 proceedings and will be entitled to a limited recovery, if any. Any trading in shares of our common stock during the pendency of the Chapter 11 proceedings is highly speculative and poses substantial risks to purchasers of shares of our common stock.

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Operating under Bankruptcy Court protection for a long period of time may harm our business.

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the proceedings related to the Chapter 11 proceedings continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating under Bankruptcy Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the proceedings related to the Chapter 11 proceedings continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our businesses successfully and seek to establish alternative commercial relationships.

Furthermore, so long as the Chapter 11 proceedings continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 proceeding. The Chapter 11 cases may also require us to seek debtor-in-possession financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any securities in the debtor could become further devalued or become worthless.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 proceedings.

We may not be able to obtain confirmation of a Chapter 11 plan of reorganization.

On January 26, 2016, the Debtors filed with the Bankruptcy Court a joint plan of Reorganization (the “Plan of Reorganization”) for the resolution of the outstanding claims against and interests in the Debtors and a disclosure statement (the “Disclosure Statement”) related thereto. The Plan of Reorganization, if implemented as proposed by the Debtors, would significantly reduce our outstanding long-term debt and annual interest payments. To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to the Plan of Reorganization, solicit and obtain the requisite acceptances of such Plan of Reorganization and fulfill other statutory conditions for confirmation of such Plan of Reorganization, most of which have not occurred to date. The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding our Plan of Reorganization.

We may not receive the requisite acceptances of constituencies in these Chapter 11 proceedings to confirm or consummate the Plan of Reorganization, an alternative plan of reorganization or another alternative restructuring transaction, including a sale of all or substantially all of our assets, which satisfies the condition of the Bankruptcy Code and is authorized by the Bankruptcy Court. Even if the requisite acceptances of our Plan of Reorganization are received, the Bankruptcy Court may not confirm the Plan of Reorganization. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (e.g., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock).

If a Chapter 11 plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face risks.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes

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in our industry, potential revaluing of our assets due to Chapter 11 proceedings, changes in consumer demand for, and acceptance of, our oil and gas and increasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that the Plan of Reorganization or any other plan of reorganization will achieve our stated goals.

In addition, at the outset of the Chapter 11 proceedings, the Bankruptcy Code gives the debtor the exclusive right to file and solicit acceptance of the Plan of Reorganization and prohibits creditors, equity security holders and others from filing or soliciting a plan for a certain period of time. To date, we have retained the exclusive right to propose the Plan of Reorganization, and, on December 16, 2015, the Bankruptcy Court granted a request to extend our exclusive rights to file and solicit acceptance of the Plan of Reorganization through February 10, 2016, and April 11, 2016, respectively. The Debtors have filed a motion to further extend their exclusive rights to file and solicit acceptance of the Plan of Reorganization through June 9, 2016 and August 9, 2016, respectively. If the Bankruptcy Court terminates that right, however, or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of the Plan of Reorganization in order to achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through the Plan of Reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the Chapter 11 process. Adequate funds may not be available when needed or may not be available on favorable terms.

We have substantial liquidity needs and may be required to seek additional financing. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to replace our proved reserves or to maintain current production levels and generate revenue will be limited.

Our principal sources of liquidity historically have been equity contributions, borrowings under the New Revolving Credit Facility, net cash provided by operating activities, net proceeds from the issuance of the 2017 Notes and proceeds from the Term Loan Facility. Our capital program will require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations remains depressed or decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and proved reserves over time. In addition, drilling activity may be directed by our partners in certain areas and we may have to forfeit acreage if we do not have sufficient capital resources to fund our portion of expenses.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for and consummation of the Chapter 11 proceedings. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to the Chapter 11 Cases until we are able to emerge from Chapter 11. We face additional uncertainty regarding the ability to emerge successfully from Chapter 11 and to obtain adequate liquidity to finance our capital program subsequent to emergence from Chapter 11.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things: (i) our ability to comply with the terms and conditions of the final cash collateral order entered by the Bankruptcy Court on September 16, 2015 in connection with the Chapter 11 proceedings, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction, and (v) the cost, duration and outcome of the Chapter 11 proceedings. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that cash on hand and cash flow from operations is not sufficient to meet our liquidity needs, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

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As a result of the Chapter 11 Cases, our historical financial information may be volatile and not be indicative of our future financial performance.

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments and may significantly impact our consolidated financial statements. As a result, our historical financial performance may not be indicative of our financial performance after the date of the bankruptcy filing.

Our capital structure will likely be significantly altered under any Chapter 11 plan confirmed by the Bankruptcy Court. Under fresh-start accounting rules that may apply to us upon the effective date of a Chapter 11 plan, our assets and liabilities would be adjusted to fair value, which could have a significant impact on our financial statements. Accordingly, if fresh-start accounting rules apply, our financial condition and results of operations following our emergence from Chapter 11 would not be comparable to the financial condition and results of operations reflected in our historical financial statements. In connection with the Chapter 11 Cases and the development of a Chapter 11 plan, it is also possible that additional restructuring and related charges may be identified and recorded in future periods. Such charges could be material to our consolidated financial position, liquidity and results of operations.

We may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Court provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to July 15, 2015 or before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

Transfers of our equity, or issuances of equity in connection with our Chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have net operating loss carryforwards of approximately $1.0 billion as of December 31, 2015. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more shareholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation of a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under section 382 of the Internal Revenue Code, absent an application exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation.

We may experience increased levels of employee attrition as a result of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, we may experience increased levels of employee attrition, and our employees likely will face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incent key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, liquidity and results of operations.

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Oil, natural gas and NGLs prices are volatile. The recent decline in oil, natural gas and NGLs prices has adversely affected our financial position, financial results, cash flow, access to capital and ability to grow.

Our future financial condition, revenues, results of operations and rate of growth depend primarily upon the prices we receive for our oil and natural gas production, and the carrying value of our oil and natural gas properties is dependent upon prevailing prices for oil, natural gas and NGLs. Oil, natural gas and NGLs prices historically have been volatile, and are likely to continue to be volatile in the future, especially given current economic and geopolitical conditions. The New York Mercantile Exchange (“NYMEX”) natural gas prices during ~~2014~~2015 ranged from a high of $83.1532 to a low of $21.7463 per MMbtu and the NYMEX oil prices during ~~2014~~2015 ranged from a high of $~~107~~61.9536 to a low of $5334.4555 per Bbl. Thus far in ~~2015~~2016, commodity prices have continued to be significantly depressed and volatile, with NYMEX natural gas prices ranging from a high of $32.3254 to a low of $21.6249 per MMbtu and the NYMEX oil prices ranging from a high of $5338.5651 to a low of $4326.9319 per Bbl through March 1521, ~~2015~~2016. This low commodity price environment and price volatility also affects the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.

The ~~recent~~speed ~~decreases~~and severity of the decline in oil and gas prices ~~have~~during 2015 and the continued lower prices in the first quarter of 2016 has adversely affected our ~~revenues,~~results ~~net~~of ~~income,~~operations ~~cash~~and ~~flow~~our ~~and~~estimates of our proved oil and natural gas reserves. Continued periods of depressed commodity prices or further price decreases could have a material adverse effect on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. Sustained low commodity prices will further adversely affect our revenues, net income, cash flows, proved reserves and our ability to fund capital expenditures.

Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

the regional, domestic and foreign supply of oil and natural gas;

uncertainty in capital and commodities markets;

the price of foreign imports;

the ability and willingness of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

overall domestic and global economic conditions;

political and economic conditions in oil and natural gas producing countries, including the Middle East, Africa, South America and Russia including the imposition of trade sanctions;

the level of consumer product demand;

weather conditions;

technological advances affecting energy consumption;

domestic and foreign governmental regulations and taxes;

proximity and capacity of oil and natural gas pipelines and other transportation facilities;

the price and availability of competitors’ supplies of oil and natural gas and alternative fuels;

variations between product prices at sales points and applicable index prices; and

the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East.

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~~Due~~We have significant exposure to ~~reduced~~fluctuations in commodity prices ~~and~~since ~~lower~~none ~~operating~~of ~~cash~~our ~~flows,~~estimated ~~coupled~~future ~~with~~production ~~substantial~~is ~~interest~~covered ~~payments,~~by commodity derivatives and we may not be ~~unable~~able to ~~maintain~~enter ~~adequate~~into ~~liquidity~~commodity ~~and~~derivatives covering our ~~ability~~estimated tofuture ~~make~~production ~~interest~~on ~~payments~~favorable interms ~~respect~~or ofat ~~our indebtedness could be adversely affected~~all.

~~Recent~~In ~~declines~~the inpast, ~~commodity~~we ~~prices~~ have ~~caused~~entered ainto ~~reduction~~financial incommodity ~~our~~derivative ~~available~~contracts ~~liquidity~~to ~~and~~mitigate ~~we may not have~~ the ~~ability~~potential tonegative ~~generate~~impact ~~sufficient~~on cash ~~flows~~flow ~~from~~caused ~~operations~~by ~~and,~~changes ~~therefore,~~in ~~sufficient~~oil ~~liquidity~~and tonatural ~~meet~~gas ~~our~~prices. ~~anticipated working capital~~However, ~~debt~~as ~~service~~a ~~and~~result ~~other~~of ~~liquidity~~certain ~~needs.~~events Weof ~~are~~default ~~currently~~under ~~evaluating~~our ~~strategic~~derivative ~~alternatives~~contracts, toall ~~address~~ our ~~liquidity~~derivative ~~issues~~contracts ~~and~~have ~~high~~been ~~debt levels~~terminated. WeSubsequent ~~cannot~~to ~~assure~~the ~~you~~termination ~~that any~~ of these ~~efforts~~derivative ~~will~~contracts, bewe ~~successful~~have ornot ~~will~~entered ~~result~~into ~~in cost reductions or~~ additional ~~cash~~derivative ~~flows~~contracts. orDuring the ~~timing~~Chapter of11 ~~any~~proceedings, ~~such cost reductions or additional cash flows. In order to increase~~ our ~~liquidity~~ability to ~~levels~~enter ~~sufficient~~into tonew ~~meet~~commodity ~~our~~derivatives ~~commitments,~~covering weadditional ~~are~~estimated ~~currently~~future ~~pursuing~~production orwill ~~considering~~be adependent ~~number~~upon ofeither ~~actions~~entering ~~including~~into ~~(i)~~unsecured ~~dispositions~~hedges ofor ~~non-core~~obtaining ~~assets,~~Bankruptcy ~~(ii)~~Court ~~actively~~approval ~~managing~~to ~~our~~enter ~~debt~~into ~~capital~~secured ~~structure~~hedges. ~~through~~As a ~~number~~result, ofwe ~~alternatives,~~may ~~including~~not ~~debt~~be ~~repurchases,~~able ~~debt-~~to ~~for-debt~~enter ~~exchanges,~~into ~~debt-for-equity~~additional ~~exchanges~~commodity ~~and~~derivatives ~~secured~~covering ~~financing,~~our ~~(iii)~~production in- ~~and~~future ~~out-of-court~~periods ~~restructuring,~~on ~~(iv)~~favorable ~~minimizing~~terms ~~our capital expenditures, (v) obtaining waivers~~ or ~~amendments~~at ~~from our lenders, (vi) effectively managing our working capital and (vii) improving our cash flows from operations~~all. ~~There~~If ~~can~~we becannot ~~no assurance that sufficient liquidity can be raised from one~~ or ~~more~~choose ofnot ~~these~~to ~~transactions~~enter orinto ~~that~~commodity ~~these~~derivatives ~~transactions~~in ~~can be consummated within~~ the ~~period~~future, ~~needed~~we tocould ~~meet certain obligations. We cannot assure you that any refinancing or debt or equity restructuring would~~ be ~~possible~~more oraffected ~~that~~by ~~additional~~changes ~~equity~~in orcommodity ~~debt~~prices ~~financing~~than ~~could~~our becompetitors ~~obtained~~who onengage ~~acceptable~~in ~~terms,~~hedging ~~if at all~~arrangements. ~~Furthermore,~~Our weinability ~~cannot assure you that any of our strategies will yield sufficient funds~~ to ~~meet~~hedge ~~our~~the ~~working~~risk ~~capital or other liquidity needs, including for payments~~ of ~~interest~~low ~~and~~commodity ~~principal~~prices ~~on our debt~~ in the future, ~~and~~on ~~any~~favorable ~~such~~terms ~~alternative measures may be unsuccessful~~ or ~~may~~at ~~not~~all, ~~permit~~could ushave toa ~~meet~~material ~~scheduled~~adverse ~~debt~~impact ~~service~~on ~~obligations~~our business, ~~which~~financial ~~could~~condition ~~cause~~and usresults toof ~~default on our obligations~~operations.

~~Our~~If ~~level~~we ofare ~~indebtedness~~able ~~could~~to ~~adversely~~enter ~~affect~~into ~~our~~any ~~ability~~commodity toderivatives, ~~raise~~they ~~additional~~may ~~capital~~limit tothe ~~fund~~benefit ~~our~~we ~~operations,~~would ~~limit~~receive ~~our~~from ~~ability~~increases toin ~~react~~commodity toprices. ~~changes~~These inarrangements ~~our~~would ~~business~~also orexpose ~~our~~us ~~industry~~to ~~and~~risk ~~place~~of usfinancial atlosses ain ~~competitive~~some ~~disadvantage.~~circumstances, including the following:

As· ~~of March 15, 2015, the total outstanding principal amount of~~ our ~~long-term~~production ~~indebtedness~~could ~~was~~be ~~$2.821~~materially ~~billion,~~less ~~consisting~~than ofexpected; indebtedness under the New Revolving Credit Facility, our 9.75% Senior Notes due 2017 (the “2017 Notes”), our 7.25% Senior Notes due 2019 (the “2019 Notes”) and our 7.50% Senior Notes due 2020 (the “2020 Notes” and, together with the 2019 Notes, the “Legacy Forest Notes”), and our $700 million term loan facility (as amended, the “Term Loan Facility”), and, as of March 15, 2015, no extensions of credit are available under the New Revolving Credit Facility after giving effect to $29 million of outstanding letters of credit. or

If· wethe docounterparties ~~not generate sufficient cash flow from operations~~ to ~~satisfy~~the ~~our~~contracts ~~debt~~could ~~obligations,~~fail ~~we may have~~ to ~~undertake~~perform ~~alternative~~their ~~financing~~contractual plans such as refinancing or restructuring our debt, selling assets, reducing or delaying scheduled expansions and capital investments, including planned drilling and completion activity, or seeking to raise additional capitalobligations.

WeIf ~~cannot~~our ~~assure~~actual ~~you~~production ~~that~~and wesales ~~would~~for beany ~~able~~period toare ~~enter~~less ~~into~~than ~~these~~the ~~alternative~~production ~~financing~~covered ~~plans~~by onany ~~commercially~~commodity ~~reasonable~~derivatives ~~terms~~(including orreduced atproduction ~~all.~~due ~~However,~~to ~~any~~operational ~~alternative~~delays) ~~financing~~or ~~plans~~if ~~that~~ we ~~undertake,~~are ifunable ~~necessary, may not allow us~~ to ~~meet~~perform our ~~debt~~exploration ~~obligations.~~and ~~Our~~development ~~inability~~activities toas ~~generate~~planned, ~~sufficient~~we ~~cash~~might ~~flow~~be required to satisfy ~~our~~a ~~debt~~portion of our obligations orunder tothose ~~obtain~~commodity ~~alternative~~derivatives ~~financing~~without ~~could~~the ~~materially~~benefit ~~and~~of ~~adversely~~the ~~affect~~cash ~~our~~flow ~~business,~~from ~~results~~the sale of ~~operations~~that production, ~~financial~~which ~~condition~~may ~~and~~materially ~~business~~impact ~~prospects,~~our asliquidity. ~~well~~Additionally, asif ~~our~~market ~~ability~~prices tofor ~~satisfy~~ our ~~obligations~~production inexceed ~~respect~~collar ofceilings ~~the~~or ~~New~~swap ~~Revolving~~prices, ~~Credit~~we ~~Facility,~~would ~~the~~be ~~2017~~required ~~Notes,~~to ~~the~~make ~~2019~~monthly ~~Notes~~cash payments, ~~the~~which ~~2020~~could ~~Notes~~materially ~~and~~adversely ~~the~~affect ~~Term~~our ~~Loan Facility~~liquidity.

Our debt could have important consequences to you. For example, it could (i) increase our vulnerability to general adverse economic and industry conditions, (ii) limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt, (iii) result in an event of default if we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the New Revolving Credit Facility, the indentures governing the 2017 Notes, the 2019 Notes and the 2020 Notes, the Term Loan Facility or other agreements governing our indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on any of our assets securing such debt, (iv) increase our cost of borrowing, (v) restrict us from making strategic acquisitions or causing us to make non-strategic divestitures, (vi) limit our flexibility in planning for, or reacting to, changes in our

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business or industry in which we operate, placing us at a competitive disadvantage compared to our competitors who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploring and (vii) impair our ability to obtain additional financing in the future.

In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders may have the right to accelerate the maturity of that debt and foreclose upon the collateral securing that debt. Such an occurrence would adversely affect our financial condition.

The borrowing base under the New Revolving Credit Facility may be reduced by our lenders, and we may be required to repay a portion of the borrowings under the New Revolving Credit Facility.

The New Revolving Credit Facility limits the amounts we can borrow up to the lesser of the committed amount and a borrowing base amount, which is subject to redeterminations by the lenders semi-annually each April 1 and October 1, beginning April 1, 2015 or such later time as we may agree upon request of the administrative agent, or as the majority lenders may agree upon our request. We and the lenders comprising two-thirds of the lenders as measured by exposure may each request two unscheduled borrowing base redeterminations during any 12-month period. The borrowing base under the New Revolving Credit Facility could increase or decrease in connection with a redetermination with increases being subject to the approval of all lenders and decreases (and redeterminations maintaining the borrowing base) being subject to the approval of two-thirds of the lenders as measured by exposure. If the prices for oil and natural gas remain weak or deteriorate, if we have a downward revision in estimates of our proved reserves, or if we sell oil and natural gas reserves, our borrowing base may be reduced. The borrowing base is also subject to reduction as a result of certain issuances of additional debt, certain asset sales, cancellation of certain hedging positions or lack of sufficient title information. Based on discussions with the lenders under our New Revolving Credit Facility, we believe that our borrowing base may be decreased significantly in April 2015. Because our New Revolving Credit Facility is fully drawn, any decrease in our borrowing base as a result of the redetermination will result in a deficiency which must be repaid within 30 days or in six monthly installments thereafter, at our election. We may not have the financial resources in the future to make any mandatory deficiency principal prepayments required under our New Revolving Credit Facility, which could result in an event of default. Additionally, failure to make any mandatory deficiency principal payment under our New Revolving Credit Facility may result in a cross-default under our Term Loan Facility and certain of our senior notes.

Our substantial indebtedness, liquidity issues and the potential for restructuring transactions may impact our business, financial condition and operations.

Due to our substantial indebtedness, liquidity issues and the potential for restructuring, there is risk that, among other things:

· third parties’ confidence in our ability to explore and produce oil and natural gas could erode, which could impact our ability to execute on our business strategy;

· it may become more difficult to retain, attract or replace key employees;

· employees could be distracted from performance of their duties or more easily attracted to other career opportunities; and

· our suppliers, hedge counterparties, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.

The occurrence of certain of these events has already negatively affected our business and may have a material adverse effect on our business, results of operations and financial condition.

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The trustee for our 2019 Notes has asserted certain claims against us related to the Combination.

On February 26, 2015, we were served with a complaint (the “Complaint”) concerning the indenture that governs our 2019 Notes that generally alleges that certain events of default had occurred with respect to the 2019 Notes due to the Combination. Specifically, the Complaint alleges that the Combination constituted a change of control under the indenture which requires us to offer to purchase the 2019 Notes at 101% of the outstanding principal, plus accrued and outstanding interest of the notes. We also received a notice of default and acceleration from the Trustee with respect to the 2019 Notes containing similar allegations. ~~While~~We we believe these allegations against us are without merit, ifand weintend ~~are~~to ~~not~~vigorously ~~successful~~defend inagainst ~~our~~such ~~defense~~claims ofand ~~the~~pursue ~~Complaint,~~any weand ~~may~~all bedefenses ~~required~~available. toWe ~~purchase~~are separately evaluating potential claims that we may assert against the ~~holders~~trustee offor the 2019 Notes, for any and all losses we may ~~not~~suffer ~~have~~as ~~sufficient~~a ~~liquidity~~result toof ~~fund~~the ~~such~~complaint ~~purchase~~or notice. IfWe ~~the~~can ~~court~~provide ~~determines~~no weguarantee ~~are~~that inany ~~default~~such ~~under~~claims, if brought by us, will be successful or, if successful, that the ~~indenture~~responsible ~~governing~~parties will have the ~~2019~~financial ~~Notes,~~resources ato ~~cross~~address ~~default~~any ~~and~~such ~~acceleration~~claims. ~~under~~Furthermore, ~~our~~additional ~~other~~claims, ~~debt~~lawsuits, ~~agreements~~or proceedings may ~~result,~~be filed or commenced arising out of the indentures to which ~~would~~we ~~have~~are a ~~material~~party ~~adverse~~and ~~effect~~with onrespect ~~our~~to ~~financial~~the ~~condition~~Combination.

~~Our~~As ~~debt~~a ~~ratings~~result ~~were~~of ~~recently~~the ~~downgraded. This~~pending ~~recent~~bankruptcy ~~downgrade could restrict our access to~~proceedings, ~~and~~this ~~negatively~~matter ~~impact~~is ~~the~~currently ~~terms of, current or future financings or trade credit~~stayed.

Our ~~ability~~common tostock ~~obtain financings, hedging arrangements and trade credit and the terms of any financings, hedging arrangements or trade credit~~ is, inno ~~part,~~longer ~~dependent~~listed on the credit ratings assigned to our debt by independent credit rating agencies. Our debt ratings were recently downgraded. Additionally, we cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a ~~rating~~national ~~will~~securities beexchange ~~further~~and ~~lowered~~is orquoted ~~withdrawn~~only ~~entirely by a rating agency if,~~ in ~~its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near~~over-~~term and long~~the-~~term~~counter ~~production growth opportunities~~markets, ~~liquidity,~~which ~~asset~~carries ~~quality,~~substantial ~~cost~~risks ~~structure, product mix~~ and ~~commodity~~could ~~pricing~~continue ~~levels.~~to ~~Our~~negatively ~~recent ratings downgrade and any future downgrade could adversely~~ impact our ~~ability~~stock ~~to access financings~~price, ~~hedging~~volatility ~~arrangements or trade credit, increase our borrowing costs~~ and ~~potentially require us to post letters of credit for certain obligations~~liquidity.

