Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________________________________

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934

For the fiscal year ended December 31, 2012

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the transition period from to 

Commission File Number: 1-13515

____________________________________________________________________________

FOREST OIL CORPORATION

(Exact name of registrant as specified in its charter)

State of incorporation: New York I.R.S. Employer Identification No. 25-0484900

707 17th Street, Suite 3600, Denver, Colorado 80202

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (303) 812-1400

Securities registered pursuant to Section 12(b) of the Act:

Title of each class Name of each exchange on which registered

Common Stock, Par Value $.10 Per Share New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

____________________________________________________________________________

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the

preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past

90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be

submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was

required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be

contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this

Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of

“large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer o

Non-accelerated filer o

(Do not check if a smaller

reporting company) Smaller reporting company o

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

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 29, 2012, the last business day of the registrant’s most recently

completed second fiscal quarter, was $857,155,481 (based on the closing price of such stock).

There were 119,353,202 shares of the registrant’s common stock, par value $.10 per share, outstanding as of February 19, 2013.

Documents incorporated by reference: Portions of the registrant’s notice of annual meeting of shareholders and proxy statement to be filed pursuant to Regulation 14A

within 120 days after the registrant’s fiscal year end of December 31, 2012 are incorporated by reference into Part III of this Form 10-K.
Table of Contents

TABLE OF CONTENTS

Page No.

PART I

Item 1. Business 1

Item 1A. Risk Factors 17

Item 1B. Unresolved Staff Comments 24

Item 2. Properties 24

Item 3. Legal Proceedings 24

Item 4. Mine Safety Disclosures 24

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 25

Item 6. Selected Financial Data 28

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 29

Item 7A. Quantitative and Qualitative Disclosures about Market Risk 48

Item 8. Financial Statements and Supplementary Data 52

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 113

Item 9A. Controls and Procedures 113

Item 9B. Other Information 113

PART III

Item 10. Directors, Executive Officers and Corporate Governance 115

Item 11. Executive Compensation 116

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 116

Item 13. Certain Relationships and Related Transactions, and Director Independence 116

Item 14. Principal Accounting Fees and Services 116

PART IV

Item 15. Exhibits, Financial Statement Schedules 117

Signatures 125

i
Table of Contents

PART I

Item 1. Business.

General

Throughout this Annual Report on Form 10-K, we use the terms “Forest,” “Company,” “we,” “our,” and “us” to refer to Forest Oil Corporation and

its subsidiaries. In the following discussion, we make statements that may be deemed “forward-looking” statements within the meaning of Section 27A of the

Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). See

“Forward-Looking Statements,” below, for more details. We also use a number of terms used in the oil and gas industry. See “Glossary of Oil and Gas Terms”

for the definition of certain terms.

Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural

gas liquids (“NGL”) primarily in North America. Forest 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. Forest’s total estimated proved oil and gas reserves as of December 31, 2012 were approximately 1,363 Bcfe, all of

which are located in the United States.

Strategy

Forest’s long-term operating strategy strives to increase shareholder value through the achievement of economic growth by developing our core

operational areas located in the Texas Panhandle Area, the Eagle Ford Shale in South Texas, and the East Texas / North Louisiana Area. In addition, our

growth may be supplemented from time to time through opportunistic acquisitions. We endeavor to execute this strategy as follows:

Exploit and develop our oil and gas assets for economic growth while maintaining a capital expenditure budget that approximates cash

flows from operating activities. In our efforts to build shareholder value, we plan to continue to apply advanced drilling and completion technologies when

developing our oil and gas assets, including horizontal drilling and multi-stage hydraulic fracture stimulation techniques. We believe these technologies are

critical to our efforts to provide capital-efficient growth from our diverse portfolio of shale, unconventional, and conventional oil and natural gas properties.

Our core operational areas have a large number of commodity-diverse drilling locations identified. In 2012, due to a low natural gas price environment, we

devoted the majority of our capital expenditures to oil and natural gas liquids projects, including approximately 40% in the Texas Panhandle Area and 30% in

the Eagle Ford Shale. We developed our original 2012 capital expenditure budget using natural gas pricing assumptions that were higher than the actual prices

we realized during 2012. As a result, our capital expenditures exceeded cash flows in 2012. However, we meaningfully reduced our drilling program from nine

rigs to five rigs in the second half of 2012 and our capital expenditures now more closely approximate our cash flows. In 2013, we expect to maintain our

capital expenditures within a reasonable range of our expected cash flows based on the current commodity price environment.

As the graph below depicts (see “Recent Trends and 2013 Outlook”), natural gas prices have become substantially disconnected from oil prices and

trade significantly below the energy-equivalent conversion of six Mcf “equivalents” per barrel of oil or natural gas liquids. For example, during 2012, the

average of the first-day-of-the-month NYMEX gas price was $2.76 per Mcf, and the average of the first-day-of-the-month NYMEX oil price was $94.79 per

barrel. Based on these prices, if a price-equivalent conversion was used, the conversion factor would be approximately 34 Mcf per barrel of oil and

approximately 16 Mcf per barrel of NGLs. Over the last ten years, this price-equivalent ratio has averaged approximately 15 Mcf per barrel of oil and

approximately 7.5 Mcf per barrel of NGLs. While our total net sales volumes declined in 2012 as compared to 2011 using the energy-equivalent ratio, our

2012 net sales volumes have grown in excess of 3% compared to 2011 using the more relevant ten-year average price-equivalent conversion factor.

Focus on operational control, cost efficiencies, and high-margin projects. Our development efforts are focused in areas where we have

concentrated land positions, a large drilling inventory, and operational control,

1
Table of Contents

which allow us to optimize our development plans and, therefore, reduce costs. Furthermore, our portfolio of drilling opportunities provides us with the

flexibility to allocate capital to projects with the highest margins, which currently include oil or natural gas liquids drilling projects. In addition, focusing on

areas in which we have operational control allows us to control the timing of our development efforts and capital spending.

Rationalize our asset base through property divestitures and acquisitions. In the near term, as economic conditions permit, we may divest

certain non-core assets, focusing primarily on non-producing, non-reserve based assets that are not located in our three core operational areas of the Texas

Panhandle Area, the Eagle Ford Shale in South Texas, and the East Texas / North Louisiana Area. Over the longer term, we intend to pursue property

acquisitions to enhance existing business operations in our core operational areas.

Maintain financial flexibility. We intend to maintain a strong liquidity position to successfully execute our long-term operating strategy through the

application of budget controls and prudent financial management. Further, we intend to focus on maintaining or reducing our debt at levels relative to our

estimated proved reserves and EBITDA, and, if needed, we may consider divestitures to increase our financial flexibility. In addition, we may consider other

avenues, such as farm-ins or joint development partnerships, as a way to increase our ability to accelerate development opportunities.

Recent Trends and 2013 Outlook

The market prices for oil, natural gas, and NGLs, which have been extremely volatile in recent years, have a significant impact on our financial

results and also influence, among other things, where we direct our capital expenditures, the amount of our capital expenditures, and the quantity and duration

of our hedging program, which is designed to lessen our exposure to fluctuations in commodity prices. Beginning in the second half of 2008, the market prices

for oil, natural gas, and NGLs declined dramatically as a result of the global economic crisis. As the graph below depicts, while the average prices we received

for our oil, and to a lesser extent for our NGLs, have improved since 2009, natural gas prices have continued to lag due to North American supply and

demand fundamentals. In 2012, the market price for natural gas reached a ten-year low primarily due to an abnormally warm winter, which significantly

reduced demand. While prices have improved since mid-2012, we are not planning on natural gas prices to materially improve from current levels in 2013.

With this view, we have hedged all of our forecasted 2013 natural gas production at approximately $4.00 per MMBtu. In addition, in 2013 we plan to continue

to direct the majority of our exploration and development capital expenditures to oil and NGL rich prospects within our core development areas discussed

below.

2
Table of Contents

Core Operational Areas

Our core operational areas consist of a balanced portfolio of tight-gas sands and shale plays with multiple stacked-pay opportunities that have

exposure to oil, natural gas, and natural gas liquids. Our primary areas of focus in 2013 will be in the Texas Panhandle Area, the Eagle Ford Shale in South

Texas, and the East Texas / North Louisiana Area.

Texas Panhandle Area

We have approximately 100,000 net acres in the Texas Panhandle Area, establishing Forest as one of the top acreage holders in this area. The area

provides us with horizontal drilling opportunities targeting multiple oil formations such as the Missourian Wash (Hogshooter), Tonkawa, Douglas, and

Cleveland as well as several liquids-rich intervals in the Granite Wash formation. We drilled our first horizontal wells targeting the Granite Wash formation in

2009, leveraging our vertical delineation database of over 600 wells to determine the most prospective intervals to initiate a horizontal drilling campaign. Based

on success achieved in 2009, we began a horizontal development program targeting other productive formations in the Texas Panhandle and now have

successfully completed horizontal wells in 16 distinct formations, including seven zones that have been identified as prospective for oil development. During

2012, we primarily focused on developing our oil opportunities, including the Missourian Wash Hogshooter interval. We have drilled eight Missourian Wash

Hogshooter wells since initiating our drilling program in 2011 that have had a 30-day average gross production rate of 1,820 Boe/d (67% oil) and a 90-day

average gross production rate of 1,200 Boe/d (64% oil). In 2013, we plan to operate a two rig drilling program targeting primarily the Missourian Wash

Hogshooter, Tonkawa, Douglas, and other oil intervals.

Eagle Ford Shale

We have approximately 86,000 net acres in the Eagle Ford Shale, primarily located in Gonzales County in South Texas. We commenced the drilling

of our first horizontal well in the Eagle Ford Shale at the end of 2010 and expanded the program in 2011 to focus on the optimization of our development

operations. Currently, our drilling in the Eagle Ford Shale is focused in the central fairway of our acreage position, where we have experienced the most

consistent results and have the largest, most contiguous block of acreage. We have initiated a development plan that employs a one to two rig drilling program

in the area, which should allow us to hold approximately 40,000 acres over the next several years. We have identified approximately 500 total locations on this

acreage position based on 80-acre spacing. In an effort to increase drilling efficiencies and generate higher rates of return while reducing well costs, we recently

equipped one of our drilling rigs with a “rig-walking” system that will allow for multi-well pad drilling. We drilled 14 wells in the central fairway of the Eagle

Ford Shale during 2012 that had a 30-day average gross production rate of 490 Boe/d (94% oil) and 13 of the wells had a 90-day average gross production rate

of 353 Boe/d (94% oil). Average net sales from the Eagle Ford Shale approximated 1,600 Boe/d in 2012, a 132% increase over 2011 average net sales volumes.

In 2013, we plan to maintain a one to two rig drilling program in the Eagle Ford Shale.

East Texas / North Louisiana Area

We have approximately 123,000 net acres in the East Texas / North Louisiana Area. The area provides for horizontal drilling opportunities targeting

multiple stacked-pay intervals, including the Cotton Valley, Haynesville, and other formations. Our development program was initially focused on natural gas

in the Haynesville Shale in North Louisiana, but in 2011 we reduced activity in this area due to the decrease in natural gas prices. During 2012, we changed

our focus to liquids-rich drilling projects to take advantage of these higher-margin opportunities. We drilled eight wells targeting the liquids-rich area of the

Cotton Valley that had a 30-day average gross production rate of 7.9 MMcfe/d (38% liquids) and seven of the wells had a 90-day average gross production rate

of 6.6 MMcfe/d (39% liquids). In 2013, we plan to operate a one rig drilling program in East Texas.

3
Table of Contents

Acquisition and Divestiture Activities

We pursue acquisitions that meet our criteria for investment returns and have generally focused on properties that have substantial development

drilling opportunities and undeveloped acreage positions. We also divest non-core assets from time to time to, among other things, upgrade our portfolio,

increase our operational efficiencies, and improve financial flexibility.

In January 2013, we entered into an agreement to sell all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford Shale

oil properties. This transaction closed on February 15, 2013 and we received net proceeds of $307 million.

In November 2012, we sold all of our oil and natural gas properties located in South Louisiana for net proceeds of $208 million in cash and in

October 2012, we sold the majority of our East Texas natural gas gathering assets for net proceeds of $29 million in cash. In conjunction with the natural gas

gathering assets sale, we may also earn up to $9 million of additional performance payments contingent on future activity.

In June 2011, we completed an initial public offering of approximately 18% of the common stock of our then wholly-owned subsidiary, Lone Pine

Resources Inc. (“Lone Pine”), which held our ownership interests in our Canadian operations. On September 30, 2011, we distributed, or spun-off, our

remaining 82% ownership in Lone Pine to our shareholders, by means of a special stock dividend of Lone Pine common shares.

In 2009, we sold oil and natural gas properties located in the Permian Basin in West Texas and New Mexico for net proceeds of $908 million in

cash.

In September 2008, we acquired producing oil and natural gas properties located in our Texas Panhandle and East Texas / North Louisiana core areas

from Cordillera Texas, L.P. for approximately $570 million in cash and 7.25 million shares of our common stock, valued at approximately $360 million.

Reserves

The following table summarizes our estimated quantities of proved reserves as of December 31, 2012, all of which are located in the United States,

based on the NYMEX Henry Hub (“HH”) price of $2.76 per MMBtu for natural gas and the NYMEX West Texas Intermediate (“WTI”) price of $94.79 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, 2012. See “Preparation of Reserves Estimates” below and Note 15 to the Consolidated Financial Statements for additional information

regarding our estimated proved reserves.

Estimated Proved Reserves

Natural Gas

(MMcf) Oil (MBbls)

Natural Gas Liquids

(MBbls)

Total

(MMcfe)(1)

Developed 710,288 12,315 25,518 937,286

Undeveloped 202,545 21,387 15,737 425,289

Total estimated proved reserves 912,833 33,702 41,255 1,362,575

____________________________________________

(1) Oil and natural gas liquids are converted to gas-equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. This conversion is based on

energy equivalence and not price equivalence. For 2012, the average of the first-day-of-the-month gas price was $2.76 per Mcf, and the average of the first-day-of-the-month

oil price was $94.79 per barrel. If a price-equivalent conversion based on these twelve-month average prices was used, the conversion factor would be approximately 34 Mcf

per barrel of oil and approximately 16 Mcf per barrel of NGLs (based on the average of the first-day-of-the-month Mt. Belvieu pricing for NGLs in 2012).

As of December 31, 2012, we had estimated proved reserves of 1,363 Bcfe, a decrease of 28% compared to 1,904 Bcfe of estimated proved reserves

at December 31, 2011. During 2012, we added 235 Bcfe of estimated proved reserves through extensions and discoveries primarily driven by our 2012

drilling activity in the Texas

4
Table of Contents

Panhandle Area and the Eagle Ford Shale in South Texas, with such additions offset by property sales of 52 Bcfe and negative revisions of 604 Bcfe. The

negative revisions were primarily associated with lower natural gas and natural gas liquids prices, which caused certain natural gas-weighted projects to no

longer meet economic investment criteria based on the unweighted arithmetic average of the first-day-of-the-month commodity prices utilized in calculating our

reserve estimates. In addition, lower natural gas prices also delayed our initial expected development time frame for drilling certain of our proved undeveloped

natural gas locations beyond five years from the time the associated reserves were originally recorded. Accordingly, these proved undeveloped reserves

(“PUDs”) were reclassified to probable undeveloped reserves in 2012. Also included in the revisions is a reclassification of all 52 Bcfe of our Italian PUDs to

probable due to an Italian regional regulatory body’s denial of our environmental impact assessment associated with our proposal to commence natural gas

production from wells that we drilled and completed in 2007. We are currently appealing the region’s denial; however, until the region’s denial is reversed or

overturned, we determined that we could no longer conclude with reasonable certainty that our Italian natural gas reserves are producible.

As of December 31, 2012, we had estimated proved undeveloped reserves of 425 Bcfe, or 31% of estimated proved reserves, compared to 866 Bcfe,

or 45% of estimated proved reserves as of December 31, 2011. The net decrease of 441 Bcfe was primarily due to the negative revisions associated with lower

natural gas and natural gas liquids prices and the reclassification to probable of 52 Bcfe of our Italian PUDs, both as discussed above. During 2012, we

invested $116 million to convert 45 Bcfe of our December 31, 2011 PUDs to proved developed reserves. The rate at which we convert PUDs to proved

developed reserves has been negatively impacted in the last several years due to our transition away from developing natural gas reserves, many of which were

reclassified to probable reserves in 2011 and 2012, and towards the development of oil reserves. In connection with this transition, we drilled a high percentage

of non-proved locations in an effort to hold leases that would otherwise be lost if instead we were to drill proved undeveloped locations that are on leases already

held by producing wells. We expect this trend to continue throughout 2013, after which point we expect to increase our PUD conversion rate. As of December

31, 2012, we have no PUDs that have remained undeveloped for five years or more after they were initially disclosed as PUDs.

Preparation of Reserves Estimates

Reserves estimates included in this Annual Report on Form 10-K are prepared by 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 is restricted to select

individuals from our engineering department. Moreover, new reserves estimates and significant changes to existing reserves are reviewed and approved by

various levels of management, depending on their magnitude. Proved reserves estimates are reviewed and approved by the Senior Vice President, Corporate

Engineering and Technology, and at least 80% of our proved reserves, based on net present value, are audited by independent reserve engineers (see

“Independent Audit of Reserves” below) prior to review by the Audit Committee. In connection with its review, the Audit Committee meets privately with

personnel from DeGolyer and MacNaughton, the independent petroleum engineering firm that audits our reserves, to confirm that DeGolyer and MacNaughton

has not identified any concerns or issues relating to the audit and maintains independence. In addition, Forest’s internal audit department randomly selects a

sample of new reserves estimates or changes made to existing reserves and tests to ensure that they were properly documented and approved.

Forest’s Senior Vice President, Corporate Engineering and Technology, who has held this position since January 2013, has 35 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 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 Forest, he held various

positions in reservoir engineering and corporate planning with Phillips Petroleum, Midcon Exploration, and Apache Corporation.

5
Table of Contents

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our 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. See Part I, Item 1A “Risk Factors” below for a description of some

of the risks and uncertainties associated with our business and reserves.

Independent Audit of Reserves

We engage independent reserve engineers to audit a substantial portion of our reserves. Our audit procedures require 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

our year-end proved reserves for each country in which proved reserves have been recorded. The fields selected for audit also must comprise at least 80% of

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 prohibit exclusions of any fields, or any part of a field, that comprise part of the top 80%. The independent reserve engineers compare their

own estimates to those prepared by Forest. Our audit guidelines require Forest’s internal estimates, which are used for financial reporting and disclosure

purposes, to be within 5% of the independent reserve engineers’ quantity estimates. The independent reserve audit is conducted based on reserve definition and

cost and price parameters specified by the Securities and Exchange Commission (“SEC”).

For the years ended December 31, 2012, 2011, and 2010, we engaged DeGolyer and MacNaughton, an independent petroleum engineering firm, to

perform reserve audit services. For the year ended December 31, 2012, DeGolyer and MacNaughton independently audited estimates relating to properties

constituting over 83% of our reserves by NPV as of December 31, 2012. When compared on a field-by-field basis, some of Forest’s estimates of proved

reserves were greater and some were less than the estimates prepared by DeGolyer and MacNaughton. However, in the aggregate, Forest’s estimates of total

proved reserves were within 3% of DeGolyer and MacNaughton’s aggregate estimate of proved reserves for the fields audited. The lead technical person at

DeGolyer and MacNaughton primarily responsible for overseeing the audit of our reserves 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 in excess of 38 years of experience

in oil and gas reservoir studies and reserves evaluations.

6
Table of Contents

Drilling Activities

The following table summarizes the number of wells drilled during 2012, 2011, and 2010, 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 we do not have a working interest. As of December 31,

2012, we had 19 gross (13 net) wells in progress, all of which are located in the United States. During 2012, we drilled a total of 139 gross (77 net) wells, of

which 30 were classified as exploratory and 109 were classified as development. Our 2012 drilling program, which primarily consisted of horizontal wells,

achieved a 96% success rate.

Year Ended December 31,

2012 2011 2010

Gross Net Gross Net Gross Net

Development wells:

Productive(1) 106 49 101 44 75 38

Non-productive(2)

3 1 — — 5 4

Total development wells 109 50 101 44 80 42

Exploratory wells:

Productive(1) 27 24 22 21 24 16

Non-productive(2)

3 3 4 3 5 4

Total exploratory wells 30 27 26 24 29 20

____________________________________________

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

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

known as a dry well (or dry hole).

Oil and Natural Gas Wells and Acreage

Productive Wells

The following table summarizes our productive wells as of December 31, 2012, 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, 2012, we owned interests in 5 9 gross wells containing multiple completions.

Gross Net

Natural Gas 3,554 2,568

Oil 268 140

Total 3,822 2,708

7
Table of Contents

Acreage

The following table summarizes developed and undeveloped acreage in which we owned a working interest or held an exploration license as of

December 31, 2012. A substantial majority of our developed acreage is subject to mortgage liens securing our 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 us to acquire additional

leasehold interests. At December 31, 2012, approximately 20%, 18%, and 13% of our net undeveloped acreage in the United States was held under leases that

will expire in 2013, 2014, and 2015, respectively, if not extended by exploration or production activities.

Developed

Acreage

Undeveloped

Acreage

Location Gross Net Gross Net

United States(1) 622,184 376,538 621,836 425,372

South Africa(2)

— — 2,771,695 1,474,542

Italy — — 107,043 86,507

Total 622,184 376,538 3,500,574 1,986,421

____________________________________________

(1) Concentrations of net acres in the United States as of December 31, 2012 include: 100,000 net acres in the Texas Panhandle Area; 123,000 net acres in the East Texas / North

Louisiana Area; 192,000 net acres in South Texas (including 86,000 in the Eagle Ford Shale); 132,000 net acres in the Permian Basin in West Texas; and 74,000 net acres in

the Uintah Basin in Utah.

(2) In December 2012, we entered into agreements to dispose of our interests in the Block 2A Production Right and the Block 2C Exploration Right in South Africa. The

completion of these transactions is contingent upon the approval of the Minister of Mineral Resources for the government of the Republic of South Africa. At the completion of

these transactions, we will no longer hold any acreage in South Africa.

8
Table of Contents

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, 2012, 2011, and

2010 for continuing operations. All of our production occurred in the United States for the years presented and we do not have any fields that individually

contain 15% or more of our total estimated proved reserves.

Year Ended December 31,

2012 2011 2010

Liquids:

Oil and condensate:

Production volumes (MBbls) 3,146 2,491 2,357

Average sales price (per Bbl) $ 96.14 $ 96.22 $ 76.08

Natural gas liquids:

Production volumes (MBbls) 3,489 3,154 3,589

Average sales price (per Bbl) $ 31.77 $ 42.91 $ 34.54

Total liquids:

Production volumes (MBbls) 6,635 5,645 5,946

Average sales price (per Bbl) $ 62.29 $ 66.43 $ 51.01

Natural Gas:

Production volumes (MMcf) 81,008 88,497 101,346

Average sales price (per Mcf) $ 2.37 $ 3.71 $ 3.99

Total production volumes (MMcfe)(1)

120,818 122,367 137,022

Average sales price (per Mcfe)

$ 5.01 $ 5.75 $ 5.16

Production costs (per Mcfe):

Lease operating expenses $ .89 $ .81 $ .67

Transportation and processing costs .12 .11 .10

Production costs excluding production and property taxes (per Mcfe)

1.02 .92 .77

Production and property taxes .28 .33 .32

Total production costs (per Mcfe) $ 1.30 $ 1.25 $ 1.09

____________________________________________

(1) Oil and natural gas liquids are converted to gas-equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. This conversion is based on

energy equivalence and not price equivalence. For 2012, the average of the first-day-of-the-month gas price was $2.76 per Mcf, and the average of the first-day-of-the-month

oil price was $94.79 per barrel. If a price-equivalent conversion based on these twelve-month average prices was used, the conversion factor would be approximately 34 Mcf

per barrel of oil and approximately 16 Mcf per barrel of NGLs (based on the average of the first-day-of-the-month Mt. Belvieu pricing for NGLs in 2012).

Marketing and Delivery Commitments

Our natural gas production is generally sold on a month-to-month basis in the spot market, priced in reference to published indices. Our 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. Our natural gas liquids production is typically sold under term agreements at prices based on postings at large fractionation facilities. We believe 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 our ability to sell our

production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption. We had no material delivery

commitments as of February 21, 2013.

Competition

Forest encounters competition in all aspects of its business, including acquisition of properties and oil and gas leases, marketing oil and gas,

obtaining services and labor, and securing drilling rigs and other equipment

9
Table of Contents

necessary for drilling and completing wells. Our ability to increase reserves in the future will depend on our ability to generate successful prospects on our

existing properties, execute on major development drilling programs, and acquire additional leases and prospects for future development and exploration. A

large number of the companies that we compete with have substantially larger staffs and greater financial and operational resources than we have. Because of

the nature of our oil and gas assets and management’s experience in exploiting our reserves and acquiring properties, management believes that we effectively

compete in our markets.

Industry Regulation

Our oil and gas operations are subject to various national, state, and local laws and regulations in the jurisdictions in which we operate. These laws

and regulations may be changed in response to economic or political conditions. Matters subject to current governmental regulation or pending legislative or

regulatory changes include bonding or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment costs,

reports concerning our operations, the spacing of wells, unitization and pooling of properties, taxation, and the use of derivative hedging instruments. Our

operations are also subject to permit requirements for the drilling of wells and regulations relating to the location of wells, the method of drilling and the casing

of wells, surface use and restoration of properties on which wells are located, and the plugging and abandonment of wells. Failure to comply with the laws and

regulations in effect from time to time may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and

the issuance of injunctions that could delay, limit, or prohibit certain of our operations. At various times, regulatory agencies have imposed price controls and

limitations on oil and gas production. In order to conserve supplies of oil and gas, these agencies may restrict the rates of flow of oil and gas wells below actual

production capacity. Further, a significant spill from one of our facilities could have a material adverse effect on our results of operations, competitive

position, or financial condition. The laws of the jurisdictions in which we operate regulate, among other things, the production, handling, storage,

transportation, and disposal of oil and gas, by-products from oil and gas, and other substances and materials produced or used in connection with oil and gas

operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or

proration units and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws 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. Certain of

our operations are conducted on federal land pursuant to oil and gas leases administered by the Bureau of Land Management (“BLM”). These leases contain

relatively standardized terms and require compliance with detailed BLM regulations and orders (which are subject to change by the BLM). In addition to

permits required from other agencies, lessees must obtain a permit from the BLM prior to the commencement of drilling and comply with regulations

governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production, and the

removal of facilities. Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated. Any such suspension

or termination could materially and adversely affect our financial condition and operations.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) imposes reporting and other requirements on our business

and operations, including with respect to payments made to U.S. and foreign governments related to our oil and gas exploration and development activities.

The legislation also imposes new requirements and oversight on our derivatives transactions, including potential new clearing, margin, and position limits

requirements. Significant regulations have been promulgated by the SEC, the Commodity Futures Trading Commission, and other regulatory agencies to

implement these requirements and provide certain exemptions for qualified end-users. Although Forest does not anticipate it will be affected differently than

other producers of oil and natural gas, the new requirements are likely to impose additional reporting obligations on us with respect to the use of derivative

instruments to hedge against commercial risks related to fluctuations in oil and gas commodity prices and interest rates. In addition, this legislation could have

a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future. The imposition of these types of

requirements or limitations could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activities.

10
Table of Contents

Additional proposals and proceedings that might affect the oil and gas industry are regularly considered by Congress, the states, the Federal Energy

Regulatory Commission, and the courts. We cannot predict when or whether any such proposal, or any additional new legislative or regulatory proposal, may

become effective. No material portion of Forest’s business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the

federal government.

Environmental and Climate Change Regulation

We are subject to stringent national, state, and local laws and regulations in the jurisdictions where we operate relating to environmental protection,

including the manner in which various substances such as wastes generated in connection with oil and gas exploration, production, and transportation

operations are managed. Compliance with these laws and regulations can affect the location or size of wells and facilities, prohibit or limit the extent to which

exploration and development may be allowed, and require proper closure of wells and restoration of properties when production ceases. Failure to comply with

these laws and regulations may result in the assessment of administrative, civil, or criminal penalties, imposition of remedial obligations, incurrence of

additional compliance costs, and even injunctions that limit or prohibit exploration and production activities or that constrain the disposal of substances

generated by oil field operations.

We currently operate or lease, and have in the past operated or leased, a number of properties that for many years have been used for the exploration

and production of oil and gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other

wastes may have been disposed of or released on or under the properties operated or leased by us or on or under other locations where such wastes have been

taken for disposal. In addition, many of these properties have been operated by third parties whose treatment, disposal, or release of hydrocarbons or other

wastes was not under our control. These properties and the wastes disposed thereon may be subject to laws and regulations imposing joint and several, strict

liability without regard to fault or the legality of the original conduct that could require us to remove previously disposed wastes or remediate property

contamination, or to perform well pluggings or pit closures or other actions of a remedial nature to prevent future contamination.

Our operations produce wastewater that is disposed via injection in underground wells. These wells are regulated under the Safe Drinking Water Act

(the “SDWA”) and similar state and local laws. The underground injection well program under the SDWA requires permits from the United States

Environmental Protection Agency (“EPA”) or analogous state agencies for our disposal wells, establishes minimum standards for injection well operations, and

restricts the types and quantities of fluids that may be injected. We believe that our disposal well operations comply with all applicable requirements under the

SDWA and similar state and local laws. However, a change in the regulations or the inability to obtain permits for new injection wells in the future may affect

the Company’s ability to dispose of produced waters and ultimately increase the cost of the Company’s operations.

Hydraulic fracturing is an important process used in the completion of our oil and gas wells. The process involves the injection of water, sand, and

chemicals under pressure into low-permeability formations to fracture the surrounding rock and stimulate production. The process is typically regulated by

state oil and gas commissions. Various state and local governments have implemented or are considering increased regulatory oversight of hydraulic fracturing

through additional permit requirements, operational restrictions, requirements for disclosure of chemical constituents, and temporary or permanent bans on

hydraulic fracturing in certain environmentally sensitive areas such as watersheds. For instance, Texas, Colorado, and Louisiana have adopted far-reaching

rules that require the public disclosure of chemicals used in the hydraulic fracturing process, with the Texas rules applicable to fracturing treatments on wells

with initial drilling permits issued on or after February 1, 2012, and the Colorado rules applicable to fracturing treatments performed on or after April 1,

2012. The Louisiana regulations require operators to disclose all additives used in hydraulic fracturing fluids and the names and concentrations of chemicals

subject to Occupational Safety and Health Administration Hazard Communication requirements that are not deemed a trade secret. The Louisiana requirements

are effective for wells with drilling permits issued on or after October 20, 2011. The availability of this information could make it easier for third parties

opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could

adversely affect groundwater. Several federal entities, including the EPA, also have recently asserted potential

11
Table of Contents

regulatory authority over hydraulic fracturing, and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities,

with the results of the study anticipated to be available for review in 2014. In addition, Congress has considered legislation that would amend the SDWA to

encompass hydraulic fracturing activities. Such a provision would have required hydraulic fracturing operations to meet permitting and financial assurance

requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and record keeping obligations, including disclosure of chemicals

used in the fracturing process, and meet plugging and abandonment requirements. If such legislation is adopted in the future, it would establish an additional

level of regulation and impose additional costs on our operations. See Part I, Item 1A “Risk Factors— We may incur significant costs related to

environmental and other governmental laws and regulations, including those related to “hydraulic fracturing,” that may materially affect our

operations” below.

