8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

Amendment No. 1

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report

December 16, 2014

(Date of earliest event reported)

SABINE OIL & GAS CORPORATION

(Formerly Forest Oil Corporation)

(Exact name of registrant as specified in its charter)

New York	1-13515	25-0484900
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(IRS Employer Identification Number)

1415 Louisiana, Suite 1600

Houston, Texas 77002

(Address of principal executive offices, including zip code)

(832) 242-9600

(Registrant’s telephone number, including area code)

Forest Oil Corporation

707 17^th Street, Suite 3600

Denver, Colorado, 80202

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.01 Completion of Acquisition or Disposition of Assets

As disclosed on its Current Report on Form 8-K filed with the Securities and Exchange Commission on December 22, 2014 (the “Closing Date 8-K”), which is being amended by this Amendment to Form 8-K, on December 16, 2014, Sabine Oil & Gas Corporation, formerly known as Forest Oil Corporation (the “Company”), completed the transactions (the “Combination”) contemplated under Amendment No. 1 to the Amended and Restated Agreement and Plan of Merger, dated as of May 5, 2014, and amended and restated as of July 9, 2014, by and among the Company, Sabine Investor Holdings LLC, a Delaware limited liability company, FR XI Onshore AIV, LLC, a Delaware limited liability company, Sabine Oil & Gas Holdings LLC, a Delaware limited liability company, Sabine Oil & Gas Holdings II LLC, a Delaware limited liability company (“Sabine Holdings II”) and Sabine Oil & Gas LLC, a Delaware limited liability company (“Sabine O&G”).

The Combination will be accounted for as a reverse acquisition in conformity with accounting principles generally accepted in the United States of America. The unaudited pro forma condensed consolidated combined financial statements were prepared using the acquisition method of accounting with Sabine O&G considered the predecessor or acquirer of the Company.

Filed as Exhibit 99.1 hereto are certain audited historical financial statements of Sabine O&G as of and for the three years ended December 31, 2013 and unaudited historical financial statements of Sabine O&G as of and for the nine months ended September 30, 2014, together with Management’s Discussion and Analysis of Financial Condition and Results of Operations for the related periods, required by Item 9.01(a) of Form 8-K.

Filed as Exhibit 99.2 are the unaudited pro forma condensed combined financial information giving effect to the Combination and related transactions, and notes related thereto, required by Item 9.01(b) of Form 8-K.

Item 8.01 Other Events.

On January 21, 2015, Sabine Oil & Gas Corporation, a Delaware corporation, filed a registration statement on Form S-4 containing a preliminary proxy statement with respect to Sabine. Attached to this Current Report on Form 8-K as Exhibit 99.3 is the section entitled “Business and Properties” from such proxy statement.

Item 9.01 Financial Statements and Exhibits.

(a) Financial Statements of Businesses Acquired.

The audited consolidated financial statements of Sabine O&G as of and for the three years ended December 31, 2013 and unaudited historical financial statements of Sabine O&G as of and for the nine months ended September 30, 2014, together with Management’s Discussion and Analysis of Financial Condition and Results of Operations for the related periods, are hereby filed as Exhibit 99.1 and are incorporated by reference into this Current Report on Form 8-K/A.

(b) Pro Forma Financial Information

The unaudited pro forma condensed consolidated combined financial information for the year ended December 31, 2013 and as of and for the nine months ended September 30, 2014, giving effect to the Combination and related transactions, and notes related thereto, are filed as Exhibit 99.2 and are incorporated by reference into this Current Report on Form 8-K/A.

(d) Exhibits.

No.	Exhibit
23.1	Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm for Sabine Oil & Gas LLC.
23.2	Consent of PricewaterhouseCoopers LLP, independent accountants for Sabine Oil & Gas LLC.
99.1	Audited consolidated financial statements of Sabine Oil & Gas LLC as of and for the three years ended December 31, 2013 and unaudited historical financial statements of Sabine O&G as of and for the nine months ended September 30, 2014, together with Management’s Discussion and Analysis of Financial Condition and Results of Operations for the related periods.
99.2	Unaudited pro forma condensed consolidated combined financial information for the year ended December 31, 2013 and as of and for the nine months ended September 30, 2014.
99.3	Business and Properties as of and for the three years ended December 31, 2013.

1

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	SABINE OIL & GAS CORPORATION
January 21, 2015
	By:	/s/ Timothy D. Yang
	Name:	Timothy D. Yang
	Title:	Senior Vice President, Land & Legal, General Counsel, Chief Compliance Officer and Secretary

2

Exhibit Index

No.	Exhibit
23.1	Consent of Deloitte & Touche LLP, Independent Registered Public Accounting Firm for Sabine Oil & Gas LLC.
23.2	Consent of PricewaterhouseCoopers LLP, independent accountants for Sabine Oil & Gas LLC.
99.1	Audited consolidated financial statements of Sabine Oil & Gas LLC as of and for the three years ended December 31, 2013 and unaudited historical financial statements of Sabine O&G as of and for the nine months ended September 30, 2014, together with Management’s Discussion and Analysis of Financial Condition and Results of Operations for the related periods.
99.2	Unaudited pro forma condensed consolidated combined financial information for the year ended December 31, 2013, and as of and for the nine months ended September 30, 2014.
99.3	Business and Properties as of and for the three years ended December 31, 2013.

3

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in the Registration Statement No. 333-200977 of Sabine Oil & Gas Corporation on Form S-8 of our report dated March 31, 2014, relating to the consolidated financial statements of Sabine Oil & Gas LLC as of and for the years ended December 31, 2013 and 2012 (which report expresses an unqualified opinion and includes an emphasis-of-matter paragraph relating to the restatement of the 2012 consolidated financial statements as discussed in Note 2 to the consolidated financial statements), appearing in this Current Report on Form 8-K/A of Sabine Oil & Gas Corporation.

/s/ Deloitte & Touche LLP

Houston, Texas

January 21, 2015

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-200977) of Sabine Oil & Gas Corporation of our report dated March 31, 2013, except with respect to our opinion on the consolidated financial statements in so far as it relates to the Restatement of Previously Issued Financial Statements as described in Note 2, as to which the date is March 31, 2014, relating to the financial statements of Sabine Oil & Gas LLC, which appears in this Current Report on Form 8-K/A of Sabine Oil & Gas Corporation.

/s/ PricewaterhouseCoopers

Houston, TX

January 21, 2015

EX-99.1

Exhibit 99.1

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS OF SABINE OIL & GAS CORPORATION

As discussed under “The Forest Oil Combination” below, on December 16, 2014, Sabine O&G and Old Forest completed the combination of their respective businesses. Because Sabine O&G was considered the accounting acquirer in the Combination under U.S generally accepted accounting principles (“GAAP”), Sabine O&G is also considered the accounting predecessor of Sabine Oil & Gas Corporation. Accordingly, the historical financial statements of Sabine Oil & Gas Corporation included in this Current Report on Form 8-K, each of which cover periods prior to the completion of the Combination, reflect the assets, liabilities and operations of Sabine Oil & Gas LLC, the predecessor to Sabine Oil & Gas Corporation, and do not reflect the assets, liabilities and operations of Old Forest. In this section, “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.

You should read the following discussion and analysis of the Company’s financial condition and results of operations in conjunction with the financial statements and notes thereto, including the historical financial statements of Sabine and Forest and the pro forma financial information reflecting the effects of the Combination, included elsewhere in this Current Report on Form 8-K.

The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. Sabine cautions 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 natural gas and oil 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 the Company’s ability to access them and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting Sabine’s business, as well as those factors discussed below and elsewhere in this report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

Sabine is 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. The Company’s operations are focused into three core geographic areas:

• East Texas and Louisiana, targeting the Cotton Valley Sand and Haynesville Shale formations;

• South Texas region, targeting the Eagle Ford Shale formation; and

• North Texas region, targeting the Granite Wash formation.

Sabine, formerly known as Forest Oil Corporation, was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969.

As of September 30, 2014, Sabine O&G held interests in approximately 126,600 gross (101,600 net) acres in East Texas, 41,700 gross (34,800 net) acres in South Texas and 51,700 gross (37,400 net) in North Texas. Sabine is the operator on 99%, 97% and 99% of the Company’s net acreage positions in South Texas, East Texas and North Texas, respectively. Sabine management has not yet completed its estimates for the combined company as of December 31, 2014. Sabine expects to focus operations in the exploration and production segment of the energy industry in the United States. The Company’s gathering and processing assets are primarily dedicated to supporting the natural gas volumes the Company produces and does not generate any material amounts of revenue. Sabine’s ability to develop and produce current reserves and add additional reserves is driven by several factors, including:

• success in the drilling of new wells;

• commodity prices;

• the availability of attractive acquisition opportunities and the ability to execute them;

• the activities and elections of third parties under the Company’s joint development agreements;

• the availability of capital and the amount the Company invests in the leasing and development of properties and the drilling of wells;

• facility or equipment availability and unexpected delays or downtime, including delays imposed by or resulting from compliance with regulatory requirements; and

• the rate at which production volumes naturally decline.

The Forest Oil 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 Oil Corporation, with Forest Oil Corporation 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, Forest Oil Corporation changed its name to “Sabine Oil & Gas Corporation.” In connection with the completion of the Combination, the members of the executive management team of Sabine O&G were appointed as the executive management team of Sabine, and the members of the former executive management team of Old 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. In the future, the combined assets and operations reported on as Sabine Oil & Gas Corporation for the year ending December 31, 2014 will include the historical financial statements of Sabine O&G, with the combined operating results of Forest consolidated therein from the closing date of December 16, 2014 and thereafter. The underlying Forest assets acquired and liabilities assumed by Sabine were based on their respective fair market values with any excess purchase price allocated to goodwill.

Prior to the Combination, Sabine O&G was a privately-held company and Old Forest’s common stock was listed on the New York Stock Exchange. Following the Combination, Sabine’s common stock trades on the OTCQB.

Overview of Sabine O&G

From inception in 2007 through 2012, Sabine O&G was focused primarily in East Texas, where it completed multiple acquisitions and executed a development program to build an extensive inventory of Cotton Valley Sand and Haynesville Shale drilling locations. During 2012, Sabine O&G established its initial position in South Texas in the Eagle Ford Shale formation through two farm-out agreements with a major operator, establishing a footprint in the basin at an attractive upfront cost. Subsequently, Sabine O&G completed three additional transactions and grassroots leasing in the Eagle Ford Shale. Sabine O&G’s North Texas position was acquired from a privately-held company in December 2012 and is concentrated in the Granite Wash formation. In 2014, Sabine O&G purchased additional working interests in certain of its operated Granite Wash properties.

Other Recent Events

Arkoma Basin Disposition

On December 15, 2014, prior to the completion of the Combination, Old Forest closed on an agreement to sell its natural gas properties located in the Arkoma Basin for after-tax cash proceeds of approximately $185 million. The sale had an economic effective date of October 1, 2014. The properties produced 22 MMcfe/d (100% natural gas) during the third quarter of 2014, had estimated proved reserves of 159 Bcfe (100% natural gas) as of December 31, 2013, and generated approximately $23 million of lease-level income during the prior twelve months ended September 30, 2014 (when NYMEX Henry Hub pricing averaged $4,27 per Mcf).

Combination-Related Financing Agreements and Amendments

In connection with the completion of the Combination and related transactions, including the merger of Sabine O&G with and into Sabine (which was then known as “Forest Oil Corporation”), Old Forest and Sabine O&G entered into a series of amendments with respect to certain of each company’s historical debt agreements. As a result of these agreements and amendments, Sabine is a party to an amended and restated credit agreement with terms described below, the prior revolving credit agreements of Old Forest and Sabine O&G were refinanced with proceeds therefrom, Sabine borrowed an incremental $50 million pursuant to an amendment to Sabine O&G’s term loan agreement and the remaining long-term debt of Old Forest and Sabine O&G remained in place as obligations of Sabine.

New Revolving Credit Agreement

On December 16, 2014, Sabine amended and restated the Amended and Restated First Lien 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 with the Second Amended and Restated Credit Agreement (the “New Revolving Credit Agreement”). The New Revolving Credit Agreement provides for a $2 billion revolving credit facility, with an initial borrowing base of $1 billion. The New Revolving Credit Agreement includes a sub-limit permitting up to $100 million of letters of credit.

The borrowing base is subject to redeterminations by the lenders semi-annually, each April 1 and October 1, beginning April 1, 2015 or such later time as Sabine may agree upon request of the administrative agent, or as the majority lenders may agree upon the request of Sabine. Sabine and, after the first scheduled redetermination, the lenders may each request two unscheduled borrowing base redeterminations during any 12-month period. The borrowing base under the New Revolving Credit Agreement 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. 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. A reduction of the borrowing base would require us to repay outstanding exposure under the New Revolving Credit Agreement in excess of the new borrowing base.

On December 16, 2014, Sabine borrowed $750.8 million under the New Revolving Credit Agreement, which was used to, among other things, to refinance borrowings under the prior revolving credit agreements of Old Forest and Sabine O&G and to fund costs and expenses in connection with the transactions.

Loans under the New Revolving Credit Agreement bear interest at our option at either:

• the sum of (1) the Alternate Base Rate, which is defined as the highest of (a) Wells Fargo Bank, National Association’s prime rate; (b) the federal funds effective rate plus 0.50%; or (c) the Eurodollar Rate (as defined in the New Revolving Credit Agreement) for a one-month interest period plus 1% and (2) a margin varying from 0.50% to 1.50% depending on our most recent borrowing base utilization percentage; or

• the Eurodollar Rate plus a margin varying from 1.50% to 2.50% depending on our most recent borrowing base utilization percentage.

The unused portion of the New Revolving Credit Agreement is subject to a commitment fee ranging from 0.375% to 0.50% per annum depending on our most recent borrowing base utilization percentage.

The New Revolving Credit Agreement also provides for certain representations and warranties, events of default, affirmative covenants and negative covenants customary for transactions of this type, including a financial maintenance covenant in the form of a first lien secured leverage ratio not to exceed 3.0 to 1.0. The New Revolving Credit Agreement provides that that all obligations thereunder as well as certain swap and cash management obligations will, subject to certain terms and exceptions, be jointly and severally guaranteed by the guarantors described therein.

The New Revolving Credit Agreement provides that all such obligations and the guarantees will be secured by a lien on at least 80% of the PV-9 of the borrowing base properties evaluated in the most recent reserve report delivered to the administrative agent and a pledge of all of the capital stock of Forest’s restricted subsidiaries, subject to certain customary grace periods and exceptions. The New Revolving Credit Agreement matures on the earlier of (1) the date that is the fifth anniversary of the closing date and (2) the date that is 91 days prior to the maturity date of the Second Lien Credit Agreement (as defined below), if it is in existence at such time, and is subject to terms of the Intercreditor Agreement.

Second Lien Credit Agreement Amendment

In connection with the consummation of the Combination, on December 16, 2014, Sabine O&G, entered into Amendment No. 2 to the Credit Agreement (the “Second Amendment”), among Sabine O&G, Bank of America, N.A., as administrative Agent and the incremental term lenders party thereto.

The Second Amendment amends the Second Lien Credit Agreement, dated as of December 14, 2012 (as amended by Amendment No. 1 to the Credit Agreement, dated as of January 23, 2013, and the Second Amendment, the “Second Lien Credit Agreement”) among Sabine O&G, Bank of America, N.A., as administrative agent, the lenders party thereto and the other parties thereto to provide for $50,000,000 of incremental term loans (the “Incremental Term Loans”). The Incremental Term Loans are fungible with the existing $650,000,000 of second lien loans under the Second Lien Credit Agreement, including with respect to interest and, in the case of eurodollar borrowings, they bear interest at the Adjusted Eurodollar Rate (as defined in the Second Lien Credit Agreement) plus 7.50%, with an interest rate floor of 1.25%, and, in the case of alternate base rate borrowings, they bear interest at the Alternate Base Rate (as defined in the Second Lien Credit Agreement) plus 6.50%, with an interest rate floor of 2.25%.

Second Lien Credit Agreement Assumption Agreement

In connection with the consummation of the Combination, Sabine entered into the Assumption Agreement, dated as of December 16, 2014 (the “Assumption Agreement”). Pursuant to the Assumption Agreement, Sabine has unconditionally assumed all of the obligations of the “Borrower” under the Second Lien Credit Agreement.

Legacy Forest Supplemental Indentures

In connection with the consummation of the Combination, Sabine entered into that certain (a) First Supplemental Indenture (the “2019 Legacy Forest Supplemental Indenture”) to the 2019 Legacy Forest Indenture, by and among Forest, Sabine East Texas Basin LLC, Sabine Oil & Gas Finance Corporation, Sabine Williston Basin LLC, Sabine Bear Paw Basin LLC, Redrock Drilling, LLC, Sabine South Texas LLC, Giant Gas Gathering LLC, Sabine Mid-Continent Gathering LLC, Sabine South Texas Gathering LLC and Sabine Mid-Continent LLC (collectively, the “New Guarantors”), and U.S. Bank National Association, as trustee (the “Trustee”), relating to the 2019 Legacy Forest Notes and (b) First Supplemental Indenture (the “2020 Legacy Forest Supplemental Indenture” and, together with the 2019 Legacy Forest Supplemental Indenture, the “Legacy Forest Supplemental Indentures”) to the 2020 Legacy Forest Indenture, by and among Sabine, the New Guarantors and the Trustee, relating to the 2020 Legacy Forest Notes. Pursuant to the Forest Supplemental Indentures, the New Guarantors have unconditionally guaranteed all of Sabine’s obligations under the Legacy Forest Indentures providing for the issuance of the Legacy Forest Notes.

Legacy Sabine O&G Supplemental Indentures

In connection with the consummation of the merger, Sabine entered into the Fifth Supplemental Indenture, dated as of December 16, 2014 (the “Sabine Supplemental Indenture”), among Sabine Oil & Gas Corporation (f/k/a Forest Oil Corporation) (the “Successor Issuer”), Sabine Oil & Gas LLC (f/k/a NFR Energy LLC) (the “Original Issuer”), Sabine Oil & Gas Finance Corporation (f/k/a NFR Energy Finance Corporation) (together with the Original Issuer, the “Original Issuers”) and The Bank of New York Mellon Trust Company, N.A, as trustee.

Pursuant to the Legacy Sabine O&G Supplemental Indenture, the Successor Issuer has unconditionally assumed all of the obligations of the Original Issuer under the Legacy Sabine O&G Indenture providing for the issuance of the Legacy Sabine O&G Notes. On February 12, 2010, the Original Issuers co-issued $200.0 million of the Legacy Sabine O&G Notes at 98.73% and on April 14, 2010, the Original Issuers issued an additional $150.0 million of the Legacy Sabine O&G Notes at 98.75%.

Source of Revenues

The Company derives substantially all of its revenue from the sale of oil, NGLs and natural gas that are produced from the Company’s 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 the Company’s control. To achieve more predictable cash flows and to reduce exposure to downward price fluctuations, Sabine uses derivative instruments to hedge future sales prices on a significant portion of oil and natural gas production. Sabine currently uses a combination of fixed price oil and natural gas swaps and options for which the Company receives a fixed price (via either swap price, floor of collar or put price) for future production in exchange for a payment of the variable market price received at the time future production is sold. See “—Commodity Hedging Activities” below for more information regarding the Company’s economic hedge positions.

Principal Components of Cost Structure

Lease operating, workover, 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.

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 the Company operates. 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 the Company’s business activities. Included costs are: payroll and benefits for corporate staff, costs of maintaining the Company’s headquarters, audit, tax, legal and other professional and consulting fees, insurance and other costs necessary in the management of the Company’s production and development operations.

As a full cost method of accounting company, Sabine capitalizes general and administrative expenses that are directly attributable to oil and natural gas activities. The Company capitalized $7.5 million and $4.7 million for the nine months ended September 30, 2014 and 2013, respectively.

Depletion, depreciation and amortization. This primarily includes the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas. As a full cost company, Sabine capitalizes all costs associated with acquisition, development and related efforts and depletes these costs using the units-of-production method.

Impairments. Sabine evaluates 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 the Company is 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 three and nine months ended September 30, 2014 and 2013, Sabine recorded no non-cash impairment charge as a result of full cost ceiling limitation. The Company could have a 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 periods declines. Sabine also assesses the Company’s unproved oil and natural gas properties for impairment by comparing the unproved properties carrying value to their fair value and recording reclassifications to the full cost pool as necessary.

The Company evaluates gas gathering and processing equipment for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of 2014, the Company recorded impairment charges for gas gathering and processing equipment of $1.7 million based on expected present value and estimated future cash flows using current volume throughput and pricing assumptions. No impairment charge for gas gathering and processing equipment was recorded in the nine months ended September 30, 2013.

Interest. During the periods presented, Sabine has historically financed a portion of the Company’s working capital requirements and acquisitions with borrowings under Sabine’s senior secured revolving credit facility and second lien term loan agreement. As a result, the Company incurred interest expense that was affected by the level of drilling, completion and acquisition activities, as well as fluctuations in interest rates and the Company’s financing decisions. Sabine also incurred interest expense on the Legacy Sabine O&G Notes. As described under “—Other Recent Events—Combination-Related Financing Agreements and Amendments,” in connection with the Combination, for periods following the Combination, Sabine will continue to be exposed to interest rates that may be effected by the level of drilling, completion and acquisition activities through borrowings under the New Revolving Credit Agreement and the Second Lien Credit Agreement, and expects to incur interest expense on the Legacy Sabine O&G Notes as well as incremental interest expense on the Legacy Forest Notes. The Company will likely continue to incur significant interest expense as it continues to grow. To date, the Company has not entered into any interest rate hedging arrangements to mitigate the effects of interest rate changes. Additionally, Sabine capitalized $5.0 million and $10.1 million for the nine months ended September 30, 2014 and 2013, respectively.

Results of Operations

Items Affecting Comparability of Our Financial Results

Our historical financial results discussed below may not be comparable to our future financial results, for the following reasons:

• Prior to December 16, 2014, our financial results only included the assets, liabilities and operations of Sabine O&G, our predecessor. Beginning on December 16, 2014, our financial results also consolidate assets, liabilities and operations of the legacy business of Old Forest prior to the Combination.

• In connection with the Combination, we entered into the amended and restated New Revolving Credit Agreement and the Second Lien Credit Agreement, as described under “—Other Recent Events—Combination-Related Financing Agreements and Amendments.”

• We have incurred and expect to incur material transaction costs associated with the Combination that are not reflected in the historical results of operations.

• Our predecessor, Sabine O&G, was a private limited liability company that did not historically incur certain incremental expenses associated with being a public company or U.S. federal income tax expense.

• Our predecessor’s acquisition and divestiture history during the periods presented, described in more detail under “Business and Properties—Sabine O&G Properties—Sabine O&G’s Acquisition History.”

For additional information regarding the historical financial statements and results of operations of Old Forest as well as the pro forma impact of the Combination on the results of operations of Sabine, please see the historical financial statements of Old Forest and the pro forma financial information included elsewhere in this Current Report on Form 8-K.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

The following table sets forth selected operating data for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013:

	For the Nine Months Ended September 30,
	2014			2013			Amount of Increase (Decrease)			Percent Change
	(in thousands)
	(As Restated)
Revenues
Oil, natural gas liquids and natural gas	$	355,401		$	244,886		$	110,515			45	%
Other		1,145			627			518			83	%
Total revenues		356,546			245,513			111,033			45	%
Operating expenses
Lease operating		34,662			30,650			4,012			13	%
Workover		2,361			1,078			1,283			119	%
Marketing, gathering, transportation and other		17,091			12,507			4,584			37	%
Production and ad valorem taxes		15,579			12,564			3,015			24	%
General and administrative		20,584			18,812			1,772			9	%
Depletion, depreciation and amortization		142,995			94,179			48,816			52	%
Accretion		668			655			13			2	%
Impairments		1,659			6			1,653				*
Other operating expenses (income)		7,999			(25	)		8,024				*
Total operating expenses		243,598			170,426			73,172			43	%
Other income (expenses)
Interest, net of capitalized interest		(80,383	)		(73,625	)		6,758			9	%
Gain (loss) on derivative instruments		(1,611	)		7,777			9,388				*
Other income		27			23			(4	)			*
Total other income (expenses)		(81,967	)		(65,825	)		16,142				*
Net income	$	30,981		$	9,262		$	21,719				*
Reconciliation to derive Adjusted EBITDA(1):
Interest, net of capitalized interest		80,383			73,625
Depletion, depreciation and amortization		142,995			94,179
Impairments		1,659			6
Other		8,410			1
Amortization of deferred rent		(72	)		(222	)
Accretion		668			655
Loss (gain) on derivative instruments		(6,033	)		27,063
Option premium amortization		(9,774	)		(859	)
Adjusted EBITDA(1)	$	249,217		$	203,710

* Not meaningful or applicable.

(1) Adjusted EBITDA is a non-GAAP financial measure.

	For the Nine Months Ended September 30,
	2014		2013			Amount of Increase (Decrease)			Percent Change
Oil, NGL and natural gas sales by product (in thousands):
Oil	$	139,251	$	90,404		$	48,847			54	%
NGL		50,608		38,987			11,621			30	%
Natural gas		165,542		115,495	(3)		50,047			43	%
Total	$	355,401	$	244,886	(3)	$	110,515			45	%
Production data:
Oil (MBbl)		1,497.01		937.02			559.99			60	%
NGL (MBbl)		1,581.34		1,214.54			366.80			30	%
Natural gas (Bcf)(1)		36.29		31.45			4.84			15	%
Combined (Bcfe)(2)		54.76		44.36			10.40			23	%
Average prices before effects of economic hedges(2):
Oil (per Bbl)	$	93.02	$	96.48			(3.46	)		(4	)%
NGL (per Bbl)	$	32.00	$	32.10			(0.10	)		(0	)%
Natural gas (per Mcf)(1)	$	4.56	$	3.67	(3)		0.89			24	%
Combined (per Mcfe)(2)	$	6.49	$	5.52	(3)		0.97			18	%
Average realized prices after effects of economic hedges(2):
Oil (per Bbl)	$	87.50	$	92.37			(4.87	)		(5	)%
NGL (per Bbl)	$	32.00	$	32.10			(0.10	)		(0	)%
Natural gas (per Mcf)(1)	$	4.35	$	4.88	(3)		(0.53	)		(11	)%
Combined (per Mcfe)(2)	$	6.17	$	6.29	(3)		(0.12	)		(2	)%
Average costs (per Mcfe)(1):
Lease operating	$	0.63	$	0.69			(0.06	)		(9	)%
Workover	$	0.04	$	0.02			0.02			100	%
Marketing, gathering, transportation and other	$	0.31	$	0.28	(3)		0.03			11	%
Production and ad valorem taxes	$	0.28	$	0.28			—			0	%
General and administrative	$	0.38	$	0.42			(0.04	)		(10	)%
Depletion, depreciation and amortization	$	2.61	$	2.12	(3)		0.49			23	%

(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.

(3) Revised for the effects of the restatement. Refer to Note 2.

Oil, natural gas liquids and natural gas sales. Revenues from production of oil, natural gas liquids and natural gas increased from $244.9 million in the first nine months of 2013 to $355.4 million in the first nine months of 2014, an increase of 45%. This increase of $110.5 million was primarily the result of an increase in oil, natural gas liquids and natural gas revenues of $48.8 million, $11.6 million and $50.0 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 24%. These increases were partially offset by the December 2013 sale of Sabine’s interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area and a decrease in the realized price of oil 4%.

The following table sets forth additional information concerning production volumes for the nine months ended September 30, 2014 and 2013:

	For the Nine Months Ended September 30,
	2014		2013		Percent Change
	(in Bcfe)
South Texas		16.87		4.47		277	%
East Texas		32.41		30.68		6	%
North Texas		5.48		9.21		(40	)%
Total		54.76		44.36		23	%

Lease operating expenses. Lease operating expenses increased from $30.7 million in the first nine months of 2013 to $34.7 million in the first nine months of 2014, an increase of 13%. The increase in lease operating expense of $4.0 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 the Company’s interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area. Lease operating expenses decreased from $0.69 per Mcfe in the first nine months of 2013 to $0.63 per Mcfe in the first nine months of 2014. The decrease of $0.06 per Mcfe in the first nine months of 2014 versus the first nine months of 2013 is primarily due to higher production volumes associated with increased completion activity in the last 12 months and the sale of interests in higher costs areas. The following table displays the lease operating expense by area for the nine months ended September 30, 2014 and 2013:

	For the Nine Months Ended
	September 30, 2014		Per Mcfe		September 30, 2013			Per Mcfe
	(in thousands, except per Mcfe data)
South Texas	$	5,430	$	0.32	$	1,175		$	0.26
East Texas		27,185		0.84		25,322			0.83
North Texas		2,047		0.37		4,160			0.45
Other		—		—		(7	)		—
Total	$	34,662	$	0.63	$	30,650		$	0.69

Marketing, gathering, transportation and other. Marketing, gathering, transportation and other expenses increased from $12.5 million in the first nine months of 2013 to $17.1 million in the first nine months of 2014. Marketing, gathering, transportation and other expenses increased from $0.28 per Mcfe in the first nine months of 2013 to $0.31 per Mcfe in the first nine months of 2014. The increase of $0.03 per Mcfe in the first nine months of 2014 versus the first nine months of 2013 is primarily due to increasing gas volumes associated with the Company’s South Texas development activities as well as gas volumes associated with the Company’s Haynesville development activities in East Texas, which were subject to higher fees due to lack of pipeline infrastructure, partially offset by decreases due to increasing oil volumes associated with the Company’s development activities in North Texas and South Texas regions which are not subject to gathering and transportation charges.

Production and ad valorem taxes. Production and ad valorem taxes increased from $12.6 million in the first nine months of 2013 to $15.6 million in the first nine months of 2014, an increase of 24%. Production and ad valorem taxes remained consistent on a per unit basis at $0.28 per Mcfe in the first nine months of 2014 and 2013. Offsetting changes on a per unit basis include increases 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, and decreases due to a slight decrease in North Texas production due to the December 2013 sale of the Company’s interests in certain oil and natural gas properties in the Texas

Panhandle and surrounding Oklahoma area. The Company expects to experience continued variability in its production taxes as a result of timing of approval for high cost gas tax exemptions. Production taxes as a percentage of oil and natural gas revenues were 4% and 5% for the first nine months of 2014 and 2013, respectively.

General and administrative. General and administrative expenses increased from $18.8 million in the first nine months of 2013 to $20.6 million in the first nine months of 2014, an increase of $1.8 million, or 9%, primarily as a result of higher overhead associated with the Company’s growing business. General and administrative expenses decreased from $0.42 per Mcfe in the first nine months of 2013 to $0.38 per Mcfe in the first nine months of 2014 due to increased production without a proportionate increase in general and administrative expenses.

Depletion, depreciation and amortization. DD&A increased from $94.2 million in the first nine months of 2013 to $143.0 million in the first nine months of 2014, an increase of $48.8 million. Depletion, depreciation, and amortization increased from $2.12 per Mcfe in the first nine months of 2013 to $2.61 per Mcfe in the first nine months of 2014, or an increase of 23%. 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 June 2014, the Company recorded impairment charges for gas gathering and processing equipment of $1.7 million based on expected present value and estimated future cash flows using current volume throughput and pricing assumptions. No impairment charge for gas gathering and processing equipment was recorded in the nine months ended September 30, 2013.

Other operating expenses. Other operating expenses in the first nine months of 2014 relate primarily to the write-off of previously deferred public offering costs of $2.0 million related to offerings which were aborted prior to the Company’s decision to commence the merger described in Note 1 and $8.0 million of transaction costs related to the Combination, partially offset by the gain on sale of other assets of $1.5 million.

Interest. Interest expense increased from $73.6 million in the first nine months of 2013 to $80.4 million in the first nine months of 2014, an increase of $6.8 million, or 9%, primarily as a result of increased borrowings on the Legacy Sabine O&G Credit Facility and lower capitalized interest. Sabine capitalized $5.0 million and $10.1 million of interest expense for the nine months ended September 30, 2014 and 2013, respectively. Capitalized interest has decreased due to reclassification of unproved oil and natural gas properties, with capitalized interest associated with higher rate debt, into the full cost pool as a result of development activities or impairments due to lease expirations and abandonments.

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 the Company’s results of operations. During the nine months ended September 30, 2014 and 2013, the Company recognized a net loss on derivative instruments of $1.6 million and a net gain on derivative instruments of $7.8 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.

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 December 31,
	2013			2012			Amount of Increase (Decrease)			Percent Change
	(in thousands)
	(as restated)
Revenues
Oil, natural gas and NGLs	$	354,223		$	177,422		$	176,801			100	%
Other		755			24			731				*
Total revenues		354,978			177,446			177,532			100	%
Operating expenses
Lease operating		42,491			41,011			1,480			4	%
Workover		2,160			2,638			(478	)		(18	)%
Marketing, gathering, transportation and other		17,567			17,491			76				*
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	)			*
Total operating expenses		246,656			843,627			(596,971	)		(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 (expenses)		912			(498	)		(1,410	)			*
Total other expenses		(97,745	)		(20,618	)		77,127			374	%
Net income (loss), including noncontrolling interests		10,577			(686,799	)		697,376				*
Less: Net loss 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 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.

	For the Year Ended December 31,
	2013		2012			Amount of Increase (Decrease)			Percent Change
Oil, natural gas and NGL 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	(3)		51,816			47	%
Total	$	354,223	$	177,422	(3)	$	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 (per Bbl)	$	32.44	$	39.68		$	(7.24	)		(18	)%
Natural gas (per Mcf)	$	3.66	$	2.68	(3)	$	0.98			37	%
Combined (per Mcfe)(1)	$	5.55	$	3.65	(3)	$	1.90			52	%
Average realized prices after effects of economic hedges(2):
Oil (per Bbl)	$	90.59	$	95.79		$	(5.20	)		(5	)%
NGL (per Bbl)	$	32.44	$	39.68		$	(7.24	)		(18	)%
Natural gas (per Mcf)	$	4.82	$	5.23	(3)	$	(0.41	)		(8	)%
Combined (per Mcfe)(1)	$	6.28	$	5.81	(3)	$	0.47			8	%
Average costs (per Mcfe)(1):
Lease operating	$	0.67	$	0.84		$	(0.17	)		(20	)%
Workover	$	0.03	$	0.05		$	(0.02	)		(40	)%
Marketing, gathering, transportation and other	$	0.28	$	0.36	(3)	$	(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	(3)	$	0.27			14	%

(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 Sabine’s cash settlements on commodity derivative transactions. Sabine’s calculation of such effects includes gains or losses on cash settlements for commodity derivative transactions.

(3) Revised for the effects of the restatement. Refer to Note 2 of Sabine’s consolidated financial statements.

Oil, natural gas and NGLs sales. Revenues from production of oil and natural gas increased from $177.4 million in 2012 to $354.2 million in 2013, an increase of 100%. This increase of $176.8 million was primarily the result of an increase in liquids revenues of $124.9 million due to an increase in liquids production subsequent to Sabine’s North Texas and South Texas acquisitions and Sabine’s active and successful development program in these regions contributing approximately $140.1 million, partially offset by decreased liquids pricing of approximately $15.2 million. Additionally, natural gas revenues increased approximately $51.8 million, or 47%, due to an increase in realized natural gas price by 37% contributing approximately $43.4 million, and increased natural gas production contributing approximately $8.5 million due to acquisitions in North Texas and South Texas and the successful development programs in these regions, partially offset by lower East Texas volumes and the sale of the Rockies assets.

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

	For the Year Ended December 31,
	2013		2012		Percent Change
	(in Bcfe)
East Texas		42.05		45.83		(8	)%
South Texas		9.89		0.38		2503	%
North Texas		11.83		0.54		2091	%
Rockies (through August 31, 2012)		—		1.86		(100	)%
Total		63.77		48.61		31	%

Lease operating expenses. Lease operating expenses increased from $41.0 million in 2012 to $42.5 million in 2013, an increase of 4%. The increase in lease operating expense of $1.5 million is primarily due to Sabine’s December 2012 acquired properties. Lease operating expenses decreased from $0.84 per Mcfe in 2012 to $0.67 per Mcfe in 2013. The decrease of $0.17 per Mcfe is primarily due to the commencement of lower cost production in South Texas and North Texas following Sabine’s December 2012 acquisitions in these areas as well as a lower realized cost on Sabine’s higher volume East Texas 2013 completions. The following table displays the lease operating expense by area for years ended December 31, 2013 and 2012:

	For the Years Ended December 31,
	2013			Per Mcfe		2012		Per Mcfe
	(in thousands, except per Mcfe data)
East Texas	$	34,100		$	0.81	$	37,991	$	0.83
South Texas		2,266			0.23		246		0.65
North Texas		6,086			0.51		186		0.35
Rockies (through August 31, 2012)		(11	)		—		2,588		1.39
Giant(1)		50			—		—		—
Total	$	42,491		$	0.67	$	41,011	$	0.84

(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 Sabine’s North Texas and South Texas regions resulting from Sabine’s 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 Sabine’s 2013 completions in East Texas and the sale of the 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 Sabine’s 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 Sabine’s wells in 2013 compared to 2012. Sabine also expects to experience continued variability in its production taxes as a result of timing of approval for high cost gas tax exemptions. Production 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%, primarily as a result of increased legal and consulting fees related to various current year projects contributing approximately $5.0 million and higher overhead associated with Sabine’s growing business contributing approximately $1.0 million. General and administrative expenses decreased from $0.44 per Mcfe in 2012 to $0.43 per Mcfe in 2013.

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%. Increase in the DD&A rate is primarily the result of Sabine’s December 2012 acquisitions and increased production.