~~Restrictions~~Upon inthe ~~our~~closing ~~existing~~of ~~and~~the ~~future~~Combination, ~~debt~~the ~~agreements~~New ~~could~~York ~~limit~~Stock Exchange (the “NYSE”) suspended trading in our ~~growth~~common stock and ~~our~~commenced ~~ability~~delisting proceedings due to ~~respond~~our failure to ~~changing~~meet ~~conditions~~the initial listing standards under Rule 102. 01 of the NYSE Listed Company Manual. On December 17, 2014, our common stock began trading over the counter on the OTCQB Marketplace (the “OTCQB”) under the ticker symbol “FSTO” and later under the ticker symbol

The New Revolving Credit Facility, the Term Loan Facility and the indentures governing the 2017 Notes, the 2019 Notes and the 2020 Notes contain a number of significant covenants in addition to covenants restricting the incurrence of certain kinds of additional debt. For example, the New Revolving Credit Facility requires us, among other things, to maintain a financial maintenance ratio in the form of a first lien secured leverage ratio not to exceed 3.0 to 1.0 commencing with the period ending March 31, 2015. These restrictions also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing the 2017 Notes, the 2019 Notes and the 2020 Notes, our Term Loan Facility and our New Revolving Credit Facility impose on us. In addition, complying with these covenants may also cause us to take actions that are not favorable to holders of our common stock and may make it more difficult for us to successfully execute our business strategy and compete against companies that are not subject to such restrictions.37

The New Revolving Credit Facility, the Term Loan Facility and the indentures governing the 2017 Notes, the 2019 Notes and the 2020 Notes contain certain other covenants, including restrictions on our ability to create or incur liens, make dividends and other restricted payments, sell assets, engage in transactions with affiliates or merge or consolidate, in each case subject to certain carve-outs and exceptions. For more information regarding the existing debt agreements, please see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

A breach of any covenant in our New Revolving Credit Facility, the Term Loan Facility, the indentures governing the 2017 Notes, the 2019 Notes and the 2020 Notes or other agreements governing any other indebtedness that we may incur from time to time would result in a default under such agreement after any applicable grace periods. The report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2014 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. As a result, we are in default under our New Revolving Credit Facility and Term Loan Facility. A default, if not waived, could result in acceleration of the debt outstanding under the agreement and a default

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~~with~~“SOGCQ.” ~~respect to~~Additionally, ~~and~~as ana ~~acceleration~~result of, the ~~debt~~filing ~~outstanding~~of ~~under~~the ~~other~~Bankruptcy ~~debt~~Petitions, ~~agreements.~~the ~~The~~Company’s ~~accelerated~~common ~~debt~~stock ~~would~~can ~~become~~no ~~immediately~~longer ~~due and payable. If that occurs, we may not~~ be ~~able~~traded toon ~~make all of~~ the ~~required~~OTCQB ~~payments~~Marketplace orand ~~borrow~~is ~~sufficient~~now ~~funds~~trading ~~to refinance such debt. Even if new financing were available at that time, it may not be~~ on ~~terms~~the ~~that~~OTC ~~are~~Pink ~~acceptable to us~~Marketplace. IfWe wecontinue ~~are unable~~ to ~~repay~~file ~~the~~periodic ~~accelerated~~reports ~~amounts,~~with ~~our creditors could proceed against~~ the ~~collateral~~SEC ~~granted to them to secure such debt. If our debt is~~ in ~~default~~accordance ~~for~~with ~~any~~the ~~reason,~~requirements ~~our~~of ~~business,~~Section ~~financial~~12 ~~condition~~(g) ~~and results~~ of ~~operations~~the ~~could~~Exchange ~~be materially and adversely affected~~Act.

WeOur ~~may~~delisting befrom ~~unable~~the toNYSE ~~maintain~~and ~~compliance~~commencement ~~with~~of ~~certain~~trading ~~financial~~on ~~ratio~~the ~~covenants~~OTC ofPink ~~our~~Marketplace ~~outstanding~~has ~~indebtedness~~resulted ~~which~~and ~~could~~may continue to result in ana ~~event~~reduction ofin ~~default~~some ~~that,~~or ifall ~~not~~of ~~cured~~the ~~or waived~~following, ~~would~~each of which could have a material adverse effect on our ~~business, financial condition and results of operations.~~stockholders:

Our New Revolving Credit Facility requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. For example, the New Revolving Credit Facility requires us, among other things, to maintain a financial maintenance ratio in the form of a first lien secured leverage ratio not to exceed 3.0 to 1.0 commencing with the period ending March 31, 2015. As of December 31, 2014, we were in compliance with our financial covenants; however, we cannot guarantee that we will be able to comply with such terms at all times in the future. Any failure to comply with the conditions and covenants in our New Revolving Credit Facility that is not waived by our lenders or otherwise cured could lead to a termination of our New Revolving Credit Facility, acceleration of all amounts due under our New Revolving Credit Facility, or trigger cross-default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our indebtedness impose on us.

We failed to meet applicable New York Stock Exchange requirements following the Combination and as a result our stock was delisted from the New York Stock Exchange, which could adversely affect the market liquidity of our common stock and harm our businesses.

Upon the closing of the Combination, the New York Stock Exchange (the “NYSE”) suspended trading in our common stock and commenced delisting proceedings due to our failure to meet the initial listing standards under Rule 102.01 of the NYSE Listed Company Manual. On December 17, 2014, our common stock began trading over the counter on the OTCQB Marketplace (the “OTCQB”) under the ticker symbol “FSTO” and is now trading under the ticker symbol “SOGC.” We continue to file periodic reports with the SEC in accordance with the requirements of Section 12 (g) of the Exchange Act.

Our delisting from the NYSE and commencement of trading on the OTCQB has resulted and may continue to result in a reduction in some or all of the following, each of which could have a material adverse effect on our stockholders:

the liquidity of our common stock;

the market price of shares of our common stock;

our ability to obtain financing for the continuation of our operations;

the number of institutional and other investors that will consider investing in shares of our common stock;

the number of market makers in shares of our common stock;

the availability of information concerning the trading prices and volume of shares of our common stock; and

the number of broker-dealers willing to execute trades in shares of our common stock.

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We may encounter difficulties in integrating Forest’s business with our business and realizing the anticipated benefits of the Combination.

The Combination involved the combination of two companies which previously operated as independent companies. We have had to devote management attention and resources to integrating our business practices and operations. Potential difficulties we may encounter in the integration process include the following:

· the inability to successfully integrate the respective businesses of Forest and Sabine in a manner that permits us to achieve the cost savings and operating synergies anticipated to result from the Combination, which could result in the anticipated benefits of the Combination not being realized partly or wholly in the time frame currently anticipated or at all;

· lost sales and customers as a result of certain customers of either or both of the two companies deciding not to do business with us, or deciding to decrease their amount of business in order to reduce their reliance on a single company;

· integrating personnel from the two companies while maintaining focus on providing consistent, high quality products and services;

· preserving significant business relationships;

· consolidating corporate and administrative functions;

· potential unknown liabilities and unforeseen increased expenses, delays or regulatory conditions associated with the Combination;

· conforming standards, controls, procedures and policies, business cultures and compensation structures between Forest and Sabine O&G;

· retaining key employees;

· changes in estimates or errors impacting purchase accounting and the financial statements; and

· performance shortfalls as a result of the diversion of management’s attention caused by completing the merger and integrating the companies’ operations.

We expect to incur substantial expenses related to the integration of Forest’s business with our business.

We expect to incur substantial expenses in connection with integrating the respective businesses, policies, procedures, operations, technologies and systems of Forest and Sabine. There are a large number of systems that must be integrated, including information management, purchasing, accounting and finance, sales, billing, payroll and benefits, fixed asset and lease administration and regulatory compliance. There are a number of factors beyond our control that could affect the total amount or the timing of all of the expected integration expenses. These expenses could, particularly in the near term, reduce the savings that we expect to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings related to the integration of the businesses following the completion of the merger. These integration expenses may result in us taking significant charges against earnings now that the Combination has been completed.

Business issues historically faced by one company may be imputed to the operations of the other company.

To the extent that either we or Forest had or were perceived by customers to have had operational challenges, those challenges may raise concerns by customers of the other company now that the Combination has been completed, which may limit or impede our future ability to obtain additional work from those customers.

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Estimates of reserves and future net cash flows are not precise. The actual quantities of our reserves and future net cash flows may prove to be lower than estimated.

Numerous uncertainties exist in estimating quantities of reserves and future net cash flows therefrom. Our estimates of reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate. Petroleum engineering is a subjective process of estimating accumulations of oil or natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:

historical production from the area compared with production from other producing areas;

the quality, quantity and interpretation of available relevant data;

the assumed effects of regulations by governmental agencies;

assumptions concerning future commodity prices; and

assumptions concerning future operating costs, severance, ad valorem and excise taxes, development costs, and workover and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items, or other items not identified below, may differ materially from those assumed in estimating reserves:

the quantities of oil and natural gas that are ultimately recovered;

the production and operating costs incurred;

the amount and timing of future development expenditures; and

future commodity prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.

The prices used in calculating our estimated proved reserves and the estimated discounted future net cash flows from proved reserves are, in accordance with SEC requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding 12 months. For the 12-months ended December 31, 2014, average prices used to calculate our estimated proved reserves and estimated discounted future net cash flows from proved reserves were $94.99 per Bbl for crude oil and $4.35 per MMbtu for natural gas. Commodity prices declined significantly in the fourth quarter of 2014 and if such prices do not increase significantly, it could have a negative impact on our future calculations of estimated proved reserves and the estimated discounted future net cash flows from proved reserves will be significantly lower than as of December 31, 2014. This could result in our having to remove non-economic reserves from our proved reserves in future periods. 38

~~Holding~~Table ~~all other factors constant, if March SEC pricing~~ of $82.72 per Bbl for crude oil and $3.88 per Mcf for natural gas is used in our year-end reserve estimates, our estimated discounted future net cash flows from proved reserves at December 31, 2014 would decrease by approximately $363 million, or 21%.Contents

The prices used in calculating our estimated proved reserves and the estimated discounted future net cash flows from proved reserves are, in accordance with SEC requirements, calculated by determining the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. December 31, 2015, average prices used to calculate our estimated proved reserves and estimated discounted future net cash flows from proved reserves were $50.28 per Bbl for crude oil and $2.58 per MMbtu for natural gas. Commodity prices declined significantly throughout 2015 and if such prices do not increase significantly, it could have a negative impact on our future calculations of estimated proved reserves and the estimated discounted future net cash flows from proved reserves will be significantly lower than as of December 31, 2015. This could result in our having to remove non-economic reserves from our proved reserves in future periods.

Holding all other factors constant, if SEC pricing as of March 2016 of $46.26 per Bbl for crude oil and $2.39 per Mcf for natural gas is used in our year-end reserve estimates, our estimated discounted future net cash flows from proved reserves at December 31, 2015 would decrease by approximately $69 million, or 14%.

Actual future net cash flows also will be affected by other factors, including:

the amount and timing of actual production;

levels of future capital spending;

increases or decreases in the supply of or demand for oil and natural gas; and

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changes in governmental regulations or taxation.

Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor mandated by the rules and regulations of the SEC to be used in calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Therefore, the estimates of discounted future net cash flows included in this Annual Report on Form 10-K should not be construed as accurate estimates of the current market value of our proved reserves.

Our business requires substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves and production.

The oil and natural gas industry is capital intensive. During the years ended December 31, 2014 and 2013, we incurred approximately $562 million and $431 million in capital expenditures (excluding acquisitions and divestitures), respectively, and our full year capital expenditure forecast for 2015 is expected to total between approximately $230 million to $275 million (excluding acquisitions and divestitures). Additionally, prior to the completion of the Combination on December 16, 2014, Forest had incurred approximately $245 million in capital expenditures for property exploration, development and leasehold acquisitions in 2014 and $350 million during the year ended December 31, 2013.

We expect to continue to make substantial capital expenditures for the acquisition, development and production of oil and natural gas reserves. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive development.

To date, we have financed our capital expenditures primarily with capital contributions by our equity sponsors (for periods prior to the Combination), proceeds from bank borrowings, cash generated by operations and net proceeds from the sale of the 2017 Notes. We intend to finance future capital expenditures through, among other things, cash on hand, cash flow from operations, borrowings under the New Revolving Credit Facility to the extent we repay current borrowings, the issuance of debt or equity securities and the sale of assets. Our cash flow from operations and access to capital are subject to a number of variables, including:

· our proved reserves;

· the level of oil and natural gas we are able to produce from existing wells;

· the prices at which we are able to sell oil, natural gas and NGLs;

· the costs of developing and producing our oil and natural gas reserves;

· our ability to acquire, locate and produce new reserves;

· global credit and securities markets; and

· the ability and willingness of lenders and investors to provide capital and the cost of that capital.

If our cash flows or the borrowing base under the New Revolving Credit Facility decrease as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may be required to seek additional debt or equity financing to fund our operations and capital expenditures. Our Term Loan Facility, the New Revolving Credit Facility and the indentures governing the 2017 Notes, the 2019 Notes and the 2020 Notes restrict our ability to obtain certain kinds of new financing, and we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If we are unable to secure sufficient capital to meet our capital requirements, we may be required to curtail operations, which could lead to a possible loss of properties and an adverse impact on our oil and natural gas reserves, production, revenues and results of operations.

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Drilling for and producing oil and natural gas are risky activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling for oil and natural gas can be unprofitable, not only from dry holes, but from productive wells that do not produce sufficient revenues to return a profit. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on our evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical or less economic than forecasted. Further, many factors may curtail, delay or cancel drilling, including the following:

delays imposed by or resulting from compliance with regulatory and contractual requirements;

pressure or irregularities in geological formations;

shortages of or delays in obtaining equipment and qualified personnel or other services or in obtaining water for hydraulic fracturing activities;

equipment failures or accidents;

adverse weather conditions;

reductions in oil, natural gas and NGL prices;

surface access restrictions;

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loss of title or other title related issues;

pipe or cement failures or casing collapses;

compliance with environmental and other government requirements;

environmental hazards, such as natural gas leaks, groundwater contamination resulting from improper well casing and cementing, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface or subsurface environment;

fires, blowouts, surface craterings and explosions;

uncontrollable flows of oils, natural gas, formation water, or well fluids;

oil, natural gas or NGLs gathering, transportation and processing availability restrictions or limitations; and

limitations in the market for oil and natural gas.

The occurrence of certain of these events could also affect third parties, including persons living near our operations, our employees and employees of our contractors, leading to injuries or death or property damage. As a result, we face the possibility of liabilities from these events that could adversely affect our business, financial condition and results of operations.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

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wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and results of operations are highly dependent upon our success in efficiently developing and exploiting our current properties and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

Drilling locations that we have identified may not yield oil, natural gas or NGLs in commercially viable quantities.

Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. It is impossible to predict in advance of drilling and testing whether any particular location will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil, natural gas or NGLs exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our identified drilling location inventories are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of factors, some of which are beyond our control, including the availability and cost of capital, weather conditions, including seasonal restrictions, regulatory approvals, oil, natural gas and NGLs prices, costs and drilling results. As a consequence, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Therefore, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

As a result of the uncertainties described above, we may be unable to drill many of our potential resource play drilling locations. In addition, depending on the timing and concentration of the development of the non-proved locations, we would be required to generate or raise significant capital to develop all of our potential drilling locations should we elect to do so. Estimated reserves related to our properties as of December 31, 2014 assumed that capital costs of approximately $1.073 billion would be required over a period of approximately five years in order to develop our proved undeveloped reserves. We may not be able to raise or generate the capital required to drill or develop these additional non-proved locations. Any drilling activities we are able to conduct on these potential locations may not be successful or allow us to add additional proved reserves to our overall proved reserves or may result in a downward revision of estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

We have incurred losses from operations for various periods since our inception and may do so in the future.

Our development of and participation in an increasingly larger number of prospects has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves. As a result, we may not be able to sustain profitability or positive cash flows from operating activities in the future.

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including the availability and cost of capital, weather conditions, including seasonal restrictions, regulatory approvals, oil, natural gas and NGLs prices, costs and drilling results. As a consequence, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Therefore, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

As a result of the uncertainties described above, we may be unable to drill many of our potential resource play drilling locations. In addition, depending on the timing and concentration of the development of the non-proved locations, we would be required to generate or raise significant capital to develop all of our potential drilling locations should we elect to do so. Estimated reserves related to our properties as of December 31, 2015 assumed that capital costs of approximately $109.7 million would be required over a period of approximately five years in order to develop our proved undeveloped reserves. We may not be able to raise or generate the capital required to drill or develop these additional non-proved locations. Any drilling activities we are able to conduct on these potential locations may not be successful or allow us to add additional proved reserves to our overall proved reserves or may result in a downward revision of estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

We have incurred losses from operations for various periods since our inception and may do so in the future.

We cannot be certain that the insurance coverage we maintain will be adequate to cover all losses that may be sustained in connection with our oil and natural gas producing activities.

We maintain an insurance program designed to provide coverage for our property and casualty exposures. Our risk management program provides coverage types, limits and deductibles commensurate with companies of comparable size and with similar risk profiles. ~~Our insurance program includes the following coverage:~~

· As ~~Commercial~~is ~~general~~common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a material adverse effect on our financial position and results of operations. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover every claim made against us in the future. As hydraulic fracturing is a key component of our operational strategy, we maintain claims made pollution liability ~~covering:~~insurance, which provides coverage for long-term gradual seepage pollution events. A loss in connection with our oil and natural gas operations could have a material adverse effect on our financial position and results of operations to the extent that the insurance coverage provided under our policies is inadequate to cover any such loss.

o bodily injury and property damage;

o advertising injury and personal injury;

o production and completed operations;

o medical expenses; and

o underground resources and equipment property damage;

· Business automobile covering:

o liability on all autos, including owned, hired and non-owned vehicles;

· Claims made pollution liability covering:

o sudden and accidental and gradual seepage pollution events; and

o on-site cleanup;

· Workers’ compensation and employer’s liability covering statutory coverage in all states in which we operate;

· Umbrella and excess liability;

· Property and equipment;

· Crime; and

· Control of covering:

o cost of well control;

o pollution clean-up and debris removal;

o restoration and redrill; and

o care, custody and control.

As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because we believe the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations. There can be no assurance that the insurance coverage that we maintain will be sufficient to cover every claim made against us in the future. As hydraulic fracturing is a key component of our operational strategy, we maintain claims made pollution liability insurance, which provides coverage for long-term gradual seepage pollution events. A loss in connection with our oil and natural gas operations could have a material adverse effect on our financial position and results of operations to the extent that the insurance coverage provided under our policies is inadequate to cover any such loss.

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Lower oil, natural gas, and natural gas liquids prices and other factors have resulted, and in the future may result, in ceiling test write-downs.

We use the full cost method of accounting to report our oil and natural gas activities. Under this method, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and natural gas properties may not exceed a ceiling limit, which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a ceiling test writedown. Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down does not impact cash flows from operating activities, but it does reduce our shareholders’ equity.

The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil, natural gas, and natural gas liquids prices are low. In addition, write-downs may occur if we experience downward adjustments to our estimated proved reserves, or if estimated future development or operating costs increase. ~~For example, during 2012, 2013 and 2014 we incurred a ceiling test write-down of $641.8 million, zero and $247.7 million, respectively.~~

Additional write-downs may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, and natural gas liquids prices used in the calculation of the present value of future net revenue from estimated production of estimated proved reserves decline compared to prices used as of December 31, 2014, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any. For example, as of December 31, 2014, the unweighted average of the historical first day of the month pricing for the previous twelve months of oil and natural gas were $94.99 per Bbl and $4.35 per MMbtu, respectively, compared to $82.72 per Bbl and $3.88 per MMbtu for oil and natural gas, respectively, in March 2015. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were decreased by $12.27 per Bbl for crude oil and $0.47 per Mcf for natural gas, thereby approximating the pricing environment existing in March 2015, our estimated discounted future cash flows from proved reserves at December 31, 2014 would decrease by approximately $363 million, or 21%.41

In connection with certain audits and reviews of Sabine O&G’s financial statements in prior years, our independent registered public accounting firm identified and reported misstatements to management. Certain of such misstatements were deemed to be the result of internal control deficiencies that constituted material weaknesses in our internal control over financial reporting. In addition, Forest’s management concluded that certain material weaknesses existed in its internal control over financial reporting as of December 31, 2013. If one or more material weaknesses recur or if we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Sabine O&G restated its financial statements for the years ended December 31, 2012 and 2011 with respect to the accounting and disclosures for certain derivative financial transactions in both the 2012 and 2011 periods and with respect to reversing a bargain purchase gain recognized for the acquisition of certain oil and natural gas properties in 2012. Sabine O&G concluded that these restatements constituted material weaknesses in internal control over financial reporting. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

Additionally, Forest previouslyconcluded that material weaknesses existed in its internal control over financial reporting as of December 31, 2013 with respect to certain information technology general controls, controls over division of interests and controls associated with inputs to the ceiling limitation test. Our management is in the process of reviewing the remediation of controls over these processes and has not reached a conclusion regarding the effectiveness of such remediation. We anticipate complying with Section 404 certification and attestation requirements for the year ended December 31, 2015.

Our efforts to develop and maintain internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future. Further, our remediation efforts may not

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~~enable~~For usexample, toduring ~~remedy~~2013, or2014 ~~avoid~~and ~~material~~2015 ~~weaknesses~~we orincurred ~~significant~~a ~~deficiencies~~ceiling intest ~~the~~write-down ~~future.~~of ~~Any~~zero, ~~failure~~$247.7 tomillion ~~remediate deficiencies~~ and to$1.6 ~~develop or maintain effective controls~~billion, or any difficulties encountered in our implementation or improvement of our internal control over financial reporting could result in material misstatements that are not prevented or detected on a timely basisrespectively.

Additional write-downs may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, and natural gas liquids prices used in the calculation of the present value of future net revenue from estimated production of estimated proved reserves decline compared to prices used as of December 31, 2015, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if any. For example, the unweighted average of the historical first day of the month pricing for the previous twelve months of oil and natural gas as of December 31, 2015, were $50.28 per Bbl and $2.58 per MMbtu, respectively, compared to $46.26 per Bbl and $2.39 per MMbtu for oil and natural gas, respectively, as of March 2016. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were decreased to these prices as of March 2016, our estimated discounted future cash flows from proved reserves at December 31, 2015 would decrease by approximately $69 million, or 14%.

There are inherent limitations in all internal control over financial reporting systems, and misstatements due to error or fraud may occur and not be detected.

While we have taken actions designed to address compliance with the requirements of the Sarbanes-Oxley Act of 2002, as amended, and the rules and regulations thereunder, there are inherent limitations in our ability to comply with these requirements. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal control over financial reporting and disclosure controls and procedures will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Poor general economic, business or industry conditions, including commodity prices, may adversely affect our ability to refinance our debt, results of operations, liquidity and financial condition.

~~During the last several years~~Oil, economic uncertainty for the global economy has arisen due to concerns relating to the global financial crisis, including the mortgage and real estate markets in the United States, high levels of unemployment in the United States, increased levels of sovereign and individual debt, energy costs, geopolitical issues and the availability and cost of credit. In addition, oil, natural gas and NGL prices historically and recently have been volatile, and are likely to continue to be volatile in the future, and as such economic uncertainty for the oil and gas industry exists.

Concerns about global economic conditions have had a significant adverse impact on global financial markets and commodity prices and the volatility of oil and gas prices ~~may~~ have had a significant effect on the oil and gas industry. If the economic recovery in the United States or abroad slows or is not sustained, demand for petroleum products could diminish or stagnate, which could affect the price at which we can sell our production and affect our vendors’, suppliers’ and customers’ ability to continue operations. Similarly, if the price of oil and gas does not increase, it may affect our production plans and profitability and affect our vendors’, suppliers’ and customers’ ability to continue operations.

Further, our ability to access the capital markets or borrow money may be restricted or more expensive at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund operations and capital expenditures in the future or refinance our debt as it becomes current and matures. Economic circumstances, including commodity prices, could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments. Also, market conditions could have an impact on commodities derivatives transactions if our counterparties are unable to perform their obligations or seek bankruptcy protection. The ultimate outcome and impact of current economic conditions cannot be predicted and may have a material adverse effect on our future results of operations, liquidity and financial condition.

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obligations or seek bankruptcy protection. The ultimate outcome and impact of current economic conditions cannot be predicted and may have a material adverse effect on our future results of operations, liquidity and financial condition.

The recent decreases in oil and gas prices have adversely affected our revenues, net income, cash flow and proved reserves. Continued price decreases could have a material adverse effect on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. Sustained decreases in oil and gas prices will further adversely affect our revenues, net income, cash flows, proved reserves and our ability to fund capital expenditures.