Nearly half of the states in the U.S., either individually or through multi-state initiatives, have begun implementing legal measures to reduce

emissions of greenhouse gases (“GHGs”). Also, the Supreme Court held in Massachusetts, et al. v. EPA (2007) that carbon dioxide may be regulated as an

“air pollutant” under the federal Clean Air Act, and subsequently in December 2009, the EPA determined that GHG emissions present an endangerment to

public health and the environment because such emissions, according to the EPA, are contributing to warming of the earth’s atmosphere and other climate

changes. These findings allow the EPA to implement regulations that would restrict GHG emissions under existing provisions of the Clean Air Act. On

November 8, 2010, the EPA finalized GHG reporting requirements for the petroleum and natural gas industries. Under this final rule, owners or operators of

facilities that contain petroleum and natural gas systems, as defined by the rule, and emit 25,000 metric tons or more of GHGs per year per basin (expressed

as carbon dioxide equivalents) will report emissions from all source categories located at the facility for which emission calculation methods are defined in the

rule. Owners or operators will collect emission data, calculate GHG emissions, and follow the specified procedures for quality assurance, missing data, record

keeping, and reporting defined in the final rule. For purposes of the rule, an onshore petroleum and natural gas production facility is generally defined as all

petroleum and natural gas equipment associated with all petroleum or natural gas production wells and carbon dioxide enhanced oil recovery operations that are

under common ownership or control. This includes leased, rented, and contracted activities by an onshore petroleum and natural gas production owner or

operator that is located within a single hydrocarbon basin as defined by the American Association of Petroleum Geologists. The rule is estimated to require

reporting from approximately 2,800 facilities, covering 85% of the total GHG emissions from the U.S. petroleum and natural gas industries, including all of

Forest’s facilities, with modeling reporting beginning in late 2012 and actual data reporting beginning in 2013. We expect these new rules to result in increased

compliance costs on our operations. In addition, these rules, and any other new rules and regulations addressing GHG emissions, could result in additional

operating restrictions.

We believe that it is likely that the trend in environmental legislation and regulation will continue toward stricter standards. While we believe that we

are in substantial compliance with applicable environmental laws and regulations in effect at the present time and that continued compliance with existing

requirements will not have a material adverse impact on us, we cannot give any assurance that we will not be adversely affected in the future. We have

established internal guidelines to be followed in order to comply with environmental laws and regulations in the United States and other relevant international

jurisdictions. We employ an environmental, health, and safety department whose responsibilities include providing assurance that our operations are carried

out in accordance with applicable environmental guidelines and safety precautions. Although we maintain pollution insurance against the costs of cleanup

operations, public liability, and physical damage, there is no assurance that such insurance will be adequate to cover all such costs or that such insurance will

continue to be available in the future.

Employees

As of December 31, 2012, we had 605 employees. None of our employees is currently represented by a union for collective bargaining purposes.

12
Table of Contents

Geographical Data

Forest operates in one industry segment, oil and gas exploration and production, and has one reportable geographical business segment, the United

States.

Offices

Our corporate office is located in leased space at 707 17 th Street, Denver, Colorado. We maintain an office in Houston, Texas, and also lease or own

field offices in the areas in which we conduct operations.

Title to Properties

Title to our oil and gas properties is subject to royalty, overriding royalty, carried, net profits, working, and similar interests customary in the oil

and gas industry. Under the terms of our bank credit facility, we have granted the lenders a lien on the substantial majority of our properties. In addition, our

properties may also be subject to liens incident to operating agreements, as well as other customary encumbrances, easements, and restrictions, and for current

taxes not yet due. Forest’s general practice is to conduct a title examination on material property acquisitions. Prior to the commencement of drilling operations,

a title examination and, if necessary, curative work is performed. The methods of title examination that we have adopted are reasonable in the opinion of

management and are designed to ensure that production from our properties, if obtained, will be salable by Forest.

Glossary of Oil and Gas Terms

The terms defined in this section are used throughout this Annual Report on Form 10-K. Certain definitions, including the definitions of proved

developed reserves, proved reserves, and proved undeveloped reserves, have been abbreviated from the applicable definitions contained in Rule 4-10(a) of

Regulation S-X under the Securities Exchange Act of 1934. The entire definitions of those terms can be viewed on the SEC’s website at http://www.sec.gov.

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

Bcf. Billion cubic feet of natural gas.

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

Bbtu. One billion British Thermal Units.

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

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

is in the liquid phase at surface temperature and pressure.

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

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

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

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

one barrel to six Mcf.

13
Table of Contents

Exploitation. Ordinarily considered to be a form of development within a known reservoir.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another

reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

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

undertaking of other work obligations.

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

feature and/or stratigraphic condition.

Full cost pool. The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company

using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration, and development

activities are included. Any costs related to production, general and administrative expense, or similar activities are not included.

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

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

Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals

under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, constituting part of the current operating

expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, and

other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

Liquids. Describes oil, condensate, and natural gas liquids.

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

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

gas liquids.

Mcf. Thousand cubic feet of natural gas.

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

liquids.

MMBtu. One million British Thermal Units.

MMcf. Million cubic feet of natural gas.

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

liquids.

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

propane, butanes, and natural gasoline.

14
Table of Contents

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

of whole numbers.

NYMEX. New York Mercantile Exchange.

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

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

operating methods.

Proved reserves. Quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be

economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government

regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of

whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must

be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic

producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the end of the reporting period,

determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual

arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves or PUDs. Estimated proved reserves that are expected to be recovered from new wells on undrilled acreage or from

existing wells where a relatively major expenditure is required for recompletion.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by

impermeable rock or water barriers and is individual and separate from other reservoirs.

Standardized measure or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues

from proved oil and gas reserves at a date indicated after deducting estimated production and property taxes, future capital costs, operating expenses, and

estimated future income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the SEC’s requirements, to

determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as

being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the estimation

date in accordance with the SEC’s regulations and are held constant for the life of the reserves.

Undeveloped Acreage. Acreage on which wells have not been drilled or completed to a point that would permit the production of economic

quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

Working interest. An operating interest which gives the owner the right to drill, produce, and conduct operating activities on the property, and to

receive a share of production.

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

Available Information

Forest’s website address is http://www.forestoil.com. Available on our website, free of charge, are Forest’s Annual Reports on Form 10-K, Quarterly

Reports on Form 10-Q, Current Reports on Form 8-K, reports on Forms 3, 4, and 5 filed on behalf of directors and officers, as well as amendments to these

reports. These materials are available as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC.

15
Table of Contents

Also posted on Forest’s website, and available in print upon written request of any shareholder addressed to the Secretary of Forest, at 707

17th Street, Suite 3600, Denver, Colorado 80202, are Forest’s Corporate Governance Guidelines, the charters for each of the committees of our Board of

Directors (including the charters of the Audit Committee, Compensation Committee, and Nominating and Corporate Governance Committee), and codes of

ethics for our directors and employees entitled “Code of Business Conduct and Ethics” and “Proper Business Practices Policy,” respectively.

Forward-Looking Statements

The information in this Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act

and Section 21E of the Exchange Act. Forward-looking statements are statements other than statements of historical or present facts, that address activities,

events, outcomes, and other matters that Forest plans, expects, intends, assumes, believes, budgets, predicts, forecasts, projects, estimates, or anticipates

(and other similar expressions) will, should, or may occur in the future. Generally, the words “expects,” “anticipates,” “targets,” “goals,” “projects,”

“intends,” “plans,” “believes,” “seeks,” “estimates,” “may,” “will,” “could,” “should,” “future,” “potential,” “continue,” the negative of such words or other

variations of such words, and similar expressions, identify forward-looking statements. Similarly, statements that describe our strategies, initiatives,

objectives, plans, or goals are forward-looking. These forward-looking statements are based on our current intent, plans, belief, expectations, estimates,

projections, forecasts, and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

These statements are not guarantees of future performance.

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

• estimates of our oil and natural gas reserves;

• estimates of our future oil and natural gas production, including estimates of any increases or decreases in our production, and the

liquids/natural gas mix of that production;

• our future financial condition and results of operations;

• our future revenues, cash flows, and expenses;

• our access to capital and our anticipated liquidity;

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

• our outlook on oil and natural gas prices;

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

• our ability to access the capital markets to fund capital and other expenditures;

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

• the impact of federal, state, and local political, regulatory, and environmental developments in the United States and certain foreign locations

where we conduct business operations.

We believe the expectations, estimates, projections, beliefs, forecasts, and assumptions reflected in our forward-looking statements are reasonable,

but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements are subject to all of the risks and

uncertainties, most of which are

16
Table of Contents

difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, and sale of oil and gas. See

“Competition,” “Industry Regulation,” and “Environmental and Climate Change Regulation” above, as well as Part I, Item 1A “Risk Factors,” Part II, Item 7

“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources,” and Part II, Item 7A

“Quantitative and Qualitative Disclosures about Market Risk” for a description of various, but by no means all, factors that could materially affect our

ability to achieve the anticipated results described in the forward-looking statements.

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no

obligation to update this information to reflect events or circumstances after the filing of this report with the SEC, except as required by law. All forwardlooking statements, expressed or implied, included in this Annual Report on Form 10-K and attributable to Forest are expressly qualified in their entirety by

this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements

that we may make or persons acting on our behalf may issue.

Item 1A. Risk Factors.

We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks discussed below, any of which could

materially and adversely affect our business, financial condition, cash flows, and results of operations, are not the only risks we face. We may experience

additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be

immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations. Except where the context

otherwise indicates, references to oil and natural gas in this section include natural gas liquids.

Oil and natural gas prices are volatile. Declines in commodity prices have adversely affected, and in the future may adversely affect, our results of

operations, cash flows, financial condition, access to the capital markets, the economic viability of our reserves, and our ability to reinvest in order

to maintain or grow our asset base.

Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to a variety of factors that are beyond our control.

Approximately 67% of our estimated proved reserves at December 31, 2012 were natural gas, causing us to be particularly dependent on prices for natural

gas.

During the fourth quarter of 2011 and continuing into 2012, natural gas prices declined to ten-year lows. Further deterioration in prices or a

continuation of low natural gas prices may mean that it will not be economical to drill or produce natural gas from some of our existing properties, and we may

be required to curtail, or stop completely, our production activities in those areas. A continuation of low natural gas prices, or a significant decline in oil prices,

may have the following effects on our business:

• impairing our financial condition, liquidity, or ability to fund planned capital expenditures;

• limiting our access to sources of capital, such as equity and debt; or

• prohibiting us from developing our current properties, or from growing our asset base.

We have substantial indebtedness, and we may incur more debt in the future. Our leverage may materially adversely affect our operations and

financial condition.

As of December 31, 2012, we had a principal amount of long-term indebtedness of $1.9 billion, including $65 million drawn under our bank

credit facility. As of February 21, 2013, we had a principal amount of long-term indebtedness of $1.8 billion with no outstanding borrowings under our bank

credit facility.

17
Table of Contents

Our level of debt may have several important effects on our business and operations; among other things, it may:

• require us to use a significant portion of our cash flows to service the obligations, which could limit our flexibility in planning for and reacting to

changes in our business, and reduce the amount available to reinvest in order to maintain or grow our asset base;

• adversely affect the credit ratings assigned by third-party rating agencies, which have in the past and may in the future downgrade their ratings of

our debt and other obligations;

• limit our access to the capital markets;

• increase our borrowing costs, and impact the terms, conditions, and restrictions contained in our debt agreements, including the addition of more

restrictive covenants;

• place us at a disadvantage compared to companies in our industry that have less debt and other financial obligations; and

• make us more vulnerable to economic downturns, volatile oil, natural gas, and natural gas liquids prices, and adverse developments in our

business.

A higher level of debt will increase the risk that we may default on our financial obligations. Our ability to meet our debt obligations and other

expenses will depend on our future performance. Our future performance will be affected by oil, natural gas, and natural gas liquids prices, financial,

business, domestic, and global economic conditions, governmental regulations and environmental regulations, and other factors, many of which we are unable

to control. If our cash flows are not sufficient to service our debt and other obligations or to meet the financial or other restrictive covenants contained in our

bank credit facility and the indentures governing our outstanding senior notes, we may be required to refinance or restructure the debt, sell assets, or sell

shares of our common or preferred equity securities-all on terms that we do not find attractive, if it can be done at all. The governing documents of our debt

instruments contain covenants and restrictions that require that we meet certain financial tests and place restrictions on the incurrence of additional

indebtedness. A failure on our part to comply with the financial and other restrictive covenants contained in our bank credit facility and the indentures

governing our outstanding senior notes could result in a default under these agreements. Any default under our bank credit facility or indentures could

adversely affect our business and our financial condition and results of operations, and would impact our ability to obtain financing in the future.

We may not be able to obtain funding under our current bank credit facility because of a decrease in our borrowing base or obtain funding in the

capital markets on terms we find acceptable.

Historically, we have used our cash flows from operations and borrowings under our bank credit facility to fund our capital expenditures and have

relied on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions or to refinance debt

obligations. We currently have a bank credit facility with lender commitments totaling $1.5 billion. The borrowing base is determined by the lenders

periodically and is based on the estimated value of our properties using pricing models determined by the lenders at such time. The current borrowing base

was set at $900 million following the closing of the sale of our South Texas assets on February 15, 2013. The next scheduled redetermination of the borrowing

base will occur on or before May 1, 2013. Also, under the terms of our bank credit facility, our borrowing base will be immediately decreased by an amount

equal to 25% of the stated principal amount of senior notes issued in the future (excluding any senior notes that we may issue to refinance senior notes that

were outstanding on June 30, 2011). In the future, we may not be able to access adequate funding under our bank credit facility as a result of (i) a decrease in

our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending

counterparties to meet their funding obligations. Since the process for determining the borrowing base under our bank credit facility involves evaluating the

estimated value of our oil and natural gas properties using pricing models determined by the lenders at that time, a decline in those prices used may result in a

redetermination

18
Table of Contents

of our borrowing base and a decrease in the available borrowing amount at the time of the next scheduled redetermination. In such case, we would be required

to repay any indebtedness in excess of the borrowing base.

In recent years, volatility in the public and private capital markets has made it more difficult to obtain funding. There is a risk that the cost of

obtaining money from the credit markets may increase in the future as lenders and institutional investors may increase interest rates, impose tighter lending

standards, refuse to refinance existing debt at maturity on terms similar to existing debt or at all, or reduce or cease to provide any new funding. Due to these

factors, we cannot be certain that funding, if needed, will be available to the extent required, or on acceptable terms. If we are unable to access funding when

needed on acceptable terms, we may not be able to fully implement our business plans, take advantage of business opportunities, respond to competitive

pressures, or refinance our debt obligations as they come due, any of which could have a material adverse effect on our operations and financial results.

Our debt agreements contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business

opportunities.

Our bank credit facility and the indentures governing our senior notes contain restrictive covenants that will limit our ability and the ability of certain

of our subsidiaries to, among other things:

• incur or guarantee additional indebtedness or issue preferred shares;

• pay dividends or make other distributions;

• purchase equity interests or redeem subordinated indebtedness early;

• create or incur certain liens;

• enter into transactions with affiliates; and

• sell assets or merge or consolidate with another company.

Complying with the restrictions contained in some of these covenants will require us to meet certain financial ratios and tests, notably with respect to

consolidated interest coverage, total assets, net debt, equity, and net income. For example, our bank credit facility provides that we will not permit our ratio of

total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing 12-month period to be greater than 4.5 to 1.0 at any time. Our ratio of total

debt outstanding to EBITDA for the 12-month period ending December 31, 2012, as calculated in accordance with our bank credit facility, was 4.2. Our need

to comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities

we believe to be desirable, obtain future financing, fund needed capital expenditures, or withstand a future downturn in our business.

We are a relatively small company and therefore may not be able to compete effectively.

Compared to many of the companies in our industry, we are a small company. We face difficulties in competing with the larger companies. The costs

of doing business in the exploration and production industry, including such costs as those required to explore new oil and natural gas plays, to acquire new

acreage, and to develop attractive oil and natural gas projects, are significant. Our limited size can place us at a disadvantage with respect to funding such

costs. Our limited size also means that we are more vulnerable to commodity price volatility and overall industry cycles, are less able to absorb the burden of

changes in laws and regulations, and that poor results in any single exploration, development, or production play can have a disproportionately negative

impact on us. Our size can also impair our ability to attract and retain staff and maintain competitive technical capabilities.

19
Table of Contents

Our estimates of oil and natural gas reserves involve inherent uncertainty, which could materially affect the quantity and value of our reported

reserves and our financial condition.

The proved oil and natural gas reserves information and the related future net revenues information included in this Annual Report on Form 10-K

and in our other periodic reports represent only estimates, which are prepared by our internal staff of engineers and the majority of which are audited by

DeGolyer and MacNaughton, an independent petroleum engineering firm. Estimating quantities of proved oil and natural gas reserves is a complex, inexact

process and depends on a number of interpretations of technical data and various factors and assumptions, including assumptions required by the SEC as to

oil, natural gas, and natural gas liquids prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. As a result, these

estimates are inherently imprecise. Any significant inaccuracies or changes in our assumptions or changes in operating conditions could cause the estimated

quantities and net present value of the estimated reserves to be significantly different.

At December 31, 2012, approximately 31% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves

generally requires significant capital expenditures and successful drilling operations. Our reserves estimates include the assumption that we will make

significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties

may not be as estimated.

Our estimated proved reserves as of December 31, 2012 were based on a NYMEX HH price of $2.76 per MMBtu for natural gas and a NYMEX

WTI price of $94.79 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, 2012, and an average realization for a barrel of natural gas liquids during that period equal to approximately 36% of the NYMEX

WTI price or $33.83. For the year ended December 31, 2011, the comparable prices used to calculate our estimated proved reserves were $4.12 per MMBtu for

natural gas, $96.08 per barrel for oil, and an average realization for a barrel of natural gas liquids equal to approximately 46% of the oil price or $44.05. The

decline in natural gas and natural gas liquids prices from those used to estimate proved reserves as of December 31, 2011 resulted in 552 Bcfe of downward

revisions to our estimated proved reserves during 2012. These revisions were primarily due to proved undeveloped natural gas drilling locations no longer

being economic at the lower commodity prices used throughout 2012, including as of December 31, 2012. In addition, lower natural gas prices also delayed

our initial expected development time frame for drilling our proved undeveloped natural gas locations beyond five years from the time the wells were originally

recorded. Accordingly, these proved undeveloped reserves were reclassified to probable undeveloped reserves in 2012.

You should not assume that any present value of future net cash flows from our estimated proved reserves as set forth in this Annual Report on Form

10-K for the year ended December 31, 2012 represents the market value of our oil and natural gas reserves.

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

other impairments of our asset carrying values.

We use the full cost method of accounting to report our oil and natural gas activities. Under this method, we capitalize the cost to acquire, explore for,

and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and natural gas properties may not exceed a

ceiling limit, which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of

proved oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a ceiling test write-down.

Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test write-down does not impact cash flows from operating

activities, but it does reduce our shareholders’ equity.

Investments in unproved properties are also assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are

individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic

and geologic data obtained relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized,

20
Table of Contents

or is reported as a period expense, as appropriate. If an impairment of unproved properties is added to the costs to be amortized, the amount by which the

ceiling limit exceeds the capitalized costs of proved oil and natural gas properties would be reduced.

We also assess the carrying amount of goodwill in the second quarter of each year and at other periods when events occur that may indicate an

impairment exists. These events include, for example, a decline in our market capitalization relative to our net asset values or other adverse economic or

qualitative factors.

The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil, natural gas, and natural

gas liquids prices are low. In addition, write-downs may occur if we experience downward adjustments to our estimated proved reserves or our unproved

property values, or if estimated future development or operating costs increase. For example, during 2012 we incurred ceiling test write-downs of $992 million

primarily due to a decline in natural gas and natural gas liquids prices used to calculate our estimated proved reserves during 2012. Additional write-downs of

the United States cost center may be required in subsequent periods if, among other things, the unweighted arithmetic average of the first-day-of-the-month oil,

natural gas, and natural gas liquids prices used in the calculation of the present value of future net revenue from estimated production of estimated proved

reserves decline compared to prices used as of December 31, 2012, unproved property values are impaired, estimated proved reserve volumes are revised

downward, or costs incurred in exploration, development, or acquisition activities exceed the discounted future net cash flows from the additional reserves, if

any, attributable to the cost center.

If we are not able to replace reserves, we will not be able to sustain or grow production.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on

reservoir characteristics. Unless we replace the reserves we produce through successful development, exploration or acquisition, our proved reserves and

production will decline over time.

We do not always find commercially productive reserves through our drilling operations. The seismic data and other technologies that we use when

drilling wells do not allow us to determine conclusively prior to drilling a well whether oil or natural gas is present or can be produced economically. Moreover,

the costs of drilling, completing, and operating wells are often uncertain. Our drilling activities, therefore, may result in the total loss of our investment or a

return on investment significantly below expectation.

Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units

containing the acreage.

Approximately 53% of our net acreage located in the United States is currently undeveloped. Unless production in paying quantities is established on

units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. For

instance, under our current drilling plans, we will lose our rights under approximately 46,000 of the 86,000 acres in the Eagle Ford Shale that we currently

hold. Our drilling plans are subject to change based upon various factors, including drilling results, oil and natural gas prices, cash flow, the availability and

cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and

regulatory approvals.

The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.

We deliver the majority of our oil and natural gas through gathering facilities that we do not own or operate. As a result, we are subject to the risk that

these facilities may be temporarily unavailable due to mechanical reasons or market conditions, or may not be available to us in the future. If we experience

interruptions or loss of pipeline capacity or access to gathering systems that impact a substantial amount of our production, it could have an adverse impact

on our cash flow.

21
Table of Contents

Drilling is a high-risk activity that could result in substantial losses for us.

We conduct a portion of our drilling activities through a wholly-owned drilling subsidiary that operates drilling rigs and provides services to us and

third parties. The activities conducted by the drilling subsidiary are subject to many risks, including well blow-outs, cratering and explosions, pipe failures,

fires, uncontrollable flows of oil, natural gas, brine, or well fluids, other environmental hazards, and risks outside of our control, including, among other

things, the risk of natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases. Substantial losses may be caused by injury or loss of life,

severe damage to or destruction of property, natural resources, and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory

investigation and penalties, and suspension of operations. We maintain insurance against some, but not all, of the risks described above. Generally, pollution

related environmental risks are not fully insurable. We do not insure against business interruption. We cannot assure that our insurance will be fully adequate

to cover other losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.

Our use of hedging transactions could reduce our cash flow and/or result in reported losses.

We periodically enter into hedging agreements for a portion of our anticipated oil, natural gas, and natural gas liquids production. Our commodity

hedging agreements are limited in duration, usually for periods of one year or less; however, we sometimes enter into hedges for longer periods. Should

commodity prices increase after we have entered into a hedging transaction, our cash flows will be lower than they would have been without the hedging

transaction.

For financial reporting purposes, we do not use hedge accounting, thus we are required to record changes in the fair value of our hedging instruments

through our earnings rather than through other comprehensive income had we elected to use hedge accounting. As a consequence, we may report material

unrealized losses or gains on our hedging agreements prior to their expiry. The amount of the actual realized losses or gains will differ and will be based on the

actual prices of the commodities on the settlement dates as compared to the hedged prices contained in the hedging agreements. As a result, our periodic

financial results will be subject to fluctuations related to our derivative instruments.

Moreover, our hedging program may be limited due to certain regulatory constraints. The Dodd-Frank Wall Street Reform and Consumer Protection

Act enacted by Congress, among other things, imposes new requirements and oversight on hedging transactions, including new clearing and margin

requirements. While certain of the implementing regulations are yet to be finalized by the relevant federal agencies, to the extent that they are applicable to us or

our counterparties, we may incur increased costs and cash collateral requirements that could affect our ability to hedge risks associated with our business.

We may incur significant costs related to environmental and other governmental laws and regulations, including those related to “hydraulic

fracturing,” that may materially affect our operations.

Our oil and natural gas operations are subject to various U.S. federal, state, and local laws and regulations, and local and national laws and

regulations in Italy and South Africa. Many of the laws and regulations to which our operations are subject include those relating to the protection of the

environment. We could incur material costs, including clean-up costs, fines, and civil and criminal sanctions and third-party claims for property damage and

personal injury as a result of violations of, or liabilities under, present or future environmental laws and regulations.

We routinely utilize hydraulic fracturing, which is an important and common practice used to stimulate production of hydrocarbons from tight, or

low-permeability formations. State oil and gas commissions typically regulate the process. However, several federal entities, including the EPA, have also

recently asserted potential regulatory authority over hydraulic fracturing. Some states, such as Texas, have adopted, and some states, including others in

which we operate, are considering adopting, regulations that could impose more stringent permitting, disclosure, and well construction requirements on

hydraulic fracturing operations. Some local governmental bodies have adopted or are considering adopting similar regulations. If new laws or regulations that

significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to operate. Restrictions on,

22
Table of Contents

or increased costs of, hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

Recently proposed or finalized rules and guidance imposing more stringent requirements on the oil and gas exploration and production industry

could cause us to incur increased capital expenditures and operating costs as well as decrease our levels of production.

On April 17, 2012, the EPA approved final regulations under the Clean Air Act that, among other things, require additional emissions controls for

natural gas and natural gas liquids production, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic

compounds (“VOCs”) and a separate set of emission standards to address hazardous air pollutants frequently associated with such production activities. The

final regulations require, among other things, the reduction of VOC emissions from natural gas wells through the use of reduced emission completions or

“green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. For well completion operations occurring at such

well sites before January 1, 2015, the final regulations allow operators to capture and direct flowback emissions to completion combustion devices, such as

flares, in lieu of performing green completions. These regulations also establish specific new requirements regarding emissions from dehydrators, storage

tanks, and other production equipment. Compliance with these requirements could increase our costs of development and production, which costs may be

significant.

In addition, federal agencies have recently announced two other regulatory initiatives regarding certain aspects of hydraulic fracturing that could

further increase our costs to operate and decrease our levels of production. On May 4, 2012, the U.S. Department of the Interior announced proposed rules

that, if adopted, would require disclosure of chemicals used in hydraulic fracturing activities upon federal and Indian lands and also would strengthen

standards for well-bore integrity and the management of fluids that return to the surface during and after fracturing operations on federal and Indian lands.

Also on May 4, 2012, the EPA issued draft guidance for federal Safe Drinking Water Act permits issued to oil and natural gas exploration and production

operators using diesel during hydraulic fracturing. The adoption or implementation of these regulatory initiatives could cause us to incur increased

expenditures and decrease our levels of production.

The credit risk of financial institutions could adversely affect us.

We have entered into transactions with counterparties in the financial services industry, including commercial banks, insurance companies, and

their affiliates. These transactions expose us to credit risk in the event of default of our counterparty, principally with respect to hedging agreements but also

insurance contracts and bank lending commitments. Deterioration in the credit markets may impact the credit ratings of our current and potential

counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. See Note 9 to the

Consolidated Financial Statements included in this Annual Report for a more complete discussion of credit risk with respect to our derivative instruments.

We may face liabilities related to the pending bankruptcy of Pacific Energy Resources, Ltd.

In August 2007, we closed on the sale of our oil and gas assets in Alaska (the “Alaska Assets”) to Pacific Energy Resources, Ltd. (“PERL”). In

March 2009, PERL filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. PERL requested, and the bankruptcy court has

approved, abandonment of PERL’s interests in certain of the Alaska Assets. The remaining working interest owners in the Alaska Assets have made the

assertion that, in its role as assignor of the Alaska Assets, Forest should be held liable for any contractual obligations of PERL with respect to the Alaska

Assets, including obligations related to operating costs and for costs associated with the final plugging and decommissioning of wells and platforms. While we

have settled certain litigation relating to the Alaska Assets, litigation relating to decommissioning of the Spurr platform in Cook Inlet remains outstanding.

23
Table of Contents

Item 1B. Unresolved Staff Comments.

As of December 31, 2012, we did not have any SEC staff comments regarding our periodic or current reports that have been unresolved for 180

days or more.

Item 2. Properties.

Information on Properties is contained in Item 1 of this Annual Report on Form 10-K.

Item 3. Legal Proceedings.

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled, Forest Oil

Corporation, et al. v. El Rucio Land & Cattle Company, Inc., et al., which occurred in Harris County, Texas. The third member of the arbitration panel

dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land

and related damages allegedly resulting from operational and reclamation practices employed by Forest in the 1970s, 1980s, and early 1990s. The arbitration

decision awards the claimant $23 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9,

2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55 th Judicial District, in the District

Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest is seeking to have this judgment reversed on appeal and believes it has

meritorious arguments in support thereof.

On May 25, 2012, a lawsuit, styled Augenbaum v. Lone Pine Resources Inc. et al., was brought as a purported class action in the Supreme Court

of the State of New York, New York County against Forest, Lone Pine, certain of Lone Pine’s current and former directors and officers (the “Individual

Defendants”), and certain underwriters (the “Underwriter Defendants”) of Lone Pine’s initial public offering (the “IPO”), which was completed on June 1,

2011. The complaint alleges 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, and that Lone Pine, the Individual Defendants, and the Underwriter Defendants are liable for such violations. The complaint further alleges 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 seek

rescission of the securities purchased in the IPO that they continue to own and rescissionary damages for securities that they have sold. Finally, the complaint

asserts a claim against Forest under Section 15 of the Securities Act, alleging that Forest was a “control person” of Lone Pine at the time of the IPO. The

complaint alleges 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. The complaint does not specify the amount of such damages. Lone Pine

has existing obligations to indemnify Forest, the Individual Defendants, and the Underwriter Defendants in connection with the lawsuit. Forest believes that

these claims are without merit and intends to defend the claim against it vigorously.

 

We are a party to various other lawsuits, claims, and proceedings in the ordinary course of business. These proceedings are subject to uncertainties

inherent in any litigation, and the outcome of these matters is inherently difficult to predict with any certainty. We believe that the amount of any potential loss

associated with these proceedings would not be material to our consolidated financial position; however, in the event of an unfavorable outcome, the potential

loss could have an adverse effect on our results of operations and cash flow.

Item 4. Mine Safety Disclosures.

Not applicable.

24
Table of Contents

PART II

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

Common Stock

Forest has one class of common shares outstanding, its common stock, par value $.10 per share (“Common Stock”). Forest’s Common Stock is

traded on the New York Stock Exchange under the symbol “FST.” On February 21, 2013, our Common Stock was held by 621 holders of record. The

number of holders does not include the shareholders for whom shares are held in a “nominee” or “street” name.

The table below reflects the high and low intraday sales prices per share of the Common Stock on the New York Stock Exchange composite tape, as

well as adjusted prices per share of the Common Stock that reflect the stock dividend distributed by Forest on September 30, 2011. There were no cash

dividends declared on the Common Stock in 2011 or 2012. On February 21, 2013, the closing price of Forest Common Stock was $6.02.

Common Stock Common Stock (As Adjusted)(1)

High Low High Low

2011 First Quarter $ 40.23 $ 32.39 $ 28.56 $ 22.99

Second Quarter 38.65 24.56 27.44 17.44

Third Quarter 28.22 14.14 20.03 10.04

Fourth Quarter 17.22 8.88 17.22 8.88

2012 First Quarter $ 15.15 $ 11.61 $ 15.15 $ 11.61

Second Quarter 13.69 6.22 13.69 6.22

Third Quarter 9.32 5.68 9.32 5.68

Fourth Quarter 9.12 6.06 9.12 6.06

____________________________________________

(1) On September 30, 2011, Forest completed the spin-off of Lone Pine by means of a special stock dividend distributed to all shareholders of Forest Common Stock. The stock

dividend consisted of .61248511 shares of Lone Pine for each outstanding share of Forest Common Stock. Based on this ratio, the value of the stock dividend to Forest

shareholders is deemed by Forest to be equal to $4.18, or the average of the high and low intraday sales prices per share of Lone Pine common stock on September 30, 2011

multiplied by .61248511.

The prices shown in the “As Adjusted” column above for the first through third quarters of 2011 have been adjusted to reflect the stock dividend paid on September 30,

2011. The ratio used for this historical price adjustment is .2901. This represents the ratio of (a) $4.18 to (b) $14.41, the average of the high and low intraday sales prices per

share of Forest Common Stock on September 30, 2011.