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 average unweighted first day of the month pricing for the year ended December 31, 2012 of $2.76 per MMbtu as compared to $3.67 per MMbtu for the year ended December 31, 2013, as well as favorable performance from Sabine’s 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, Sabine capitalized $13.0 million and $4.3 million of interest expense for the years ended December 31, 2013 and 2012, 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 Sabine’s results of operations. During the years ended December 31, 2013 and 2012, Sabine 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.

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

This Management’s Discussion and Analysis has been revised for the effects of the restatement (refer to Note 2 of Sabine’s consolidated financial statements). The following table sets forth selected operating data for the year ended December 31, 2012 compared to the year ended December 31, 2011:

	For the Year Ended December 31,
	2012			2011			Amount of Increase (Decrease)			Percent Change
				(in thousands)
	(as restated)			(as restated)
Revenues
Oil, NGLs and natural gas	$	177,422		$	201,421		$	(23,999	)		(12	)%
Other		24			131			(107	)			*
Total revenues		177,446			201,552			(24,106	)		(12	)%
Operating expenses
Lease operating		41,011			27,113			13,898			51	%
Workover		2,638			2,903			(265	)		(9	)%
Marketing, gathering, transportation and other		17,491			16,149			1,342			8	%
Production and ad valorem taxes		4,400			7,775			(3,375	)		(43	)%
General and administrative		21,434			23,546			(2,112	)		(9	)%
Depletion, depreciation and amortization		91,353			75,424			15,929			21	%
Gain on bargain purchase		—			(99,548	)		99,548				*
Accretion		862			628			234			37	%
Impairments		664,438			4,192			660,246				*
Total operating expenses		843,627			58,182			785,445			1350	%
Other income (expenses)
Interest, net of capitalized interest		(49,387	)		(39,632	)		9,755			25	%
Gain on derivative instruments		29,267			71,834			42,567				*
Other expenses		(498	)		(389	)		109			(28	)%
Total other income (expenses)		(20,618	)		31,813			52,431			(165	)%
Net income (loss), including noncontrolling interests		(686,799	)		175,183			(861,982	)			*
Less: Net (income) loss applicable to noncontrolling interests		17			(117	)		134			(115	)%
Net income (loss) applicable to controlling interests	$	(686,782	)	$	175,066		$	(861,848	)			*
Revenues
Reconciliation to derive Adjusted EBITDA(1):
Interest, net of capitalized interest	$	49,387		$	39,632
Depletion, depreciation and amortization		91,353			75,424
Impairments		664,438			4,192
Gain on bargain purchase		—			(99,548	)
Other		599			439
Amortization of deferred rent		(532	)		(406	)
Accretion		862			628
(Gain) loss on derivative instruments		75,734			(1,272	)
Option premium amortization		(56	)		—
Net (income) loss applicable to noncontrolling interests		(17	)		117
Adjusted EBITDA(1)	$	194,986		$	194,272

* Not meaningful or applicable.

(1) Adjusted EBITDA is a non-GAAP financial measure.

	For the Year Ended December 31,
	2012			2011			Amount of Increase (Decrease)			Percent Change
Oil, NGL and natural gas sales by product (in thousands):
Oil	$	30,343		$	15,462		$	14,881			96	%
NGL		36,957			36,272			685			2	%
Natural gas		110,122	(3)		149,687	(3)		(39,565	)		(26	)%
Total	$	177,422	(3)	$	201,421	(3)	$	(23,999	)		(12	)%
Production data:
Oil (MBbl)		317.07			170.52			146.55			86	%
NGL (MBbl)		931.26			704.44			226.82			32	%
Natural gas (Bcf)		41.12			38.94			2.18			6	%
Combined (Bcfe)(1)		48.61			44.20			4.41			10	%
Average prices before effects of economic hedges(2):
Oil (per Bbl)	$	95.70		$	90.68		$	5.02			6	%
NGL (per Bbl)	$	39.68		$	51.49		$	(11.81	)		(23	)%
Natural gas (per Mcf)(1)	$	2.68	(3)	$	3.84	(3)	$	(1.16	)		(30	)%
Combined (per Mcfe)(2)	$	3.65	(3)	$	4.56	(3)	$	(0.91	)		(20	)%
Average realized prices after effects of economic hedges(2):
Oil (per Bbl)	$	95.79		$	90.68		$	5.11			6	%
NGL (per Bbl)	$	39.68		$	51.49		$	(11.81	)		(23	)%
Natural gas (per Mcf)(1)	$	5.23	(3)	$	5.66	(3)	$	(0.43	)		(8	)%
Combined (per Mcfe)(2)	$	5.81	(3)	$	6.16	(3)	$	(0.35	)		(6	)%
Average costs (per Mcfe)(1):
Lease operating	$	0.84		$	0.61		$	0.23			38	%
Workover	$	0.05		$	0.07		$	(0.02	)		(29	)%
Marketing, gathering, transportation and other	$	0.36	(3)	$	0.37	(3)	$	(0.01	)		(3	)%
Production and ad valorem taxes	$	0.09		$	0.18		$	(0.09	)		(50	)%
General and administrative	$	0.44		$	0.53		$	(0.09	)		(17	)%
Depletion, depreciation and amortization	$	1.88	(3)	$	1.71	(3)	$	0.17			10	%

(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 Sabine’s realized commodity hedging transactions. Sabine’s calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions.

(3) Revised for the effects of the restatement. Refer to Note 2 of Sabine’s consolidated financial statements.

Oil, NGLs and natural gas sales. Revenues from production of oil and natural gas decreased from $201.4 million in 2011 to $177.4 million in 2012, a decrease of 12%. This decrease of $24.0 million was a result of a decrease in average prices per Mcfe of 20% totaling approximately $44.2 million offset by an increase in production due to acquisitions and drilling success contributing approximately $20.2 million.

The following table sets forth additional information concerning Sabine’s production volumes for the years ended December 31, 2012 and 2011:

	For the Year Ended December 31,
	2012		2011		Percent Change
	(in Bcfe)
East Texas		45.83		39.97		15	%
South Texas		0.38		—		100	%
North Texas		0.54		—		100	%
Rockies (through August 31, 2012)		1.86		4.23		(56	)%
Total		48.61		44.20		10	%

Lease operating expenses. Lease operating expenses increased from $27.1 million in 2011 to $41.0 million in 2012, an increase of 51%. The increase in lease operating expense is due to an increase in production associated with Sabine’s two recent producing property acquisitions in East Texas. Lease operating expenses increased from $0.61 per Mcfe in 2011 to $0.84 per Mcfe in 2012 primarily due to an increase in production volumes associated with vertical wells acquired in the second half of 2011 with higher operating costs. The following table displays the lease operating expense by area for the years ended December 31, 2012 and 2011:

	For the Years Ended
	December 31, 2012		Per Mcfe		December 31, 2011		Per Mcfe
	(in thousands, except per Mcfe data)
East Texas	$	37,991	$	0.83	$	21,953	$	0.55
South Texas		246		0.65		—		—
North Texas		186		0.35		—		—
Rockies (through August 31, 2012)		2,588		1.39		5,160		1.22
Total	$	41,011	$	0.84	$	27,113	$	0.61

Marketing, gathering, transportation and other. Marketing, gathering, transportation and other expenses increased from $16.1 million in 2011 to $17.5 million in 2012, an increase of 8%. The increase is due to an increase in production volumes by 10%. Marketing, gathering, transportation and other expense decreased on a per unit basis from $0.37 per Mcfe in 2011 to $0.36 per Mcfe in 2012.

Production and ad valorem taxes. Total production and ad valorem taxes decreased from $7.8 million in 2011 to $4.4 million in 2012, a decrease of 43%, primarily as a result of the timing of the approval of high cost gas tax exemptions that are currently received on all of Sabine’s horizontal gas wells. Sabine expects continued variability with production taxes as a result of timing of approval for the aforementioned exemptions. Production taxes as a percentage of oil and natural gas revenues before the effects of hedging were 3.9% for 2011 and 2.5% for 2012.

General and administrative expenses. General and administrative expenses decreased from $23.5 million in 2011 to $21.4 million in 2012, a decrease of $2.1 million, or 9%, primarily as a result of lower due diligence and other acquisition costs in 2012. General and administrative expenses decreased from $0.53 per Mcfe in 2011 to $0.44 per Mcfe in 2012 primarily as a result of an increase in production volumes without a proportionate increase in general and administrative expenses.

Depletion, depreciation and amortization (DD&A). DD&A increased from $75.4 million in 2011 to $91.4 million in 2012, an increase of $15.9 million, or 21%, as a result of the impact of increased production. Depletion, depreciation, and amortization increased from $1.71 per Mcfe in 2011 to $1.88 per Mcfe in 2012 due to a higher depletion and amortization base resulting from acquired assets and capital expenditures.

Gain on bargain purchase. In 2011, Sabine recognized a gain related to the acquisition of certain oil and natural gas properties for the fair value of assets acquired in excess of the adjusted purchase price of $99.5 million.

Impairments. In 2011, there were non-cash impairment charges for gas gathering and processing equipment of $2.8 million and impairments related to the write-down of carrying value of certain sizes of casing inventory of $1.4 million. 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 impairments related to the write-down of carrying value of certain sizes of casing inventory of $1.2 million. The average unweighted first day of the month pricing for the 12 months ended December 31, 2012 was $2.76 per MMbtu versus $4.12 per MMbtu at December 31, 2011.

Interest expense. Interest expense increased from $39.6 million in 2011 to $49.4 million in 2012, an increase of $9.8 million, or 25%, primarily as a result of higher average borrowings for the period under Sabine’s Legacy Sabine O&G Credit Facility and entrance into the Term Loan Facility in December 2012. Additionally, Sabine capitalized $4.3 million and $5.9 million of interest expense for the years ended December 31, 2012 and 2011, 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 Sabine’s results of operations. During the years ended December 31, 2012 and 2011, Sabine recognized net gains on derivative instruments of $29.3 million and $71.8 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.

Capital Resources and Liquidity

Overview

Sabine believes that operating cash flows and available borrowings under the New Revolving Credit Agreement, as amended as described under “—Other Recent Events—Combination-Related Financing Agreements and Amendments,” are sufficient to meet cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for the next 12 months. Should Sabine fund a significant portion of its capital expenditures with borrowing on its New Revolving Credit Agreement, the cost of such financing would increase interest costs and could limit cash flows available for normal operating needs. However, to the extent that Sabine considers market conditions favorable, the Company may access the capital markets to raise capital from time to time, including additional senior debt, to fund acquisitions, pay down the New Revolving Credit Agreement and for general working capital purposes.

Sabine’s primary sources of liquidity have historically been equity contributions to its predecessor, borrowings under the Legacy Sabine O&G Credit Facility, net cash provided by operating activities, net proceeds from the issuance of the Legacy Sabine O&G Notes and proceeds from the Term Loan Facility. The Company’s primary use of capital has been the acquisition and development of oil and natural gas properties. As Sabine pursues reserve and production growth, the Company continually monitors the capital resources, including equity and debt financings, available to the Company to meet future financial obligations, planned capital expenditure activities and liquidity requirements. Sabine’s future success in growing proved

reserves and production will be highly dependent on the capital resources available to the Company. As of September 30, 2014, the estimated capital costs of developing proved undeveloped reserves are approximately $870 million, over a period of approximately five years which Sabine expects to fund utilizing a combination of operating cash flows and borrowings under its Legacy Sabine O&G Credit Facility. Sabine management has not yet completed reserve estimates for the combined company as of December 31, 2014. Depending on the timing and concentration of the development of the non-proved locations, Sabine would be required to generate or raise significant capital to develop all of the Company’s potential drilling locations should the Company elect to do so.

Combined contributions for an equity interest in the Company totaled over $1.5 billion from inception through September 30, 2014 to fund acquisitions of oil and natural gas properties.

As of September 30, 2014, Sabine’s borrowing base under the Legacy Sabine O&G Credit Facility was $700 million, the outstanding amount totaled $574 million and the Company had the ability to borrow approximately $126 million under the Legacy Sabine O&G Credit Facility. Subsequent to the period ended September 30, 2014, in connection with the Combination, as more fully described under “Other Recent Events—Combination-Related Financing Agreements and Amendments,” the Company entered into the New Revolving Credit Agreement which provides for a $2 billion revolving credit facility, with an initial borrowing base of $1 billion. The New Revolving Credit Agreement includes a sub-limit permitting up to $100 million of letters of credit. The Company expects that it will be in compliance with the financial covenants contained in the New Revolving Credit Agreement as of December 31, 2014.

In addition to the Legacy Sabine O&G Credit Facility, the Company entered into the Term Loan Facility on December 14, 2012 with a maturity date of April 7, 2018. On January, 23, 2013, the syndication was completed with an additional funding of $150 million of proceeds, bringing the outstanding balance to $650 million. Proceeds from the Term Loan Facility were used to acquire oil and natural gas properties in December 2012 and repay borrowings under the Legacy Sabine O&G Credit Facility in the first quarter of 2013. Subsequent to September 30, 2014, Sabine entered into the Second Amendment to the Second Lien Credit Agreement governing the Term Loan Facility to provide for $50 million of the Incremental Term Loans.

Finally, in connection with the Combination, Sabine assumed the liabilities of Old Forest, including certain existing Legacy Forest Notes totaling $800 million in principal amount which remain outstanding as obligations of Sabine following the Combination.

As of January 15, 2015, the total outstanding principal amount of our long-term indebtedness was $2,415 million, consisting of indebtedness under the New Revolving Credit Facility, the Legacy Sabine O&G Notes, the Legacy Forest Notes, and the Term Loan Facility, and approximately $406 million would have been available for additional borrowings under the New Revolving Credit Facility after giving effect to $29 million of outstanding letters of credit and the borrowing base as of January 15, 2015. Please see “—Other Recent Events—Combination-Related Financing Agreements and Amendments” for additional information regarding the financing agreements and amendments entered into in connection with the Combination, and the pro forma financial information included elsewhere in this Current Report on Form 8-K for additional information regarding the pro forma impact of the Combination on the liabilities and financing costs of Sabine.

Working Capital

Sabine’s working capital balance fluctuates as a result of timing and amount of borrowings or repayments under the Company’s credit arrangements, changes in the fair value of the Company’s outstanding commodity derivative instruments, the timing of receiving reimbursement of amounts paid by Sabine for the benefit of joint venture partners as well as changes in revenue receivables as a result price and volume fluctuations. If the Company’s capital investment levels exceed the Company’s estimate of cash flows from operations, Sabine will use available capacity under the Company’s credit arrangements.

For the nine months ended September 30, 2014, Sabine had an increase in working capital of $19.6 million compared to a decrease of $118.2 million for the nine months ended December 31, 2013. The increase in working capital is primarily due to an increase of $11.3 million in the Company’s net current asset derivative position and the settlement of derivative contracts during 2014, as well as a decrease in current liabilities of $11.5 million related to accrued capital and operating expenditures. In addition, working capital fluctuates due to the timing of the receivable collections, development activities, payments made by Sabine to vendors, and the timing and amount of advances from the Company’s joint operations.

Cash Flow Provided by Operating Activities

Cash flows from operations are Sabine’s primary source of capital and liquidity and are primarily affected by the sale of oil, natural gas liquids 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 $128.2 million and $149.8 million for the nine months ended September 30, 2014 and 2013, respectively. The decrease in cash flows from operations for the nine months ended September 30, 2014 compared to 2013 was primarily the result of an increase in cash paid for hedging settlements, transaction costs related to the Combination and an increase in cash paid for interest due to increased borrowings on the Legacy Sabine O&G Credit Facility, partially offset by an increase of 23% in production volumes and an increase of 18% in realized pricing before the effect of hedges. The increase in production volumes was attributable to the successful drilling program in South Texas and North Texas, offset by the sale of Sabine’s interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area and decreases due to higher expenditures as a result of an increased rig count and development program.

Sabine’s 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 determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets and other variable factors influence market conditions for these products. These factors are beyond the Company’s control and are difficult to predict.

Cash Flow Used in Investing Activities

During the nine months ended September 30, 2014 and 2013, cash flows used in investing activities were $458.1 million and $237.5 million, respectively, primarily related to capital expenditures for drilling, development and acquisition costs.

Our predecessor’s full year 2014 capital expenditures are estimated total approximately $528 million for drilling and completion activities and approximately $54 million for leasing and other activities, and management has not yet finalized a capital budget for Sabine in 2015. The amount, timing and allocation of capital expenditures is largely discretionary and within Sabine’s control. If oil and natural gas prices decline to levels below the Company’s acceptable levels or costs increase to levels above the Company’s acceptable levels, the Company could choose to defer a significant portion of budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that Sabine believes have the highest expected returns and potential to generate near-term cash flow. Sabine routinely monitors and adjusts the Company’s capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside the Company’s control. Such historical adjustments to Sabine’s capital expenditures have not resulted in an unfavorable liquidity position. However, a significant reduction in its capital program could result in a decline in Sabine’s oil and natural gas reserves and production and cash flows, as well as a decline in its borrowing base under its Legacy Sabine O&G Credit Facility and limit its ability to obtain needed capital or financing.

During the nine months ended September 30, 2014, Sabine collected approximately $15 million in cash proceeds for asset sales.

As of September 30, 2014, Sabine has spent approximately $483 million of the 2014 capital budget, of which approximately $413 million was spent on drilling and completion activities, approximately $38 million on working interest acquisitions and approximately $47 million on leasing and other activities, which is offset by amounts recognized on the sale of assets of approximately $15 million.

Cash Flow Provided by Financing Activities

Net cash provided by financing activities of $323.8 million during the nine months ended September 30, 2014 was primarily the result of net borrowings under the Legacy Sabine O&G Credit Facility of $324.0 million. During the nine months ended September 30, 2013, net cash provided by financing activities totaled $97.8 million, which was primarily the result of borrowings under the Term Loan Facility of $153.5 million offset by the net repayments under the Legacy Sabine O&G Credit Facility of $40.0 million and debt issuance costs of $5.7 million. Net borrowings were greater in the first nine months of 2014 as a result of increased development activities.

Subsequent to the period ended September 30, 2014, the Company amended and restated the Amended and Restated First Lien Credit Agreement as described under “—Other Recent Events—Combination-Related Financing Agreements and Amendments.” The New Revolving Credit Agreement did, and as amended continues to, contain certain covenants, including restrictions on additional indebtedness and dividends.

Senior Secured Revolving Credit Facility. During the period ended September 30, 2014, Sabine O&G had the Legacy Sabine O&G Credit Facility. As of September 30, 2014, the borrowing base under the Legacy Sabine O&G Credit Facility was $700 million, the outstanding amount totaled $574 million and Sabine O&G was able to incur approximately $126 million of secured indebtedness under the Legacy Sabine O&G Credit Facility. Subsequent to the period ended September 30, 2014, in connection with the Combination, as more fully described under “—Other Recent Events—Combination-Related Financing Agreements and Amendments,” Sabine entered into the New Revolving Credit Agreement and borrowed $750.8 million under the New Revolving Credit Agreement, which was used, among other things, to refinance borrowings under the prior revolving credit agreements of Old Forest and Sabine O&G and to fund costs and expenses in connection with the transactions. The New Revolving Credit Agreement provides for a $2 billion revolving credit facility, with an initial borrowing base of $1 billion. The New Revolving Credit Agreement includes a sub-limit permitting up to $100 million of letters of credit. Please see “—Other Recent Events—Combination-Related Financing Agreements and Amendments—New Revolving Credit Agreement” for additional information.

As of September 30, 2014 and December 31, 2013, borrowings outstanding under the Legacy Sabine O&G Credit Facility totaled $574 million and $250 million, respectively, and had a weighted average interest rate of 2.3% and 2.4% for the nine and 12 month periods ended, respectively.

Term Loan Agreement. Sabine O&G entered into the $500 million Second Lien Credit Agreement on December 14, 2012 with a maturity date of April 7, 2018. On January 23, 2013, the syndication was completed with an additional funding of $150 million, bringing the outstanding balance to $650 million as of September 30, 2014. Proceeds from the Term Loan Facility were used to acquire oil and natural gas properties in December 2012 and repay borrowings under the Legacy Sabine O&G Credit Facility in the first quarter of 2013. Interest is accrued on Eurodollar loans at a rate per annum equal to the Eurodollar rate, with a Eurodollar floor of 1.25%, plus an applicable margin of 750 basis points. Subsequent to September 30, 2014, Sabine entered into the Second Amendment to the Second Lien Credit Agreement governing the Term Loan Facility to provide for the $50 million Incremental Term Loans.

Commodity Hedging Activities

Sabine’s primary market risk exposure is in the prices the Company receives for oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to the Company’s U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and the Company expects this volatility to continue in the future. The prices Sabine receives for production depends on many factors outside of the Company’s control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on cash flow caused by changes in oil and natural gas prices, Sabine has entered into financial commodity derivative contracts in the form of fixed price oil and natural gas swap agreements, three-way collars utilizing purchased and written option contracts, sold swaption contracts and fixed price swaps with sub floors in order to receive fixed prices or set price floors for a portion of the Company’s future oil and natural gas production when management believes that favorable future prices can be secured. Sabine typically hedges the NYMEX Henry Hub price for natural gas and the NYMEX West Texas Intermediate (“WTI”) price for crude oil.

Sabine’s hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. Under the terms of Sabine’s fixed price swap agreements, the counterparty is required to make a payment to the Company for the difference between the fixed price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the fixed price. Sabine is required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the fixed price is below the settlement price. Additionally, the Company sets pricing floors for certain production by executing combinations of option agreements including written calls, purchased puts and written puts to create three-way collars. Three-way collar contracts combine a short put (the lower price), a long put (the middle price) and a short call (the higher price) to provide a higher ceiling price as compared to a regular collar and limit downside risk to the market price plus the difference between the middle price and the lower price if market price drops below the lower price. For these contracts, if the applicable monthly price indices

settle outside the range of the floor, sub floor and ceiling prices set by the various options, Sabine and the counterparty to the option contracts would be required to settle the difference. Swaps with sub floor consist of a standard swap contract plus a put option sold with a strike below the associated fixed swap. This structure enables the Company to increase the fixed price swap with the value received through the sale of the put. If the settlement price for any settlement period falls equal to the or below the put strike, then Sabine will only receive the difference between the swap price and the put strike price. If the settlement price is greater than the put strike, the result is the same as it would have been with a standard swap only. Additionally, Sabine has sold a swaption agreement allowing the counterparty the option to execute a fixed price swap agreement at a contracted price on contracted volumes before an expiration date. Sabine’s sold swaption contract expires at December 31, 2015.

At December 31, 2014, Sabine had in place oil and natural gas swaps and purchased and written oil and natural gas options covering portions of anticipated production through December 2016. The New Revolving Credit Facility allows the Company to hedge up to 100% of current production for 24 months, 75% of current production for months 25 to 36 and 50% of current production for months 37 to 60.

All derivative instruments are recorded at fair market value and are included in the Condensed Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk

Sabine expects continued volatility in the fair value of the Company’s derivative instruments. Cash flow is only impacted when the underlying physical sales transaction takes place in the future and when the associated derivative instrument contract is settled by making or receiving a payment to or from the counterparty. As of December 31, 2014, Sabine had economically hedged a portion of oil and natural gas production through December 2015 as follows:

	Natural Gas				Oil
	MMbtu/d		Average price		Bbl/Day		Average price
Year ending December 31, 2015		222,932	$	4.18		6,045	$	89.95

Additionally, the Company has purchased and sold certain options on oil and natural gas; using these contracts in combination with oil and natural gas swap agreements to further mitigate pricing risk associated with anticipated production. The Company received a premium on certain sold options, which was used to execute natural gas swap contracts above market. The details of the Company’s hedge positions and options sold are as follows:

Natural Gas
				Weighted Average Prices
Settlement Period	Derivative Instrument	Notional Amount		Swap		Sub Floor		Floor		Ceiling
		(Mmbtu)		($/Mmbtu)
2015	Collar		5,450,000	$	—	$	3.25	$	4.23	$	4.63
2015	Swap		54,020,000	$	4.15	$	—	$	—	$	—
2015	Swap with sub floor		21,900,000	$	4.25	$	3.70	$	—	$	—

Oil
				Weighted Average Prices
Settlement Period	Derivative Instrument	Notional Amount		Swap		Sub Floor		Floor		Ceiling
		(Bbl)		($/Bbl)
2015	Swap		2,206,350	$	90.02	$	—	$	—	$	—
2015	Swap with sub floor		339,450	$	89.50	$	73.47	$	—	$	—
2016	Swaption		365,000		98.00

By removing price volatility from a portion of expected oil and natural gas production through December 2015, Sabine has partially mitigated the potential effects of changing prices on operating cash flow for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits the Company would receive from increases in commodity prices.

By using derivative instruments to hedge exposures to changes in commodity prices, Sabine exposes the Company to the credit risk of counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe Sabine, which creates credit risk. To minimize the credit risk in derivative instruments, it is Sabine’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive

market makers. The creditworthiness of the Company’s counterparties is subject to periodic review. Sabine has derivative instruments in place with seven different counterparties. As of September 30, 2014, contracts with Huntington, Natixis, Bank of America Merrill Lynch, Barclays, JPMorgan Chase & Company, Comerica, Citibank and Wells Fargo accounted for 26%, 25%, 16%, 13%, 10%, 4%, 3% and 3%, respectively, of the net fair market value of Sabine O&G’s derivative assets. The Company also has contracts with Old Forest counterparties including Barclays, BP, Citi, Credit Suisse, the Toronto Dominion Bank, and Wells Fargo; however, Sabine has not completed the assessment of fair market values for the combined contracts as of December 31, 2014. Sabine believes all of these institutions currently are acceptable credit risks. Sabine is not required to provide credit support or collateral to any of the Company’s counterparties under current contracts, nor are they required to provide credit support to Sabine. As of December 31, 2014, Sabine did not have any past due receivables from counterparties.

Contractual obligations. A summary of Sabine O&G’s contractual obligations as of September 30, 2014 is provided in the following table:

	Payments due by period For the Year Ending December 31,
	2014		2015		2016		2017		2018		Thereafter		Total
	(in millions)
Legacy Sabine O&G Credit Facility(1)	$	—	$	—	$	574.0	$	—	$	—	$	—	$	574.0
Term Loan Facility(1)		—		—		—		—		650.0		—		650.0
Legacy Sabine O&G Notes(2)		—		34.1		34.1		366.8		—		—		435.0
Drilling rig commitments(3)		2.4		20.7		21.6		12.6		—		—		57.3
Office and equipment leases		0.9		2.8		0.9		—		—		—		4.6
Gathering agreements(4)		—		6.8		7.6		7.5		4.4		13.3		39.6
Other		0.3		0.6		0.1		—		—		—		1.0
Total	$	3.6	$	65.0	$	638.3	$	386.9	$	654.4	$	13.3	$	1,761.5

(1) Includes outstanding principal amounts at September 30, 2014. This table does not include future commitment fees, interest expense or other fees on these facilities because they are floating rate instruments and Sabine O&G cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2) Includes interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15.

(3) At September 30, 2014, Sabine O&G had one drilling rig under contract which expires in 2016 and two drilling rigs under contracts which expire in 2017. Any rig performing work for Sabine O&G is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the table above. The values in the table represent the gross amounts that Sabine O&G is committed to pay. However, Sabine O&G will record in the financials its proportionate share based on its working interest.

(4) Gas and condensate gathering agreements for the transportation and processing of natural gas and condensate covering certain properties in South Texas with contractually obligated annual minimum volume commitments of gas and condensate to deliver by September 22, 2024. Under the terms of the agreements, Sabine O&G is required to make annual deficiency payments for any shortfalls in delivering the minimum volumes under these commitments beginning in the third quarter.

Critical Accounting Policies, Estimates, Judgments, and Assumptions

Full Cost Method of Accounting

We use the full cost method to account for our oil and natural gas activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized and accumulated into a cost center (the amortization base), whether or not the activities to which they apply are successful. This includes any internal costs that are directly related to acquisition, exploration and development activities but does not include any costs associated with production and general corporate activities, which are expensed in the period incurred. The capitalized costs of our oil and natural gas properties, plus an estimate of our future development and abandonment costs, are amortized on a unit-of-production method based on our estimate of reserves. Unevaluated costs are excluded from the full cost pool and are periodically considered for impairment. Upon evaluation or impairment, these costs are transferred to the full cost pool and amortized. Proceeds received from disposals are credited against accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is calculated and recognized. The application of the full cost method generally results in higher capitalized costs and higher depletion rates compared to its alternative, the successful efforts method.

Oil and Gas Reserves Estimates

Our estimates of proved reserves are based on the quantities of oil and natural 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 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. The accuracy of any reserves estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as oil, natural gas, and NGL prices that we are required to use pursuant to SEC regulations change from period-to-period, the estimate of proved reserves will also change and the change can be significant. Despite the inherent uncertainty in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of- production method to amortize our oil and natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and natural gas properties are also subject to a ceiling test limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures.

Reference should be made to “Estimated Proved Reserves Associated with Sabine O&G Properties” under “Business and Properties.”

Revenue Recognition

The Company records revenues from the sales of oil, natural gas liquids and natural gas when produced, sold and collectability is ensured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, oil, natural gas liquids and natural gas sales are not recognized for deliveries in excess of the Company’s net revenue interest, while oil, natural gas liquids and natural gas sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances.

Goodwill

Goodwill is tested for impairment on an annual basis as of October 1 of each year.

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

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

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

Due to the significant judgments that go into the goodwill impairment test, as discussed above, there can be no assurance that our goodwill will not be impaired at any time in the future.

Fair Value of Derivative Instruments

We use the income approach in determining the fair value of our derivative instruments, utilizing present value techniques for valuing our swaps and option-pricing models for valuing our collars, swaptions, and puts. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. The values we report in our financial statements change as these estimates are revised to reflect changes in market conditions or other factors, many of which are beyond our control.

While not designated for hedge accounting, all of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading. All of our derivative instruments serve as economic hedges and are recorded at fair value with gains and losses recognized immediately in earnings. These marked-to market adjustments will produce a degree of earnings volatility that can be significant from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The impact to cash flow occurs upon settlement of the underlying contract.

Valuation of Deferred Tax Assets

We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are determined based on differences between the financial statement carrying values of assets and liabilities and their respective income tax bases (temporary differences). Income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect of a change in tax rates on income tax assets and liabilities is included in earnings in the period in which the change is enacted. The book value of income tax assets is limited to the amount of the tax benefit that is more likely than not to be realized in the future.

In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. In making this assessment, we consider the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies, and projected future taxable income. If the ultimate realization of deferred tax assets is dependent upon future book income, assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive, as to whether it is more likely than not that a deferred tax asset will be realized.

Asset Retirement Obligations

Forest has obligations to remove tangible equipment and restore locations at the end of the oil and natural gas production operations. Estimating the future restoration and removal costs, or asset retirement obligations (“ARO”), requires us to make estimates and judgments, because most of the obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs periodically change, as do regulatory, political, environmental, safety, and public relations considerations.

Inherent in the calculation of the present value of our ARO are numerous assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. Increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense.

Off-Balance Sheet Arrangements

From time to time, we enter into off-balance sheet arrangements and other transactions that can give rise to off-balance sheet obligations. As of December 31, 2013, the off-balance sheet arrangements and other transactions that we have entered into include (i) undrawn letters of credit, (ii) operating lease agreements, (iii) drilling commitments, and (iv) other contractual obligations for which we have recorded estimated liabilities on the balance sheet, but the ultimate settlement amounts are not fixed and determinable, such as derivative contracts, pension and other postretirement benefit obligations, and asset retirement obligations. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

Surety Bonds

In the ordinary course of our business and operations, we are required to post surety bonds from time to time with third parties, including governmental agencies. In addition, while we appeal the arbitration award in Forest Oil Corp., et al. v. El Rucio Land & Cattle Co., et al. (see “Business and Properties—Legal Proceedings”), we are required to post a supersedeas bond in the amount of $25 million. As of February 19, 2014, we had obtained this supersedeas bond and were subsequently required by the surety to obtain a letter of credit in the surety’s favor in the amount of $25 million. We also have posted surety bonds from a number of insurance and bonding institutions covering certain of our current and former operations in the United States in the aggregate amount of approximately $35 million.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm—Deloitte & Touche LLP	25
Report of Independent Registered Public Accounting Firm—PricewaterhouseCoopers LLP	26
Audited Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2013 and 2012	27
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011	28
Consolidated Statement of Member’s Capital for the Years Ended December 31, 2013, 2012 and 2011	29
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011	30
Notes to Consolidated Financial Statements	31
Unaudited Consolidated Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013 (Unaudited)	65
Condensed Consolidated Statements of Operations for the Three Months and Nine Months Ended September 30, 2014 and 2013 (Unaudited)	66
Condensed Consolidated Statement of Member’s Capital for the Nine Months Ended September 30, 2014 and Year Ended December 31, 2013 (Unaudited)	67
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013 (Unaudited)	68
Notes to Condensed Consolidated Financial Statements (Unaudited)	69

24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of

Sabine Oil & Gas LLC

Houston, Texas

We have audited the accompanying consolidated balance sheets of Sabine Oil & Gas LLC and subsidiaries (the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, member’s capital, and cash flows for each of the two years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sabine Oil & Gas LLC and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the accompanying 2012 consolidated financial statements have been restated to correct errors.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 31, 2014

25

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Member of Sabine Oil & Gas LLC

In our opinion, the accompanying consolidated statements of operations, of member’s capital and of cash flows for the year ended December 31, 2011 present fairly, in all material respects, the results of operations and cash flows of Sabine Oil & Gas LLC (formerly known as NFR Energy LLC) for the year ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As described in Note 2 to the financial statements, the 2011 financial statements have been restated to correct an error. Our opinion is not modified with regard to this matter.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 31, 2013, except with respect to our opinion on the consolidated financial statements insofar as it relates to the Restatement of Previously Issued Financial Statements as described in Note 2, as to which the date is March 31, 2014.

26

Consolidated Financial Statements

Sabine Oil & Gas LLC

Consolidated Balance Sheets

As of December 31, 2013 and 2012

	December 31, 2013			December 31, 2012
	(in thousands)
				(As Restated)
Assets
Current assets:
Cash and cash equivalents	$	11,821		$	6,193
Accounts receivable, net		71,384			33,190
Prepaid expenses and other current assets		2,910			3,618
Derivative instruments		7,806			54,855
Other short term assets		—			515
Total current assets		93,921			98,371
Property, plant and equipment:
Oil and natural gas properties (full cost method)
Proved		3,204,317			2,825,430
Unproved		208,823			332,898
Gas gathering and processing equipment		19,577			15,564
Office furniture and fixtures		11,167			9,262
		3,443,884			3,183,154
Accumulated depletion, depreciation and amortization		(2,063,842	)		(1,926,944	)
Total property, plant and equipment, net		1,380,042			1,256,210
Other assets:
Derivative instruments		4,332			1,651
Deferred financing costs, net		26,502			29,827
Goodwill		173,547			173,547
Other long term assets		375			953
Total other assets		204,756			205,978
Total assets	$	1,678,719		$	1,560,559
Liabilities and member’s capital
Current liabilities:
Accounts payable—trade	$	16,148		$	3,074
Royalties payable		33,964			8,814
Accrued interest payable		23,891			15,523
Accrued exploration and development		75,819			23,281
Accrued operating expenses and other		47,602			31,102
Derivative instruments		11,625			3,875
Other short term liabilities		278			251
Total current liabilities		209,327			85,920
Long term liabilities:
Credit facility		250,000			405,000
Term loan		645,272			490,127
Senior notes		348,040			347,411
Asset retirement obligation		13,798			13,580
Derivative instruments		11,272			18,017
Other long term liabilities		—			71
Total long term liabilities		1,268,382			1,274,206
Commitments and contingencies
Member’s capital
Member’s capital		1,523,008			1,533,008
Accumulated deficit		(1,321,998	)		(1,332,575	)
Total member’s capital		201,010			200,433
Total liabilities and member’s capital	$	1,678,719		$	1,560,559

The accompanying notes are an integral part of these consolidated financial statements.

27

Consolidated Financial Statements

Sabine Oil & Gas LLC

Consolidated Statements of Operations

For the Years Ended December 31, 2013, 2012 and 2011

	For the Year Ended December 31,
	2013			2012			2011
	(in thousands)
				(as restated)			(as restated)
Revenues
Oil, natural gas liquids and natural gas	$	354,223		$	177,422		$	201,421
Other		755			24			131
Total revenues		354,978			177,446			201,552
Operating expenses
Lease operating		42,491			41,011			27,113
Workover		2,160			2,638			2,903
Marketing, gathering, transportation and other		17,567			17,491			16,149
Production and ad valorem taxes		17,824			4,400			7,775
General and administrative		27,469			21,434			23,546
Depletion, depreciation and amortization		137,068			91,353			75,424
Gain on bargain purchase		—			—			(99,548	)
Accretion		952			862			628
Impairments		1,125			664,438			4,192
Total operating expenses		246,656			843,627			58,182
Other income (expenses)
Interest expense, net of capitalized interest		(99,471	)		(49,387	)		(39,632	)
Gain on derivative instruments		814			29,267			71,834
Other income (expenses)		912			(498	)		(389	)
Total other income (expenses)		(97,745	)		(20,618	)		31,813
Net income (loss) including noncontrolling interests		10,577			(686,799	)		175,183
Less: Net income (loss) applicable to noncontrolling interests		—			17			(117	)
Net income (loss) applicable to controlling interests	$	10,577		$	(686,782	)	$	175,066

The accompanying notes are an integral part of these consolidated financial statements.