The results of our horizontal drilling activities are subject to drilling and completion technique risks, and actual drilling results may not meet our expectations for reserves or production. As a result, we may incur material impairment of the carrying value of our unevaluated properties, and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

During the year ended December 31, ~~2014 in the Eagle Ford Shale in South Texas and the Granite Wash in North Texas~~ 2015, we ~~drilled 36 gross (27.0 net) and 19 gross (12.3 net) wells and~~ completed 4237 gross (3231.29 net) ~~and 18 gross (11.2 net)~~ wells~~, respectively, and, prior to the Combination, Forest drilled a total of 18 gross (16~~.3 ~~net) wells relating to their properties during the same year.~~ Risks that we face while horizontally drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our horizontal wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. Ultimately, the success of these horizontal drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our horizontal drilling results are less than anticipated, the return on our investment in these areas may not be as attractive as we anticipate. The carrying value of our unevaluated properties could become impaired, which would increase our depletion rate per Mcfe if there were no corresponding additions to recoverable reserves, and the value of our undeveloped acreage could decline in the future.

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increase our depletion rate per Mcfe if there were no corresponding additions to recoverable reserves, and the value of our undeveloped acreage could decline in the future.

Our business depends on transportation by truck for our oil and condensate production, and our natural gas production depends on transportation facilities that are owned by third parties.

We transport a significant portion of our oil and condensate production by truck, which is more expensive and less efficient than transportation via pipeline, and can be less reliable than transportation via pipeline in circumstances when availability of trucks is constrained. Our natural gas production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas. The disruption of third-party facilities due to maintenance or weather could negatively affect our ability to market and deliver our products. We have no control over when or if such facilities are restored or what prices will be charged in such situations. A total shut-in of production could materially affect us due to a lack of cash flows, and if a substantial portion of the production is hedged at lower than market prices, those financial hedges would have to be paid from borrowings absent sufficient cash flows.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local landowners for use in our operations. Over the past several years, areas where we operate have experienced severe drought conditions, and it is possible that such conditions could persist in the future. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations and cash flows.

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We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Companies that explore for and develop, produce and sell oil and natural gas in the United States are subject to extensive federal, state and local laws and regulations, including complex tax, environmental, occupational, health and safety laws and the corresponding regulations, and are required to obtain various permits and approvals from federal, state and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. We may be required to make large expenditures to comply with such governmental regulations. Matters subject to regulation may include:

water use, discharge and disposal permits for drilling operations;

drilling bonds;

drilling permits;

reports concerning operations;

air quality, noise levels and related permits;

spacing of wells;

rights-of-way and easements;

unitization and pooling of properties;

gathering, transportation and marketing of oil and natural gas;

taxation;

operations in wilderness, wetlands and other protected areas;

use, storage, handling and release of hazardous substances; and

waste transport and disposal permits and requirements.

Failure to comply with these laws may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, these laws or the enforcement thereof could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations.

Numerous governmental agencies, such as the EPA, issue regulations to implement and enforce environmental, health and safety laws and regulations, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations, imposition of investigatory or remedial obligations, or subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages, as well as injunctions limiting or prohibiting our activities. Under certain environmental, occupational, health and safety laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Some laws and regulations may impose strict as well as joint and several liability for environmental contamination, which could subject us to liability for the conduct of others or for our own actions even if they were in compliance with all applicable laws at the time such actions were taken. Under such laws, we could be held liable for environmental contamination at our currently or formerly owned, leased or operated properties as well as third-party locations (such as treatment or disposal facilities). Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. In addition, in some cases private individuals can bring causes of action in court regarding compliance with environmental laws and

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·regulations. ~~taxation;~~Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations.

· waste transport and disposal permits and requirements.

Failure to comply with these laws may result in the suspension or termination of our operations and subject us to liabilities under administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, these laws or the enforcement thereof could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations.

Numerous governmental agencies, such as the EPA, issue regulations to implement and enforce environmental, health and safety laws and regulations, which often require difficult and costly compliance measures. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, including the assessment of natural resource damages, as well injunctions limiting or prohibiting our activities. Under certain environmental, occupational, health and safety laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Some laws and regulations may impose strict as well as joint and several liability for environmental contamination, which could subject us to liability for the conduct of others or for our own actions that were in compliance with all applicable laws at the time such actions were taken. Under such laws, we could be held liable for environmental contamination at our currently or formerly owned, leased or operated properties as well as third-party locations (such as treatment or disposal facilities). Environmental and other governmental laws and regulations also increase the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. In addition, in some cases private individuals can bring causes of action in court regarding compliance with environmental laws and regulations. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect on our financial condition and results of operations.

In addition, our activities are subject to the regulation by oil and natural gas-producing states relating to conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of oil and natural gas we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with excessive conditions or costs could have a material adverse effect on our ability to explore on or develop our properties. Many factors, including the protection of certain species as well as public opposition, can materially affect the ability to secure construction or operation permits. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration, development and production activities that could have an adverse impact on our ability to develop and produce our reserves. Once operational, enforcement measures can include significant civil penalties for regulatory violations. Under appropriate circumstances, an administrative agency can request a cease and desist order to terminate operations.

Furthermore, the oil and natural gas regulatory environment could change in ways that might substantially increase the financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability. Furthermore, we may be put at a competitive disadvantage to larger companies in our industry that can spread these additional costs over a greater number of wells and larger operating area.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an essential and common practice in the oil and natural gas industry used to stimulate production of oil and/or natural gas from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the well bore. We routinely apply hydraulic-fracturing techniques in our drilling and completion programs. While hydraulic fracturing has historically been regulated by state oil and natural gas commissions, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities under the SDWA involving the use of diesel fuels and published revised permitting guidance in February 2014 addressing the performance of such activities. The EPA has also issued final CAA regulations in 2012 and proposed additional CAA regulations in August 2015 governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; published an advance notice of proposed rulemaking under the Toxic Substances Control Act seeking stakeholder input on development of a requirement regarding disclosure of information on chemical substances and mixtures used in hydraulic fracturing in May 2014 (the public comment period on the EPA’s advance notice ended in September 2014, and a final notice of proposed rulemaking is expected in 2016); and proposed in April 2015 effluent limit guidelines that saltwater from shale resource extraction operations must meet before discharging to publicly owned wastewater treatment plants (the final rule is expected to be issued in March 2016). Additionally, in March 2015, the federal Bureau of Land Management published a final rule that establishes new or more stringent standards for hydraulic fracturing on federal and Indian lands, including public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. In addition to rulemakings, increased scrutiny of the oil and natural gas industry may occur as a result of the EPA’s FY2014-2016 National Enforcement Initiative, "Ensuring Energy Extraction Activities Comply with Environmental Laws," through which the EPA will address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment; starting October 1, 2016, this initiative will continue for three more fiscal years.

In addition, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, including the disclosure of the chemicals used in the hydraulic fracturing process.

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~~Federal~~Certain states, including Texas, have adopted, and ~~state~~other ~~legislation~~states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and ~~regulatory~~well ~~initiatives~~construction ~~relating~~requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. For example, since 2012, the RRC has required the disclosure of chemical ingredients and water volumes used in the hydraulic fracturing ~~could~~treatment ~~result~~of oil and gas wells. In addition, in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Further, in October 2014, the RRC adopted disposal well rule amendments designed to address disposal well operations in areas of historical or future seismic activity. Texas is one of eight states identified in a 2015 U.S. Geological Survey report as having areas of increased ~~costs~~rates of induced seismicity that could be attributed to fluid injection or oil and ~~additional~~gas ~~operating~~extraction. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

~~Hydraulic~~There ~~fracturing~~are isalso ancertain ~~essential~~governmental ~~and~~reviews ~~common~~either ~~practice~~underway inor ~~the~~being ~~oil~~proposed ~~and~~that ~~natural~~focus ~~gas~~on ~~industry~~environmental ~~used~~aspects ~~to stimulate production~~ of ~~oil~~hydraulic ~~and/or~~fracturing ~~natural gas from dense subsurface rock formations~~practices. ~~Hydraulic~~The ~~fracturing~~White ~~involves~~House ~~using~~Council ~~water,~~on ~~sand,~~Environmental ~~and~~Quality ~~certain~~is ~~chemicals~~coordinating toan ~~fracture the hydrocarbon~~administration-~~bearing~~wide ~~rock~~review ~~formation to allow flow~~ of ~~hydrocarbons~~hydraulic ~~into~~fracturing ~~the wellbore~~practices. WeThe ~~routinely~~EPA ~~apply~~commenced ~~hydraulic-fracturing~~a ~~techniques~~study inof ~~our~~the ~~drilling~~potential ~~and~~environmental ~~completion~~effects ~~programs.~~of ~~While~~ hydraulic fracturing ~~has~~on ~~historically~~drinking ~~been~~water ~~regulated~~and bygroundwater ~~state~~in ~~oil~~2011 and ~~natural~~issued ~~gas~~a ~~commissions,~~draft ~~the~~assessment ~~EPA~~for ~~has~~public ~~asserted~~comment ~~federal~~and ~~regulatory~~peer ~~authority~~review ~~over~~in ~~certain~~June ~~hydraulic-fracturing~~2015; ~~activities under~~ the ~~SDWA~~assessment ~~involving~~is ~~the~~expected ~~use~~to ofbe ~~diesel~~finalized ~~fuels and published revised permitting guidance~~ in ~~February 2014 addressing the performance of such activities~~2016. ~~Also,~~The indraft ~~May~~assessment ~~2014,~~concluded ~~the~~that ~~EPA~~hydraulic ~~published~~fracturing anhas ~~advance~~not ~~notice~~led ofto ~~proposed~~widespread, ~~rulemaking~~systematic ~~under~~impacts ~~the Toxic Substances Control Act seeking stakeholder input~~ on ~~development~~drinking ofwater aresources, ~~requirement~~but ~~regarding~~it ~~disclosure~~does ofhave ~~information~~the onpotential ~~chemical~~to ~~substances~~impact ~~and~~drinking ~~mixtures~~water ~~used~~resources; inhowever, ~~hydraulic~~this ~~fracturing. The~~conclusion ~~public~~has ~~comment~~recently ~~period~~been oncriticized by the EPA’s ~~advance~~Science ~~notice~~Advisory ~~ended~~Board. Other ingovernmental ~~September 2014~~agencies, ~~and~~including the ~~resultant~~U.S. ~~proposed~~Department ~~rule~~of isEnergy ~~expected~~and inthe ~~2015~~U. ~~More~~S. ~~recently,~~Department onof ~~May~~the 24Interior, ~~2013,~~have ~~the~~evaluated ~~federal~~or ~~Bureau~~are ofevaluating ~~Land~~various ~~Management~~other ~~published~~aspects ~~a supplemental notice~~ of ~~proposed rulemaking governing~~ hydraulic fracturing. onThese ~~federal~~ongoing ~~and~~or ~~Indian lands that replaces a prior draft of~~ proposed ~~rulemaking~~studies ~~issued~~could byspur ~~the~~initiatives ~~agency~~to infurther ~~May~~regulate ~~2012. The revised proposed rule requires public disclosure of chemicals used in~~ hydraulic fracturing onunder federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the ~~surface;~~federal ~~however,~~SDWA toor ~~date,~~other noregulatory ~~further action has been taken~~mechanisms.

In addition, Congress from time to time has considered the adoption of legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. Certain states, including Texas, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example in May 2013, the RRC adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Further, in October 2014, the RRC adopted disposal well rule amendments designed to address disposal well operations in areas of historical or future seismic activity. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. A draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be released sometime in the first half of 2015. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by early 2015. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells, increased compliance costs and time, any of which could adversely affect our business.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

The EPA has determined that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted various regulations regarding GHGs under existing provisions of the CAA. For example, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations. Further, the EPA recently finalized a rule that requires reporting of GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing, and blowdowns of natural gas transmission pipelines. The expansion of the EPA’s GHG reporting program could result in increased compliance costs. In addition, the EPA has adopted rules regulating the emissions of greenhouse gases from certain sources. The EPA also recently proposed new regulations that set methane emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and natural gas sector by up to 45% from 2012 levels by 2025; the regulations are expected to be finalized in 2016.

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~~Regulation~~tracking ~~related~~and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to ~~global~~acquire ~~warming~~and surrender emission allowances in return for emitting those GHGs, with a reduction in the number of allowances over time. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and ~~climate~~regulations ~~change~~that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could ~~have~~require anus ~~adverse~~to ~~effect~~incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, and such requirements also could adversely affect demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The majority of our operations are located in Texas, making operations vulnerable to risks associated with operating in a limited number of major geographic areas.

Our operations are focused primarily in East Texas and Northern Louisiana, South Texas and North Texas, which means our current producing properties and new drilling opportunities are geographically concentrated in these areas. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil, natural gas and NGLs produced from the wells in these areas, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

We use independent contractors to provide us with technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. In addition, we rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

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know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Properties that we buy may not produce as projected and we may be unable to determine the reserve potential, identify liabilities associated with the properties or obtain protection from sellers against us.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. However, our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in detail every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remaining properties for reserve potential. We may also perform only a cursory review of title to these properties at the time we acquire interests in them, particularly if we do not intend to drill on the properties immediately. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.

Approximately 27% of our core net leasehold acreage was undeveloped as of December 31, 2014, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.47

As of December 31, 2014, approximately 27% of our core net leasehold acreage was undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, substantially all of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Approximately 45% of our total estimated proved reserves at December 31, 2014 were proved undeveloped reserves.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in our reserve engineer report assumes that substantial capital expenditures are required to develop such reserves. Although cost and reserve estimates attributable to our oil and natural gas reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate, that development will occur as scheduled or that the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves for any reason, including because we are not able to fund capital expenditures, or if we are not otherwise able to successfully develop these reserves, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any proved undeveloped reserves not developed within this five-year time frame. A removal of such reserves could adversely affect our operations.

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properties and will sample the remaining properties for reserve potential. We may also perform only a cursory review of title to these properties at the time we acquire interests in them, particularly if we do not intend to drill on the properties immediately. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.

Approximately 23% of our core net leasehold acreage was undeveloped as of December 31, 2015, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

As of December 31, 2015, approximately 23% of our core net leasehold acreage was undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, substantially all of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Approximately 23% of our total estimated proved reserves at December 31, 2015 were proved undeveloped reserves.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut down wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.

~~Our~~We ~~hedging~~are ~~activities~~exposed ~~could~~to ~~result~~credit inrisks ~~financial~~of ~~losses~~third orparties ~~could~~participating ~~reduce~~in our ~~income~~wells and our customers.

ToOur ~~achieve~~principal aexposures ~~more~~to ~~predictable~~credit ~~cash~~risk ~~flow~~are ~~and~~through tojoint ~~reduce~~interest ~~our~~receivables ~~exposure~~($7.4 tomillion ~~adverse~~at ~~fluctuations~~December 31, in2015) ~~commodity~~and ~~prices~~the sale of our oil, wenatural ~~currently~~gas ~~enter~~and ~~into~~NGLs ~~hedging~~production ~~arrangements~~($27.5 ~~for~~million ain ~~portion~~receivables ofat ~~our~~December 31, ~~oil~~2015), ~~and~~which ~~natural~~we ~~gas~~market ~~production~~to energy marketing companies and ~~may~~refineries. inJoint ~~the~~interest ~~future~~receivables ~~enter~~arise ~~into~~from ~~such~~billing ~~arrangements~~entities ~~for~~who ~~portions~~own ofpartial ~~our~~interest ~~oil~~in ~~and~~the ~~natural~~wells ~~gas~~we ~~production~~operate. These ~~hedging~~entities ~~arrangements~~participate ~~expose~~in usour towells ~~the~~primarily ~~risk~~based ofon ~~financial~~their ~~loss~~ownership in ~~some~~leases ~~circumstances, including when:~~

~~· production is less than expected;~~ 48

· the counterparty to the hedging contract defaults on its contractual obligations; or

· there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

In addition, these types of hedging arrangements limit the benefit we would receive from increases in the prices for natural gas or oil and may expose us to cash margin requirements.

Our counterparties are typically financial institutions who are lenders under our New Revolving Credit Facility. The risk that a counterparty may default on its obligations is heightened by the recent financial sector crisis and other losses incurred by many banks and other financial institutions, including our counterparties or their affiliates. These losses may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which would reduce our revenues from hedges at a time when we are also receiving a lower price for our oil and natural gas sales, thus triggering the hedge payments. As a result, our operations, liquidity and financial condition could be materially, adversely affected.

Our commodity price risk management activities could have the effect of reducing our net income. At December 31, 2014, the net unrealized gain represented by our commodity price risk management contracts was $153.3 million, but in the past we have incurred significant unrealized losses in connection with our commodity price risk management contracts. In the future, we may continue to incur significant unrealized gains or losses in the future from our commodity price risk management activities to the extent market prices increase or decrease and our derivatives contracts remain in place. In addition, because of the recent decrease in commodity prices, it may become costlier for us to enter into hedging arrangements in the future than it has been historically, in more favorable commodity price environments.

Oil and natural gas prices are volatile. A substantial portion of our hedges are set to expire in 2015. If we choose not to replace hedges as those contracts expire, our cash flows from operations will be subjected to increased volatility.

We enter into hedging transactions of our oil and natural gas production revenues to reduce our exposure to fluctuations in the price of oil and natural gas. A substantial portion of our hedges are set to expire in 2015. As our hedges expire, more of our future production will be sold at market prices, exposing us to the fluctuations in the price of oil and natural gas, unless we enter into additional hedging transactions. We may choose not to replace existing hedges as those contracts expire, which will subject our cash flows from operations to increased volatility.

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on which we wish to drill. We can do very little to choose who participates in our wells. We are ~~exposed~~also subject to credit ~~risks~~risk due to concentration of our ~~hedging counterparties~~oil, ~~third~~natural ~~parties~~gas ~~participating~~and inNGLs ~~our~~receivables ~~wells~~with ~~and~~several ~~our~~significant customers.

~~Our~~These ~~principal~~transactions ~~exposures~~expose us to credit risk ~~are~~in ~~through~~the ~~receivables~~event ~~resulting~~of ~~from~~default ~~commodity~~of ~~derivatives~~our ~~instruments ($160~~counterparty.2 ~~million~~We atdo ~~December 31,~~not ~~2014),~~require ~~joint~~most ~~interest receivables ($22.6 million at December 31, 2014) and the sale~~ of our ~~oil,~~customers ~~natural~~to ~~gas~~post ~~and NGLs production ($85~~collateral.5 ~~million~~The ininability ~~receivables~~or atfailure ~~December 31,~~of ~~2014),~~our ~~which~~significant wecustomers ~~market~~ to ~~energy~~meet ~~marketing~~their ~~companies~~obligations ~~and~~to ~~refineries.~~us ~~Joint~~or ~~interest~~their ~~receivables~~insolvency ~~arise~~or ~~from~~liquidation ~~billing~~may ~~entities~~adversely ~~who~~affect ~~own~~our ~~partial~~financial ~~interest~~results. Deterioration in the ~~wells~~credit wemarkets ~~operate.~~may ~~These~~impact ~~entities~~the ~~participate~~credit inratings of our ~~wells~~current ~~primarily~~and ~~based~~potential oncounterparties ~~their~~and ~~ownership~~affect intheir ~~leases~~ability ~~on which we wish~~ to ~~drill.~~fulfill Wetheir ~~can~~existing doobligations ~~very little~~ to ~~choose~~us ~~who~~and ~~participates~~their inwillingness ~~our wells. We are also subject~~ to ~~credit~~enter ~~risk~~into ~~due~~future totransactions ~~concentration of our oil, natural gas and NGLs receivables~~ with ~~several significant customers~~us.

These transactions expose us to credit risk in the event of default of our counterparty, principally with respect to hedging agreements but also insurance contracts and bank lending commitments. We do not require most of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us.

We depend on a limited number of key personnel who would be difficult to replace. The volatility in commodity prices and business performance may affect our ability to retain senior management and the loss of these key employees may affect our business, financial condition and results of operations.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy. The volatility in commodity prices and business performance may affect our ability to retain senior management or key employees. The loss of the services of key management personnel could have a material adverse effect on our business, financial condition and results of operations. Additionally, if we are unable to find, hire and retain needed key personnel in the future, our business, financial condition and results of operations could be materially and adversely affected. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position.

Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

A portion of our business activities is conducted through joint operating agreements under which we own partial interests in oil and natural gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

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others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

We derive a significant portion of our revenues from a few customers. For the year ended December 31, ~~2014~~ 2015, ~~four~~three customers accounted for approximately 4752% of our total revenues. If these customers fail to timely pay for our production or they cease purchasing our production and we are unable to secure alternative purchasers for our production on a timely basis, our financial condition and results of operations would be materially adversely affected.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.49

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production, and, in the future, we may enter into derivative contracts to hedge a portion of our exposure to fluctuations in interest rates. On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which requires the SEC and the CFTC to promulgate rules and regulations implementing the new legislation. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could affect liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.

The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty.

The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts or increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, the results of our operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our

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~~revenues~~production ~~could~~or ~~therefore~~they becease ~~adversely~~purchasing ~~affected~~our ifproduction and we are unable to secure alternative purchasers for our production on a ~~consequence~~timely ofbasis, ~~the~~our ~~Dodd-Frank~~financial ~~Act~~condition and ~~implementing~~results ~~regulations~~of isoperations towould ~~lower~~be ~~commodity~~materially ~~prices~~adversely affected.

~~Any~~Full ofcost ~~these~~accounting ~~consequences~~rules ~~could~~ have required us to record a ~~material~~non-cash ~~adverse~~asset ~~effect~~write-down onfor ~~us,~~the ~~our~~year ~~financial~~ended ~~condition~~December 31, 2015, and ~~the~~we ~~results~~may ofbe ~~our~~required ~~operations~~to record similar non-cash asset write-downs in the future.

We utilize the full cost method of accounting for natural gas and oil exploration and development activities. Under full cost accounting, we are required to perform a ceiling test each quarter. The ceiling test is an impairment test and generally establishes a maximum, or “ceiling,” of the book value of natural gas and oil properties that is equal to the expected after tax present value (discounted at 10%) of the future net cash flows from proved reserves, including the effect of cash flow hedges when hedge accounting is applied, calculated using the unweighted average of the first day of the month natural gas and oil prices for the prior twelve months. If the net book value of natural gas and oil properties (reduced by any related net deferred income tax liability and asset retirement obligation) exceeds the ceiling limitation, accounting rules require us to impair or “write down” the book value of our natural gas and oil properties. Once incurred, a write-down of natural gas and oil properties is not reversible at a later date.

Costs associated with unevaluated properties are not initially subject to the ceiling test limitation. Rather, we assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value based upon our intentions with respect to drilling on such properties, the remaining lease term, geological and geophysical evaluations, drilling results, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. These factors are significantly influenced by our expectations regarding future commodity prices, development costs, and access to capital at acceptable cost. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization and the ceiling test limitation. Accordingly, a significant change in these factors, some of which are beyond our control, may shift a significant amount of cost from unevaluated properties into the full cost pool that is subject to amortization and the ceiling test limitation.

As of December 31, 2015, the unweighted average of the first day of the month natural gas and oil prices for the prior twelve months was $50.28 per Bbl of oil and $2.58 per MMbtu for natural gas, which resulted in a non-cash impairment charge for oil and gas properties of $1.6 billion for the year ended December 31, 2015.

There is risk that we will be required to write down the carrying value of our natural gas and oil properties increases when natural gas and oil prices are low or volatile. Natural gas prices declined significantly in late 2014 and throughout 2015 to the lowest level in recent years and continue to trade near historic lows. If the average of the unweighted first day of the month natural gas or oil prices for the prior twelve month periods remains at current levels or decline, we could have a further reduction in our asset carrying value for oil and gas properties.

The adoption of financial reform legislation by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was signed into law by President Obama on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require certain counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The final rules will be phased in over time according to a specified schedule which is dependent on the finalization of certain other rules to be promulgated jointly by the CFTC and the SEC. The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts,

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reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. In the future, if we are unable to use derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas liquids and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is even lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

Our business and financial results may be adversely affected if proposed tax reforms are enacted or similar initiatives are implemented as part of the U.S. government’s efforts to reduce budget deficits.