Dividend Restrictions

Forest’s present or future ability to pay dividends is governed by (i) the provisions of the New York Business Corporation Law, (ii) Forest’s Restated

Certificate of Incorporation and Bylaws, (iii) the indentures concerning Forest’s 81⁄2% senior notes due 2014, 71⁄4% senior notes due 2019, and 71⁄2% senior

notes due 2020 and (iv) Forest’s bank credit facility dated as of June 30, 2011. The provisions in the indentures pertaining to these senior notes and in the

bank credit facility limit our ability to make restricted payments, which include dividend payments. On March 2, 2006, Forest distributed a special stock

dividend in connection with the spin-off of its offshore Gulf of Mexico operations and, as noted above, on September 30, 2011, Forest distributed a special

stock dividend in connection with the spin-off of Lone Pine; however, Forest has not paid cash dividends on its Common Stock during the past five years.

The future payment of cash dividends, if any, on the Common Stock is within the discretion of the Board of Directors and will depend on Forest’s earnings,

capital requirements, financial condition, and other relevant factors. There is no assurance that Forest will pay any cash dividends. For further information

regarding our

25
Table of Contents

equity securities, our ability to pay dividends on our Common Stock, and the spin-off of Lone Pine, see Notes 3 and 5 to the Consolidated Financial

Statements.

Unregistered Sales of Equity Securities

We did not make any sales of unregistered equity securities during the quarter ended December 31, 2012.

Issuer Purchases of Equity Securities

The table below sets forth information regarding repurchases of our Common Stock during the quarter ended December 31, 2012. The shares

repurchased represent shares of our Common Stock that employees elected to surrender to Forest to satisfy their tax withholding obligations upon the vesting of

shares of restricted stock. Forest does not consider this a share buyback program.

Period

Total # of

Shares Purchased

Average Price

Per Share

Total # of Shares

Purchased as Part of

Publicly Announced

Plans or Programs

Maximum # (or

Approximate Dollar

Value) of Shares that

May Yet be Purchased

Under the Plans or

Programs

October 2012 1,116 $ 8.65 — —

November 2012 6,076 6.29 — —

December 2012 14,503 6.60 — —

Fourth Quarter Total 21,695 6.62 — —

26
Table of Contents

Stock Performance Graph

The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2007 (and the reinvestment of

dividends thereafter) in each of Forest Common Stock, the S&P 500 Index, and the Dow Jones U.S. Exploration and Production Index. We believe that the

Dow Jones U.S. Exploration and Production Index is meaningful because it is an independent, objective view of the performance of other similarly-sized energy

companies.

*$100 invested on 12/31/07 in stock or index, including reinvestment of dividends.

Fiscal year ending December 31.

The information in this Annual Report on Form 10-K appearing under the heading “Stock Performance Graph” is being furnished pursuant to

Item 201(e) of Regulation S-K and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as

provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.

27
Table of Contents

Item 6. Selected Financial Data.

The following table sets forth selected financial and operating data of Forest as of and for each of the years in the five-year period ended December 31,

2012. This data should be read in conjunction with Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of

Operations” and the Consolidated Financial Statements and Notes thereto contained elsewhere in this report. We have completed several oil and gas property

acquisition and divestiture transactions that affect the comparability of the results for the years presented below. See Part I, Item 1 “Business—Acquisition

and Divestiture Activities” and Note 2 to the Consolidated Financial Statements for more information on acquisitions and divestitures.

Year Ended December 31,

2012 2011 2010 2009 2008

(In Thousands, Except Per Share Amounts,

Volumes, and Prices)

FINANCIAL DATA

Oil, natural gas, and natural gas liquids sales(1)

$ 605,523 $ 703,531 $ 707,692 $ 655,579 $ 1,396,669

Net earnings (loss) from continuing operations $ (1,288,931) $ 98,260 $ 189,662 $ (793,789) $ (1,081,446)

Net earnings (loss) from discontinued operations(2)

— 44,569 37,859 (129,344) 55,123

Net earnings (loss) (1,288,931) 142,829 227,521 (923,133) (1,026,323)

Less: net earnings attributable to noncontrolling interest (2)

— 4,987 — — —

Net earnings (loss) attributable to Forest Oil Corporation common

shareholders $ (1,288,931) $ 137,842 $ 227,521 $ (923,133) $ (1,026,323)

Basic earnings (loss) per common share attributable to Forest Oil

Corporation common shareholders: (3)

Earnings (loss) from continuing operations $ (11.21) $ .86 $ 1.68 $ (7.61) $ (12.07)

Earnings (loss) from discontinued operations — .35 .33 (1.24) .61

Basic earnings (loss) per common share attributable to Forest

Oil Corporation common shareholders $ (11.21) $ 1.21 $ 2.01 $ (8.85) $ (11.46)

Diluted earnings (loss) per common share attributable to Forest

Oil Corporation common shareholders: (3)

Earnings (loss) from continuing operations $ (11.21) $ .85 $ 1.67 $ (7.61) $ (12.07)

Earnings (loss) from discontinued operations — .34 .33 (1.24) .61

Diluted earnings (loss) per common share attributable to

Forest Oil Corporation common shareholders $ (11.21) $ 1.19 $ 2.00 $ (8.85) $ (11.46)

Total assets(1) $ 2,201,862 $ 3,381,151 $ 3,070,197 $ 3,169,054 $ 4,555,903

Long-term debt(1) $ 1,862,100 $ 1,693,044 $ 1,869,372 $ 2,022,514 $ 2,641,246

Shareholders’ (deficit) equity $ (42,824) $ 1,193,113 $ 1,352,787 $ 1,079,154 $ 1,672,912

OPERATING DATA(1)

Annual production:

Oil (MBbls) 3,146 2,491 2,357 3,397 3,778

Natural gas (MMcf) 81,008 88,497 101,346 116,029 118,120

NGLs (MBbls) 3,489 3,154 3,589 3,012 3,151

Average sales price:

Oil (per Bbl) $ 96.14 $ 96.22 $ 76.08 $ 56.87 $ 96.85

Natural gas (per Mcf) $ 2.37 $ 3.71 $ 3.99 $ 3.33 $ 7.54

NGLs (per Bbl) $ 31.77 $ 42.91 $ 34.54 $ 25.17 $ 44.54

____________________________________________

(1) Amounts reported relate to continuing operations only. See below for more information regarding discontinued operations.

28
Table of Contents

(2) On June 1, 2011, Forest completed the initial public offering of approximately 18% of the common stock of its then wholly-owned subsidiary, Lone Pine Resources Inc., which

held Forest’s ownership interests in its Canadian operations. On September 30, 2011, Forest distributed, or spun-off, the remaining 82% of Lone Pine by means of a special

stock dividend to Forest’s shareholders. Lone Pine’s results are reported as discontinued operations throughout this Annual Report on Form 10-K.

(3) In June 2008, the Financial Accounting Standards Board issued authoritative accounting guidance that addressed whether instruments granted in share-based payment

transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class

method. This guidance was effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those years. Accordingly,

Forest adopted this guidance as of January 1, 2009. All prior period earnings per share data presented has been adjusted retrospectively to conform to the provisions of this

guidance.

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

All expectations, forecasts, assumptions, and beliefs about our future financial results, condition, operations, strategic plans, and performance are

forward-looking statements, as described in more detail in Part I, Item 1 under the heading “Forward-Looking Statements.” Our actual results may differ

materially because of a number of risks and uncertainties. Some of these risks and uncertainties are detailed in Part I, Item 1A “Risk Factors,” and elsewhere

in this Annual Report on Form 10-K. Historical statements made herein are accurate only as of the date of filing of this Annual Report on Form 10-K with the

SEC, and may be relied upon only as of that date. The following discussion and analysis should be read in conjunction with Forest’s Consolidated Financial

Statements and Notes thereto.

Forest is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and natural

gas liquids primarily in North America. Forest 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. Our total estimated proved reserves as of December 31, 2012 were approximately 1,363 Bcfe, all of which are located in

our one reportable geographical segment - the United States. Our core operational areas are in the Texas Panhandle Area, the Eagle Ford Shale in South Texas,

and the East Texas / North Louisiana Area. See Item 1 “Business” for a discussion of our business strategy and core operational areas of focus.

On June 1, 2011, we completed an initial public offering of approximately 18% of the common stock of our then wholly-owned subsidiary, Lone

Pine Resources Inc. (“Lone Pine”), which held our ownership interests in our Canadian operations. On September 30, 2011, we spun-off our remaining shares

of Lone Pine to our shareholders by means of a special stock dividend of Lone Pine common shares. As a result of the spin-off, Lone Pine’s results of

operations are reported as discontinued operations in our Consolidated Statements of Operations for the periods in which we held a controlling financial interest

in Lone Pine.

2012 Highlights

Forest’s 2012 highlights were as follows:

• Increased total oil and NGL sales volumes to 33% of total equivalent sales volumes compared to 28% in 2011 and 26% in 2010.

• Increased the percentage of oil reserves to 15% of total estimated proved reserves as of December 31, 2012 from 9% as of December 31, 2011, pro

forma for the sales of oil and gas properties in 2012.

• Received cash proceeds of $263 million from the non-core property divestiture program we initiated in 2012. In addition, on February 15, 2013,

we received $307 million from the sale of certain South Texas properties as a continuing part of the divestiture program.

• Continued the development in the central fairway of our Eagle Ford Shale acreage position in Gonzales County, where we have experienced the

most consistent results. We drilled 14 wells in the central fairway of the Eagle Ford Shale during 2012 that had a 30-day average gross production

rate of 490 Boe/d (94% oil) and 13 of the wells had a 90-day average gross production rate of 353 Boe/d (94% oil).

29
Table of Contents

The most productive well completed during 2012 began producing in July and had cumulative production of approximately 70,000 barrels of oil

in its first 180 days.

• Drilled eight Missourian Wash Hogshooter wells during 2012 that had a 30-day average gross production rate of 1,820 Boe/d (67% oil) and a 90-

day average gross production rate of 1,200 Boe/d (64% oil). The most productive well completed during 2012 began producing in January and

had cumulative equivalent production of approximately 450,000 barrels of oil in its first year of sales.

See Item 1 “Business—Recent Trends and 2013 Outlook” for a discussion of recent trends regarding oil, natural gas, and NGL market prices and

our 2013 outlook.

Results of Operations

Forest recorded a net loss in 2012 of $1.3 billion as compared to net earnings from continuing operations of $98 million in 2011. The net loss in

2012 was primarily due to ceiling test write-downs and other non-cash property impairments during 2012 totaling $1.1 billion as well as a $245 million

valuation allowance placed against prior year’s net deferred tax assets primarily as a result of the ceiling test write-downs and property impairments recognized

in 2012. See “Critical Accounting Policies, Estimates, Judgments and Assumptions—Valuation of Deferred Tax Assets” for further discussion of our

valuation allowance. Adjusted EBIDTA, which is a non-generally accepted accounting principles (“GAAP”) performance measure commonly used by

management, securities analysts, and investors that excludes non-cash items such as depletion expense, deferred income tax expense, ceiling test write-downs,

and impairments, was $514 million in 2012 as compared to $551 million in 2011. The decrease of $37 million was primarily attributable to changes in oil,

natural gas, and natural gas liquids (“NGLs”) production and prices as well as changes in realized commodity derivative gains between the two periods. See

“Reconciliation of Non-GAAP Measure” at the end of this Item 7 for a reconciliation of Adjusted EBITDA to the most directly comparable financial measure

calculated and presented in accordance with GAAP.

Oil, Natural Gas, and Natural Gas Liquids Volumes and Revenues

Oil, natural gas, and natural gas liquids sales volumes, revenues, and average sales prices from continuing operations for the years ended

December 31, 2012, 2011, and 2010, are set forth in the table below.

Year Ended December 31,

2012 2011 2010

Sales volumes:

Oil (MBbls) 3,146 2,491 2,357

Natural gas (MMcf) 81,008 88,497 101,346

NGLs (MBbls) 3,489 3,154 3,589

Totals (MMcfe) 120,818 122,367 137,022

Revenues (In Thousands):

Oil $ 302,445 $ 239,695 $ 179,312

Natural gas 192,220 328,510 404,415

NGLs 110,858 135,326 123,965

Totals $ 605,523 $ 703,531 $ 707,692

Average sales price per unit:

Oil ($/Bbl) $ 96.14 $ 96.22 $ 76.08

Natural gas ($/Mcf) 2.37 3.71 3.99

NGLs ($/Bbl) 31.77 42.91 34.54

Totals ($/Mcfe) $ 5.01 $ 5.75 $ 5.16

30
Table of Contents

Equivalent sales volumes from continuing operations decreased 1% in 2012 as compared to 2011, with the 8% decrease in natural gas volumes being

nearly offset by a 26% increase in oil volumes and an 11% increase in NGL volumes. This change in the relative weighting of production by product was the

result of our continued focus on the development of liquids-rich prospects in 2012. Total oil and NGL sales volumes increased to 33% of total equivalent sales

volumes compared to 28% in 2011 and 26% in 2010. Revenues from oil, natural gas, and NGLs were $606 million in 2012 as compared to $704 million in

2011. The $98 million decrease was primarily the result of the decline in the market price for natural gas and NGLs, partially offset by the increase in oil

sales volumes of 655 MBbls, which increased oil revenues in 2012 by $63 million compared to the previous year based on the average sales price realization

of $96.14 per barrel in 2012.

Our equivalent sales volumes from continuing operations decreased 11% in 2011 compared to 2010, primarily due to a decrease in natural gas

production. Total oil, natural gas, and NGL revenues were essentially flat between 2011 and 2010, primarily with increases in oil and NGL prices being offset

by a decrease in natural gas production as well as prices.

The revenues and average sales prices reflected in the table above exclude the effects of commodity derivative instruments because we have elected not

to designate our derivative instruments as cash flow hedges. The table below shows the average realized price per unit from continuing operations including the

effects of commodity derivative instruments we had in place for the periods presented.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Oil:

Average sales price ($/Bbl) $ 96.14 $ 96.22 $ 76.08

Effects of commodity derivatives ($/Bbl) 1.86 (5.05) (1.62)

Average realized price ($/Bbl) $ 98.00 $ 91.17 $ 74.45

Natural gas:

Average sales price ($/Mcf) $ 2.37 $ 3.71 $ 3.99

Effects of commodity derivatives ($/Mcf) 1.13 .88 1.02

Average realized price ($/Mcf) $ 3.51 $ 4.60 $ 5.01

NGLs:

Average sales price ($/Bbl) $ 31.77 $ 42.91 $ 34.54

Effects of commodity derivatives ($/Bbl) .76 (8.92) —

Average realized price ($/Bbl) $ 32.54 $ 33.99 $ 34.54

Totals:

Average sales price ($/Mcfe) $ 5.01 $ 5.75 $ 5.16

Effects of commodity derivatives ($/Mcfe) .83 .31 .73

Average realized price ($/Mcfe) $ 5.84 $ 6.06 $ 5.89

See “Realized and Unrealized Gains and Losses on Derivative Instruments” below for more information on gains and losses relating to our

commodity derivative instruments.

31
Table of Contents

Production Expense

The table below sets forth the detail of production expense from continuing operations for the periods indicated.

Year Ended December 31,

2012 2011 2010

(In Thousands, Except per Mcfe Data)

Production expense:

Lease operating expenses $ 108,027 $ 99,158 $ 92,394

Production and property taxes 34,249 40,632 43,656

Transportation and processing costs 14,633 13,728 13,242

Production expense $ 156,909 $ 153,518 $ 149,292

Production expense per Mcfe:

Lease operating expenses $ .89 $ .81 $ .67

Production and property taxes .28 .33 .32

Transportation and processing costs .12 .11 .10

Production expense per Mcfe $ 1.30 $ 1.25 $ 1.09

Lease Operating Expenses

Lease operating expenses in 2012 were $108 million, or $.89 per Mcfe, compared to $99 million, or $.81 per Mcfe, in 2011. The $.08 per Mcfe

increase in 2012 compared to 2011 was primarily due to increases in water disposal costs and workovers as well as an increase in oil production. Based on

the energy-equivalent ratio of six Mcf of natural gas to one barrel of oil, oil production typically has higher per-unit lease operating costs than does natural gas

production. However, because the market price of oil relative to natural gas is currently well in excess of the six-to-one ratio, the increase in lease operating

expense associated with an increase in oil production is more than offset by the additional revenues realized from oil sales. Lease operating expenses were $99

million, or $.81 per Mcfe, in 2011 compared to $92 million, or $.67 per Mcfe, in 2010. The increase in total and per-unit lease operating expenses was

primarily due to an increase in water disposal costs.

Production and Property Taxes

Production and property taxes, consisting primarily of severance taxes paid on the value of the oil, natural gas, and NGLs sold, were 5.7%, 5.8%,

and 6.2% of oil, natural gas, and NGL sales for the years ended December 31, 2012, 2011, and 2010, respectively. Normal fluctuations occur in this

percentage between periods based upon the timing of approval of incentive tax credits in Texas, changes in tax rates, and changes in the assessed values of oil

and gas properties and equipment for purposes of ad valorem taxes.

Transportation and Processing Costs

Transportation and processing costs were $15 million, or $.12 per Mcfe, in 2012, $14 million, or $.11 per Mcfe, in 2011, and $13 million, or

$.10 per Mcfe, in 2010.

32
Table of Contents

General and Administrative Expense

The following table summarizes the components of general and administrative expense from continuing operations for the periods indicated.

Year Ended December 31,

2012 2011 2010

(In Thousands, Except Per Mcfe Data)

Stock-based compensation costs $ 22,897 $ 35,706 $ 31,475

Stock-based compensation costs capitalized (7,378) (14,886) (11,212)

15,519 20,820 20,263

Other general and administrative costs 74,149 75,792 76,018

Other general and administrative costs capitalized (30,406) (31,507) (31,395)

43,743 44,285 44,623

General and administrative expense $ 59,262 $ 65,105 $ 64,886

General and administrative expense per Mcfe $ .49 $ .53 $ .47

General and administrative expense was $59 million in 2012 compared to $65 million in both 2011 and 2010. The primary reason for the decrease

was due to a decrease in stock-based compensation costs in 2012 compared to 2011. Stock-based compensation costs decreased primarily due to the decrease

in our stock price. Additionally, $12 million in stock-based compensation costs ($7 million of expense, net of capitalized amounts) were recognized in 2011

related to the spin-off of Lone Pine, which caused the forfeiture restrictions to lapse on a portion of each outstanding restricted stock award, thus requiring the

immediate recognition of compensation cost. This decrease in stock-based compensation costs was partially offset by $5 million in accelerated stock-based

compensation costs ($4 million of expense, net of capitalized amounts) related to the termination of our former chief executive officer, which was recognized

during the second quarter of 2012. The percentage of general and administrative costs capitalized remained consistent between the three years presented,

ranging between 39% and 42%.

Depreciation, Depletion, and Amortization

The following table summarizes depreciation, depletion, and amortization expense from continuing operations for the periods indicated.

Year Ended December 31,

2012 2011 2010

(In Thousands, Except Per Mcfe Data)

Depreciation, depletion, and amortization expense $ 280,458 $ 219,684 $ 187,973

Depreciation, depletion, and amortization expense per Mcfe $ 2.32 $ 1.80 $ 1.37

Depreciation, depletion, and amortization expense (“DD&A”) increased $.52 per Mcfe to $2.32 per Mcfe in 2012 compared to $1.80 per Mcfe in

2011. The increase in DD&A from 2011 to 2012 is due primarily to the increase in oil reserve additions since 2011, which typically have higher per-unit

development costs than natural gas reserves. In addition, in 2012, a significant portion of our proved undeveloped natural gas reserves, which have lower

associated development costs than do proved undeveloped oil reserves, were reclassified from proved to probable status in conjunction with the decrease in the

natural gas prices used to determine our proved reserves. This reclassification also contributed to the increase in our DD&A rate.

33
Table of Contents

Ceiling Test Write-Down of Oil and Natural Gas Properties

In 2012, we recorded ceiling test write-downs of our United States cost center totaling $958 million, pursuant to the ceiling test limitation prescribed

by the SEC for companies using the full cost method of accounting. These ceiling test write-downs were primarily a result of the decline in the twelve-month

arithmetic average prices of natural gas and NGLs that were used to calculate the present value of future net revenues from our estimated proved oil and natural

gas reserves throughout 2012. Additional write-downs of our oil and natural gas properties may be required in subsequent periods if, among other things, the

unweighted arithmetic average of the first-day-of-the-month oil, natural gas, or NGL prices used in the calculation of the present value of future net revenues

from estimated production of proved oil and natural gas reserves declines compared to prices used as of December 31, 2012, unproved property values

decrease, estimated proved reserve volumes are revised downward, or costs incurred in exploration, development, or acquisition activities exceed the

discounted future net cash flows from the additional reserves, if any, attributable to the cost center. See “Critical Accounting Policies, Estimates, Judgments

and Assumptions—Full Cost Method of Accounting” for more information regarding ceiling test write-downs.

In April 2012, an Italian regional regulatory body denied approval of an environmental impact assessment associated with our proposal to commence

natural gas production from wells that we drilled and completed in 2007. We are currently appealing the region’s denial; however, until the region’s denial is

reversed or overturned, we determined that we could no longer conclude with reasonable certainty that our Italian natural gas reserves are producible.

Accordingly, we reclassified the Italian reserves from proved to probable effective in the first quarter of 2012 and recorded a ceiling test write-down of our

Italian cost center of $35 million.

Impairment of Properties

During the third quarter of 2012, we recorded a $67 million impairment of our unproved properties in South Africa based on several unsuccessful

attempts to sell the properties for an amount that would allow us to recover the carrying amount of our investment in these properties. Because we have no

proved reserves in South Africa, the impairment was reported as a period expense rather than being added to the costs to be amortized and is included in the

Consolidated Statement of Operations within the “Impairment of properties” line item. In December 2012, we entered into agreements to sell our South African

subsidiaries and abandon a certain exploration right in South Africa. See Note 2 to the Consolidated Financial Statements for more information regarding this

planned divestiture.

In August 2012, we entered into an agreement to sell the majority of our East Texas natural gas gathering assets for $34 million in cash and the

transaction closed in October 2012. During the third quarter of 2012, these assets were written down to their estimated fair value less cost to sell, with a $13

million impairment charge included in the Consolidated Statement of Operations within the “Impairment of properties” line item. See Note 2 to the

Consolidated Financial Statements for more information regarding this divestiture.

Interest Expense

The following table summarizes interest expense from continuing operations for the periods indicated.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Interest costs $ 149,054 $ 160,014 $ 161,139

Interest costs capitalized (7,223) (10,259) (11,248)

Interest expense $ 141,831 $ 149,755 $ 149,891

Interest expense in 2012 totaled $142 million compared to $150 million in 2011. The $8 million decrease in interest expense was primarily

attributable to the redemption of $285 million of 8% senior notes in December 2011 and the redemption of $300 million of 81⁄2% senior notes in October 2012,

partially offset by an increase in interest

34
Table of Contents

costs incurred on borrowings under our bank credit facility in 2012, interest costs on the 71⁄2% senior notes issued in September 2012, and lower capitalized

interest in 2012. Interest costs capitalized relate to our investments in significant unproved acreage positions that are under development. Interest expense totaled

$150 million in both 2011 and 2010.

In order to reduce our concentration of fixed-rate debt, we have entered into fixed-to-floating interest rate swaps under which we have swapped, as of

December 31, 2012, $500 million in notional amount at an 8.5% fixed rate for an equal notional amount at a weighted-average interest rate equal to the 1-

month LIBOR plus approximately 5.9%. We recognized realized gains under these interest rate swaps of $11 million during each of the years ended

December 31, 2012, 2011, and 2010. These gains are recorded as realized gains on derivatives rather than as a reduction to interest expense since we have not

elected to use hedge accounting. See Note 9 to the Consolidated Financial Statements for more information on our interest rate derivatives.

Realized and Unrealized Gains and Losses on Derivative Instruments

The table below sets forth realized and unrealized gains and losses on derivatives from continuing operations, which are recognized under “Costs,

expenses, and other” in our Consolidated Statements of Operations for the periods indicated. See Note 8 and Note 9 to the Consolidated Financial Statements

for more information on our derivative instruments.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Realized (gains) losses on derivative instruments, net:

Oil $ (5,862) $ 12,584 $ 3,825

Natural gas (91,891) (78,247) (103,587)

NGLs (2,667) 28,128 —

Interest (11,352) (11,442) (12,450)

Subtotal realized gains on derivative instruments, net (111,772) (48,977) (112,212)

Unrealized (gains) losses on derivative instruments, net:

Oil (6,324) (10,297) 18,978

Natural gas 43,350 (22,931) (47,078)

NGLs (5,396) (4,314) 9,710

Interest 7,496 (1,545) (19,530)

Subtotal unrealized losses (gains) on derivative instruments, net 39,126 (39,087) (37,920)

Realized and unrealized gains on derivatives, net $ (72,646) $ (88,064) $ (150,132)

35
Table of Contents

Other, Net

The table below sets forth the components of “Other, net” in the Consolidated Statements of Operations for the periods indicated.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Accretion of asset retirement obligations $ 6,663 $ 6,082 $ 6,158

Legal proceeding liabilities 29,251 6,500 —

Loss (gain) on debt extinguishment, net 36,312 — (4,576)

Other, net 11,180 4,582 5,757

$ 83,406 $ 17,164 $ 7,339

See Note 11 to the Consolidated Financial Statements for more information on the components of “Other, net”.

Income Tax

The table below sets forth total income tax and the effective income tax rates related to continuing operations for the periods indicated.

Year Ended December 31,

2012 2011 2010

(In Thousands, Except Percentages)

Current income tax $ (35,538) $ 30,141 $ (13,901)

Deferred income tax 208,975 58,994 123,671

Total income tax $ 173,437 $ 89,135 $ 109,770

Effective income tax rate (16)% 48% 37%

Our effective income tax rates were (16)%, 48%, and 37% for the years ended December 31, 2012, 2011, and 2010, respectively. The significant

difference between our blended federal and state statutory income tax rate of 36% and our effective income tax rate of (16)% in 2012 was primarily due to a

$576 million valuation allowance placed against our deferred tax assets in 2012. Without this valuation allowance, our effective income tax rate would have

been 35% in 2012. The current income tax credit provision in 2012 of $36 million primarily relates to income tax refunds filed during 2012 associated with

tax loss carrybacks to recover income taxes paid in 2009. Our effective income tax rate was 48% in 2011 due to the Canadian dividend tax of $29 million that

was incurred on a stock dividend declared and paid by our former Canadian subsidiary, Lone Pine Resources Canada Ltd. (“LPR Canada”), to Forest, as

parent, immediately before Forest’s contribution of LPR Canada to Lone Pine in conjunction with Lone Pine’s initial public offering. Without the $29 million

dividend tax, our effective income tax rate would have been 38% in 2011.

See “Critical Accounting Policies, Estimates, Judgments and Assumptions— Valuation of Deferred Tax Assets” for further discussion of our

valuation allowance and Note 4 to the Consolidated Financial Statements for a reconciliation of income tax computed using the federal statutory income tax rate

to income tax computed using our effective income tax rate for each period presented.

36
Table of Contents

Discontinued Operations

The results of operations of Lone Pine are presented as discontinued operations in our Consolidated Statements of Operations for 2011 and 2010 due

to the spin-off of Lone Pine on September 30, 2011. See Note 13 to the Consolidated Financial Statements for more information regarding the components of

earnings from discontinued operations.

Liquidity and Capital Resources

Our exploration, development, and acquisition activities require us to make significant operating and capital expenditures. Historically, we have used

cash flow from operations and our bank credit facility as our primary sources of liquidity. To fund large transactions, such as acquisitions and debt

refinancing transactions, we have looked to the private and public capital markets as another source of financing and, as market conditions have permitted,

we have engaged in asset monetization transactions.

Changes in the market prices for oil, natural gas, and natural gas liquids directly impact our level of cash flow generated from operations. Natural

gas accounted for approximately 67% of our total production in 2012 and, as a result, our operations and cash flow are more sensitive to fluctuations in the

market price for natural gas than to fluctuations in the market prices for oil and natural gas liquids. We employ a commodity hedging strategy as an attempt to

moderate the effects of wide fluctuations in commodity prices on our cash flow. As of February 21, 2013, we had hedged, via commodity swaps,

approximately 67 Bcfe of our total projected 2013 production and approximately 29 Bcf of our total projected 2014 production, excluding outstanding

commodity swaptions. This level of hedging will provide a measure of certainty with respect to the cash flow that we will receive for a portion of our future

production. However, these hedging activities may result in reduced income or even financial losses to us. See Part I, Item 1A “Risk Factors— Our use of

hedging transactions could reduce our cash flow and/or result in reported losses,” for further details of the risks associated with our hedging activities. In

the future, we may determine to increase or decrease our hedging positions. As of February 21, 2013, all but one of our derivative instrument counterparties are

lenders, or affiliates of lenders, under our credit facility. See Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Commodity

Price Risk,” below for more information on our derivative contracts.

As noted above, the other primary source of liquidity is our credit facility, which had a borrowing base of $1.07 billion as of December 31, 2012. In

connection with the closing of our South Texas divestiture, the borrowing base was reduced to $900 million effective February 15, 2013. This facility is used

to fund daily operations and to fund acquisitions and refinance debt, as needed and if available. The credit facility is secured by a portion of our assets, with

the facility maturing in June 2016. See “Bank Credit Facility” below for further details. We had $65 million of borrowings outstanding under our credit

facility as of December 31, 2012 and had no borrowings outstanding at February 21, 2013. As noted below under “Bank Credit Facility,” our credit facility

contains a covenant that we will not permit our ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelve-month period

to be greater than 4.5 to 1.0 at any time. Depending on our overall level of indebtedness, this covenant may limit our ability to borrow funds as needed under

our credit facility. See Part I, Item 1A “Risk Factors—Our debt agreements contain restrictive covenants that may limit our ability to respond to changes

in market conditions or pursue business opportunities,” for the risks associated with the restrictive covenants in our debt agreements, including the credit

agreement.

The public and private capital markets have served as our primary source of financing to fund large acquisitions and other exceptional transactions,

such as debt refinancings. In the past, we have issued debt and equity in both the public and private capital markets. For example, we completed a private

offering of $500 million of 71⁄2% senior notes due 2020 in September 2012, using some of the proceeds to redeem $300 million of our 81⁄2% senior notes due

2014. Our ability to access the debt and equity capital markets on economic terms is affected by general economic conditions, the domestic and global

financial markets, the credit ratings assigned to our debt by independent credit rating agencies, our operational and financial performance, the value and

performance of our equity and debt securities, prevailing commodity prices, and other macroeconomic factors outside of our control.

37
Table of Contents

See Note 3 and Note 5 to the Consolidated Financial Statements for more information regarding our debt and equity, respectively.

We also have engaged in asset dispositions as a means of generating additional cash to fund expenditures and enhance our financial flexibility. For

example, during 2012, 2011, and 2010, we sold various non-core assets for approximately $263 million, $121 million, and $139 million, respectively. In

February 2013, we sold all of our oil and natural gas properties located in South Texas, excluding our Eagle Ford Shale oil properties, for net proceeds of $307

million, which we plan to use in March 2013 to redeem the remaining $300 million of our outstanding 81⁄2% senior notes due 2014.

We believe that our cash flows provided by operating activities and the funds available under our credit facility will be sufficient to fund our normal

recurring operating needs, anticipated capital expenditures, and our contractual obligations. However, if our revenue and cash flow decrease in the future as a

result of a deterioration in domestic and global economic conditions, a significant decline in commodity prices, or a continuation of depressed natural gas

prices, we may elect to reduce our planned capital expenditures, as we did in the second half of 2012. We believe that this financial flexibility to adjust our

spending levels will provide us with sufficient liquidity to meet our financial obligations. See Part I, Item 1A “Risk Factors,” for a discussion of the risks and

uncertainties that affect our business and financial and operating results.

Bank Credit Facility

On June 30, 2011, we entered into the Third Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of banks led by

JPMorgan Chase Bank, N.A. (the “Administrative Agent”) consisting of a $1.5 billion credit facility maturing in June 2016. The size of the Credit Facility

may be increased by $300 million, to a total of $1.8 billion, upon agreement between us and the applicable lenders.