28

Consolidated Financial Statements

Sabine Oil & Gas LLC

Consolidated Statement of Member’s Capital

For the Years ended December 31, 2013, 2012 and 2011

(in thousands)

	Member’s Capital					Amounts Receivable from Member			Accumulated Deficit			Noncontrolling Interests			Total Member’s Capital
	Units		Value
Balance as of December 31, 2010—(as restated)		1,067	$	1,065,183		$	(150	)	$	(820,859	)	$	3,035		$	247,209
Member’s contributions		203		203,000			—			—			—			203,000
Amounts receivable from member		—		—			109			—			—			109
Distributions—noncontrolling interests		—		—			—			—			(888	)		(888	)
Distributions to member for state tax withholding		—		(485	)		—			—			—			(485	)
Net income applicable to controlling interests		—		—			—			175,066			—			175,066
Net income applicable to noncontrolling interests		—		—			—			—			117			117
Balance as of December 31, 2011—(as restated)		1,270	$	1,267,698		$	(41	)	$	(645,793	)	$	2,264		$	624,128
Member’s contributions		88		87,467			—			—			—			87,467
In-kind contributions		178		178,000			—			—			—			178,000
Amounts receivable from member		—		—			41			—			—			41
Distributions—noncontrolling interests		—		—			—			—			(175	)		(175	)
Distributions to member for state tax withholding		—		(157	)		—			—			—			(157	)
Sale of noncontrolling interests		—		—			—			—			(2,072	)		(2,072	)
Net loss applicable to controlling interests		—		—			—			(686,782	)		—			(686,782	)
Net loss applicable to noncontrolling interests		—		—			—			—			(17	)		(17	)
Balance as of December 31, 2012—(as restated)		1,536	$	1,533,008		$	—		$	(1,332,575	)	$	—		$	200,433
Distributions to member		—		(10,000	)		—			—			—			(10,000	)
Net income		—		—			—			10,577			—			10,577
Balance as of December 31, 2013		1,536	$	1,523,008		$	—		$	(1,321,998	)	$	—		$	201,010

The accompanying notes are an integral part of these consolidated financial statements.

29

Consolidated Financial Statements

Sabine Oil & Gas LLC

Consolidated Statements of Cash Flows

For the Years ended December 31, 2013, 2012 and 2011

	For the Year Ended December 31,
	2013			2012			2011
	(in thousands)
				(as restated)			(as restated)
Cash flows from operating activities:
Net income (loss), including noncontrolling interest	$	10,577		$	(686,799	)	$	175,183
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		137,068			91,353			75,424
Impairments		1,125			664,438			4,192
Loss on sale of asset		—			651			600
Accretion expense		952			862			628
Accrued interest expense		10,328			2,372			1,458
Amortization of deferred rent		(249	)		(532	)		(38	)
Amortization of deferred financing costs		9,587			4,020			2,817
(Gain) loss on derivative instruments		46,545			75,735			(1,272	)
Amortization of option premiums		(1,171	)		(56	)		—
Amortization of prepaid expenses		4,787			2,546			2,482
Gain on bargain purchase		—			—			(99,548	)
Non cash distribution to member		—			(157	)		(485	)
Working capital and other changes:
Increase in accounts receivable		(38,195	)		(8,431	)		(8,855	)
Increase in other assets		(7,248	)		(5,811	)		(6,713	)
Increase in accounts payable, royalties payable and accrued liabilities		43,092			3,975			13,159
Net cash provided by operating activities		217,198			144,166			159,032
Cash flows from investing activities:
Oil and gas property additions		(360,080	)		(170,970	)		(292,648	)
Oil and gas property acquisitions		—			(559,066	)		(385,218	)
Cash received from insurance proceeds		604			12,680			—
Gas processing equipment additions		(4,014	)		(5,409	)		(3,810	)
Other asset additions		(2,075	)		(384	)		(2,952	)
Cash received from sale of assets		171,756			35,764			3,706
Net cash used in investing activities		(193,809	)		(687,385	)		(680,922	)
Cash flows from financing activities:
Borrowings under senior secured revolving credit facility		193,000			123,000			584,500
Borrowings under second lien term loan		153,500			490,000			—
Debt repayments for the senior secured revolving credit facility		(348,000	)		(136,000	)		(260,500	)
Deferred financing costs		(6,261	)		(19,227	)		(4,462	)
Member’s contributions		—			87,508			203,109
Distributions—noncontrolling interests		—			(175	)		(888	)
Distributions to member		(10,000	)		—			—
Net cash provided by (used in) financing activities		(17,761	)		545,106			521,759
Net increase (decrease) in cash and cash equivalents		5,628			1,887			(131	)
Cash and cash equivalents, beginning of period		6,193			4,306			4,437
Cash and cash equivalents, end of period	$	11,821		$	6,193		$	4,306

The accompanying notes are an integral part of these consolidated financial statements.

30

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

Effective December 19, 2012, NFR Energy LLC was renamed Sabine Oil & Gas LLC (“Sabine” or “the Company”). Sabine was established as a Delaware limited liability company in late 2006 to invest in oil and natural gas exploration opportunities within the onshore U.S. market. Sabine is wholly owned by Sabine Oil & Gas Holdings II LLC, a Delaware limited liability company (“Holdings II” or “Member”), which is wholly owned by Sabine Oil & Gas Holdings LLC, a Delaware limited liability company (“Holdings”). Sabine’s sole membership interest is owned by Holdings. Currently, affiliates of First Reserve Corporation (“First Reserve”), own approximately 99.76% of the common equity interests of Holdings and the remaining interests are owned by certain members of Sabine’s management and board of representatives.

Sabine operates in the exploration and production segment of the energy industry and is pursuing development and exploration projects in a variety of forms including operated and non-operated working interests, joint ventures, farm-outs, and acquisitions, in both conventional and unconventional resources. Sabine is a holding company which conducts its operations through its subsidiaries, which own the operating assets of Sabine.

2. Significant Accounting Policies

Basis of Presentation

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

Restatement of Previously Issued Financial Statements

Sabine is restating its financial statements for the years ended December 31, 2012 and 2011 with respect to the accounting and disclosures for certain derivative financial transactions under Accounting Standards Codification Topic 815, Derivatives and Hedging (“ASC 815”). Sabine determined that the documentation it had prepared to support its initial hedge designations for effectiveness in connection with Sabine’s oil and natural gas hedging program was not compliant with the technical documentation requirements to qualify for cash flow hedge accounting treatment in accordance with ASC 815, and as a result, Sabine was not permitted to utilize hedge accounting treatment in the preparation of its financial statements.

Under ASC 815, the fair value of hedge contracts is recognized in Sabine’s Consolidated Balance Sheets as an asset or liability, as the case may be, and the amounts received or paid under the hedge contracts are reflected in earnings during the period in which the underlying production occurs. If the hedge contracts qualify for cash flow hedge accounting treatment, the fair value of the hedge contract that is effective in offsetting changes in expected cash flows (the effective portion) is recorded in “Accumulated other comprehensive income,” and the effective portion of the changes in the fair value do not affect net income in the period. The portion of the change in fair value of the qualified derivative instrument that is not effective in offsetting changes in expected cash flows (the ineffective portion), as well as any amount excluded from the assessment of the effectiveness of the derivative instruments, are recognized in earnings. If the hedge contract does not qualify for hedge accounting treatment, the change in the fair value of the hedge contract is reflected in earnings during the period as a “Gain (loss) on derivatives” within revenues on the Consolidated Statements of Operations. Under the cash flow hedge accounting treatment used by Sabine, the effective portion of the fair value of the hedge contracts was recognized in the Consolidated Balance Sheets with the offsetting gain or loss recorded initially in “Accumulated other comprehensive income” and later reclassified through earnings when the hedged production impacted earnings. The ineffective portion of the designated derivative instruments was recognized in “Gain on derivative instruments” within Other income (expenses) on the Consolidated Statements of Operations. As a result of the determination that the designation documentation failed to meet the requirements necessary to utilize cash flow hedge accounting treatment, any gain or loss resulting from changes in fair value should have been recorded in the Consolidated Statements of Operations as a component of earnings. Sabine previously recognized gains and

31

losses resulting from the settlement of its designated derivative financial instruments as a component of revenues, and has reclassified gains of $107.4 million in 2012 and $72.5 million in 2011 to “Gain on derivative instruments” within Other income (expenses) as a result of eliminating hedge accounting. In addition, Sabine reclassified $67.8 million of losses and $25.1 million of gains in 2012 and 2011, respectively, from “Accumulated other comprehensive income” to “Gain on derivative instruments” within Other income (expenses). Because the derivatives did not qualify for hedge accounting, the inclusion of hedge value for designated contracts in the full cost ceiling calculation at all balance sheet dates when the ceiling test was performed was not appropriate. Thus, Sabine’s full cost ceiling calculations were revised and resulted in restatements to increase impairment expense recognized in earlier periods and reductions to Sabine’s ceiling test impairment expense of $62.0 million and $25.7 million in 2012 and 2011, respectively, as well as requiring restatements to decrease depletion expense by $4.5 million and $6.8 million in 2012 and 2011, respectively.

Additionally, Sabine is restating its financial statements for the year ended December 31, 2012 with respect to reversing the $14.5 million bargain purchase gain recognized for its December 17, 2012 acquisition of certain oil and natural gas properties in South Texas. Sabine reduced the fair value allocated to the oil and gas properties acquired to reflect the consideration paid which was a reflection of market participants and similar transactions in the same period. The impact of this restatement was considered regarding the full cost ceiling calculation at December 31, 2012 for adjustment to impairment expense of $14.3 million and depletion expense of $0.2 million. Factors that gave rise to bargain purchase gains in 2011 were not present in 2012.

Certain other reclassifications have been made to prior periods. These reclassifications include the correction of pricing differentials of $3.7 million and $3.6 million in 2012 and 2011, respectively, which were previously reported as “Marketing, gathering, transportation and other” costs and are currently reported as “Oil, natural gas liquids and natural gas” revenues as a reflection of realized pricing, as well a $9.9 million reclassification of loss from “Loss on sale of assets” to “Impairments” in 2012. These reclassifications also include a $5.1 million correction of the classification of Sabine’s option premiums previously reported as “Other short term liabilities” and “Other long term liabilities” and currently reported as short term and long term derivatives assets in accordance with netting requirements. These reclassifications have no impact on previously reported net income and management believes they are immaterial to previously reported financial information.

The following table represents the impact of this restatement on relevant financial statement line items in Sabine’s Consolidated Balance Sheet:

	December 31, 2012
	As Reported			Adjustments			As Restated
	(in thousands)
Assets
Property, plant and equipment:
Oil and natural gas properties (full cost method)
Proved	$	2,839,900		$	(14,470	)	$	2,825,430
Accumulated depletion, depreciation and amortization		(1,851,998	)		(74,946	)		(1,926,944	)
Other assets:
Derivative instruments		6,731			(5,080	)		1,651
Total assets	$	1,655,055		$	(94,496	)	$	1,560,559
Liabilities and member’s capital
Long term liabilities:
Other long term liabilities	$	5,151		$	(5,080	)	$	71
Member’s capital:
Accumulated deficit		(1,306,203	)		(26,372	)		(1,332,575	)
Accumulated other comprehensive income		63,044			(63,044	)		—
Total liabilities and member’s capital	$	1,655,055		$	(94,496	)	$	1,560,559

32

The following table represents the impact of this restatement on relevant financial statement line items in Sabine’s Consolidated Statements of Operations:

	Year ended December 31, 2012
	As Reported			Adjustments			As Restated
	(in thousands)
Revenues
Oil, natural gas liquids and natural gas	$	181,098		$	(3,676	)	$	177,422
Gain on derivative instruments		107,374			(107,374	)		—
Total revenues		288,496			(111,050	)		177,446
Operating expenses
Marketing, gathering, transportation and other		21,167			(3,676	)		17,491
Depletion, depreciation and amortization		96,096			(4,743	)		91,353
Gain on bargain purchase		(14,470	)		14,470			—
Impairments		730,916			(66,478	)		664,438
Loss on sale of assets		9,880			(9,880	)		—
Total operating expenses		913,934			(70,307	)		843,627
Other income (expenses)
Gain (loss) on derivative instruments		(10,312	)		39,579			29,267
Total other income (expenses)		(60,197	)		39,579			(20,618	)
Net loss including noncontrolling interests		(685,635	)		(1,164	)		(686,799	)
Net loss applicable to controlling interests	$	(685,618	)	$	(1,164	)	$	(686,782	)

	Year ended December 31, 2011
	As Reported			Adjustments			As Restated
	(in thousands)
Revenues
Oil, natural gas liquids and natural gas	$	204,989		$	(3,568	)	$	201,421
Gain on derivative instruments		72,517			(72,517	)		—
Total revenues		277,637			(76,085	)		201,552
Operating expenses
Marketing, gathering, transportation and other		19,717			(3,568	)		16,149
Depletion, depreciation and amortization		82,178			(6,754	)		75,424
Impairments		29,921			(25,729	)		4,192
Total operating expenses		94,233			(36,051	)		58,182
Other income (expenses)
Gain (loss) on derivative instruments		(25,799	)		97,633			71,834
Total other income (expenses)		(65,820	)		97,633			31,813
Net income including noncontrolling interests		117,584			57,599			175,183
Net income applicable to controlling interests	$	117,467		$	57,599		$	175,066

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The following table represents the impact of this restatement on relevant financial statement line items in Sabine’s Consolidated Statement of Member’s Capital:

Sabine Oil and Gas LLC

Consolidated Statement of Member’s Capital

	Member’s Capital				Amounts Receivable from Member			Accumulated Deficit			Other Comprehensive Income (loss)			Noncontrolling Interests		Total Member’s Capital
	Units		Value
Balance as of December 31, 2010—(as reported)		1,067	$	1,065,183	$	(150	)	$	(738,052	)	$	105,722		$	3,035	$	435,738
Adjustments to comprehensive loss:
Net loss applicable to controlling interests		—		—		—			(82,807	)		—			—		(82,807	)
Unrealized loss on derivative contracts		—		—		—			—			(105,722	)		—		(105,722	)
Total
Balance as of December 31, 2010—(as restated)		1,067	$	1,065,183	$	(150	)	$	(820,859	)	$	—		$	3,035	$	247,209

	Member’s Capital				Amounts Receivable from Member			Accumulated Deficit			Other Comprehensive Income (loss)			Noncontrolling Interests		Total Member’s Capital
	Units		Value
Balance as of December 31, 2011—(as reported)		1,270	$	1,267,698	$	(41	)	$	(620,585	)	$	130,837		$	2,264	$	780,173
Adjustments to comprehensive loss:
Net loss applicable to controlling interests		—		—		—			(25,208	)		—			—		(25,208	)
Unrealized loss on derivative contracts		—		—		—			—			(130,837	)		—		(130,837	)
Total
Balance as of December 31, 2011—(as restated)		1,270	$	1,267,698	$	(41	)	$	(645,793	)	$	—		$	2,264	$	624,128

	Member’s Capital				Amounts Receivable from Member		Accumulated Deficit			Other Comprehensive Income (loss)			Noncontrolling Interests		Total Member’s Capital
	Units		Value
Balance as of December 31, 2012—(as reported)		1,536	$	1,533,008	$	—	$	(1,306,203	)	$	63,044		$	—	$	289,849
Adjustments to comprehensive loss:
Net loss applicable to controlling interests		—		—		—		(26,372	)		—			—		(26,372	)
Unrealized loss on derivative contracts		—		—		—		—			(63,044	)		—		(63,044	)
Total
Balance as of December 31, 2012—(as restated)		1,536	$	1,533,008	$	—	$	(1,332,575	)	$	—		$	—	$	200,433

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The following table represents the impact of this restatement on relevant financial statement line items in Sabine’s Consolidated Statements of Cash Flows:

	Year ended December 31, 2012
	As Reported			Adjustments			As Restated
	(in thousands)
Cash flows from operating activities:
Net loss, including noncontrolling interest	$	(685,635	)	$	(1,164	)	$	(686,799	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		96,096			(4,743	)		91,353
Impairments		730,916			(66,478	)		664,438
Loss on sale of asset		10,531			(9,880	)		651
Loss on derivative instruments		7,940			67,795			75,735
Gain on bargain purchase		(14,470	)		14,470			—
Net cash provided by operating activities	$	144,166		$	—		$	144,166

	Year ended December 31, 2011
	As Reported		Adjustments			As Restated
	(in thousands)
Cash flows from operating activities:
Net income, including noncontrolling interest	$	117,584	$	57,599		$	175,183
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		82,178		(6,754	)		75,424
Impairments		29,921		(25,729	)		4,192
(Gain) loss on derivative instruments		23,844		(25,116	)		(1,272	)
Net cash provided by operating activities	$	159,032	$	—		$	159,032

Cash and Cash Equivalents

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

Concentration of Credit Risk

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

Derivative instruments subject Sabine to a concentration of credit risk (see Note 8).

Inventory

Inventory, which is included in “Prepaid expenses and other current assets” on Sabine’s Consolidated Balance Sheets, consists principally of tubular goods, spare parts, and equipment used in Sabine’s drilling operations. The inventory balance, net of impairments, was $0.7 million and $1.6 million as of December 31, 2013 and 2012, respectively. Inventory is stated at the lower of weighted average cost or market. Under this method, impairments relating to obsolete inventory were $1.1 million; $1.2 million and $1.4 million for the years ended December 31, 2013, 2012 and 2011, respectively, and are included in “Impairments” in the Consolidated Statements of Operations.

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Oil and Natural Gas Properties and Equipment

Sabine uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method, Sabine capitalizes all acquisition, exploration, and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits, and other internal costs directly attributable to these activities. Sabine capitalized $6.6 million, $2.7 million and $3.5 million of internal costs during the years ended December 31, 2013, 2012 and 2011, respectively. Costs associated with production and general corporate activities are expensed in the period incurred. Sabine also includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and natural gas property balance (see “Asset Retirement Obligation” below). Unless a significant portion of Sabine’s proved reserve quantities is sold (greater than 25%), proceeds from the sale of oil and natural gas properties are accounted for, as a reduction to capitalized costs, and gains and losses are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

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

Under the full cost method of accounting, a ceiling test is performed on a quarterly basis. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of “Accumulated depletion, depreciation and amortization” (“accumulated DD&A”) on Sabine’s Consolidated Balance Sheets, may not exceed the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on Sabine’s Consolidated Balance Sheets, using the unweighted average first-day-of-the-month prices for the prior twelve month period ended December 31, 2013 and 2012 (adjusted for quality and basis differentials), held flat for the life of production, discounted at 10%, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as accumulated DD&A.

For the year ended December 31, 2013 Sabine did not recognize an impairment for the carrying value of proved oil and natural gas properties in excess of the ceiling limitation. For the year ended December 31, 2012 Sabine recognized an impairment of $641.8 million for the carrying value of proved oil and natural gas properties in excess of the ceiling limitation mostly as a result of the decline of oil and natural gas prices. For the year ended December 31, 2011 Sabine did not recognize an impairment for the carrying value of proved oil and natural gas properties in excess of the ceiling limitation. The average of the unweighted first day of the month prices for the prior twelve month period ended December 31, 2013 was $3.67 per Mcf for natural gas. Additionally, the average of the unweighted first day of the month prices for the prior twelve month period ended December 31, 2013 was $96.78 per Bbl for oil. As of December 31, 2013, the ceiling limitation exceeded the carrying value of proved oil and natural gas properties by approximately $201 million. Sabine could have a reduction in its asset carrying value for oil and natural gas properties if the average of the unweighted first day of the month natural oil and natural gas prices for the prior twelve month periods declines.

Gathering assets and related facilities, certain other property and equipment, and furniture and fixtures are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from 3 to 30 years. These assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is then recognized if the carrying amount is not recoverable and exceeds fair value. No impairment charge for gas gathering and processing equipment was recorded in the year ended December 31, 2013. In 2012, Sabine recorded impairment charges for gas gathering and processing equipment of $21.4 million based on expected present value and estimated future cash flows using current volume throughput and pricing assumptions, for properties which were

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subsequently sold in August 2012. No impairment charge for gas gathering and processing equipment was recorded in the year ended December 31, 2011. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.

Sabine’s depletion, depreciation and amortization (“DD&A”) expense on its oil and natural gas properties is calculated each quarter utilizing period end reserve quantities. For the years ended December 31, 2013, 2012 and 2011, Sabine recorded $134.2 million, $87.6 million and $71.2 million, respectively, of depletion on oil and natural gas properties. As a rate of production, depletion was $2.10 per Mcfe, $1.80 per Mcfe and $1.61 per Mcfe for the years ended December 31, 2013, 2012 and 2011, respectively.

For the years ended December 31, 2013 and 2012, Sabine received insurance proceeds of $0.6 million and $12.7 million, respectively, which were netted with the replacement costs recognized in oil and natural gas properties. Insurance proceeds were received as the result of control of well events during drilling or completion operations in East Texas. No insurance proceeds were received for the year ended December 31, 2011.

Capitalized Interest

Sabine capitalizes interest costs to oil and natural gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Sabine capitalized $13.0 million, $4.3 million and $5.9 million of interest during the years ended December 31, 2013, 2012 and 2011, respectively.

Leases

Sabine accounts for leases with escalation clauses and rent holidays on a straight-line basis. The deferred rent expense liability associated with future lease commitments is reported under the caption “Other short term liabilities” on Sabine’s Consolidated Balance Sheets.

Derivative Instruments and Hedging Activities

Sabine uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. Such derivative instruments, which are placed with major financial institutions who are participants in Sabine’s Credit Facility (see Note 5) that Sabine believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps, options, or basis swaps.

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

Sabine’s derivatives instruments at December 31, 2013 included natural gas basis swaps in addition to fixed price swaps and oil and natural gas options. The basis swaps are used to minimize exposure to fluctuating differentials on certain pricing indices against other pricing indices. These instruments are settled monthly. Upon settlement, Sabine will pay a floating price on a specified index, and the counterparty will pay a floating price on

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a different specified index, either of which may include a specified differential. When Sabine’s specified index price is less than the counterparties, the counterparty will pay Sabine. When Sabine’s specified index price is greater than the counterparties specified index price, Sabine will pay the counterparty. Additionally, Sabine has bought and sold natural gas puts, bought and sold oil and natural gas calls and sold oil puts. For the oil and natural gas calls, the counterparty has the option to purchase a set volume of the contracted commodity at a contracted price on a contracted date in the future. For the oil and natural gas puts, the counterparty has the option to sell a contracted volume of the commodity at a contracted price on a contracted date in future.

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

Deferred Financing Costs

Deferred financing costs of approximately $6.3 million and $19.2 million were incurred during 2013 and 2012, respectively, and include costs associated with Sabine’s term loan agreement (“Term Loan”) and senior secured revolving credit facility (“Credit Facility”) (see Note 5). Deferred financing costs associated with the Term Loan, Credit Facility and 9.75% senior unsecured notes due 2017 (the “2017 Notes”) are being amortized over the life of the respective obligations with $9.0 million, $3.2 million and $2.8 million included in interest expense during 2013, 2012 and 2011, respectively. As a result of reductions in the borrowing base of Sabine’s Credit Facility, Sabine also expensed $0.6 million and $0.8 million, in 2013 and 2012, respectively.

Financial Instruments

Sabine’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Sabine’s Credit Facility and Term Loan are reported at carrying value which approximates fair value based on current rates applicable to similar instruments. Since considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts Sabine could realize upon the purchase or refinancing of such instruments. Sabine’s derivative instruments are reported at fair value based on Level 2 fair value methodologies and the 2017 Notes are reported at carrying value but further compared to fair value based on Level 2 fair value methodologies (see Note 9).

Goodwill

Goodwill represents the excess of the purchase price of an asset over the estimated fair value of the assets acquired. Sabine assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. Goodwill totaled $173.5 million at December 31, 2013 and 2012. The goodwill was recognized during 2012 as a result of Sabine’s December 2012 acquisitions discussed in Note 4—Property Acquisitions and Divestitures. No impairment of goodwill was recognized during 2013 and 2012.

Asset Retirement Obligations

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

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its future estimated value using the same assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. The capitalized costs associated with an ARO are included in the amortization base for purposes of calculating the ceiling test.

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

	For the year ended December 31,
	2013			2012
	(in thousands)
Beginning balance	$	13,580		$	15,348
Liabilities incurred		993			1,887
Liabilities disposed		(1,678	)		(4,689	)
Liabilities settled		(49	)		(102	)
Change in estimate		—			274
Accretion expense		952			862
Ending balance	$	13,798		$	13,580

Revenue Recognition

Sabine records revenues from the sales of oil, natural gas liquids and natural gas when produced, sold and collectability is ensured. Sabine uses the entitlement method that requires revenue recognition for its net revenue interest of sales from its properties. Accordingly, oil, natural gas liquids and natural gas sales are not recognized for deliveries in excess of Sabine’s net revenue interest, while oil, natural gas liquids and natural gas sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. Sabine had no material overproduction or underproduction at December 31, 2013 and 2012.

Additionally, Sabine owns and operates certain gathering facilities in Texas and charges fees to collect and transport produced natural gas from common delivery points to locations along the sales stream. These gathering fees are reported in “Other revenue” on the Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011.

Use of Estimates

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

Sabine’s consolidated financial statements are based on a number of significant estimates, including oil, natural gas liquids and natural gas reserve quantities that are the basis for the calculation of DD&A and impairment of oil, natural gas liquids and natural gas properties, and timing and costs associated with its asset retirement obligations.

Income Taxes

Sabine is a limited liability company treated as a partnership for federal and state income tax purposes with all income tax liabilities and/or benefits of Sabine being passed through to the Member. As such, no recognition of federal or state income taxes for Sabine or its subsidiaries that are organized as limited liability companies have been provided for in the accompanying consolidated financial statements. Any uncertain tax position taken by the Member is not an uncertain position of Sabine.

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In accordance with the operating agreement of Sabine, to the extent possible without impairing Sabine’s ability to continue to conduct its business and activities, and in order to permit its Member to pay taxes on the taxable income of Sabine, it would be required to make distributions to the Member in the amount equal to the estimated tax liability of such Member computed as if the Member paid income tax at the highest marginal federal and state rate applicable to an individual resident of New York, New York, in the event that taxable income is generated for the Member. There was no taxable income and therefore no distributions to the Member in 2013, 2012 or 2011.

Recent Accounting Pronouncements

In December 2011, the FASB issued Accounting Standards Update 2011-11, “Disclosures About Offsetting Assets and Liabilities” (“ASU 2011-11”), which was clarified by Accounting Standards Update 2013-01. These updates amend the disclosure requirements on offsetting assets and liabilities by requiring improved information about financial instruments and derivative instruments that have a right of offset or are subject to an enforceable master netting arrangement or similar agreement. This information will enable users of a company’s financial statements to evaluate the effect or potential effect of netting arrangements on a company’s financial position, including the effect or potential effect of rights of setoff associated with certain financial instruments and derivative instruments. Sabine is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. Sabine adopted the provisions of ASU 2011-11 in the quarter ended March 31, 2013. As ASU 2011-11 relates to disclosure requirements, there will be no impact on Sabine’s financial condition or results of operations. Refer to Note 8 for updated disclosure.

3. Significant Customers

During the year ended December 31, 2013, purchases by three companies exceeded 10% of the total oil, natural gas liquids and natural gas sales of Sabine. Purchases by Eastex Crude Company, Enbridge Pipeline (East Texas) LP and CP Energy LLC accounted for approximately 19%, 16% and 11% of oil, natural gas liquids and natural gas sales, respectively. During the year ended December 31, 2012, purchases by four companies exceeded 10% of the total oil, natural gas liquids and natural gas sales of Sabine. Purchases by Enbridge Pipeline (East Texas) LP, Shell Trading (US) Company, Texla Energy Management LLC and Eastex Crude Company accounted for approximately 17%, 14%, 13% and 12% of oil, natural gas liquids and natural gas sales, respectively. During the year ended December 31, 2011, purchases by three companies exceeded 10% of the total oil, natural gas liquids and natural gas sales of Sabine. Purchases by Enbridge Pipeline (East Texas) LP, Texla Energy Management LLC and PVR Midstream LLC accounted for approximately 18%, 15% and 13% of oil, natural gas liquids and natural gas sales, respectively.

4. Property Acquisitions and Divestitures

On December 18, 2013, Sabine closed on the sale of its interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area for $169.0 million, net of certain purchase price adjustments. The sale of the Texas Panhandle and surrounding Oklahoma properties was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

On April 30, 2013, Sabine closed on the purchase of interests in approximately 5,000 net acres in South Texas for approximately $14.9 million. The acquisition does not qualify as a business combination under Accounting Standards Codification Topic 805, Business Combinations (“ASC 805”).

Total costs incurred for oil and natural gas property acquisitions for 2012 were approximately $737.1 million, net of purchase price adjustments, of which $145.1 million related to unproved property, $420.2 million related to proved property acquisitions, and $173.5 million related to goodwill. Total costs incurred for related gathering and processing facilities was approximately $5.7 million, net of purchase price adjustments. The goodwill resulted most significantly from movement in inputs used by Sabine, such as estimated type curves,

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recovery rates, and future rates of production that were updated in addition to applying risk adjustment discount rates, as well as expected synergies from combining operations of the acquiree and the acquiror.

The results of the acquisitions described below are included in the accompanying Consolidated Statements of Operations since each acquisitions respective close date.

On December 14, 2012, Sabine closed the acquisition of certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area for $657.8 million, net of purchase price adjustments. The acquisition was funded in part by $181.6 million of equity contributed by the Member with the remaining balance funded from the proceeds of the Term Loan. This acquisition qualified as a business combination. Sabine recorded a fair value of $340.9 million for proved property and $145.1 million for unproved acreage, net of the ARO liability assumed of $1.7 million. This transaction resulted in the recognition of $173.5 million of goodwill for the excess of the consideration transferred over the net assets received and represents the future economic benefits arising from assets acquired that could not be individually identified and separately recognized. The valuation to derive the purchase price included both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition (in millions):

Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved properties	$	340.9
Unproved properties		145.1
Goodwill		173.5
Asset retirement obligation		(1.7	)
Consideration, net of accrued purchase price adjustments	$	657.8

The unaudited pro forma results presented below have been prepared to give the effect of the acquisition discussed above on Sabine’s results of operations for the years ended December 31, 2012 and 2011 as if it had been consummated on January 1, 2011. The unaudited pro forma results do not purport to represent what Sabine’s actual results of operations would have been if the acquisition had been completed on such date or to project Sabine’s results of operations for any future date or period.

	Year ended December 31, 2012						Year ended December 31, 2011
	Actual			Pro Forma			Actual		Pro Forma
	(in thousands)
Pro Forma (unaudited)	(as restated)						(as restated)
Total revenues	$	177,446		$	258,362		$	201,552	$	251,395
Net loss applicable to controlling interests(1)	$	(686,782	)	$	(385,929	)	$	175,066	$	213,016

(1) Reductions in operating expenses due to pro forma ceiling test impact of $252.1 million for 2012 have been included in pro forma results above.

On December 17, 2012, Sabine closed the acquisition of certain oil and natural gas properties in South Texas for $79.3 million, net of purchase price adjustments. This acquisition qualified as a business combination pursuant to ASC 805. Sabine recorded a fair value of $79.3 million for proved property. The valuation to derive the purchase price included proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates.

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The unaudited pro forma results presented below have been prepared to give the effect of the acquisition discussed above on Sabine’s results of operations for the years ended December 31, 2012 and 2011 as if it had been consummated on January 1, 2011. The unaudited pro forma results do not purport to represent what Sabine’s actual results of operations would have been if the acquisition had been completed on such date or to project Sabine’s results of operations for any future date or period.

	December 31, 2012						December 31, 2011
	Actual			Pro Forma			Actual		Pro Forma
	(in thousands)
Pro Forma (unaudited)	(as restated)						(as restated)
Total revenues	$	177,446		$	181,197		$	201,552	$	213,412
Net loss applicable to controlling interests(1)	$	(686,782	)	$	(648,246	)	$	175,066	$	184,495

(1) Reductions in operating expenses due to pro forma ceiling test impact of $37.8 million for 2012 have been included in pro forma results above.

Acquired properties that are considered to be business combinations are recorded at their fair value. In determining the fair value of the properties, Sabine prepares estimates of oil and natural gas reserves. Sabine uses estimated future prices to apply to the estimated reserve quantities acquired and the estimated future operating and development costs to arrive at the estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. To compensate for inherent risks of estimating and valuing reserves, proved undeveloped, probable and possible reserves are reduced by additional risk-weighting factors.

On August 31, 2012, Sabine closed on the sale of its interests in Montana oil and natural gas properties for $15.8 million, net of purchase price adjustments. The sale of the Montana oil and natural gas properties was accounted for as an adjustment to the full cost pool with no gain or loss recognized. Concurrently with the sale of the Montana oil and natural gas properties, Sabine closed on the sale of its controlling ownership interests in Montana gathering entities Lodge Creek Pipelines, LLC and Willow Creek Gathering, LLC for a combined $2.5 million, net of purchase price adjustments.

On May 22, 2012, Sabine closed on the sale of its interests in Utah oil and natural gas properties for $18.2 million, net of purchase price adjustments. The sale of the Utah oil and natural gas properties was accounted for as an adjustment to the full cost pool with no gain or loss recognized.

Total costs incurred for 2011 were approximately $396.4 million (excluding related asset retirement costs), of which approximately $31.3 million related to unproved properties, $365.1 million related to proved property acquisitions, and no goodwill acquired.

On November 14, 2011, Sabine closed on the acquisition of certain oil and natural gas properties in East Texas for $222 million, net of purchase price adjustments. This acquisition qualified as a business combination pursuant to ASC 805. Sabine recorded a fair value of $235.1 million for proved property and $5.3 million for unproved acreage, which resulted in a bargain purchase gain of $18.4 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for the proved developed and undeveloped reserves and unproved acreage.

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The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition:

	Year Ended December 31, 2011
	(in millions)
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	235.1
Unproved leasehold properties		5.3
Bargain purchase gain		(18.4	)
Cash, net of accrued purchase price adjustments	$	222.0

The unaudited pro forma results presented below have been prepared to give the effect of the acquisition discussed above on Sabine’s results of operations for the year ended December 31, 2011 as if it had been consummated on January 1, 2010. The unaudited pro forma results do not purport to represent what Sabine’s actual results of operations would have been if the acquisition had been completed on such date or to project Sabine’s results of operations for any future date or period.

	Year Ended December 31, 2011
	Actual		Pro Forma
	(in thousands)
Pro Forma (unaudited)	(as restated)
Total revenues	$	201,552	$	241,169
Net income applicable to controlling interests(1)	$	75,518	$	90,973

(1) Bargain purchase gain of $99.5 million, recognized in operating expenses, has been excluded from actual results above.

On August 18, 2011, Sabine closed on the acquisition of certain oil and natural gas properties in East Texas for $102.6 million, net of purchase price adjustments. This acquisition qualified as a business combination pursuant to ASC 805. Sabine recorded a fair value of $142.3 million for proved property and $14.8 million for unproved acreage, which resulted in a bargain purchase gain of $54.5 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for the proved developed and undeveloped reserves and unproved acreage, as well as an upward shift in the forward price curve at the time of closing.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition:

	December 31, 2011
	$ (in millions)
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved properties	$	142.3
Unproved properties		14.8
Bargain purchase gain		(54.5	)
Cash, net of accrued purchase price adjustments	$	102.6

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The unaudited pro forma results presented below have been prepared to give the effect of the acquisition discussed above on Sabine’s results of operations for the year ended December 31, 2011 as if it had been consummated on January 1, 2010. The unaudited pro forma results do not purport to represent what Sabine’s actual results of operations would have been if the acquisition had been completed on such date or to project Sabine’s results of operations for any future date or period.

	Year Ended December 31, 2011
	Actual		Pro Forma
	(in thousands)
Pro Forma (unaudited)	(as restated)
Total revenues	$	201,552	$	216,071
Net income applicable to controlling interests(1)	$	75,518	$	84,456

(1) Bargain purchase gain of $99.5 million, recognized in operating expenses, has been excluded from actual results above.

On January 31, 2011 and February 8, 2011, Sabine entered into agreements to purchase working interests in developed and undeveloped acreage in East Texas for $60.7 million and $11.2 million, respectively, for a total adjusted purchase price of $71.8 million, which qualified as a business combination pursuant to ASC 805. Sabine recorded a fair value of $87.4 million for developed acreage, which resulted in a bargain purchase gain of $26.7 million that was recorded in the current period’s earnings. The valuation to derive the purchase price included proved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates considering a depressed natural gas market. The gain was a result of fair market value in excess of the discounted purchase price for both proved developed and undeveloped reserves and unproved acreage, as well as a result of an upward shift in the forward price curve at the time of closing and receipt of updated production data for the recent producing wells that improved the well economics.

The following table summarizes the consideration paid and the amounts of the assets acquired and liabilities assumed as of the date of acquisition:

	Year Ended December 31, 2011
	$ (in millions)
Recognized amounts of identifiable assets acquired and liabilities assumed:
Proved developed properties	$	87.4
Unproved leasehold properties		11.2
Asset retirement obligation		(0.1	)
Bargain purchase gain		(26.7	)
Cash, net of accrued purchase price adjustments	$	71.8

The unaudited pro forma results presented below have been prepared to give the effect of the acquisitions discussed above on Sabine’s results of operations for the year ended December 31, 2011 as if it had been consummated on January 1, 2010. The unaudited pro forma results do not purport to represent what Sabine’s actual results of operations would have been if these acquisitions had been completed on such date or to project Sabine’s results of operations for any future date or period.