The Obama administration’s budget proposals for fiscal year ~~2015~~2016 contain numerous proposed tax changes, and from time to time, legislation has been introduced that would enact many of these proposed changes. The proposed budget and legislation would repeal many tax incentives and deductions that are currently available to U.S. oil and natural gas companies. Among others, the provisions include: elimination of the ability to fully deduct intangible drilling and development costs in the year incurred; repeal of the percentage depletion deduction for oil and natural gas properties; repeal of the domestic manufacturing tax deduction for oil and natural gas companies; and increase in the geological and geophysical amortization period for independent producers. Several bills have been introduced in Congress that would implement these proposals. It is unclear whether any of these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of legislation containing some or all of these provisions or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could have a material adverse effect on our business, financial condition and results of operations.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our products and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely affected if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Our operations are subject to the risk of cyber-attacks that could have a material adverse effect on our results of operations and financial condition.

Our information technology systems are subject to possible breaches and other threats that could cause us harm. If our systems for protecting against cyber security risks prove not to be sufficient, we could be adversely affected by the loss or damage of intellectual property, proprietary information, or client data, interruption of business operations, or additional costs to prevent, respond to, or mitigate cyber security attacks. These risks could have a material adverse effect on our business, results of operations, and financial condition.

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Item 1B.Unresolved Staff Comments

There were no unresolved SEC staff comments at December 31, ~~2014~~ 2015.

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Item 3.Legal Proceedings

Augenbaum v. Lone Pine Resources Inc. et al.

This claim was filed on May 25, 2012, as a purported class action in the Supreme Court of the State of New York, New York County against Forest, Lone Pine, certain of Lone Pine’s current and former directors and officers (the “Individual Defendants”), and certain underwriters (the “Underwriter Defendants”) of Lone Pine’s initial public offering (the “IPO”), which was completed on June 1, 2011. The class action was subsequently removed to the United States District Court for the Southern District of New York. The complaint alleged that Lone Pine’s registration statement and prospectus issued in connection with the IPO contained untrue statements of material fact or omitted to state material facts relating to forest fires that occurred in Northern Alberta in May 2011, the rupture of a third-party oil sales pipeline in Northern Alberta in April 2011, and the impact of those events on Lone Pine, that the alleged misstatements or omissions violated Section 11 of the Securities Act of 1933 (the “Securities Act”), and that Lone Pine, the Individual Defendants, and the Underwriter Defendants are liable for such violations. (The complaint was subsequently amended to drop the allegation regarding the forest fires.) The complaint further alleged that the Underwriter Defendants offered and sold Lone Pine’s securities in violation of Section 12 (a) (2) of the Securities Act, and the putative class members sought rescission of the securities purchased in the IPO that they continued to own and rescissionary damages for securities that they had sold. Finally, the complaint asserted a claim against Forest under Section 15 of the Securities Act, alleging that Forest was a “control person” of Lone Pine at the time of the IPO. The complaint alleged that the putative class, which purchased shares of Lone Pine’s common stock pursuant and/or traceable to Lone Pine’s registration statement and prospectus, was damaged when the value of the stock declined in August 2011.

On March 26, 2014, the judge overseeing the lawsuit granted Defendants’ motion to dismiss, with prejudice, for failure to state a claim upon which relief may be granted. Plaintiffs appealed the decision on April 28, 2014, and briefing was completed on August 5, 2014. Forest subsequently agreed to a settlement with the named plaintiff, all of which will be paid by Lone Pine’s insurance carrier. The appeal was dismissed on December 3, 2014.

The Parish of Jefferson v. Destin Operating Company, Inc., et al.

On November 11, 2013, Jefferson Parish filed suit against ~~Forest~~the Company and fourteen (14) other defendants, alleging that certain of defendants’ oil and gas exploration, production, and transportation operations associated with the development of the Bay de Chene, Queen Bess Island, and Saturday Island oil and gas fields in Jefferson Parish, Louisiana were conducted in violation of Louisiana’s State and Local Coastal Resources Management Act and its associated rules and regulations, and that these activities caused substantial damage to land and waterbodies located in the Jefferson Parish Coastal Zone. ~~Forest~~The Company tendered a claim for indemnity to Texas Petroleum Investment Company (“TPIC’”), which TPIC rejected. ~~Forest~~The Company responded with a reservation of rights to indemnity from TPIC. The case was removed to federal court and is currently pending in the United States District Court for the Eastern District of Louisiana. The case ~~has~~was ~~been~~administratively onclosed ~~hold~~ pending the court’s decision regarding federal jurisdiction in aother similar ~~lawsuit~~lawsuits. ~~That~~Those ~~lawsuit~~lawsuits ~~was~~were recently remanded to Louisiana state court. On March 12, so2015, the ~~parties~~case ~~have~~was ~~filed~~administratively areopened ~~motion~~and the court directed the defendants to ~~reopen~~show cause as to how and why the jurisdictional issues in this case differ from those issues presented in the similar lawsuits. Defendants filed the requisite briefing and ~~set~~the amatter ~~status~~is ~~conference~~under advisement. Plaintiffs seek unspecified monetary damages and restoration of the Jefferson Parish Coastal Zone to its original condition. ~~This~~On ~~matter~~July is15, in2015, the ~~very~~Company ~~early~~filed ~~stages~~a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. Plaintiffs filed a motion to dismiss the Company from the litigation on July 21, 2015.

The Parish of Plaquemines v. ConocoPhillips Company, et al.

On November 8, 2013, Plaquemines Parish filed suit against ~~Forest~~the Company and seventeen (17) other defendants, alleging that certain of defendants’ oil and gas exploration, production, and transportation operations associated with the development of the Bay Batiste, Grand Ecaille, Lake Washington, Manila Village, Manila Village Southeast, Saturday Island, and Saturday Island Southeast oil and gas fields in Plaquemines Parish, Louisiana were conducted in violation of Louisiana’s State and Local Coastal Resources Management Act and its associated rules and regulations, and that these activities caused substantial damage to land and waterbodies in the Plaquemines Parish Coastal Zone. Forest tendered a claim for indemnity to Texas Petroleum Investment Company (“TPIC’”), which TPIC rejected. ~~Forest~~The Company responded with a reservation of rights to indemnity from TPIC. The case was removed to the United States District Court for the Eastern District of Louisiana, but was remanded to Louisiana state court on March 10, 2015. The matter is now pending before the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana. Plaintiffs seek unspecified monetary damages and restoration of the Plaquemines Parish Coastal Zone to its original condition. On July 15, 2015, the Company filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. The Company was dismissed from the litigation on July 28, 2015.

Forest Oil Corporation v. El Rucio Land and Cattle Company, Inc., et al.

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to the Company in the proceeding styled Forest Oil Corp. et al. v. El Rucio Land & Cattle Co. et al. The third member of the arbitration panel dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land and related damages allegedly resulting from operational and reclamation practices employed by Forest Oil in the 1970s, 1980s, and early 1990s. The arbitration decision awarded the claimant $23 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9, 2012, after vacating a portion of the decision imposing a future bonding requirement on the Company, the trial court for the 55th Judicial District of Harris County, Texas, reduced the arbitration decision to a judgment. The judgment was affirmed by the Court of Appeals for the First District of Texas on July 24, 2014, and a motion for rehearing was denied on August 8, 2014. The Company filed a petition for review with the Texas Supreme Court on January 5, 2015, and on May 1, 2015, the Texas Supreme Court requested full briefing on the merits. On July 15, 2015, the Company filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. On September 15, 2015, the

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~~reservation~~bankruptcy ofcourt ~~rights~~granted toan ~~indemnity~~unopposed ~~from~~motion ~~TPIC.~~to ~~The~~lift ~~case~~the ~~was~~automatic ~~removed~~stay tothereby ~~federal~~allowing ~~court~~the ~~and~~appeal is currently pending in the ~~United~~Texas ~~States~~Supreme ~~District~~ Court ~~for~~to ~~the~~move ~~Eastern District of Louisiana~~forward. All Abriefing ~~motion to remand is scheduled to be heard~~ in ~~early 2015. Plaintiffs seek unspecified monetary damages and restoration of~~ the ~~Plaquemines Parish Coastal Zone to its original condition. This~~ matter is innow ~~the very early stages of litigation~~completed.

Forest Oil Corporation v. El Rucio Land and Cattle Company, Inc., et al.

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al., which occurred in Harris County, Texas. The third member of the arbitration panel dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land and related damages allegedly resulting from operational and reclamation practices employed by Forest in the 1970s, 1980s, and early 1990s. The arbitration decision awarded the claimant $23 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9, 2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55th Judicial District, in the District Court in Harris County, Texas, reduced the arbitration decision to a judgment. The judgment was affirmed by the Court of Appeals for the First District of Texas on July 24, 2014, and a motion for rehearing was denied on August 8, 2014. Forest filed a petition for review with the Texas Supreme Court on January 5, 2015.

We are a party to various other lawsuits, claims, and proceedings in the ordinary course of business. These proceedings are subject to uncertainties inherent in any litigation, and the outcome of these matters is inherently difficult to predict with any certainty. We believe that the amount of any potential loss associated with these proceedings would not be material to our consolidated financial position; however, in the event of an unfavorable outcome, the potential loss could have an adverse effect on our results of operations and cash flow.

Stourbridge Investments, LLC v. Forest Oil Corporation, et al., Raul v. Carroll, et al., Rothenberg v. Forest Oil Corporation, et al., Gawlikowski v. Forest Oil Corporation, et al., Edwards v. Carroll, et al., Jabri v. Forest Oil Corporation, et al., Olinatz v. Forest Oil Corporation, et al.

Following the May 6, 2014 announcement of the proposed ~~Transactions~~Combination, six putative class action lawsuits were filed by Forest Oil shareholder in the Supreme Court of the State of New York, County of New York, alleging breaches of fiduciary duty by the directors of Forest Oil and aiding and abetting of those breaches of fiduciary duty by Sabine entities in connection with the proposed ~~Transactions~~Combination. By order dated July 8, 2014, the six New York cases were consolidated for all purposes under the caption In re Forest Oil Corporation Shareholder Litigation, Index No. 651418/2014. On July 17, 2014, plaintiffs in the consolidated New York action filed a Consolidated Class Action Complaint (the “Consolidated Complaint”). The Consolidated Complaint seeks to certify a plaintiff class consisting of all holders of Forest Oil common stock other than the defendants and their affiliates. The defendants named in these actions include the directors of Forest Oil (Patrick R. McDonald, James H. Lee, Dod A. Fraser, James D. Lightner, Loren K. Carroll, Richard J. Carty, and Raymond I. Wilcox), as well as Sabine and certain of its affiliates (specifically, Sabine Oil & Gas LLC, Sabine Investor Holdings LLC, Sabine Oil & Gas Holdings LLC, and Sabine Oil & Gas Holdings II LLC). The Consolidated Complaint also purports to identify FR XI Onshore AIV, L.L.C. as a defendant, but no causes of action are alleged against that entity.

The Consolidated Complaint alleges that the proposed ~~Transactions~~Combination ~~arise~~arises out of a series of unlawful actions by the board of directors of Forest Oil seeking to ensure that Sabine and affiliates of First Reserve Corporation (“First Reserve”) acquire the assets of, and take control over, Forest Oil through an alleged “three-step merger transaction” that allegedly does not represent a value-maximizing transaction for the shareholders of Forest Oil. The Consolidated Complaint also complains that the proposed ~~Transactions~~Combination ~~have~~has been improperly restructured to require only a majority vote of current Forest Oil shareholders to approve the Combination with Sabine, rather than a two-thirds majority as would have been required under the original transaction structure. The Consolidated Complaint additionally alleges that members of Forest Oil’s board, as well as Forest Oil’s financial adviser for the proposed ~~Transactions~~Combination, are subject to conflicts of interest that compromise their loyalty to Forest Oil’s shareholders, that the defendants have improperly sought to “lock up” the proposed ~~Transactions~~Combination with certain inappropriate “deal protection devices” that impede Forest Oil from pursuing superior potential transactions with other bidders.

The Consolidated Complaint asserts causes of action against the directors of Forest Oil for breaches of fiduciary duty and violations of the New York Business Corporation Law, as well as a cause of action against the Sabine defendants for aiding and abetting the directors’ breaches of duty and violations of law, and it seeks preliminary and permanent injunctive relief to enjoin consummation of the proposed Combination or, in the alternative, rescission and/or rescissory and other damages in the event that the proposed Combination is consummated before the lawsuit is resolved.

In addition to these New York proceedings, one putative class action lawsuit has been filed by Forest Oil shareholders in the United States District Court for the District of Colorado. That action, captioned Olinatz v. Forest Oil Corp., No. 1:14-cv-01409-MSK-CBS, was commenced on May 19, 2014, and plaintiffs filed an Amended Complaint (the “Olinatz Complaint”) on June 13, 2014. The Olinatz Complaint also alleges breaches of fiduciary duty by the directors of Forest Oil and aiding and abetting of those breaches of fiduciary duty by the Sabine defendants in connection with the proposed Combination, as well as related claims alleging violations of Section 14 (a) and 20 (a) of the Securities Exchange Act of 1934, and Securities and Exchange Commission Rule 14a-9 promulgated thereunder, in connection with alleged misstatements in a Form S-4 Registration Statement filed by Forest Oil on May 29, 2014, which recommends that Forest Oil shareholders approve the proposed Combination. The Olinatz Complaint names as defendants Forest Oil and certain of its affiliates (specifically, Forest Oil Corporation, New Forest Oil Inc., and Forest Oil Merger Sub Inc.), the directors of Forest Oil (Patrick R. McDonald, James H. Lee, Dod A. Fraser, James D. Lightner, Loren K. Carroll, Richard J. Carty, and Raymond I. Wilcox), and Sabine and certain of its affiliates (specifically, Sabine Oil & Gas LLC, Sabine Investor Holdings LLC, Sabine Oil & Gas Holdings LLC, and Sabine Oil & Gas Holdings II LLC), and seeks preliminary and permanent injunctive relief to enjoin consummation of the Combination or, in the alternative, rescission in the event the proposed Combination is consummated before the lawsuit is resolved, as well as imposition of a constructive trust on any alleged benefits improperly received by defendants.

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The Consolidated Complaint asserts causes of action against the directors of Forest Oil for breaches of fiduciary duty and violations of the New York Business Corporation Law, as well as a cause of action against the Sabine defendants for aiding and abetting the directors’ breaches of duty and violations of law, and it seeks preliminary and permanent injunctive relief to enjoin consummation of the proposed Transactions or, in the alternative, rescission and/or rescissory and other damages in the event that the proposed Transactions are consummated before the lawsuit is resolved.

In addition to these New York proceedings, one putative class action lawsuit has been filed by Forest Oil shareholders in the United States District Court for the District of Colorado. That action, captioned Olinatz v. Forest Oil Corp., No. 1:14-cv-01409-MSK-CBS, was commenced on May 19, 2014, and plaintiffs filed an Amended Complaint (the “Olinatz Complaint”) on June 13, 2014. The Olinatz Complaint also alleges breaches of fiduciary duty by the directors of Forest Oil and aiding and abetting of those breaches of fiduciary duty by the Sabine defendants in connection with the proposed Transactions, as well as related claims alleging violations of Section 14 (a) and 20 (a) of the Securities Exchange Act of 1934, and Securities and Exchange Commission Rule 14a-9 promulgated thereunder, in connection with alleged misstatements in a Form S-4 Registration Statement filed by Forest Oil on May 29, 2014, which recommends that Forest Oil shareholders approve the proposed Transactions. The Olinatz Complaint names as defendants Forest Oil and certain of its affiliates (specifically, Forest Oil Corporation, New Forest Oil Inc., and Forest Oil Merger Sub Inc.), the directors of Forest Oil (Patrick R. McDonald, James H. Lee, Dod A. Fraser, James D. Lightner, Loren K. Carroll, Richard J. Carty, and Raymond I. Wilcox), and Sabine and certain of its affiliates (specifically, Sabine Oil & Gas LLC, Sabine Investor Holdings LLC, Sabine Oil & Gas Holdings LLC, and Sabine Oil & Gas Holdings II LLC), and seeks preliminary and permanent injunctive relief to enjoin consummation of the proposed Transactions or, in the alternative, rescission in the event the proposed Transactions are consummated before the lawsuit is resolved, as well as imposition of a constructive trust on any alleged benefits improperly received by defendants.

On October 14, 2014, on motion by the Colorado plaintiffs, the Court in the Colorado action entered an order directing the Clerk of the Court to administratively close the action, subject to reopening on good cause shown.

On November 11, 2014, the defendants reached an agreement in principle with plaintiffs in the New York action regarding a settlement of that action, and that agreement is reflected in a memorandum of understanding executed by the parties on that date. The settlement, if consummated, ~~will~~would also resolve the Colorado action. In connection with the settlement contemplated by the memorandum of understanding, Forest Oil agreed to make certain additional disclosures related to the proposed transaction with Sabine, which are contained in Forest Oil’s November 12, 2014 Form 8-K, and Sabine agreed that, within 120 days after the closing of the proposed combination transaction, Sabine Investor Holdings LLC will designate for a period of no less than three (3) years at least one additional independent director, as defined in Section 303A.02 of the New York Stock Exchange Listed Company Manual, as a Sabine Nominee (as defined in Section 1.4 of the Amended and Restated Agreement and Plan of Merger). The total number of Sabine Nominees will remain unchanged, but at least one of the remaining two Sabine Nominees that had not yet been determined was required to be independent. In connection with the closing of the Combination, Thomas Chewning, an independent director as defined in Section 303A.02 of the New York Exchange Listed Company Manual, was appointed as a Sabine Nominee. The memorandum of understanding contemplates that the parties will enter into a stipulation of settlement.

~~The~~On ~~stipulation~~March of13, ~~settlement~~2015, ~~will~~plaintiffs beinformed ~~subject~~Sabine tothat ~~customary~~they ~~conditions,~~believed ~~including~~Sabine ~~court~~had ~~approval. In~~materially ~~the~~violated ~~event~~ the ~~parties~~terms ~~enter~~of ~~into~~the amemorandum ~~stipulation~~ of ~~settlement,~~understanding aby ~~hearing~~(i) ~~will~~failing beto ~~scheduled~~replace ator ~~which~~create ~~the~~a ~~New~~mechanism ~~York~~to ~~Court~~replace ~~will~~an ~~consider~~independent ~~the~~director ~~fairness,~~who ~~reasonableness,~~resigned ~~and~~from ~~adequacy of~~ the ~~settlement. If~~board ~~the~~of ~~settlement~~directors isin ~~finally~~January ~~approved~~of by2015, ~~the~~and ~~court,~~(ii) itmaking ~~will~~changes ~~resolve~~to ~~and~~the ~~release~~terms ~~all~~of ~~claims~~the ormerger ~~actions~~agreement that were ornot ~~could~~necessary ~~have~~or ~~been~~required ~~brought~~to ~~challenging~~facilitate ~~any~~the ~~aspect~~consummation of the proposed ~~combination~~ transaction, ~~the~~without ~~Amended~~first disclosing and ~~Restated~~permitting ~~Agreement~~shareholders ~~and~~to ~~Plan~~vote ofon ~~Merger,~~ the ~~merger~~changes. ~~agreement~~Sabine ~~originally~~disagrees ~~entered~~with ~~into~~plaintiffs’ byposition ~~Sabine~~and ~~Investor~~believes ~~Holdings~~it ~~LLC,~~has ~~Forest~~fully ~~Oil,~~complied ~~New~~with ~~Forest~~the ~~Oil~~memorandum ~~Inc~~of understanding. ~~and~~In ~~certain~~an ofattempt ~~their~~to ~~affiliated~~facilitate ~~entities~~a ~~on May 5~~resolution, ~~2014~~however, ~~any~~Sabine ~~disclosure~~offered ~~made~~to: in(i) ~~connection~~appoint ~~therewith,~~an ~~including~~independent ~~the~~director ~~Definitive~~if ~~Proxy~~an ~~Statement,~~additional ~~and~~director ~~all~~was ~~other~~added ~~matters~~to ~~that were~~ the ~~subject~~Board of ~~the~~Directors ~~complaint~~(bringing in the ~~New~~total ~~York~~number ~~action,~~of ~~pursuant~~directors to ~~terms~~eight) ~~that~~in ~~will be disclosed to stockholders prior to final approval of~~ the ~~settlement. In~~next ~~addition,~~twelve ~~in connection with the settlement~~months, ~~the~~and ~~parties~~(ii) ~~contemplate~~remove ~~that~~or ~~the~~waive ~~parties will negotiate in good faith regarding~~ the ~~amount~~“Reincorporation ofPenalty” ~~attorney’s fees and expenses that shall be paid to plaintiffs’ counsel in connection with the Actions~~provision. ~~There~~Plaintiffs ~~can~~accepted ~~be no assurances that~~ the ~~parties~~offer ~~will~~on ~~ultimately~~April ~~enter~~22, ~~into~~2015, acontingent ~~stipulation~~upon ~~of settlement or that~~ the ~~New~~Parties’ ~~York~~reaching ~~Court~~agreement ~~will~~on ~~approve~~a ~~the settlement even if the parties were to enter into such~~ stipulation~~. In~~ ~~such~~of ~~event~~settlement, ~~the~~which ~~proposed~~they ~~settlement~~are aspresently ~~contemplated by the memorandum of~~ negotiating.

The stipulation of settlement will be subject to customary conditions, including court approval. In the event the parties enter into a stipulation of settlement, a hearing will be scheduled at which the New York Court will consider the fairness, reasonableness, and adequacy of the settlement. If the settlement is finally approved by the court, it will resolve and release all claims or actions that were or could have been brought challenging any aspect of the proposed combination transaction, the Amended and Restated Agreement and Plan of Merger, the merger agreement originally entered into by Sabine Investor Holdings LLC, Forest Oil, New Forest Oil Inc. and certain of their affiliated entities on May 5, 2014, any disclosure made in connection therewith, including the Definitive Proxy Statement, and all other matters that were the subject of the complaint in the New York action, pursuant to terms that will be disclosed to shareholders prior to final approval of the settlement. In addition, in connection with the settlement, the parties contemplate that the parties will negotiate in good faith regarding the amount of attorney’s fees and expenses that shall be paid to plaintiffs’ counsel in connection with the Actions. There can be no assurances that the parties will ultimately enter into a stipulation of settlement or that the New York Court will approve the settlement even if the parties were to enter into such stipulation. In such event, the proposed settlement as contemplated by the memorandum of understanding may be terminated. The parties are presently negotiating the stipulation of settlement. At this time, the Company is unable to guarantee the potential outcome of this litigation or the ultimate exposure.

On July 15, 2015, the Company filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. As a result of the pending bankruptcy, this matter is currently stayed.

HPIP-Gonzales Holdings, LLC v. Forest Oil Corporation

On November 11, 2014, HPIP-Gonzales Holdings, LLC (“HPIP”) initiated arbitration against the Company alleging that the Company breached various provisions, along with our duty of good faith and fair dealing, of the Gathering, Treating and Processing Agreement with HPIP entered into in May 2013 and the Acid Gas Handling Agreement with HPIP entered into in May 2014 (collectively, the “HPIP Agreements”). HPIP also sought to exercise a contractual provision requiring us to purchase the facilities governed by the HPIP Agreements in the event the related drilling program terminates. On December 19, 2014, the Company filed its Answering Statement and Notice of Counterclaim,

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~~understanding~~denying ~~may~~HPIP’s beclaims ~~terminated~~and asserting generally that HPIP breached various provisions of the agreements, resulting in damages to the Company. The ~~parties~~Company ~~are~~further ~~presently~~alleged ~~negotiating~~that ~~the~~its ~~stipulation~~drilling ofprogram ~~settlement~~had not terminated. AtOn ~~this~~July ~~time~~15, 2015, the Company isfiled ~~unable~~a tovoluntary ~~guarantee~~petition for relief under Chapter 11 of the ~~potential~~Bankruptcy ~~outcome~~Code. As a result of ~~this~~the ~~litigation~~pending orbankruptcy, the ~~ultimate~~arbitration ~~exposure~~is currently stayed.