Our availability under the Credit Facility is governed by a borrowing base. As of December 31, 2012, the borrowing base under the Credit Facility

was $1.07 billion. The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into consideration

the estimated value of our oil and gas properties based on pricing models determined by the lenders at such time, in accordance with the lenders’ customary

practices for oil and gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. A lowering

of the borrowing base could require us to repay indebtedness in excess of the borrowing base in order to cover the deficiency. The last scheduled semi-annual

redetermination of the borrowing base occurred in October 2012 and resulted in a $50 million reduction to the borrowing base. The next scheduled semi-annual

redetermination of the borrowing base will occur on or about May 1, 2013. In addition to the scheduled semi-annual redeterminations, we and the lenders each

have discretion at any time, but not more often than once during a calendar year, to have the borrowing base redetermined.

The borrowing base is also subject to automatic adjustments if certain events occur, such as if we or any of our Restricted Subsidiaries (as defined

in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated

principal amount of such issued senior notes, excluding any senior unsecured notes that we or any of our Restricted Subsidiaries may issue to refinance senior

notes that were outstanding on June 30, 2011. This was the case in September 2012, when the borrowing base was reduced by $50 million. The borrowing

base is also subject to automatic adjustment if we or any of our Restricted Subsidiaries sell oil and natural gas properties included in the borrowing base, as

applicable, having a fair market value in excess of 10% of the borrowing base then in effect. In this case, the borrowing base will be reduced by an amount

either (i) equal to the percentage of the borrowing base attributable to the sold properties, as determined by the Administrative Agent, or (ii) if none of the

borrowing base is attributable to the sold properties, a value agreed upon by us and the required lenders. The sale of our South Louisiana properties resulted in

an $80 million reduction to the borrowing base when the transaction closed in November 2012 and the sale of our South Texas properties resulted in a $170

million reduction to the borrowing base when the transaction closed in February 2013, bringing the borrowing base to $900 million. See Note 2 to the

Consolidated Financial Statements for more information regarding these divestitures.

38
Table of Contents

The Credit Facility is collateralized by our assets. Under the Credit Facility, we are required to mortgage and grant a security interest in 75% of the

present value of the estimated proved oil and gas properties and related assets. If our corporate credit ratings issued by Moody’s and S&P meet pre-established

levels, the security requirements would cease to apply and, at our request, the banks would release their liens and security interest on our properties.

Borrowings under the Credit Facility bear interest at one of two rates as may be elected by us. Borrowings bear interest at:

(i) the greatest of (a) the prime rate announced by JPMorgan Chase Bank, N.A., (b) the federal funds effective rate from time to time plus 1⁄2 of

1%, and (c) the one-month rate applicable to dollar deposits in the London interbank market for one, two, three or six months (as selected

by us) (the “LIBO Rate”) plus 1%, plus, in the case of each of clauses (a), (b), and (c), 50 to 150 basis points depending on borrowing

base utilization; or

(ii) the LIBO Rate as adjusted for statutory reserve requirements (the “Adjusted LIBO Rate”), plus 150 to 250 basis points, depending on

borrowing base utilization. 

The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with

respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant.

The Credit Facility provides that we will not permit our ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelvemonth period to be greater than 4.5 to 1.0 at any time. Our ratio of total debt outstanding to EBITDA for the twelve-month period ended December 31, 2012, as

calculated in accordance with the Credit Facility, was 4.2. We expect to continue to meet this covenant by maintaining our capital expenditures at levels that

approximate our cash flows from operating activities in subsequent quarters and by using proceeds from the sale of non-core assets such as our South Texas

properties to reduce debt.

Under certain conditions, amounts outstanding under the Credit Facility may be accelerated. Bankruptcy and insolvency events with respect to us or

certain of our subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facility. Subject to notice and cure periods, certain

events of default under the Credit Facility will result in acceleration of the indebtedness under the Credit Facility at the option of the lenders. Such other events

of default include non-payment, breach of warranty, non-performance of obligations under the Credit Facility (including the financial covenant), default on

other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the Credit Facility.

Of the $1.5 billion total nominal amount under the Credit Facility, JPMorgan and ten other banks hold approximately 68% of the total commitments.

With respect to the other 32% of the total commitments, no single lender holds more than 3.3% of the total commitments. Commitment fees accrue on the

amount of unutilized borrowing base. If borrowing base utilization is greater than 50%, commitment fees are 50 basis points of the unutilized amount, and if

borrowing base utilization is 50% or less, commitment fees are 35 basis points of the unutilized amount.

At December 31, 2012, there were outstanding borrowings of $65 million under the Credit Facility at a weighted average interest rate of 2.1% and we

had used the Credit Facility for $2 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $1.0 billion. At February 21,

2013, there were no borrowings outstanding under the Credit Facility and we had used the Credit Facility for $2 million in letters of credit, leaving an unused

borrowing amount under the Credit Facility of $898 million.

Credit Ratings

Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing

discussions with the rating agencies. Moody’s Investors Service and Standard & Poor’s Ratings Services currently rate each series of our senior notes and, in

addition, they have

39
Table of Contents

assigned Forest a general credit rating. Our Credit Facility includes provisions that are linked to our credit ratings. For example, our collateral requirements will

vary based on our credit ratings; however, we do not have any credit rating triggers that would accelerate the maturity of amounts due under the Credit Facility

or the debt issued under the indentures for our senior notes. The indentures for our senior notes also include terms linked to our credit ratings. These terms

allow us greater flexibility if our credit ratings improve to investment grade and other tests have been satisfied, in which event we would not be obligated to

comply with certain restrictive covenants included in the indentures. Our ability to raise funds and the costs of any financing activities will be affected by our

credit ratings at the time any such financing activities are conducted.

Historical Cash Flow

Net cash provided by operating activities of continuing operations, net cash used by investing activities of continuing operations, and net cash

provided (used) by financing activities of continuing operations for the years ended December 31, 2012, 2011, and 2010 were as follows:

Year Ended December 31,

2012 2011 2010

(In Thousands)

Net cash provided by operating activities of continuing operations $ 371,655 $ 398,097 $ 446,725

Net cash used by investing activities of continuing operations (467,782) (759,730) (423,054)

Net cash provided (used) by financing activities of continuing operations 94,171 (173,305) (142,211)

Net cash provided by operating activities of continuing operations is primarily affected by sales volumes and commodity prices net of the effects of

settlements of our derivative contracts and changes in working capital. The decrease in net cash provided by operating activities of continuing operations of

$26 million in 2012 as compared to 2011 was primarily due to a $98 million decrease in revenue that was partially offset by an increase in realized gains on

commodity derivatives of $63 million. The decrease in net cash provided by operating activities of continuing operations of $49 million in 2011 as compared

to 2010 was primarily due to lower realized gains on commodity derivative instruments of $62 million and an increase in current income tax expense of $44

million, both of which were partially offset by a decreased investment in net operating assets (i.e., working capital) of $69 million.

The components of net cash used by investing activities of continuing operations for the years ended December 31, 2012, 2011, and 2010 were as

follows:

Year Ended December 31,

2012 2011 2010

(In Thousands)

Exploration, development, acquisition, and leasehold costs(1)

$ (721,536) $ (873,877) $ (556,988)

Proceeds from sales of assets 262,882 121,115 139,077

Other fixed asset costs (9,128) (6,968) (5,143)

Net cash used by investing activities of continuing operations $ (467,782) $ (759,730) $ (423,054)

____________________________________________

(1) Cash paid for exploration, development, acquisition, and leasehold costs as reflected in the Consolidated Statements of Cash Flows differs from the reported capital

expenditures in the “Capital Expenditures” table below due to the timing of when the capital expenditures are incurred and when the actual cash payments are made as well

as non-cash capital expenditures such as the value of common stock issued for oil and natural gas property acquisitions and capitalized stock-based compensation costs.

Net cash used by investing activities of continuing operations is primarily comprised of expenditures for the acquisition, exploration, and

development of oil and gas properties net of proceeds from the dispositions of oil and gas properties and other capital assets. The $292 million decrease in

cash used for investing activities of continuing operations between 2012 and 2011 was primarily due to a decrease in leasehold acquisition costs and an

increase in proceeds from sales of assets in 2012 as compared to 2011. The $337 million increase in cash used for

40
Table of Contents

investing activities of continuing operations between 2011 and 2010 was primarily due to an increase in leasehold acquisition costs and exploration and

development expenditures in 2011 as compared to 2010.

Net cash provided by financing activities of continuing operations of $94 million in 2012 primarily included the issuance of the 71⁄2% senior notes

due 2020 for net proceeds of $491 million, partially offset by the redemption of the 81⁄2% senior notes due 2014 for $331 million, including the $31 million

call premium, net credit facility repayments of $40 million, and a decrease in bank overdrafts of $24 million. Net cash used by financing activities of

continuing operations of $173 million in 2011 primarily included the redemption of the 8% senior notes due 2011 for $285 million, partially offset by net

credit facility borrowings of $105 million. Net cash used by financing activities of continuing operations of $142 million in 2010 primarily included the

redemption of the 73⁄4% senior notes due 2014 for $152 million, including the $2 million call premium.

Capital Expenditures

Expenditures of continuing operations for property exploration, development, and acquisitions were as follows:

Year Ended December 31,

2012 2011 2010

(In Thousands)

Property Acquisitions:

Proved properties $ — $ — $ 5,823

Unproved properties including leasehold acquisition costs 64,057 204,537 64,593

64,057 204,537 70,416

Exploration:

Direct costs 250,302 272,422 172,746

Overhead capitalized 19,157 20,964 22,241

269,459 293,386 194,987

Development:

Direct costs 380,496 392,406 299,461

Overhead capitalized 18,627 25,429 20,366

399,123 417,835 319,827

Total capital expenditures(1)

$ 732,639 $ 915,758 $ 585,230

____________________________________________

(1) Total capital expenditures include cash expenditures, accrued expenditures, and non-cash capital expenditures including the value of common stock issued for oil and natural

gas property acquisitions and stock-based compensation capitalized under the full cost method of accounting. Total capital expenditures also include changes in estimated

discounted asset retirement obligations of $6 million, $3 million, and $(1) million recorded during the years ended December 31, 2012, 2011, and 2010, respectively.

We have established an exploration and development capital budget of $355 million to $375 million for 2013, which we anticipate will approximate

our cash flow based on expected commodity prices and continues our focus on higher-margin oil opportunities. Primary factors impacting the level of our

capital expenditures include oil and natural gas prices, the volatility in these prices, the cost and availability of oil field services, general economic and market

conditions, and weather disruptions.

41
Table of Contents

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2012:

2013 2014 2015 2016 2017 After 2017 Total

(In Thousands)

Bank debt(1)

$ 4,916 $ 4,916 $ 4,916 $ 67,458 $ — $ — $ 82,206

Senior notes(2)

135,512 413,188 110,000 110,000 110,000 1,707,292 2,585,992

Derivative liabilities(3)

9,347 7,204 — — — — 16,551

Other liabilities(4)

7,510 12,676 8,527 7,741 7,755 86,521 130,730

Operating leases(5)

30,070 24,188 17,573 17,026 10,032 10,135 109,024

Unconditional purchase

obligations(6)

4,165 140 105 — — — 4,410

Total contractual obligations $ 191,520 $ 462,312 $ 141,121 $ 202,225 $ 127,787 $ 1,803,948 $ 2,928,913

____________________________________________

(1) Bank debt consists of the $65 million outstanding balance under our credit facility as of December 31, 2012, as well as the anticipated interest payments on that balance and

commitment and letter of credit fees, all based on the actual rates in effect as of December 31, 2012 and the $1.07 billion borrowing base and $2 million in outstanding letters of

credit as of December 31, 2012, assuming all such balances remain outstanding until the maturity of the credit facility.

(2) Senior notes consist of the principal obligations on our senior notes and senior subordinated notes and anticipated interest payments due on each, assuming all notes remain

outstanding in full until their respective maturities.

(3) Derivative liabilities represent the fair value of our derivative liabilities as of December 31, 2012. The ultimate settlement amounts of our derivative liabilities are unknown,

because they are subject to continuing market risk. See “Critical Accounting Policies, Estimates, Judgments, and Assumptions” below for a more detailed discussion of the

nature of the accounting estimates involved in valuing derivative instruments.

(4) Other liabilities are comprised of pension and other postretirement benefit obligations and asset retirement obligations, for which neither the ultimate settlement amounts nor the

timing of settlement can be precisely determined in advance. See “Critical Accounting Policies, Estimates, Judgments, and Assumptions” below for a more detailed discussion of

the nature of the accounting estimates involved in estimating asset retirement obligations.

(5) Operating leases consist of leases for drilling rigs, compressors, and office facilities and equipment.

(6) Unconditional purchase obligations consist primarily of drilling commitments, throughput obligations, and voice and data services.

We also make delay rental payments to lessors during the primary terms of oil and gas leases to delay drilling or production of wells, usually for one

year. Although we are not obligated to make such payments, discontinuing them would result in the loss of the oil and gas lease. Our estimated maximum

commitment of future delay lease rental payments, through 2020, totaled approximately $5 million as of December 31, 2012.

Off-balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and other transactions that can give rise to off-balance sheet obligations. As of

December 31, 2012, the off-balance sheet arrangements and other transactions that we have entered into include (i) undrawn letters of credit, (ii) operating lease

agreements, (iii) drilling commitments, and (iv) other contractual obligations for which we have recorded estimated liabilities on the balance sheet, but the

ultimate settlement amounts are not fixed and determinable, such as derivative contracts, pension and other postretirement benefit obligations, and asset

retirement obligations. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or

requirements for, capital resources.

Surety Bonds

In the ordinary course of our business and operations, we are required to post surety bonds from time to time with third parties, including

governmental agencies. In addition, while we appeal the arbitration award in Forest Oil Corporation, et al. v. El Rucio Land & Cattle Company, Inc., et al.

(see Item 3 “Legal Proceedings”), we are required to post a supercedeas bond. As of February 21, 2013, we had obtained this supercedeas bond as well as

surety bonds from a number of insurance and bonding institutions covering certain of our current and former

42
Table of Contents

operations in the United States in the aggregate amount of approximately $39 million. See Part I, Item 1 “Business—Industry Regulation” for further

information.

Critical Accounting Policies, Estimates, Judgments, and Assumptions

Full Cost Method of Accounting

The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of

accounting for oil and gas business activities: the full cost method and the successful efforts method. The differences between the two methods can lead to

significant variances in the amounts reported in financial statements. We have elected to follow the full cost method, which is described below.

Under the full cost method, separate cost centers are maintained for each country in which we incur costs. All costs incurred in the acquisition,

exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to

exploration and development activities) are capitalized. The fair value of estimated future costs of site restoration, dismantlement, and abandonment activities

is capitalized, and a corresponding asset retirement obligation liability is recorded.

Capitalized costs applicable to each full cost center are depleted using the units of production method based on conversion to common units of

measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. Changes in estimates of reserves or future development costs are

accounted for in the current quarter and prospectively in the depletion calculations. We have historically updated our quarterly depletion calculations with our

quarter-end reserves estimates. Based on this accounting policy, our December 31, 2012 reserves estimates were used for our fourth quarter 2012 depletion

calculation. See Part I, Item 1, “Business—Reserves” and Note 15 to the Consolidated Financial Statements for a more complete discussion of our estimated

proved reserves as of December 31, 2012.

Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each

quarter for each cost center. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a

fair value based measurement. Rather, it is a standardized mathematical calculation. The test determines a limit, or ceiling, on the book value of oil and gas

properties. That limit is basically the after tax present value of the future net cash flows from estimated proved oil and natural gas reserves calculated using

current prices, which are the unweighted arithmetic average of the first-day-of-the-month oil, natural gas, and NGL prices. This ceiling is compared to the net

book value of the oil and gas properties reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income

taxes exceeds the ceiling, a non-cash write-down is required. In 2012, Forest recorded ceiling test write-downs in the United States cost center totaling $958

million and in the Italian cost center totaling $35 million. The United States ceiling test write-downs were primarily a result of the decline in the twelve-month

arithmetic average prices of natural gas and NGLs.

In areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs, and other costs incurred during the

exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. Investments in

unproved properties are not depleted pending the determination of the existence of proved reserves. If exploration activities result in the establishment of proved

reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion, and amortization, and the application of the ceiling

limitation. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually

significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, geographic and geologic data

obtained relating to the properties, and estimated discounted future net cash flows from the properties. Where it is not practicable to individually assess

properties whose costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment

assessed is added to the costs to be amortized in the appropriate full cost pool, or reported as impairment expense in the Consolidated Statements of

Operations, as applicable. During the year ended December 31, 2012, we recorded a $67 million impairment of our unproved properties in South Africa based

on several unsuccessful

43
Table of Contents

attempts to sell the properties for an amount that would allow us to recover the carrying amount of our investment in these properties. Because we have no

proved reserves in South Africa, and therefore no costs being amortized, the impairment was reported as a period expense and is included in the Consolidated

Statement of Operations within the “Impairment of properties” line item.

Under the alternative successful efforts method of accounting, surrendered, abandoned, and impaired leases, delay lease rentals, exploratory dry

holes, and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis. Impairments are also assessed on a

property-by-property basis and are charged to expense when assessed.

The full cost method is used to account for our oil and gas exploration and development activities because we believe it appropriately reports the costs

of our exploration programs as part of an overall investment in discovering and developing proved reserves.

Goodwill

Goodwill is tested for impairment on an annual basis in the second quarter of the year. In addition, we test goodwill for impairment between annual

tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

In the first step of testing for goodwill impairment, we estimate the fair value of our reporting unit, which we have determined to be our U.S.

geographic operating segment, and compare the fair value with the carrying value of the net assets assigned to the reporting unit. If the fair value is greater than

the carrying value, then no impairment results. If the fair value is less than the carrying value, then we perform a second step and determine the fair value of

the goodwill. In this second step, the fair value of goodwill is determined by deducting the fair value of a reporting unit’s identifiable assets and liabilities from

the fair value of the reporting unit as a whole, as if that reporting unit had just been acquired and the purchase price was being initially allocated. If the fair

value of the goodwill is less than its carrying value for a reporting unit, an impairment charge would be recorded to earnings in the Consolidated Statement of

Operations.

To determine the fair value of our reporting unit, we calculate the market capitalization of our reporting unit based on our quoted stock price. Quoted

prices in active markets are the best evidence of fair value. Because value results from the ability to take advantage of synergies and other benefits that exist

from a collection of assets and liabilities that operate together in a controlled entity, the market capitalization of a reporting unit with publicly traded equity

securities may not be representative of the fair value of the reporting unit as a whole. Therefore, we add a control premium to the market capitalization.

Additionally, we subtract an estimated amount that market participants would attribute to our stock price for the value of our international operations, to

which no goodwill has been allocated. The sum of our market capitalization and control premium, less the international value, is the fair value of our reporting

unit. This amount is then compared to the carrying value of our reporting unit.

In performing step two of the goodwill impairment test, one of the more significant estimates is determining the fair value of our oil and gas

properties. To determine the fair value of our oil and gas properties, we use a discounted cash flow model to value our total estimated reserves, which include

proved, probable, and possible reserves. This approach relies on significant judgments about the quantity of reserves, the timing of the expected production,

the pricing that will be in effect at the time of production, and the appropriate discount rates to be used. Our discount rate assumptions are based on an

assessment of Forest’s weighted average cost of capital.

At the time of our annual 2012 goodwill impairment test, the fair value of the reporting unit exceeded its carrying value. The market capitalization

alone, without adjustments for the control premium and international value, also exceeded the carrying value. Subsequent to the completion of our annual test,

we performed an interim quarterly test due to the loss of key personnel in the second quarter. We did not record a goodwill impairment charge during the year

ended December 31, 2012. However, due to the significant judgments that go into the goodwill impairment test, as discussed above, there can be no assurance

that our goodwill will not be impaired at any time in the future.

44
Table of Contents

Oil and Gas Reserves Estimates

Our estimates of proved reserves are based on the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated

with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions,

operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that

renewal is reasonably certain. The accuracy of any reserves estimate is a function of the quality of available data, engineering and geological interpretation, and

judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs, and workover

costs, all of which may in fact vary considerably from actual results. In addition, as oil, natural gas, and NGL prices that we are required to use pursuant to

SEC regulations change from period-to-period, the estimate of proved reserves will also change and the change can be significant. Despite the inherent

uncertainty in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method

to amortize our oil and gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and gas properties are also subject to a

ceiling test limitation based in part on the quantity of our proved reserves. Finally, these reserves are the basis for our supplemental oil and gas disclosures

included in Note 15 to the Consolidated Financial Statements.

Reference should be made to “Reserves” under Part I, Item 1 “Business,” and “Our estimates of oil and natural gas reserves involve inherent

uncertainty, which could materially affect the quantity and value of our reported reserves and our financial condition ,” under Part I, Item 1A “Risk

Factors,” in this Annual Report on Form 10-K.

Fair Value of Derivative Instruments

We use the income approach in determining the fair value of our derivative instruments, utilizing present value techniques for valuing our swaps and

option-pricing models for valuing our collars, swaptions, and puts. Inputs to these valuation techniques include published forward prices, volatilities, and

credit risk considerations, including the incorporation of published interest rates and credit spreads. The values we report in our financial statements change

as these estimates are revised to reflect changes in market conditions or other factors, many of which are beyond our control.

The accounting treatment for the changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is a cash

flow hedge or a fair value hedge, and upon whether or not the derivative is designated as a hedge. Changes in fair value of a derivative designated as a cash

flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item is recognized in earnings. Changes in the fair

value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the statement of operations, because

changes in fair value of the derivative offset changes in the fair value of the hedged item. Where hedge accounting is not elected, or if a derivative instrument

does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in earnings as other income or expense. We have elected

not to use hedge accounting to account for our derivative instruments and, as a result, all changes in the fair values of our derivative instruments are

recognized in earnings as unrealized gains or losses in the line item “Realized and unrealized gains on derivative instruments, net” in our Consolidated

Statements of Operations.

Due to the volatility of oil, natural gas, and natural gas liquids prices and interest rates, the estimated fair values of our derivative instruments are

subject to large fluctuations from period to period. See Item 7A “Quantitative and Qualitative Disclosures about Market Risk” for a sensitivity analysis of the

change in net fair values of our commodity and interest rate derivatives based on a hypothetical change in commodity prices and interest rates.

45
Table of Contents

Valuation of Deferred Tax Assets

We use the asset and liability method of accounting for income taxes. Under this method, income tax assets and liabilities are determined based on

differences between the financial statement carrying values of assets and liabilities and their respective income tax bases (temporary differences). Income tax

assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect of a change in tax

rates on income tax assets and liabilities is included in earnings in the period in which the change is enacted. The book value of income tax assets is limited to

the amount of the tax benefit that is more likely than not to be realized in the future.

In assessing the need for a valuation allowance on our deferred tax assets, we consider whether it is more likely than not that some portion or all of the

deferred tax assets will be realized. In making this assessment, we consider the scheduled reversal of deferred tax liabilities, available taxes in carryback

periods, tax planning strategies, and projected future taxable income. If the ultimate realization of deferred tax assets is dependent upon future book income,

assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both negative and positive, as to whether it

is more likely than not that a deferred tax asset will be realized.

Negative evidence considered by us included a three-year cumulative book loss driven primarily by the ceiling test write-downs incurred in 2012.

Positive evidence considered by us included forecasted book income in future years based on expected future oil, natural gas, and NGL production and

expected commodity prices based on NYMEX oil and natural gas futures. Based upon the evaluation of what we determined to be relevant evidence, we have

recorded a valuation allowance of $576 million against our deferred tax assets as of December 31, 2012. Although we expect future book income based on

future production and future NYMEX oil and natural gas prices, oil and natural gas prices have been highly volatile over recent years, and only a portion of

our forecasted production is hedged through the end of 2014.

Asset Retirement Obligations

Forest has obligations to remove tangible equipment and restore locations at the end of the oil and gas production operations. Estimating the future

restoration and removal costs, or asset retirement obligations (“ARO”), requires us to make estimates and judgments, because most of the obligations are many

years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs periodically

change, as do regulatory, political, environmental, safety, and public relations considerations.

Inherent in the calculation of the present value of our ARO are numerous assumptions and judgments, including the ultimate settlement amounts,

inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the

extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas

property balance. Increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense, which is included in “Other,

net” in the Consolidated Statements of Operations.

Impact of Recently Issued Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance

Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”), which requires that an entity disclose both gross and net

information about instruments and transactions that are either eligible for offset in the balance sheet or subject to an agreement similar to a master netting

agreement. In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210) Clarifying the Scope of Disclosures about Offsetting Assets and

Liabilities, which limits the scope of ASU No. 2011-11 to derivatives, including bifurcated embedded derivatives, repurchase agreements and reverse

repurchase agreements, and securities borrowing and lending transactions. ASU 2011-11 was issued in order to facilitate comparison of financial statements

prepared under U.S. generally accepted accounting principles (“U.S. GAAP”) and International Financial Reporting Standards by requiring enhanced

disclosures, but does not change existing U.S. GAAP, which permits

46
Table of Contents

balance sheet offsetting. This authoritative guidance is effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within

those annual periods. The adoption of this authoritative guidance will not have an impact on our financial position or results of operations, but will require us

to make additional disclosures regarding our derivative instruments.

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220) Reporting of Amounts Reclassified out of

Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 does not change the current requirements for reporting net earnings or other

comprehensive income in financial statements. However, it requires an entity to provide information about the amounts reclassified out of accumulated other

comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive

income by the respective line items of net earnings, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net earnings in its

entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net earnings, an entity is

required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This authoritative guidance is

effective prospectively for annual reporting periods beginning after December 15, 2012, and interim periods within those annual periods. The adoption of this

authoritative guidance will not have an impact on our financial position or results of operations. We are currently evaluating the impact adoption of this

authoritative guidance may have on our disclosures.

Reconciliation of Non-GAAP Measure

Adjusted EBITDA

In addition to reporting net earnings (loss) from continuing operations as defined under GAAP, we also present adjusted earnings from continuing

operations before interest, income taxes, depreciation, depletion, and amortization (“Adjusted EBITDA”), which is a non-GAAP performance measure.

Adjusted EBITDA consists of net earnings from continuing operations before interest expense, income taxes, depreciation, depletion, and amortization, as well

as other non-cash operating items such as unrealized gains and losses on derivative instruments and accretion of asset retirement obligations and other items

presented in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to, GAAP measurements, such as net earnings

(loss) from continuing operations (its most comparable GAAP financial measure), and our calculations thereof may not be comparable to similarly titled

measures reported by other companies. By eliminating interest, taxes, depreciation, depletion, amortization, and other items from earnings, we believe the

result is a useful measure across time in evaluating our fundamental core operating performance. Management also uses Adjusted EBITDA to manage our

business, including in preparing our annual operating budget and financial projections. We believe that Adjusted EBITDA is also useful to investors because

similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. Our

management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net earnings (loss) from continuing operations and

revenues, to measure operating performance. The following table provides a reconciliation of net earnings (loss) from continuing operations, the most directly

comparable GAAP measure, to Adjusted EBITDA for the periods presented.

47
Table of Contents

Year Ended December 31,

2012 2011 2010

(In Thousands)

Net earnings (loss) from continuing operations $ (1,288,931) $ 98,260 $ 189,662

Income tax expense 173,437 89,135 109,770

Unrealized losses (gains) on derivative instruments, net 39,126 (39,087) (37,920)

Interest expense 141,831 149,755 149,891

Loss (gain) on debt extinguishment, net 36,312 — (4,576)

Accretion of asset retirement obligations 6,663 6,082 6,158

Ceiling test write-down of oil and natural gas properties 992,404 — —

Impairment of properties 79,529 — —

Depreciation, depletion, and amortization 280,458 219,684 187,973

Stock-based compensation 15,074 20,536 18,143

Legal proceeding/severance costs 31,102 6,500 —

Rig stacking 6,604 — —

Adjusted EBITDA from continuing operations $ 513,609 $ 550,865 $ 619,101

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

We are exposed to market risk, including the effects of adverse changes in commodity prices, interest rates, and foreign currency exchange rates as

discussed below.

Commodity Price Risk

We produce and sell natural gas, oil, and NGLs in the United States. As a result, our financial results are affected when prices for these commodities

fluctuate. Such effects can be significant. In order to reduce the impact of fluctuations in commodity prices, or to protect the economics of property

acquisitions, we make use of a commodity hedging strategy. Under our hedging strategy, we enter into commodity swaps, collars, and other derivative

instruments with counterparties who, in general, are lenders, or affiliates of such lenders, in our credit facility. These arrangements, which are typically based

on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons.

Swaps

In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon

published, third-party index if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap

agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis.

As of December 31, 2012, we had entered into the following swaps:

Commodity Swaps

Natural Gas (NYMEX HH) Oil (NYMEX WTI)

Swap Term

Bbtu

Per Day

Weighted

Average

Hedged Price

per MMBtu

Fair Value

(In Thousands)

Barrels

Per Day

Weighted

Average

Hedged Price

per Bbl

Fair Value

(In Thousands)

Calendar 2013 160 $ 3.98 $ 25,349 4,000 $ 95.53 $ 3,341

Calendar 2014 40 4.50 6,775 — — —

48
Table of Contents

Commodity Options

In connection with several natural gas and oil swaps entered into, we granted swaptions to the swap counterparties in exchange for our receiving

premium hedged prices on the natural gas and oil swaps. These swaptions grant the swap counterparties the option to enter into future swaps with us and may

not be exercised until their expiration dates. The table below sets forth the outstanding swaptions as of December 31, 2012.

Commodity Options

Natural Gas (NYMEX HH) Oil (NYMEX WTI)

Underlying Term Option Expiration

Underlying Bbtu

Per Day

Underlying

Hedged Price

per MMBtu

Fair Value

(In Thousands)

Underlying

Barrels

Per Day

Underlying

Hedged Price

per Bbl

Fair Value

(In Thousands)

Gas Swaptions:

Calendar 2014 December 2013 30 $ 4.50 $ (2,349) — $ — $ —

Calendar 2014 December 2013 10 4.51 (778) — — —

Oil Swaptions:

Calendar 2014 December 2013 — — — 2,000 110.00 (1,776)

Calendar 2014 December 2013 — — — 1,000 109.00 (954)

Calendar 2014 December 2013 — — — 2,000 100.00 (3,490)

Calendar 2015 December 2014 — — — 3,000 100.00 (7,204)

The estimated fair value at December 31, 2012 of all our commodity derivative instruments based on various inputs, including published forward

prices, was a net asset of approximately $19 million.

Due to the volatility of oil, natural gas, and NGL prices, the estimated fair values of our commodity derivative instruments are subject to large

fluctuations from period to period. For example, a hypothetical 10% increase in the forward oil, natural gas, and NGL prices used to calculate the fair values

of our commodity derivative instruments at December 31, 2012 would decrease the net fair value of our commodity derivative instruments at December 31,

2012 by approximately $53 million to a net liability of $34 million. It has been our experience that commodity prices are subject to large fluctuations, and we

expect this volatility to continue. Actual gains or losses recognized related to our commodity derivative instruments will likely differ from those estimated at

December 31, 2012 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

Derivative Instruments Entered Into Subsequent to December 31, 2012

Subsequent to December 31, 2012, through February 21, 2013, we entered into the following derivative instruments:

Commodity Swaps

Natural Gas (NYMEX HH)

Swap Term

Bbtu

Per Day

Weighted Average

Hedged Price per MMBtu

Calendar 2014(1) 40 $ 4.19

____________________________________

(1) In connection with entering into these natural gas swaps with premium hedged prices, we amended the terms of existing oil swaptions with the counterparties for Calendar

2014 covering 2,000 barrels per day, changing the hedged price per barrel from $110.00 to $100.00.