	Year Ended December 31, 2011
	Actual		Pro Forma
	(in thousands)
Pro Forma (unaudited)	(as restated)
Total revenues	$	201,552	$	204,434
Net income applicable to controlling interests(1)	$	75,518	$	77,768

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(1) Bargain purchase gain of $99.5 million, recognized in operating expenses for 2011, has been excluded from actual results above.

Sabine incurred $371.5 million and $56.1 million in development costs, for 2013 and 2012, respectively. Sabine incurred exploration costs of $4.6 million and $43.1 million in 2013 and 2012, respectively.

The costs of unproved properties are excluded from amortization until the properties are evaluated. Sabine reviews all of its 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. Unevaluated properties are grouped by major prospect area where individual property costs are not significant. In addition, Sabine analyzes its 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 not a part of Sabine’s development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2013 and the year in which the associated costs were incurred:

	Year of Acquisition
	2013		2012		2011		Prior		Total
	(in millions)
Leasehold acquisition costs	$	20.3	$	87.7	$	2.1	$	37.4	$	147.5
Development costs(1)		46.3		—		—		4.4		50.7
Capitalized interest		5.3		1.8		1.9		1.6		10.6
Total	$	71.9	$	89.5	$	4.0	$	43.4	$	208.8

(1) Development costs excluded from the amortized base in accordance with full cost accounting rules. Substantially all of the development costs excluded from the amortization base as of December 31, 2013 relate to projects that will be completed in the first half of 2014 and either the determination of proved reserves or impairment will occur. The leasehold acquisition costs were incurred for leases which will be developed, impaired or will expire over approximately ten years.

5. Long-Term Debt

Senior Notes

On February 12, 2010, Sabine and its subsidiary Sabine Oil & Gas Finance Corporation, formerly NFR Energy Finance Corporation, co-issued $200 million in 9.75% senior unsecured notes due 2017 (the “2017 Notes”) in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act of 1933 and to persons outside the United States in compliance with Regulation S of the Securities Act of 1933. The 2017 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15 each year commencing August 15, 2010. The 2017 Notes were issued at 98.73% of par. In conjunction with the issuance of the 2017 Notes, Sabine recorded a discount of $2.5 million to be amortized over the remaining life of the 2017 Notes utilizing the simple interest method. The remaining unamortized discount was $1.1 million and $1.5 million at December 31, 2013 and 2012, respectively. The 2017 Notes were issued under and are governed by an indenture dated February 12, 2010 between Sabine, Sabine Oil & Gas Finance Corporation, the Bank of New York Mellon Trust Company, N.A. as trustee, and Sabine’s subsidiaries named therein as guarantors.

All of Sabine’s restricted subsidiaries that guarantee its senior secured revolving Credit Facility (other than Sabine Oil & Gas Finance Corporation) have guaranteed the 2017 Notes on a senior unsecured basis.

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On April 14, 2010, Sabine and Sabine Oil & Gas Finance Corporation issued an additional $150 million in senior notes at 9.75% due 2017. The additional notes were issued at 98.75% of par and bear interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15 of each year commencing August 15, 2010. The additional notes were issued under the same indenture as the 2017 Notes issued on February 12, 2010. Sabine recorded a discount of $1.9 million to be amortized over the remaining life of the 2017 Notes utilizing the simple interest method. The remaining unamortized discount was $0.8 million and $1.1 million at December 31, 2013 and 2012, respectively.

Sabine may redeem the 2017 Notes, in whole or in part, at any time on or after February 15, 2014, at a redemption price (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below:

Year	Percentage
2014		104.875
2015		102.438
2016		100.000

The indenture governing the 2017 Notes contains covenants that, among other things, limit Sabine’s ability and the ability of its restricted subsidiaries to incur additional indebtedness unless the ratio of Sabine’s adjusted consolidated EBITDA to its adjusted consolidated interest expense over the trailing four fiscal quarters will be at least 2.0 to 1.0 (subject to exceptions for borrowings within certain limits under Sabine’s Credit Facility); pay dividends or repurchase or redeem equity interests; limit dividends or other payments by restricted subsidiaries that are not guarantors to Sabine or its other subsidiaries; make certain investments; incur liens; enter into certain types of transactions with its affiliates; and sell assets or consolidate or merge with or into other companies. However, if the 2017 Notes have an investment grade rating from Standard & Poor’s Ratings Group, Inc. and Moody’s Investors Service, Inc., and no default or event of default exists under the indenture, Sabine will not be subject to certain of the foregoing covenants.

Senior Secured Revolving Credit Facility

On November 30, 2007, Sabine entered into a senior secured revolving credit facility (“Credit Facility”) with a syndicate of banks. Through a series of redeterminations, Sabine has amended and restated the Credit Facility. The most recent redetermination effective November 7, 2013, increased the borrowing base from $550 million to $675 million. Effective December 18, 2013, the borrowing base was reduced from $675 million to $620 million due to the sale of certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area. The next scheduled redetermination will be in April 2014.

As of December 31, 2013, commitments under the Credit Facility were $750 million, the borrowing base was $620 million, the outstanding balance amount totaled $250 million and Sabine was able to incur approximately $370 million of additional secured indebtedness under the Credit Facility. The Credit Facility’s maturity date is April 7, 2016.

Subsequent to the period ended December 31, 2013, through March 31, 2014, Sabine has borrowed $130 million and has repaid $25 million. As of March 31, 2014 after giving effect to the net amount of borrowings and repayments, the borrowing base under the Credit Facility was $620 million, the outstanding amount totaled $355 million and Sabine had approximately $265 million of secured indebtedness available under the Credit Facility.

Borrowings made under the Credit Facility are guaranteed by first priority perfected liens and security interests on substantially all assets of Sabine and its wholly-owned domestic subsidiaries.

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Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (ABR). The Eurodollar rate is calculated as London Interbank Offered Rate (LIBOR) plus an applicable margin that varies from 1.75% (for periods in which Sabine has utilized less than 30% of the borrowing base) to 2.75% (for periods in which Sabine has utilized equal to or greater than 90% of the borrowing base). The ABR is calculated as the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) Eurodollar rate on such day (or if such day is not a business day, the immediately preceding business day) plus 1.5%. Sabine elects the basis of the interest rate at the time of each borrowing. In addition, Sabine pays a commitment fee of 0.50% under the Credit Facility (quarterly in arrears) for the amount that the aggregate commitments exceed borrowings under the Credit Facility.

Under the Credit Facility, Sabine may request letters of credit, provided that the borrowing base is not exceeded or will not be exceeded as a result of issuance of the letter of credit. There were no outstanding letters of credit on December 31, 2013 or 2012.

The Credit Facility requires Sabine to comply with certain financial covenants to maintain (a) a current ratio, defined as a ratio of consolidated current assets (including the unused amount of the total commitments under the Credit Facility, but excluding noncash assets under ASC 815, Derivatives and Hedging), to consolidated current liabilities (excluding noncash obligations under ASC 815 and the current maturities under the Credit Facility, determined at the end of each quarter), of not less than 1.0 to 1.0; (b) an interest coverage ratio at the end of each quarter defined as a ratio of EBITDA (as such terms are defined in the Credit Facility) for the period of four fiscal quarters then ending to interest expense for such period of not less than 2.5 to 1.0.

In addition, the Credit Facility contains covenants that restrict, among other things, Sabine’s ability to incur other indebtedness, create liens, or sell its assets; merge with other entities; pay dividends; enter into hedging agreements; and make certain investments.

We received a waiver from our lenders to make a one time payment in June 2013 to Nabors in the amount of $10.0 million in order to satisfy Holdings’ commitment to Nabors that was otherwise guaranteed by First Reserve.

At December 31, 2013 and 2012, Sabine was in compliance with its financial debt covenants under the Credit Facility.

Term Loan Agreement

Sabine entered into a $500 million term loan agreement (the “Term Loan”) on December 14, 2012 with a maturity date of November 16, 2016. On January 23, 2013, the syndication was completed with an additional funding of $150 million bringing the outstanding balance to $650 million as of December 31, 2013. Proceeds from the Term Loan were used to acquire oil and natural gas properties in December 2012 and repay borrowings under the Credit Facility in the first quarter of 2013.

Borrowings made under the Term Loan are subordinate to the liens and security interests securing the Credit Facility.

Interest on borrowings under the Term Loan accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (ABR). Effective with the close of the syndicate in January 2013, the Eurodollar rate is calculated as London Interbank Offered Rate (LIBOR) with a floor of 1.25%, plus an applicable margin of 7.50%. Sabine elects the basis of the interest rate at the time of each borrowing. The weighted average interest rate incurred on this indebtedness for the years ended December 31, 2013 and 2012 was 8.8% and 10.0%, respectively.

6. Member’s Capital

Common Units

Sabine is authorized to issue one class of units to be designated as “Common Units.” The Units are not represented by certificates. All Common Units are issued at a price equal to $1,000 per unit.

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In June 2013, the Company made a one-time payment to Nabors in the amount of $10.0 million in order to satisfy Holdings’ commitment to Nabors that was otherwise guaranteed by First Reserve.

Incentive Units

In addition to common units, Holdings established an incentive plan which provides for incentive units which have been issued to certain of Sabine’s directors, officers and employees. The incentive units have no voting rights and participate only upon liquidation events meeting certain requisite financial thresholds. No compensation expense related to the incentive units has been recognized by Sabine as the occurrence of a liquidation event is not considered probable, and thus the value of the incentive, if any, cannot be determined.

7. Statement of Cash Flows

During the year ended December 31, 2013, Sabine’s noncash investing and financing activities consisted of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to Sabine’s oil and natural gas properties valued at $1.0 million.

• Working capital related to capital expenditures as of December 31, 2013 was $90.3 million.

During the year ended December 31, 2012, Sabine’s noncash investing and financing activities consisted of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to Sabine’s oil and natural gas properties valued at $1.9 million.

• Working capital related to capital expenditures as of December 31, 2012 was $25.9 million.

• In-kind contribution of assets for an equity interest in Sabine of $178.0 million.

During the year ended December 31, 2011, Sabine’s noncash investing and financing activities consisted of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to Sabine’s oil and natural gas properties valued at $5.7 million.

• Recognition of bargain purchase gains of $99.5 million related to the recognition of the fair market value in excess of the consideration paid for proved developed and undeveloped reserves and undeveloped acreage.

• Working capital related to capital expenditures as of December 31, 2011 was $56.2 million.

Sabine paid $89.7 million, $47.1 million and $41.1 million for interest during 2013, 2012 and 2011, respectively.

8. Derivative Financial Instruments

Sabine is exposed to risks associated with unfavorable changes in the market price of natural gas as a result of the forecasted sale of its production and uses derivative instruments to hedge or reduce its exposure to certain of these risks. For these derivative instruments, Sabine did not elect hedge accounting for accounting purposes or did not qualify for hedge accounting treatment and, accordingly, recorded the net change in the mark-to-market valuation of these derivative instruments in the Consolidated Statements of Operations.

All of Sabine’s derivative instruments serve as economic hedges and are recorded at fair value with gains and losses recognized immediately in earnings. These marked-to-market adjustments will produce a degree of earnings volatility that can be significant from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The impact to cash flow occurs upon settlement of the underlying contract.

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Throughout the year ended December 31, 2013, Sabine has executed derivative contracts as market conditions allowed in order to economically hedge Sabine’s anticipated future cash flows from oil and natural gas producing activities. These include both oil and natural gas fixed-price swap agreements covering certain portions of Sabine’s anticipated 2013, 2014, and 2015 production volumes. Additionally, Sabine executed option contracts including purchased and written oil and natural gas call agreements, as well as purchased and written oil and natural gas put agreements, covering certain portions of Sabine’s anticipated 2014 oil and natural gas production. No material premiums were recognized as a result of these option agreements. None of the fixed-price swap or option contracts executed during 2013 were designated for hedge accounting, with all mark to market changes in fair value recognized currently in earnings. See the table below for specific volume, timing, and pricing details regarding Sabine’s outstanding trade positions.

In December 2012, Sabine entered into certain oil and natural gas swap contracts covering a portion of anticipated production for 2013 and 2014. These contracts were not designated as cash flow hedges at the time of their execution, with all mark to market changes recognized currently in earnings. See the table below for specific volume, timing, and pricing details regarding Sabine’s trade positions.

Additionally, during 2012 and in prior years, Sabine entered into certain option contracts on oil and natural gas. These included purchased natural gas puts, written oil and natural gas calls, and written oil and natural gas puts for periods from 2014 through 2016, for which a net premium was recognized. The net unamortized premium included in short term and long term derivative liabilities is $7.2 million and $9.0 million, respectively, at December 31, 2013. See the table below for specific volume, timing, and pricing details regarding Sabine’s derivative positions.

The following swaps and options were outstanding with associated notional volumes and contracted swap, floor, and ceiling prices that represent hedge weighted average prices for the index specified as of December 31, 2013:

Natural Gas
Settlement Period	Derivative Instrument	Notional Amount		Weighted Average Prices
				Swap		Sub Floor		Floor		Ceiling
		(Mmbtu)		($/Mmbtu)
2014	Swap		19,722,000	$	4.06
2014	Swap with sub floor		3,128,000	$	3.99	$	3.25
2014	Three-way collar		4,554,000			$	3.50	$	4.50	$	5.25
2014	Three-way collar		3,096,000			$	3.50	$	4.50	$	4.50
2014	Three-way collar		18,775,000			$	3.25	$	4.50	$	4.50
2015	Swap		18,250,000	$	4.09
2015	Sold Call		21,900,000							$	5.25
2016	Sold Call		21,960,000							$	5.00
Oil
Settlement Period	Derivative Instrument	Notional Amount		Weighted Average Prices
				Swap		Sub Floor		Floor		Ceiling
		(Bbl)		($/Bbl)
2014	Swap		1,264,725	$	92.25
2014	Swap with sub floor		122,275	$	89.13	$	70.00
2014	Sold Call		73,000							$	100.00
2015	Swap		365,000	$	89.50
2015	Sold Call		200,750							$	106.36

Sabine recorded a short term and a long term derivative asset of $7.8 million and $4.3 million, respectively, and recorded a short term and a long term derivative liability of $11.6 million and $11.3 million, respectively, related to the fair value of the derivative instrument’s prices on related volumes as of December 31, 2013.

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	For the Year Ended December 31,
	2013		2012		2011
	(in thousands)
Gain on commodity derivative instruments	$	814	$	29,267	$	71,834

Sabine received $46.2 million, $104.9 million and $70.6 million on settlements of derivatives in 2013, 2012 and 2011, respectively.

Sabine’s derivative contracts are executed with counterparties under certain master netting agreements that allow Sabine to offset assets due from, and liabilities due to, the counterparties. The table below presents the carrying value of Sabine’s derivative assets and liabilities both before and after the impact of such netting agreements on Sabine’s Consolidated Balance Sheets as of December 31, 2013 and December 31, 2012:

	Derivative Assets
		December 31, 2013			December 31, 2012
		(in thousands)
		Fair Value
Current assets	Derivative Instruments	$	15,859		$	55,230
Current liabilities(1)	Derivative Instruments		2,826			45
Total current asset fair value			18,685			55,275
Other assets	Derivative Instruments		6,488			11,908
Long term liabilities(1)	Derivative Instruments		223			5,727
Total long term asset fair value			6,711			17,635
Less: Counterparty set-off			(13,258	)		(16,404	)
Total derivative asset net fair value		$	12,138		$	56,506
	Derivative Liabilities
		December 31, 2013			December 31, 2012
		(in thousands)
		Fair Value
Current liabilities	Derivative Instruments	$	(14,451	)	$	(3,921	)
Current assets(1)	Derivative Instruments		(8,052	)		(375	)
Total current liability fair value			(22,503	)		(4,296	)
Long term liabilities	Derivative Instruments		(11,496	)		(23,744	)
Other assets(1)	Derivative Instruments		(2,156	)		(10,256	)
Total long term liability fair value			(13,652	)		(34,000	)
Less: Counterparty set-off			13,258			16,404
Total derivative liability net fair value		$	(22,897	)	$	(21,892	)

(1) Impact of counterparty right of set-off for derivative instruments subject to certain master netting agreements.

At December 31, 2013, and December 31, 2012, none of Sabine’s outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to Sabine upon any change in its credit ratings.

9. Fair Value Measurements

As discussed in Note 8, Sabine utilizes derivative instruments to hedge against the variability in cash flows associated with the forecasted sale of its anticipated future natural gas production. Sabine generally hedges a

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substantial, but varying, portion of anticipated natural gas production for the next 12 to 60 months. These derivatives are carried at fair value on the Consolidated Balance Sheets.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Sabine utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. Sabine classifies fair value balances based on the observability of those inputs.

The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

The three levels of the fair value hierarchy are as follows:

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, basis swaps, options, and collars.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table sets forth, by level, within the fair value hierarchy, Sabine’s financial assets and liabilities that were accounted for at fair value as of December 31, 2013 and 2012. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Sabine’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Recurring Fair Value Measures
	(in millions)
	Level 1		Level 2			Level 3		Total
As of December 31, 2013
Derivative Assets	$	—	$	12.1		$	—	$	12.1
Derivative Liabilities		—		(22.9	)		—		(22.9	)
Total	$	—	$	(10.8	)	$	—	$	(10.8	)
As of December 31, 2012
Derivative Assets	$	—	$	56.5		$	—	$	56.5
Derivative Liabilities		—		(21.9	)		—		(21.9	)
Total	$	—	$	34.6		$	—	$	34.6

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Derivatives listed above include commodity swaps, basis swaps, put and call options that are carried at fair value. The fair value amounts on the Consolidated Balance Sheets associated with Sabine’s derivatives resulted from Level 2 fair value methodologies, that is, Sabine is able to value the assets and liabilities based on observable market data for similar instruments. The amounts above include the impact of netting assets and liabilities with counterparties with which the right of offset exists.

The observable data includes the forward curve for commodity prices and interest rates based on quoted markets prices and prospective volatility factors related to changes in commodity prices, as well as the impact of Sabine’s non-performance risk of the counterparties which is derived using credit default swap values.

Sabine measures fair value of its long term debt based on a Level 2 methodology using quoted market prices with consideration given to the effect of Sabine’s credit risk. The carrying value of Sabine’s Credit Facility and Term Loan approximate fair value based on current rates applicable to similar instruments. The following table outlines the fair value of Sabine’s 2017 Notes as of December 31, 2013 and 2012:

	December 31, 2013		December 31, 2012
	(in thousands)
2017 Senior Notes
Carrying Value	$	348,040	$	347,411
Fair Value	$	327,698	$	326,050

Sabine utilizes fair value on a non-recurring basis to perform impairment tests as required on Sabine’s inventory, property, plant and equipment, goodwill and intangible assets. No impairment charge for gas gathering and processing equipment was recorded in the year ended December 31, 2013. For the years ended December 31, 2012 and 2011, Sabine recognized $21.4 million and $2.8 million, respectively, of impairment charges for gas gathering and processing equipment. For the years ended December 31, 2013, 2012 and 2011, Sabine recognized $1.1 million, $1.2 million and $1.4 million, respectively, of impairment charges related to the write-down of carrying value of certain sizes of casing inventory. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition (Note 4). The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified as Level 3. Additionally, Sabine uses fair value to determine the inception value of Sabine’s asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified as Level 3.

10. Commitments and Contingencies

From time to time, Sabine may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued when probable and reasonably estimable based on Sabine’s best estimate of the potential loss. While the outcome and impact of currently pending legal proceedings cannot be predicted with certainty, Sabine’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on Sabine’s consolidated operating results, financial position or cash flows.

Holdings has entered into a Committed Oilfield Services Agreement (the “Services Agreement”) with Nabors, which grants Nabors service contracts with revenues of no less than 20% and 75% of Sabine’s gross spend on hydraulic fracturing services and drilling and directional services, respectively, through December 13, 2016. If at any yearly anniversary of the execution of the Services Agreement, Sabine has failed to meet the revenue commitment for the previous 12-month period and Nabors has complied with its service obligations under the Services Agreement, Holdings may be required to pay Nabors an amount equal to the revenue shortfall multiplied by 40%, which would likely result in Holdings requesting that Sabine settle such obligations. For the annual period ended December 31, 2013, Sabine recognized a shortfall and penalty amount due to Nabors under

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the terms of the services agreement of $1.7 million which is included in “Accrued operating expenses and other” liabilities on the Consolidated Balance Sheets and “Other income (expense)” on the Consolidated Statements of Operations as of December 31, 2013 and was paid in January 2014.

As part of Sabine’s ongoing operations, since inception Sabine has contracted with affiliates of Nabors to secure drilling rigs and other services for the oil and natural gas well activity Sabine has undertaken. Amounts paid to affiliates of Nabors under these agreements totaled $55.2 million, $42.8 million and $87.3 million for the years ended December 31, 2013, 2012 and 2011, respectively, and Sabine recognized a liability on Sabine’s Consolidated Balance Sheets as of December 31, 2013 and 2012 of $8.5 million and $3.6 million, respectively, for these services which are reflected in “Accounts payable—trade” and “Accrued exploration and development” balances on Sabine’s Consolidated Balance Sheets.

As of December 31, 2013 total future commitments relating to Sabine’s secured rig and servicing contracts were $68.9 million over the next five years, which does not include non-contracted services or any estimated shortfalls required by the Nabors Services Agreement.

Sabine leases approximately 73,000 square feet of office space in downtown Houston, Texas, under a lease, which was amended effective January 1, 2014 to terminate on April 30, 2016. The average rent for this space over the life of the lease is approximately $1.8 million per year. As of December 31, 2013, total future commitments are $5.4 million.

Sabine leases approximately 11,000 square feet of office space in downtown Denver, Colorado. The lease terminates on August 31, 2014 and Sabine has the option to extend its lease term for an additional 60 months. This lease is sub leased out with proceeds to offset the rent commitments. As of December 31, 2013 total future commitments are $0.2 million.

Rent expense was approximately $1.8 million, $1.4 million and $1.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Sabine leases various office and production equipment. As of December 31, 2013, total future commitments are $0.9 million. The majority of Sabine’s operating leases continue with a month to month lease term after initial contractual obligations have expired.

As is customary in the oil and natural gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If Sabine does not pay such commitments, the acreage positions or wells may be lost.

A summary of Sabine’s contractual obligations as of December 31, 2013 is provided in the following table:

	Payments due by period For the Year Ending December 31,
	2014		2015		2016		2017		2018		Thereafter		Total
	(in millions)
Senior Secured revolving credit facility(1)	$	—	$	—	$	250.0	$	—	$	—	$	—	$	250.0
Second Lien term loan (1)		—		—		—		—		650.0		—		650.0
2017 Senior Notes		34.1		34.1		34.1		366.8		—		—		469.1
Drilling rig commitments(2)		19.3		28.5		20.1		1.0		—		—		68.9
Office and equipment leases		3.1		2.5		0.9		—		—		—		6.5
Other		0.9		0.3		0.1		—		—		—		1.3
Total	$	57.4	$	65.4	$	305.2	$	367.8	$	650.0	$	—	$	1,445.8

53

(1) Includes outstanding principal amounts at December 31, 2013. This table does not include future commitment fees, interest expense or other fees on these facilities because they are floating rate instruments and Sabine cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged.

(2) At December 31, 2013, Sabine had three drilling rigs under contract which expires in 2016. Any other rig performing work for Sabine is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the table above. The values in the table represent the gross amounts that Sabine is committed to pay. However, Sabine will record in its financials its proportionate share based on its working interest.

11. Employee Benefit Plans

Sabine co-sponsors a 401(k) tax deferred savings plan (the “Plan”) and makes it available to employees. The Plan is a defined contribution plan, and Sabine may make discretionary matching contributions of up to 6% of each participating employee’s compensation to the Plan. The contributions made by Sabine totaled approximately $972,000, $905,000 and $845,000 during the years ended December 31, 2013, 2012 and 2011, respectively.

12. Subsequent Events

Management has evaluated subsequent events through March 31, 2014, which represents the date the consolidated financial statements were issued. On March 25, 2014, the Company completed the acquisition of certain oil and natural gas properties in North Texas for approximately $20 million. The acquisition qualifies as a business combination; however, no further disclosure is feasible as of the date of this report as the Company is still in the process of determining fair value.

13. Selected Quarterly Financial Data (Unaudited)

	2013
	First (As Restated)			Second (As Restated)			Third (As Restated)			Fourth			Total
	(in thousands)
Total oil, natural gas liquids and natural gas	$	67,523		$	81,356		$	96,007		$	109,337		$	354,223
Income from operations	$	17,317		$	24,934		$	32,737		$	33,334		$	108,322
Net income (loss) applicable to controlling interests	$	(25,575	)	$	28,291		$	6,546		$	1,315		$	10,577
	2012
	First (As Restated)			Second (As Restated)			Third (As Restated)			Fourth			Total (As Restated)
	(in thousands)
Total oil, natural gas liquids and natural gas	$	48,897		$	38,580		$	41,590		$	48,355		$	177,422
Loss from operations	$	(88,129	)	$	(307,975	)	$	(233,930	)	$	(36,147	)	$	(666,181	)
Net loss applicable to controlling interests	$	(61,454	)	$	(326,616	)	$	(258,390	)	$	(40,322	)	$	(686,782	)

Sabine is restating its financial statements for each of the fiscal quarters ended March 31, 2013 and 2012, June 30, 2013 and 2012, and September 30, 2013 and 2012 with respect to the accounting and disclosures for certain derivative financial transactions under Accounting Standards Codification Topic 815, Derivatives and Hedging (“ASC 815”). Sabine determined that the formal documentation it had prepared to support its initial hedge designations for effectiveness in connection with Sabine’s oil hedging program was not compliant with the technical documentation requirements to qualify for cash flow hedge accounting treatment in accordance with ASC 815, and as a result, Sabine was not permitted to utilize hedge accounting treatment in the preparation of its financial statements. The restatements eliminate hedge accounting treatment which had been applied in 2013 and 2012 and reflect other immaterial adjustments to oil and natural gas sales.

54

Under ASC 815, the fair value of hedge contracts is recognized in Sabine’s Consolidated Balance Sheets as an asset or liability, as the case may be, and the amounts received or paid under the hedge contracts are reflected in earnings during the period in which the underlying production occurs. If the hedge contracts qualify for cash flow hedge accounting treatment, the fair value of the hedge contract that is effective in offsetting changes in expected cash flows (the effective portion) is recorded in “Accumulated other comprehensive income,” and the effective portion of the changes in the fair value do not affect net income in the period. The portion of the change in fair value of the qualified derivative instrument that was not effective in offsetting changes in expected cash flows (the ineffective portion), as well as any amount excluded from the assessment of the effectiveness of the derivative instruments, are recognized in earnings. If the hedge contract does not qualify for hedge accounting treatment, the change in the fair value of the hedge contract is reflected in earnings during the period as a “Gain (loss) on derivatives.” Under the cash flow hedge accounting treatment used by Sabine, the effective portion of the fair value of the hedge contracts was recognized in the Consolidated Balance Sheets with the offsetting gain or loss recorded initially in “Accumulated other comprehensive income” and later reclassified through earnings when the hedged production impacted earnings. The ineffective portion of the designated derivative instruments was recognized in “Gain on derivative instruments” within Other income (expenses) on the Consolidated Statements of Operations. As a result of the determination that the designation documentation failed to meet the requirements necessary to utilize cash flow hedge accounting treatment, any gain or loss resulting from changes in fair value should have been recorded in the Consolidated Statements of Operations as a component of earnings. Sabine previously recognized gains and losses resulting from the settlement of its designated derivative financial instruments as a component of Revenues, and has reclassified gains in 2012 and in 2011 to “Gain on derivative instruments” within “Other income (expenses)” as a result of eliminating hedge accounting.

55

The following tables present the restated condensed Consolidated Balance Sheets as of March 31, 2013 and 2012, June 30, 2013 and 2012 and September 30, 2013 and 2012, the restated condensed Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012, June 30, 2013 and 2012 and September 30, 2013 and 2012 and the condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012, six months ended June 30, 2013 and 2012 and nine months ended September 30, 2013 and 2012:

Sabine Oil and Gas LLC

Consolidated Balance Sheets

(Unaudited)

	March 31, 2013									June 30, 2013									September 30, 2013
	As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated
	(in thousands)									(in thousands)									(in thousands)
Assets
Derivative instruments	$	29,403		$	(1,292	)	$	28,111		$	37,802		$	(2,599	)	$	35,203		$	29,800		$	(3,841	)	$	25,959
Property, plant and equipment:
Oil and natural gas properties (full cost method) Proved		2,907,592			(14,470	)		2,893,122			3,027,316			(14,470	)		3,012,846			3,154,639			(14,470	)		3,140,169
Accumulated depletion, depreciation and amortization		(1,892,001	)		(61,114	)		(1,953,115	)		(1,924,809	)		(59,933	)		(1,984,742	)		(1,962,242	)		(58,711	)		(2,020,953	)
Other assets:
Derivative instruments		3,901			(3,788	)		113			8,276			(2,481	)		5,795			6,441			(1,239	)		5,202
Total assets	$	1,686,206		$	(80,664	)	$	1,605,542		$	1,778,925		$	(79,483	)	$	1,699,442		$	1,858,139		$	(78,261	)	$	1,779,878
Liabilities and member’s capital
Current liabilities:
Other short term liabilities	$	143		$	—		$	143		$	2,707		$	(2,599	)	$	108		$	3,972		$	(3,841	)	$	131
Long term liabilities:
Other long term liabilities		5,124			(5,080	)		44			2,499			(2,481	)		18			1,239			(1,239	)		—
Member’s capital:
Member’s capital		1,533,008			—			1,533,008			1,533,008			(10,000	)		1,523,008			1,533,008			(10,000	)		1,523,008
Accumulated deficit		(1,316,493	)		(41,657	)		(1,358,150	)		(1,295,200	)		(34,659	)		(1,329,859	)		(1,283,000	)		(40,313	)		(1,323,313	)
Accumulated other comprehensive income		33,927			(33,927	)		—			29,744			(29,744	)		—			22,868			(22,868	)		—
Total controlling interests member’s capital		250,442			(75,584	)		174,858			267,552			(74,403	)		193,149			272,876			(73,181	)		199,695
Total member’s capital		250,442			(75,584	)		174,858			267,552			(74,403	)		193,149			272,876			(73,181	)		199,695
Total liabilities and member’s capital	$	1,686,206		$	(80,664	)	$	1,605,542		$	1,778,925		$	(79,483	)	$	1,699,442		$	1,858,139		$	(78,261	)	$	1,779,878

56

	March 31, 2012									June 30, 2012									September 30, 2012
	As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated
	(in thousands)									(in thousands)									(in thousands)
Assets
Property, plant and equipment:
Accumulated depletion, depreciation and amortization	$	(1,200,366	)	$	(100,203	)	$	(1,300,569	)	$	(1,513,780	)	$	(108,801	)	$	(1,622,581	)	$	(1,763,270	)	$	(99,091	)	$	(1,862,361	)
Other assets:
Derivative instruments		39,114			—			39,114			30,121			(5,080	)		25,041			13,339			(5,080	)		8,259
Total assets	$	1,565,078		$	(100,203	)	$	1,464,875		$	1,213,088		$	(113,881	)	$	1,099,207		$	921,246		$	(104,171	)	$	817,075
Liabilities and member’s capital
Long term liabilities:
Other long term liabilities	$	721		$	—		$	721		$	5,667		$	(5,080	)	$	587		$	5,535		$	(5,080	)	$	455
Member’s capital:
Accumulated deficit		(750,736	)		43,487			(707,249	)		(1,034,326	)		463			(1,033,863	)		(1,270,511	)		(21,742	)		(1,292,253	)
Accumulated other comprehensive income		143,690			(143,690	)		—			109,264			(109,264	)		—			77,349			(77,349	)		—
Total liabilities and member’s capital	$	1,565,078		$	(100,203	)	$	1,464,875		$	1,213,088		$	(113,881	)	$	1,099,207		$	921,246		$	(104,171	)	$	817,075

57

Sabine Oil and Gas LLC

Consolidated Statements of Operations

(Unaudited)

	Three months ended March 31, 2013									Three months ended June 30, 2013								Three months ended September 30, 2013
	As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated		As Reported			Adjustments			As Restated
	(in thousands)									(in thousands)								(in thousands)
Revenues
Oil, natural gas and natural gas liquids	$	68,283		$	(760	)	$	67,523		$	81,356		$	—		$	81,356	$	96,007		$	—		$	96,007
Gain on derivative instruments		15,004			(15,004	)		—			5,205			(5,205	)		—		—			—			—
Total revenues		83,460			(15,764	)		67,696			86,762			(5,205	)		81,557		96,260			—			96,260
Operating expenses
Marketing, gathering, transportation and other		5,237			(760	)		4,477			3,744			—			3,744		4,286			—			4,286
Depletion, depreciation and amortization		27,285			(1,113	)		26,172			32,893			(1,181	)		31,712		37,518			(1,222	)		36,296
Impairments		12,719			(12,719	)		—			4			—			4		2			—			2
Total operating expenses		64,971			(14,592	)		50,379			57,804			(1,181	)		56,623		64,745			(1,222	)		63,523
Other income (expenses)
Gain (loss) on derivative instruments		(5,472	)		(14,113	)		(19,585	)		27,284			1,022			28,306		5,932			(6,876	)		(944	)
Other income (expense)		11			—			11			(9,971	)		10,000			29		82			—			82
Total other income (expense)		(28,779	)		(14,113	)		(42,892	)		(7,665	)		11,022			3,357		(19,315	)		(6,876	)		(26,191	)
Net income (loss) including noncontrolling interests		(10,290	)		(15,285	)		(25,575	)		21,293			6,998			28,291		12,200			(5,654	)		6,546
Net income (loss) applicable to controlling interests	$	(10,290	)	$	(15,285	)	$	(25,575	)	$	21,293		$	6,998		$	28,291	$	12,200		$	(5,654	)	$	6,546

	Three months ended March 31, 2012									Three months ended June 30, 2012									Three months ended September 30, 2012
	As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated
	(in thousands)									(in thousands)									(in thousands)
Revenues	$	49,816		$	(919	)	$	48,897		$	38,580		$	—		$	38,580		$	41,590		$	—		$	41,590
Oil, natural gas liquids and natural gas		26,405			(26,405	)		—			31,669			(31,669	)		—			27,060			(27,060	)		—
Gain on derivative instruments		76,132			(27,324	)		48,808			70,237			(31,669	)		38,568			68,698			(27,060	)		41,638
Total revenues
Operating expenses
Marketing, gathering, transportation and other		5,530			(919	)		4,611			4,177			—			4,177			4,429			—			4,429
Depletion, depreciation and amortization		27,028			(1,548	)		25,480			24,267			(955	)		23,312			20,296			(983	)		19,313
Impairments		140,603			(54,296	)		86,307			291,698			9,553			301,251			233,923			1,153			235,076
Loss on sale of assets		—			—			—			—			—			—			9,880			(9,880	)		—
Total operating expenses		193,700			(56,763	)		136,937			337,945			8,598			346,543			285,278			(9,710	)		275,568
Other income (expenses)
Gain (loss) on derivative instruments		(640	)		39,258			38,618			(4,488	)		(2,758	)		(7,246	)		(8,212	)		(4,854	)		(13,066	)
Total other income (expense)		(12,610	)		39,258			26,648			(15,886	)		(2,758	)		(18,644	)		(19,592	)		(4,854	)		(24,446
Net income (loss) including noncontrolling interests		(130,178	)		68,697			(61,481	)		(283,594	)		(43,025	)		(326,619	)		(236,172	)		(22,204	)		(258,376	)
Net income (loss) applicable to controlling interests	$	(130,151	)	$	68,697		$	(61,454	)	$	(283,591	)	$	(43,025	)	$	(326,616	)	$	(236,186	)	$	(22,204	)	$	(258,390	)

58

Sabine Oil and Gas LLC

Consolidated Statements of Cash Flows

(Unaudited)

	Three months ended March 31, 2013									Six months ended June 30, 2013									Nine months ended September 30, 2013
	As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated
	(in thousands)									(in thousands)									(in thousands)
Cash flows from operating activities:
Net income (loss), including noncontrolling interest	$	(10,290	)	$	(15,285	)	$	(25,575	)	$	11,003		$	(8,287	)	$	2,716		$	23,203		$	(13,941	)	$	9,262
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		27,285			(1,113	)		26,172			60,177			(2,294	)		57,883			97,695			(3,516	)		94,179
Impairments		12,719			(12,719	)		—			12,723			(12,719	)		4			12,725			(12,719	)		6
(Gain) loss on derivative instruments		5,574			29,117			34,691			(18,731	)		33,300			14,569			(13,138	)		40,176			27,038
Net cash provided by operating activities	$	22,197		$	—		$	22,197		$	83,386		$	10,000		$	93,386		$	139,771		$	10,000		$	149,771
Cash flows from financing activities:
Distributions to member	$	—		$	—		$	—		$	—		$	(10,000	)	$	(10,000	)	$	—		$	(10,000	)	$	(10,000	)
Net cash provided by (used in) financing activities	$	49,753		$	—		$	49,753		$	52,364		$	(10,000	)	$	42,364		$	107,845		$	(10,000	)	$	97,845
	Three months ended March 31, 2012									Six months ended June 30, 2012									Nine months ended September 30, 2012
	As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated
	(in thousands)									(in thousands)									(in thousands)
Cash flows from operating activities:
Net loss, including noncontrolling interest	$	(130,178	)	$	68,697		$	(61,481	)	$	(413,772	)	$	25,672		$	(388,100	)	$	(649,944	)	$	3,468		$	(646,476	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		27,028			(1,548	)		25,480			51,296			(2,503	)		48,793			71,592			(3,486	)		68,106
Impairments		140,603			(54,296	)		86,307			432,301			(44,743	)		387,558			666,223			(43,590	)		622,633
Loss on sale of asset		439			—			439			438			—			438			10,318			(9,880	)		438
Loss on derivative instruments		49			(12,853	)		(12,804	)		(1,098	)		21,574			20,476			11,524			53,488			65,012
Net cash provided by operating activities	$	31,629		$	—		$	31,629		$	79,392		$	—		$	79,392		$	106,973		$	—		$	106,973

59

SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

(UNAUDITED)

The following supplemental information regarding Sabine’s oil and natural gas producing activities is presented in accordance with the requirements of Section 932-235-50 of the ASC.