On March 13, 2015, plaintiffs informed Sabine that they believe Sabine has materially violated the terms of the memorandum of understanding executed on November 11, 2014 by (i) failing to replace or create a mechanism to replace an independent director who resigned from the board of directors in January of 2015, and (ii) making changes to the terms of the merger agreement that were not necessary or required to facilitate the consummation of the proposed transaction without first disclosing and permitting shareholders to vote on the changes. Sabine disagrees with plaintiffs and will respond to their letter in due course. If plaintiffs prevail in their position concerning the memorandum of understanding, the proposed settlement as contemplated by the memorandum of understanding may be terminated.

Wilmington Savings Fund Society, FSB v. Forest Oil Corporation

On February 26, 2015, wethe ~~were~~Company was served with a complaint concerning the indenture governing ~~our~~its 2019 Notes. The complaint is pending in the Supreme Court of the State of New York and generally alleges that certain events of default ~~had~~ occurred with respect to the 2019 Notes due to the business combination between Forest Oil Corporation and Sabine Oil & Gas LLC. WeThe Company also received a notice of default and acceleration from the trustee with respect to the 2019 Notes containing similar allegations. If wethe ~~are~~Company is not successful in ~~our~~its defense of this complaint, wethe Company may be required to redeem the holders of the 2019 Notes at 101% of the outstanding principal, plus accrued and outstanding interest of the notes,. ~~and~~The ifCompany ~~the~~filed ~~court~~its ~~determines~~Answer weto ~~are in default under~~ the ~~indenture~~complaint ~~governing~~on ~~the~~April ~~2019 Notes~~17, ~~a cross-default and acceleration under our other debt agreements may result~~2015. WeThe ~~believe~~Company ~~these~~believes the allegations against usit are without merit and intend to vigorously defend against such claims and pursue any and all defenses available. However, wethe ~~are~~Company is unable to predict the outcome of such matter, and the proceedings may have a negative impact on ~~our~~the Company’s liquidity, financial condition and results of operations.

WeThe ~~are~~Company is separately evaluating potential claims that weit may assert against the trustee for the 2019 Notes for any and all losses wethe Company may suffer as a result of the complaint or notice. WeThe Company can provide no guarantee that any such claims, if brought by usthe Company, will be successful or, if successful, that the responsible parties will have the financial resources to address any such claims. While the Company intends to vigorously defend the claims against it and believe they are without merit, an adverse ruling could cause the Company’s indebtedness to become immediately due and payable.

Additional claims, lawsuits, or proceedings may be filed or commenced arising out of the indentures to which wethe ~~are~~Company is a party and with respect to the business combination.

~~While~~On weJuly ~~intend~~15, to2015, ~~vigorously~~the ~~defend~~Company ~~the~~filed ~~claims~~a ~~against~~voluntary uspetition ~~and~~for ~~believe~~relief ~~they~~under ~~are~~Chapter ~~without~~11 ~~merit,~~of anthe ~~adverse~~Bankruptcy ~~ruling~~Code. As ~~could~~a ~~cause~~result ~~our~~of ~~indebtedness~~the topending ~~become~~bankruptcy, ~~immediately~~this ~~due~~matter ~~and~~is ~~payable~~currently stayed.

Patrick R. McDonald v. Sabine Oil & Gas Corporation

On March 30, 2015, Mr. Patrick R. McDonald filed a complaint against the Company in the District Court, City and County of Denver, State of Colorado, alleging that the Company breached its obligations under a severance agreement with Mr. McDonald, and violated the Colorado Wage Act by allegedly not paying Mr. McDonald certain accrued vacation. The complaint arises from the Company’s decision to defer the payment of severance and associated benefits to certain of its former executive officers. In the complaint, Mr. McDonald seeks relief in the form of monetary damages. Mr. McDonald served as an executive officer until December 2014, and continues to serve on the Company’s Board of Directors. On April 29, 2015, the Company removed the lawsuit from state court to the U.S. District Court for the District of Colorado, where it now pends. The Company filed an answer to Mr. McDonald’s complaint on May 6, 2015. On July 15, 2015, the Company filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. As a result of the pending bankruptcy, this matter is currently stayed.

Sabine Oil & Gas Corporation v. Wilmington Trust, N.A.

On July 15, 2015, the Company filed an adversary proceeding asserting, on its behalf, a constructive fraudulent transfer claim against the Term Loan Facility administrative agent Wilmington Trust, N.A. Specifically, the complaint states that immediately before the Combination between Sabine Oil & Gas LLC and Forest Oil Corporation, both Forest Oil Corporation and Sabine Oil & Gas LLC were insolvent from a balance-sheet standpoint. The complaint likewise alleges that immediately after the Business Combination, the combined company was insolvent. The complaint also alleges that Forest Oil Corporation and its creditors did not receive reasonably equivalent value in the Combination and financing transactions that occurred simultaneously on December 16, 2014. Specifically, the complaint alleges that Forest Oil Corporation’s creditors did not receive reasonably equivalent value in exchange for pledging hundreds of millions of dollars of previously unencumbered oil and gas assets to secure the Term Loan Facility debt that was under-

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secured, and that Sabine Oil & Gas LLC had previously incurred. Accordingly, pursuant to Bankruptcy Code Section 551, the Company is seeking to avoid and preserve, for the benefit of our unsecured creditors, the liens imposed on legacy Forest Oil Corporation assets that were pledged to secure the preexisting Sabine Oil & Gas LLC’s Term Loan Facility. In August 2015, the defendant filed a motion to dismiss, which is now fully briefed. The court heard first oral argument on October 15, 2015, but did not rule.

On December 30, 2015, the official committee for unsecured creditors (the “Creditors Committee”) and counsel for the Forest Notes Trustees filed motions to intervene in the adversary proceeding. On January 5, 2016, the Creditors Committee also filed an objection to Wilmington Trust, N.A.’s motion to dismiss the complaint. The court held a second hearing on the motion to dismiss on January 12, 2016, but has yet to rule.

Item 4.Mine Safety Disclosures

Not applicable.

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PART II

Item 5.Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock

We have one class of common shares outstanding, our common stock, par value $0.10 per share (“Common Stock”). Our Common Stock is traded on the ~~OTCQB~~OTC Pink Marketplace under the symbol “SOGC.” On March 1521, ~~2015~~2016, there were ~~214~~211,~~669~~693,~~984~~364 shares of our Common Stock outstanding held by ~~691~~695 holders of record. The number of holders does not include the shareholders for whom shares are held in a “nominee” or “street” name.

Under our Amended and Restated Certificate of Incorporation, we are authorized to issue up to 650,000,000 shares of our Common Stock, and up to 10,000,000 shares of our Preferred Stock. On March 1521, ~~2015~~2016, there were 2,508,945 shares of our Series A preferred shares outstanding.

For periods prior to the Combination on December 16, 2014, when we were listed on the NYSE under the symbol “FST,” the table below reflects the high and low intraday sales prices per share of the Common Stock as reported by the NYSE. For periods following our delisting on the NYSE, we commenced trading on the OTCQB under the symbol “SOGC.” Beginning on December 17, 2014, the table below reflects the high and low intraday sales price per share of the Common Stock as reported by the OTCQB. As a result of the Bankruptcy Petitions, the Company’s common stock can no longer be traded on the OTCQB and is now trading on the OTC Pink Marketplace. Beginning on July 16, 2015, the table below reflects the high and low intraday sales price per share of the Common Stock as reported by the OTC Pink Marketplace. There were no cash dividends declared on the Common Stock in 2013, 2014 or ~~2014~~2015. On March 1521, ~~2015~~2016, the closing price of our Common Stock was $0.1301. Our Common Stock’s trading range during the periods indicated was as follows:

	Common Stock
	High		Low
2013
First Quarter	$	7.44	$	5.18
Second Quarter		5.43		3.77
Third Quarter		6.67		4.02
Fourth Quarter		6.52		3.43
2014
First Quarter	$	3.73	$	1.68
Second Quarter		2.59		1.75
Third Quarter		2.43		1.16
Fourth Quarter		1.31		0.16
2015
First Quarter	$	0.33	$	0.04
Second Quarter		0.11		0.06
Third Quarter		0.07		0.01
Fourth Quarter		0.03		0.00

Dividend Restrictions

Our ~~present or future~~ ability to pay dividends isand ~~governed~~make bycertain ~~(i)~~payments ~~the~~was ~~provisions~~subject ofto the ~~New~~restrictions ~~York~~included ~~Business~~in ~~Corporation~~the ~~Law,~~covenants ~~(ii)~~of our ~~Restated~~debt ~~Certificate of Incorporation and Bylaws~~obligations. However, ~~(iii)~~with the ~~indentures~~filing ~~governing~~of the ~~2017~~Bankruptcy ~~Notes,~~Petitions ~~the~~and ~~2019~~until ~~Notes~~our ~~and~~emergence ~~the~~from ~~2020 Notes~~bankruptcy, ~~(iv)~~our ~~the~~ability ~~Term~~to ~~Loan~~make ~~Facility~~such ~~and~~payments ~~(v)~~is ~~the~~limited ~~New~~and ~~Revolving~~now ~~Credit~~subject ~~Facility. The provisions in the indentures pertaining~~ to ~~these senior notes,~~ the ~~Term~~approval ~~Loan~~of ~~Facility and~~ the ~~New~~Bankruptcy ~~Revolving Credit Facility limit our ability to make restricted payments, which include dividend payments~~Court. On September 30, 2011, Forest distributed a special stock dividend in connection with the spin-off of Lone Pine Resources, Inc.; however, prior to the Combination, Forest had not paid cash dividends on its Common Stock during the previous five years. The future payment of cash dividends, if any, on the Common Stock is within the discretion of the Board of Directors and will depend on our earnings, capital requirements, financial condition, and other relevant factors. We do not currently intend to pay any cash dividends in the foreseeable future, and there is no assurance that we will pay any cash dividends. For further information regarding our equity securities and our ability to pay dividends on our Common Stock, please see “Note 78. Long-Term Debt” and “Note 89. Shareholders’ Equity” to our Consolidated Financial Statements included herein.

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Unregistered Sales of Equity Securities

On December 16, 2014, in connection with the closing of the Combination, we issued an aggregate of 79,241,916 common shares and 2,508,945 Series A preferred shares (convertible into 250,894,494 common shares) to Sabine Investor Holdings and FR XI Onshore AIV, LLC, a Delaware limited liability company (“AIV Holdings”). The issuance of the common shares and Series A preferred shares was made in reliance upon an exemption from registration provided by Section 4 (a)-(2) of the Securities Act as a transaction not involving a public offering. We did not make any ~~other~~ sales of unregistered equity securities during the ~~quarter~~year ended December 31, ~~2014~~2015. As a result of the filing of the Bankruptcy Petitions, there is a high probability that the Series A preferred shares (and the common shares that the preferred can convert into) will receive no recovery and be cancelled.

The Series A preferred shares are convertible into our common shares at the option of Sabine Investor Holdings if (1) Sabine Investor Holdings is able to convert a portion of the Series A preferred shares into our common shares and, as a result of such conversion, would not, together with affiliates, hold more than 50% of our voting power and (2) our board of directors approves such conversion (such approval not to be unreasonably withheld). In addition, Series A preferred shares will convert automatically if Sabine Investor Holdings transfers such shares to a third party and such third party would not, together with its affiliates, hold more than 50% of our voting power upon receipt of such shares as voting securities.

The Series A preferred shares are non-voting. Initially, in connection with a conversion of Series A preferred shares into our common shares as described in the preceding paragraph, each Series A preferred share will be convertible into 100 of our common shares. If our reincorporation from New York to Delaware (the “Reincorporation Merger”) is not approved by holders of the requisite number of our shares at the first special meeting of our shareholders held for such purpose, then from the date of such special meeting until the time at which the Reincorporation Merger is approved by our shareholders, the conversion ratio will be adjusted upwards such that, on an annualized basis, the adjustment results in the Series A preferred shares being convertible into an additional number of our common shares equal to 10% of the total number of our common shares underlying all of the then outstanding Series A preferred shares (assuming all such Series A preferred shares were then convertible into our common shares). The adjustment to the foregoing conversion ratio will be calculated quarterly.

Issuer Purchases of Equity Securities

We did not purchase any of our equity securities during ~~the fourth quarter of 2014~~2015.

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Stock Performance Graph

The following graph compares the cumulative total shareholder return on our Common Stock during the five years ended December 31, 2014 with the cumulative total shareholder return of the Russell 2000 Index, the Standard & Poors 500 Index, the Dow Jones U.S. Select Oil Exploration & Production Index (DJSOEP), and the State Street SPDR of the Standard & Poors Oil & Gas Exploration & Production Select Industry Index (“XOP”), of which the ten largest weighted company holdings as of March 27, 2015 are SandRidge Energy Incorporated, Energy XXI Ltd., SM Energy Company, Range Resources Corporation, Laredo Petroleum Incorporated, EXCO Resources Incorporated, Rice Energy Incorporated, California Resources Corporation, EP Energy Corporation, and Callon Petroleum Company. The comparison assumes an investment of $100 on December 31, 2009 in each of our Common Stock, the Russell 2000 Index and the XOP.

Comparison Of 5 Year Cumulative Total Return*Among Sabine Oil & Gas Corporation, the Russell 2000, the S&P500, the DJSOEP and the XOP

*$100 invested on 12/31/09 in stock or index, including reinvestment of dividends. Fiscal year ending December 31.

The information in this Annual Report on Form 10-K appearing under the heading “Stock Performance Graph” is being furnished pursuant to Item 201 (e) of Regulation S-K and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201 (e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.

In our annual report for the year ended December 31, 2013, we had prepared the Comparison of 5 Year Cumulative Total Return by comparing the cumulative total shareholder return on our common stock during the five years ended December 31, 2013 with the cumulative total shareholder return of the S&P 500 Index and the Dow Jones U.S. Exploration and Production Index. Given the significant decrease in our market capitalization since December 31, 2013, we believe a comparison to the Russell 2000 Index and the XOP, which are comprised of companies more similarly sized to us, is more meaningful to investors.

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Securities Authorized for Issuance under Equity Compensation Plans

In November 2014, we adopted the 2014 Long Term Incentive Plan (the “2014 LTIP”) under which nonstatutory options, incentive stock options, stock appreciation rights, restricted stock, restricted stock units, bonus stock, dividend equivalents, and other stock-based awards may be granted to our employees, directors and consultants. The aggregate number of shares of common stock that the Company may issue under the 2014 LTIP may not exceed 20 million shares. The following table summarizes the restricted stock activity in the 2014 LTIP for the year ended December 31, ~~2014~~2015.

	Restricted Stock Awards
	Weighted
				Number of Shares
		Weighted Average		Remaining Available
	Number of	Grant Date		for Future Issuance
	Shares	Fair Value ($)		under 2014 LTIP ~~($)~~
Unvested at December 31, 2013	—		—		20,000,000
Unvested at December 31, 2014	13,923,230	$	0.34		3,205,597
Awarded	16719,~~859,403~~132		0.3424		(16719,~~859,403~~132)
Vested	(2,~~871~~727,~~173~~871)		0.34		—
Forfeited	(651,~~000~~815,200)		0.34		651,~~000~~815,200
Unvested at December 31, 2014	13,923,230		0.34		3,205,597
Unvested at December 31, 2015	10,099,291		0.33		4,301,665

Incentive Units

The Incentive Units were issued pursuant to the Combination in exchange for Incentive Units that were outstanding prior to the Combination, and were amended in connection with the closing of the Combination. The Incentive Units that were outstanding prior to the Combination were not a substantive class of equity and participated only upon liquidation events meeting certain requisite financial thresholds which were not considered probable, and, as such, were considered to be liability-based awards with no fair value recognized as of December 31, 2013. As amended, the Incentive Units represent the equivalent of stock appreciation rights redeemable for an applicable number of common shares of the Company (based on the value of the common shares). As such, the Incentive Units as amended in connection with the Combination were considered to be equity-based awards with a grant date fair value of approximately $2.1 million, of which compensation expense will be recognized on a straight line basis over the requisite service period. The compensation expense recognized in the year ended December 31, 2015 was $0.4 million. On December 16, 2014, in connection with the closing of the Combination, subject to the approval of the Sabine shareholders, the board of directors of Sabine voted to amend the 2014 LTIP to increase the total number of Common Shares reserved for issuance in connection with awards under the 2014 LTIP from 20 million to 40 million, effective as of the date of such shareholder approval.

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Item 6. Selected Financial Data

The following selected historical financial and operating information was derived from Sabine’s Consolidated Financial Statements as of and for the five years ended December 31, 2014. The selected financial data should be read in conjunction with the Company’s Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements and Supplemental Information on Oil and Natural Gas Producing Activities in “Part I, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Part II, Item 8. Financial Statements and Supplementary Data.”

	Year Ended December 31,
	2014		2013		2012		2011		2010
	(in thousands, except per share amounts)								(unaudited)
Total revenues	$	464,723	$	354,978	$	177,446	$	201,552	$	133,452
Total operating expenses		762,566		246,656		843,627		58,182		108,700
Total other income (expenses)		6,110		(97,745)		(20,618)		31,813		69,544
Net income (loss) before taxes		(291,733)		10,577		(686,799)		175,183		94,296
Income tax expense		34,987		—		—		—		—
Total operating income (loss) including noncontrolling interests		(326,720)		10,577		(686,799)		175,183		94,296
Less: Net income (loss) applicable to noncontrolling interest		—		—		17		(117)		(260)
Net income (loss) applicable to controlling interests		(326,720)		10,577		(686,782)		175,066		94,036
Net income (loss) per share (1)
Basic	$	(2.67)	$	0.09	$	(6.92)	$	2.01	$	1.14
Diluted	$	(2.67)	$	0.09	$	(6.92)	$	2.01	$	1.14
Weighted average shares outstanding – basic		122,237		118,863		99,179		87,084		82,570
Weighted average shares outstanding – diluted		122,237		118,863		99,179		87,084		82,570
Balance Sheet Data
Cash and cash equivalents	$	3,252	$	11,821	$	6,193	$	4,306	$	4,437
Total property, plant and equipment, net		2,066,068		1,380,042		1,256,210		1,351,815		648,044
Total Assets		2,438,350		1,678,719		1,560,559		1,529,069		801,552
Debt, net of discount		1,988,883		1,243,312		1,242,538		764,782		440,153
Total shareholders' (deficit) equity		(63,792)		201,010		200,433		624,128		247,207
Total liabilities and shareholders' (deficit) equity		2,438,350		1,678,719		1,560,559		1,529,069		801,552
Cash Flow Data
Cash flows provided by operating activities		209,201		217,198		144,166		159,032		105,715
Cash flows used in investing activities		(438,614)		(193,809)		(687,385)		(680,922)		(325,389)
Cash flows provided by (used in) financing activities		220,844		(17,761)		545,106		521,759		221,622
Other Financial Data
Adjusted EBITDA		330,880		296,057		194,986		194,272		129,222

(1) Earnings per share and share information presented in the consolidated financial statements for periods prior to December 16, 2014 are based on the Company’s common shares calculated by multiplying the number of Sabine O&G’s units outstanding at the end of each period using an exchange ratio as derived from the agreement governing the Combination. The Company retroactively adjusted its Statement of Shareholders’ (Deficit) Equity to reflect the legal capital of the accounting acquiree. Beginning on December 16, 2014, common shares are presented for the combined company.

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	For the Year Ended December 31,
	2014		2013		2012		2011		2010
									(unaudited)
Reconciliation of consolidated net income (loss) to Adjusted EBITDA
Net income (loss) applicable to controlling interests	$	(326,720)	$	10,577	$	(686,782)	$	175,066	$	94,036
Adjustments to derive adjusted EBITDA
Interest, net of capitalized interest		115,586		99,471		49,387		39,632		33,468
Depletion, depreciation and amortization		189,516		137,068		91,353		75,424		47,547
Impairments		423,092		1,125		664,438		4,192		1,711
Gain on bargain purchase		—		—		—		(99,548)		(372)
Other		25,974		1,739		599		439		1,156
Amortization of deferred rent		(72)		(249)		(532)		(406)		(320)
Accretion		958		952		862		628		493
Loss (gain) on derivative instruments		(120,848)		46,545		75,734		(1,272)		(51,996)
Option premium amortization		(11,593)		(1,171)		(56)		—		3,239
Income tax expense		34,987		—				—		—
Net income applicable to noncontrolling interests		—		—		(17)		117		260
Adjusted EBITDA	$	330,880	$	296,057	$	194,986	$	194,272	$	129,222

	For the Year Ended December 31,
	2014		2013		2012		2011		2010
									(unaudited)
Reconciliation of net cash flows from operating activities to Adjusted EBITDA
Net cash flow provided by operating activities	$	209,201	$	217,198	$	144,166	$	159,032	$	105,715
Interest adjustments		94,976		79,556		42,995		35,357		17,190
Working capital and other adjustments		26,703		(697)		7,825		(117)		6,317
Adjusted EBITDA	$	330,880	$	296,057	$	194,986	$	194,272	$	129,222

“Adjusted EBITDA” is a non-GAAP financial measure which Sabine uses in its business. This measure is not calculated or presented in accordance with US GAAP.

We believe the presentation of Adjusted EBITDA provides useful information to investors to evaluate the operations of our business excluding certain items and for the reasons set forth below. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow operating activities or any other measure of financial performance presented in accordance with US GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

We use Adjusted EBITDA for the following purposes:

· to assess the financial performance of our assets, without regard to financing methods, capital structure or historical cost basis;

· to assess our operating performance and return on capital as compared to those of other companies in the oil and gas industry, without regard to financing or capital structure;

· to assess the viability of acquisition and capital expenditure projects and the overall rates of return on alternative investment opportunities;

· to assess the ability of our assets to generate cash sufficient to pay interest costs and support indebtedness;

· for various purposes, including strategic planning and forecasting;

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· the Term Loan Facility and the indenture governing the 2017 Notes contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness unless the ratio of adjusted consolidated EBITDA to adjusted consolidated interest expense and other fixed charges over the trailing four fiscal quarters will be at least 2.0 to 1.0 (subject to exceptions for borrowings within certain limits);

· the Legacy Forest Notes contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness unless the ratio of adjusted consolidated EBITDA to adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.25 to 1.00 (subject to exceptions within certain limits); and

· the New Revolving Credit Facility requires us to comply with a financial maintenance ratio in the form of a first lien secured leverage ratio not to exceed 3.0 to 1.0 which is defined as a ratio of consolidated first lien secured debt as of the last day of a fiscal quarter to adjusted EBITDA for the period of four fiscal quarters then ending.

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Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains “forward- looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from expectations include changes in oil and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of oil and natural gas properties onshore in the United States. Our properties are primarily focused in three core geographic areas:

· East Texas targeting the Cotton Valley Sand, and Haynesville Shale ~~and Pettet~~ formations;

South Texas, targeting the Eagle Ford Shale formation; and

North Texas, targeting the Granite Wash formation.

Our ~~full~~2016 ~~year 2015~~ capital expenditures are forecasted to total approximately $~~230~~18 million ~~to $275 million~~. As a result, we expect production growth from our ~~2015~~2016 capital program will not offset production declines, which will result in material decreases to our production and related cash flows. Consistent with our historical practice, we periodically review our capital expenditures and adjust our budget based on liquidity, commodity prices and drilling results.