49
Table of Contents

Interest Rate Risk

We periodically enter into interest rate derivative agreements in an attempt to manage the mix of fixed and floating interest rates within our debt

portfolio. As of December 31, 2012, we had entered into the following fixed-to-floating interest rate swaps:

Interest Rate Swaps

Remaining Swap Term

Notional Amount

(In Thousands)

Weighted Average

Floating Rate

Weighted Average

Fixed Rate

Fair Value

(In Thousands)

January 2013 - February 2014 $ 500,000 1 month LIBOR + 5.89% 8.50% $ 13,060

The estimated fair value at December 31, 2012 of all our interest rate derivative instruments based on various inputs, including published forward

rates, was an asset of approximately $13 million.

Due to the volatility of interest rates, the estimated fair values of our interest rate derivative instruments are subject to fluctuations from period to

period. For example, a hypothetical 10% increase in the forward 1-month LIBOR interest rates used to calculate the fair values of our interest rate derivative

instruments at December 31, 2012 would decrease the net fair value of our interest rate derivative instruments at December 31, 2012 by approximately $.1

million. Actual gains or losses recognized related to our interest rate derivative instruments will likely differ from those estimated at December 31, 2012 and

will depend exclusively on the future 1-month LIBOR interest rates.

Derivative Fair Value Reconciliation

The table below sets forth the changes that occurred in the fair values of our derivative contracts during the year ended December 31, 2012,

beginning with the fair value of our derivative contracts on December 31, 2011. It has been our experience that commodity prices are subject to large

fluctuations, and we expect this volatility to continue. Due to the volatility of oil, natural gas, and NGL prices, the estimated fair values of our commodity

derivative instruments are subject to large fluctuations from period to period. Actual gains and losses recognized related to our commodity derivative

instruments will likely differ from those estimated at December 31, 2012 and will depend exclusively on the price of the commodities on the specified

settlement dates provided by the derivative contracts.

Fair Value of Derivative Contracts

Commodity Interest Rate Total

(In Thousands)

As of December 31, 2011 $ 50,543 $ 20,556 $ 71,099

Net increase in fair value 68,791 3,856 72,647

Net contract gains recognized (100,420) (11,352) (111,772)

As of December 31, 2012 $ 18,914 $ 13,060 $ 31,974

50
Table of Contents

Interest Rates on Borrowings

The following table presents principal amounts and related interest rates by year of maturity for our bank credit facility and senior notes at

December 31, 2012:

2013 2014(1) 2016 2019 2020 Total

(Dollar Amounts in Thousands)

Bank credit facility:

Borrowings outstanding $ — $ — $ 65,000 $ — $ — $ 65,000

Interest rate(2) — — 2.12% — — 2.12%

Senior notes:

Principal $ 12 $ 300,000 $ — $ 1,000,000 $ 500,000 $ 1,800,012

Fixed interest rate 7.00% 8.50% — 7.25% 7.50% 7.53%

Effective interest rate(3)

7.49% 9.47% — 7.24% 7.50% 7.69%

____________________________________________

(1) On February 15, 2013, we irrevocably called $300 million of 81⁄2% senior notes due 2014 to be redeemed March 17, 2013.

(2) Weighted average interest rate as of December 31, 2012.

(3) The effective interest rates on the senior notes differ from the fixed interest rates due to the amortization of related discounts or premiums on the notes.

Foreign Currency Exchange Rate Risk

We conduct business in Italy and South Africa, and thus are subject to foreign currency exchange rate risk on cash flows related primarily to

expenses and investing transactions. We have not entered into any foreign currency forward contracts or other similar financial instruments to manage this

risk. Expenditures incurred relative to the foreign concessions held by us outside of North America have been primarily United States dollar-denominated.

51
Table of Contents

Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Forest Oil Corporation

We have audited the accompanying consolidated balance sheets of Forest Oil Corporation as of December 31, 2012 and 2011, and the related

consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended

December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these

financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards

require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit

includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the

accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that

our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Forest Oil

Corporation at December 31, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended

December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Forest Oil

Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control-Integrated Framework issued

by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 22, 2013 expressed an unqualified opinion

thereon.

/s/ Ernst & Young LLP

Denver, Colorado

February 22, 2013

52
Table of Contents

FOREST OIL CORPORATION

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

December 31,

2012 2011

ASSETS

Current assets:

Cash and cash equivalents $ 1,056 $ 3,012

Accounts receivable 67,516 79,089

Derivative instruments 40,190 89,621

Other current assets 16,318 38,950

Total current assets 125,080 210,672

Property and equipment, at cost:

Oil and natural gas properties, full cost method of accounting:

Proved, net of accumulated depletion of $8,237,186 and $6,901,997 1,459,312 1,923,145

Unproved 277,798 675,995

Net oil and natural gas properties 1,737,110 2,599,140

Other property and equipment, net of accumulated depreciation and amortization of $46,908 and

$47,989 17,128 51,976

Net property and equipment 1,754,238 2,651,116

Deferred income taxes 14,681 231,116

Goodwill 239,420 239,420

Derivative instruments 8,335 10,422

Other assets 60,108 38,405

$ 2,201,862 $ 3,381,151

LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:

Accounts payable and accrued liabilities $ 164,786 $ 247,880

Accrued interest 23,407 23,259

Derivative instruments 9,347 28,944

Deferred income taxes 14,681 20,172

Current portion of long-term debt 12 —

Other current liabilities 14,092 20,582

Total current liabilities 226,325 340,837

Long-term debt 1,862,088 1,693,044

Asset retirement obligations 56,155 77,898

Derivative instruments 7,204 —

Other liabilities 92,914 76,259

Total liabilities 2,244,686 2,188,038

Commitments and contingencies (Note 10)

Shareholders’ equity:

Preferred stock, none issued and outstanding — —

Common stock, 118,245,320 and 114,525,673 shares issued and outstanding 11,825 11,454

Capital surplus 2,541,859 2,486,994

Accumulated deficit (2,575,994) (1,287,063)

Accumulated other comprehensive loss (20,514) (18,272)

Total shareholders’ (deficit) equity (42,824) 1,193,113

$ 2,201,862 $ 3,381,151

See accompanying Notes to Consolidated Financial Statements.
53
Table of Contents

FOREST OIL CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

Year Ended December 31,

2012 2011 2010

Revenues:

Oil, natural gas, and natural gas liquids sales $ 605,523 $ 703,531 $ 707,692

Interest and other 136 1,026 989

Total revenues 605,659 704,557 708,681

Costs, expenses, and other:

Lease operating expenses 108,027 99,158 92,394

Production and property taxes 34,249 40,632 43,656

Transportation and processing costs 14,633 13,728 13,242

General and administrative 59,262 65,105 64,886

Depreciation, depletion, and amortization 280,458 219,684 187,973

Ceiling test write-down of oil and natural gas properties 992,404 — —

Impairment of properties 79,529 — —

Interest expense 141,831 149,755 149,891

Realized and unrealized gains on derivative instruments, net (72,646) (88,064) (150,132)

Other, net 83,406 17,164 7,339

Total costs, expenses, and other 1,721,153 517,162 409,249

Earnings (loss) from continuing operations before income taxes (1,115,494) 187,395 299,432

Income tax 173,437 89,135 109,770

Net earnings (loss) from continuing operations (1,288,931) 98,260 189,662

Net earnings from discontinued operations — 44,569 37,859

Net earnings (loss) (1,288,931) 142,829 227,521

Less: net earnings attributable to noncontrolling interest — 4,987 —

Net earnings (loss) attributable to Forest Oil Corporation common shareholders $ (1,288,931) $ 137,842 $ 227,521

Basic earnings (loss) per common share attributable to Forest Oil Corporation common

shareholders:

Earnings (loss) from continuing operations $ (11.21) $ .86 $ 1.68

Earnings from discontinued operations — .35 .33

Basic earnings (loss) per common share attributable to Forest Oil Corporation common

shareholders $ (11.21) $ 1.21 $ 2.01

Diluted earnings (loss) per common share attributable to Forest Oil Corporation common

shareholders:

Earnings (loss) from continuing operations $ (11.21) $ .85 $ 1.67

Earnings from discontinued operations — .34 .33

Diluted earnings (loss) per common share attributable to Forest Oil Corporation common

shareholders $ (11.21) $ 1.19 $ 2.00

Amounts attributable to Forest Oil Corporation common shareholders:

Net earnings (loss) from continuing operations $ (1,288,931) $ 98,260 $ 189,662

Net earnings from discontinued operations — 39,582 37,859

Net earnings (loss) $ (1,288,931) $ 137,842 $ 227,521

See accompanying Notes to Consolidated Financial Statements.

54
Table of Contents

FOREST OIL CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

Year Ended December 31,

2012 2011 2010

(In Thousands)

Net earnings (loss) $ (1,288,931) $ 142,829 $ 227,521

Other comprehensive income (loss):

Foreign currency translation (losses) gains — (27,852) 15,153

Defined benefit postretirement plans losses, net of tax (2,242) (6,669) (746)

Total other comprehensive income (loss) (2,242) (34,521) 14,407

Total comprehensive income (loss) (1,291,173) 108,308 241,928

Less: total comprehensive loss attributable to noncontrolling interest — (1,330) —

Total comprehensive income (loss) attributable to Forest Oil Corporation common shareholders $ (1,291,173) $ 109,638 $ 241,928

See accompanying Notes to Consolidated Financial Statements.

5 5
Table of Contents

FOREST OIL CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In Thousands)

Common Stock

Capital

Surplus

Retained

Earnings

(Accumulated

Deficit)

Accumulated

Other

Comprehensive

Income (Loss)

Forest Oil

Corporation

Shareholders’ Equity

(Deficit) Noncontrolling Interest

Total Shareholders’

Shares Amount Equity (Deficit)

Balances at

January 1, 2010 112,337 $ 11,234 $ 2,652,689 $ (1,652,426) $ 67,657 $ 1,079,154 $ — $ 1,079,154

Exercise of stock

options 458 46 8,653 — — 8,699 — 8,699

Employee stock

purchase plan 64 6 1,431 — — 1,437 — 1,437

Restricted stock

issued, net of

forfeitures 889 8 8 (88) — — — — —

Amortization of

stock-based

compensation — — 28,440 — — 28,440 — 28,440

Other, net (153) (15) (6,856) — — (6,871) — (6,871)

Net earnings — — — 227,521 — 227,521 — 227,521

Other comprehensive

income 14,407 14,407 — 14,407

Balances at

December 31, 2010 113,595 11,359 2,684,269 (1,424,905) 82,064 1,352,787 — 1,352,787

Issuance of Lone

Pine Resources Inc.

common stock — — 112,610 — (18,007) 94,603 83,572 178,175

Spin-off of Lone Pine

Resources Inc. — — (333,568) — (54,125) (387,693) (82,242) (469,935)

Exercise of stock

options 192 19 2,363 — — 2,382 — 2,382

Employee stock

purchase plan 96 10 1,331 — — 1,341 — 1,341

Restricted stock

issued, net of

forfeitures 861 86 (86) — — — — —

Amortization of

stock-based

compensation — — 35,449 — — 35,449 — 35,449

Tax impact of

employee stock

option exercises — — (9,608) — — (9,608) — (9,608)

Other, net (218) (20) (5,766) — — (5,786) — (5,786)

Net earnings — — — 137,842 — 137,842 4,987 142,829

Other comprehensive

loss — — — — (28,204) (28,204) (6,317) (34,521)

Balances at

December 31, 2011 114,526 11,454 2,486,994 (1,287,063) (18,272) 1,193,113 — 1,193,113

See accompanying Notes to Consolidated Financial Statements.

5 6
Table of Contents

FOREST OIL CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Continued)

(In Thousands)

Common Stock

Capital

Surplus

Retained

Earnings

(Accumulated

Deficit)

Accumulated

Other

Comprehensive

Income (Loss)

Forest Oil

Corporation

Shareholders’ Equity

(Deficit) Noncontrolling Interest

Total Shareholders’

Shares Amount Equity (Deficit)

Balances at

December 31, 2011 114,526 11,454 2,486,994 (1,287,063) (18,272) 1,193,113 — 1,193,113

Common stock

issued for

acquisition of

unproved oil and

natural gas

properties 2,657 266 36,165 — — 36,431 — 36,431

Employee stock

purchase plan 164 16 1,101 — — 1,117 — 1,117

Restricted stock

issued, net of

forfeitures 1,204 121 (121) — — — — —

Amortization of

stock-based

compensation — — 21,858 — — 21,858 — 21,858

Other, net (306) (32) (4,138) — — (4,170) — (4,170)

Net loss — — — (1,288,931) — (1,288,931) — (1,288,931)

Other comprehensive

loss — — — — (2,242) (2,242) — (2,242)

Balances at

December 31, 2012 118,245 $ 11,825 $ 2,541,859 $ (2,575,994) $ (20,514) $ (42,824) $ — $ (42,824)

See accompanying Notes to Consolidated Financial Statements.

57
Table of Contents

FOREST OIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

Year Ended December 31,

2012 2011 2010

Operating activities:

Net earnings (loss) $ (1,288,931) $ 142,829 $ 227,521

Less: net earnings from discontinued operations — 44,569 37,859

Net earnings (loss) from continuing operations (1,288,931) 98,260 189,662

Adjustments to reconcile net earnings (loss) from continuing operations to net cash provided by operating

activities of continuing operations:

Depreciation, depletion, and amortization 280,458 219,684 187,973

Deferred income tax 208,975 58,994 123,671

Unrealized losses (gains) on derivative instruments, net 39,126 (39,087) (37,920)

Ceiling test write-down of oil and natural gas properties 992,404 — —

Impairment of properties 79,529 — —

Stock-based compensation expense 15,074 20,536 18,143

Accretion of asset retirement obligations 6,663 6,082 6,158

Loss (gain) on debt extinguishment, net 36,312 — (4,576)

Other, net 6,684 8,114 7,039

Changes in operating assets and liabilities:

Accounts receivable 11,573 23,236 2,640

Other current assets 2,630 14,314 24,136

Accounts payable and accrued liabilities (21,164) (6,470) (62,435)

Accrued interest and other 2,322 (5,566) (7,766)

Net cash provided by operating activities of continuing operations 371,655 398,097 446,725

Investing activities:

Capital expenditures for property and equipment:

Exploration, development, acquisition, and leasehold costs (721,536) (873,877) (556,988)

Other fixed assets costs (9,128) (6,968) (5,143)

Proceeds from sales of assets 262,882 121,115 139,077

Net cash used by investing activities of continuing operations (467,782) (759,730) (423,054)

Financing activities:

Proceeds from bank borrowings 1,244,000 160,000 —

Repayments of bank borrowings (1,284,000) (55,000) —

Issuance of senior notes, net of issuance costs 491,250 — —

Redemption of senior notes (330,709) (285,000) (152,038)

Proceeds from the exercise of options and from employee stock purchase plan 1,117 3,723 10,136

Change in bank overdrafts (24,217) 17,116 6,378

Other, net (3,270) (14,144) (6,687)

Net cash provided (used) by financing activities of continuing operations 94,171 (173,305) (142,211)

Cash flows of discontinued operations:

Operating cash flows — 101,292 86,204

Investing cash flows — (255,470) (218,155)

Financing cash flows — 478,324 1,692

Net cash provided (used) by discontinued operations — 324,146 (130,259)

Effect of exchange rate changes on cash — (3,476) (277)

Net decrease in cash and cash equivalents (1,956) (214,268) (249,076)

Net (increase) decrease in cash and cash equivalents of discontinued operations — (289) 8,370

Net decrease in cash and cash equivalents of continuing operations (1,956) (214,557) (240,706)

Cash and cash equivalents of continuing operations at beginning of year 3,012 217,569 458,275

Cash and cash equivalents of continuing operations at end of year $ 1,056 $ 3,012 $ 217,569

Cash paid by continuing operations during the year for:

Interest (net of capitalized amounts) $ 130,154 $ 139,311 $ 140,856

Income taxes (net of refunded amounts) (28,253) 31,782 53,748

Non-cash investing activities of continuing operations:

Increase (decrease) in accrued capital expenditures $ (37,766) $ 27,235 $ 16,405

Common stock issued for acquisition of unproved oil and natural gas properties 36,431 — —
See accompanying Notes to Consolidated Financial Statements.

58
Table of Contents

FOREST OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2012, 2011, and 2010

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Description of the Business

Forest Oil Corporation is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil, natural

gas, and natural gas liquids (“NGLs”) primarily in the United States. Forest 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. Forest holds assets in several exploration and producing areas in the United States and has

exploratory and development interests in two other countries. On June 1, 2011, Forest completed an initial public offering of approximately 18% of the

common stock of its then wholly-owned subsidiary, Lone Pine Resources Inc. (“Lone Pine”), which held Forest’s ownership interests in its Canadian

operations. On September 30, 2011, Forest distributed, or spun-off, its remaining 82% ownership in Lone Pine to Forest’s shareholders by means of a special

stock dividend of Lone Pine shares. See Note 5 for more information regarding the initial public offering and spin-off of Lone Pine. Unless the context

indicates otherwise, the terms “Forest,” the “Company,” “we,” “our,” and “us,” as used in this Annual Report on Form 10-K, refer to Forest Oil Corporation

and its subsidiaries.

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of Forest and its consolidated subsidiaries. As a result of the spin-off, Lone Pine’s results

of operations are reported as discontinued operations. See Note 13 for more information regarding the results of operations of Lone Pine. All intercompany

balances and transactions have been eliminated. Certain amounts in prior years’ financial statements have been reclassified to conform to the 2012 financial

statement presentation.

Assumptions, Judgments, and Estimates

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments, and estimates to determine the

reported amounts of assets, liabilities, revenues, and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions,

judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from

amounts previously established.

The more significant areas requiring the use of assumptions, judgments, and estimates relate to volumes of oil, natural gas, and natural gas liquids

reserves used in calculating depletion, the amount of future net revenues used in computing the ceiling test limitations, and the amount of future capital costs

and abandonment obligations used in such calculations, assessing investments in unproved properties and goodwill for impairment, determining the need for

and the amount of deferred tax asset valuation allowances, and estimating fair values of financial instruments, including derivative instruments.

Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less and all money market funds with no

restrictions on the Company’s ability to withdraw money from the funds to be cash equivalents.

Property and Equipment

The Company uses the full cost method of accounting for oil and gas properties. Separate cost centers are maintained for each country in which the

Company has operations. During the periods presented, the Company’s

5 9
Table of Contents

primary oil and gas operations were conducted in the United States and Canada. Concurrent with the spin-off of Lone Pine on September 30, 2011, the

Company no longer has any operations in Canada. All costs incurred in the acquisition, exploration, and development of properties (including costs of

surrendered and abandoned leaseholds, delay lease rentals, dry holes, and overhead related to exploration and development activities) and the fair value of

estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. During the years ended December 31, 2012, 2011, and

2010, Forest capitalized $37.8 million, $46.4 million, and $42.6 million, respectively, of general and administrative costs (including stock-based

compensation) related to its continuing operations. Interest costs related to significant unproved properties that are under development are also capitalized to oil

and gas properties. During the years ended December 31, 2012, 2011, and 2010, Forest capitalized $7.2 million, $10.3 million, and $11.2 million,

respectively, of interest costs attributed to the unproved properties of its continuing operations.

Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves.

Unproved properties are assessed at least annually to ascertain whether impairment has occurred. Unproved properties whose costs are individually

significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, geographic and geologic data

obtained relating to the properties, and estimated discounted future net cash flows from the properties. Estimated discounted future net cash flows are based on

discounted future net revenues associated with estimated probable and possible reserves, risk adjusted as appropriate. Where it is not practicable to

individually assess the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of

assessing impairment. The amount of impairment assessed is added to the costs to be amortized, or is reported as a period expense, as appropriate.

During the year ended December 31, 2012, Forest recorded a $66.9 million impairment of its unproved properties in South Africa based on several

unsuccessful attempts to sell the properties for an amount that would allow Forest to recover the carrying amount of its investment in these properties. Because

Forest has no proved reserves in South Africa, and therefore no costs being amortized, the impairment was reported as a period expense and is included in the

Consolidated Statement of Operations within the “Impairment of properties” line item. In December 2012, Forest entered into agreements to dispose of its South

African subsidiaries. See Note 2 for more information regarding this planned divestiture.

The Company performs a ceiling test each quarter on a country-by-country basis under the full cost method of accounting. The ceiling test is a

limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized

mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may

not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current prices, excluding the

future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the

cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if

any; less (4) income tax effects related to differences in the book and tax bases of oil and gas properties. Should the net capitalized costs for a cost center exceed

the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs.

In 2012, Forest recorded ceiling test write-downs in the United States cost center totaling $957.6 million and the Italian cost center totaling $34.8

million. The United States write-downs resulted primarily from decreases in natural gas and NGL prices. The Italian write-down resulted from Forest

concluding that its Italian natural gas reserves could no longer be classified as proved reserves, due to an Italian regional regulatory body’s April 2012 denial of

approval of an environmental impact assessment associated with Forest’s proposal to commence natural gas production from wells that Forest drilled and

completed in 2007. Forest is currently appealing the region’s denial.

Gain or loss is not recognized on the sale of oil and natural gas properties unless the sale significantly alters the relationship between capitalized costs

and estimated proved oil and natural gas reserves attributable to a cost center.

60
Table of Contents

Depletion of proved oil and natural gas properties is computed on the units-of-production method, whereby capitalized costs, as adjusted for future

development costs and asset retirement obligations, are amortized over the total estimated proved reserves. The Company uses its quarter-end reserves estimates

to calculate depletion for the current quarter.

Gas gathering assets are depreciated on the units-of-production method whereby the capitalized costs are amortized over the total estimated throughput

of the system. Furniture and fixtures, leasehold improvements, computer hardware and software, and other equipment are depreciated on the straight-line

method over the estimated useful lives of the assets, which range from three to fifteen years.

Asset Retirement Obligations

Forest records the fair value of a liability for an asset retirement obligation in the period in which it is incurred with a corresponding increase in the

carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement obligation is required to be accreted each period to its

present value. Capitalized costs are depleted as a component of the full cost pool using the units-of-production method. Forest’s asset retirement obligations

consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties.

The following table summarizes the activity for the Company’s asset retirement obligations of its continuing operations for the periods indicated:

Year Ended December 31,

2012 2011

(In Thousands)

Asset retirement obligations at beginning of period $ 78,938 $ 73,132

Accretion expense 6,663 6,082

Liabilities incurred 1,412 2,321

Liabilities settled (5,650) (3,103)

Disposition of properties (27,418) (282)

Revisions of estimated liabilities 4,640 788

Asset retirement obligations at end of period 58,585 78,938

Less: current asset retirement obligations (2,430) (1,040)

Long-term asset retirement obligations $ 56,155 $ 77,898

Oil, Natural Gas, and NGL Sales

The Company recognizes revenues when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when:

(i) persuasive evidence of an arrangement exists, (ii) delivery has occurred, (iii) the Company’s price to the buyer is fixed or determinable and (iv) collectibility

is reasonably assured.

When the Company has an interest with other producers in properties from which natural gas is produced, the Company uses the entitlements

method to account for any imbalances. Imbalances occur when the Company sells more or less product than it is entitled to under its ownership percentage.

Revenue is recognized only on the entitlement percentage of volumes sold. Any amount that the Company sells in excess of its entitlement is treated as a liability

and is not recognized as revenue. Any amount of entitlement in excess of the amount the Company sells is recognized as revenue and an asset is accrued. At

December 31, 2012 and 2011, the Company had gas imbalance liabilities of $7.5 million and $7.8 million, respectively, and gas imbalance assets of $6.7

million and $6.9 million, respectively.

61
Table of Contents

In 2012, sales to two purchasers were approximately 19%, or $117.2 million, and 14%, or $82.1 million, respectively, of the Company’s total

revenues. In 2011, sales to one purchaser were approximately 22%, or $151.9 million, of the Company’s total revenues from continuing operations. In 2010,

sales to two purchasers were approximately 20%, or $145.1 million, and 10%, or $73.2 million, respectively, of the Company’s total revenues from

continuing operations. Forest’s revenues from continuing operations are attributable to the United States. Forest believes that the loss of one or more of the

Company’s current oil, natural gas, and NGL purchasers would not have a material adverse effect on the Company’s ability to sell its production, because

any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption.

Accounts Receivable

The components of accounts receivable are as follows:

December 31,

2012 2011

(In Thousands)

Oil, natural gas, and NGL sales $ 50,679 $ 58,799

Joint interest billings 5,845 14,451

Tax incentive refunds due from Texas 6,836 6,604

Other 5,619 698

Allowance for doubtful accounts (1,463) (1,463)

Total accounts receivable $ 67,516 $ 79,089

Forest’s accounts receivable are primarily from purchasers of the Company’s oil, natural gas, and NGL sales and from other exploration and

production companies which own working interests in the properties that the Company operates. This industry concentration could adversely impact Forest’s

overall credit risk because the Company’s customers and working interest owners may be similarly affected by changes in economic and financial market

conditions, commodity prices, and other conditions. Forest’s oil, natural gas, and NGL production is sold to various purchasers in accordance with the

Company’s credit policies and procedures. These policies and procedures take into account, among other things, the creditworthiness of potential purchasers

and concentrations of credit risk. Forest generally requires letters of credit or parental guarantees for receivables from parties that are deemed to have substandard credit or other financial concerns, unless the Company can otherwise mitigate the perceived credit exposure. Forest routinely assesses the collectibility

of all material receivables and accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be

collected and the amount of the reserve can be reasonably estimated.

Income Taxes

The Company recognizes deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial

accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred tax benefits are recorded as an asset to the

extent that management assesses the utilization of such assets to be more likely than not. When the future utilization of some portion of the deferred tax asset is

determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax assets.

Earnings (Loss) per Share

Basic earnings (loss) per share is computed using the two-class method by dividing net earnings (loss) attributable to common stock by the weighted

average number of common shares outstanding during each period. The two-class method of computing earnings (loss) per share is required to be used since

Forest has participating securities. The two-class method is an earnings allocation formula that determines earnings (loss) per share for each class of common

stock and participating security according to dividends declared (or accumulated) and participation

62
Table of Contents

rights in undistributed earnings. Holders of restricted stock issued under Forest’s stock incentive plans have the right to receive non-forfeitable cash and

certain non-cash dividends, participating on an equal basis with common stock. Holders of phantom stock units issued to directors under Forest’s stock

incentive plans also have the right to receive non-forfeitable cash and certain non-cash dividends, participating on an equal basis with common stock, while

phantom stock units issued to employees do not participate in dividends. Stock options issued under Forest’s stock incentive plans do not participate in

dividends. Performance units issued under Forest’s stock incentive plans do not participate in dividends in their current form. Holders of performance units

participate in dividends paid during the performance units’ vesting period only after the performance units vest and common shares are deliverable under the

terms of the performance unit awards. Performance units may vest with no common shares being deliverable, depending on Forest’s shareholder return over

the performance units’ vesting period in relation to the shareholder returns of specified peers. See Note 6 for more information on Forest’s stock-based

incentive awards. In summary, restricted stock issued to employees and directors and phantom stock units issued to directors are participating securities, and

earnings are allocated to both common stock and these participating securities under the two-class method. However, these participating securities do not have

a contractual obligation to share in Forest’s losses. Therefore, in periods of net loss, none of the loss is allocated to these participating securities.

Diluted earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of

common shares outstanding during each period, increasing the denominator to include the number of additional common shares that would have been

outstanding if the dilutive potential common shares (e.g. stock options, unvested restricted stock, unvested phantom stock units that may be settled in shares,

and unvested performance units) had been issued. Additionally, the numerator is also adjusted for certain contracts that provide the issuer or holder with a

choice between settlement methods. Diluted earnings (loss) per share is computed using the more dilutive of the treasury stock method, the contingently

issuable share method, or the two-class method, depending on the security. Under the treasury stock method, the dilutive effect of options, unvested restricted

stock, and unvested phantom stock units is calculated by assuming common shares are issued for these securities at the beginning of the period, with the

proceeds from exercise assumed to be used to purchase common shares at the average market price for the period, and the incremental shares (the difference

between the number of shares assumed issued and the number of shares assumed purchased) included in the denominator of the diluted earnings (loss) per

share computation. Under the contingently issuable share method, the number of contingently issuable shares pursuant to the outstanding performance units

are included in the denominator of the calculation of diluted earnings (loss) per share based on the number of shares, if any, that would be issuable if the end

of the reporting period were the end of the contingency period and if the result would be dilutive. Under the two-class method, the dilutive effect of nonparticipating potential common shares is determined and undistributed earnings are reallocated between common shares and participating securities. No

potential common shares are included in the computation of any diluted per share amount when a net loss exists, as was the case for the year ended

December 31, 2012. Unvested restricted stock grants were not included in the calculations of diluted earnings per share for the years ended December 31, 2011

and 2010 as their inclusion would have an antidilutive effect.

63
Table of Contents

The following reconciles net earnings (loss) as reported in the Consolidated Statements of Operations to net earnings (loss) used for calculating basic

and diluted earnings (loss) per share for the periods presented.

Year Ended December 31,

2012 2011 2010

Continuing

Operations Discontinued Operations Total

Continuing

Operations

Discontinued

Operations Total

Continuing

Operations

Discontinued

Operations Total

(In Thousands)

Net earnings (loss) $ (1,288,931) $ — $ (1,288,931) $ 98,260 $ 44,569 $ 142,829 $ 189,662 $ 37,859 $ 227,521

Net earnings attributable to

noncontrolling interest — — — — (4,987) (4,987) — — —

Net earnings attributable to

participating securities — — — (2,037) (821) (2,858) (3,736) (746) (4,482)

Net earnings (loss)

attributable to common

stock for basic earnings (loss)

per share (1,288,931) — (1,288,931) 96,223 38,761 134,984 185,926 37,113 223,039

Adjustment for liability

classified stock-based

compensation awards — — — — (707) (707) — 500 500

Net earnings (loss) for diluted

earnings (loss) per share $ (1,288,931) $ — $ (1,288,931) $ 96,223 $ 38,054 $ 134,277 $ 185,926 $ 37,613 $ 223,539

The following reconciles basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the periods

presented.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Weighted average common shares outstanding during the period for basic earnings (loss)

per share 114,958 111,690 110,809

Dilutive effects of potential common shares — 1,178 689

Weighted average common shares outstanding during the period, including the effects of

dilutive potential common shares, for diluted earnings (loss) per share 114,958 112,868 111,498

Stock-Based Compensation

Compensation cost is measured at the grant date based on the fair value of the awards (stock options, restricted stock, performance units, employee

stock purchase plan rights) or is measured at the reporting date based on the current stock price (phantom stock units), and is recognized on a straight-line

basis over the requisite service period (usually the vesting period).

Derivative Instruments

The Company records all derivative instruments as either assets or liabilities at fair value, other than the derivative instruments that meet the normal

purchases and sales exception. The Company has not elected to designate its derivative instruments as hedges and, therefore, records all changes in fair value

of its derivative instruments through earnings, with such changes reported in a single line item in the Consolidated Statements of Operations together with

realized gains and losses on the derivative instruments.

64
Table of Contents

Debt Issue Costs

Included in other assets are costs associated with the issuance of our senior notes and our revolving bank credit facility. The remaining unamortized

debt issue costs at December 31, 2012 and 2011 totaled $27.0 million and $25.0 million, respectively, and are being amortized over the life of the respective

debt instruments.

Inventory

Inventories, which are carried at average cost with adjustments made from time to time to recognize, as appropriate, any reductions in value, were

comprised of $4.2 million and $10.1 million of materials and supplies as of December 31, 2012 and 2011, respectively. The Company’s materials and

supplies inventory, which is acquired for use in future drilling operations, is primarily comprised of items such as tubing and casing.

Goodwill

The Company is required to perform an annual impairment test of goodwill in lieu of periodic amortization. The Company performs its annual

goodwill impairment test in the second quarter of the year. In addition, the Company tests goodwill for impairment if an event occurs or circumstances change

that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The impairment test requires the Company to estimate the

fair value of the reporting unit to which goodwill has been assigned and, in some cases, the fair values of the assets and liabilities assigned to the reporting

unit. Although the Company bases its fair value estimates on assumptions it believes to be reasonable, those assumptions are inherently unpredictable and

uncertain. The Company had no goodwill impairments for the years ended December 31, 2012, 2011, and 2010.