Costs Incurred

The costs incurred in oil and natural gas acquisitions, exploration and development activities were as follows:

	For the Year Ended December 31,
	2013		2012			2011
	(in thousands)
Property acquisition costs, proved	$	—	$	429,682	(1)	$	466,874
Property acquisition costs, unproved		51,184		165,657	(1)		28,663
Exploration and extension well costs		4,553		43,097	(1)		507
Development costs		371,525		56,112	(1)		274,631
Asset retirement costs		993		1,887			5,693
Total Costs	$	428,255	$	696,435	(1)	$	776,368

(1) Sabine revised this previously reported unaudited financial information to exclude the proceeds from divested properties of $39.2 million, remove the effects of bargain purchase gains as restated and to conform to current period presentation.

Capitalized Costs

The capitalized costs in oil and natural gas properties were as follows:

	For the Year Ended December 31,
	2013			2012			2011
	(in thousands)
				(as restated)			(as restated)
Proved properties	$	3,204,317		$	2,825,430		$	2,292,875
Unproved properties		208,823			332,898			208,230
		3,413,140			3,158,328			2,501,105
Accumulated depletion, depreciation and amortization		(2,049,132	)		(1,914,919	)		(1,185,582	)
Net capitalized costs	$	1,364,008		$	1,243,409		$	1,315,523

60

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES

(UNAUDITED)

Results of Operations

Results of operations for oil and natural gas producing activities, which exclude processing and other activities, corporate general and administrative expenses, and straight-line depreciation expense on non oil and gas assets, were as follows:

	For the Year Ended December 31,
	2013		2012			2011
	(in thousands)
			(as restated)			(as restated)
Revenues
Oil, natural gas liquids and natural gas	$	354,223	$	177,422		$	201,421
Operating costs:
Lease operating expenses		42,491		41,011			27,113
Workover expenses		2,160		2,638			2,903
Marketing, gathering, transportation and other		17,567		17,491			16,149
Production and ad valorem taxes		17,824		4,400			7,775
Depletion, depreciation and amortization		134,213		87,625			71,178
Impairments		—		641,891			—
Results of operations	$	139,968	$	(617,634	)	$	76,303

Oil and Natural Gas Reserves and Related Financial Data

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.

The following tables set forth Sabine’s total proved reserves and the changes in its total proved reserves. These reserve estimates are based in part on reports prepared by Ryder Scott L.P. (“Ryder Scott”) and Miller and Lents, Ltd. (“Miller and Lents”) independent petroleum engineers, utilizing data compiled by Sabine. In preparing their reports, Ryder Scott evaluated properties representing all of Sabine’s proved reserves at December 31, 2013 and Miller and Lents evaluated properties representing all of its proved reserves at December 31, 2012 and 2011. Sabine’s proved reserves are located onshore in the United States. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and the timing of future development expenditures. In addition, reserve estimates of new discoveries are more imprecise than those of properties with production history. Accordingly, these estimates are subject to change as additional information becomes available. Proved reserves are the estimated quantities of natural gas, natural gas liquids and oil that geoscience and engineering data demonstrate with reasonable certainty to be economically producible in future years from known oil and natural gas reservoirs under existing economic conditions, operating methods and government regulations at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves as of December 31, 2013, 2012 and 2011 were estimated using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve months as required under SEC rules. The average of the historical unweighted first-day-of-the-month prices for the prior twelve month

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periods ended December 31, 2013, 2012 and 2011 were $3.67, $2.76 and $4.12, respectively, for natural gas. The average of the historical unweighted first-day-of-the-month prices for the prior twelve month periods ended December 31, 2013, 2012 and 2011 were $96.78, $94.71 and $96.19, respectively, for oil. The average of the historical unweighted first-day-of-the-month prices for the prior twelve months as of March 2014 is $3.99 for natural gas and $98.30 for oil, and the future prices actually received may materially differ from current prices or the prices used in making the reserve estimates impacting the amount of proved developed and proved undeveloped reserves as of December 31, 2013. With respect to future development costs and operating expenses, Sabine derived estimates using the current cost environment at year end, which is consistent with current SEC rules.

Estimated Proved Reserves	Oil (MMbbls)			NGLS (MMbbls)			Natural Gas (Bcf)			Natural Gas Equivalents (Bcfe)
December 31, 2010		4.8			11.2			1,111.0			1,206.7
Revisions of previous estimates		(2.8	)		(5.6	)		(720.2	)		(770.6	)
Extensions and discoveries		1.3			5.1			207.1			245.7
Production		(0.7	)		(0.2	)		(39.0	)		(44.3	)
Purchases of minerals in Place		3.3			15.5			611.1			723.9
December 31, 2011		5.9			26.0			1,170.0			1,361.4
Revisions of previous estimates		(2.2	)		(12.2	)		(504.3	)		(591.1	)
Extensions and discoveries		2.2			0.4			2.6			18.0
Production		(0.3	)		(0.9	)		(41.1	)		(48.6	)
Purchases of minerals in Place		10.5			16.2			117.5			277.8
Sales of minerals in Place		(0.1	)		(0.1	)		(35.7	)		(36.7	)
December 31, 2012		16.0			29.4			709.0			980.8
Revisions of previous estimates		0.1			—			(58.3	)		(57.4	)
Extensions and discoveries		6.9			5.4			73.7			147.5
Production		(1.4	)		(1.8	)		(44.0	)		(63.4	)
Sales of minerals in Place		(4.7	)		(8.0	)		(92.1	)		(168.2	)
December 31, 2013		16.9			25.0			588.3			839.3
December 31, 2010
Proved developed		4.6			1.5			295.6			332.6
Proved undeveloped		0.2			9.7			815.4			874.1
		4.8			11.2			1,111.0			1,206.7
December 31, 2011
Proved developed		2.4			10.3			514.9			591.2
Proved undeveloped		3.5			15.7			655.1			770.2
		5.9			26.0			1,170.0			1,361.4
December 31, 2012
Proved developed		3.8			10.2			415.0			499.2
Proved undeveloped		12.1			19.3			292.9			481.6
		15.9			29.5			707.9			980.8
December 31, 2013
Proved developed		6.0			11.6			360.6			466.1
Proved undeveloped		10.9			13.4			227.7			373.2
		16.9			25.0			588.3			839.3

Revisions of previous estimates. Negative revisions of 720.2 Bcf in 2011 and 504.3 Bcf in 2012, were primarily the result the reclassification of proved undeveloped reserves to probable undeveloped reserves for

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proved undeveloped reserves that are not expected to be developed five years from the time the reserves were initially disclosed. As a result of significantly declining gas price from $4.376 in 2010 to $4.12 in 2011 to $2.76 in 2012, certain natural gas-weighted projects no longer met economic investment criteria based on the unweighted arithmetic average of the first-day-of-the-month commodity prices utilized in calculating the reserve estimates. In addition, lower natural gas prices also delayed Sabine’s initial expected development time frame for drilling certain of its proved undeveloped natural gas locations beyond five years from the time the associated reserves were originally recorded. Also as a result of increased development and operating costs, Sabine reduced the development program and rig count. Accordingly, these PUDs were reclassified to probable undeveloped reserves.

Extensions and discoveries. In 2011, Sabine had 245.7 Bcfe of extensions and discoveries, which were primarily due to exploration and development activities in Haynesville Shale and Cotton Valley in East Texas. In 2013, Sabine had 147.5 Bcfe of extensions and discoveries, which were primarily due to exploration and development activities in the Texas Panhandle and Eagle Ford in South Texas.

Purchases and sales of minerals in place. Purchases and sales of reserves in place for each of the years presented in the table above represent the acquisition and sale of oil and natural gas property interests. See Note 4 for a description of these transactions.

The proved oil and natural gas reserves utilized in the preparation of the financial statements were estimated by Ryder Scott as of December 31, 2013 and Miller and Lents as of December 31, 2012 and 2011. These independent petroleum consultants made their estimations in accordance with guidelines established by the SEC and the Financial Accounting Standards Board, which require that reserve reports be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual agreement.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information was developed utilizing procedures prescribed by ASC 932, Disclosures about Oil and Gas Producing Activities. The information is based on estimates prepared by Sabine’s petroleum engineering staff. The “standardized measure of discounted future net cash flows” should not be viewed as representative of the current value of Sabine’s proved oil and natural gas reserves. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating Sabine or its performance.

In reviewing the information that follows, Sabine believes that the following factors should be taken into account:

• future costs and sales prices will probably differ from those required to be used in these calculations;

• actual production rates for future periods may vary significantly from the rates assumed in the calculations;

• a 10% discount rate may not be reasonable relative to risk inherent in realizing future net oil and natural gas revenues.

Under the standardized measure, future cash inflows were estimated by using the average of the historical unweighted first-day-of-the-month prices of oil and natural gas for the prior twelve month periods ended December 31, 2013, 2012 and 2011. Future cash inflows do not reflect the impact of open hedge positions. Future cash inflows were reduced by estimated future development and production costs based on year end costs in order to arrive at net cash flows before tax. Use of a 10% discount rate and year-end prices and costs are required by ASC 932.

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In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible outcomes.

The standardized measure of discounted future net cash flows from Sabine’s estimated proved oil and natural gas reserves follows:

	For the Year Ended December 31,
	2013			2012			2011
	(in thousands)
Future cash inflows	$	4,667,459		$	4,615,745		$	6,724,283
Less related future:
Production costs		(1,127,359	)		(1,413,634	)		(2,020,736	)
Development costs		(682,876	)		(1,055,357	)		(1,326,857	)
Future net cash inflows		2,857,224			2,146,754			3,376,690
10% annual discount for estimated timing of cash flows		(1,506,352	)		(1,236,961	)		(2,207,421	)
Standardized measure of discounted future net cash flows	$	1,350,872		$	909,793		$	1,169,269

An adjustment for future income tax expense is not included because Sabine is a limited liability company and treated as a partnership for federal and state income tax purposes with all income tax liabilities and/or benefits of Sabine being passed through to the Member.

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows:

	For the Year Ended December 31,
	2013			2012			2011
	(in thousands)
Beginning Balance	$	909,793		$	1,169,269		$	585,674
Revisions of previous estimates
Changes in prices and costs		186,943			(105,480	)(1)		(41,896	)
Changes in quantities		45,167			(561,009	)(1)		40,535
Net change due to extensions, discoveries, and improved recovery		392,752			35,351			168,123
Purchases of reserves		—			467,885	(1)		527,760
Sales of reserves		(152,677	)		(26,436	)(1)		—
Accretion of discount		90,973			116,927			58,567
Sales of oil and gas, net		(274,180	)		(114,520	)(1)		(147,481	)
Change in estimated future development costs		22,181			(5,636	)(1)		(102,647	)
Previously estimated development costs incurred		117,377			29,068			88,980
Changes in rate of production and other, net		12,542			(95,626	)(1)		(8,346	)
Net change		441,078			(259,476	)		583,595
Ending Balance	$	1,350,872		$	909,793		$	1,169,269

(1) Sabine has revised this previously reported unaudited financial information.

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Condensed Consolidated Financial Statements

Sabine Oil & Gas LLC

Condensed Consolidated Balance Sheets (Unaudited)

	September 30, 2014			December 31, 2013
	(in thousands)
Assets
Current assets:
Cash and cash equivalents	$	5,774		$	11,821
Accounts receivable, net		96,245			71,384
Prepaid expenses and other current assets		3,938			2,910
Derivative instruments		12,819			7,806
Total current assets		118,776			93,921
Property, plant and equipment:
Oil and natural gas properties (full cost method)
Proved		3,725,465			3,204,317
Unproved		170,220			208,823
Gas gathering and processing equipment		14,207			19,577
Office furniture and fixtures		13,252			11,167
		3,923,144			3,443,884
Accumulated depletion, depreciation and amortization		(2,201,651	)		(2,063,842	)
Total property, plant and equipment, net		1,721,493			1,380,042
Other assets:
Derivative instruments		1,422			4,332
Deferred financing costs, net		19,531			26,502
Goodwill		173,547			173,547
Other long term assets		100			375
Total other assets		194,600			204,756
Total assets	$	2,034,869		$	1,678,719
Liabilities and member’s capital
Current liabilities:
Accounts payable—trade	$	21,311		$	16,148
Royalties payable		37,636			33,964
Accrued exploration and development		99,170			75,819
Accrued operating expenses and other		35,746			47,602
Accrued interest payable		15,364			23,891
Derivative instruments		5,293			11,625
Other short term liabilities		44			278
Total current liabilities		214,564			209,327
Long term liabilities:
Credit facility		574,000			250,000
Term loan		646,505			645,272
Senior notes		348,511			348,040
Asset retirement obligation		14,872			13,798
Derivative instruments		3,899			11,272
Other short term liabilities		527			—
Total long term liabilities		1,588,314			1,268,382
Commitments and contingencies
Member’s capital:
Member’s capital		1,523,008			1,523,008
Accumulated deficit		(1,291,017	)		(1,321,998	)
Total member’s capital		231,991			201,010
Total liabilities and member’s capital	$	2,034,869		$	1,678,719

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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Condensed Consolidated Financial Statements

Sabine Oil & Gas LLC

Condensed Consolidated Statements of Operations (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)						(in thousands)
				(as restated)						(as restated)
Revenues
Oil, natural gas liquids and natural gas	$	122,125		$	96,007		$	355,401		$	244,886
Other		286			253			1,145			627
Total revenues		122,411			96,260			356,546			245,513
Operating expenses
Lease operating		11,913			11,004			34,662			30,650
Workover		1,656			817			2,361			1,078
Marketing, gathering, transportation and other		6,544			4,286			17,091			12,507
Production and ad valorem taxes		5,138			4,996			15,579			12,564
General and administrative		6,560			5,882			20,584			18,812
Depletion, depreciation and amortization		52,787			36,296			142,995			94,179
Accretion		229			227			668			655
Impairments		—			2			1,659			6
Other operating expenses		4,749			(48	)		7,999			(25	)
Total operating expenses		89,576			63,462			243,598			170,426
Other income (expenses)
Interest expense, net of capitalized interest		(27,726	)		(25,329	)		(80,383	)		(73,625	)
Gain (loss) on derivative instruments		37,430			(944	)		(1,611	)		7,777
Other income		5			21			27			23
Total other income (expenses)		9,709			(26,252	)		(81,967	)		(65,825	)
Net income (loss)	$	42,544		$	6,546		$	30,981		$	9,262

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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Condensed Consolidated Financial Statements

Sabine Oil & Gas LLC

Condensed Consolidated Statement of Member’s Capital (Unaudited)

(in thousands)

	Member’s Capital					Accumulated Deficit			Total Member’s Capital
	Units		Value
Balance as of December 31, 2012—(As Restated)		1,536	$	1,533,008		$	(1,332,575	)	$	200,433
Distributions to member		—		(10,000	)		—			(10,000	)
Net income		—		—			10,577			10,577
Balance as of December 31, 2013		1,536	$	1,523,008		$	(1,321,998	)	$	201,010
Net loss		—		—			30,981			30,981
Balance as of September 30, 2014		1,536	$	1,523,008		$	(1,291,017	)	$	231,991

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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Condensed Consolidated Financial Statements

Sabine Oil & Gas LLC

Condensed Consolidated Statements of Cash Flows (Unaudited)

	For the Nine Months Ended September 30,
	2014			2013
	(in thousands)
				(as restated)
Cash flows from operating activities:
Net income (loss)	$	30,981		$	9,262
Adjustments to reconcile net income (loss )to net cash provided by operating activities:
Depletion, depreciation and amortization		142,995			94,179
Impairments		1,659			6
Gain on sale of asset		(1,375	)		—
Accretion expense		668			655
Accrued interest expense and unamortized debt discount		(5,945	)		1,534
Amortization of deferred rent		(72	)		(239	)
Amortization of deferred financing costs		8,624			6,962
(Gain) loss on derivative instruments		(6,033	)		27,038
Amortization of option premiums		(9,774	)		(859	)
Amortization of prepaid expenses		2,697			3,509
Working capital and other changes:
Increase in accounts receivable		(25,084	)		(36,208	)
Increase in other assets		(3,687	)		(5,177	)
Increase (decrease) in accounts payable, royalties payable and accrued liabilities		(7,405	)		49,109
Net cash provided by operating activities		128,249			149,771
Cash flows from investing activities:
Oil and natural gas property additions		(431,494	)		(236,458	)
Oil and natural gas property acquisitions		(36,772	)		—
Cash received from insurance proceeds		—			604
Gas processing equipment additions		(2,881	)		(3,121	)
Other asset additions		(2,122	)		(1,302	)
Cash received from sale of assets		15,127			2,746
Net cash used in investing activities		(458,142	)		(237,531	)
Cash flows from financing activities:
Borrowings under senior secured revolving credit facility		364,000			150,000
Borrowings under second lien term loan		—			153,500
Debt repayments for the senior secured revolving credit facility		(40,000	)		(190,000	)
Debt issuance costs		(154	)		(5,655	)
Distributions to member		—			(10,000	)
Net cash provided by financing activities		323,846			97,845
Net increase (decrease) in cash and cash equivalents		(6,047	)		10,085
Cash and cash equivalents, beginning of period		11,821			6,193
Cash and cash equivalents, end of period	$	5,774		$	16,278

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

Effective December 19, 2012, NFR Energy LLC was renamed Sabine Oil & Gas LLC (“Sabine” or “the Company”). The Company was established as a Delaware limited liability company in late 2006 to invest in oil and natural gas exploration and production opportunities within the onshore U.S. market. The Company is wholly owned by Sabine Oil & Gas Holdings II LLC, a Delaware limited liability company (“Holdings II”), which is wholly owned by Sabine Oil & Gas Holdings LLC, a Delaware limited liability company (“Holdings” or “Member”), which in turn is wholly owned by Sabine Investor Holdings LLC (“SIH”). Currently, affiliates of First Reserve Corporation (“First Reserve”), own approximately 99.7% of the equity interests of SIH. Certain members of the Company’s management and board of representatives indirectly own interests in the Company through their 0.3% ownership interests in SIH, the controlling member of Holdings.

The Company operates in the exploration and production segment of the energy industry and is pursuing development and exploration projects in a variety of forms including operated and non-operated working interests, joint ventures, farm-outs, and acquisitions, in both conventional and unconventional resources. Sabine is a holding company which conducts its operations through its subsidiaries, which own the operating assets of the Company.

Recent Developments

On July 9, 2014, the Company entered into an amended and restated merger agreement (the “Merger Agreement”) with Forest Oil Corporation (“Forest Oil”), SIH, Holdings, Holdings II, and FR XI Onshore AIV, LLC (“AIV Holdings”) providing for a combination of Forest Oil’s and the Company’s business. The Merger Agreement provides that SIH will contribute all of the equity interests of Holdings, and AIV Holdings will contribute all of the equity interests in two other holding companies, FR NFR Holdings, Inc. and FR NFR, PI, Inc., to Forest Oil, with Holdings becoming a wholly owned subsidiary of Forest Oil. FR NFR Holdings, Inc. and FR NFR PI, Inc. will subsequently merge with and into Forest Oil, with Forest Oil surviving. Holdings, Holdings II and the Company will then subsequently merge with and into Forest Oil, with Forest Oil surviving and the operating subsidiaries of the Company becoming subsidiaries of Forest Oil.

In exchange for the contribution, (i) SIH and AIV Holdings will receive approximately 123,837,490 and 39,874,020 shares of Forest Oil common stock, respectively and (ii) SIH and AIV Holdings will receive 1,258,900 and 405,349 shares of Forest Oil Series A convertible common-equivalent preferred stock (convertible into approximately 166,424,900 shares of Forest common stock), respectively. Upon consummation of the combination transaction, current Forest Oil common shareholders will continue to hold their shares of Forest Oil common stock, which shares will represent (based on the number of Forest Oil common shares outstanding as of May 5, 2014) approximately 42% of the issued and outstanding Forest Oil common shares, approximately a 26.5% economic interest in Forest Oil and 20% of the total voting power in Forest Oil, and SIH and AIV Holdings will collectively hold approximately 58% of the issued and outstanding Forest Oil common shares and 100% of the issued and outstanding Forest Series A convertible common-equivalent preferred shares, collectively representing approximately a 73.5% economic interest in Forest Oil and 80% of the total voting power in Forest Oil. If approved, Forest Oil will be renamed “Sabine Oil & Gas Corporation” concurrently with the closing of the transactions contemplated by the Merger Agreement (the “Transactions”).

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The closing of the Transactions is conditioned on (i) approval by holders of a majority of the Forest Oil common shares present (in person or by proxy) at a special meeting of the Forest Oil common shareholders of the issuance of Forest Oil stock to SIH and AIV Holdings in connection with the Transactions (ii) approval by the affirmative vote of holders of a majority of the outstanding Forest Oil common shares of an amendment to Forest Oil’s certificate of incorporation to increase the number of authorized common shares (the “authorized share proposal”) and (iii) other customary conditions.

If the authorized share proposal is not approved and Forest Oil and SIH mutually agree to waive this condition, then in exchange for the contribution, SIH and AIV Holdings will instead receive shares of Forest Oil Series B convertible common-equivalent preferred stock in lieu of a portion of the Forest Oil common stock that would have been received by them if there were available for issuance a sufficient amount of authorized but unissued common shares. As a result, SIH and AIV Holdings would receive (i) approximately 37,822,023 and 12,178,187 shares of Forest Oil common shares, (ii) approximately 1,258,900 and 405,349 shares of Forest Oil Series A convertible common-equivalent preferred stock and (iii) approximately 860,155 and 276,958 shares of Forest Series Oil B convertible common-equivalent preferred stock, respectively. In that case, upon consummation of the Transactions, and based upon the number of Forest Oil common shares outstanding as of May 5, 2014, current Forest Oil common shareholders would hold approximately 70% of the issued and outstanding Forest Oil common shares, representing approximately a 26.5% economic interest in Forest Oil and 20% of the total voting power in Forest Oil, and SIH and AIV Holdings will collectively hold approximately 30% of the issued and outstanding Forest Oil common shares, 100% of the issued and outstanding Forest Oil Series A convertible common-equivalent preferred shares and 100% of the issued and outstanding Forest Oil Series B convertible common-equivalent preferred shares, collectively representing approximately a 73.5% economic interest in Forest Oil and 80% of the total voting power in Forest Oil.

In connection with entering into the Merger Agreement, SIH and AIV Holdings entered into a related amended and restated stockholder’s agreement and an amended and restated registration rights agreement with Forest Oil, governing certain rights and obligations of SIH and AIV Holdings with respects to the shares of Forest Oil stock they will receive as consideration in connection with the transactions, which will become effective upon the closing of the Transactions.

The foregoing summary of the Merger Agreement and Transactions does not purport to be complete and is subject to, and qualified in its entirety by, the full text of the Merger Agreement, stockholder’s agreement and registration rights agreement, which are filed as Exhibit 2.1, Exhibit 10.1 and Exhibit 10.2, respectively, to Forest Oil’s Form 8-K filed with the SEC on July 10, 2014.

The definitive proxy materials, including notice of Forest Oil shareholders’ meeting to be held on November 20, 2014, were mailed to Forest Oil shareholders on or about October 20, 2014.

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2. Significant Accounting Policies

Basis of Presentation

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

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of only normal recurring adjustments necessary for a fair statement of the financial statements have been included. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. In addition, as these are interim financial statements, they do not include all disclosures required for financial statements prepared in conformity with GAAP. These financial statements and notes should be read in conjunction with Sabine’s audited consolidated financial statements and the notes thereto included in the Company’s Annual Report for the year ended December 31, 2013.

Restatement of Previously Issued Financial Statements

The Company is restating its financial statements for the three and nine months ended September 30, 2013 with respect to the accounting and disclosures for certain derivative financial transactions under Accounting Standards Codification Topic 815, Derivatives and Hedging (“ASC 815”). The Company determined that the formal documentation it had prepared to support its initial hedge designations for effectiveness in connection with the Company’s oil and natural gas hedging program was not compliant with the technical documentation requirements to qualify for cash flow hedge accounting treatment in accordance with ASC 815, and as a result, the Company was not permitted to utilize hedge accounting treatment in the preparation of its financial statements. The restatements eliminate hedge accounting treatment which had been applied in 2013.

Under ASC 815, the fair value of hedge contracts is recognized in the balance sheets as an asset or liability, as the case may be, and the amounts received or paid under the hedge contracts are reflected in earnings during the period in which the underlying production occurs. If the hedge contracts qualify for cash flow hedge accounting treatment, the fair value of the hedge contract that is effective in offsetting changes in expected cash flows (the effective portion) is recorded in “Accumulated other comprehensive income”, and the effective portion of the changes in the fair value do not affect net income in the period. The portion of the change in fair value of the qualified derivative instrument that was not effective in offsetting changes in expected cash flows (the ineffective portion), as well as any amount excluded from the assessment of the effectiveness of the derivative instruments, are recognized in earnings. If the hedge contract does not qualify for hedge accounting treatment, the change in the fair value of the hedge contract is reflected in earnings during the period as a “Gain (loss) on derivative instruments”. Under the cash flow hedge accounting treatment used by the Company, the effective portion of the fair value of the hedge contracts was recognized in the balance sheets with the offsetting gain or loss recorded initially in “Accumulated other comprehensive income” and later reclassified through earnings when the hedged production impacted earnings. The

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ineffective portion of the designated derivative instruments was recognized in “Gain (loss) on derivative instruments” within Other income (expenses) on the statements of operations. As a result of the determination that the designation documentation failed to meet the requirements necessary to utilize cash flow hedge accounting treatment, any gain or loss resulting from changes in fair value should have been recorded in the statements of operations as a component of earnings.

The Company previously recognized gains and losses resulting from the settlement of its designated derivative financial instruments as a component of revenues, and has reclassified gains of $20.2 million in the nine months ended September 30, 2013 to “Loss on derivative instruments” within Other income (expenses) as a result of eliminating hedge accounting. No gains were reclassified to “Loss on derivative instruments” within Other income (expenses) in the three months ended September 30, 2013. In addition, the Company reclassified $6.9 million and $40.2 million of losses in the three and nine months ended September 30, 2013 from “Accumulated other comprehensive income” to “Loss on derivative instruments” within Other income (expenses). Because the derivatives did not qualify for hedge accounting, the inclusion of hedge value for designated contracts in the full cost ceiling calculation at all balance sheet dates when the ceiling test was performed was not appropriate. Thus, Sabine’s full cost ceiling calculations were revised and resulted in restatements to increase impairment expense recognized in earlier periods and reductions to the Company’s ceiling test impairment expense of $12.7 million in the nine months ended September 30, 2013, as well as requiring restatements to decrease depletion expense by $1.2 million and $3.5 million in the three and nine months ended September 30, 2013. No reductions to the Company’s ceiling test impairment expense were recorded in the three months ended September 30, 2013.

In December 2012, Ramshorn, a subsidiary of Nabors, sold its entire membership interest in Sabine to affiliates of First Reserve, excluding a deferred payment of $10 million due on or before June 30, 2013. The deferred payment was deemed a senior equity right in the Company until paid in full and guaranteed by First Reserve. The deferred payment was settled by Sabine in June 2013. The Company previously recognized the $10 million within Other income (expenses) on the Condensed Consolidated Statements of Operations for the nine months ended September 30, 2013, and has reclassified this payment to Member’s capital on the Condensed Consolidated Balance Sheets as of September 30, 2013 for treatment as an equity distribution.

Certain other reclassifications have been made to prior periods in order to conform to current period presentation.

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The following table represents the impact of this restatement on relevant financial statement line items in Sabine’s Condensed Consolidated Statements of Operations:

	Three months ended September 30, 2013									Nine months ended September 30, 2013
	As Reported			Adjustments			As Restated			As Reported			Adjustments			As Restated
	(in thousands)									(in thousands)
Revenues
Gain (loss) on derivative instruments	$	—		$	—		$	—		$	20,209		$	(20,209	)	$	—
Total revenues		96,260			—			96,260			265,722			(20,209	)		245,513
Operating expenses
Lease operating		11,017			(13	)		11,004			30,724			(74	)		30,650
Depletion, depreciation and amortization		37,518			(1,222	)		36,296			97,695			(3,516	)		94,179
Impairments		2			—			2			12,725			(12,719	)		6
Other operating expenses		—			(48	)		(48	)		—			(25	)		(25	)
Total operating expenses		64,745			(1,283	)		63,462			186,760			(16,334	)		170,426
Other income (expenses)
Gain (loss) on derivative instruments		5,932			(6,876	)		(944	)		27,744			(19,967	)		7,777
Other income (expense)		82			(61	)		21			(9,878	)		9,901			23
Total other expenses		(19,315	)		(6,937	)		(26,252	)		(55,759	)		(10,066	)		(65,825	)
Net income (loss)	$	12,200		$	(5,654	)	$	6,546		$	23,203		$	(13,941	)	$	9,262

The following table represents the impact of this restatement on relevant financial statement line items in Sabine’s Condensed Consolidated Statements of Cash Flows:

	Nine months ended September 30, 2013
	As Reported			Adjustments			As Related
	(in thousands)
Cash flows from operating activities:
Net income (loss), including noncontrolling interest	$	23,203		$	(13,941	)	$	9,262
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		97,695			(3,516	)		94,179
Impairments		12,725			(12,719	)		6
(Gain) loss on derivative instruments		(13,138	)		40,176			27,038
Net cash provided by operating activities	$	139,771		$	10,000		$	149,771
Cash flows from financing activities:
Distributions to member		—			(10,000	)		(10,000	)
Net cash provided by (used in) financing activities	$	107,845		$	(10,000	)	$	97,845

Cash and Cash Equivalents

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

Concentration of Credit Risk

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

Derivative instruments subject the Company to a concentration of credit risk (see Note 8).

Inventory

Inventory, which is included in “Prepaid expenses and other current assets” on Sabine’s Condensed Consolidated Balance Sheets, consists principally of tubular goods, spare parts, and equipment used in the Company’s drilling operations. The inventory balance, net of impairments, was $0.8 million and $0.7 million as of September 30, 2014 and December 31, 2013, respectively. Inventory is stated at the lower of weighted average cost or market. The Company had no material impairments relating to obsolete inventory during the three and nine months ended September 30, 2014 and 2013.

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Oil and Natural Gas Properties and Equipment

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method, the Company capitalizes all acquisition, exploration and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits and other internal costs directly attributable to these activities. The Company capitalized $2.1 million and $2.7 million of internal costs for the three months ended September 30, 2014 and 2013, respectively, and $7.5 million and $4.7 million of internal costs for the nine months ended September 30, 2014 and 2013, respectively. Costs associated with production and general corporate activities are expensed in the period incurred. The Company also includes the present value of its dismantlement, restoration and abandonment costs within the capitalized oil and natural gas property balance (see “Asset Retirement Obligation” below). Unless a significant portion of the Company’s proved reserve quantities is sold (greater than 25%), proceeds from the sale of oil and natural gas properties are accounted for as a reduction to capitalized costs, and gains and losses are not recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

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

Under the full cost method of accounting, a ceiling test is performed on a quarterly basis. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of “Accumulated depletion, depreciation and amortization” (“Accumulated DD&A”) on the Company’s Condensed Consolidated Balance Sheets, may not exceed the estimated future net cash flows from proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the Company’s Condensed Consolidated Balance Sheets, using the unweighted average first day of the month prices for the prior twelve month period ended September 30, 2014 and December 31, 2013 (adjusted for quality and basis differentials) held flat for the life of production, discounted at 10%, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as accumulated DD&A.

For the three and nine months ended September 30, 2014 and 2013, the Company did not recognize an impairment for the carrying value of proved oil and natural gas properties in excess of the ceiling limitation. The average of the unweighted first day of the month prices for the prior twelve month periods ended September 30, 2014 and 2013 was $4.24 and $3.60 per Mcf for natural gas. Additionally, the average of the unweighted first day of the month prices for the prior twelve month periods ended September 30, 2014 and 2013 was $99.08 and $95.04 per Bbl for oil. As of September 30, 2014, the ceiling limitation exceeded the carrying value of proved oil and natural gas properties by approximately $69.9 million.

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The Company’s depletion expense on oil and natural gas properties is calculated each quarter utilizing period end reserve quantities. The Company recorded $52.1 million and $35.6 million of depletion on oil and natural gas properties for the three months ended September 30, 2014 and 2013, respectively, and $141.0 million and $91.8 million for the nine months ended September 30, 2014 and 2013, respectively. As a rate of production, depletion was $2.68 per Mcfe and $2.10 per Mcfe for the three months ended September 30, 2014 and 2013, respectively, and $2.57 per Mcfe and $2.07 per Mcfe for the nine months ended September 30, 2014 and 2013, respectively.

Gathering assets and related facilities, certain other property and equipment, and furniture and fixtures are depreciated using the straight-line method based on the estimated useful lives of the respective assets, generally ranging from 3 to 30 years. These assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is then recognized if the carrying amount is not recoverable and exceeds fair value. In the second quarter of 2014, the Company recorded impairment charges for gas gathering and processing equipment of $1.7 million based on expected present value and estimated future cash flows using current volume throughput and pricing assumptions. No impairment charge for gas gathering and processing equipment was recorded in the three months ended September 30, 2014. Additionally, no impairment charge for gas gathering and processing equipment was recorded in the three and nine months ended September 30, 2013. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. Repairs and maintenance costs are expensed in the period incurred.

No insurance proceeds were received during the three and nine months ended September 30, 2014. During the nine months ended September 30, 2013, the Company received insurance proceeds of $0.6 million, which was netted with the replacement costs recognized in oil and natural gas properties. No insurance proceeds were received during the three months ended September 30, 2013.

Capitalized Interest

The Company capitalizes interest costs to oil and natural gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. The Company capitalized $1.5 million and $3.2 million of interest for the three months ended September 30, 2014 and 2013, respectively, and $5.0 million and $10.1 million for the nine months ended September 30, 2014 and 2013, respectively.

Leases

The Company accounts for leases with escalation clauses and rent holidays on a straight-line basis. The deferred rent expense liability associated with future lease commitments, if applicable, is reported under the caption “Other short term liabilities” on the Company’s Condensed Consolidated Balance Sheets.

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Derivative Instruments and Hedging Activities

The Company uses derivative financial instruments to achieve a more predictable cash flow from its oil and natural gas production by reducing its exposure to price fluctuations. Such derivative instruments, which are placed with major financial institutions who are participants in the Company’s Credit Facility (see Note 5) that the Company believes are minimal credit risks, may take the form of forward contracts, futures contracts, swaps, options, or basis swaps.

At September 30, 2014, substantially all of Sabine’s oil and natural gas derivative contracts are settled based upon reported New York Mercantile Exchange (NYMEX) prices. Sabine’s derivative contracts are with multiple counterparties to minimize the Company’s exposure to any individual counterparty, and Sabine has netting arrangements with all of the Company’s counterparties that provide for offsetting payables against receivables from separate hedging arrangements with that counterparty. The oil and natural gas reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a generally high degree of historical correlation with actual prices received by the Company for its oil and natural gas production. Sabine’s fixed-price swap and option agreements are used to fix the sales price for the Company’s anticipated future oil and natural gas production. Upon settlement, the Company receives a fixed price for the hedged commodity and receives or pays the counterparty a floating market price, as defined in each instrument. The instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, the Company pays the counterparty. When the fixed price exceeds the floating price, the counterparty is required to make a payment to the Company.

Sabine’s derivatives instruments at September 30, 2014 included oil and natural gas options in addition to fixed price swaps. The Company has bought and sold natural gas puts, bought and sold oil and natural gas calls and sold oil puts. For the oil and natural gas calls, the buyer has the option to purchase a set volume of the contracted commodity at a contracted price on a contracted date in the future. For the oil and natural gas puts, the buyer has the option to sell a contracted volume of the commodity at a contracted price on a contracted date in the future.

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

Deferred Financing Costs

Deferred financing costs of approximately $0.4 million were incurred during the three months ended September 30, 2014. The Company had no material deferred financing costs during the three months ended September 30, 2013. Deferred financing costs of approximately $1.5 million and $4.9 million were incurred during the nine months ended September 30, 2014 and 2013, respectively. Costs in 2014 and 2013 are associated with the Company’s second lien term loan agreement (“Term Loan”) and senior secured revolving credit facility (“Credit Facility”) (see Note 5). Deferred financing costs associated with the Term Loan, Credit Facility and 9.75% senior unsecured notes due 2017 (the “2017 Notes”) are being amortized over the life of the respective obligations with $2.2 million included in interest expense for each of the three months ended September 30, 2014 and 2013, and $6.7 million for each of the nine months ended September 30, 2014 and 2013. The Company also expensed $0.3 million in January 2013 as a result of reductions in the borrowing base of the Credit Facility.

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Financial Instruments

The Company’s financial instruments including cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The Company’s Credit Facility and Term Loan are reported at carrying value which approximates fair value based on current rates applicable to similar instruments. Since considerable judgment is required to develop estimates of fair value, the estimates provided are not necessarily indicative of the amounts the Company could realize upon the purchase or refinancing of such instruments. The Company’s derivative instruments are reported at fair value based on Level 2 fair value methodologies and the 2017 Notes are reported at carrying value but further compared to fair value based on Level 2 fair value methodologies (see Note 9).