~~We expect to focus operations in the exploration and production segment of the energy industry in the United States.~~ Our ~~gathering~~MD&A ~~and~~includes ~~processing assets are primarily dedicated to supporting~~ the ~~natural~~following ~~gas volumes we produce and do not generate any material amounts of revenue. Our ability to develop and produce current reserves and add additional reserves is driven by several factors, including:~~sections;

· ~~success~~Chapter in11 ~~the~~Filings ~~drilling~~- a description of ~~new~~our ~~wells;~~recent events and our Chapter 11 filings

· ~~commodity~~The ~~prices;~~Combination - a description of the 2014 combination with Forest Oil Corporation

· ~~the~~Sources ~~availability~~ of ~~attractive acquisition opportunities and our ability to execute them;~~Revenue

· ~~the~~Principal ~~activities~~Components ~~and elections~~ of ~~third~~Cost ~~parties under our joint development agreements;~~Structure

· ~~the~~Significant ~~availability of capital and the amount we invest in the leasing and development of properties and the drilling of wells;~~Transactions

· ~~facility~~Results orof ~~equipment~~Operations ~~availability~~- ~~and~~an ~~unexpected~~analysis ~~delays~~of orour ~~downtime,~~consolidated ~~including~~results ~~delays~~of ~~imposed~~operations byfor orthe ~~resulting~~annual ~~from~~periods ~~compliance~~presented ~~with~~in ~~regulatory~~our ~~requirements;~~financial ~~and~~statements

64 · Liquidity, Capital Resources and Financial Position - an analysis of our cash flows, sources and uses of cash, contractual obligations and commercial commitments

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· Chapter ~~the~~11 ~~rate at which production volumes naturally decline.~~Filings

~~Ability~~On July 15, 2015, we and certain of our subsidiaries, including Giant Gas Gathering LLC, Sabine Bear Paw Basin LLC, Sabine East Texas Basin LLC, Sabine Mid-Continent Gathering LLC, Sabine Mid-Continent LLC, Sabine Oil & Gas Finance Corp., Sabine South Texas Gathering LLC, Sabine South Texas LLC and Sabine Williston Basin LLC (collectively, the “Filing Subsidiaries” and, together with us, the “Debtors”), filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under the Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York (the “Bankruptcy Court”). The Debtors Chapter 11 cases (the “Chapter 11 Cases”) are being jointly administered under the case styled In re Sabine Oil & Gas Corporation, et al, Case No. 15-11835. The Debtors will continue to ~~Continue~~operate their businesses as a“debtors-in-possession” ~~Going~~under ~~Concern~~the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

WeBy ~~have~~certain ~~significant~~“first ~~pending~~day” ~~maturities~~motions onfiled ~~our debt obligations. If we are unable to refinance our 2017 Notes to mature at least 91 days after December 31, 2018, our Term Loan Facility~~ in anthe ~~outstanding~~Chapter ~~amount~~11 ~~of $700 million will mature on November 16~~Cases, ~~2016.~~we ~~Our~~obtained ~~New~~Bankruptcy ~~Revolving~~Court ~~Credit~~approval ~~Facility~~to, ~~which~~among ~~currently~~other ~~has~~things ~~$971~~and ~~million~~subject ~~of debt outstanding, will mature on April 7, 2016. Our ability~~ to ~~repay~~ the ~~principal~~terms ~~amount~~ of ~~our debt upon~~ the ~~pending~~orders ~~maturities~~entered ~~has been negatively impacted~~ by ~~significant~~the ~~decreases~~Bankruptcy inCourt, ~~the~~pay ~~market~~certain ~~price~~employee ~~for oil~~wages, ~~natural~~health ~~gas,~~benefits and ~~NGLs~~certain ~~during~~other ~~the~~employee ~~fourth quarter of 2014 with continued weakness into the first quarter of 2015. Additionally~~obligations, ~~our~~pay ~~borrowing~~certain ~~base~~lienholders ~~under~~and ~~our~~forward ~~New~~funds ~~Revolving Credit Facility is subject~~ to ~~its~~third ~~next semi-annual redetermination in April 2015. Based on discussions with the lenders under our New Revolving Credit Facility~~parties, weincluding ~~believe~~royalty ~~that~~holders ~~our~~and ~~borrowing~~other ~~base may be decreased significantly~~partners. ~~Because~~ our New Revolving Credit Facility is fully drawn, any decrease in our borrowing base as a result of the redetermination will result in a deficiency which must be repaid within 30 days or in six monthly installments thereafter, at our election. The uncertainty associated with our ability to repay our outstanding debt obligations as they become due raises substantial doubt about our ability to continue as a going concern.

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deposited into a segregated account, which is reflected as Cash in the Consolidated Balance Sheet as of December 31, 2015, and is used solely to pay for the operations of the prepetition collateral properties.

The Combination

On December 16, 2014, the Legacy Sabine Investors contributed the equity interests in Sabine O&G to Sabine Oil & Gas Corporation, which was then known as Forest Oil Corporation. In exchange for this contribution, the Legacy Sabine Investors received shares of Sabine common stock and Sabine Series A preferred stock, collectively representing approximately a 73.5% economic interest in Sabine and 40% of the total voting power in Sabine. Immediately following the contribution, Sabine O&G and related holding companies merged into Forest, with Forest surviving the mergers. Holders of Sabine common stock immediately prior to the closing of the Combination continued to hold their Sabine common stock following the closing, which immediately following the closing represented approximately a 26.5% economic interest in Sabine and 60% of the total voting power in Sabine. On December 19, 2014, Forest Oil Corporation changed its name to Sabine Oil & Gas Corporation. In connection with the completion of the Combination, the executive management team of Sabine O&G ~~were~~was appointed as the executive management team of Sabine, and the members of the former executive management team of Forest resigned or were removed from their positions.

Sabine O&G is considered the predecessor of Sabine or acquirer of Forest, and, accordingly, the historical financial statements and results of operations of Sabine for periods prior to the completion of the Combination are those of Sabine O&G, as the predecessor, and the historical financial statements and results of operations for the year ending December 31, 2014 include the historical financial statements of Sabine O&G, with the combined operating results of Forest consolidated therein only from the closing date of December 16, 2014 and thereafter. Accordingly, our results of operations discussed in this section may not be indicative of our results of operation following the Combination. The underlying Forest assets acquired and liabilities assumed by us were based on their respective fair market values. No goodwill resulted from the Combination as the fair value of assets acquired and liabilities assumed approximated purchase price.

Prior to the Combination, Sabine O&G was a privately-held company and Forest’s common stock was listed on the NYSE. ~~Following~~Currently, the ~~Combination,~~Company’s ~~our~~ common stock trades on the ~~OTCQB,~~OTC ~~currently~~Pink Marketplace under the ticker symbol “SOGC”.

Source of Revenues

We derive substantially all of our revenue from the sale of oil, NGLs and natural gas that are produced from our interests in properties located onshore in the United States. Oil and natural gas prices are inherently volatile and are influenced by many factors outside of our control. Oil and natural gas prices decreased significantly in the second half of 2014 and have remained low ~~throughout~~through the first quarter of ~~2015~~2016. If commodity prices remain at current levels, we expect significantly lower revenues and operating cash flows compared to historical results.

ToIn ~~achieve~~the ~~more~~past ~~predictable cash flows and to reduce exposure to downward price fluctuations,~~ we ~~use~~have used derivative instruments to hedge future sales prices on a significant portion of oil and natural gas production., Weto ~~currently~~achieve ~~use~~more apredictable ~~combination~~cash offlows ~~fixed~~and to reduce exposure to downward price ~~oil~~fluctuations. ~~and~~However, ~~natural~~as ~~gas~~a ~~swaps~~result ~~and~~of ~~options~~certain ~~for~~events ~~which~~of wedefault ~~receive~~under aour ~~fixed~~derivative ~~price~~contracts, ~~(via~~all ~~either~~our ~~swap~~derivative instruments have been

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~~price,~~terminated ~~floor~~and orwe ~~collar~~no orlonger ~~put~~have ~~price)~~any ~~for~~derivative ~~future~~contracts ~~production~~ in ~~exchange for a payment of the variable market price received at the time future production is sold~~place. See “Commodity Hedging Activities” below for more information regarding our economic hedge positions.

Principal Components of Cost Structure

Lease operating, marketing, gathering, transportation and other. These are costs incurred to produce oil and natural gas and deliver the volumes to the market, together with the costs incurred to maintain producing properties, such as maintenance and repairs. These costs, which have both a fixed and variable component, are primarily a function of volume of oil and natural gas produced from currently producing wells and incrementally from new production from drilling and completion activities. Lease operating expenses include workover expenses.

Production and ad valorem taxes. Production taxes are paid on produced oil and natural gas primarily based on the wellhead value of production. The applicable rates vary across the areas in which we operate. As the proportion of production changes from area to area, production tax rates will vary depending on the quantities produced from each area and the applicable production tax rates then in effect. Ad valorem taxes are typically computed on the basis of a property valuation as determined by certain state and local taxing authorities and will vary annually based on commodity price fluctuations.

General and administrative. This cost includes all overhead associated with our business activities, including payroll and benefits for corporate staff, costs of maintaining our headquarters, audit, tax, legal and other professional and consulting fees, insurance and other costs necessary in the management of our production and development operations.

As a full cost method of accounting company, we capitalize general and administrative expenses that are directly attributable to our oil and natural gas activities. We capitalized $109.12 million, $610.61 million and $26.76 million for the years ended December 31, 2015, 2014, ~~2013~~ and ~~2012~~2013, respectively.

· Depletion, depreciation and amortization (“DD&A”). This includes the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. As a full cost company, we capitalize all costs associated with acquisition, exploration, development and related efforts and deplete these costs using the units-of-production method.

· Impairments. We evaluate the impairment of proved oil and natural gas properties on a full cost basis. Property impairment charges result from application of the ceiling test under the full cost accounting rules, which we are required to calculate on a quarterly basis. The ceiling test requires that a non-cash impairment charge be taken to reduce the carrying value of oil and natural gas properties if the carrying value exceeds a defined cost-center ceiling. Because current commodity prices, and related calculations of the discounted present value of reserves, are significant factors in the full cost ceiling test, impairment charges may result from declines in oil, NGLs and natural gas prices. For the years ended December 31, ~~2014~~2015, ~~2013~~2014 and ~~2012~~2013, we recorded $1.6 billion, $247.7 million, and no impairment, ~~and $641.8 million,~~ respectively, of non-cash impairment charges as a result of the full cost ceiling limitation.

We could have a future reduction in asset carrying value for oil and natural gas properties if the average of the unweighted first day of the month oil and natural gas prices for the prior twelve month period declines. For example, as of December 31, ~~2014~~ 2015, the unweighted average of the historical first day of the month pricing for oil and natural gas were $9450.9928 per Bbl and $42.3558 per MMbtu, respectively, compared to $8246.7226 per Bbl and $32.8839 per MMbtu for oil and natural gas, respectively, in March ~~2015~~2016. Holding all other factors constant, if commodity prices used in our year-end reserve estimates were decreased by $124.2702 per Bbl for crude oil and $0.4719 per Mcf for natural gas, thereby approximating the pricing environment existing in March ~~2015~~2016, our estimated discounted future cash flows from proved reserves at December 31, 2015 ~~2014~~ would decrease by approximately $~~363~~69 million, or 21 14%. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. In addition, we analyze our unevaluated leasehold and transfer to evaluated properties leasehold that can be associated with proved reserves, leasehold that expired in the quarter or leasehold that is

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~~leasehold~~not ~~that~~a ~~can~~part beof ~~associated~~our ~~with~~development ~~proved~~strategy ~~reserves,~~and ~~leasehold~~will ~~that~~be ~~expired~~abandoned. inAs ~~the~~of ~~quarter~~December or31, ~~leasehold~~2015 ~~that~~the isCompany ~~not~~has ano ~~part~~unevaluated ofproperties ~~our~~excluded ~~development~~from ~~strategy~~the ~~and~~full ~~will~~cost ~~be abandoned~~pool.

We evaluate gas gathering and processing equipment for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For the years ended December 31, 2015, 2014, ~~2013~~ and ~~2012~~2013, we recorded no impairment, ~~charges for gas gathering and processing equipment of~~ $1.7 million, and no impairment, ~~and $21.4 million,~~ respectively, based on expected present value and estimated future cash flows using current volume throughput and pricing assumptions. Additionally, for the years ended December 31, 2015, 2014, ~~2013~~ and ~~2012~~2013, we recorded impairment charges for other assets of $01.21 million, $10.12 million and $1.21 million, respectively.

Goodwill is tested for impairment on an annual basis as of October 1 of each year and more frequently if changes in circumstances warrant. Due to a drop in commodity prices and the $247.7 million ceiling impairment in 2014, a December 31, 2014 impairment test was also performed and resulted in the impairment of our $173.5 million of goodwill for the year ended December 31, 2014. No goodwill remains as of December 31, 2015 and 2014.

· ~~Interest.~~Other ~~During~~operating the periods presented, we have historically financed a portion of our working capital requirements and acquisitions with borrowings under the Former Revolving Credit Facility, the New Revolving Credit Facility and the Term Loan Facilityexpenses. AsOther aoperating ~~result,~~expenses weconsist ~~incurred~~primarily ~~interest expense that was affected by the level~~ of ~~drilling,~~transaction ~~completion~~costs ~~and~~related ~~acquisition~~to ~~activities, as well as fluctuations in interest rates and our financing decisions. We also incurred interest expense on our 2017 Notes, and, for~~ the ~~period following the completion of the~~ Combination ~~on December 16, 2014, the 2019 Notes and 2020 Notes~~. As of March 15, 2015, the total outstanding principal amount of our long-term indebtedness was $2.821 billion, consisting of indebtedness under the New Revolving Credit Facility, the 2017 Notes, the Legacy Forest Notes, and the Term Loan Facility, which will continue to expose us to interest rates. As of March 15, 2015, no extensions of credit are available under the New Revolving Credit Facility. We will likely continue to incur significant interest expense as we continue to grow. To date, we have not entered into any interest rate hedging arrangements to mitigate the effects of interest rate changes. Additionally, we capitalized $6.5 million, $13.0 million and $4.3 million of interest expense for the years ended December 31, 2014, 2013 and 2012, respectively.

· ~~Income Tax Expense~~Interest. ~~Prior~~During to the ~~Combination~~periods presented, we ~~were~~have historically financed a ~~limited~~portion ~~liability~~of ~~company~~our ~~treated~~working ascapital arequirements ~~partnership~~and ~~for~~acquisitions ~~federal~~with ~~and~~borrowings ~~state~~under ~~income~~the ~~tax~~Former ~~liabilities~~Revolving ~~and/or~~Credit ~~benefits~~Facility, ofthe ~~Sabine~~New ~~O&G~~Revolving ~~being~~Credit ~~passed~~Facility ~~through~~and tothe ~~its~~Term ~~member~~Loan Facility. ~~Accordingly~~As a result, nowe ~~provision~~incurred ~~for~~interest ~~federal~~expense orthat ~~state~~was ~~income~~affected ~~taxes~~by ~~was~~the ~~recorded~~level ~~prior~~of todrilling, ~~the~~completion ~~Combination~~and acquisition activities, as well as fluctuations in interest rates and our ~~equity~~financing ~~holders~~decisions. ~~were~~We ~~responsible~~also ~~for~~incurred ~~income~~interest ~~tax~~expense on our ~~profits.~~2017 InNotes, ~~connection~~and, ~~with~~for the period following the completion of the Combination on December 16, we2014, ~~merged~~the ~~into~~2019 aNotes ~~corporation~~and 2020 Notes. As of March 21, 2016, the total outstanding principal amount of our long-term indebtedness was $2.752 billion, consisting of indebtedness under the New Revolving Credit Facility, the 2017 Notes, the Legacy Forest Notes, and ~~became~~the ~~subject~~Term Loan Facility, which will continue to ~~federal~~expose ~~and~~us ~~state~~to ~~income~~interest ~~taxes~~rates. ~~Our~~As ~~book~~of ~~and~~March ~~tax~~21, ~~basis~~2016, inno ~~assets~~extensions ~~and~~of ~~liabilities~~credit ~~differed~~are atavailable under the ~~time~~New ofRevolving ~~our~~Credit ~~change~~Facility. inTo ~~tax~~date, ~~status~~we ~~due~~have ~~primarily~~not entered into any interest rate hedging arrangements to ~~different~~mitigate ~~cost~~the ~~recovery~~effects ~~periods~~of ~~utilized~~interest ~~for~~rate ~~book~~changes. Additionally, we capitalized $3.3 million, $6.5 million and ~~tax~~$13.0 ~~purposes~~million of interest expense for ~~our~~the ~~oil~~years ~~and~~ended ~~natural~~December ~~gas~~31, ~~properties~~2015, 2014 and 2013, respectively.

~~For~~· ~~the~~Reorganization ~~year December 31, 2014, we recorded total income tax expense of $35 million~~Expense. The ~~significant~~Company ~~differences~~uses ~~between~~this ~~our~~category ~~blended federal and state statutory income tax rate of 36% were primarily due~~ to ~~earnings~~reflect ~~prior to~~ the ~~corporate~~net ~~merger~~revenues, ~~that are not subject to corporate income tax~~expenses, ~~recording~~gains ~~the initial book~~ and ~~tax~~losses ~~basis~~that ~~differences~~are ~~associated with~~ the ~~change~~result inof ~~tax~~the ~~status,~~reorganization and ~~impairment~~restructuring of ~~non-deductible goodwill and changes in~~ the ~~valuation allowance~~business.

67Professional 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. For additional information, please see Note 14 to our financial statements included herein. The terminated contracts represent the estimated claims related to rejection of approved contracts that were not previously included in the 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. The Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) 852, Reorganizations, 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.

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Income Tax Expense. Prior to the Combination, we were a limited liability company treated as a partnership for federal and state income tax liabilities and/or benefits of Sabine O&G being passed through to its member. Accordingly, no provision for federal or state income taxes was recorded for the year ended December 31, 2013 prior to the Combination as our equity holders were responsible for income tax on our profits. In connection with the completion of the Combination, we merged into a corporation and became subject to federal and state income taxes. Our book and tax basis in assets and liabilities differed at the time of our change in tax status due primarily to different cost recovery periods utilized for book and tax purposes for our oil and natural gas properties.

For the year December 31, 2014, we recorded total income tax expense of $35 million. The significant differences between our blended federal and state statutory income tax rate of 36% were primarily due to earnings prior to the corporate merger that are not subject to corporate income tax, recording the initial book and tax basis differences associated with the change in tax status, and impairment of non-deductible goodwill and changes in the valuation allowance. For the year December 31, 2015, we recorded total income tax expense of $3.1 million attributable to an increase in the valuation allowance which offsets the additional deferred tax assets recorded through purchase accounting for Forest. The significant differences between our blended and state statutory income tax rate of 35.5% were primarily due to the change in the Company’s full valuation allowance recorded against the net deferred tax asset balance, changes in estimate for the 2014 period and state income taxes.

Significant Transactions

Other than the Combination, which is described under “The Combination” above, the following table presents a summary of our significant property acquisitions from ~~2012~~2013 through ~~2014~~2015:

Primary locations of acquired properties	Transaction Date	Purchase Price
		(in millions)
North Texas – Granite Wash (TX)	June 2014	$	18
North Texas – Granite Wash (TX)	March 2014	$	20
South Texas – Eagleford Shale (TX)	April 2013	$	15
North Texas – Granite Wash/Cleveland Sand (TX)	December 2012	$	658
South Texas – Eagle Ford Shale (TX)	December 2012	$	79

Our acquisitions were financed with a combination of funding from equity contributions from sponsors, borrowings under the Former Revolving Credit Facility and Term Loan Facility and cash flow from operations. Because of our substantial recent acquisition activity, the discussion and analysis of our historical financial condition and results of operations for the periods discussed below may not necessarily be comparable with or applicable to future results of operations. Our historical results include the results from recent acquisitions beginning on the closing dates indicated in the table above.

In ~~December 2013,~~2015 we sold our working interest in ~~approximately~~various ~~27,000~~oil ~~net~~and ~~acres~~gas properties in ~~the~~our ~~Texas~~non-core ~~Panhandle~~areas ~~and~~at ~~surrounding~~auction ~~Oklahoma areas~~ for ~~an adjusted purchase price of~~ approximately $~~169~~6.4 million. ~~This~~In ~~includes~~December 2013, ~~primarily~~we ~~the~~sold ~~Cleveland~~our ~~Sand~~working ~~assets~~interest ~~acquired~~ in ~~2012.~~approximately ~~In addition~~27,000 wenet ~~sold~~acres ~~all~~in ofthe ~~our~~Texas ~~oil~~Panhandle and ~~natural~~surrounding ~~gas~~Oklahoma ~~properties~~areas ~~located~~(including in the ~~Rocky~~Cleveland ~~Mountain~~Sands ~~region~~assets acquired in ~~the~~2012) ~~second~~for ~~quarter~~an adjusted purchase price of ~~2012~~approximately $169 million.

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Results of Operations

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

The following table sets forth selected operating data for the year ended December 31, 2015 compared to the year ended December 31, 2014:


	For the Year Ended				Amount of
	December 31,				Increase		Percent
	2015		2014		(Decrease)		Change
	(in thousands)
Revenues
Oil, natural gas liquids and natural gas	$	334,984	$	462,363	$	(127,379)	(28)	%
Other		2,227		2,360		(133)	(6)	%
Total revenues		337,211		464,723		(127,512)	(27)	%

Operating expenses
Lease operating		88,855		51,262		37,593	73	%
Marketing, gathering, transportation and other		33,901		23,621		10,280	44	%
Production and ad valorem taxes		17,592		18,161		(569)	(3)	%
General and administrative		42,687		30,373		12,314	41	%
Depletion, depreciation and amortization		182,417		189,516		(7,099)	(4)	%
Accretion		1,930		958		972	101	%
Impairments		1,576,728		423,092		1,153,636		*
Other operating expenses		24,431		25,583		(1,152)		*
Total operating expenses		1,968,541		762,566		1,205,975	158	%

Other income (expenses)
Interest, net of capitalized interest (2)		(180,285)		(115,559)		64,726	56	%
Gain on derivative instruments		33,897		121,669		87,772		*
Total other income (expenses)		(146,388)		6,110		152,498		*
Reorganization items, net		(458,838)		—		(458,838)		*
Net loss before income taxes		(2,236,556)		(291,733)		(1,944,823)		*
Income tax expense		(3,087)		(34,987)		31,900		*
Net loss	$	(2,239,643)	$	(326,720)	$	(1,912,923)		*
Reconciliation to derive Adjusted EBITDA (1):
Interest, net of capitalized interest		180,285		115,559
Depletion, depreciation and amortization		182,417		189,516
Impairments		1,576,728		423,092
Other		19,609		25,929
Accretion		1,930		958
Loss (gain) on derivative instruments		62,790		(120,848)
Option premium amortization		(4,645)		(11,593)
Reorganization items, net		458,838		—
Income tax expense		3,087		34,987
Adjusted EBITDA (1)	$	241,396	$	330,880

* Not meaningful or applicable

(1)

Adjusted EBITDA is a non-GAAP financial measure. Please see “—Non-GAAP Financial Measure.”

(2)

Interest at contractual interest rates would have been $193.5 million for 2015. As of the petition date, interest is no longer being accrued on the Term Loan Facility, 2017 Notes, 2019 Notes and 2020 Notes.