Comprehensive Income (Loss)

Comprehensive income (loss) is a term used to refer to net earnings (loss) plus other comprehensive income (loss). Other comprehensive income (loss)

is comprised of revenues, expenses, gains, and losses that under generally accepted accounting principles are reported as separate components of shareholders’

equity instead of net earnings (loss). Items included in the Company’s other comprehensive income (loss) during the last three years are net foreign currency

gains and losses related to the translation of the assets and liabilities of Lone Pine’s Canadian operations prior to the spin-off of Lone Pine on September 30,

2011, and defined benefit postretirement plan losses.

The components of other comprehensive income (loss), both before-tax and net-of-tax, for the years ended December 31, 2012, 2011, and 2010 are as

follows:

Before-Tax Tax (Expense) / Benefit Net-of-Tax

(In Thousands)

Year Ended December 31, 2012:

Defined benefit postretirement plans - net loss $ (2,036) $ (206) $ (2,242)

Other comprehensive loss $ (2,036) $ (206) $ (2,242)

Year Ended December 31, 2011:

Defined benefit postretirement plans - net loss $ (10,417) $ 3,748 $ (6,669)

Foreign currency translation losses (27,852) — (27,852)

Other comprehensive loss $ (38,269) $ 3,748 $ (34,521)

Year Ended December 31, 2010:

Defined benefit postretirement plans - net loss $ (1,221) $ 475 $ (746)

Foreign currency translation gains 15,153 — 15,153

Other comprehensive income $ 13,932 $ 475 $ 14,407

6 5
Table of Contents

The components of accumulated other comprehensive income (loss) attributable to Forest Oil Corporation common shareholders for the years ended

December 31, 2012, 2011, and 2010 are as follows:

Foreign

Currency

Translation

Defined Benefit

Postretirement Plans

Accumulated

Other

Comprehensive

Income (Loss)

(In Thousands)

Balance at December 31, 2009 $ 78,514 $ (10,857) $ 67,657

Other comprehensive income (loss) 15,153 (746) 14,407

Balance at December 31, 2010 93,667 (11,603) 82,064

Other comprehensive loss (21,535) (6,669) (28,204)

Changes in ownership interest in Lone Pine Resources (72,132) — (72,132)

Balance at December 31, 2011 — (18,272) (18,272)

Other comprehensive loss — (2,242) (2,242)

Balance at December 31, 2012 $ — $ (20,514) $ (20,514)

Impact of Recently Issued Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance

Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”), which requires that an entity disclose both gross and net

information about instruments and transactions that are either eligible for offset in the balance sheet or subject to an agreement similar to a master netting

agreement. In January 2013, the FASB issued ASU 2013-01, Balance Sheet (Topic 210) Clarifying the Scope of Disclosures about Offsetting Assets and

Liabilities, which limits the scope of ASU No. 2011-11 to derivatives, including bifurcated embedded derivatives, repurchase agreements and reverse

repurchase agreements, and securities borrowing and lending transactions. ASU 2011-11 was issued in order to facilitate comparison of financial statements

prepared under U.S. generally accepted accounting principles (“U.S. GAAP”) and International Financial Reporting Standards by requiring enhanced

disclosures, but does not change existing U.S. GAAP, which permits balance sheet offsetting. This authoritative guidance is effective for annual reporting

periods beginning on or after January 1, 2013, and interim periods within those annual periods. The adoption of this authoritative guidance will not have an

impact on Forest’s financial position or results of operations, but will require Forest to make additional disclosures regarding its derivative instruments.

In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220) Reporting of Amounts Reclassified out of

Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 does not change the current requirements for reporting net earnings or other

comprehensive income in financial statements. However, it requires an entity to provide information about the amounts reclassified out of accumulated other

comprehensive income by component. In addition, an entity is required to present significant amounts reclassified out of accumulated other comprehensive

income by the respective line items of net earnings, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net earnings in its

entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net earnings, an entity is

required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This authoritative guidance is

effective prospectively for annual reporting periods beginning after December 15, 2012, and interim periods within those annual periods. The adoption of this

authoritative guidance will not have an impact on Forest’s financial position or results of operations. Forest is currently evaluating the impact adoption of this

authoritative guidance may have on its disclosures.

6 6
Table of Contents

(2) PROPERTY AND EQUIPMENT:

Net property and equipment consists of the following as of the dates indicated:

December 31,

2012 2011

(In Thousands)

Oil and gas properties:

Proved $ 9,696,498 $ 8,825,142

Unproved 277,798 675,995

Accumulated depletion (8,237,186) (6,901,997)

Net oil and gas properties 1,737,110 2,599,140

Other property and equipment:

Gas gathering, furniture and fixtures, computer hardware and software, and other equipment 64,036 99,965

Accumulated depreciation and amortization (46,908) (47,989)

Net other property and equipment 17,128 51,976

Total net property and equipment(1) $ 1,754,238 $ 2,651,116

__________________________________________

(1) At December 31, 2011, $98.7 million of the Company’s total net property and equipment was located in foreign countries. This balance was written off during 2012 when the

South African properties were impaired and the Italian natural gas reserves were reclassified from proved to probable, causing a full ceiling test write-down of the Italian cost

center, both of which are discussed in Note 1.

The following table sets forth a summary as of December 31, 2012 of Forest’s unproved properties, all of which are located in the United States, by

the year in which such property costs were incurred:

Total 2012 2011 2010 2009 and Prior

(In Thousands)

Acquisition costs $ 232,176 $ 14,136 $ 46,729 $ 15,530 $ 155,781

Exploration costs 45,622 37,614 3,940 641 3,427

Total unproved oil and gas properties $ 277,798 $ 51,750 $ 50,669 $ 16,171 $ 159,208

The majority of the unproved oil and gas property costs, which are not subject to depletion, relate to oil and gas property acquisitions and leasehold

acquisition costs as well as work-in-progress on various projects. The Company expects that substantially all of its unproved property costs as of

December 31, 2012 will be reclassified to proved properties within ten years.

Divestitures

In August 2012, the Company entered into an agreement to sell the majority of its East Texas natural gas gathering assets for $34.0 million in cash,

subject to customary purchase price adjustments. This transaction closed on October 31, 2012, resulting in Forest receiving net proceeds of $28.8 million.

Forest can also earn up to $9.0 million of additional performance payments contingent on future activity including the number of additional wells drilled by

Forest and connected to the buyer’s gathering facilities. During the first month of 2013, Forest earned and received a performance payment of $1.0 million. In

conjunction with the sale, Forest entered into a ten-year natural gas gathering agreement with the buyer under which Forest will pay market-based gathering

rates and commit the production from its existing and future operated wells located within five miles of the gathering system as it was configured at the time of

sale. During the third quarter of 2012, these assets were written down to their estimated fair

67
Table of Contents

value less cost to sell, resulting in a $12.7 million impairment charge, which is included in the Consolidated Statement of Operations within the “Impairment

of properties” line item. Since there will be a continuation of cash flows between Forest and the disposed component by way of the natural gas gathering

agreement, these assets did not qualify for discontinued operations reporting.

In October 2012, Forest entered into an agreement to sell all of its oil and natural gas properties located in South Louisiana for $220.0 million in cash.

This transaction closed on November 16, 2012 and was subject to customary purchase price adjustments, resulting in Forest receiving net proceeds of $208.4

million.

In December 2012, Forest entered into an agreement with a third party whereby Forest will receive $9.1 million in exchange for Forest abandoning its

Exploration Right covering Block 2C in South Africa. The $9.1 million is payable in two tranches: a first payment of $2.8 million is to be received upon

acceptance from South Africa of the abandonment and a second payment of $6.3 million is to be received in the event that the third party is successful in

being awarded a new Exploration Right in respect of an area encompassing all or part of Forest’s abandoned Block 2C. As of December 31, 2012, neither event

had occurred and, accordingly, neither event is reflected in the Consolidated Financial Statements.

Forest also entered into a separate agreement in December 2012 to sell its South African subsidiary which holds a Production Right related to Block

2A in South Africa. The consideration for this sale is payable in several steps, subject to various contingencies. Upon signing the sale agreement, Forest

received a nonrefundable cash payment of $.7 million. Following approval of the sale by the Minister of Mineral Resources for the government of the Republic

of South Africa, Forest will receive a payment of $1.0 million. If such approval is not received, closing on the sale will not occur. If closing occurs, Forest may

receive further payments, as defined in the agreement. Forest recognized $.6 million of the initial consideration received, net of estimated selling costs, as other

income within the “Other, net” line item in the Consolidated Statement of Operations.

During the year ended December 31, 2012, Forest also sold miscellaneous oil and natural gas properties for proceeds of $25.6 million. During the

years ended December 31, 2011 and 2010, Forest sold various U.S. oil and natural gas properties for total proceeds of $121.0 million and $75.9 million

respectively. During 2010, Forest also entered into sale-leaseback transactions involving drilling rigs, receiving $63.1 million in total proceeds.

Divestitures - Subsequent Event

In January 2013, Forest entered into an agreement to sell all of its oil and natural gas properties located in South Texas, excluding its Eagle Ford Shale

oil properties, for $325.0 million in cash. This transaction closed on February 15, 2013 and was subject to customary purchase price adjustments, resulting

in Forest receiving net proceeds of $307.2 million.

68
Table of Contents

(3) DEBT:

The components of debt are as follows:

December 31, 2012 December 31, 2011

Principal

Unamortized

Premium

(Discount) Total Principal

Unamortized

Premium

(Discount) Total

(In Thousands)

Credit facility $ 65,000 $ — $ 65,000 $ 105,000 $ — $ 105,000

7% senior subordinated notes due 2013 12 — 12 12 — 12

81⁄2% senior notes due 2014 300,000 (3,277) 296,723 600,000 (12,389) 587,611

71⁄4% senior notes due 2019 1,000,000 365 1,000,365 1,000,000 421 1,000,421

71⁄2% senior notes due 2020 500,000 — 500,000 — — —

Total debt 1,865,012 (2,912) 1,862,100 1,705,012 (11,968) 1,693,044

Less: current portion of long-term debt (1)

(12) — (12) — — —

Long-term debt $ 1,865,000 $ (2,912) $ 1,862,088 $ 1,705,012 $ (11,968) $ 1,693,044

____________________________________________

(1) Due in June 2013.

Bank Credit Facility

On June 30, 2011, the Company entered into the Third Amended and Restated Credit Agreement (the “Credit Facility”) with a syndicate of banks led

by JPMorgan Chase Bank, N.A. (the “Administrative Agent”) consisting of a $1.5 billion credit facility maturing in June 2016. The size of the Credit

Facility may be increased by $300.0 million, to a total of $1.8 billion, upon agreement between the applicable lenders and Forest.

Forest’s availability under the Credit Facility is governed by a borrowing base. As of December 31, 2012, the borrowing base under the Credit

Facility was $1.07 billion. The determination of the borrowing base is made by the lenders in their sole discretion, on a semi-annual basis, taking into

consideration the estimated value of Forest’s oil and gas properties based on pricing models determined by the lenders at such time, in accordance with the

lenders’ customary practices for oil and gas loans. The available borrowing amount under the Credit Facility could increase or decrease based on such

redetermination. A lowering of the borrowing base could require Forest to repay indebtedness in excess of the borrowing base in order to cover the deficiency.

The last scheduled semi-annual redetermination of the borrowing base occurred in October 2012 and resulted in a $50.0 million reduction to the borrowing

base. The next scheduled semi-annual redetermination of the borrowing base will occur on or about May 1, 2013. In addition to the scheduled semi-annual

redeterminations, Forest and the lenders each have discretion at any time, but not more often than once during a calendar year, to have the borrowing base

redetermined.

The borrowing base is also subject to automatic adjustments if certain events occur, such as if Forest or any of its Restricted Subsidiaries (as defined

in the Credit Facility) issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated

principal amount of such issued senior notes, excluding any senior unsecured notes that Forest or any of its Restricted Subsidiaries may issue to refinance

senior notes that were outstanding on June 30, 2011. This was the case in September 2012 in connection with the issuance of senior unsecured notes, when the

borrowing base was reduced by $50.0 million. The borrowing base is also subject to automatic adjustment if Forest or any of its Restricted Subsidiaries sell

oil and natural gas properties included in the borrowing base, as applicable, having a fair market value in excess of 10% of the borrowing base then in effect.

In this case, the borrowing base will be reduced by an amount either (i) equal to the percentage of the borrowing base attributable to the sold properties, as

determined by the Administrative Agent, or (ii) if none of the borrowing base is attributable to the sold properties, a value agreed upon by Forest and the

required lenders. The sale of Forest’s South Louisiana properties, discussed in Note 2, resulted in an $80.0 million reduction to the borrowing base when the

transaction closed in November 2012. The February 2013 sale of Forest’s

6 9
Table of Contents

South Texas properties, discussed in Note 2, resulted in a $170.0 million reduction to the borrowing base, which reduced the borrowing base to $900.0

million effective February 15, 2013.

The Credit Facility is collateralized by Forest’s assets. Under the Credit Facility, Forest is required to mortgage and grant a security interest in 75%

of the present value of the estimated proved oil and gas properties and related assets. If Forest’s corporate credit ratings issued by Moody’s and S&P meet preestablished levels, the security requirements would cease to apply and, at Forest’s request, the banks would release their liens and security interest on Forest’s

properties.

Borrowings under the Credit Facility bear interest at one of two rates as may be elected by the Company. Borrowings bear interest at:

(i) the greatest of (a) the prime rate announced by JPMorgan Chase Bank, N.A., (b) the federal funds effective rate from time to time plus 1⁄2 of

1%, and (c) the one-month rate applicable to dollar deposits in the London interbank market for one, two, three or six months (as selected

by Forest) (the “LIBO Rate”) plus 1%, plus, in the case of each of clauses (a), (b), and (c), 50 to 150 basis points depending on borrowing

base utilization; or

(ii) the LIBO Rate as adjusted for statutory reserve requirements (the “Adjusted LIBO Rate”), plus 150 to 250 basis points, depending on

borrowing base utilization. 

The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with

respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions, and also includes a financial covenant.

The Credit Facility provides that Forest will not permit its ratio of total debt outstanding to EBITDA (as adjusted for non-cash charges) for a trailing twelvemonth period to be greater than 4.5 to 1.0 at any time. 

Under certain conditions, amounts outstanding under the Credit Facility may be accelerated. Bankruptcy and insolvency events with respect to

Forest or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facility. Subject to notice and cure periods,

certain events of default under the Credit Facility will result in acceleration of the indebtedness under the Credit Facility at the option of the lenders. Such other

events of default include non-payment, breach of warranty, non-performance of obligations under the Credit Facility (including the financial covenant), default

on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the Credit Facility.

Of the $1.5 billion total nominal amount under the Credit Facility, JPMorgan and ten other banks hold approximately 68% of the total commitments.

With respect to the other 32% of the total commitments, no single lender holds more than 3.3% of the total commitments. Commitment fees accrue on the

amount of unutilized borrowing base. If borrowing base utilization is greater than 50%, commitment fees are 50 basis points of the unutilized amount, and if

borrowing base utilization is 50% or less, commitment fees are 35 basis points of the unutilized amount.

At December 31, 2012, there were outstanding borrowings of $65.0 million under the Credit Facility at a weighted average interest rate of 2.1% and

Forest had used the Credit Facility for $1.6 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $1.0 billion. At

December 31, 2011, there were outstanding borrowings of $105.0 million under the Credit Facility at a weighted average interest rate of 2.1% and Forest had

used the Credit Facility for $2.1 million in letters of credit, leaving an unused borrowing amount under the Credit Facility of $1.1 billion.

81⁄2% Senior Notes Due 2014

On February 17, 2009, Forest issued $600.0 million in principal amount of 81⁄2% senior notes due 2014 (the “81⁄2% Notes”) at 95.15% of par for

net proceeds of $559.8 million, after deducting initial purchaser discounts. The 81⁄2% Notes are redeemable, at the Company’s option, in whole or in part, at

any time at the principal amount, plus

70
Table of Contents

accrued interest, and a make-whole premium. In October 2012, Forest redeemed $300.0 million of the 81⁄2% Notes at 110.24% of par, recognizing a loss of

$36.3 million upon redemption, using proceeds from the issuance of $500.0 million in principal amount of 71⁄2% senior notes due 2020. Due to the

amortization of the discount, the effective interest rate on the 81⁄2% Notes is 9.47%. Interest on the 81⁄2% Notes is payable semiannually on February 15 and

August 15. On February 15, 2013, Forest irrevocably called the remaining $300.0 million of 81⁄2% Notes outstanding to be redeemed on March 17, 2013

using cash on hand and borrowings under the Credit Facility.

71⁄4% Senior Notes Due 2019

On June 6, 2007, Forest issued $750.0 million in principal amount of 71⁄4% senior notes due 2019 (the

“71⁄4% Notes”) at par for net proceeds of $739.2 million, after deducting initial purchaser discounts, and on May 22, 2008, Forest issued an additional

$250.0 million in principal amount of 71⁄4% Notes at 100.25% of par for net proceeds of $247.2 million, after deducting initial purchaser discounts. Due to

the amortization of the premium, the effective interest rate on the 71⁄4% Notes is 7.24%. Interest on the 71⁄4% Notes is payable semiannually on June 15 and

December 15.

The 71⁄4% Notes are redeemable, at Forest’s option, at the prices set forth below, expressed as percentages of the principal amount redeemed, plus

accrued but unpaid interest, if redeemed during the twelve-month period beginning on June 15 of the years indicated below:

2012 103.625%

2013 102.417%

2014 101.208%

2015 and thereafter 100.000%

71⁄2% Senior Notes Due 2020

On September 17, 2012, Forest issued $500.0 million in principal amount of 71⁄2% senior notes due 2020 (the “71⁄2% Notes”) at par for net proceeds

of $491.3 million, after deducting initial purchaser discounts. Net proceeds from the 71⁄2% Notes were used to temporarily reduce outstanding borrowings

under the Credit Facility until $300.0 million in principal amount of the 81⁄2% Notes could be redeemed in October 2012 (after the required notice of redemption

period elapsed). Interest on the 71⁄2% Notes is payable semiannually on March 15 and September 15.

The 71⁄2% Notes are redeemable, at Forest’s option, at the prices set forth below, expressed as percentages of the principal amount redeemed, plus

accrued but unpaid interest, if redeemed during the twelve-month period beginning on September 15 of the years indicated below:

2016 103.750%

2017 101.875%

2018 and thereafter 100.000%

Forest may also redeem the 71⁄2% Notes, in whole or in part, at any time prior to September 15, 2016, at a price equal to the principal amount plus a

make-whole premium, calculated using the applicable Treasury yield plus 0.5%, plus accrued but unpaid interest. In addition, prior to September 15, 2015,

Forest may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the 71⁄2% Notes with the net proceeds of certain equity

offerings at 107.5% of the principal amount of the 71⁄2% Notes, plus any accrued but unpaid interest, if at least 65% of the aggregate principal amount of the

71⁄2% Notes remains outstanding after such redemption and the redemption occurs within 120 days of the date of the closing of such equity offering.

71
Table of Contents

Principal Maturities

Principal maturities of Forest’s debt at December 31, 2012 are as follows:

Principal

Maturities

(In Thousands)

2013 $ 12

2014 300,000

2015 —

2016 65,000

2017 —

Thereafter 1,500,000

(4) INCOME TAXES:

Income Tax Provision

The table below sets forth the provision for income taxes attributable to continuing operations for the periods presented.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Current:

Federal $ (34,733) $ (201) $ (16,393)

Foreign — 28,921 —

State (805) 1,421 2,492

(35,538) 30,141 (13,901)

Deferred:

Federal 202,552 56,482 121,111

State 6,423 2,512 2,560

208,975 58,994 123,671

Total income tax $ 173,437 $ 89,135 $ 109,770

Earnings (loss) from continuing operations before income taxes consists of the following for the periods presented:

Year Ended December 31,

2012 2011 2010

(In Thousands)

United States Federal $ (1,013,801) $ 188,421 $ 301,349

Foreign (101,693) (1,026) (1,917)

$ (1,115,494) $ 187,395 $ 299,432

72
Table of Contents

A reconciliation of reported income tax attributable to continuing operations to the amount of income tax that would result from applying the United

States federal statutory income tax rate to pretax earnings from continuing operations is as follows:

Year Ended December 31,

2012 2011 2010

(In Thousands)

Federal income tax at 35% of earnings before income taxes and discontinued operations $ (390,423) $ 65,947 $ 105,472

State income taxes, net of federal income tax benefits (11,211) 2,214 3,526

Change in valuation allowance 575,570 — —

Canadian dividend tax, net of U.S. tax benefit — 18,460 —

Effect of federal, state, and foreign tax on permanent differences 3,026 4,025 4,030

Other (3,525) (1,511) (3,258)

Total income tax $ 173,437 $ 89,135 $ 109,770

Net Deferred Tax Assets and Liabilities

The components of net deferred tax assets and liabilities at December 31, 2012 and 2011 are as follows:

December 31,

2012 2011

(In Thousands)

Deferred tax assets:

Property and equipment(1) $ 353,352 $ 101,299

Accrual for postretirement benefits 3,134 11,545

Stock-based compensation accruals 10,748 7,921

Net operating loss carryforwards 157,103 60,965

Alternative minimum tax credit carryforward 49,409 54,776

Other 32,278 8,418

Total gross deferred tax assets 606,024 244,924

Less valuation allowance (575,570) —

Net deferred tax assets 30,454 244,924

Deferred tax liabilities:

Unrealized gains on derivative contracts, net (17,429) (25,713)

Amortization of deferred gain on rig sales (10,472) (8,267)

Other (2,553) —

Total gross deferred tax liabilities (30,454) (33,980)

Net deferred tax assets $ — $ 210,944

____________________________________________

(1) Includes deferred tax assets of $28.3 million related to Italy and South Africa as of December 31, 2012.

73
Table of Contents

The net deferred tax assets and liabilities are reflected in the Consolidated Balance Sheets as follows:

December 31,

2012 2011

(In Thousands)

Current deferred tax liabilities $ (14,681) $ (20,172)

Non-current deferred tax assets 14,681 231,116

Net deferred tax assets $ — $ 210,944

Tax Attributes

Net Operating Losses

U.S. federal net operating loss carryforwards (“NOLs”) at December 31, 2012 were approximately $440.3 million, with $32.2 million of NOLs

limited under Section 382 of the Internal Revenue Code scheduled to expire in 2019 and the remaining scheduled to expire after 2030.

The statute of limitations is closed for the Company’s U.S. federal income tax returns for years ending on or before December 31, 2008. Preacquisition returns of acquired businesses are also closed for tax years ending on or before December 31, 2008. However, the Company has utilized, and will

continue to utilize, NOLs (including NOLs of acquired businesses) in its open tax years. The earliest available NOLs were generated in the tax year beginning

January 1, 1999, but are potentially subject to adjustment by the federal tax authorities in the tax year in which they are utilized. Thus, the Company’s

earliest U.S. federal income tax return that is closed to potential audit adjustment is the tax year ending December 31, 1998.

Alternative Minimum Tax Credits

The Alternative Minimum Tax credit carryforward available to reduce future U.S. federal regular taxes equaled an aggregate amount of $49.4 million

at December 31, 2012, which can be carried forward indefinitely.

Accounting for Uncertainty in Income Taxes

The table below sets forth the reconciliation of the beginning and ending balances of the total amounts of unrecognized tax benefits. The Company

records interest accrued related to unrecognized tax benefits in interest expense and penalties in other expense, to the extent they apply. The Company does not

expect a material amount of unrecognized tax benefits to reverse in the next twelve months.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Gross unrecognized tax benefits at beginning of period $ 2,829 $ 3,345 $ 2,665

Increases as a result of tax positions taken during a prior period — — 1,078

Decreases as a result of tax positions taken during a prior period (1,970) (516) (398)

Gross unrecognized tax benefits at end of period $ 859 $ 2,829 $ 3,345

74
Table of Contents

Income Tax Receivables

The table below sets forth income tax receivables as of the dates indicated.

December 31,

2012 2011

(In Thousands)

Current income tax receivable(1) $ — $ 16,481

Non-current income tax receivable (2) 20,651 —

$ 20,651 $ 16,481

____________________________________________

(1) Included in “Other current assets” in the Consolidated Balance Sheets.

(2) Included in “Other assets” in the Consolidated Balance Sheets.

(5) SHAREHOLDERS’ EQUITY:

Common Stock

At December 31, 2012, the Company had 200.0 million shares of common stock, par value $.10 per share, authorized and 118.2 million shares

issued and outstanding.

In February 2012, the Company issued 2.7 million shares of common stock, valued at approximately $36.4 million, as partial consideration

pursuant to a lease purchase agreement whereby Forest acquired leases on unproved oil and natural gas properties in the Permian Basin in Texas.

Preferred Stock

Forest has 10.0 million shares of preferred stock, par value $.01 per share, authorized under its Articles of Incorporation. The preferred stock is

classified into two classes, Senior Preferred Stock and Junior Preferred Stock, each of which shall be issuable in one or more series. Subject to any limitation

prescribed by law, the number of shares in each series and the designation and relative rights, preferences, and limitations of each series shall be fixed by the

Board of Directors of Forest. The class of Senior Preferred Stock consists of 7.4 million shares and the class of Junior Preferred Stock consists of 2.7 million

shares. No preferred stock is issued or outstanding.

Lone Pine Resources Inc.

On June 1, 2011, Forest completed an initial public offering of approximately 18% of the common stock of its then wholly-owned subsidiary, Lone

Pine, which held Forest’s ownership interests in its Canadian operations. In May 2011, as part of a corporate restructuring in anticipation of Lone Pine’s

initial public offering, Lone Pine Resources Canada Ltd. (“LPR Canada”), Forest’s former Canadian subsidiary, declared a stock dividend to Forest

immediately before Forest’s contribution of LPR Canada to Lone Pine, with such stock dividend resulting in Forest incurring a dividend tax payable to

Canadian federal tax authorities of $28.9 million, which Forest paid in June 2011. This dividend tax is classified within the “Income tax” line item in the

Consolidated Statement of Operations. The net proceeds from the initial public offering received by Lone Pine, after deducting underwriting discounts and

commissions and offering expenses, were approximately $178.2 million. Lone Pine used the net proceeds to pay $29.2 million to Forest as partial

consideration for Forest’s contribution to Lone Pine of Forest’s direct and indirect interests in its Canadian operations. Additionally, Lone Pine used the

remaining net proceeds and borrowings under Lone Pine’s credit facility to repay Lone Pine’s outstanding indebtedness owed to Forest, consisting of a note

payable, intercompany advances, and accrued interest, of $400.5 million. On September 30, 2011, Forest distributed, or spun-off, its remaining 82%

ownership in Lone Pine to Forest’s shareholders, by means of a special stock dividend whereby Forest shareholders received .61248511 of a share of Lone

Pine common stock for every share of Forest common stock held. In accordance with applicable authoritative accounting guidance, Forest accounted for the

spin-off based on the carrying value of Lone Pine.

75
Table of Contents

The table below sets forth the effects of changes in Forest’s ownership interest in Lone Pine on Forest’s equity, during the 2011 period in which Forest

had an ownership interest in Lone Pine up to its spin-off on September 30, 2011.

Nine Months Ended

September 30, 2011

(In Thousands)

Net earnings attributable to Forest Oil Corporation common shareholders $ 118,375

Transfers from (to) the noncontrolling interest:

Increase in Forest Oil Corporation’s capital surplus for sale of 15 million Lone Pine Resources Inc. common shares 112,610

Decrease in Forest Oil Corporation’s capital surplus for spin-off of 70 million Lone Pine Resources Inc. common shares (333,568)

Change from net earnings attributable to Forest Oil Corporation common shareholders and transfers from (to) noncontrolling interest $ (102,583)

Rights Agreement

In October 1993, the Board of Directors of Forest adopted a shareholders’ rights plan and entered into a Rights Agreement (the “1993 Agreement”),

which was amended and supplemented in October 2003 by the First Amended and Restated Rights Agreement (taken together with the 1993 Agreement, the

“Rights Agreement”). Under the Rights Agreement, one Preferred Share Purchase Right (the “Rights”) is issued for each outstanding share of the Company’s

common stock. The Rights expire on October 29, 2013, unless earlier exchanged or redeemed. The Rights entitle the holder thereof to purchase 1/100 th of a

preferred share at an initial purchase price of $120 and are exercisable only if a person or group acquires 20% or more of the Company’s common stock or

announces a tender offer that would result in ownership by a person or group of 20% or more of the common stock.

76
Table of Contents

(6) STOCK-BASED COMPENSATION:

Stock-based Compensation Plans

In 2001, the Company adopted the Forest Oil Corporation 2001 Stock Incentive Plan (the “2001 Plan”) and in 2007, the Company adopted the Forest

Oil Corporation 2007 Stock Incentive Plan (the “2007 Plan,” and together with the 2001 Plan, the “Stock-based Compensation Plans”) under which qualified

and non-qualified stock options, restricted stock, performance units, phantom stock units, and other awards may be granted to employees, consultants, and

non-employee directors. The aggregate number of shares of common stock that the Company may issue under the 2007 Plan may not exceed 8.7 million

shares. As of December 31, 2012, the Company had 3.2 million shares available to be issued under the 2007 Plan. The aggregate number of shares of common

stock that the Company could issue under the 2001 Plan was 5.0 million, of which there are no remaining shares to be issued at December 31, 2012.

Compensation Costs

The table below sets forth stock-based compensation related to Forest’s continuing operations for the years ended December 31, 2012, 2011, and

2010, and the remaining unamortized amounts and weighted average amortization period as of December 31, 2012.

Stock

Options

Restricted

Stock

Performance

Units

Phantom Stock

Units Total(1)

(In Thousands)

Year ended December 31, 2012:

Total stock-based compensation costs $ — $ 14,621 $ 6,838 $ 859 $ 22,318

Less: stock-based compensation costs capitalized — (5,219) (1,565) (569) (7,353)

Stock-based compensation costs expensed $ — $ 9,402 $ 5,273 $ 290 $ 14,965

Unamortized stock-based compensation costs as of

December 31, 2012(2) $ — $ 16,588 $ 7,723 $ 6,795 $ 31,106

Weighted average amortization period remaining as of

December 31, 2012 — 1.8 years 1.8 years 2.3 years 1.9 years

Year ended December 31, 2011:

Total stock-based compensation costs $ 1,536 $ 30,234 $ 3,178 $ 156 $ 35,104

Less: stock-based compensation costs capitalized (663) (13,113) (957) (134) (14,867)

Stock-based compensation costs expensed $ 873 $ 17,121 $ 2,221 $ 22 $ 20,237

Year ended December 31, 2010:

Total stock-based compensation costs $ 563 $ 25,377 $ 1,907 $ 3,129 $ 30,976

Less: stock-based compensation costs capitalized (241) (9,492) (469) (1,010) (11,212)

Stock-based compensation costs expensed $ 322 $ 15,885 $ 1,438 $ 2,119 $ 19,764

____________________________________________

(1) The Company also maintains an employee stock purchase plan (which is not included in the table) under which $.4 million, $.5 million, and $.5 million of compensation costs

were recognized for the years ended December 31, 2012, 2011, and 2010, respectively.

(2) The unamortized stock-based compensation costs of the phantom stock units are based on the closing price of the Company’s common stock on December 31, 2012.

77
Table of Contents

Stock Options

The following table summarizes stock option activity in the Stock-based Compensation Plans for the years ended December 31, 2012, 2011, and

2010.