Goodwill

Goodwill is tested for impairment on an annual basis as of October 1 of each year.

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

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

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

Goodwill totaled $173.5 million at September 30, 2014 and December 31, 2013. No impairment of goodwill was recognized during the nine months ended September 30, 2014 and 2013.

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Asset Retirement Obligation

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

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

	For the nine months ended September 30, 2014
	(in thousands)
Beginning balance	$	13,798
Liabilities incurred		559
Liabilities settled		(110	)
Revisions		(43	)
Accretion expense		668
Ending balance	$	14,872

Revenue Recognition

The Company records revenues from the sales of oil, natural gas liquids and natural gas when produced, sold and collectability is ensured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales from its properties. Accordingly, oil, natural gas liquids and natural gas sales are not recognized for deliveries in excess of the Company’s net revenue interest, while oil, natural gas liquids and natural gas sales are recognized for any under delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. The Company had no material overproduction or underproduction at September 30, 2014 or December 31, 2013.

Use of Estimates

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

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

Income Taxes

The Company is a limited liability company treated as a partnership for federal and state income tax purposes with all income tax liabilities and/or benefits of the Company being passed through to the Member. As such, no recognition of federal or state income taxes for the Company or its subsidiaries that are organized as limited liability companies have been provided for in the accompanying condensed consolidated financial statements.

In accordance with the operating agreement of the Company, to the extent possible without impairing the Company’s ability to continue to conduct its business and activities, and in order to permit its Member to pay taxes on the taxable income of the Company, the Company would be required to make distributions to the Member in the amount equal to the estimated tax liability of such Member computed as if the Member paid income tax at the highest marginal federal and state rate applicable to an individual resident of New York, New York, in the event that taxable income is generated for the Member. There was no taxable income and therefore no distributions to the Member in 2014 or 2013.

Recent Accounting Pronouncements

In August 2014, the FASB issued Accounting Standards Update 2014-15, “Presentation of Financial Statements – Going Concern (Subtopic 205-40)” (ASU 2014-15). The amendments within this update provide guidance about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern with the intent to reduce diversity in the timing and content of footnote disclosures. Specifically, the amendments (1) provide a definition of the term substantial doubt, (2) require an evaluation every reporting period including interim periods, (3) provide principles for considering the mitigating effect of management’s plans, (4) require certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, (5) require an express statement and other disclosures when substantial doubt is not alleviated, and (6) require an assessment for a period of one year after the date that the financial statements are issued (or available to be issued). This ASU is effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Sabine is analyzing the requirements of ASU 2014-15 to determine what impact the new standard will have on its consolidated financial statements and related disclosures.

In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenues from Contracts with Customers” (ASU 2014-09). This update creates Accounting Standards Codification Topic 606, Revenue from Contracts with Customers (“ASC 606”) to supersede the revenue recognition requirements in Accounting Standards Codification Topic 605, Revenue Recognition (“ASC 605”) by requiring an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective for annual reporting periods beginning after December 15, 2016, and interim periods within those annual periods. Sabine is analyzing the requirements of ASU 2014-9 to determine what impact the new standard will have on its consolidated financial statements and related disclosures.

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3. Significant Customers

During the nine months ended September 30, 2014, purchases by three companies exceeded 10% of the total oil, natural gas liquids and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP, Eastex Crude Company and Laclede Energy accounted for approximately 13%, 12% and 12% of oil, natural gas liquids and natural gas sales, respectively. During the nine months ended September 30, 2013, purchases by four companies exceeded 10% of the total oil, natural gas liquids and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP, Eastex Crude Company, Unimark LLC and CP Energy LLC accounted for approximately 17%, 16%, 12% and 11% of oil, natural gas liquids and natural gas sales, respectively.

4. Property Acquisitions and Divestitures

On June 10, 2014 and March 25, 2014, the Company acquired working interests in certain oil and natural gas properties in North Texas for a total of $38.0 million, net of purchase price adjustments. The Company recorded a fair value of $33.4 million for proved properties and $4.6 million for unproved properties. No material ARO liability was assumed. The valuations to derive the purchase price included both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, risk adjusted discount rates and fair value of unevaluated leaseholds.

Total pro forma impact of the June 10, 2014 and March 25, 2014 acquisitions was an increase to “Total revenues” on the Condensed Consolidated Statement of Operations of $4.0 million for the nine months ended September 30, 2014, and a decrease to “Net income” on the Condensed Consolidated Statement of Operations of $2.4 million for the nine months ended September 30, 2014.

On December 18, 2013, the Company closed on the sale of Sabine’s interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area for $169.0 million, net of certain purchase price adjustments. The sale of the Texas Panhandle and surrounding Oklahoma properties was accounted for as an adjustment to the full cost pool with no gain or loss recognized. Subsequent to December 31, 2013, the Company has recorded purchase price adjustments of approximately $8.4 million as a result of clearing title defects and adjusting post effective date estimates.

On April 30, 2013, the Company closed on the purchase of interests in approximately 5,000 net acres in South Texas for approximately $14.9 million. The acquisition does not qualify as a business combination under Accounting Standards Codification Topic 805, Business Combinations (“ASC 805”).

Acquired properties that are considered to be business combinations are recorded at their fair value. In determining the fair value of the properties, the Company prepares estimates of oil and natural gas reserves as well as an estimate of fair value of unevaluated leaseholds. The

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Company uses estimated future prices to apply to the estimated reserve quantities acquired and the estimated future operating and development costs to arrive at the estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. To compensate for inherent risks of estimating and valuing reserves, proved undeveloped, probable and possible reserves are reduced by additional risk-weighting factors.

5. Long Term Debt

Senior Notes

On February 12, 2010, the Company and its subsidiary Sabine Oil & Gas Finance Corporation, formerly NFR Energy Finance Corporation, co-issued $200 million in 9.75% 2017 Notes in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act of 1933 and to persons outside the United States in compliance with Regulation S of the Securities Act of 1933. The 2017 Notes bear interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15 each year commencing August 15, 2010. The 2017 Notes were issued at 98.73% of par. In conjunction with the issuance of the 2017 Notes, the Company recorded a discount of $2.5 million to be amortized over the remaining life of the 2017 Notes utilizing the simple interest method. The remaining unamortized discount was $0.9 million and $1.1 million at September 30, 2014 and December 31, 2013, respectively. On April 14, 2010, the Company and Sabine Oil & Gas Finance Corporation issued an additional $150 million in senior notes at 9.75% due 2017. The additional notes were issued at 98.75% of par and bear interest at a rate of 9.75% per annum, payable semi-annually on February 15 and August 15 of each year commencing August 15, 2010. The additional notes were issued under the same indenture as the 2017 Notes issued on February 12, 2010. The Company recorded a discount of $1.9 million to be amortized over the remaining life of the 2017 Notes utilizing the simple interest method. The remaining unamortized discount was $0.6 million and $0.8 million at September 30, 2014 and December 31, 2013, respectively. The 2017 Notes were issued under and are governed by an indenture dated February 12, 2010 between the Company, Sabine Oil & Gas Finance Corporation, the Bank of New York Mellon Trust Company, N.A. as trustee, and the Company’s subsidiaries named therein as guarantors.

All of the restricted subsidiaries that guarantee the Company’s senior secured revolving Credit Facility (other than Sabine Oil & Gas Finance Corporation) have guaranteed the 2017 Notes on a senior unsecured basis.

The Company may redeem the 2017 Notes, in whole or in part, at any time, at a redemption price (expressed as a percentage of principal amount) set forth in the following table plus accrued and unpaid interest, if any, to the applicable redemption date, if redeemed during the twelve-month period beginning on February 15 of the years indicated below:

Year	Percentage
2014		104.875
2015		102.438
2016		100.000

The indenture governing the 2017 Notes contains covenants that, among other things, limit the Company’s ability and the ability of the Company’s 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

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at least 2.0 to 1.0 (subject to exceptions for borrowings within certain limits under the Credit Facility); pay dividends or repurchase or redeem equity interests; limit dividends or other payments by restricted subsidiaries that are not guarantors to the Company or the Company’s other subsidiaries; make certain investments; incur liens; enter into certain types of transactions with Sabine’s affiliates; and sell assets or consolidate or merge with or into other companies. However, if the 2017 Notes have an investment grade rating from Standard & Poor’s Ratings Group, Inc. and Moody’s Investors Service, Inc., and no default or event of default exists under the indenture, Sabine will not be subject to certain of the foregoing covenants.

Senior Secured Revolving Credit Facility

On November 30, 2007, the Company entered into a senior secured revolving credit facility with a syndicate of banks. Through a series of redeterminations, the Company has amended and restated the Credit Facility. The most recent redetermination effective November 12, 2014, increased the borrowing base from $700 million to $750 million. The next scheduled redetermination will be in April 2015.

As of September 30, 2014, commitments under the Credit Facility were $750 million, the borrowing base was $700 million, the outstanding balance amount totaled $574 million and the Company was able to incur approximately $126 million of additional secured indebtedness under the Credit Facility. The Credit Facility’s maturity date is April 7, 2016.

Subsequent to the period ended September 30, 2014, through November 12, 2014, the Company has borrowed $35 million. As of November 12, 2014 after giving effect to the recent redetermination and the borrowings, the borrowing base under the Credit Facility was $750 million, the outstanding amount totaled $609 million and the Company had approximately $141 million of secured indebtedness available under the Credit Facility.

Borrowings made under the Credit Facility are guaranteed by first priority perfected liens and security interests on substantially all assets of Sabine and its wholly-owned domestic subsidiaries.

Interest on borrowings under the Credit Facility accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (ABR). The Eurodollar rate is calculated as London Interbank Offered Rate (LIBOR) plus an applicable margin that varies from 1.75% (for periods in which Sabine has utilized less than 30% of the borrowing base) to 2.75% (for periods in which Sabine has utilized equal to or greater than 90% of the borrowing base). The ABR is calculated as the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c) Eurodollar rate on such day (or if such day is not a business day, the immediately preceding business day) plus 1.5%. The Company elects the basis of the interest rate at the time of each borrowing. In addition, Sabine pays a commitment fee of 0.50% under the Credit Facility (quarterly in arrears) for the amount that the aggregate commitments exceed borrowings under the Credit Facility. Effective April 2, 2014, the applicable margin for the Eurodollar rate was amended and reduced to 1.50% (for periods in which Sabine has utilized less than 30% of the borrowing base) and 2.50% (for periods in which Sabine has utilized equal to or greater than 90% of the borrowing base).

Under the Credit Facility, the Company may request letters of credit, provided that the borrowing base is not exceeded or will not be exceeded as a result of issuance of the letter of credit. There were no outstanding letters of credit on September 30, 2014 or December 31, 2013.

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The Credit Facility requires the Company to comply with certain financial covenants to maintain (a) a current ratio, defined as a ratio of consolidated current assets (including the unused amount of the total commitments under the Credit Facility, but excluding noncash assets under ASC 815, Derivatives and Hedging), to consolidated current liabilities (excluding noncash obligations under ASC 815 and the current maturities under the Credit Facility, determined at the end of each quarter), of not less than 1.0 to 1.0; (b) an interest coverage ratio at the end of each quarter defined as a ratio of EBITDA (as such terms are defined in the Credit Facility) for the period of four fiscal quarters then ending to interest expense for such period of not less than 2.5 to 1.0.

In addition, the Credit Facility contains covenants that restrict, among other things, the Company’s ability to incur other indebtedness, create liens, or sell its assets; merge with other entities; pay dividends; enter into hedging agreements; and make certain investments.

At September 30, 2014 and December 31, 2013, Sabine was in compliance with its financial debt covenants under the Credit Facility.

Term Loan Agreement

The Company entered into a $500 million term loan agreement on December 14, 2012 with a maturity date of April 7, 2018. On January 23, 2013, the syndication was completed with an additional funding of $150 million bringing the outstanding balance to $650 million as of September 30, 2014. Proceeds from the Term Loan were used to acquire oil and gas properties in December 2012 and repay borrowings under the Credit Facility in the first quarter of 2013.

Borrowings made under the Term Loan are subordinate to the liens and security interests securing the Credit Facility.

Interest on borrowings under the Term Loan accrues at variable interest rates at either a Eurodollar rate or an alternate base rate (ABR). Effective with the close of the syndicate in January 2013, the Eurodollar rate is calculated as London Interbank Offered Rate (LIBOR) with a floor of 1.25%, plus an applicable margin of 7.50%. The Company elects the basis of the interest rate at the time of each borrowing. The weighted average interest rate incurred on this indebtedness for the three and nine months ended September 30, 2014 was 8.75%. The weighted average interest rate incurred on this indebtedness for the three and nine months ended September 30, 2013 was 8.75% and 8.83%, respectively.

6. Member’s Capital

Common Units

The Company is authorized to issue one class of units to be designated as “Common Units”. The units are not represented by certificates. All Common Units are issued at a price equal to $1,000 per unit.

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Incentive Units

In addition to common units, Holdings established an incentive plan which provides for incentive units which have been issued to certain of the Company’s directors, officers and employees. The incentive units have no voting rights and participate only upon liquidation events meeting certain requisite financial thresholds. No compensation expense related to the incentive units has been recognized by the Company as the occurrence of a liquidation event is not considered probable, and thus the value of the incentive, if any, cannot be determined.

7. Statement of Cash Flows

During the nine months ended September 30, 2014, the Company’s noncash investing and financing activities consisted primarily of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $0.6 million.

• Accrued and payable capital expenditures as of September 30, 2014 were $116.8 million.

• Accrued debt issuance costs as of September 30, 2014 were $1.4 million.

During the nine months ended September 30, 2013, the Company’s noncash investing and financing activities consisted primarily of the following transactions:

• Recognition of an asset retirement obligation for the plugging and abandonment costs related to the Company’s oil and natural gas properties valued at $0.5 million.

• Accrued and payable capital expenditures as of September 30, 2013 were $80.0 million.

8. Derivative Financial Instruments

The Company is exposed to risks associated with unfavorable changes in the market price of oil and natural gas as a result of the forecasted sale of its production and uses derivative instruments to hedge or reduce its exposure to certain of these risks. For these derivative instruments, the Company did not elect hedge accounting for accounting purposes and, accordingly, recorded the net change in the mark-to-market valuation of these derivative instruments in the Condensed Consolidated Statements of Operations.

All of Sabine’s derivative instruments serve as economic hedges and are recorded at fair value with gains and losses recognized immediately in earnings. These marked-to-market adjustments will produce a degree of earnings volatility that can be significant from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The impact to cash flow occurs upon settlement of the underlying contract.

Throughout the nine months ended September 30, 2014, the Company has executed derivative contracts as market conditions allowed in order to economically hedge anticipated future cash flows from oil and natural gas producing activities. These include both oil and natural gas fixed-price swap agreements covering certain portions of anticipated 2014 and 2015 production volumes. Additionally, the Company executed option contracts including purchased and written oil and natural gas call agreements, as well as purchased and written oil and natural gas put agreements, covering certain portions of anticipated 2014 and 2015 oil and natural gas production. No material premiums were recognized as a result of these option agreements. None of the fixed-price swap or option contracts were designated for hedge accounting, with all mark to market changes in fair value recognized currently in earnings. See the table below for specific volume, timing, and pricing details regarding Sabine’s outstanding trade positions.

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Additionally, prior to the nine months ended September 30, 2014, the Company purchased natural gas puts, wrote oil and natural gas calls, and wrote oil and natural gas puts for periods from 2014 through 2016, for which a net premium was recognized. In March 2014, the Company restructured certain sold call contracts for which the Company had previously recognized a premium liability related to 2015 volumes. As a result of this restructuring, the Company released $4.4 million of premium liability into earnings, recognized in “Gain (loss) on derivative instruments” on the Condensed Consolidated Statement of Operations for the nine months ended September 30, 2014. The net unamortized premium included in short term and long term derivative liabilities is $5.3 million and $1.2 million, respectively, at September 30, 2014. See the table below for specific volume, timing, and pricing details regarding Sabine’s derivative positions.

The following swaps and options were outstanding with associated notional volumes and contracted swap, floor, and ceiling prices that represent hedge weighted average prices for the index specified as of September 30, 2014:

Natural Gas
				Weighted Average Prices
Settlement Period	Derivative Instrument	Notional Amount		Swap		Sub Floor		Floor		Ceiling
		(Mmbtu)		($/Mmbtu)
2014	Swap		5,336,000	$	4.04	$	—	$	—	$	—
2014	Swap with sub floor		1,564,000	$	3.99	$	3.25	$	—	$	—
2014	Three-way collar		5,520,000	$	—	$	3.25	$	4.50	$	4.50
2015	Swap		20,075,000	$	4.11	$	—	$	—	$	—
2015	Swap with sub floor		21,900,000	$	4.25	$	3.70	$	—	$	—
2016	Sold Call		21,960,000	$	—	$	—	$	—	$	5.00
Oil
				Weighted Average Prices
Settlement Period	Derivative Instrument	Notional Amount		Swap		Sub Floor		Floor		Ceiling
		(Bbl)		($/Bbl)
2014	Swap		521,180	$	92.46	$	—	$	—	$	—
2014	Swap with sub floor		30,820	$	89.13	$	70.00	$	—	$	—
2015	Swap		1,841,350	$	90.18	$	—	$	—	$	—
2015	Swap with sub floor		339,450	$	89.50	$	73.47	$	—	$	—

Effective November 6, 2014, the Company executed additional natural gas swap agreements on 930,000 Mmbtu of anticipated 2014 production, swap agreements on 15,695,000 Mmbtu of anticipated 2015 production and written put agreements on 15,695,000 Mmbtu of anticipated 2015 production.

The Company recorded a short term and a long term derivative asset of $12.8 million and $1.4 million, respectively, and a short term and a long term derivative liability of $5.3 million and $3.9 million, respectively, related to the fair value of the derivative instrument’s prices on related volumes as of September 30, 2014.

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2014		2013			2014			2013
	(in thousands)					(in thousands)
Gain (loss) on derivative instruments	$	37,430	$	(944	)	$	(1,611	)	$	7,777

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For the three months ended September 30, 2014 and 2013 Sabine paid $2.5 million and received $11.3 million, respectively, on settlements of derivatives. Sabine paid $17.4 million and received $34.0 million on settlements of derivatives in the nine months ended September 30, 2014 and 2013, respectively.

Sabine’s derivative contracts are executed with counterparties under certain master netting agreements that allow the Company to offset assets due from, and liabilities due to, the counterparties. The table below presents the carrying value of Sabine’s derivative assets and liabilities both before and after the impact of such netting agreements on the Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013:

	Derivative Assets
		September 30, 2014			December 31, 2013
		(in thousands)
		Fair Value
Current assets	Derivative Instruments	$	19,180		$	15,859
Current liabilities(1)	Derivative Instruments		—			2,826
Total current asset fair value			19,180			18,685
Other assets	Derivative Instruments		2,317			6,488
Long term liabilities(1)	Derivative Instruments		2,028			223
Total long term asset fair value			4,345			6,711
Less: Counterparty set-off			(9,285	)		(13,258	)
Total derivative asset net fair value		$	14,240		$	12,138

	Derivative Liabilities
		September 30, 2014			December 31, 2013
		(in thousands)
		Fair Value
Current liabilities	Derivative Instruments	$	(5,293	)	$	(14,451	)
Current assets(1)	Derivative Instruments		(6,361	)		(8,052	)
Total current liability fair value			(11,654	)		(22,503	)
Long term liabilities	Derivative Instruments		(5,928	)		(11,496	)
Other assets(1)	Derivative Instruments		(895	)		(2,156	)
Total long term liability fair value			(6,823	)		(13,652	)
Less: Counterparty set-off			9,285			13,258
Total derivative liability net fair value		$	(9,192	)	$	(22,897	)

(1) Impact of counterparty right of set-off for derivative instruments subject to certain master netting agreements.

At September 30, 2014, and December 31, 2013, none of the Company’s outstanding derivatives contained credit-risk related contingent features that would result in a material adverse impact to Sabine upon any change in the Company’s credit ratings.

9. Fair Value Measurements

As discussed in Note 8, the Company utilizes derivative instruments to hedge against the variability in cash flows associated with the forecasted sale of its anticipated future oil and natural gas production. The Company generally hedges a substantial, but varying, portion of anticipated natural gas production for the next 12 to 60 months. These derivatives are carried at fair value on the Condensed Consolidated Balance Sheets.

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs.

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The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

The three levels of the fair value hierarchy are as follows:

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, basis swaps, options, and collars.

Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The following table sets forth, by level, within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value as of September 30, 2014 and December 31, 2013. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Recurring Fair Value Measurements
	(in millions)
	Level 1		Level 2			Level 3		Total
As of September 30, 2014
Derivative Assets	$	—	$	14.2		$	—	$	14.2
Derivative Liabilities		—		(9.2	)		—		(9.2	)
Total	$	—	$	5.0		$	—	$	5.0

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	Level 1		Level 2			Level 3		Total
As of December 31, 2013
Derivative Assets	$	—	$	12.1		$	—	$	12.1
Derivative Liabilities		—		(22.9	)		—		(22.9	)
Total	$	—	$	(10.8	)	$	—	$	(10.8	)

The Company’s financial assets and liabilities consist solely of the derivative assets and liabilities also disclosed in table in Note 8. Derivatives listed above include commodity swaps, basis swaps, put and call options that are carried at fair value. The fair value amounts on the Condensed Consolidated Balance Sheets associated with the Company’s derivatives resulted from Level 2 fair value methodologies, that is, the Company is able to value the assets and liabilities based on observable market data for similar instruments. The amounts above include the impact of netting assets and liabilities with counterparties with which the right of offset exists.

The observable data includes the forward curve for commodity prices and interest rates based on quoted markets prices and prospective volatility factors related to changes in commodity prices, as well as the impact of the Company’s non-performance risk of the counterparties which is derived using credit default swap values.

The Company measures fair value of its long term debt based on a Level 2 methodology using quoted market prices with consideration given to the effect of the Company’s credit risk. The carrying value of the Company’s Credit Facility and Term Loan approximate fair value based on current rates applicable to similar instruments. The following table outlines the fair value of the 2017 Notes as of September 30, 2014 and December 31, 2013:

	September 30, 2014		December 31, 2013
	(in thousands)
2017 Senior Notes
Carrying Value	$	348,511	$	348,040
Fair Value	$	329,074	$	327,698

Sabine utilizes fair value on a non-recurring basis to perform impairment tests as required on the Company’s inventory, property, plant and equipment, goodwill and intangible assets. No impairment charge for gas gathering and processing equipment was recorded in the three months ended September 30, 2014. In the nine months ended September 30, 2014, the Company recorded impairment charges for gas gathering and processing equipment of $1.7 million based on expected present value and estimated future cash flows using current volume throughput and pricing assumptions. No impairment charge for gas gathering and processing equipment was recorded in the three and nine months ended September 30, 2013. Additionally, no impairment charges related to the write-down of carrying value of certain sizes of casing inventory was recorded in each of the three and nine months ended September 30, 2014 and 2013. Assets and liabilities acquired in business combinations are recorded at their fair value as of the date of acquisition (Note 4). The inputs used to determine such fair value are primarily based upon internally developed cash flow models and would generally be classified as Level 3. Additionally, the Company uses fair value to determine the inception value of the Company’s asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified as Level 3.

10. Commitments and Contingencies

From time to time, the Company may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of its business. All known liabilities are accrued when probable and reasonably estimable based on the Company’s best estimate of the potential loss. While the outcome and impact of currently pending legal proceedings cannot be predicted with certainty, the Company’s management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the Company’s consolidated operating results, financial position or cash flows.

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Following the May 6, 2014 announcement of the proposed Transactions, six putative class action lawsuits were filed by Forest Oil shareholders 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. 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 as against that entity.

The Consolidated Complaint alleges that the proposed Transactions arise 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 have 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 advisor for the proposed Transactions, 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 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 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

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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 Sections 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 that 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 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 have not yet been determined will be independent. The memorandum of understanding contemplates that the parties will enter into a stipulation of settlement.

The stipulation of settlement will be subject to customary conditions, including court approval. In the event that 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 in all 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 in 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 stockholders

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prior to final approval of the settlement. In addition, in connection with the settlement, the parties contemplate that the parties shall negotiate in good faith regarding the amount of attorneys’ fees and expenses that shall be paid to plaintiffs’ counsel in connection with the Actions. There can be no assurance 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. At this time, the Company is unable to guarantee the potential outcome of this litigation or the ultimate exposure.

In addition, Holdings has entered into a Committed Oilfield Services Agreement (the “Services Agreement”) with Nabors, which grants Nabors service contracts with revenues of no less than 20% and 75% of the Company’s gross spend on hydraulic fracturing services and drilling and directional services, respectively, through December 13, 2016. If at any yearly anniversary of the execution of the Services Agreement, Sabine has failed to meet the revenue commitment for the previous 12-month period and Nabors has complied with its service obligations under the Services Agreement, Holdings may be required to pay Nabors an amount equal to the revenue shortfall multiplied by 40%, which would likely result in Holdings requesting that the Company settle such obligations. For the annual period ended December 31, 2013, the Company recognized a shortfall and penalty amount due to Nabors under the terms of the services agreement of $1.7 million which is included in “Accrued operating expenses and other” liabilities on the Condensed Consolidated Balance Sheets and “Other income (expense)” on the Condensed Consolidated Statements of Operations for the year ended December 31, 2013 and was paid in January 2014.

As part of Sabine’s ongoing operations, since inception the Company has contracted with affiliates of Nabors to secure drilling rigs and other services for the oil and natural gas well activity the Company has undertaken. Amounts paid to affiliates of Nabors under these agreements totaled $37.6 million and $14.6 million for the three months ended September 30, 2014 and 2013, respectively, and $87.7 million and $34.4 million for the nine months ended September 30, 2014 and 2013, respectively. The Company recognized a liability on the Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013 of $4.6 million and $8.5 million, respectively, for these services which are reflected in “Accounts payable – trade” and “Accrued exploration and development” balances on the Condensed Consolidated Balance Sheets.

As of September 30, 2014 total future commitments relating to the Company’s secured rig and servicing contracts were $57.4 million over the next five years.

During 2014, the Company executed ten year gas and condensate gathering agreements for the transportation and processing of natural gas and condensate, covering certain properties in South Texas with contractually obligated annual minimum volume commitments to deliver a cumulative 88.5 Bcfe of gas and 5,150 MBbl of condensate by September 22, 2024. The gathering and transportation rates under these contracts are considered by management to be consistent with competitive market rates of other service providers. Under the terms of the agreements, the Company is required to make annual deficiency payments for any shortfalls in delivering the minimum annual volumes under these commitments beginning in the third quarter of 2015, which shall be partially offset by then-existing credit balances for production in excess

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of minimum commitments, if any. As of September 30, 2014, the Company has no material shortfall related to these contracts; however, as the Company continues to execute its development plan for these and other oil and gas assets, it could experience insufficient future production from the applicable assets and dedicated area to meet its transportation and processing commitments.

11. Subsequent Events

Management has evaluated subsequent events through November 12, 2014, which represents the date the condensed consolidated financial statements were issued. There were no subsequent events other than those discussed under Recent Developments in Note 1, the redetermination and borrowings subsequent to September 30, 2014 discussed in Note 5, additional natural gas swap and written put agreements discussed in Note 8 and the agreement reached with certain plaintiffs on November 11, 2014 discussed in Note 10.

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EX-99.2

Exhibit 99.2

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED FINANCIAL STATEMENTS

Introduction

On December 16, 2014, Forest Oil Corporation (“Old Forest”), Sabine Investor Holdings LLC, a Delaware limited liability company (“Sabine Investor Holdings”), FR XI Onshore AIV, LLC, a Delaware limited liability company (“AIV Holdings”), Sabine Oil & Gas Holdings LLC, a Delaware limited liability company (“Sabine Holdings”), Sabine Oil & Gas Holdings II LLC, a Delaware limited liability company (“Sabine Holdings II”) and Sabine Oil & Gas LLC (“Sabine”) entered into Amendment No. 1 (“Amendment No. 1”) to the Amended and Restated Agreement and Plan of Merger, dated as of May 5, 2014, and amended and restated as of July 9, 2014 (the “Original Merger Agreement” and the Original Merger Agreement as amended by Amendment No. 1, the “Amended Merger Agreement”).

Pursuant to the terms of the Original Merger Agreement, Sabine Investor Holdings agreed to contribute all of its equity interests in Sabine Holdings, and AIV Holdings agreed to contribute all of the equity interests in two other holding companies, FR NFR Holdings, Inc. and FR NFR, PI, Inc., to Old Forest, with Sabine Holdings becoming a wholly owned subsidiary of Old Forest (the “Contribution”). Pursuant to the terms of Amendment No. 1, the consideration payable to Sabine Investor Holdings and AIV Holdings in connection with the Contribution was modified such that upon the consummation of the Contribution, Sabine Investor Holdings and AIV Holdings received 59,941,540 and 19,300,376 shares of Old Forest common stock (the “Common Shares”), respectively, and 1,897,860 and 611,085 shares of Old Forest Series A senior non-voting equity equivalent preferred stock (the “Series A Preferred Shares”)(convertible into an aggregate 250,894,494 Common Shares), collectively representing approximately a 73.5% economic interest in Old Forest and 40% of the total voting power in Old Forest. Holders of Common Shares immediately prior to the closing of the Combination continued to hold their Common Shares following the closing of the Transactions (the “Closing”), which immediately following the Closing represented approximately a 26.5% economic interest in Old Forest and 60% of the total voting power in Old Forest. Immediately following the Closing, AIV Holdings contributed all of the Common Shares and Series A Preferred Shares it received in the Contribution to Sabine Investor Holdings. Together, these transactions are referred to as the “Combination.”

The Series A Preferred Shares are convertible into 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 Common Shares and, as a result of such conversion, would not, together with affiliates, hold more than 50% of the combined company (the “Company”)’s voting power and (2) the Company’s 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 the Company’s voting power upon receipt of such shares as voting securities.

The following unaudited pro forma condensed consolidated combined financial statements present the combination of the historical consolidated financial statements of Sabine O&G and Old Forest adjusted to give effect to the Combination as well as certain dispositions of assets by each of Sabine O&G and Old Forest during the periods presented. The unaudited pro forma condensed consolidated combined statements of operations for the nine months ended September 30, 2014 and for the year ended December 31, 2013 combine the historical consolidated statements of operations of Sabine O&G and the historical consolidated statements of operations of Old Forest, giving effect to the applicable dispositions and the Combination as if they had been consummated on January 1, 2013, the beginning of the earliest period presented. The unaudited pro forma condensed consolidated combined balance sheet combines the historical consolidated balance sheet of Sabine O&G and the historical condensed consolidated balance sheet of Old Forest as of September 30, 2014, giving effect to the Combination as if it had been consummated on September 30, 2014. The historical consolidated financial statements of Old Forest have been adjusted to reflect certain reclassifications in order to conform to Sabine O&G’s consolidated financial statement presentation.

The unaudited pro forma condensed consolidated combined financial statements were prepared using the acquisition method of accounting with Sabine O&G considered the predecessor of the Company or the acquirer of Old Forest in the Combination. Under the acquisition method of accounting, the purchase price is allocated to the underlying Forest assets acquired and liabilities assumed based on their respective fair market values with any excess purchase price allocated to goodwill.

1

Management performed an estimation of fair values of Old Forest’s assets and liabilities as of December 16, 2014. The value of the consideration given by Sabine Investor Holdings and AIV Holdings upon the consummation of the Combination was determined based on the closing price of Old Forest’s common shares on the closing date of the Combination. The preliminary estimated fair value of Old Forest’s assets and liabilities is based on discussions with Old Forest’s management, preliminary valuation studies, due diligence, and information presented in Old Forest’s public filings, the most significant assumptions related to the estimated fair values assigned to oil and gas properties. As additional information becomes available and as additional analyses are performed, adjustments may be necessary which may include adjustments to confirm Old Forest’s accounting policies to Sabine O&G’s accounting policies. Any increases or decreases in the fair value of relevant balance sheet amounts will result in adjustments to the pro forma balance sheet and/or statements of operations. The final purchase price allocation may be different than that reflected in the pro forma purchase price allocation presented herein, and this difference may be material.

The preliminary pro forma adjustments have been made solely for the purpose of providing the unaudited pro forma condensed consolidated combined financial statements presented below.

Assumptions and estimates underlying the unaudited adjustments to the pro forma condensed consolidated combined financial statements (the “pro forma adjustments”) are described in the accompanying notes. The historical consolidated financial statements have been adjusted in the pro forma condensed consolidated combined financial statements to give effect to pro forma events that are: (1) directly attributable to the Combination; (2) factually supportable; and (3) with respect to the pro forma statements of operations, expected to have a continuing impact on the combined results of Sabine O&G and Old Forest following the Combination. The unaudited pro forma condensed consolidated combined financial statements have been presented for illustrative purposes only and are not necessarily indicative of the operating results and financial position that would have been achieved had the Combination occurred on the dates indicated. Further, the unaudited pro forma condensed consolidated combined financial statements do not purport to project the future operating results or financial position of the combined company following the Combination.

The unaudited pro forma condensed consolidated combined financial statements, although helpful in illustrating the financial characteristics of the combined company under one set of assumptions, do not reflect the benefits of expected cost savings (or associated costs to achieve such savings), opportunities to earn additional revenue, or other factors that may result as a consequence of the Combination and, accordingly, do not attempt to predict or suggest future results. Specifically, the unaudited pro forma condensed consolidated combined statements of operations exclude projected operating efficiencies and synergies expected to be achieved as a result of the Combination. The unaudited pro forma condensed consolidated combined financial statements also exclude the effects of costs associated with any restructuring or integration activities or asset dispositions resulting from the Combination, as they are currently not known, and to the extent they occur, are expected to be non-recurring and will not have been incurred at the closing date of the Combination. However, such costs could affect the combined company following the Combination in the period the costs are incurred or recorded. Further, the unaudited pro forma condensed consolidated combined financial statements do not reflect the effect of any regulatory actions that may affect the results of the combined company following the Combination.

The unaudited pro forma condensed consolidated combined financial statements have been developed from and should be read in conjunction with:

• the accompanying notes to the unaudited pro forma condensed consolidated combined financial statements;

• the historical audited consolidated financial statements of Sabine O&G for the year ended December 31, 2013 disclosed in this current report;

• the historical unaudited consolidated financial statements of Sabine O&G as of and for the nine months ended September 30, 2014, disclosed in this current report;

• the historical audited consolidated financial statements of Old Forest as of and for the year ended December 31, 2013, disclosed in Annex B to Schedule 14A for Forest Oil Corporation filed with the Securities and Exchange Commission (“SEC”) on October 20, 2014;

• the historical unaudited condensed consolidated financial statements of Old Forest as of and for the nine months ended September 30, 2014, disclosed in Annex B to Schedule 14A for Forest Oil Corporation filed with the SEC on October 20, 2014; and

• other information relating to Sabine O&G and Old Forest contained in this current report and in Annex B to Schedule 14A for Forest Oil Corporation filed with the SEC on October 20, 2014.

2

SABINE UNAUDITED PRO FORMA CONDENSED CONSOLIDATED

COMBINED STATEMENT OF OPERATIONS

(In Thousands, Except Per Share Amounts)

	Nine Months Ended September 30, 2014
	Sabine O&G Predecessor Historical		Sabine O&G Divestiture Adjustments (a)		Old Forest Historical			Old Forest Divestiture Adjustments (b)			Pro Forma Adjustments			Pro Forma As Adjusted
Revenues:
Oil, natural gas, and natural gas liquids	$	355,401	$	—	$	186,616		$	(25,158	)	$	—		$	516,859
Other		1,145		—		1,068			—			—			2,213
Total revenues		356,546		—		187,684			(25,158	)		—			519,072
Costs, expenses, and other:
Lease operating expenses		34,662		—		43,254			(4,233	)		—			73,683
Marketing, gathering, transportation and other		17,091		—		7,122			(1,456	)		—			22,757
Production and ad valorem taxes		15,579		—		7,231			(1,326	)		—			21,484
General administrative expenses		20,584		—		22,451			(1,357	)		—			41,678
Depletion, depreciation, and amortization		142,995		—		62,639			(12,502	)		—			193,132
Impairment		1,659		—		204,621			—			—			206,280
Interest expense		80,383		—		47,631			(56	)		—			127,958
Realized and unrealized losses on derivatives instruments, net		1,611		—		353			—			—			1,964
Other, net		11,001		—		4,356			17,959			(20,157	)(j)		13,159
Total costs, expenses, and other		325,565		—		399,658			(2,971	)		(20,157	)		702,095
Loss before income taxes		30,981		—		(211,974	)		(22,187	)		20,157			(183,023	)
Income tax (benefit) expense		—		—		(2,405	)		(8,022	)		2,259	(d)		(146	)
									8,022	(b)
Net Income / (loss)	$	30,981	$	—	$	(209,569	)	$	(22,187	)	$	17,898		$	(182,877	)
Basic loss per common share	$	—	$	—	$	(1.79	)	$	(0.19	)	$	—		$	(0.92	)(i)
Diluted loss per common share	$	—	$	—	$	(1.79	)	$	(0.19	)	$	—		$	(0.92	)(i)
Weighted Average Shares Outstanding:
Basic		—		—		117,113			117,113			—			199,290	(i)
Diluted		—		—		117,113			117,113			—			199,290	(i)

The accompanying notes are an integral part of, and should be read together with,

this unaudited pro forma condensed combined financial information.