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	For the Year Ended				Amount of
	December 31,				Increase		Percent
	2015		2014		(Decrease)		Change
Oil, NGL and natural gas sales by product (in thousands):
Oil	$	120,996	$	181,313	$	(60,317)	(33)	%
NGL		41,610		62,420		(20,810)	(33)	%
Natural gas		172,378		218,630		(46,253)	(21)	%
Total	$	334,984	$	462,363	$	(127,380)	(28)	%

Production data:
Oil (MBbl)		2,786.40		2,169.52		616.88	28	%
NGL (MBbl)		3,168.98		2,120.56		1,048.42	49	%
Natural gas (Bcf)		66.22		49.22		17.00	35	%
Combined (Bcfe) (1)		101.95		74.96		26.99	36	%

Average prices before effects of economic hedges (2):
Oil (per Bbl)	$	43.42	$	83.57	$	(40.15)	(48)	%
NGL (per Bbl)	$	13.13	$	29.44	$	(16.31)	(55)	%
Natural gas (per Mcf)	$	2.60	$	4.44	$	(1.84)	(41)	%
Combined (per Mcfe) (1)	$	3.29	$	6.17	$	(2.88)	(47)	%

Average realized prices after effects of economic hedges (2):
Oil (per Bbl)	$	60.83	$	81.79	$	(20.97)	(26)	%
NGL (per Bbl)	$	13.13	$	29.44	$	(16.31)	(55)	%
Natural gas (per Mcf)	$	3.26	$	4.30	$	(1.04)	(24)	%
Combined (per Mcfe)(1)	$	4.19	$	6.02	$	(1.84)	(30)	%

Average costs (per Mcfe) (1):
Lease operating	$	0.87	$	0.68	$	0.19	28	%
Marketing, gathering, transportation and other	$	0.33	$	0.32	$	0.01	3	%
Production and ad valorem taxes	$	0.17	$	0.24	$	(0.07)	(29)	%
General and administrative	$	0.42	$	0.41	$	0.01	2	%
Depletion, depreciation and amortization	$	1.79	$	2.53	$	(0.74)	(29)	%

(1)

Oil and NGL production was converted at 6 Mcf per Bbl to calculate combined production and per Mcfe amounts.

(2)

Average prices shown in the table reflect prices both before and after the effects of cash settlements on commodity derivative transactions. The Company’s calculation of such effects includes gains or losses on cash settlements for commodity derivative transactions.

Oil, natural gas liquids and natural gas sales. Revenues from production of oil and natural gas decreased from $462.4 million in 2014 to $335.0 million in 2015, a decrease of 28%. This decrease of $127.4 million was primarily the result of a decrease in oil, natural gas liquids and natural gas revenues of $60.3 million, $20.8 million and $46.3 million, respectively, due to a decrease in prices of $40.15/Bbl, $16.31/Bbl and $1.84/Mcf, respectively. These decreases were partially offset by a 36% increase in production, primarily due to the Combination and our East Texas development activities.

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The following table sets forth additional information concerning our production volumes for the year ended December 31, 2015 compared to the year ended December 31, 2014:


	For the Year Ended
	December 31,		Percent
	2015	2014	Change
	(in Bcfe)
South Texas	19.96	22.65	(12)	%
East Texas	72.76	44.39	64	%
North Texas	9.23	7.92	16	%
Total	101.95	74.96	36	%

Lease operating. Lease operating expenses increased from $51.3 million in 2014 to $88.9 million in 2015, an increase of 73%. The increase in lease operating expense of $37.6 million is primarily due to an increase in producing properties as a result of the Combination. Lease operating expenses increased from $0.68 per Mcfe in 2014 to $0.87 per Mcfe in 2015. The increase of $0.19 per Mcfe in the year ended December 31, 2015 versus the year ended December 31, 2014 is primarily due to higher cost legacy Forest production. The following table displays the lease operating expense by area for the years ended December 31, 2015 and 2014:


	For the Year Ended
	December 31,				December 31,
	2015		Per Mcfe		2014		Per Mcfe
	(in thousands, except per Mcfe data)
South Texas	$	18,737	$	0.94	$	8,185	$	0.36
East Texas		66,961		0.92		40,089		0.94
North Texas		3,157		0.34		3,008		0.38
Other		—		—		(20)		—
Total	$	88,855	$	0.87	$	51,262	$	0.68

Marketing, gathering, transportation and other. Marketing, gathering, transportation and other expenses increased from $23.6 million in 2014 to $33.9 million in 2015, an increase of 44%. Marketing, gathering, transportation and other expenses increased on a per unit basis from $0.32 per Mcfe in 2014 to $0.33 per Mcfe in 2015. The increase of $10.3 million in the year ended December 31, 2015 versus the year ended December 31, 2014 is primarily due to increased processing of gas volumes associated with our development activities throughout 2014 and 2015, coupled with increasing oil volumes associated with development activities and the Combination.

Production and ad valorem taxes. Production and ad valorem taxes decreased from $18.2 million in 2014 to $17.6 million in 2015, a decrease of 3%. Production and ad valorem taxes decreased on a per unit basis from $0.24 per Mcfe in 2014 to $0.17 per Mcfe in 2015. The decrease of $0.07 per Mcfe in the year ended December 31, 2015 versus the year ended December 31, 2014 is primarily due to lower pricing of 48% per Bbl for oil and 41% per Mcf for natural gas, coupled with processing high cost gas exemptions in 2015, partially offset by increased production associated with the Combination. We expect to experience continued variability in our production taxes as a result of timing of approval for high cost gas tax exemptions. Production and ad valorem taxes as a percentage of oil and natural gas revenues were 5% and 4% for 2015 and 2014, respectively.

General and administrative. General and administrative expenses increased from $30.4 million in 2014 to $42.7 million in 2015, an increase of $12.3 million, or 41%, primarily as a result of higher overhead associated with the Combination. General and administrative expenses increased on a per unit basis from $0.41 per Mcfe in 2014 to $0.42 per Mcfe in 2015.

Depletion, depreciation and amortization. DD&A decreased from $189.5 million in 2014 to $182.4 million in 2015, a decrease of $7.1 million. DD&A decreased from $2.53 per Mcfe in 2014 to $1.79 per Mcfe in 2015, or a decrease of 4%. The decrease in the DD&A rate per Mcfe is driven by a lower amortization base due to recent ceiling test impairments resulting from declines in the prior 12 month pricing and lower PV-10 estimates compared to net book value, coupled with increased total reserves from the Combination.

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Impairments. In 2015, as a result of a decrease in commodity pricing, there were non-cash impairment charges related to oil and natural gas properties of $1.6 billion and impairment charges for other assets of $1.1 million. In 2014, there were non-cash impairment charges related to oil and gas properties of $247.7 million, impairment charges for gas gathering and processing equipment of $1.7 million and impairment charges for other assets of $0.2 million. Additionally, due to a drop in commodity prices and the $247.7 million ceiling impairment in 2014 the Company tested goodwill for impairment. At December 31, 2014 goodwill impairment test resulted in the impairment of our $173.5 million of goodwill for the year ended December 31, 2014.

Other operating expenses. Other operating expenses in 2015 consist primarily of $19.8 million of transaction costs related to the Combination and $2.9 million of charges related to marketing contract volume commitments. Other operating expenses in 2014 consist primarily of $25.5 million of transaction costs related to the Combination and $2.0 million for the write-off of previously deferred public offering costs related to offerings which were aborted prior to our decision to commence the Combination, partially offset by the gain on a sale of other assets of $1.5 million.

Interest expense. Interest expense increased from $115.6 million in the year ended December 31, 2014 to $180.3 million in the year ended December 31, 2015, an increase of $64.7 million, or 56%, primarily as a result of increased borrowings on the New Revolving Credit Facility, the assumption of the 2019 Notes and 2020 Notes in connection with the consummation of the Combination on December 16, 2014 and increased amortization of associated debt discounts. No interest expense has been recognized subsequent to the petition date on the Term Loan, 2017 Notes, 2019 Notes or the 2020 Notes.

Gain on derivative instruments. Gains from the change in fair value of derivative instruments as well as cash settlements on commodity derivatives are recognized in our results of operations. During the years ended December 31, 2015 and 2014, we recognized net gains on derivative instruments of $33.9 million and $121.7 million, respectively. The Company’s Bankruptcy Petition in July 2015 represented an event of default under Sabine’s existing derivative agreements resulting in a termination right by counterparties on all derivative positions at July 15, 2015. Additionally, certain of the Company’s derivative positions were terminated prior to July 15, 2015 as a result of defaults under Sabine’s derivative agreements that occurred prior to the filing of the Bankruptcy Petition.

Reorganization Items, net. Professional fees included in Reorganization Items, net represent professional fees incurred for post-petition expenses which would not have otherwise been incurred by the Company and are presented as reorganization items. Terminated contracts represent the estimated claims related primarily to rig and servicing contracts, certain office leases and other executory contracts, and were not previously included in the Consolidated Balance Sheets as the liability was contingent in nature or other executory contracts included in commitments and contingencies.


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

Income Tax Expense. Prior to the Combination, no provision for federal or state income taxes was recorded, as we were a limited liability company and not subject to federal or state income tax. In connection with the completion of the Combination, we merged into a corporation and became subject to federal and state income taxes. For December 31, 2014, we recorded an estimated net deferred tax expense of $35.0 million to recognize a deferred tax liability for the initial book and tax basis difference associated with the change in tax status, impairment of a non-deductible goodwill and changes in the valuation allowance associated with the Combination. We recorded an additional deferred tax expense of $3.1 million in December 2015 for adjustments related to the net deferred tax expense estimate recorded in December 2014.

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Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

The following table sets forth selected operating data for the year ended December 31, 2014 compared to the year ended December 31, 2013:

	For the Year Ended				Amount of
	December 31,				Increase		Percent
	2014		2013		(Decrease)		Change
	(in thousands)
Revenues
Oil, natural gas liquids and natural gas	$	462,363	$	354,223	$	108,140	31	%
Other		2,360		755		1,605	213	%
Total revenues		464,723		354,978		109,745	31	%
Operating expenses
Lease operating		51,262		44,620		6,642	15	%
Marketing, gathering, transportation and other		23,621		17,567		6,054	34	%
Production and ad valorem taxes		18,161		17,824		337	2	%
General and administrative		30,373		27,469		2,904	11	%
Depletion, depreciation and amortization		189,516		137,068		52,448	38	%
Accretion		958		952		6	1	%
Impairments		423,092		1,125		421,967		*
Other operating expenses (income)		25,583		(858)		26,441		*
Total operating expenses		762,566		245,767		516,799	210	%
Other income (expenses)
Interest, net of capitalized interest		(115,586)		(99,471)		16,115	16	%
Gain on derivative instruments		121,669		814		(120,855)		*
Other income		27		23		(4)		*
Total other income (expenses)		6,110		(98,634)		(104,744)		*
Net (loss) income before income taxes	$	(291,733)	$	10,577	$	(302,310)		*
Net income (loss), including noncontrolling interests		(291,733)		10,577		(302,310)		*
Income tax expense		(34,987)		—		(34,987)		*
Net (loss) income	$	(326,720)	$	10,577	$	(337,297)		*
Net income (loss) applicable to controlling interests	$	(326,720)	$	10,577	$	(337,297)		*
Reconciliation to derive Adjusted EBITDA (1):
Interest, net of capitalized interest		115,586		99,471
Depletion, depreciation and amortization		189,516		137,068
Impairments		423,092		1,125
Other		25,974		1,739
Amortization of deferred rent		(72)		(249)
Accretion		958		952
(Gain) loss on derivative instruments		(120,848)		46,545
Loss (gain) on derivative instruments		(120,848)		46,545
Option premium amortization		(11,593)		(1,171)
Income tax expense		34,987		—
Adjusted EBITDA (1)	$	330,880	$	296,057

* Not meaningful or applicable

(1)

Adjusted EBITDA is a non-GAAP financial measure. Please see “—Non-GAAP Financial Measure.”

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	For the Year Ended				~~Amount of~~	Amount of
	December 31,				~~Increase~~	Increase	Percent
	2014		2013		~~(Decrease)~~	(Decrease)	Change
Oil, NGL and natural gas sales by product (in thousands):
Oil	$	181,313	$	132,513	$	48,800	37	%
NGL		62,420		59,772		2,648	4	%
Natural gas		218,630		161,938		56,692	35	%
Total	$	462,363	$	354,223	$	108,140	31	%
Production data:
Oil (MBbl)		2,169.52		1,403.62		765.90	55	%
NGL (MBbl)		2,120.56		1,842.47		278.09	15	%
Natural gas (Bcf)		49.22		44.29		4.93	11	%
Combined (Bcfe) (1)		74.96		63.77		11.19	18	%
Average prices before effects of economic hedges (2):
Oil (per Bbl)	$	83.57	$	94.41	$	(10.84)	(11)	%
NGL (per Bbl)	$	29.44	$	32.44	$	(3)	(9)	%
NGL (Bbl)	$	29.44	$	32.44	$	(3.00)	(9)	%
Natural gas (per Mcf)	$	4.44	$	3.66	$	0.78	21	%
Combined (per Mcfe) (1)	$	6.17	$	5.55	$	0.62	11	%
Average realized prices after effects of economic hedges (2):
Oil (per Bbl)	$	81.79	$	90.49	$	(8.70)	(10)	%
NGL (per Bbl)	$	29.44	$	32.44	$	(3.00)	(9)	%
NGL (Bbl)	$	29.44	$	32.44	$	(3.00)	(9)	%
Natural gas (per Mcf)	$	4.30	$	4.82	$	(0.52)	(11)	%
Combined (per Mcfe)(1)	$	6.02	$	6.28	$	(0.26)	(4)	%
Combined (per Mcfe) (1)	$	6.02	$	6.28	$	(0.26)	(4)	%
Average costs (per Mcfe) (1):
Lease operating	$	0.68	$	0.70	$	(0.02)	(3)	%
Marketing, gathering, transportation and other	$	0.32	$	0.28	$	0.04	14	%
Production and ad valorem taxes	$	0.24	$	0.28	$	(0.04)	(14)	%
General and administrative	$	0.41	$	0.43	$	(0.02)	(5)	%
Depletion, depreciation and amortization	$	2.53	$	2.15	$	0.3738	18	%

(1)

Oil and NGL production was converted at 6 Mcf per Bbl to calculate combined production and per Mcfe amounts.

(2)

Oil, natural gas liquids and natural gas sales. Revenues from production of oil and natural gas increased from $354.2 million in 2013 to $462.4 million in 2014, an increase of 31%. This increase of $108.1 million was primarily the result of an increase in oil, natural gas liquids and natural gas revenues of $48.8 million, $2.6 million and $56.7 million, respectively, due to an increase in production in South Texas through an active and successful development program in this region as well as an increase in realized price for natural gas of 21%. These increases were partially offset by the December 2013 sale of our interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area and a decrease in realized price for oil of 11%.

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The following table sets forth additional information concerning our production volumes for the year ended December 31, 2014 compared to the year ended December 31, 2013:


	For the Year Ended
	December 31,		Percent
	2014	2013	Change
	(in Bcfe)
South Texas	22.65	9.89	129	%
East Texas	44.39	42.05	6	%
North Texas	7.92	11.83	(33)	%
Total	74.96	63.77	18	%

Lease operating expenses. Lease operating expenses increased from $44.6 million in 2013 to $51.3 million in 2014, an increase of 15%. The increase in lease operating expense of $6.6 million is primarily due to an increase in producing properties as a result of development activities in South Texas partially offset by the December 2013 sale of our interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area. Lease operating expenses decreased from $0.70 per Mcfe in 2013 to $0.68 per Mcfe in 2014. The decrease of $0.02 per Mcfe in the year ended December 31, 2014 versus the year ended December 31, 2013 is primarily due to the December 2013 sale of our interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area with offsetting increases in South Texas and East Texas as a result of increasing development activities. The following table displays the lease operating expense by area for the years ended December 31, 2014 and 2013:


	For the Year Ended
	December 31,				December 31,
	2014		Per Mcfe		2013		Per Mcfe
	(in thousands, except per Mcfe data)
South Texas	$	8,185	$	0.36	$	2,266	$	0.23
East Texas		40,089		0.94		36,183		0.86
North Texas		3,008		0.38		6,162		0.52
Other		(20)		—		9		—
Total	$	51,262	$	0.68	$	44,620	$	0.70

Marketing, gathering, transportation and other. Marketing, gathering, transportation and other expenses increased from $17.6 million in 2013 to $23.6 million in 2014, an increase of 34%. Marketing, gathering, transportation and other expense increased on a per unit basis from $0.28 per Mcfe in 2013 to $0.32 per Mcfe in 2014. The increase of $0.04 per Mcfe in the year ended December 31, 2014 versus the year ended December 31, 2013 is primarily due to increased processing of gas volumes associated with our South Texas development activities as well as gas volumes associated with our Haynesville development activities in East Texas, which were subject to higher fees due to lack of pipeline infrastructure, partially offset by decreases in the average rate per Mcfe due to the December 2013 sale of our interests in certain oil and gas properties in the Texas Panhandle and surrounding Oklahoma area coupled with increasing oil volumes associated with development activities in that area.

Production and ad valorem taxes. Production and ad valorem taxes increased from $17.8 million in 2013 to $18.2 million in 2014, an increase of 2%. Production and ad valorem taxes decreased on a per unit basis from $0.28 per Mcfe in 2013 to $0.24 per Mcfe in 2014. The decrease of $0.04 per Mcfe in the year ended December 31, 2014 versus the year ended December 31, 2013 is primarily due to a decrease in North Texas production due to the December 2013 sale of our interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area. This decrease in the rate per Mcfe is partially offset by increases in production tax expenses primarily due to increased production in the South Texas region which is incurring higher production taxes on oil, natural gas liquids and natural gas production. We expect to experience continued variability in our production taxes as a result of timing of approval for high cost gas tax exemptions. Production and ad valorem taxes as a percentage of oil and natural gas revenues were 4% and 5% for 2014 and 2013, respectively.

General and administrative expenses. General and administrative expenses increased from $27.5 million in 2013 to $30.4 million in 2014, an increase of $2.9 million, or 11%, ~~primarily~~ as a result of higher overhead associated with our growing

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business. General and administrative expenses decreased on a per unit basis from $0.43 per Mcfe in 2013 to $0.41 per Mcfe in 2014 ~~due to increased~~ production without a proportionate increase in general and administrative expenses.

Depletion, depreciation and amortization (DD&A). DD&A increased from $137.1 million in 2013 to $189.5 million in 2014, an increase of $52.4 million. Depletion, depreciation, and amortization increased from $2.15 per Mcfe in 2013 to $2.53 per Mcfe in 2014, or an increase of 18%. The increase in the DD&A rate per Mcfe is driven by reductions to proved reserves due to the sale of certain oil and natural gas properties in North Texas during the fourth quarter of 2013 as well as an increase in the amortization base as a result of development activities without a proportionate increase in reserve volumes.

Impairments. In 2014, there were non-cash impairment charges related to oil and natural gas properties of $247.7 million, impairment charges for gas gathering and processing equipment of $1.7 million and impairment charges for other assets of $0.2 million. Additionally, due to a drop in commodity prices and the $247.7 million ceiling impairment, a December 31, 2014 goodwill impairment test resulted in the impairment of our $173.5 million of goodwill for the year ended December 31, 2014. In 2013, there were impairment charges for other assets of $1.1 million. There were no impairments related to oil and natural gas properties recognized in 2013 as a result of favorable unweighted average of the historical first day of the month pricing for the year ended December 31, 2013 of $3.67 per MMbtu as compared to $2.76 per MMbtu for the year ended December 31, ~~2012~~ 2013 as well as favorable performance from our 2013 development activities.

Other operating expenses. Other operating expenses in 2014 relate primarily to $25.5 million of transaction costs related to the Combination and $2.0 million for the write-off of previously deferred public offering costs related to offerings which were aborted prior to our decision to commence the Combination, partially offset by the gain on sale of other assets of $1.5 million, as compared to $0.9 million of other operating income for the year ended December 31, 2013.

Interest expense. Interest expense increased from $99.5 million in the year ended December 31, 2013 to $115.6 million in the year ended December 31, 2014, an increase of $16.1 million, or 16%, primarily as a result of increased borrowings on the New Revolving Credit Facility and $5.8 million of interest expense on the 2019 Notes and ~~the~~ 2020 Notes. Additionally, capitalized interest has decreased due to reclassification of unproved oil and natural gas properties in 2014 into the full cost pool as a result of development activities or impairments due to lease expirations and abandonments. We capitalized $6.5 million and $13.0 million of interest expense for the years ended December 31, 2014 and 2013, respectively.

Gain on derivative instruments. Gains and losses from the change in fair value of derivative instruments as well as cash settlements on commodity derivatives are recognized in our results of operations. During the years ended December 31, 2014 and 2013, we recognized net gains on derivative instruments of $121.7 million and $0.8 million, respectively. ~~The amount of future gain or loss recognized on derivative instruments is dependent upon future commodity prices, which will affect the value of the contracts.~~

Income Tax Expense. Prior to the Combination, no provision for federal or state income taxes was recorded, as we were a limited liability company and not subject to federal or state income tax. In connection with the completion of the Combination, we merged into a corporation and became subject to federal and state income taxes. For December 31, 2014, we recorded an estimated net deferred tax expense of $35 million to recognize a deferred tax liability for the initial book and tax basis difference associated with the change in tax status, impairment of a non-deductible goodwill and changes in the valuation allowance.

72Capital Resources and Liquidity

~~Table~~Our primary sources of ~~Contents~~ liquidity have historically been equity contributions, borrowings under the New Revolving Credit Facility, net cash provided by operating activities, net proceeds from the issuance of the 2017 Notes and proceeds from the Term Loan Facility. Our primary use of capital has been the acquisition and development of oil and natural gas properties. Since the Chapter 11 filings, our principal sources of liquidity have been limited to cash flow from operations and cash on hand. In addition to the cash requirements necessary to fund ongoing operations, we have incurred and continue to incur significant professional fees and other costs in connection with the preparation and administration of

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The following table sets forth selected operating data for the year ended December 31, 2013 compared to the year ended December 31, 2012:

	For the Year Ended				Amount of
	December 31,				Increase		Percent
	2013		2012		(Decrease)		Change
	(in thousands)
Revenues
Oil, natural gas liquids and natural gas	$	354,223	$	177,422	$	176,801	100	%
Other		755		24		731		*
Total revenues		354,978		177,446		177,532	100	%
Operating expenses
Lease operating		44,620		43,649		971	2	%
Marketing, gathering, transportation and other		17,567		17,491		76	0	%
Production and ad valorem taxes		17,824		4,400		13,424	305	%
General and administrative		27,469		21,434		6,035	28	%
Depletion, depreciation and amortization		137,068		91,353		45,715	50	%
Accretion		952		862		90	10	%
Impairments		1,125		664,438		(663,313)		*
Other operating expenses (income)		(858)		516		(1,374)		*
Total operating expenses		245,767		844,143		(598,376)	(71)	%
Other income (expenses)
Interest, net of capitalized interest		(99,471)		(49,387)		50,084	101	%
Gain on derivative instruments		814		29,267		28,453		*
Other income		23		18		(5)		*
Total other expenses		(98,634)		(20,102)		78,532		*
Net income (loss), including noncontrolling interests		10,577		(686,799)		697,376		*
Less: Net income applicable to noncontrolling interests		—		17		(17)	(100)	%
Net income (loss) applicable to controlling interests	$	10,577	$	(686,782)	$	697,359		*
Reconciliation to derive Adjusted EBITDA (1):
Interest, net of capitalized interest		99,471		49,387
Depletion, depreciation and amortization		137,068		91,353
Impairments		1,125		664,438
Other		1,739		599
Amortization of deferred rent		(249)		(532)
Accretion		952		862
Loss (gain) on derivative instruments		46,545		75,734
Option premium amortization		(1,171)		(56)
Net income applicable to noncontrolling interests		—		(17)
Adjusted EBITDA (1)	$	296,057	$	194,986

* Not meaningful or applicable

(1) Adjusted EBITDA is a non-GAAP financial measure. Please see “—Non-GAAP Financial Measure.”

