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:

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:

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:

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:

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:

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.

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

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:

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:

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.

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.

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:

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.

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.”

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.

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.

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.

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.

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.

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.