Number of

Options

Weighted

Average

Exercise

Price

Aggregate

Intrinsic

Value

(In Thousands)(1)

Number of

Options

Exercisable

Outstanding at January 1, 2010 1,818,419 $ 21.26 $ 7,387 1,722,216

Granted — —

Exercised (457,974) 18.99 6,027

Cancelled (32,750) 36.28

Outstanding at December 31, 2010 1,327,695 21.67 22,531 1,283,232

Granted — —

Exercised (29,711) 18.55 331

Cancelled (13,273) 25.11

Spin-off adjustment(2) 673,189

Outstanding at September 30, 2011 1,957,900 14.29 187 1,957,900

Granted — —

Exercised (161,834) 11.32 634

Cancelled (29,479) 14.86

Outstanding at December 31, 2011 1,766,587 14.55 2,731 1,766,587

Granted — —

Exercised — — —

Cancelled (895,771) 11.33

Outstanding at December 31, 2012 870,816 $ 17.86 $ — 870,816

____________________________________________

(1) The intrinsic value of a stock option is the amount by which the market value of the underlying stock, as of the date outstanding or exercised, exceeds the exercise price of

the option.

(2) In conjunction with the spin-off of Lone Pine, both the number of options outstanding and the option exercise prices were adjusted in accordance with antidilution provisions

provided for by the Stock-based Compensation Plans.

Stock options are granted at the fair market value of one share of common stock on the date of grant and have a term of ten years. Options granted to

non-employee directors vest immediately and options granted to officers and other employees vest in increments of 25% on each of the first four anniversary

dates of the grant.

The following table summarizes information about options outstanding at December 31, 2012:

Stock Options Outstanding and Exercisable

Range of Exercise Prices Number of Options

Weighted Average

Remaining Contractual

Life (Years)

Weighted Average

Exercise Price

Aggregate Intrinsic Value

(In Thousands)

$9.70 - 11.09 197,002 0.85 $ 10.75 $ —

11.10 - 13.47 38,676 1.57 12.44 —

13.48 - 13.56 244,070 1.86 13.56 —

13.57 - 24.31 167,978 3.05 20.33 —

24.32 - 27.90 223,090 4.42 27.90 —

$9.70 - 27.90 870,816 2.50 $ 17.86 $ —

78
Table of Contents

Restricted Stock, Performance Units, and Phantom Stock Units

The following table summarizes the restricted stock, performance unit, and phantom stock unit activity in the Stock-based Compensation Plans for

the years ended December 31, 2012, 2011, and 2010.

Restricted Stock Performance Units Phantom Stock Units

Number of

Shares

Weighted

Average

Grant

Date

Fair

Value

Vest Date

Fair Value

(In

Thousands)

Number of

Units

Weighted

Average

Grant

Date

Fair

Value

Vest Date

Fair Value

(In

Thousands)

Number of

Units(1)

Weighted

Average

Grant

Date

Fair

Value

Vest Date

Fair Value

(In

Thousands)

Unvested at January 1, 2010 2,028,683 $ 39.44 — $ — 475,063 $ 27.91

Awarded 1,006,163 24.69 264,500 31.63 153,135 25.96

Vested (645,660) 40.66 $ 19,806 — — $ — (65,140) 41.88 $ 1,910

Forfeited (116,865) 36.55 — — (52,449) 35.28

Unvested at December 31, 2010 2,272,321 32.71 264,500 31.63 510,609 24.79

Awarded 1,025,782 27.30 226,000 27.53 500 28.24

Vested (610,681) 61.33 18,416 — — — (52,587) 60.04 1,449

Forfeited (131,330) 23.51 (41,000) 29.98 (25,737) 19.12

Spin-off adjustment(2) — 233,740 225,004

Vested due to spin-off(3) — (19,000) 20.81 — (342,765) 15.15 3,246

Unvested at September 30, 2011 2,556,092 24.18 664,240 19.52 315,024 12.15

Awarded 25,700 15.19 — — 941,300 15.08

Vested (48,560) 28.84 595 — — — (3,505) 17.07 43

Forfeited (59,120) 23.93 (9,120) 20.81 (14,002) 16.21

Unvested at December 31, 2011 2,474,112 24.00 655,120 19.50 1,238,817 14.32

Awarded 1,743,757 9.95 789,500 13.40 718,500 6.73

Vested (956,547) 19.51 7,667 (323,760) 18.18 — (608,543) 14.15 4,511

Forfeited (539,685) 18.65 (181,680) 17.55 (187,037) 13.10

Unvested at December 31, 2012 2,721,637 $ 17.64 939,180 $ 15.20 1,161,737 $ 9.91

__________________________________________

(1) All of the unvested units of phantom stock at December 31, 2012 must be settled in cash. The phantom stock units have been accounted for as a liability within the

Consolidated Financial Statements. Of the 608,543 phantom stock units that vested during 2012, 6,080 units were settled in shares of common stock and 602,463 units

were settled in cash. Of the 398,857 phantom stock units that vested during 2011, 5,500 units were settled in shares of common stock and 393,357 units were settled in

cash. Of the 65,140 phantom stock units that vested in 2010, 63,750 were settled in shares of common stock and 1,390 units were settled in cash.

(2) In conjunction with the spin-off of Lone Pine, the number of performance units and phantom stock units outstanding was adjusted in accordance with antidilution provisions

provided for by the Stock-based Compensation Plans. In addition, the initial stock prices used to measure Forest’s total shareholder returns over the performance periods of the

performance units were adjusted in accordance with the antidilution provisions provided for by the Stock-based Compensation Plans. The number of restricted stock awards

outstanding was not adjusted as a result of the spin-off since holders of restricted stock awards received Lone Pine common shares in the spin-off.

(3) In conjunction with the spin-off of Lone Pine, Lone Pine employees were deemed to have been involuntarily terminated under the terms of their phantom stock agreements,

and, therefore, all phantom stock units held by Lone Pine employees vested on September 30, 2011 and were settled in cash by Lone Pine. The single Lone Pine employee

who held a performance unit award was deemed to have been involuntarily terminated under the terms of his performance unit agreement at the time of the spin-off and,

therefore, his performance units vested on September 30, 2011, but with no shares deliverable under his agreement. No Forest restricted stock awards were held by Lone Pine

employees at the time of the spin-off.

The grant date fair value of the restricted stock was determined by averaging the high and low stock price of a share of common stock as published

by the New York Stock Exchange on the date of grant. The restricted stock generally vests on the third anniversary of the date of the award, but may vest

earlier upon a qualifying disability, death, retirement, certain involuntary terminations, or a change in control of the Company in accordance with the term of

the underlying agreement.

79
Table of Contents

The grant date fair value of the phantom stock units was determined by averaging the high and low stock price of a share of common stock as

published by the New York Stock Exchange on the date of grant. Phantom stock units outstanding prior to the fourth quarter of 2011 generally vest on the

third anniversary of the date of the award. In the fourth quarter of 2011, the Company granted 941,300 phantom stock units to employees, which vest in onethird increments on each of the first three anniversaries of the date of grant. In the fourth quarter of 2012, the Company granted 718,500 phantom stock units

to certain Company officers. The awards vest over a four-year period in accordance with the following schedule: (i) 10% on the first anniversary of the grant

date; (ii) 20% on the second anniversary of the grant date; (iii) 30% on the third anniversary of the grant date; and (iv) 40% on the fourth anniversary of the

grant date. Like restricted stock, phantom stock units may vest earlier due to certain circumstances, as discussed above.

Beginning in 2010, Forest has made annual grants of performance units to its officers. Under the terms of the award agreements, each performance

unit represents a contractual right to receive one share of Forest’s common stock; provided that the actual number of shares that may be deliverable under an

award will range from 0% to 200% of the number of performance units awarded, depending on Forest’s relative total shareholder return in comparison to an

identified peer group over a thirty-six month performance period. The grant date fair values of these awards were determined using a process that takes into

account probability-weighted shareholder returns assuming a large number of possible stock price paths, which are modeled based on inputs such as volatility

and the risk-free interest rate.

Employee Stock Purchase Plan

The Company has a 1999 Employee Stock Purchase Plan (the “ESPP”), under which it is authorized to issue up to .8 million shares of common

stock. Employees who are regularly scheduled to work more than 20 hours per week and more than five months in any calendar year may participate in the

ESPP. Currently, under the terms of the ESPP, employees may elect each calendar quarter to have up to 15% of their annual base earnings withheld to

purchase shares of common stock, up to a limit of $25,000 of common stock per calendar year. The purchase price of a share of common stock purchased

under the ESPP is equal to 85% of the lower of the beginning-of-quarter or end-of-quarter market price. ESPP participants are restricted from selling the shares

of common stock purchased under the ESPP for a period of six months after purchase. As of December 31, 2012, the Company had .1 million shares

available for issuance under the ESPP.

The fair value of each stock purchase right granted under the ESPP during 2012, 2011, and 2010 was estimated using the Black-Scholes option

pricing model. The following assumptions were used to compute the weighted average fair market value of purchase rights granted during the periods

presented:

Year Ended December 31,

2012 2011 2010

Expected option life 3 months 3 months 3 months

Risk free interest rates .02% - .10% .02% - .15% .08% - .17%

Estimated volatility 46% 59% 38%

Dividend yield 0% 0% 0%

Weighted average fair market value of purchase rights

granted $2.43 $5.00 $7.78

(7) EMPLOYEE BENEFITS:

Pension Plans and Postretirement Benefits

The Company has a qualified defined benefit pension plan that covers certain employees and former employees in the United States (the “Forest

Pension Plan”). The Company also has a non-qualified unfunded supplementary retirement plan (the “SERP”) that provides certain retired executives with

defined retirement benefits in excess of qualified plan limits imposed by federal tax law. The Forest Pension Plan and the SERP were curtailed

80
Table of Contents

and all benefit accruals under both plans were suspended effective May 31, 1991. In addition, as a result of The Wiser Oil Company acquisition in 2004,

Forest assumed a noncontributory defined benefit pension plan (the “Wiser Pension Plan,” and together with the “Forest Pension Plan,” the “Pension Plans”).

The Wiser Pension Plan was curtailed and all benefit accruals were suspended effective December 11, 1998. The Forest Pension Plan, the Wiser Pension

Plan, and the SERP are hereinafter collectively referred to as the “Plans.”

In addition to the Plans described above, Forest also provides postretirement benefits to certain employees in the U.S. hired on or prior to January 1,

2009, their beneficiaries, and covered dependents. These benefits, which consist primarily of medical benefits payable on behalf of retirees in the U.S., are

referred to as the “Postretirement Benefits Plan” throughout this Note.

Expected Benefit Payments

As of December 31, 2012, it is anticipated that the Company will be required to provide benefit payments from the Forest Pension Plan trust and the

Wiser Pension Plan trust and fund benefit payments directly for the SERP and the Postretirement Benefits Plan in 2013 through 2017 and in the aggregate for

the years 2018 through 2022 in the following amounts:

2013 2014 2015 2016 2017

2018-

2022

(In Thousands)

Forest Pension Plan(1)

$ 2,399 $ 2,318 $ 2,267 $ 2,196 $ 2,145 $ 9,770

Wiser Pension Plan(1)

852 840 829 820 809 3,845

SERP 130 127 123 119 114 496

Postretirement Benefits Plan 710 704 684 659 675 3,607

____________________________________________

(1) Benefit payments expected to be made to participants in the Forest Pension Plan and Wiser Pension Plan are expected to be paid out of funds held in trusts established for

each plan.

Forest anticipates that it will make contributions in 2013 totaling $1.6 million to the Plans and $.6 million to the Postretirement Benefits Plan, net of

retiree contributions, as applicable.

Benefit Obligations

The following table sets forth the estimated benefit obligations associated with the Company’s Pension Plans and Postretirement Benefits Plan.

Year Ended December 31,

Pension Plans

Postretirement

Benefits Plan

2012 2011 2012 2011

(In Thousands)

Benefit obligation at the beginning of the year $ 44,755 $ 42,213 $ 13,498 $ 9,212

Service cost — — 1,131 825

Interest cost 1,554 1,836 547 529

Actuarial loss 2,902 3,931 2,613 3,645

Benefits paid (3,194) (3,225) (619) (779)

Retiree contributions — — 57 6 6

Benefit obligation at the end of the year $ 46,017 $ 44,755 $ 17,227 $ 13,498

81
Table of Contents

Fair Value of Plan Assets

The Company’s Pension Plans’ assets measured at fair value on a recurring basis are set forth by level within the fair value hierarchy in the table

below as of the dates indicated (see Note 8 for information on the fair value hierarchy). There were no changes to the valuation techniques used during the

period. There are no assets set aside under the SERP and the Postretirement Benefits Plan. During 2012, the amount of contributions in the case of the

Postretirement Benefit Plan, equals the amount of benefits paid.

December 31, 2012 December 31, 2011

Using Quoted

Prices in Active

Markets for

Identical Assets

(Level 1)

Using

Significant

Other

Observable

Inputs

(Level 2)

Using

Significant

Unobservable

Inputs

(Level 3) Total

Using Quoted

Prices in Active

Markets for

Identical Assets

(Level 1)

Using

Significant

Other

Observable

Inputs

(Level 2)

Using

Significant

Unobservable

Inputs

(Level 3) Total

(In Thousands)

Investment funds

—equities:

Research equity

portfolio(1)

$ — $ 10,379 $ — $ 10,379 $ — $ 9,681 $ — $ 9,681

International stock

funds(2)

10,479 — — 10,479 10,363 — — 10,363

Investment funds

—fixed income:

Short-term fund(3)

1,994 — — 1,994 1,549 — — 1,549

Bond fund(4)

4,801 — — 4,801 4,166 — — 4,166

Oil and gas royalty

interests(5)

— — 138 138 — — 198 198

$ 17,274 $ 10,379 $ 138 $ 27,791 $ 16,078 $ 9,681 $ 198 $ 25,957

____________________________________________

(1) This investment fund’s assets are primarily large capitalization U.S. equities. The investment approach of this fund, which typically holds 110 - 130 securities, focuses on

diversifying the investment portfolio by delegating the equity selection process to research analysts with expertise in their respective industries. Industry weights are kept

similar to those of the S&P 500 Index. As of December 31, 2012, the sector weighting of this fund was comprised of the following: information technology ( 18%), financials

(16%), consumer discretionary (14%), health care (13%), energy (11%), consumer staples (11%), and other (17%). The fair value of this investment fund was determined

based on the net asset value per unit provided by the investee. Forest performs procedures to validate the net asset value per unit provided by the investee. Such procedures

include verifying a sample of the net asset values of the underlying securities, which are directly observable in the marketplace.

(2) These three investment funds seek long-term growth of principal and income by investing primarily in diversified portfolios of equity securities issued by foreign, medium-tolarge companies in international markets including emerging markets. The first fund typically holds 50 - 100 securities and seeks to invest in solid, well-established global leaders

with emphasis on strong corporate governance, positive future growth opportunities, and growing return on capital. As of December 31, 2012, the sector weighting of this

fund, which seeks diversification across regions, countries, and market sectors, was comprised of the following: financials ( 25%), health care (16%), consumer discretionary

(13%), information technology (12%), and other (34%). The second fund seeks to obtain growth through long-term appreciation of its holdings, selecting investments based

upon their current fundamentals. As of December 31, 2012, the sector weighting of this fund, which invests in Asian (excluding Japanese) growth equities with a focus on

domestic demand growth rather than an export orientation, was comprised of the following: financials ( 32%), information technology (15%), consumer staples (14%), consumer

discretionary (12%), and other (27%). The third fund seeks to deliver equity-like returns with significantly less volatility by investing in emerging markets equity securities.

As of December 31, 2012, the sector weighting of this fund, which holds approximately 80 positions across the portfolio, with country allocations not exceeding 25%, was

comprised of the following: information technology ( 19%), financials (18%), energy (17%), materials (15%), and other (31%). The fair value of these investment funds was

determined based on the funds’ net asset values per unit, which are directly observable in the marketplace.

(3) This investment fund’s assets are high-quality money market instruments and short-term fixed income securities. This fund is actively managed as an enhanced cash strategy,

seeking to derive excess returns versus money market fund indices by capturing term, transactional liquidity, credit, and volatility premiums. As of December 31, 2012, the

sector weighting of this fund was comprised of the following: government related ( 33%), investment grade (29%), mortgage (13%), and other (25%). The fair value of this

investment fund was determined based on the fund’s net asset value per unit, which is directly observable in the marketplace.

82
Table of Contents

(4) These two investment funds consist of diversified portfolios of bonds. The first fund’s main investments are intermediate maturity fixed income securities with a duration

between three and six years, with a maximum of 10% of the portfolio being invested in securities below Baa grade, and up to 30% of the portfolio being invested in non-U.S.

dollar denominated securities. As of December 31, 2012, the sector weighting of this fund was comprised of the following: mortgage ( 40%), government-related (25%), nonU.S. dollar developed market (11%), investment grade (10%), and other (14%). The second fund seeks to deliver equity-like returns with significantly less volatility by

investing in emerging markets debt securities. As of December 31, 2012, the sector weighting of this fund, which holds approximately 80 positions across the portfolio, with

country allocations not exceeding 25%, was comprised of the following: sovereign-local ( 41%), inflation linked (30%), corporates (22%), and sovereign U.S. dollar denominated

(7%). The fair value of these investment funds was determined based on the funds’ net asset values per unit, which are directly observable in the marketplace.

(5) The oil and gas royalty interests are valued at their estimated discounted future cash flows, which approximate fair value.

The following table sets forth a rollforward of the fair value of the plan assets.

Year Ended December 31,

Pension Plans

Postretirement

Benefits Plan

2012 2011 2012 2011

(In Thousands)

Fair value of plan assets at beginning of the year $ 25,957 $ 29,609 $ — $ —

Actual return on plan assets 4,048 (1,566) — —

Retiree contributions — — 57 6 6

Employer contribution 980 1,139 562 713

Benefits paid (3,194) (3,225) (619) (779)

Fair value of plan assets at the end of the year $ 27,791 $ 25,957 $ — $ —

The following table presents a reconciliation of the beginning and ending balances of the Company’s Pension Plan assets measured at fair value on a

recurring basis using significant unobservable inputs (Level 3).

Year Ended December 31,

2012 2011

Oil and Gas Royalty Interests

(In Thousands)

Balance at beginning of period $ 198 $ 161

Actual return on plan assets 119 6 6

Purchases, sales, and settlements (net) (179) (29)

Transfers in and/or out of Level 3 — —

Balance at end of period $ 138 $ 198

Investments of the Plans

The Pension Plans’ assets are invested with a view toward the long term in order to fulfill the obligations promised to participants as well as to

control future funding levels. The Company continually reviews the levels of funding and investment strategy for the Pension Plans. Generally, the strategy

includes allocating the Pension Plans’ assets between equity securities and fixed income securities, depending on economic conditions and funding needs,

although the strategy does not define any specified minimum exposure for any point in time. The equity and fixed income asset allocation levels in place from

time to time are intended to achieve an appropriate balance between capital appreciation, preservation of capital, and current income.

The overall investment goal for the Pension Plans’ assets is to achieve an investment return that allows the assets to achieve the assumed actuarial

interest rate and to exceed the rate of inflation. In order to manage risk, in terms of volatility, the portfolios are designed with the intent of avoiding a loss of

20% during any single year and

83
Table of Contents

expressing no more volatility than experienced by the S&P 500 Index. The Pension Plans’ investment allocation target is up to 75% equity, with discretion to

vary the mix temporarily, in response to market conditions.

The weighted average asset allocations of the Forest Pension Plan and Wiser Pension Plan are set forth in the following table as of the dates indicated:

December 31,

Forest

Pension Plan

Wiser

Pension Plan

2012 2011 2012 2011

Fixed income securities 24% 22% 25% 21%

Equity securities 75% 76% 74% 78%

Other 1% 2% 1% 1%

100% 100% 100% 100%

Funded Status

The following table sets forth the funded status of the Company’s Pension Plans and Postretirement Benefits Plan.

December 31,

Pension Plans Postretirement Benefits Plan

2012 2011 2012 2011

(In Thousands)

Excess of benefit obligation over plan assets $ (18,225) $ (18,798) $ (17,227) $ (13,498)

Unrecognized actuarial loss 24,811 25,192 5,633 3,214

Net amount recognized $ 6,586 $ 6,394 $ (11,594) $ (10,284)

Amounts recognized in the balance sheet consist of:

Accrued benefit liability—noncurrent $ (18,225) $ (18,798) $ (17,227) $ (13,498)

Accumulated other comprehensive income—net actuarial loss 24,811 25,192 5,633 3,214

Net amount recognized $ 6,586 $ 6,394 $ (11,594) $ (10,284)

The following table sets forth the projected and accumulated benefit obligations for the Pension Plans compared to the fair value of the plan assets for

the periods indicated.

December 31,

2012 2011

(In Thousands)

Projected benefit obligation $ 46,017 $ 44,755

Accumulated benefit obligation 46,017 44,755

Fair value of plan assets 27,791 25,957

84
Table of Contents

Annual Periodic Expense and Actuarial Assumptions

The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions.

Year Ended December 31,

Pension Plans Postretirement Benefits Plan

2012 2011 2010 2012 2011 2010

(Dollar Amounts In Thousands)

Service cost $ — $ — $ — $ 1,131 $ 825 $ 668

Interest cost 1,554 1,836 2,005 547 529 430

Expected return on plan assets (1,744) (2,014) (1,952) — — —

Recognized actuarial loss (gain) 979 651 606 194 — (40)

Total net periodic expense $ 789 $ 473 $ 659 $ 1,872 $ 1,354 $ 1,058

Assumptions used to determine net periodic expense:

Discount rate 3.58% 4.50% 5.04% 4.14% 5.15% 5.55%

Expected return on plan assets 7% 7% 7% n/a n/a n/a

Assumptions used to determine benefit obligations:

Discount rate 2.98% 3.58% 4.50% 3.68% 4.14% 5.15%

The discount rates used to determine benefit obligations were determined by adjusting composite AA bond yields to reflect the difference between the

duration of the future estimated cash flows of the Plans and the Postretirement Benefits Plan obligations and the duration of the composite AA bond yields. The

expected rate of return on plan assets was determined based on historical returns.

The Company estimates that net periodic expense for the year ended December 31, 2013 for the Pension Plans and for the Postretirement Benefits Plan

will include expense of $.9 million and $.2 million, respectively, resulting from the amortization of the related accumulated actuarial loss included in

accumulated other comprehensive income at December 31, 2012.

The assumed health care cost trend rate for the next year and thereafter that was used to measure the expected cost of benefits covered by the

Postretirement Benefits Plan was 5.5%. Assumed health care cost trend rates can have a significant effect on the amounts reported for the Postretirement

Benefits Plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

Year Ended December 31, 2012

Postretirement Benefits Plan

1% Increase 1% Decrease

(In Thousands)

Effect on service and interest cost components $ 471 $ (344)

Effect on postretirement benefit obligation 3,839 (2,914)

Other Employee Benefit Plans

Forest sponsors various defined contribution plans under which the Company contributed matching contributions equal to $3.7 million in 2012,

$3.7 million in 2011, and $3.3 million in 2010.

Forest also provides life insurance benefits for certain retirees and former executives under split dollar life insurance plans. Under the life insurance

plans, the Company is assigned a portion of the benefits. No current employees are covered by these plans. The Company has recognized a liability for the

estimated cost of maintaining the insurance policies during the postretirement periods of the retirees and former executives, with such liability

85
Table of Contents

accreted each period to its present value. The Company’s estimate of costs expected to be paid in 2013 to maintain these life insurance policies is $1.0 million.

Forest recognized accretion expense related to the split dollar life insurance obligations of $.9 million, $1.0 million, and $1.0 million for the years ended

December 31, 2012, 2011, and 2010, respectively. The discount rates used to determine the accretion expense were 3.19%, 4.08%, and 4.01% for the years

ended December 31, 2012, 2011, and 2010, respectively. The split dollar life insurance obligation recognized in the Consolidated Balance Sheets was $7.3

million as of December 31, 2012 and 2011. The discount rates used to determine the obligations were 2.57% and 3.19% as of December 31, 2012 and 2011,

respectively. The cash surrender value of the split dollar life insurance policies recognized in the Consolidated Balance Sheets was $3.6 million as of

December 31, 2012 and 2011.

(8) FAIR VALUE MEASUREMENTS:

The Company’s assets and liabilities measured at fair value on a recurring basis at December 31, 2012 and 2011 are set forth by level within the fair

value hierarchy in the table below.

December 31,

2012 2011

Description

Using Significant Other Observable Inputs

(Level 2)(1)

(In Thousands)

Assets:

Derivative instruments:(2)

Commodity $ 35,465 $ 79,487

Interest rate 13,060 20,556

Total Assets $ 48,525 $ 100,043

Liabilities:

Derivative instruments:(2)

Commodity $ 16,551 $ 28,944

Interest rate — —

Total Liabilities $ 16,551 $ 28,944

____________________________________________

(1) The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which

prioritizes the inputs used to measure fair value. These tiers consist of: Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use

when relevant observable inputs are not available. The Company uses the income approach to value its derivative instruments under the Level 2 hierarchy. There were no

transfers between levels of the fair value hierarchy during 2012. The Company’s policy is to recognize transfers between levels of the fair value hierarchy as of the beginning of

the reporting period in which the event or change in circumstances caused the transfer.

(2) The Company’s derivative assets and liabilities include commodity and interest rate derivatives (see Note 9 for more information on these instruments). The Company utilizes

present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit

risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore,

the Company’s derivative instruments are included within the Level 2 fair value hierarchy.

86
Table of Contents

The fair values and carrying amounts of the Company’s financial instruments are summarized below as of the dates indicated.

December 31, 2012

Fair Value Measurements:

Carrying

Amount

Total Fair

Value(1)

Using Quoted Prices in

Active Markets for

Identical Assets

(Level 1)

Using Significant

Other

Observable Inputs

(Level 2)

(In Thousands)

Assets:

Derivative instruments $ 48,525 $ 48,525 $ — $ 48,525

Liabilities:

Derivative instruments 16,551 16,551 — 16,551

Credit facility 65,000 65,000 — 65,000

81⁄2% senior notes due 2014 296,723 321,000 321,000 —

71⁄4% senior notes due 2019 1,000,365 1,006,850 1,006,850 —

71⁄2% senior notes due 2020

500,000 526,250 526,250 —

____________________________________________

(1) The Company used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior notes were estimated based on

quoted market prices. The carrying amount of the credit facility approximated fair value due to the short original maturities of the borrowings and because the borrowings bear

interest at variable market rates. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 9 for more information on the

derivative instruments.

December 31, 2011

Carrying

Amount

Fair

Value(1)

(In Thousands)

Assets:

Derivative instruments $ 100,043 $ 100,043

Liabilities:

Derivative instruments 28,944 28,944

Credit facility 105,000 105,000

81⁄2% senior notes due 2014 587,611 653,250

71⁄4% senior notes due 2019 1,000,421 1,025,000

____________________________________________

(1) The Company used various assumptions and methods in estimating the fair values of its financial instruments. The fair values of the senior notes were estimated based on

quoted market prices. The carrying amount of the credit facility approximated fair value due to the short original maturities of the borrowings and because the borrowings bear

interest at variable market rates. The methods used to determine the fair values of the derivative instruments are discussed above. See also Note 9 for more information on the

derivative instruments.

(9) DERIVATIVE INSTRUMENTS:

Commodity Derivatives

Forest periodically enters into commodity derivative instruments such as swap and collar agreements as an attempt to moderate the effects of wide

fluctuations in commodity prices on Forest’s cash flow and to manage the exposure to commodity price risk. Forest’s commodity derivative instruments

generally serve as effective economic hedges of commodity price exposure; however, Forest has elected not to designate its derivatives as hedging

87
Table of Contents

instruments for accounting purposes. As such, Forest recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on

derivative instruments in the Consolidated Statement of Operations.

The table below sets forth Forest’s outstanding commodity swaps as of December 31, 2012.

Commodity Swaps

Natural Gas

(NYMEX HH)

Oil

(NYMEX WTI)

Swap Term

Bbtu

Per Day

Weighted

Average

Hedged Price

per MMBtu

Barrels

Per Day

Weighted

Average

Hedged Price

per Bbl

Calendar 2013 160 $ 3.98 4,000 $ 95.53

Calendar 2014 40 4.50 — —

In connection with several natural gas and oil swaps entered into, Forest granted swaptions to the swap counterparties in exchange for Forest receiving

premium hedged prices on the natural gas and oil swaps. These swaptions grant the swap counterparties the option to enter into future swaps with Forest and

may not be exercised until their expiration dates. The table below sets forth the outstanding swaptions as of December 31, 2012.

Commodity Options

Natural Gas (NYMEX HH) Oil (NYMEX WTI)

Underlying Term Option Expiration

Underlying Bbtu

Per Day

Underlying

Hedged Price

per MMBtu

Underlying

Barrels Per Day

Underlying

Hedged Price

per Bbl

Gas Swaptions:

Calendar 2014 December 2013 30 $ 4.50 — $ —

Calendar 2014 December 2013 10 4.51 — —

Oil Swaptions:

Calendar 2014 December 2013 — — 2,000 110.00

Calendar 2014 December 2013 — — 1,000 109.00

Calendar 2014 December 2013 — — 2,000 100.00

Calendar 2015 December 2014 — — 3,000 100.00

Derivative Instruments Entered Into Subsequent to December 31, 2012

Subsequent to December 31, 2012, through February 21, 2013, Forest entered into the following derivative instruments:

Commodity Swaps

Natural Gas (NYMEX HH)

Swap Term

Bbtu

Per Day

Weighted Average

Hedged Price

per MMBtu

Calendar 2014(1) 40 $ 4.19

____________________________________

(1) In connection with entering into these natural gas swaps with premium hedged prices, Forest amended the terms of existing oil swaptions with the counterparties for Calendar

2014 covering 2,000 barrels per day, changing the hedged price per barrel from $110.00 to $100.00.

88
Table of Contents

Interest Rate Derivatives

Forest has entered into interest rate derivative instruments in an attempt to manage the mix of fixed and floating interest rates within its debt portfolio.

The Company has elected not to designate its derivatives as hedging instruments for accounting purposes. As such, the Company recognizes all changes in

fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the Consolidated Statement of Operations. The table below

sets forth Forest’s outstanding fixed-to-floating interest rate swaps as of December 31, 2012.

Interest Rate Swaps

Remaining Swap Term

Notional

Amount

(In Thousands)

Weighted Average

Floating Rate

Weighted

Average

Fixed Rate

January 2013 - February 2014 $ 500,000 1 month LIBOR + 5.89% 8.50%

Fair Value and Gains and Losses

The table below summarizes the location and fair value amounts of Forest’s derivative instruments reported in the Consolidated Balance Sheets as of the

dates indicated. These derivative instruments are not designated as hedging instruments for accounting purposes. For financial reporting purposes, Forest does

not offset asset and liability fair value amounts recognized for derivative instruments with the same counterparty under its master netting arrangements. See

Note 8 for more information on the determination of the fair values of Forest’s derivative instruments.

December 31,

2012 2011

(In Thousands)

Current assets:

Derivative instruments:

Commodity $ 28,690 $ 79,487

Interest rate 11,500 10,134

Total current assets $ 40,190 $ 89,621

Long-term assets:

Derivative instruments:

Commodity $ 6,775 $ —

Interest rate 1,560 10,422

Total long-term assets $ 8,335 $ 10,422

Current liabilities:

Derivative instruments:

Commodity $ 9,347 $ 28,944

Long-term liabilities:

Derivative instruments:

Commodity $ 7,204 $ —

89
Table of Contents

The table below summarizes the amount of derivative instrument gains and losses reported in the Consolidated Statements of Operations as realized and

unrealized (gains) losses on derivative instruments, net, for the periods indicated. These derivative instruments are not designated as hedging instruments for

accounting purposes.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Commodity derivatives:

Realized gains $ (100,420) $ (37,535) $ (99,762)

Unrealized losses (gains) 31,630 (37,542) (18,390)

Interest rate derivatives:

Realized gains (11,352) (11,442) (12,450)

Unrealized losses (gains) 7,496 (1,545) (19,530)

Realized and unrealized gains on derivative instruments, net $ (72,646) $ (88,064) $ (150,132)

Due to the volatility of oil, natural gas, and NGL prices, the estimated fair values of Forest’s commodity derivative instruments are subject to large

fluctuations from period to period. Forest has experienced the effects of these commodity price fluctuations in both the current period and prior periods and

expects that volatility in commodity prices will continue.