3

SABINE UNAUDITED PRO FORMA CONDENSED CONSOLIDATED

COMBINED STATEMENT OF OPERATIONS

(In Thousands, Except Share Amounts)

	Year Ended December 31, 2013
	Sabine O&G Predecessor Historical			Sabine O&G Divestiture Adjustments (a)			Old Forest Historical			Old Forest Divestiture Adjustments (b)			Pro Forma Adjustments			Pro Forma As Adjusted
Revenues:
Oil, natural gas, and natural gas liquids	$	354,223		$	(52,083	)	$	441,341		$	(226,398	)	$	—		$	517,083
Other		755			—			331			—			—			1,086
Total revenues		354,978			(52,083	)		441,672			(226,398	)		—			518,169
Costs, expenses, and other:
Lease operating expenses		42,491			(4,081	)		76,675			(35,142	)		—			79,943
Marketing, gathering, transportation and other		17,567			(2,132	)		11,895			(2,547	)		—			24,783
Production and ad valorem taxes		17,824			(4,108	)		14,857			(5,569	)		—			23,004
General administrative expenses		27,469			—			54,826			(18,498	)		—			63,797
Depletion, depreciation, and amortization		137,068			(17,009	)		171,557			(94,432	)		—			197,184
Ceiling test write-down of oil and natural gas properties		—			—			57,636			—			—			57,636
Interest expense		99,471			(4,162	)		119,829			(53,684	)		—			161,454
Realized and unrealized losses on derivatives instruments, net		(814	)		—			3,786			—			—			2,972
Other, net		3,325			(124	)		(142,606	)		142,637			—	(j)		3,232
Total costs, expenses, and other		344,401			(31,616	)		368,455			(67,235	)		—			614,005
Income (loss) before income taxes		10,577			(20,467	)		73,217			(159,163	)		—			(95,836	)
Income tax (benefit) expense		—			—			(707	)		(57,522	)		3,267	(d)		2,560
											57,522	(b)
Net Income / (loss)	$	10,577		$	(20,467	)	$	73,924		$	(159,163	)	$	(3,267	)	$	(98,396	)
Basic earnings per common share	$	—		$	—		$	0.62		$	(1.37	)	$	—		$	(0.49	)(i)
Diluted earnings per common share	$	—		$	—		$	0.62		$	(1.37	)	$	—		$	(0.49	)(i)
Weighted Average Shares Outstanding:
Basic		—			—			116,125			116,125			—			199,290	(i)
Diluted		—			—			116,125			116,125			—			199,290	(i)

The accompanying notes are an integral part of, and should be read together with,

this unaudited pro forma condensed combined financial information.

4

SABINE UNAUDITED PRO FORMA CONDENSED CONSOLIDATED

COMBINED BALANCE SHEET

(In Thousands)

	As of September 30, 2014
	Sabine O&G Predecessor Historical			Old Forest Historical			Old Forest Divestiture Adjustments (b)			Pro Forma Adjustments (c)			Pro Forma As Adjusted
Assets:
Current assets:
Cash and cash equivalents	$	5,774		$	823		$	184,222		$	—		$	190,819
Account receivable, net		96,245			38,306			—			—			134,551
Prepaid expenses and other current assets		3,938			6,203			(4	)		(107	)(e)		10,030
Deferred income taxes		—			—			—			—			—
Derivative instruments		12,819			8,033			—			—			20,852
Total current assets		118,776			53,365			184,218			(107	)		356,252
Property, plant, and equipment:
Oil and natural gas properties (full cost method)
Proved, net of accumulated depletion of $2,190,113 and $8,722,987		1,535,352			663,853			(207,475	)		(385,315	)(e)		1,606,415
Unproved		170,220			46,840			(6,720	)		97,525	(e)		307,865
Net oil and natural gas properties		1,705,572			710,693			(214,195	)		(287,790	)		1,914,280
Other property and equipment, net of accumulated depreciation and amortization of $11,538 and $45,892		15,921			6,199			(124	)		—			21,996
Total property, plant, and equipment		1,721,493			716,892			(214,319	)		(287,790	)		1,936,276
Other assets:
Derivatives instruments		1,422			1,134			—			—			2,556
Deferred income taxes		—			3,203			—			3,125	(f)		6,328
Goodwill		173,547			134,434			(30,920	)		63,996	(e)		341,057
Other long term assets		19,631			18,457			(1,748	)		(9,164	)(e)		27,176
Total other assets		194,600			157,228			(32,668	)		57,957			377,117
Total assets	$	2,034,869		$	927,485		$	(62,769	)	$	(229,940	)	$	2,669,645
Liabilities and member’s capital/shareholders’ equity:
Current liabilities:
Accounts payable and accrued liabilities	$	193,863		$	157,672		$	(1,146	)	$	21,577	(e)(g)	$	371,966
Accrued interest		15,364			13,244			—			—			28,608
Derivatives instruments		5,293			563			—			—			5,856
Deferred income taxes		—			3,203			—			8,650	(f)		11,853
Other short-term obligations		44			4,976			(115	)		(388	)(e)		4,517
Total current liabilities		214,564			179,658			(1,261	)		29,839			422,800
Long-term liabilities:
Long-term debt		1,569,016			813,155			—			(418,295	)(e)		1,963,876
Asset retirement obligation		14,872			20,487			(3,514	)		—			31,845
Derivatives instruments		3,899			601			—			—			4,500
Deferred income taxes		—			—			—			—	(f)		—
Other long-term obligations		527			61,620			(1,649	)		(1,371	)(e)		59,127
Total long-term liabilities		1,588,314			895,863			(5,163	)		(419,666	)		2,059,348
Member’s capital/shareholders’ equity:
Sabine member’s capital		1,523,008			—			—			(1,523,008	)(h)		—
Forest common stock, 119,369,323 shares issued and outstanding		—			11,937			—			7,879	(h)		19,816
Forest preferred stock (pro forma)		—			—			—			24,948	(h)		24,948
Forest capital surplus		—			2,560,353			—			(904,760	)(e)(g)(h)		1,655,593
Retained deficit		(1,291,017	)		(2,711,639	)		(56,345	)		2,546,141	(f)(g)(h)		(1,512,860	)
Accumulated other comprehensive loss		—			(8,687	)		—			8,687	(h)		—
Total member’s capital/shareholders’ equity		231,991			(148,036	)		(56,345	)		159,887			187,497
Total liabilities and member’s capital/shareholders’ equity	$	2,034,869		$	927,485		$	(62,769	)	$	(229,940	)	$	2,669,645

The accompanying notes are an integral part of, and should be read together with,

this unaudited pro forma condensed combined financial information.

5

NOTES TO THE UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED

FINANCIAL STATEMENTS

1. Basis of Pro Forma Presentation

Overview

The pro forma financial statements have been prepared assuming the Combination is accounted for using the acquisition method of accounting with Sabine O&G as the acquiring entity. Under acquisition accounting, Sabine O&G’s assets and liabilities will retain their carrying values and Old Forest’s assets and liabilities will be recorded at their fair values measured as of the acquisition date. The preliminary estimated fair value of Old Forest’s assets and liabilities approximates the preliminary estimated purchase price. The pro forma adjustments have been prepared as if the Combination had taken place on September 30, 2014 in the case of the pro forma balance sheet and on January 1, 2013 in the case of the pro forma statements of operations. The Combination and adjustments are described in Note 2. “Divestiture and Pro Forma Adjustments and Assumptions” to these unaudited pro forma condensed consolidated combined financial statements.

The unaudited pro forma condensed consolidated combined financial statements should be read in conjunction with (i) Sabine O&G’s (as predecessor) historical consolidated financial statements and related notes for the year ended December 31, 2013 and for the nine months ended September 30, 2014 and (ii) Old Forest’s historical consolidated financial statements and related notes for the year ended December 31, 2013 and for the nine months ended September 30, 2014.

Certain reclassifications have been made to reflect comparability of financial information. However, the pro forma condensed consolidated combined financial statements may not reflect all adjustments necessary to conform the accounting policies of Old Forest to those of Sabine O&G due to limitations on the availability of information as of the date of this current report. The pro forma adjustments represent management’s estimates based on information available as of the date of this document and are subject to change as additional information becomes available and additional analyses are performed. The pro forma financial statements do not reflect the impact of possible revenue or earnings enhancements, cost savings from operating efficiencies or synergies, or asset dispositions. Also, the pro forma financial statements do not reflect possible adjustments related to restructuring or integration activities that have yet to be determined or transaction or other costs following the Combination that are not expected to have a continuing impact. Further, one-time transaction-related expenses anticipated to be incurred prior to, or concurrent with, closing the Combination are not included in the pro forma statements of operations.

Purchase Price

The following table summarizes the deemed purchase price (in thousands, except per share data) paid by Sabine O&G for Old Forest:

Common stock outstanding at Combination		120,048
Common stock price (1)	$	0.34
Common stock value	$	40,816
Consideration	$	40,816

(1) The purchase price is based on the fair value of the issued and outstanding Old Forest common shares as of the closing date. The estimated fair value of the Sabine common shares is based on the closing price as of December 16, 2014.

Purchase Price Allocation

The unaudited pro forma condensed consolidated combined financial statements were prepared using the acquisition method of accounting with Sabine O&G considered the acquirer or predecessor. Under the acquisition method of accounting, tangible and identifiable assets acquired and liabilities assumed are recorded at their estimated fair values. The excess of the purchase price over the preliminary estimated fair values of net assets acquired is recorded as goodwill. As additional information becomes available and as additional analyses are performed, adjustments may be necessary. Any increases or decreases in the fair value of relevant balance sheet amounts will result in adjustments to the pro forma balance sheet and/or statements of operations. The final purchase price allocation may be different than that reflected in the pro forma purchase price allocation presented herein, and this difference may be material.

6

The following table summarizes allocation of the preliminary estimate of the purchase price to the assets acquired and liabilities assumed (in thousands):

Old Forest fair values (1):
Current assets	$	53,258
O&G property, plant and equipment, net		422,903
Other PPE, net		6,199
Other long-term assets		10,427
Goodwill		198,430
Current liabilities		(174,204	)
Long-term debt		(394,860	)
Deferred income taxes		—
Other long-term liabilities		(81,337	)
Total consideration and fair value	$	40,816

(1) The fair value of the proved and unproved oil and gas properties is based on an income (risk adjusted reserve engineering) approach. Other fair value adjustments were made to Old Forest’s assets and liabilities, as appropriate. A change in the estimated fair value of Old Forest’s assets and liabilities would increase or decrease the amount of goodwill recognized from the Combination by the same amount.

2. Divestiture and Pro Forma Adjustments and Assumptions

The accompanying unaudited pro forma condensed consolidated combined financial statements give pro forma effect to the following:

(a) Sabine O&G Divestiture Adjustments reflect the pro forma impact of the sale of interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area by Sabine O&G on December 18, 2013 as if the sale had been consummated on January 1, 2013.

(b) Old Forest Divestiture Adjustments reflect the pro forma impact of the sale of oil and natural gas properties in the Texas Panhandle in November 2013, in South Texas in February 2013, and in Arkoma in December 2014 by Old Forest as if these sales had been consummated on January 1, 2013. Additional notation is referenced to adjust income tax expense to give effect to the change in the valuation allowance that would have been required or associated with the effects of the pro forma adjustments at statutory rates. As discussed in Old Forest’s Annual and Quarterly Reports on Forms 10-K/A and 10-Q/A for the periods ended December 31, 2013 and September 30, 2014, respectively, Old Forest has placed a full valuation allowance against its deferred tax assets.

(c) Adjustments to reflect Old Forest’s assets and liabilities at their estimated fair values as discussed in Note 1. “Purchase Price Allocation” as well as other pro forma adjustments discussed herein.

(d) Adjustment to reflect the impact on deferred taxes and the estimated income tax effect on the pro forma adjustments described herein using a blended federal and state statutory income tax rate of 36%. A full valuation allowance is recorded to reduce the combined deferred tax asset balance. Based upon all available evidence, it is more likely than not that the deferred tax assets will not be realized. The income tax expense of $3,267 for the year ended December 31, 2013 and income tax expense of $2,259 for the nine months ended September 30, 2014 relate to deferred taxes for goodwill.

(e) Adjustments necessary to reflect assets and liabilities at their estimated fair values as discussed in Note 1. “Preliminary Estimated Purchase Price Allocation.”

(f) Adjustments reflect the accounting for the income tax effects of the purchase accounting adjustments. A full valuation allowance is recorded against the combined net deferred tax asset balance. In addition, adjustments were recorded on the balance sheet to account for the federal and state deferred tax impact of Sabine’s cumulative temporary differences resulting from the change in tax status which will be recognized through income tax expense during the period of the change. The change in tax status is not reflected in the pro forma statement of operations. In connection with the Combination, Sabine O&G’s historical owners contributed entities that were under common control into Old Forest. As a result, tax loss carry forwards of $270 million will be accounted for through equity which will be offset with a corresponding valuation allowance recorded through equity. Adjustments were recorded to account for the valuation allowance on the net deferred tax asset

7

of the combined deferred taxes of Sabine O&G and Old Forest excluding the deferred tax liability related to indefinite lived intangibles of $5.5 million, which is not considered when assessing the valuation allowance on the combined deferred taxes of Sabine O&G and Old Forest.

(g) Adjustments to accrued liabilities include estimated remaining transaction costs totaling $23.4 million yet to be incurred and paid which are offset as an adjustment to capital surplus. Additionally, certain of Old Forest’s unvested stock-based compensation awards vested upon the consummation of the Combination and settled in cash. These Phantom Stock Units were liability based awards that had been accrued with a value of approximately $0.4 million in current liabilities and $0.2 million in long-term liabilities based on amounts recorded in Old Forest’s September 30, 2014 trial balance. These accruals have been removed within adjustment (e) recorded to reflect Old Forest assets and liabilities at their fair values.

(h) To eliminate the historical Member’s capital of Sabine O&G, Capital surplus and accumulated other comprehensive income of Old Forest and to recognize the additional $7.9 million related to common stock and $24.9 million related to preferred stock, each issued in the aggregate to Sabine Investor Holdings and AIV Holdings and Capital surplus as a result of the purchase accounting.

(i) To reflect adjustments to basic and diluted earnings per share data based on an estimated 199 million weighted average basic and diluted Sabine common shares outstanding upon consummation of the Combination. The 251 million shares of Series A non-voting equity-equivalent preferred shares were not included in the calculations of diluted earnings per share as their inclusion would have an antidilutive effect.

(j) Adjustment to exclude transaction costs recognized in the current period.

3. Pro Forma Supplemental Oil and Natural Gas Disclosures

The following schedules reflect Sabine O&G’s and Old Forest’s combined supplemental information regarding oil and natural gas producing activities, giving effect to the merger as if it had taken place on January 1, 2013. The following estimates of proved oil and natural gas reserves, both developed and undeveloped, represent combined estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells for which relatively minor expenditures are required for completion.

Disclosures of oil and natural gas reserves which follow are based on estimates as of December 31, 2013 in accordance with guidelines established by the SEC. Such estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. These estimates do not include probable and possible reserves. The information provided does not necessarily represent the combined companies’ estimate of expected future cash flows or value of proved oil and natural gas reserves.

Changes in estimated reserve quantities:

	Sabine O&G												Old Forest												Combined
	Oil (Mbbls)			NGLS (Mbbls)			Natural Gas (Bcf)			Natural Gas Equivalents (Bcfe)			Oil (Mbbls)			NGLS (Mbbls)			Natural Gas (Bcf)			Natural Gas Equivalents (Bcfe)			Oil (Mbbls)			NGLS (Mbbls)			Natural Gas (Bcf)			Natural Gas Equivalents (Bcfe)
Estimated Proved Reserves
Balance at December 31, 2012		16.0			29.4			709.0			980.8			33.7			41.3			912.8			1,362.6			49.7			70.7			1,621.8			2,343.4
Revision of previous estimates		0.1			—			(58.3	)		(57.4	)		(3.4	)		(2.0	)		22.0			(10.2	)		(3.3	)		(2.0	)		(36.3	)		(67.6	)
Extensions and discoveries		6.9			5.4			73.7			147.5			11.6			4.6			51.1			148.4			18.5			10.0			124.8			295.9
Production (1)		(1.4	)		(1.8	)		(44.0	)		(63.4	)		(2.3	)		(2.5	)		(46.7	)		(75.4	)		(3.7	)		(4.3	)		(90.7	)		(138.8	)
Sale of minerals in Place		(4.7	)		(8.0	)		(92.1	)		(168.2	)		(23.0	)		(29.7	)		(494.7	)		(800.5	)		(27.7	)		(37.7	)		(576.8	)		(968.7	)
Balance at December 31, 2013		16.9			25.0			588.3			839.3			16.7			11.7			454.6			624.9			33.6			36.7			1,042.9			1,464.2
Estimated Proved Developed Reserves
December 31, 2012		3.8			10.3			415.0			499.2			12.3			25.5			710.3			937.3			16.1			35.8			1,125.3			1,436.5
December 31, 2013		6.0			11.6			360.6			466.1			6.2			6.9			336.3			414.4			12.2			18.5			696.9			880.5

The following table sets forth unaudited pro forma supplemental oil and natural gas disclosures concerning the combined companies’ discounted future net cash flows from proved oil and natural gas reserves as of December 31, 2013, net of income tax expense, and giving effect to the merger as if it had taken place on January 1, 2013. Income tax expense has been computed using assumptions relating to the future tax rates and the permanent differences and credits under the tax laws relating to oil and natural gas activities as of December 31, 2013. Cash flows relating to Old Forest are based on Old Forest’s evaluation of reserves. Future income tax expense on the combined companies’ properties was calculated based on the combined companies’ estimated tax rate after giving effect to the pro forma transactions.

8

Standardized measure of discounted future net cash flows from estimated production of proved oil and natural gas reserves (in thousands) as of December 31, 2013:

	Sabine O&G			Old Forest			Pro Forma Adjustments (1)			Combined
Future cash inflows		4,667,459			3,459,749			—			8,127,208
Future production costs		(1,127,359	)		(1,165,344	)		—			(2,292,703	)
Future development costs		(682,876	)		(676,684	)		—			(1,359,560	)
Future income taxes		—			(18,441	)		(32,571	)		(51,012	)
Future net cash flows		2,857,224			1,599,280			(32,571	)		4,423,933
10% annual discount for estimated timing of cash flows		(1,506,352	)		(864,672	)		6,459			(2,364,565	)
Standardized measure of discounted future net cash flows		1,350,872			734,608			(26,112	)		2,059,368

(1) Pro forma adjustments related to reflecting the income tax expense on the combined future net cash flows giving a tax effect to Sabine O&G’s historical flow through financial statements, based on the combined companies’ estimated effective tax rate, after giving effect to the pro forma adjustments.

Changes in standardized measure of discounted future net cash flows from proved oil and natural gas reserves (in thousands):

	Sabine O&G			Old Forest			Pro Forma Adjustments (1)			Combined
Beginning Balance		909,793			1,397,097			—			2,306,890
Revisions of previous estimates:
Changes in prices and costs		186,943			222,516			—			409,459
Changes in quantity		45,167			(114,712	)		—			(69,545	)
Additions to proved reserves		392,752			295,585			—			688,337
Sale of oil, natural gas and NGL, net		(274,180	)		(337,914	)		—			(612,094	)
Sales of reserves		(152,677	)		(1,099,372	)		—			(1,252,049	)
Accretion of discount		90,973			143,432			—			234,405
Changes in estimated future developments costs		22,181			50,568			—			72,749
Previously estimated future development costs incurred		117,377			128,482			—			245,859
Change in rate of production and other, net		12,542			19,321			—			31,863
Net change in income tax		—			29,605			(26,112	)		3,493
Net change		441,078			(662,489	)		(26,112	)		(247,523	)
Ending Balance		1,350,872			734,608			(26,112	)		2,059,367

(1) Pro forma adjustments related to reflecting the income tax expense on the combined future net cash flows giving a tax effect to Sabine’s historical flow through financial statements, based on the combined companies’ estimated effective tax rate, after giving effect to the pro forma adjustments.

9

EX-99.3

Exhibit 99.3

BUSINESS AND PROPERTIES

General

Sabine is an independent oil and natural gas company engaged in the acquisition, development, exploitation and exploration of oil, natural gas properties and natural gas liquids primarily in North America. Sabine was incorporated in New York in 1924, as the successor to a company formed in 1916, and has been a publicly held company since 1969.

On December 16, 2014, pursuant to a series of transaction agreements, the Legacy Sabine Investors contributed the equity interests in Sabine O&G to Sabine (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. 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, the Company filed a certificate of amendment with the New York Secretary of State to change its name from “Forest Oil Corporation” to “Sabine Oil & Gas Corporation.” Sabine’s principal executive offices and corporate headquarters are located at 1415 Louisiana Street, Suite 1600, Houston, Texas 77002. Sabine’s telephone number at that address is (832) 242-9600.

Following the consummation of the transactions contemplated by the Registration Statement on Form S-4 of Sabine Oil & Gas Corporation, a Delaware corporation (“New Delaware Holdco”) as filed on January 21, 2015, Sabine, which will be a wholly owned subsidiary of New Delaware Holdco, will be renamed as “Sabine Oil & Gas Corporation (New York)”.

Sabine O&G Properties

Overview

The Sabine O&G Properties are focused in three core geographic areas:

• East Texas, targeting the Cotton Valley Sand and Haynesville Shale formations;

• South Texas, targeting the Eagle Ford Shale formation; and

• North Texas, targeting the Granite Wash formation.

From Sabine O&G’s inception in 2007 through 2012, it was focused primarily in East Texas, where Sabine O&G completed multiple acquisitions and executed a development program to build an extensive inventory of Cotton Valley Sand and Haynesville Shale drilling locations. During 2012, Sabine O&G established its initial position in South Texas in the Eagle Ford Shale formation through two farm-out agreements with a major operator, establishing a footprint in the basin at an attractive upfront cost. Subsequently, Sabine O&G has completed three additional transactions and grassroots leasing in the Eagle Ford Shale. Sabine O&G’s North Texas position was acquired from a privately-held company in December 2012 and is concentrated in the Granite Wash formation. In December 2013, Sabine O&G sold its interests in certain oil and natural gas properties in the Texas Panhandle and surrounding Oklahoma area. In 2014, Sabine O&G has purchased additional working interests in certain of its operated Granite Wash properties.

Through Sabine O&G’s drilling program and its acquisition activities, Sabine O&G grew production from approximately 32 MMcfe/d for the twelve months ended December 31, 2008, to approximately 211 MMcfe/d for the three months ended September 30, 2014, representing a compound annual growth rate (“CAGR”) of 39%. During that same period, the percentage of Sabine O&G’s production comprised of oil and natural gas liquids (“NGLs”), which are collectively referred to as “liquids” grew from approximately 12% of total production to approximately 36%.

As of September 30, 2014, Sabine O&G held interests in approximately 126,600 gross (101,600 net) acres in East Texas, 41,700 gross (34,800 net) acres in South Texas and 51,700 gross (37,400 net) acres in North Texas. As of September 30, 2014, Sabine O&G was the operator on 97%, 99% and 99% of Sabine O&G’s net acreage positions in East Texas, South Texas and North Texas, respectively.

From Sabine O&G’s formation through December 31, 2013, it had drilled over 194 total wells, including over 129 horizontal wells. Sabine O&G utilized drilling and completion expertise gained in its East Texas operations and extended that expertise to its South Texas operations where it reported an average initial 30-day production rate of approximately 2,400 Boe/d for the first eight wells in Sabine O&G’s Sugarkane prospect and approximately 1,400 Boe/d for the first eight wells in Sabine O&G’s South Shiner prospect.

The hydrocarbon content of this inventory ranges from predominantly oil to entirely natural gas, providing significant optionality in our capital allocation to maximize returns in a wide variety of commodity price environments. Furthermore, the Sabine O&G Property acreage in the Haynesville Shale is approximately 95% held by production, which gives us flexibility to focus our drilling and completion capital program on the liquids-rich Eagle Ford Shale, Granite Wash and Cotton Valley Sand positions and defer development in the Haynesville Shale until commodity prices justify such development.

The 2014 drilling and completion capital program associated with the Sabine O&G Properties was focused on projects that exhibit attractive economics and best continue to drive our growth in cash flow. Full year 2014 capital expenditures were estimated to total approximately $582 million, including approximately $528 million on drilling and completion activities and approximately $54 million on leasing and other activities. Drilling and completion expenditures included approximately $148 million for the development of proved undeveloped reserves and approximately $380 million for the development of unproved reserves. The drilling and completion expenditures for the development of proved undeveloped reserves in 2014 was reduced from figures incorporated in Sabine O&G’s third party report as of December 31, 2013 in relation to 2014 development. Sabine O&G revised the near term development program to focus on areas in North Texas and East Texas where recent completions support greater economic results. Certain 2014 proved undeveloped projects are now expected to be developed in 2015; however, the revisions to the development program do not extend the development of any proved undeveloped reserves beyond five years from the date of initial booking and do not significantly impact the present value of estimated future cash flows.

As of December 31, 2013, Sabine O&G had overall estimated proved reserves of 839.3 Bcfe, consisting of 596.0 Bcfe in East Texas, 182.6 Bcfe in South Texas and 60.7 Bcfe in North Texas. Approximately 56% of Sabine O&G’s proved reserves were classified as proved developed, and 30% of Sabine O&G’s proved reserves were liquids. The following chart summarizes certain operating information of Sabine O&G’s properties as of December 31, 2013:

								Estimated Net Proved Reserves
Area	Gross Acreage		Net Acreage		% Held By Production			Bcfe		Average WI/NRI	% Developed
East Texas(1)
Cotton Valley Sand		100,488		88,900		95	%		514.3	76.5% / 60.3%		58.8	%
Haynesville Shale		85,004		67,283		95	%		81.7	75.4% / 58.6%		86.2	%
South Texas
Sugarkane		2,631		2,387		90	%		118.9	92.3% / 72.5%		34.8	%
South Shiner		29,150		24,196		20	%		53.6	57.1% / 44.1%		21.3	%
North Shiner		10,263		7,261		31	%		10.1	55.8% / 42.8%		30.2	%
North Texas
Granite Wash		51,103		33,537		15	%		60.7	51.3% / 39.7%		28.5	%

(1) Sabine O&G’s acreage in East Texas excludes 81,060 gross and 71,291 net acres prospective for other formations. Furthermore, a significant portion of Sabine O&G’s Haynesville Shale and Cotton Valley Sand acreage overlaps geographically, so such acreage is only counted once in Sabine O&G’s East Texas acreage despite representing two distinct targets and development opportunities.

Sabine O&G’s Acquisition History

During 2011 through 2013, Sabine O&G successfully completed five significant acquisitions that, coupled with farm out agreements, established Sabine O&G’s positions in the Eagle Ford Shale in South Texas and in the Granite Wash and Cleveland Sand areas in North Texas, and expanded Sabine O&G’s positions in the Cotton Valley Sand and Haynesville Shale areas in East Texas. Sabine O&G’s key acquisitions and development activities during such period were as follows:

• In January and February 2011, Sabine O&G acquired, in two acquisitions, approximately an additional 21,000 net leasehold acres with then-current net production of approximately 3,900 Boe/d, further growing Sabine O&G’s position in the Haynesville Shale.

• In July and September 2011, Sabine O&G acquired, in two acquisitions, approximately an additional 37,000 net leasehold acres with then current production of approximately 5,800 Boe/d, to significantly consolidate Sabine O&G’s acreage in the Cotton Valley Sand;

• Sabine O&G established its initial position in the Eagle Ford Shale in South Texas in 2012 through a farm-out agreement, which obligated it to drill and complete two wells in the play to earn approximately 20,000 gross (15,500 net) acres.

• Subsequently, Sabine O&G has grown its position in the Eagle Ford Shale to over 40,400 net acres as of the date of this filing, via four additional transactions and an active leasing campaign and continue to benefit from low-cost acreage earning potential through the execution of additional joint venture and farm-out agreements.

• In December 2012, Sabine O&G acquired interests in over 60,000 net leasehold acres with then-current net production of approximately 6,500 Boe/d, which established Sabine O&G’s position in the Granite Wash and Cleveland Sand in North Texas. Sabine O&G has since divested the Cleveland Sand assets.

Operating Regions Associated with the Sabine O&G Properties

East Texas

The East Texas portion of the Sabine O&G Properties is characterized by several productive horizons, such as the Cotton Valley Sand, Haynesville Shale, Haynesville Lime, 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 the Sabine O&G 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 the Sabine O&G 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.

The Sabine O&G Properties are primarily located in Harrison, Panola, Rusk and Shelby Counties with estimated proved reserves of 596.0 Bcfe as of December 31, 2013, of which 83% is gas and 63% is developed. As of December 31, 2013, the Sabine O&G Properties were producing from 822 wells in East Texas, and Sabine O&G operated 734, or 89%, of those wells. Average net daily production in East Texas from the Sabine O&G Properties for the three months ended December 31, 2013 was 123.64 MMcfe/d.

Substantially all of the reserves in East Texas associated with the Sabine O&G Properties are located in the following geological formations:

• Cotton Valley Sand—As of December 31, 2013, approximately 100,500 gross (89,000 net) acres of this East Texas position was prospective for the liquids-rich Cotton Valley Sand formation, 95% of which was held by production. As of December 31, 2013, the Sabine O&G Properties produced from 37 horizontal and 694 vertical wells in the Cotton Valley Sand, and Sabine O&G operated 655, or 90%, of those wells.

• Haynesville Shale—As of December 31, 2013, approximately 85,000 gross (67,300 net) acres of Sabine O&G’s East Texas position was prospective for the Haynesville Shale, 95% of which was held by production. As of December 31, 2013, Sabine O&G produced from 56 horizontal wells in the Haynesville Shale, and it operated 48, or 86%, of those wells. Sabine is currently executing on a program to complete eight previously drilled but uncompleted wells under a joint venture with a third party in 2014.

South Texas

The South Texas assets associated with the Sabine O&G Properties are primarily prospective for the Eagle Ford Shale formation. The Eagle Ford Shale play is experiencing significant growth due to attractive development economics driven by high liquids content. 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, 2013, the Sabine O&G Properties represented interests in approximately 42,000 gross (33,800 net) acres in DeWitt and Lavaca Counties prospective for the Eagle Ford Shale, approximately 27% of which was held by production. This area had estimated proved reserves of 182.6 Bcfe as of December 31, 2013, of which 60.1% was oil or NGLs and 30.6% was developed. As of December 31, 2013, the Sabine O&G Properties were producing from 22 wells in South Texas, and Sabine O&G operated 21, or 95%, of those wells. Average net daily production associated with the Sabine O&G Properties in South Texas for the three months ended December 31, 2013 was 58.87 MMcfe/d. Sabine O&G acquired its initial acreage in the Eagle Ford Shale in 2012 through a drill-to-earn joint venture with a major oil company. Subsequently, Sabine O&G has continued to grow the position via an active leasing program and four additional strategic transactions. We believe the Sabine O&G Properties’ South Texas inventory has significant resource potential and exhibits attractive economics in the current commodity price environment. We continue to evaluate and pursue opportunities to grow this position within the guidelines of our strategic and financial objectives.

Primary operations are in the following areas:

• Sugarkane Area—As of December 31, 2013, the Sugarkane area was approximately 2,600 gross (2,400 net) acres, 90% of which was held- by-production. As of December 31, 2013, the Sabine O&G Properties were producing from 10 horizontal wells, nine of which it operates. The shape of this acreage block makes it well-suited for full field pad development, and we are the operator for all of the identified drilling locations.

• South Shiner Area—As of December 31, 2013, the South Shiner area was approximately 29,200 gross (24,200 net) acres, 20% of which was held-by-production. As of December 31, 2013, the Sabine O&G Properties were producing from eight horizontal wells, all of which Sabine O&G operated.

• North Shiner Area—As of December 31, 2013, the North Shiner area was approximately 10,300 gross (7,300 net) acres, 31% of which was held-by-production. As of December 31, 2013, the Sabine O&G Properties were producing from four horizontal wells, all of which Sabine O&G operated.

North Texas

The North Texas properties associated with the Sabine O&G Properties are located in the Anadarko Basin and it is actively targeting the Granite Wash play. The Anadarko Basin has a long history of vertical well development, with first commercial production in 1904, and modern horizontal development techniques have vastly improved recoveries. 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.

In North Texas, as of December 31, 2013, Sabine O&G held rights to develop approximately 51,100 gross (33,500 net) acres primarily in Roberts County in Texas, approximately 15% of which was held by production. The North Texas acreage as of December 31, 2013 includes approximately 30,000 net acres that are subject to a continuous drilling clause which requires it to drill one gross well every 180 days to hold the entire 30,000 net acre position.

This area has estimated proved reserves of 60.7 Bcfe as of December 31, 2013, of which 66% was oil or NGLs and 28.5% was developed. As of December 31, 2013, the Sabine O&G Properties were producing from 20 wells in North Texas, all of which Sabine O&G operated. Average net daily production in North Texas for the three months ended December 31, 2013 was 28.4 MMcfe/d. We continue to evaluate and pursue opportunities to grow this position on an opportunistic basis.

Old Forest Properties

Old Forest’s core operational areas consist of drilling projects that have exposure to oil, natural gas, and natural gas liquids. Old Forest’s primary areas of focus in 2014 were in the Ark-La-Tex in East Texas and the Eagle Ford in South Texas.

Ark-La-Tex

The acreage position associated with the Old Forest Properties consist of 234,000 gross (162,000 net) acres in the greater Ark-La-Tex. Approximately 78% of such acreage is held by production, of which 85% is operated by Old Forest. Old Forest believes that this asset base provides repeatable and predictable drilling and recompletion opportunities within multiple stacked-pay intervals, including the Cotton Valley, Haynesville, and other formations. Recent drilling activity has focused on the liquids-rich Cotton Valley and other formations in East Texas. During 2012, Old Forest changed its focus to target primarily liquids-rich drilling projects to take advantage of these higher-margin opportunities as a result of a decrease in natural gas prices. In 2013, Old Forest continued to primarily target the Cotton Valley formation and experienced relatively consistent and predictable results. Old Forest drilled a total of six wells in 2013 that had a 30-day average gross production rate of 8.7 MMcfe/d (40% liquids). During 2014, Old Forest targeted the Cotton Valley and its efforts focused on transitioning to multi-well pad drilling in certain areas to improve efficiency as Old Forest sought to reduce well costs.

Eagle Ford

The acreage position associated with the Old Forest Properties consist of 48,000 gross (24,000 net) acres in the Eagle Ford. In April 2013, Old Forest announced a joint development agreement with an industry partner that allowed Old Forest to increase its pace of drilling activity during 2013 and implement technological refinements and enhancements. These enhancements involve ongoing micro-seismic and subsurface data analysis and reservoir studies that are being used to optimize well placement, lateral length, and fracture stimulation techniques and design. Old Forest is attempting to operate more efficiently through a combination of decreased drilling and completion time, the utilization of a more targeted completion design, and capitalizing on operational synergies associated with pad drilling. Drilling and completion costs for the wells drilled in 2014 have averaged approximately $4.5 million per gross well as compared to $6 million for the wells drilled in 2013.

Old Forest Acquisition and Divestiture Activities

On November 17, 2014, Old Forest entered into an Agreement for Purchase and Sale of Assets with Camterra Resources Partners, Ltd (“Camterra”). Pursuant to the purchase and sale agreement, Old Forest agreed to sell to Camterra natural gas properties located in the Arkoma Basin (the “Arkoma Gas Assets”) and various other related assets (together with the Arkoma Gas Assets, the “Arkoma Assets”). The transaction closed on December 15, 2014. The sales price of the Arkoma Assets was approximately $185 million, subject to customary adjustments to reflect an economic effective date of October 1, 2014. Old Forest received $9 million of the sales price as a deposit upon execution of the purchase and sale agreement and $175 million at closing.

On October 1, 2014, Old Forest entered into, and closed on, an agreement to purchase approximately 7,700 net acres comprised of both undeveloped and producing properties, including three horizontal Cotton Valley wells, located in Rusk County in East Texas, for a purchase price of $20 million.

In October 2013, Old Forest entered into an agreement to sell all of its oil and natural gas properties located in the Texas Panhandle for $1 billion in cash. This transaction closed in November 2013 and Old Forest has received proceeds of $985 million through June 2014, including $20 million received in May 2014, after customary purchase price adjustments and escrow account settlements.

In August 2013, Old Forest entered into an agreement to sell a portion of its largely undeveloped acreage position located in Crockett County in the Permian Basin of West Texas. This transaction closed on September 10, 2013 and Old Forest received net cash proceeds of $31 million.

In January 2013, Old Forest entered into an agreement to sell all of its oil and natural gas properties located in South Texas, excluding its Eagle Ford oil properties, for $325 million in cash. This transaction closed in February 2013 and Old Forest received proceeds of $321 million, after customary purchase price adjustments.

In November 2012, Old Forest sold all of its oil and natural gas properties located in South Louisiana for net cash proceeds of $211 million. In October 2012, Old Forest sold the majority of its East Texas natural gas gathering assets for net cash proceeds of $29 million.

In June 2011, Old Forest completed an initial public offering of approximately 18% of the common stock of Old Forest’s then wholly-owned subsidiary, Lone Pine Resources Inc. (“Lone Pine”), which held Old Forest’s ownership interests in its Canadian operations. On September 30, 2011, Old Forest distributed, or spun-off, its remaining 82% ownership in Lone Pine to Old Forest’s stockholders, by means of a special stock dividend of Lone Pine common shares.

In 2009, Old Forest sold oil and natural gas properties located in the Permian Basin in West Texas and New Mexico in three separate transactions for net proceeds of $908 million in cash.