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	For the Year Ended				Amount of
	December 31,				Increase	Percent
	2013		2012		(Decrease)	Change
Oil, NGL and natural gas sales by product (in thousands):
Oil	$	132,513	$	30,343	102,170	337	%
NGL		59,772		36,957	22,815	62	%
Natural gas		161,938		110,122	51,816	47	%
Total	$	354,223	$	177,422	176,801	100	%
Production data:
Oil (MBbl)		1,403.62		317.07	1,086.55	343	%
NGL (MBbl)		1,842.47		931.26	911.21	98	%
Natural gas (Bcf)		44.29		41.12	3.17	8	%
Combined (Bcfe) (1)		63.77		48.61	15.16	31	%
Average prices before effects of economic hedges (2):
Oil (per Bbl)	$	94.41	$	95.70	(1.29)	(1)	%
NGL (Bbl)	$	32.44	$	39.68	(7.24)	(18)	%
Natural gas (per Mcf)	$	3.66	$	2.68	0.98	37	%
Combined (per Mcfe) (1)	$	5.55	$	3.65	1.90	52	%
Average realized prices after effects of economic hedges (2):
Oil (per Bbl)	$	90.49	$	95.79	(5.30)	(6)	%
NGL (Bbl)	$	32.44	$	39.68	(7.24)	(18)	%
Natural gas (per Mcf)	$	4.82	$	5.17	(0.35)	(7)	%
Combined (per Mcfe) (1)	$	6.28	$	5.81	0.47	(8)	%
Average costs (per Mcfe) (1):
Lease operating	$	0.70	$	0.90	(0.20)	(22)	%
Marketing, gathering, transportation and other	$	0.28	$	0.36	(0.08)	(22)	%
Production and ad valorem taxes	$	0.28	$	0.09	0.19	211	%
General and administrative	$	0.43	$	0.44	(0.01)	(2)	%
Depletion, depreciation and amortization	$	2.15	$	1.88	0.27	14	%

the Chapter 11 Cases. We anticipate that we will continue to incur significant professional fees and costs for the pendency of the Chapter 11 Cases.

~~(1)~~ Subsequent ~~Oil~~to ~~and~~December ~~NGL~~31, ~~production~~2015 ~~was~~we ~~converted~~have not entered into additional derivative contracts. Additionally, the filing of our Bankruptcy Petition in July 2015 represented an event of default under our derivative agreements resulting in a termination right by counterparties on all derivative positions at 6July ~~Mcf~~15, ~~per~~2015. ~~Bbl~~Certain of the Company’s derivative positions were terminated prior to ~~calculate~~July ~~combined~~15, ~~production~~2015 ~~and~~as ~~per~~a ~~Mcfe~~result ~~amounts~~of defaults under Sabine’s derivative agreements that occurred prior to the filing of the Bankruptcy Petition. The terminations resulted in settlements of approximately $24.3 million for which such proceeds were used to reduce the amount of borrowing outstanding under our New Revolving Credit Facility. Other terminations resulted in approximately $70.8 million of direct offsets against the New Revolving Credit Facility. As a result, the Company no longer has any derivatives beyond July 2015.

~~(2)~~ Although ~~Average~~we ~~prices~~believe ~~shown~~our incash ~~the~~flow ~~table~~from ~~reflect~~operations ~~prices~~and ~~both~~cash ~~before~~on ~~and~~hand ~~after~~will be adequate to meet the ~~effects~~operating costs of our existing business, there are no assurances that our cash ~~settlements~~flow from operations and cash on ~~commodity~~hand ~~derivative~~will ~~transactions~~be sufficient to continue to fund our operations or to allow us to continue as a going concern until a Chapter 11 plan is confirmed by the Bankruptcy Court or another alternative restructuring transaction is approved by the Bankruptcy Court and consummated. Our long-term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a Chapter 11 plan has been confirmed, if at all, by the Bankruptcy Court. If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to significantly reduce, delay or eliminate capital expenditures, implement further cost reductions, seek other financing alternatives or seek the sale of some or all of our assets. The Company’s ~~calculation~~has oftemporarily ~~such~~deferred ~~effects~~additional ~~includes~~development ~~gains~~activities. If we (i) continue to limit, defer or ~~losses~~eliminate onfuture ~~cash~~capital ~~settlements~~expenditure ~~for~~plans, ~~commodity~~(ii) ~~derivative~~are ~~transactions~~unsuccessful in developing reserves and adding production through our capital program or (iii) implement cost-cutting efforts that are too overreaching, the value of our oil and natural gas properties and our financial condition and results of operations could be adversely affected.

~~Oil,~~In ~~natural~~connection ~~gas~~with ~~liquids~~funding ~~and~~our ~~natural~~liquidity ~~gas~~and ~~sales. Revenues~~the ~~from~~Combination, ~~production~~we ofhave ~~oil~~incurred ~~and~~substantial ~~natural~~additional ~~gas increased from $177~~debt.4 ~~million~~As inof ~~2012~~December to31, ~~$354.2~~2015, ~~million~~the intotal ~~2013,~~outstanding anprincipal ~~increase~~amount of ~~100%.~~our ~~This~~long-term ~~increase~~indebtedness ofwas $~~176~~2.8752 ~~million~~billion, ~~was~~consisting ~~primarily the result~~ of anindebtedness ~~increase~~under inthe ~~liquids~~New ~~revenues~~Revolving ofCredit ~~$125.0~~Facility, ~~million~~the ~~due~~2017 toNotes, anthe ~~increase~~Legacy inForest ~~liquids~~Notes, ~~production subsequent to our North Texas~~ and ~~South~~the ~~Texas~~Term ~~acquisitions~~Loan ~~and~~Facility, ~~our active~~ and, ~~successful~~as ~~development~~of ~~program~~December in31, ~~these~~2015, ~~regions~~no ~~contributing~~extensions ~~approximately~~of ~~$140.1~~credit ~~million,~~are ~~partially~~available ~~offset~~under bythe ~~decreased~~New ~~liquids~~Revolving ~~pricing~~Credit ~~of approximately $15~~Facility.2 ~~million.~~In ~~Additionally~~addition, ~~natural~~our ~~gas~~filing ~~revenues~~of ~~increased~~the ~~$51.8~~Bankruptcy ~~million,~~Petitions orconstituted ~~47%, due to~~ an ~~increase~~event inof ~~realized~~default ~~natural~~that ~~gas~~accelerated ~~prices~~our ofobligations ~~37%~~under ~~contributing~~these ~~approximately~~debt ~~$43~~instruments.4 ~~million,~~For ~~and~~a ~~increased~~description ~~natural~~of ~~gas~~our ~~production~~outstanding ~~contributing~~debt ~~approximately~~instruments, ~~$8.5~~please ~~million~~see ~~due~~“—Net toCash ~~acquisitions~~Provided inby ~~North~~Financing ~~Texas~~Activities.” ~~and~~The ~~South~~stay ~~Texas~~under ~~and~~ the ~~successful~~Bankruptcy ~~development~~Code ~~programs~~does innot ~~these~~apply ~~regions,~~to ~~partially~~letters ~~offset~~of bycredit ~~lower~~and ~~East~~third ~~Texas~~parties ~~volumes~~may ~~and~~continue ~~the~~do ~~sale~~draw ofon ~~the~~their ~~Rockies~~letters ~~assets~~of credit.

On February 25, 2015, we borrowed $356 million under our New Revolving Credit Facility which represented the remaining undrawn amount under the New Revolving Credit Facility. Our borrowing base under our New Revolving Credit Facility was subject to its semi-annual redetermination on April 27, 2015 and was decreased to $750 million. The decrease in our borrowing base as a result of the redetermination resulted in a deficiency of approximately $250 million which required repayment in six monthly installments in an amount of $41.54 million, beginning May 27, 2015. None of such payments has been made or will be made and pursuant to the automatic stay under the Bankruptcy Code, the creditors under the New Revolving Credit Facility are currently stayed from taking any action against us as a result of these non-payments. Our cash balance at March 21, 2016 was approximately $173.0 million.

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The following table sets forth additional information concerning our production volumes for the year ended December 31, 2013 compared to the year ended December 31, 2012:

	For the Year Ended
	December 31,		Percent
	2013	2012	Change
	(in Bcfe)
South Texas	9.89	0.38	2,508	%
East Texas	42.05	45.83	(8)	%
North Texas	11.83	0.54	2,091	%
Rockies (through August 31, 2012)	—	1.86	(100)	%
Total	63.77	48.61	31	%

Lease operating expenses. Lease operating expenses increased from $43.6 million in 2012 to $44.6 million in 2013, an increase of 2%. The increase in lease operating expense of $1.0 million is primarily due to our December 2012 acquired properties. Lease operating expenses decreased from $0.90 per Mcfe in 2012 to $0.70 per Mcfe in 2013. The decrease of $0.20 per Mcfe is primarily due to the commencement of lower cost production in South Texas and North Texas following our December 2012 acquisitions in these areas as well as a lower realized cost on our higher volume East Texas 2013 completions. The following table displays the lease operating expense by area for the years ended December 31, 2013 and 2012:

	For the Year Ended
	December 31,				December 31,
	2013		Per Mcfe		2012		Per Mcfe
	(in thousands, except per Mcfe data)
South Texas	$	2,266	$	0.23	$	246	$	0.65
East Texas		36,183		0.86		40,360		0.88
North Texas		6,162		0.52		248		0.46
Rockies (through August 31, 2012)		(11)		—		2,795		1.50
Giant (1)		20		—		—		—
Total	$	44,620	$	0.70	$	43,649	$	0.90

(1) Giant Gas Gathering LLC, acquired in December 2012, owns and operates gas gathering and processing equipment servicing certain wells in North Texas.

Marketing, gathering, transportation and other. Marketing, gathering, transportation and other expenses increased from $17.5 million in 2012 to $17.6 million in 2013. Marketing, gathering, transportation and other expense decreased on a per unit basis from $0.36 per Mcfe in 2012 to $0.28 per Mcfe in 2013. The per unit basis decrease is primarily associated with our North Texas and South Texas regions resulting from our 2012 acquisitions and current year development activities, as well as a reduction in fees on a per unit of production basis attributable to volumes from our 2013 completions in East Texas and the sale of our Rockies assets.

Production and ad valorem taxes. Production and ad valorem taxes increased from $4.4 million in 2012 to $17.8 million in 2013, an increase of 305%. Production and ad valorem taxes increased on a per unit basis from $0.09 per Mcfe in 2012 to $0.28 per Mcfe in 2013. The increase is primarily related to increased production in our North Texas and South Texas regions which are incurring higher production taxes on oil and NGLs production and not earning tax credits attributed to high cost gas exemptions for our wells in 2013 compared to 2012. We also expect to experience continued variability in our production taxes as a result of timing of approval for high cost gas tax exemptions. Production and ad valorem taxes as a percentage of oil and natural gas revenues were 5% and 3% for 2013 and 2012, respectively.

General and administrative expenses. General and administrative expenses increased from $21.4 million in 2012 to $27.5 million in 2013, an increase of $6.0 million, or 28%, as a result of increased legal and consulting fees related to various current year projects and higher overhead associated with our growing business. General and administrative expenses decreased from $0.44 per Mcfe in 2012 to $0.43 per Mcfe in 2013.

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Depletion, depreciation and amortization (DD&A). DD&A increased from $91.4 million in 2012 to $137.1 million in 2013, an increase of $45.7 million, or 50%. Depletion, depreciation, and amortization increased from $1.88 per Mcfe in 2012 to $2.15 per Mcfe in 2013, or an increase of 14%. The increase in the DD&A rate is primarily the result of our December 2012 acquisitions.

Impairments. In 2012, there were non-cash impairment charges related to oil and natural gas properties of $641.8 million, impairment charges for gas gathering and processing equipment of $21.4 million and impairment charges for other assets of $1.2 million. In 2013, there were impairment charges for other assets of $1.1 million. There were no impairments related to oil and natural gas properties recognized in 2013 as a result of favorable unweighted average of the historical first day of the month pricing for the year ended December 31, 2013 of $3.67 per MMbtu as compared to $2.76 per MMbtu for the year ended December 31, 2012 as well as favorable performance from our 2013 development activities.

Interest expense. Interest expense increased from $49.4 million in the year ended December 31, 2012 to $99.5 million in the year ended December 31, 2013, an increase of $50.1 million, or 101%, primarily as a result of the Term Loan Facility. Additionally, we capitalized $13.0 million and $4.3 million of interest expense for the years ended December 31, 2013 and 2012, respectively.

Gain (loss) on derivative instruments. Gains and losses from the change in fair value of derivative instruments as well as cash settlements on commodity derivatives are recognized in our results of operations. During the years ended December 31, 2013 and 2012, we recognized net gains on derivative instruments of $0.8 million and $29.3 million, respectively. The amount of future gain or loss recognized on derivative instruments is dependent upon future commodity prices, which will affect the value of the contracts.

Capital Resources and Liquidity

Our primary sources of liquidity have historically been equity contributions, borrowings under the New Revolving Credit Facility, net cash provided by operating activities, net proceeds from the issuance of the 2017 Notes and proceeds from the Term Loan Facility. Our primary use of capital has been the acquisition and development of oil and natural gas properties. In connection with funding our liquidity and the Combination, we have incurred substantial additional debt. As of March 15, 2015, the total outstanding principal amount of our long-term indebtedness was $2.821 billion, consisting of indebtedness under the New Revolving Credit Facility, the 2017 Notes, the Legacy Forest Notes, and the Term Loan Facility, and, as of March 15, 2015, no extensions of credit are available under the New Revolving Credit Facility after giving effect to $29 million of outstanding letters of credit. We have substantial interest payment obligations related to this debt of approximately $145 million for the remainder of 2015. In addition, if we are unable to obtain the consent of the agent or lenders under the Term Loan, our New Revolving Credit Facility will mature April 7, 2016. We may not be able to refinance our debt on terms acceptable to us or at all. For a description of our outstanding debt instruments, please see “—Cash Flow Provided by (Used in) Financing Activities.”

Our ability to service our debt obligations and fund our capital expenditures has been negatively impacted by significant decreases in the market price for oil, NGLs and natural gas during the fourth quarter of 2014 with continued weakness into the first quarter of 2015. The decrease in the market price for our production directly reduces our operating cash flow. While we use hedging arrangements to reduce our exposure to fluctuations in the prices of oil, NGLs and natural gas, only a portion of our production is hedged and we may be unable to effectively hedge our production for future periods. In addition, the decrease in the market price for our production indirectly impacts our other sources of potential liquidity. Lower market prices for our production may result in lower borrowing capacity under our New Revolving Credit Facility or higher borrowing costs from other potential sources of debt financing as our borrowing capacity and borrowing costs are generally related to the value of our estimated proved reserves.

Our borrowing base under our New Revolving Credit Facility is subject to its next semi-annual redetermination in April 2015. On February 25, 2015, we borrowed $356 million under our New Revolving Credit Facility which represented the remaining undrawn amount under the New Revolving Credit Facility, and our cash balance at March 15, 2015 was approximately $326.8 million. Based on discussions with the lenders under our New Revolving Credit Facility, we believe that our borrowing base may be decreased significantly. Because our New Revolving Credit Facility is fully drawn, any reduction in our borrowing base as a result of the redetermination will result in a deficiency which must be

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repaid within 30 days or in six monthly installments thereafter, at our election. Despite our significant cash balance, we may be unable to service the interest payments on our debt or fund our capital expenditure program during the remainder of 2015 if our borrowing base is materially decreased.

In order to increase our liquidity to levels sufficient to meet our commitments, we are currently pursuing or considering a number of actions including (i) dispositions of non-core assets, (ii) actively managing our debt capital structure through a number of alternatives, including debt repurchases, debt-for-debt exchanges, debt-for-equity exchanges and secured financing, (iii) in- and out-of-court restructuring, (iv) minimizing our capital expenditures, (v) obtaining waivers or amendments from our lenders, (vi) effectively managing our working capital and (vii) improving our cash flows from operations. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to meet certain obligations, which may affect the overall timing of our current development plan associated with our proved undeveloped reserves. Additionally, covenants contained in our debt agreements may limit our ability to pursue certain of the above strategies. The terms of our New Revolving Credit Facility, Term Loan Facility and the indentures governing our senior notes require that some or all of the proceeds from certain asset sales be used to permanently reduce outstanding debt which could substantially reduce the amount of proceeds we retain. The covenants in these debt agreements also impose limitations on the amount and type of additional indebtedness we can incur, which may significantly reduce our ability to obtain liquidity through the incurrence of additional indebtedness. Furthermore, our ability to refinance any of our existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and our financial condition. If commodity prices do not significantly increase from current levels and we are unable to complete some or all of the above mentioned actions, our liquidity position will be significantly constrained in the future.

Ability to Continue as a Going Concern

WeOur ~~have~~filing ~~significant~~of ~~pending~~the ~~maturities~~Bankruptcy onPetitions ~~our~~described ~~debt~~above ~~obligations. If~~accelerated ~~we are unable to refinance~~ our ~~2017~~obligations ~~Notes~~under tothe ~~mature~~New atRevolving ~~least~~Credit ~~91 days after December 31~~Facility, ~~2018,~~the ~~our~~ Term Loan Facility, inthe an2017 ~~outstanding~~Notes ~~amount~~and ofthe ~~$700~~Legacy ~~million~~Forest ~~will mature on November 16, 2016~~Notes. We ~~Our~~have ~~New~~classified ~~Revolving~~all ~~Credit Facility, which currently has $971 million of~~ debt ~~outstanding,~~as ~~will~~“Liabilities ~~mature~~Subject ~~on April 7, 2016. Our ability~~ to ~~repay~~Compromise” ~~the principal amount of our debt upon the pending maturities has been negatively impacted by significant decreases~~ in the ~~market~~Consolidated ~~price~~Balance ~~for~~Sheet ~~oil,~~at ~~natural~~December ~~gas~~31, ~~and NGLs during the fourth quarter of 2014 with continued weakness into the first quarter of~~ 2015. ~~Additionally,~~If ~~our~~we ~~borrowing~~cannot ~~base~~continue ~~under~~as ~~our~~a ~~New~~going ~~Revolving~~concern, ~~Credit~~adjustments ~~Facility is subject~~ to ~~its next semi-annual redetermination in April 2015. Based on discussions with~~ the ~~lenders~~carrying ~~under~~values ~~our~~and ~~New~~classification ~~Revolving~~of ~~Credit Facility, we believe that~~ our ~~borrowing~~assets ~~base~~and ~~may~~liabilities beand ~~decreased significantly. Because our New Revolving Credit Facility is fully drawn, any decrease in our borrowing base as a result of~~ the ~~redetermination~~reported ~~will~~income ~~result~~and inexpenses acould ~~deficiency which must~~ be ~~repaid~~required ~~within~~and 30would ~~days~~be ~~or in six monthly installments thereafter, at our election~~material. ~~The~~For ~~uncertainty~~additional ~~associated~~description ~~with~~of ~~our~~the ~~ability~~defaults topresent ~~repay~~under our ~~outstanding~~ debt obligations, asplease ~~they~~see ~~become~~Note ~~due~~8 ~~raises~~within ~~substantial~~“Part ~~doubt~~II, ~~about~~Item ~~our~~8. ~~ability~~Financial toStatements ~~continue~~and asSupplementary ~~a going concern~~Data.”

Our New Revolving Credit Facility and Term Loan Facility require that our annual financial statements include a report from our independent registered public accounting firm with an unqualified opinion without an explanatory paragraph as to going concern. In consideration of the uncertainty mentioned above, the report of our independent registered public accounting firm that accompanies our audited consolidated financial statements for the year ended December 31, 2014 contains an explanatory paragraph regarding the substantial doubt about our ability to continue as a going concern. As a result, we are in default under our New Revolving Credit Facility and Term Loan Facility. We are currently in discussions with the lenders under our New Revolving Credit Facility regarding a waiver of this requirement. If we do not obtain a waiver of this requirement within 30 days, there will exist an event of default under the New Revolving Credit Facility and the lenders under the New Revolving Credit Facility will be able to accelerate the debt. Similarly, if we do not obtain a waiver under the Term Loan Facility within 180 days, there will exist an event of default under the Term Loan Facility and the lenders under the Term Loan Facility will be able to accelerate the debt. Any acceleration of the debt obligations under the New Revolving Credit Facility or Term Loan Facility would result in a cross-default and potential acceleration of the maturity of our other outstanding debt obligations. Therefore, all of our outstanding debt obligations in the amount of $2.0 billion (net of discount) are presented in current liabilities as of December 31, 2014. Additionally, the lenders under the Term Loan Facility are subject to a 180-day standstill before they are able to exercise remedies as a result of the uncured event of default. Following the expiration of the 180-day standstill, the lenders are permitted to foreclose on the collateral securing the Term Loan Facility. These defaults create

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additional uncertainty associated with our ability to repay our outstanding debt obligations as they become due and raises substantial doubt about our ability to continue as a going concern.

Working Capital

Our working capital balance fluctuates as a result of timing and amount of borrowings or repayments under our credit arrangements, changes in the fair value of our outstanding commodity derivative instruments, the timing of receiving reimbursement of amounts paid by us for the benefit of joint venture partners as well as changes in revenue receivables as a result of price and volume fluctuations.

For the year ended December 31, ~~2014~~ 2015, we had aan ~~decrease~~increase in working capital of $~~1,986~~2.72 ~~million compared to a decrease in working capital of $127~~billion.9 ~~million for the year ended December 31, 2013.~~ The ~~decrease~~increase in working capital is primarily due to the ~~classification~~reclassification of ~~$1,988.9~~our ~~million of~~ debt asfrom ~~current~~“Current ~~liabilities~~maturities atof ~~December 31, 2014 versus~~ long-term ~~liabilities~~debt” atto ~~December~~“Liabilities ~~31,~~Subject ~~2013~~to ~~and~~Compromise” ~~an increase of $60.4 million~~ in ~~accrued~~the ~~capital~~Consolidated ~~and~~Balance ~~operating~~Sheets ~~expenditures.~~at ~~These~~December ~~fluctuations~~31, ~~are partially offset by an increase of $159~~2015.4 ~~million in our net current asset derivative position and the settlement of derivative contracts during 2014.~~ In addition, fluctuations are due to the timing and amount of the receivable collections, development activities, payments made by us to vendors, and the timing and amount of advances from our joint operations. For more information on the classification of debt, please see Note 28 within “Part II, Item 8. Financial Statements and Supplementary Data.”

Cash Flow Provided by Operating Activities

Cash flows from operations are our primary source of capital and liquidity and are primarily affected by the sale of oil, NGLs and natural gas, as well as commodity prices, net of effects of derivative contract settlements and changes in working capital. Net cash provided by operating activities was $~~209~~134.24 million, $~~217~~209.2 million and $~~144~~217.2 million for the years ended December 31, 2015, 2014, ~~2013~~ and ~~2012~~2013, respectively. The decrease in cash flow from operations for the year ended December 31, ~~2014~~2015 as compared to ~~2013~~2014 was primarily the result of ~~the~~decrease ~~excess~~ in ~~cash outflows for settlements of derivatives~~prices, higher interest payments, and costs incurred for the Combination and ~~the~~costs ~~December~~incurred ~~2013 sale of our interests~~ in ~~certain~~the ~~oil~~Chapter ~~and~~11 ~~natural~~Cases. ~~gas~~A ~~properties~~substantial inportion ~~the~~of ~~Texas~~2015 ~~Panhandle~~cash ~~and~~flow ~~surrounding~~(approximately ~~Oklahoma,~~$76 ~~offset~~million) bywas ~~greater~~also ~~cash~~derived ~~proceeds~~from ~~due~~changes toin ~~18%~~working ~~higher~~capital ~~volumes~~during ~~and~~the ~~11% higher realized prices~~year. The ~~increase~~decrease in cash flow from operations for the year ended December 31, 2014 ~~2013~~ compared to ~~2012~~2013 was primarily the result of anthe ~~increase~~excess ofin ~~31%~~cash inoutflows ~~production~~for ~~volumes.~~settlements ~~This~~of ~~increase~~derivatives, ~~was~~higher ~~due~~interest topayments, ~~acquisitions~~costs ~~and~~incurred ~~development,~~for ~~offset~~the byCombination and the December 2013 sale of our ~~Rockies~~interests ~~assets~~in certain oil and ~~decreases~~natural ~~due~~gas toproperties ~~higher~~in ~~expenditures~~the asTexas aPanhandle ~~result~~and ofsurrounding anOklahoma, ~~increased~~offset ~~rig~~by ~~count~~greater cash proceeds due to 18% higher volumes and ~~development~~11% ~~program~~higher realized prices.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for oil and natural gas production. Prices for these commodities are

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