Estimated Proved Reserves Associated with the Sabine O&G Properties

The information with respect to estimated proved reserves of the Sabine O&G Properties as of December 31, 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 SEC applicable to companies involved in oil and natural gas producing activities in effect at the applicable time. The report of Ryder Scott is dated January 24, 2014. The information with respect to the estimated proved reserves of the Sabine O&G Properties as of December 31, 2012 and 2011 presented below have been prepared by our independent petroleum engineering firm, Miller and Lents, Ltd. (“Miller and Lents”), in accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities in effect at the applicable time. The reports of Miller and Lents are dated February 21, 2013 and January 18, 2012. The reports of Ryder Scott and Miller and Lents were filed as Exhibits 99.2 and 99.3 to the Registration Statement on Form S-4 of New Delaware Holdco on January 21, 2015. These proved reserve estimates as of December 31, 2012 and December 31, 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 proved reserves is the current market value of the Sabine O&G Properties’ 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 estimated present value of the Sabine O&G Properties’ 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 new rules also permit the presentation of estimated “probable” or “possible” reserves, we have limited our presentation to estimated proved reserves.

	At December 31,
	2013(1)		2012(2)		2011(3)
	Proved reserves (Bcfe)		Proved reserves (Bcfe)		Proved reserves (Bcfe)
Operating area
East Texas		596.0		686.4		1,322.9
South Texas		182.6		107.5		—
North Texas		60.7		186.9		—
Other		—		—		38.5
Total		839.3		980.8		1,361.4

(1) 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.

(2) Data for December 31, 2012 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 $94.71 per Bbl for oil and (b) Henry Hub spot market prices for the prior 12 months of $2.76 per MMbtu for natural gas.

(3) Data for December 31, 2011 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 $96.19 per Bbl for oil and (b) Henry Hub spot market prices for the prior 12 months of $4.12 per MMbtu for natural gas.

The following table sets forth additional information regarding estimated proved reserves of the Sabine O&G Properties at the dates indicated.

	At December 31,
	2013(1)			2012(2)			2011(3)
Estimated proved reserves:
Oil (MMBbl)		16.9			16.0			5.9
NGLs (MMBbl)		25.0			29.4			26.0
Natural gas (Bcf)		588.1			709.0			1,170.0
Total estimated proved reserves (Bcfe)		839.3			980.8			1,361.4
Proved developed producing reserves:
Oil (MMBbl)		5.5			3.4			1.8
NGLs (MMBbl)		11.0			8.9			8.7
Natural gas (Bcf)		348.3			322.9			398.4
Total proved developed producing reserves (Bcfe)		447.7			396.3			461.6
Proved developed non-producing:
Oil (MMBbl)		0.5			0.4			0.6
NGLs (MMBbl)		0.6			1.4			1.6
Natural gas (Bcf)		12.3			92.1			116.5
Total proved developed non-producing reserves (Bcfe)		18.4			102.9			129.8
Total proved undeveloped:
Oil (MMBbl)		10.9			12.2			3.5
NGLs (MMBbl)		13.4			19.1			15.7
Natural gas (Bcf)		227.5			293.8			655.1
Total proved undeveloped reserves (Bcfe)		373.2			481.5			770.0
Percent developed		55.5	%		50.9	%		43.4	%

(1) 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.

(2) Data for December 31, 2012 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 $94.71 per Bbl for oil and (b) Henry Hub spot market prices for the prior 12 months of $2.76 per MMbtu for natural gas.

(3) Data for December 31, 2011 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 $96.19 per Bbl for oil and (b) Henry Hub spot market prices for the prior 12 months of $4.12 per MMbtu for natural gas.

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, Miller and Lents, independent reserve engineers, estimated 100% of proved reserve information associated with the Sabine O&G Properties as of December 31, 2011 and as of December 31, 2012, and Ryder Scott, independent reserve engineers, estimated 100% of the proved reserve information of the Sabine O&G Properties as of December 31, 2013. 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 its proved reserves relating to its 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.

The preparation of proved reserve estimates for the Sabine O&G Properties were completed in accordance with Sabine O&G’s internal control procedures. These 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 Senior Vice President—Engineering and Development or under her direct supervision;

• review by our Senior Vice President—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 Senior Vice President—Engineering to our Chief Executive Officer; and

• verification of property ownership by our land department.

Cheryl R. Levesque, Senior Vice President, Asset Development, is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mrs. Levesque is a graduate of Texas Tech University with a Bachelor of Science degree in Petroleum Engineering and is a Registered Professional Engineer in Texas. Mrs. Levesque has 18 years of energy experience and Sabine O&G’s geoscience staff has an average of more than 18 years of industry experience per person.

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.

To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineers, Miller and Lents and 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, 2013

As of December 31, 2013, proved undeveloped reserves associated with the Sabine O&G Properties totaled 11 MMBbls of oil, 13 MMBbls of NGLs and 228 Bcf of natural gas, for a total of 373 Bcfe. There were a total of 100 PUD’s booked with 50, 27, 19 and 4 wells booked in the Eagle Ford, Cotton Valley Sand, Granite Wash and Haynesville Shale, respectively. This total represents less than two years of inventory at year-end rig count and is indicative of our conservative PUD booking methodology.

Changes in PUDs that occurred during 2013 were primarily due to:

• additions of 87,861 MMcfe attributable to extensions resulting from strategic drilling of wells by Sabine O&G to delineate Sabine O&G’s acreage position;

• the conversion of approximately 48,478 MMcfe attributable to PUDs into proved developed reserves;

• negative revisions of approximately 82,089 MMcfe due to the reduction of booked Cotton Valley Sand inventory from 47 locations to 27 locations, or three years of drilling activity at Sabine O&G’s current level of one rig;

• positive revisions of approximately 35,675 MMcfe in PUDs due to a combination of adjustments in working interest, performance revisions and pricing; and

• sales of reserves in place of 101,269 MMcfe.

Costs incurred relating to the development of PUDs were approximately $112.3 million during the twelve months ended December 31, 2013.

As of December 31, 2013, 2.2% of total proved reserves associated with the Sabine O&G Properties were classified as proved developed non-producing.

Productive Wells

The principal Sabine O&G Properties consist of developed and undeveloped oil and natural gas leases in the operating areas described above and the reserves associated with these leases. Generally, developed oil and natural gas leases remain in force as long as 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 undeveloped leases associated with the Sabine O&G Properties 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 in which Sabine O&G owned a working interest at December 31, 2013. Productive wells consist of producing wells identified as proved developed producing (“PDP”) per the December 31, 2013 reserve report prepared by Ryder Scott. Gross wells are the total number of productive wells in which Sabine O&G has working interests, and net wells are the sum of Sabine O&G’s fractional working interests owned in gross wells. Approximately 58% of future net revenue associated with the Sabine O&G Properties is from natural gas while the remaining 42% is from oil and NGLs.

	Gross		Net
East Texas		822		621
South Texas		22		17
North Texas		20		9
Total		864		647

Drilling Activities

The table below sets forth the results of drilling activities associated with the Sabine O&G Properties 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 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,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive(1)(2)		2.0		1.3		3.0		2.5		—		—
Dry		—		—		—		—		—		—
Total Exploratory		2.0		1.3		3.0		2.5		—		—
Development Wells:
Productive(1)(2)		43.0		30.8		7.0		7.0		21.0		21.0
Dry		1.0		0.4		—		—		—		—
Total Development		44.0		31.2		7.0		7.0		21.0		21.0
Total Wells:
Productive(1)(2)		45.0		32.1		10.0		9.5		21.0		21.0
Dry		1.0		0.4		—		—		—		—
Total		46.0		32.5		10.0		9.5		21.0		21.0

(1) 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.

(2) As of September 30, 2014, Sabine O&G had completed 60 wells (44.69 net).

Developed and Undeveloped Acreage

The Sabine O&G 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 acreage interests associated with the Sabine O&G Properties as of December 31, 2013:

	Developed acreage				Undeveloped acreage				Total acreage				HBP
	Gross		Net		Gross		Net		Gross		Net		%
East Texas(1)		106,002		89,162		25,092		14,820		131,094		103,982		95	%
South Texas		12,576		9,276		29,467		24,567		42,044		33,844		27	%
North Texas		9,124		5,183		41,979		28,354		51,103		33,537		15	%
Total Acreage		127,702		103,621		96,538		67,741		224,241		171,363		61	%

(1) The East Texas acreage excludes 81,060 gross and 71,291 net acres outside of the Haynesville Shale and Cotton Valley Sand, which is considered non-core acreage.

The Sabine O&G Properties’ 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.

Undeveloped Acreage Expirations

The following table sets forth the number of total net undeveloped acres as of December 31, 2013 that will expire in 2014, 2015, 2016 and 2017 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. Such acreage is not associated with proved undeveloped reserves.

	2014		2015		2016		2017
East Texas(1)		2,571		739		1,942		0
South Texas		5,016		6,914		3,860		0
North Texas		14,543		4,091		0		0
Total		22,130		11,744		5,802		0

(1) The acreage expiration in East Texas excludes approximately 71,000 net acres prospective for other formations, all of which expire by the end of 2015.

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 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 expects that volatility to continue in the future. A substantial or extended decline in natural gas or oil prices or poor drilling results could have a material adverse effect on Sabine O&G’s financial position, results of operations, cash flows, quantities of reserves that may be economically produced and its ability to access capital markets.

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, 2013, 2012 and 2011. For additional information on price calculations, see information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Sabine Oil & Gas Corporation.”

	For the Years Ended December 31,
	2013		2012			2011
Oil, NGLs and natural gas sales by product (in thousands):
Oil	$	132,513	$	30,343		$	15,462
NGL		59,772		36,957			36,272
Natural gas		161,938		110,122	(3)		149,687	(3)
Total	$	354,223	$	177,422	(3)	$	201,421	(3)
Production data:
Oil (MBbl)		1,403.62		317.07			170.52
NGL (MBbl))		1,842.47		931.26			704.44
Natural gas (Bcf)		44.29		41.12			38.94
Combined (Bcfe)(1)		63.77		48.61			44.20
Average prices before effects of economic hedges(2):
Oil (per Bbl)	$	94.41	$	95.70		$	90.68
NGL (per Bbl)	$	32.44	$	39.68		$	51.49
Natural gas (per Mcf)	$	3.66	$	2.68	(3)	$	3.84	(3)
Combined (per Mcfe)(1)	$	5.55	$	3.65	(3)	$	4.56	(3)
Average realized prices after effects of economic hedges(2):
Oil (per Bbl)	$	90.59	$	95.79		$	90.68
NGL (per Bbl)	$	32.44	$	39.68		$	51.49
Natural gas (per Mcf)	$	4.82	$	5.23	(3)	$	5.66	(3)
Combined (per Mcfe)(1)	$	6.28	$	5.81	(3)	$	6.16	(3)
Average costs (per Mcfe)(1):
Lease operating expenses	$	0.67	$	0.84		$	0.61
Workover expense	$	0.03	$	0.05		$	0.07
Marketing, gathering, transportation and other	$	0.28	$	0.36	(3)	$	0.37	(3)
Production and ad valorem taxes	$	0.28	$	0.09		$	0.18
General and administrative expenses	$	0.43	$	0.44		$	0.53
Depletion, depreciation and amortization	$	2.15	$	1.88	(3)	$	1.71	(3)

(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 Sabine O&G’s realized commodity derivative transactions. Sabine O&G’s calculation of such effects includes realized gains or losses on cash settlements for commodity derivative transactions.

(3) Revised for the effects of the restatement. Refer to Note 2 of Sabine O&G’s consolidated financial statements located in this Current Report on Form 8-K.

Estimated Proved Reserves Associated with the Old Forest Properties

The following table summarizes estimated quantities of proved reserves associated with the Old Forest Properties as of December 31, 2013, all of which are located in the United States, based on the NYMEX Henry Hub (“HH”) price of $3.67 per MMBtu for natural gas and the NYMEX West Texas Intermediate (“WTI”) price of $97.33 per barrel for oil, each of which represents the unweighted arithmetic average of the first-day-of-the-month prices during the twelve-month period prior to December 31, 2013. See “—Preparation of Reserves Estimates Associated with the Old Forest Properties” below and Note 14 to the Consolidated Financial Statements for additional information regarding estimated proved reserves associated with the Old Forest Properties.

	Estimated Proved Reserves
	Natural Gas (MMcf)		Oil (MBbls)		Natural Gas Liquids (MBbls)		Total (MMcfe)(1)
Developed		336,342		6,151		6,855		414,378
Undeveloped		118,249		10,523		4,856		210,523
Total estimated proved reserves		454,591		16,674		11,711		624,901

(1) Oil and natural gas liquids are converted to gas- equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. This conversion is based on energy equivalence and not price equivalence. For 2013, the average of the first-day-of-the-month natural gas price was $3.67 per Mcf, and the average of the first-day-of-the-month oil price was $97.33 per barrel. If a price-equivalent conversion based on these twelve-month average prices was used, the conversion factor would be approximately 27 Mcf per barrel of oil and approximately 10 Mcf per barrel of NGLs (based on the average of the first-day-of-the-month Mt. Belvieu pricing for NGLs in 2013).

As of December 31, 2013, estimated proved reserves associated with the Old Forest Properties consisted of 625 Bcfe, a decrease of 54% compared to 1,363 Bcfe of estimated proved reserves at December 31, 2012. During 2013, Old Forest added 148 Bcfe of estimated proved reserves through extensions and discoveries primarily driven by its 2013 drilling activity in the Eagle Ford in South Texas and Cotton Valley in East Texas. These reserve additions were offset by property sales of 800 Bcfe and net negative revisions of 10 Bcfe. The net negative revisions of 10 Bcfe were comprised of (i) the reclassification of 41 Bcfe of proved undeveloped reserves (“PUDs”) to probable undeveloped reserves for PUDs that are not expected to be developed five years from the time the reserves were initially disclosed, (ii) negative performance revisions of 9 Bcfe, and (iii) positive pricing revisions of 40 Bcfe.

As of December 31, 2013, estimated proved undeveloped reserves associated with the Old Forest Properties consisted of 211 Bcfe, or 34% of estimated proved reserves, compared to 425 Bcfe, or 31% of estimated proved reserves as of December 31, 2012. The net decrease of 215 Bcfe was primarily due to property sales including 286 Bcfe of proved undeveloped reserves. During 2013, Old Forest invested $75 million to convert 22 Bcfe of its December 31, 2012 PUDs to proved developed reserves. The rate at which Old Forest convert PUDs to proved developed reserves has been negatively impacted in the last several years due to its transition away from developing natural gas reserves, many of which were reclassified to probable reserves in the last several years, and towards the development of oil reserves. In connection with this transition, Old Forest drilled a high percentage of non-proved locations in an effort to hold leases that would otherwise be lost if instead Old Forest were to drill proved undeveloped locations that are on leases already held by producing wells. This trend continued throughout 2013. As of December 31, 2013, Old Forest had no PUDs that had remained undeveloped for five years or more after they were initially disclosed as PUDs.

Preparation of Reserves Estimates Associated with the Old Forest Properties

Reserves estimates associated with the Old Forest Properties included in this Current Report on Form 8-K were prepared by Old Forest’s internal staff of engineers with significant consultation with internal geologists and geophysicists. The reserves estimates are based on production performance and data acquired remotely or in wells, and are guided by petrophysical, geologic, geophysical, and reservoir engineering models. Access to the database housing reserves information was restricted to select individuals from Old Forest’s engineering department. Moreover, new reserves estimates and significant changes to existing reserves were reviewed and approved by various levels of management, depending on their magnitude. Proved reserves estimates were reviewed and approved by the Senior Vice President, Corporate Engineering and Technology, and at least 80% of Old Forest’s proved reserves, based on net present value, are audited by independent reserve engineers (see “—Independent Audit of Reserves Associated with the Old Forest Properties” below) prior to review by the Audit Committee. In connection with its review, the Audit Committee met privately with personnel from DeGolyer and MacNaughton, the independent petroleum engineering firm that audited Old Forest’s reserves, to confirm that DeGolyer and MacNaughton had not identified any concerns or issues relating to the audit and maintained independence. In addition, Old Forest’s internal audit department randomly selected a sample of new reserves estimates or changes made to existing reserves and tests to ensure that they were properly documented and approved.

Old Forest’s Senior Vice President, Corporate Engineering and Technology, who held this position since January 2013, has 36 years of experience in oil and gas exploration and production and received a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. Prior to January 2013, he held positions of increasing responsibility at Old Forest since joining the company in 2001, including most recently Vice President, Corporate Engineering, a position in which he was also primarily responsible for overseeing the preparation of reserves estimates. Prior to joining Old Forest, he held various positions in reservoir engineering and corporate planning with Phillips Petroleum, Midcon Exploration, and Apache Corporation.

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond Old Forest’s control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil, natural gas liquids, and natural gas that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality of

available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing, and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development and production expenses, may require revision of such estimates. Accordingly, oil, natural gas liquids, and natural gas quantities ultimately recovered will vary from reserves estimates.

Independent Audit of Reserves associated with the Old Forest Properties

Old Forest engaged independent reserve engineers to audit a substantial portion of the reserves associated with the Old Forest Properties. Old Forest’s audit procedures historically required the independent engineers to prepare their own estimates of proved reserves for fields comprising at least 80% of the aggregate net present value, discounted at 10% per annum (“NPV”), of year-end proved reserves associated with the Old Forest Properties. The fields selected for audit also must have comprised at least 80% of Old Forest’s fields based on the NPV of such fields and a minimum of 80% of the NPV added during the year through discoveries, extensions, and acquisitions. The procedures prohibited exclusions of any fields, or any part of a field that comprised part of the top 80%. The independent reserve engineers compared their own estimates to those prepared by Old Forest. Old Forest’s audit guidelines required its internal estimates, which were used for financial reporting and disclosure purposes, to be within 5% of the independent reserve engineers’ quantity estimates. The independent reserve audit was conducted based on reserve definition and cost and price parameters specified by the SEC.

For the years ended December 31, 2013, 2012, and 2011, Old Forest engaged DeGolyer and MacNaughton, an independent petroleum engineering firm, to perform reserve audit services. For the year ended December 31, 2013, DeGolyer and MacNaughton independently audited estimates relating to properties constituting over 87% of the reserves associated with the Old Forest Properties by NPV as of December 31, 2013. When compared on a field-by-field basis, some of Old Forest’s estimates of proved reserves associated with the Old Forest Properties were greater and some were less than the estimates prepared by DeGolyer and MacNaughton. However, in the aggregate, Old Forest’s estimates of total proved reserves associated with the Old Forest Properties were within 3% of DeGolyer and MacNaughton’s aggregate estimate of proved reserves quantities for the fields audited. The lead technical person at DeGolyer and MacNaughton primarily responsible for overseeing the audit of Old Forest’s reserves received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University, is a Registered Professional Engineer in the State of Texas, is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists, and has 39 years of experience in oil and gas reservoir studies and reserves evaluations.

Drilling Activities

The following table summarizes the number of wells drilled during 2013, 2012, and 2011 with respect to the Old Forest Properties, all of which are located in the United States, excluding any wells drilled under farmout agreements, royalty interest ownership, or any other wells in which Old Forest does not have a working interest. As of December 31, 2013, the Old Forest Properties included 9 gross (5 net) wells in progress, all of which are located in the United States. During 2013, a total of 93 gross (45 net) wells associated with the Old Forest Properties were drilled, of which 41 were classified as exploratory and 52 were classified as development.

	Year Ended December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development wells:
Productive(1)		52		23		106		49		101		44
Non-productive(2)		—		—		3		1		—		—
Total development wells		52		23		109		50		101		44
Exploratory wells:
Productive(1)		40		21		27		24		22		21
Non-productive(2)		1		1		3		3		4		3
Total exploratory wells		41		22		30		27		26		24

(1) A well classified as productive does not always provide economic levels of production.

(2) A non-productive well is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well; also known as a dry well (or dry hole).

Oil and Natural Gas Wells and Acreage

Productive Wells

The following table summarizes productive wells associated with the Old Forest Properties as of December 31, 2013, all of which are located in the United States. Productive wells consist of producing wells and wells capable of production, including shut-in wells. A well bore with multiple completions is counted as only one well. As of December 31, 2013, the Old Forest Properties included ownership of interests in 40 gross wells containing multiple completions.

	Gross		Net
Natural Gas		1,432		1,001
Oil		93		68
Total		1,525		1,069

Acreage

The following table summarizes developed and undeveloped acreage associated with the Old Forest Properties in which Old Forest owned a working interest or held an exploration license as of December 31, 2013. A substantial majority of developed acreage associated with the Old Forest Properties is subject to mortgage liens securing its bank credit facility. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this summary, as well as acreage related to any options held by Old Forest to acquire additional leasehold interests. At December 31, 2013, approximately 36%, 30%, and 16% of net undeveloped acreage associated with the Old Forest Properties in the United States was held under leases that will expire in 2014, 2015, and 2016, respectively, if not extended by exploration or production activities.

	Developed Acreage				Undeveloped Acreage
	Gross		Net		Gross		Net
Location
United States(1)		239,089		159,927		189,999		121,008
South Africa(2)		—		—		1,235,500		657,286
Italy		—		—		107,043		86,507
Total		239,089		159,927		1,532,542		864,801

(1) Concentrations of net acres in the United States as of December 31, 2013 include: 162,000 net acres in Ark-La-Tex in East Texas, Louisiana, and Arkansas; 24,500 net acres in Eagle Ford; and 63,500 net acres in Permian Basin in West Texas.

(2) In December 2012, Old Forest entered into agreements to dispose of Old Forest’s interests in the Block 2A Production Right and the Block 2C Exploration Right in South Africa. The abandonment of the Block 2C Exploration Right was completed in December 2013, with Old Forest receiving $9 million. The disposal of Old Forest’s interest in the Block 2A Production Right is contingent upon the approval of the government of South Africa, which has not yet occurred. Upon the completion of this transaction, if it occurs, Old Forest will no longer hold any acreage in South Africa.

Production, Average Sales Prices, and Production Costs

The following table reflects production, average sales price, and production cost information for the years ended December 31, 2013, 2012, and 2011 for continuing operations associated with the Old Forest Properties. All production associated with the Old Forest Properties occurred in the United States for the years presented and the Old Forest Properties did not include any fields that individually contain 15% or more of its total estimated proved reserves.

	Year Ended December 31,
	2013		2012		2011
Liquids:
Oil and condensate:
Production volumes (MBbls)		2,271		3,146		2,491
Average sales price (per Bbl)	$	96.30	$	96.14	$	96.22
Natural gas liquids:
Production volumes (MBbls)		2,521		3,489		3,154
Average sales price (per Bbl)	$	29.79	$	31.77	$	42.91
Total liquids:
Production volumes (MBbls)		4,792		6,635		5,645
Average sales price (per Bbl)	$	61.31	$	62.29	$	66.43
Natural Gas:
Production volumes (MMcf)		46,676		81,008		88,497
Average sales price (per Mcf)	$	3.16	$	2.37	$	3.71
Total production volumes (MMcfe)(1)		75,428		120,818		122,367
Average sales price (per Mcfe)	$	5.85	$	5.01	$	5.75
Production costs (per Mcfe):
Lease operating expenses	$	1.02	$	.89	$	.81
Transportation and processing costs		.16		.12		.11
Production costs excluding production and property taxes (per Mcfe)		1.17		1.02		.92
Production and property taxes		.20		.28		.33
Total production costs (per Mcfe)	$	1.37	$	1.30	$	1.25

(1) Oil and natural gas liquids are converted to gas- equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. This conversion is based on energy equivalence and not price equivalence. For 2013, the average of the first-day-of- the-month natural gas price was $3.67 per Mcf, and the average of the first-day-of-the-month oil price was $97.33 per barrel. If a price-equivalent conversion based on these twelve-month average prices was used, the conversion factor would be approximately 27 Mcf per barrel of oil and approximately 10 Mcf per barrel of NGLs (based on the average of the first- day-of-the-month Mt. Belvieu pricing for NGLs in 2013).

Risk Management of Sabine O&G

Sabine O&G has designed a risk management policy 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 Sabine O&G’s operations and its ability to finance its capital budget and operations. Sabine O&G’s decision on the quantity and price at which it chooses to hedge its production is based on its 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, Sabine O&G typically uses 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, Sabine O&G may pay a fixed premium to increase the floor price above the existing market value at the time it enters into the arrangement. All collar agreements provide for payments to 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, Sabine O&G has 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 Sabine (purchased) has the option to sell a contracted volume of the commodity at a contracted price on a contracted date in future.

Sabine O&G enters into derivatives arrangements only with counterparties within the $750 million senior secured revolving credit facility with Wells Fargo as the administrative agent (as amended, the “Legacy Sabine O&G Credit Facility”). banking group that it believes are creditworthy, as these arrangements expose Sabine O&G to the risk of financial loss if Sabine O&G’s counterparty is unable to satisfy its obligations. The Legacy Sabine O&G Credit Facility allows it 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 Sabine O&G’s latest monthly production total. For additional information on Sabine’s hedging position, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations of Sabine Oil & Gas Corporation—Commodity Hedging Activities.”

Competitive Conditions in the Business

The oil and natural gas industry is highly competitive and Sabine competes with a substantial number of other companies that have greater financial and other resources than Sabine does. 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 Sabine encounters substantial competition are in locating and acquiring desirable leasehold acreage for its 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 Sabine produces and hiring and

retaining key employees. Sabine’s larger competitors may be able to pay more for productive natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than Sabine’s 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 natural gas market prices.

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 Sabine operates. It is not possible to predict the nature of any such legislation or regulation which may ultimately be adopted or its effects upon Sabine’s 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. Sabine’s 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 it can, which would adversely affect Sabine’s competitive position.

Marketing and Significant Customers

Sabine O&G

Sabine markets the majority of the natural gas production from properties it operates for both its account and the account of the other working interest owners in these properties.

In East Texas, Sabine sells approximately half of its production under three to five year gathering and purchase contracts to a variety of midstream companies. The remainder of Sabine’s production is sold under short-term contracts or spot gas purchase contracts ranging anywhere from one month to one year terms at competitive market prices. In East Texas, Sabine’s oil is sold to one purchaser under a short-term contract which is month to month.

In South Texas, Sabine sells its production under either short-term contracts or spot gas purchase contracts which are on a month to month term. In South Texas, Sabine’s oil is sold to various purchasers under short-term contracts which are month to month.

In North Texas, Sabine sells its production under a long-term contract, to one midstream company, through an acreage dedication. Sabine’s oil is sold under a three year contract which allows it to offtake to a dedicated last unit.

During the year ended December 31, 2013, purchases by three companies exceeded 10% of the total oil, NGLs and natural gas sales of the Company. Purchases by Eastex Crude Company, Enbridge Pipeline (East Texas) LP and CP Energy LLC accounted for approximately 19%, 16% and 11% of oil, NGLs and natural gas sales, respectively. During the year ended December 31, 2012, purchases by four companies exceeded 10% of the total oil, NGLs and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP, Shell Trading (US) Company, Texla Energy Management LLC and Eastex Crude Company accounted for approximately 17%, 14%, 13% and 12% of oil, NGLs and natural gas sales, respectively. The Company believes that the loss of any of the purchasers above would not result in a material adverse effect on its ability to competitively market future oil and natural gas production. During the year ended December 31, 2011, purchases by three companies exceeded 10% of the total oil, NGLs and natural gas sales of the Company. Purchases by Enbridge Pipeline (East Texas) LP, Texla Energy Management LLC and PVR Midstream LLC accounted for approximately 18%, 15% and 13% of oil, NGLs and natural gas sales, respectively.

Old Forest

Old Forest’s natural gas production is generally sold on a month-to-month basis in the spot market, priced in reference to published indices. Old Forest’s oil production is generally sold under short-term contracts at prices based upon refinery postings or NYMEX WTI monthly averages and is typically sold at the wellhead. Old Forest’s natural gas liquids production is typically sold under term agreements at prices based on postings at large fractionation facilities. Old Forest believes that the loss of one or more of our current oil, natural gas, or natural gas liquids purchasers would not have a material adverse effect on its ability to sell its production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption. Old Forest had no material delivery commitments as of February 19, 2014.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas and can also delay drilling activities, disrupting Sabine’s 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

Sabine’s 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 Sabine owns or operates 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. Sabine’s 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 Sabine believes it is in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, Sabine is 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. Sabine cannot predict when or whether any such proposals may become effective.

Sabine believes that continued substantial compliance with existing requirements will not have a material adverse effect on Sabine’s 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 Sabine owns and operates 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 Sabine can produce from its wells and to limit the number of wells or the locations at which it can drill, although Sabine 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. Sabine’s competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect its operations.

Regulation of Transportation of Oil

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

Sabine’s 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. The 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, the 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, the 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, Sabine believes that the regulation of oil transportation rates will not affect its operations in any way that is of material difference from those of its 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, Sabine believes that access to oil pipeline transportation services generally will be available to it to the same extent as to its similarly situated competitors.

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 Sabine produces, as well as the revenues it receives for sales of its 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 (the “NGPA”) 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.

Sabine cannot accurately predict how FERC’s actions will impact competition in markets in which Sabine’s 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, Sabine 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, Sabine does not believe that any action taken will affect it in a way that materially differs from the way it affects other natural gas producers.

The price at which Sabine sells 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 its physical sales of energy commodities, Sabine is required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC and the Federal Trade Commission (the “FTC”). Should Sabine violate the anti-market manipulation laws and regulations, it 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 the FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, the 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, Sabine believes that the regulation of similarly situated intrastate natural gas

transportation in any states in which it operates and ships natural gas on an intrastate basis will not affect its operations in any way that is of material difference from those of its competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that Sabine produces, as well as the revenues it receives for sales of its natural gas.

Environmental Regulation

Sabine’s operations are subject to stringent federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to health and safety or the protection of the environment. Numerous governmental agencies, such as the EPA, 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 Sabine’s 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 Sabine’s cost of doing business and consequently affects its profitability.

Environmental regulatory programs typically regulate the permitting, construction and operations of a facility. Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit. Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent. Under appropriate circumstances, an administrative agency can request a cease and desist order to terminate operations. New programs and changes in existing programs are anticipated, some of which include 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 Sabine’s financial condition and results of operations.

The following is a summary of the more significant existing environmental and occupational health and safety laws, as amended from time to time, to which Sabine’s business operations are subject and for which compliance may have a material adverse impact on Sabine’s 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 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, 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 federal laws. However, it is possible that certain oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in Sabine’s costs to manage and dispose of generated wastes, which could have a material adverse effect on Sabine’s results of operations and financial position. In addition, in the course of Sabine’s operations, it generates 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 a “hazardous substance” into the environment. These persons 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. Sabine generates materials in the course of its operations that may be regulated as hazardous substances.

Sabine currently owns, leases, or operates numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although Sabine believes that it has 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 Sabine, 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 Sabine’s 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 Sabine’s 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, Sabine 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

Sabine’s operations are also subject to the Clean Water Act (the “CWA”) and analogous state laws. The CWA and similar state acts regulate discharges of wastewater, oil, and other pollutants to 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 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. Sabine believes that it will be able to obtain, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on Sabine.

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. Sabine engages third parties to provide hydraulic fracturing or other well stimulation services to it in connection with many of the wells for which Sabine is the operator. 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 federal Safe Drinking Water Act (“SDWA”) involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. Also, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. In addition, in May 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 would continue to require 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.

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, with draft and final reports drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available by late 2014 and 2016, respectively. Moreover, the EPA has announced that it will develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by late 2014. 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 SDWA and the Underground Injection Control (the “UIC”) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. Sabine routinely uses such wells for the disposal of flowback and produced water resulting from its operations. EPA directly administers the UIC program in some states and in others it is delegated to the state for administering. 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.

Several states have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas requires oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. Regulations require that well operators disclose the list of chemical ingredients subject to the requirements of the Occupational Safety and Health Act, as amended (“OSHA”) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission (the “TRC”) with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the TRC. Furthermore, in May 2013, the TRC issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The “well integrity rule” took effect in January 2014. Sabine believes that it follows applicable standard industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Sabine operates, it could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

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. Sabine’s operations, or the operations of service companies engaged by it, may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants.

Over the next several years, Sabine 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 to be “remote” under the rule. Sabine’s operations are in substantial compliance with the requirements of this rule.

In addition, in August 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regards to production activities, these final rules require, among other things, the reduction of 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. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. The EPA published a rule in September 2013 extending the compliance date for controlling regulated emissions from certain storage vessels. Compliance with these requirements could increase Sabine’s costs of development and production, which costs could be significant.

Climate Change Legislation and Greenhouse Gas Regulation

In December 2009, the EPA published its findings 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 adopted regulations under existing provisions of the CAA that establish Prevention of Significant Deterioration (“PSD”) and Title V permit reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also 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 Sabine’s operations. In addition, as noted above, in August 2012, the EPA established new source performance standards for VOCs and sulfur dioxide and an air toxic standard for oil and natural gas production, transmission, and storage.

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. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. In any event, the Obama administration recently announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and natural gas agency. As part of the Climate Action Plan, the Obama Administration also announced that it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies in the coming years. 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 Sabine’s business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from Sabine’s equipment and operations could require Sabine to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with Sabine’s operations, and such requirements also could adversely affect demand for the oil and natural gas that it produces. 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 Sabine’s financial condition and results of operations.

Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require Sabine to incur additional operating costs, such as costs to purchase and operate emissions control systems, and additional compliance costs. Such laws and regulations could also result in reduced demand for oil and natural gas, decreasing the need for Sabine’s services, which could result in an adverse effect on Sabine’s 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 migratory birds. The U.S. Fish and Wildlife Service (“FWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered 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 Sabine to incur increased costs arising from species protection measures or could result in limitations on Sabine’s exploration and production activities that could have an adverse impact on Sabine’s ability to develop and produce reserves.

OSHA

Sabine is subject to the requirements of 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 Sabine organizes and/or discloses information about hazardous materials used or produced in Sabine’s operations and that this information be provided to employees, state and local governmental authorities and citizens. Sabine believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Related Permits and Authorizations

Many environmental laws require Sabine 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 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.

Related Insurance

Sabine maintains an insurance program designed to provide coverage for the Company’s property and casualty exposures. Sabine’s 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, Sabine does not insure fully against all risks associated with its business either because such insurance is not available or because Sabine believes the premium costs are prohibitive. A loss not fully covered by insurance could have a materially adverse effect on Sabine’s financial position and results of operations. There can be no assurance that the insurance coverage that Sabine maintains will be sufficient to cover every claim made against it in the future. As hydraulic fracturing is a key component of Sabine’s operational strategy, Sabine maintains Claims Made Pollution Liability Insurance, which provides coverage for long-term gradual seepage pollution events. A loss in connection with Sabine’s oil and natural gas operations could have a material adverse effect on Sabine’s financial position and results of operations to the extent that the insurance coverage provided under Sabine’s policies is inadequate to cover any such loss.

Employees

As of December 31, 2013, Sabine O&G had 136 full-time employees. Sabine hires independent contractors on an as needed basis. Sabine has no collective bargaining agreements with its employees. Sabine believes that its employee relationships are satisfactory.

As of December 31, 2013, Old Forest had 363 employees. As of September 30, 2014, Old Forest had 185 employees. None of Old Forest’s employees is currently represented by a union for collective bargaining purposes.

Legal Proceedings

Sabine

Sabine is party to lawsuits arising in the ordinary course of Sabine’s business. Sabine cannot predict the outcome of any such lawsuits with certainty, but its management team does not expect the outcome of pending or threatened legal matters to have a material adverse impact on its financial condition.

Old Forest

On March 26, 2014, the judge overseeing the lawsuit styled Augenbaum v. Lone Pine Resources Inc. et al., granted defendants’ motion to dismiss, with prejudice, for failure to state a claim upon which relief may be granted. The original claim was brought on May 25, 2012, as a purported class action in the Supreme Court of the State of New York, New York County against Forest Oil Corporation, 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 Oil Corporation under Section 15 of the Securities Act, alleging that Forest Oil Corporation 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. Lone Pine’s obligation to indemnify Forest, the Individual Defendants, and the Underwriter Defendants, was extinguished in Lone Pine’s bankruptcy proceedings. Plaintiffs appealed the decision on April 28, 2014, and briefing was completed on August 5, 2014, and appellate briefs have been submitted. A date for oral arguments has not yet been set.

On November 11, 2013, Jefferson Parish and the State of Louisiana filed suit against Forest Oil Corporation 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 tendered a claim for indemnity to Texas Petroleum Investment Company (“TPIC’), which TPIC rejected. Forest 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 been on hold pending the court’s decision regarding federal jurisdiction in a similar lawsuit. That lawsuit was recently remanded to Louisiana state court, so the parties have filed a motion to reopen this case and set a status conference. Plaintiffs seek unspecified monetary damages and restoration of the Jefferson Parish Coastal Zone to its original condition. This matter is in the very early stages of litigation.

On November 8, 2013, Plaquemines Parish and the State of Louisiana filed suit against Forest Oil Corporation 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 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. A 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 in the very early stages of litigation.

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest Oil Corporation 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 Oil Corporation 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 Oil Corporation, the trial court for the 55th Judicial District, in the District Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest Oil Corporation appealed the judgment to the Court of Appeals for the First District of the State of Texas. The judgment was affirmed on July 24, 2014. Forest Oil Corporation is now seeking a rehearing before the Court of Appeals and, failing that, will seek to have the judgment reversed at the Supreme Court for the State of Texas.

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. Forest Oil Corporation believes that the amount of any potential loss associated with these proceedings would not be material to Forest Oil Corporation’s consolidated financial position; however, in the event of an unfavorable outcome, the potential loss could have an adverse effect on Forest Oil Corporation’s results of operations and cash flow.