Credit Risk

Forest executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. (“ISDA”) Master Agreement, which is a

standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Forest executes,

with each of its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties’

requirements and the specific types of derivatives to be traded. As of December 31, 2012, all but one of Forest’s derivative counterparties are lenders, or

affiliates of lenders, under the Credit Facility. The terms of the Credit Facility provide that any security granted by Forest thereunder shall also extend to and

be available to those lenders that are counterparties to derivative transactions. None of these counterparties requires collateral beyond that already pledged under

the Credit Facility. The remaining counterparty, a purchaser of Forest’s natural gas production, generally owes money to Forest and therefore does not require

collateral under the ISDA Master Agreement and Schedule it has executed with Forest.

The ISDA Master Agreements and Schedules contain cross-default provisions whereby a default under the Credit Facility will also cause a default under

the derivative agreements. Such events of default include non-payment, breach of warranty, non-performance of the financial covenant, default on other

indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the Credit Facility. In addition,

bankruptcy and insolvency events with respect to Forest or certain of its U.S. subsidiaries will result in an automatic acceleration of the indebtedness under

the Credit Facility. None of these events of default is specifically credit-related, but some could arise if there were a general deterioration of Forest’s credit. The

ISDA Master Agreements and Schedules contain a further credit-related termination event that would occur if Forest were to merge with another entity and the

creditworthiness of the resulting entity was materially weaker than that of Forest.

The majority of Forest’s derivative counterparties are financial institutions that are engaged in similar activities and have similar economic

characteristics that, in general, could cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.

Forest does not require the posting of collateral for its benefit under its derivative agreements. However, the ISDA Master Agreements and Schedules generally

contain netting provisions whereby if on any date amounts would otherwise be payable by each party to the other, then on such date, the party that owes the

larger amount will pay the excess of that amount over the smaller amount owed by the other party, thus satisfying each party’s obligations. These provisions

generally apply to

90
Table of Contents

all derivative transactions, or all derivative transactions of the same type (e.g. commodity, interest rate, etc.), with the particular counterparty. If all

counterparties failed, Forest would be exposed to a risk of loss equal to this net amount owed to Forest, the fair value of which was $33.3 million at

December 31, 2012. If Forest suffered an event of default, each counterparty could demand immediate payment, subject to notification periods, of the net

obligations due to it under the derivative agreements. At December 31, 2012, Forest owed a net derivative liability to one counterparty, the fair value of which

was $1.3 million. In the absence of netting provisions, at December 31, 2012, Forest would be exposed to a risk of loss of $48.5 million under its derivative

agreements and Forest’s derivative counterparties would be exposed to a risk of loss of $16.6 million.

On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted. As part of a broader financial

regulatory reform, the Dodd-Frank Act includes derivatives reform that may impact Forest’s business. Congress delegated many of the details of the DoddFrank Act to federal regulatory agencies. Forest is monitoring the impact, if any, that the Dodd-Frank Act and related rules will have on its existing derivative

transactions under its outstanding ISDA Master Agreements and Schedules, as well as its ability to enter into such transactions and agreements in the future.

(10) COMMITMENTS AND CONTINGENCIES:

The table below shows the Company’s future payments under non-cancelable operating leases and unconditional purchase obligations as of

December 31, 2012.

2013 2014 2015 2016 2017

After

2017 Total

(In Thousands)

Operating leases(1)

$ 30,070 $ 24,188 $ 17,573 $ 17,026 $ 10,032 $ 10,135 $ 109,024

Unconditional purchase obligations(2)

1,935 140 105 — — — 2,180

$ 32,005 $ 24,328 $ 17,678 $ 17,026 $ 10,032 $ 10,135 $ 111,204

____________________________________________

(1) Includes future rental payments for office facilities and equipment, drilling rigs, and compressors under the remaining terms of non-cancelable operating leases with initial terms

in excess of one year.

(2) Includes unconditional purchase obligations for throughput and voice and data services. Payments made under these unconditional purchase obligations were $.8 million in

each of the years 2012, 2011, and 2010.

Net rental payments under non-cancelable operating leases applicable to exploration and development activities and capitalized to oil and gas

properties approximated $15.6 million in 2012, $21.0 million in 2011, and $14.0 million in 2010. Net rental payments under non-cancelable operating

leases, including compressor rentals, charged to expense approximated $22.0 million in 2012, $16.5 million in 2011, and $18.4 million in 2010. The

Company has no leases that are accounted for as capital leases.

Forest, in the ordinary course of business, is a party to various lawsuits, claims, and proceedings. While the Company believes that the amount of

any potential loss upon resolution of these matters would not be material to its consolidated financial position, the ultimate outcome of these matters is

inherently difficult to predict with any certainty. In the event of an unfavorable outcome, the potential loss could have an adverse effect on Forest’s results of

operations and cash flow. Forest is also involved in a number of governmental proceedings in the ordinary course of business, including environmental

matters.

91
Table of Contents

(11) COSTS, EXPENSES, AND OTHER:

The table below sets forth the components of “Other, net” in the Consolidated Statements of Operations for the periods indicated.

Year Ended December 31,

2012 2011 2010

(In Thousands)

Accretion of asset retirement obligations $ 6,663 $ 6,082 $ 6,158

Legal proceeding liabilities 29,251 6,500 —

Loss (gain) on debt extinguishment, net 36,312 — (4,576)

Other, net 11,180 4,582 5,757

$ 83,406 $ 17,164 $ 7,339

Accretion of Asset Retirement Obligations

Accretion of asset retirement obligations is the expense recognized to increase the carrying amount of the liability associated with Forest’s asset

retirement obligations as a result of the passage of time. See Note 1 for more information on Forest’s asset retirement obligations.

Legal Proceeding Liabilities

On February 29, 2012, two members of a three-member arbitration panel reached a decision adverse to Forest in the proceeding styled, Forest Oil

Corporation, et al. v. El Rucio Land & Cattle Company, Inc., et al., which occurred in Harris County, Texas. The third member of the arbitration panel

dissented. The proceeding was initiated in January 2005 and involves claims asserted by the landowner-claimant based on the diminution in value of its land

and related damages allegedly resulting from operational and reclamation practices employed by Forest in the 1970s, 1980s, and early 1990s. The arbitration

decision awards the claimant $22.8 million in damages and attorneys’ fees and additional injunctive relief regarding future surface-use issues. On October 9,

2012, after vacating a portion of the decision imposing a future bonding requirement on Forest, the trial court for the 55 th Judicial District, in the District

Court in Harris County, Texas, reduced the arbitration decision to a judgment. Forest is seeking to have this judgment reversed on appeal and believes it has

meritorious arguments in support thereof. However, Forest is unable to predict the final outcome in this matter and has accrued a liability, which is classified

within “Other liabilities” in the Consolidated Balance Sheet, of $23.0 million, which includes accrued interest, for this matter.

In August 2007, Forest sold all of its Alaska assets to Pacific Energy Resources Ltd. and its related entities (“PERL”). On March 9, 2009, PERL

filed for bankruptcy. As part of the plan of liquidation of its bankruptcy, PERL “abandoned” its interests in many of the Alaska assets sold to it by Forest,

including the Trading Bay Unit and Trading Bay Field (“Trading Bay”). On December 2, 2010, Union Oil Company of California (“Unocal”) filed a

lawsuit styled, Union Oil Company of California v. Forest Oil Corporation. In the lawsuit, the plaintiff complained about PERL’s abandonment of

Trading Bay and asserted that PERL has failed to pay approximately $49.0 million in joint interest billings owed on those properties to date from the time

PERL owned them. The plaintiff claimed that, as predecessor of PERL, Forest was liable for PERL’s share of all joint interest billings owed on Trading Bay.

As of December 31, 2011, Unocal sold its interest in the Trading Bay assets, including its claims against Forest, to Hilcorp Alaska, LLC, and Hilcorp was

substituted for Unocal as plaintiff in the lawsuit. In August 2012, Forest and the plaintiff reached a settlement whereby the plaintiff released Forest from all

claims, agreed to indemnify Forest with respect to all decommissioning and abandonment liabilities associated with Trading Bay, and dismissed the

complaint against Forest in exchange for a $7.0 million payment from Forest.

On March 7, 2011, Pacific Energy Resources Ltd., Pacific Energy Alaska Holdings LLC, and Pacific Energy Alaska Operating LLC filed suit

against Forest Oil Corporation and Forest Alaska Holdings LLC in United States Bankruptcy Court in the District of Delaware. In this suit, the plaintiffs

claimed that, at the time Forest sold

92
Table of Contents

Pacific Energy Resources Ltd. its Alaska assets, those assets were overvalued due to Forest’s alleged nondisclosure, fraud, and negligent misrepresentations

and that, as a result, the sales transaction rendered Pacific Energy Resources Ltd. insolvent. The plaintiffs sought to recover over $250.0 million in value from

Forest. During 2011, Forest and the plaintiffs in this action reached a settlement whereby the plaintiffs released Forest from all claims and agreed to dismiss

the complaint against Forest in exchange for a $6.5 million payment from Forest.

Loss (Gain) on Debt Extinguishment

In October 2012, Forest redeemed $300.0 million of the 81⁄2% Notes at 110.24% of par, recognizing a loss of $36.3 million upon redemption due to

the $30.7 million call premium and write-off of $5.6 million of unamortized discount and debt issue costs.

The net gain on debt extinguishment for the year ended December 31, 2010 includes the net gain related to the January 2010 redemption of $150.0

million 73⁄4% senior notes due 2014 at 101.292% of par. A net gain was recognized upon redemption due to the write-off of $7.6 million of unamortized

deferred gains resulting from the previous termination of interest rate swaps related to these notes. This gain was partially offset by the $1.9 million call

premium and write-off of $1.1 million of unamortized discount and debt issue costs.

93
Table of Contents

(12) SELECTED QUARTERLY FINANCIAL DATA (unaudited):

First

Quarter

Second

Quarter

Third

Quarter

Fourth

Quarter

(In Thousands, Except Per Share Amounts)

2012

Oil, natural gas, and natural gas liquids sales $ 158,901 $ 135,694 $ 156,014 $ 154,914

Costs and expenses associated directly with products sold (1) $ 110,110 $ 110,996 $ 114,304 $ 104,048

Earnings (loss) before income taxes(2) $ (31,758) $ (344,099) $ (451,272) $ (288,365)

Net earnings (loss)(2) $ (32,673) $ (511,173) $ (458,552) $ (286,533)

Basic earnings (loss) per share $ (.29) $ (4.44) $ (3.97) $ (2.48)

Diluted earnings (loss) per share $ (.29) $ (4.44) $ (3.97) $ (2.48)

2011

Oil, natural gas, and natural gas liquids sales

As reported(3) $ 202,571 $ 237,848 $ 174,012 $ 176,616

Less: discontinued operations 36,261 51,255 — —

Oil, natural gas, and natural gas liquids sales from continuing operations $ 166,310 $ 186,593 $ 174,012 $ 176,616

Costs and expenses associated directly with products sold (1):

As reported(3) $ 118,465 $ 126,479 $ 89,343 $ 105,377

Less: discontinued operations 31,325 34,873 — —

Costs and expenses associated directly with products sold from continuing

operations $ 87,140 $ 91,606 $ 89,343 $ 105,377

Earnings (loss) before income taxes(2):

As reported(3) $ (5,047) $ 90,682 $ 94,166 $ 31,662

Less: discontinued operations 9,247 14,821 — —

Earnings (loss) from continuing operations before income taxes $ (14,294) $ 75,861 $ 94,166 $ 31,662

Net earnings (loss)(2) $ (3,330) $ 38,974 $ 87,718 $ 19,467

Net earnings (loss) attributable to Forest Oil Corporation common shareholders (2)(4) $ (3,330) $ 38,910 $ 82,795 $ 19,467

Basic earnings (loss) per share attributable to Forest Oil Corporation common

shareholders $ (.03) $ .34 $ .72 $ .17

Diluted earnings (loss) per share attributable to Forest Oil Corporation common

shareholders $ (.03) $ .34 $ .72 $ .17

____________________________________________

(1) Costs and expenses associated directly with products sold is comprised of lease operating expenses, production and property taxes, transportation and processing costs,

depletion expense, and accretion of asset retirement obligations.

(2) Earnings (loss) before income taxes, net earnings (loss), and net earnings (loss) attributable to Forest Oil Corporation common shareholders have been impacted by non-cash

ceiling test write-downs in every quarter of 2012 as discussed in Note 1 and are also subject to large fluctuations due to Forest’s election not to use cash flow hedge

accounting for derivative instruments as discussed in Note 9.

(3) Amounts shown for the first and second quarters of 2011 are those amounts that were previously reported in Forest’s Quarterly Reports on Form 10-Q prior to the September

30, 2011 spin-off of Lone Pine, whose results are now reported as discontinued operations.

(4) Upon completion of Lone Pine’s initial public offering on June 1, 2011, Forest maintained a controlling interest in Lone Pine until it was spun-off on September 30, 2011. As

such, during the second and third quarters of 2011, Forest had net earnings attributable to the noncontrolling interest.

94
Table of Contents

(13) DISCONTINUED OPERATIONS:

Lone Pine was a component of Forest with operations and cash flows clearly distinguishable, both operationally and for financial reporting purposes,

from those of Forest. As a result of the spin-off of Lone Pine on September 30, 2011, Lone Pine’s operations and cash flows were eliminated from the ongoing

operations of Forest, and Forest will not have any significant continuing involvement in the operations of Lone Pine. Accordingly, Forest has presented Lone

Pine’s results of operations as discontinued operations in the Consolidated Statements of Operations for the periods presented. For more information regarding

the spin-off see Note 5.

The table below presents the major components of earnings from discontinued operations for the periods presented.

Nine Months Ended

September 30, 2011

Year Ended December

31, 2010

(In Thousands)

Total revenues $ 137,834 $ 146,070

Production expenses 40,350 38,841

General and administrative 8,846 8,318

Depreciation, depletion, and amortization 60,780 63,645

Interest expense 3,866 381

Realized and unrealized gains on derivative instruments, net (33,628) —

Realized foreign currency exchange gains (33,869) (270)

Unrealized foreign currency exchange losses (gains), net 28,488 (14,290)

Other, net 1,328 729

Earnings from discontinued operations before tax 61,673 48,716

Income tax 17,104 10,857

Net earnings from discontinued operations $ 44,569 $ 37,859

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION:

The Company’s 81⁄2% senior notes due 2014, 71⁄4% senior notes due 2019, and 71⁄2% senior notes due 2020 have been fully and unconditionally

guaranteed by a 100%-owned subsidiary of the Company (the “Guarantor Subsidiary”). The Company’s remaining subsidiaries (the “Non-Guarantor

Subsidiaries”) have not provided guarantees. The Guarantor Subsidiary’s guarantee may be released automatically under the following customary

circumstances:

• in connection with any sale or other disposition of all or substantially all of the property of the Guarantor Subsidiary (including by way of merger or

consolidation) to a person that is not (either before or after giving effect to such transaction) a restricted subsidiary of the Company;

• in connection with any sale or other disposition of the capital stock of the Guarantor Subsidiary to a person that is not (either before or after giving

effect to such transaction) a restricted subsidiary of the Company;

• if the Company designates that Guarantor Subsidiary as an unrestricted subsidiary in accordance with the applicable provisions of the indentures;

• if the Company exercises its legal defeasance option or its covenant defeasance option or upon satisfaction and discharge of the indentures; or

9 5
Table of Contents

• at such time as such Guarantor Subsidiary ceases to guarantee any other indebtedness of the Company, provided that at such time it does not have

outstanding an aggregate of $25.0 million or more of indebtedness and preferred stock.

The following presents condensed consolidating financial information as of December 31, 2012 and 2011, and for the three years in the period ended

December 31, 2012 on an issuer (parent company), guarantor subsidiary, non-guarantor subsidiaries, eliminating entries, and consolidated basis. Eliminating

entries presented are necessary to combine the entities.

CONDENSED CONSOLIDATING BALANCE SHEETS

(In Thousands)

December 31, 2012

Parent

Company

Guarantor

Subsidiary

Combined

Non-Guarantor

Subsidiaries Eliminations Consolidated

ASSETS

Current assets:

Cash and cash equivalents $ 667 $ 45 $ 344 $ — $ 1,056

Accounts receivable 33,979 27,969 6,393 (825) 67,516

Other current assets 55,869 286 353 — 56,508

Total current assets 90,515 28,300 7,090 (825) 125,080

Property and equipment, at cost 8,439,898 1,416,364 182,070 — 10,038,332

Less accumulated depreciation, depletion, and

amortization 6,937,606 1,173,332 173,156 — 8,284,094

Net property and equipment 1,502,292 243,032 8,914 — 1,754,238

Investment in subsidiaries 68,048 — — (68,048) —

Goodwill 216,460 22,960 — — 239,420

Due from subsidiaries 116,602 83,983 — (200,585) —

Deferred income taxes 111,015 — 36,106 (132,440) 14,681

Other assets 68,443 — — — 68,443

$ 2,173,375 $ 378,275 $ 52,110 $ (401,898) $ 2,201,862

LIABILITIES AND SHAREHOLDERS’

EQUITY

Current liabilities:

Accounts payable and accrued liabilities $ 157,404 $ 2,133 $ 6,074 $ (825) $ 164,786

Other current liabilities 55,187 67 6,285 — 61,539

Total current liabilities 212,591 2,200 12,359 (825) 226,325

Long-term debt 1,862,088 — — — 1,862,088

Due to parent and subsidiaries — — 200,585 (200,585) —

Deferred income taxes — 132,440 — (132,440) —

Other liabilities 141,520 3,642 11,111 — 156,273

Total liabilities 2,216,199 138,282 224,055 (333,850) 2,244,686

Shareholders’ equity (deficit) (42,824) 239,993 (171,945) (68,048) (42,824)

$ 2,173,375 $ 378,275 $ 52,110 $ (401,898) $ 2,201,862

9 6
Table of Contents

CONDENSED CONSOLIDATING BALANCE SHEETS (Continued)

(In Thousands)

December 31, 2011

Parent

Company

Guarantor

Subsidiary

Combined

Non-Guarantor

Subsidiaries Eliminations Consolidated

ASSETS

Current assets:

Cash and cash equivalents $ 1,734 $ 1 $ 1,277 $ — $ 3,012

Accounts receivable 43,999 34,142 2,201 (1,253) 79,089

Other current assets 127,667 313 591 — 128,571

Total current assets 173,400 34,456 4,069 (1,253) 210,672

Property and equipment, at cost 8,000,466 1,317,917 282,719 — 9,601,102

Less accumulated depreciation, depletion, and

amortization 5,782,409 1,102,339 65,238 — 6,949,986

Net property and equipment 2,218,057 215,578 217,481 — 2,651,116

Investment in subsidiaries 160,591 — — (160,591) —

Goodwill 216,460 22,960 — — 239,420

Due from subsidiaries 214,394 46,944 — (261,338) —

Deferred income taxes 312,564 — 25,564 (107,012) 231,116

Other assets 48,827 — — — 48,827

$ 3,344,293 $ 319,938 $ 247,114 $ (530,194) $ 3,381,151

LIABILITIES AND SHAREHOLDERS’

EQUITY

Current liabilities:

Accounts payable and accrued liabilities $ 235,788 $ 8,846 $ 4,499 $ (1,253) $ 247,880

Other current liabilities 86,618 63 6,276 — 92,957

Total current liabilities 322,406 8,909 10,775 (1,253) 340,837

Long-term debt 1,693,044 — — — 1,693,044

Due to parent — — 261,338 (261,338) —

Deferred income taxes — 107,012 — (107,012) —

Other liabilities 135,730 2,614 15,813 — 154,157

Total liabilities 2,151,180 118,535 287,926 (369,603) 2,188,038

Shareholders’ equity 1,193,113 201,403 (40,812) (160,591) 1,193,113

$ 3,344,293 $ 319,938 $ 247,114 $ (530,194) $ 3,381,151

97
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

Year Ended December 31, 2012

Parent

Company

Guarantor

Subsidiary

Combined

NonGuarantor

Subsidiaries Eliminations Consolidated

Revenues:

Oil, natural gas, and natural gas liquids sales $ 442,034 $ 159,578 $ 3,911 $ — $ 605,523

Interest and other 4,888 2,360 — (7,112) 136

Equity earnings in subsidiaries (71,028) — — 71,028 —

Total revenues 375,894 161,938 3,911 63,916 605,659

Costs, expenses, and other:

Lease operating expenses 91,214 16,422 391 — 108,027

Other production expenses 45,211 3,383 288 — 48,882

General and administrative 54,815 2,730 1,717 — 59,262

Depreciation, depletion, and amortization 207,622 70,993 1,843 — 280,458

Ceiling test write-down of oil and natural gas properties 950,157 — 42,247 — 992,404

Impairment of properties — — 79,529 — 79,529

Interest expense 141,830 1,058 6,055 (7,112) 141,831

Realized and unrealized gains on derivative instruments, net (58,123) (14,275) (248) — (72,646)

Other, net 73,548 413 9,445 — 83,406

Total costs, expenses, and other 1,506,274 80,724 141,267 (7,112) 1,721,153

Earnings (loss) before income taxes (1,130,380) 81,214 (137,356) 71,028 (1,115,494)

Income tax 158,551 25,428 (10,542) — 173,437

Net earnings (loss) (1,288,931) 55,786 (126,814) 71,028 (1,288,931)

Other comprehensive loss:

Defined benefit postretirement plans losses, net of tax (2,242) — — — (2,242)

Total other comprehensive loss (2,242) — — — (2,242)

Total comprehensive income (loss) $ (1,291,173) $ 55,786 $ (126,814) $ 71,028 $ (1,291,173)

98
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (Continued)

(In Thousands)

Year Ended December 31, 2011

Parent

Company

Guarantor

Subsidiary

Combined

NonGuarantor

Subsidiaries Eliminations Consolidated

Revenues:

Oil, natural gas, and natural gas liquids sales $ 517,649 $ 183,391 $ 2,491 $ — $ 703,531

Interest and other 3,569 5,834 — (8,377) 1,026

Equity earnings in subsidiaries 102,237 — — (102,237) —

Total revenues 623,455 189,225 2,491 (110,614) 704,557

Costs, expenses, and other:

Lease operating expenses 84,117 14,620 421 — 99,158

Other production expenses 47,066 7,122 172 — 54,360

General and administrative 60,855 2,787 1,463 — 65,105

Depreciation, depletion, and amortization 165,270 52,692 1,722 — 219,684

Interest expense 149,755 4,949 3,428 (8,377) 149,755

Realized and unrealized (gains) losses on derivative instruments, net (91,221) 3,192 (35) — (88,064)

Other, net 11,386 238 5,540 — 17,164

Total costs, expenses, and other 427,228 85,600 12,711 (8,377) 517,162

Earnings (loss) from continuing operations before income taxes 196,227 103,625 (10,220) (102,237) 187,395

Income tax 53,398 39,647 (3,910) — 89,135

Net earnings (loss) from continuing operations 142,829 63,978 (6,310) (102,237) 98,260

Net earnings from discontinued operations — — 44,569 — 44,569

Net earnings 142,829 63,978 38,259 (102,237) 142,829

Less: net earnings attributable to noncontrolling interest — — 4,987 — 4,987

Net earnings attributable to Forest Oil Corporation common shareholders 142,829 63,978 33,272 (102,237) 137,842

Net earnings 142,829 63,978 38,259 (102,237) 142,829

Other comprehensive loss:

Foreign currency translation losses — — (27,852) — (27,852)

Defined benefit postretirement plans losses, net of tax (6,669) — — — (6,669)

Total other comprehensive loss (6,669) — (27,852) — (34,521)

Total comprehensive income 136,160 63,978 10,407 (102,237) 108,308

Less: total comprehensive loss attributable to noncontrolling interest — — (1,330) — (1,330)

Total comprehensive income attributable to Forest Oil Corporation common

shareholders $ 136,160 $ 63,978 $ 11,737 $ (102,237) $ 109,638

9 9
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (Continued)

(In Thousands)

Year Ended December 31, 2010

Parent

Company

Guarantor

Subsidiary

Combined

NonGuarantor

Subsidiaries Eliminations Consolidated

Revenues:

Oil, natural gas, and natural gas liquids sales $ 479,250 $ 225,937 $ 2,505 $ — $ 707,692

Interest and other 5,504 32 — (4,547) 989

Equity earnings in subsidiaries 138,354 — — (138,354) —

Total revenues 623,108 225,969 2,505 (142,901) 708,681

Costs, expenses, and other:

Lease operating expenses 79,927 11,974 493 — 92,394

Other production expenses 45,318 11,454 126 — 56,898

General and administrative 60,901 2,408 1,577 — 64,886

Depreciation, depletion, and amortization 130,777 55,642 1,554 — 187,973

Interest expense 149,891 1,381 3,166 (4,547) 149,891

Realized and unrealized gains on derivative instruments, net (122,389) (27,457) (286) — (150,132)

Other, net 877 (456) 6,918 — 7,339

Total costs, expenses, and other 345,302 54,946 13,548 (4,547) 409,249

Earnings (loss) from continuing operations before income taxes 277,806 171,023 (11,043) (138,354) 299,432

Income tax 50,285 62,919 (3,434) — 109,770

Net earnings (loss) from continuing operations 227,521 108,104 (7,609) (138,354) 189,662

Net earnings from discontinued operations — — 37,859 — 37,859

Net earnings 227,521 108,104 30,250 (138,354) 227,521

Other comprehensive income (loss):

Foreign currency translation gains — — 15,153 — 15,153

Defined benefit postretirement plans (losses) gains, net of tax (932) — 186 — (746)

Total other comprehensive income (loss) (932) — 15,339 — 14,407

Total comprehensive income $ 226,589 $ 108,104 $ 45,589 $ (138,354) $ 241,928

100
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(In Thousands)

Year Ended December 31, 2012

Parent

Company

Guarantor

Subsidiary

Combined

NonGuarantor

Subsidiaries Consolidated

Operating activities:

Net earnings (loss) $ (1,217,903) $ 55,786 $ (126,814) $ (1,288,931)

Adjustments to reconcile net earnings (loss) to net cash provided (used) by operating activities:

Depreciation, depletion, and amortization 207,622 70,993 1,843 280,458

Deferred income tax 194,089 25,428 (10,542) 208,975

Unrealized losses on derivative instruments, net 32,448 6,563 115 39,126

Ceiling test write-down of oil and natural gas properties 950,157 — 42,247 992,404

Impairment of properties — — 79,529 79,529

Loss on debt extinguishment, net 36,312 — — 36,312

Other, net 31,889 404 (3,872) 28,421

Changes in operating assets and liabilities:

Accounts receivable 10,020 6,173 (4,620) 11,573

Other current assets 2,428 27 175 2,630

Accounts payable and accrued liabilities (22,240) (1,549) 2,625 (21,164)

Accrued interest and other 1,574 (47) 795 2,322

Net cash provided (used) by operating activities 226,396 163,778 (18,519) 371,655

Investing activities:

Capital expenditures for property and equipment (615,167) (102,596) (12,901) (730,664)

Proceeds from sales of assets 234,017 8 8 28,777 262,882

Net cash (used) provided by investing activities (381,150) (102,508) 15,876 (467,782)

Financing activities:

Proceeds from bank borrowings 1,244,000 — — 1,244,000

Repayments of bank borrowings (1,284,000) — — (1,284,000)

Issuance of senior notes, net of issuance costs 491,250 — — 491,250

Redemption of senior notes (330,709) — — (330,709)

Change in bank overdrafts (23,922) (428) 133 (24,217)

Net activity in investments in subsidiaries 59,221 (60,798) 1,577 —

Other, net (2,153) — — (2,153)

Net cash provided (used) by financing activities 153,687 (61,226) 1,710 94,171

Net (decrease) increase in cash and cash equivalents (1,067) 44 (933) (1,956)

Cash and cash equivalents at beginning of period 1,734 1 1,277 3,012

Cash and cash equivalents at end of period $ 667 $ 45 $ 344 $ 1,056

101
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Continued)

(In Thousands)

Year Ended December 31, 2011

Parent

Company

Guarantor

Subsidiary

Combined

NonGuarantor

Subsidiaries Consolidated

Operating activities:

Net earnings $ 40,592 $ 63,978 $ 38,259 $ 142,829

Less: net earnings from discontinued operations — — 44,569 44,569

Net earnings (loss) from continuing operations 40,592 63,978 (6,310) 98,260

Adjustments to reconcile net earnings (loss) from continuing operations to net cash provided (used)

by operating activities of continuing operations:

Depreciation, depletion, and amortization 165,270 52,692 1,722 219,684

Deferred income tax 23,257 39,647 (3,910) 58,994

Unrealized (gains) losses on derivative instruments, net (40,666) 1,596 (17) (39,087)

Other, net 36,714 331 (2,313) 34,732

Changes in operating assets and liabilities:

Accounts receivable 6,025 16,069 1,142 23,236

Other current assets 12,816 442 1,056 14,314

Accounts payable and accrued liabilities (7,894) 1,564 (140) (6,470)

Accrued interest and other (5,165) (252) (149) (5,566)

Net cash provided (used) by operating activities of continuing operations 230,949 176,067 (8,919) 398,097

Investing activities:

Capital expenditures for property and equipment (683,758) (114,715) (82,372) (880,845)

Proceeds from sales of assets 120,992 — 123 121,115

Net cash used by investing activities of continuing operations (562,766) (114,715) (82,249) (759,730)

Financing activities:

Proceeds from bank borrowings 160,000 — — 160,000

Repayments of bank borrowings (55,000) — — (55,000)

Redemption of senior notes (285,000) — — (285,000)

Change in bank overdrafts 16,682 478 (44) 17,116

Net activity in investments in subsidiaries 290,710 (61,832) (228,878) —

Other, net (10,421) — — (10,421)

Net cash provided (used) by financing activities of continuing operations 116,971 (61,354) (228,922) (173,305)

Cash flows of discontinued operations:

Operating cash flows — — 101,292 101,292

Investing cash flows — — (255,470) (255,470)

Financing cash flows — — 478,324 478,324

Net cash provided by discontinued operations — — 324,146 324,146

Effect of exchange rate changes on cash — — (3,476) (3,476)

Net (decrease) increase in cash and cash equivalents (214,846) (2) 580 (214,268)

Net increase in cash and cash equivalents of discontinued operations — — (289) (289)

Net (decrease) increase in cash and cash equivalents of continuing operations (214,846) (2) 291 (214,557)

Cash and cash equivalents of continuing operations at beginning of period 216,580 3 986 217,569

Cash and cash equivalents of continuing operations at end of period $ 1,734 $ 1 $ 1,277 $ 3,012

102
Table of Contents

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS (Continued)

(In Thousands)

Year Ended December 31, 2010

Parent

Company

Guarantor

Subsidiary

Combined

NonGuarantor

Subsidiaries Consolidated

Operating activities:

Net earnings $ 89,167 $ 108,104 $ 30,250 $ 227,521

Less: net earnings from discontinued operations — — 37,859 37,859

Net earnings (loss) from continuing operations 89,167 108,104 (7,609) 189,662

Adjustments to reconcile net earnings (loss) from continuing operations to net cash provided (used)

by operating activities of continuing operations:

Depreciation, depletion, and amortization 130,777 55,642 1,554 187,973

Deferred income tax 64,185 62,919 (3,433) 123,671

Unrealized gains on derivative instruments, net (33,602) (4,274) (44) (37,920)

Gain on debt extinguishment, net (4,576) — — (4,576)

Other, net 34,512 263 (3,435) 31,340

Changes in operating assets and liabilities:

Accounts receivable 29,833 (25,805) (1,388) 2,640

Other current assets 22,818 42 1,276 24,136

Accounts payable and accrued liabilities (60,768) (2,557) 890 (62,435)

Accrued interest and other (17,023) (191) 9,448 (7,766)

Net cash provided (used) by operating activities of continuing operations 255,323 194,143 (2,741) 446,725

Investing activities:

Capital expenditures for property and equipment (432,484) (121,458) (8,189) (562,131)

Proceeds from sales of assets 140,643 (1,565) (1) 139,077

Net cash used by investing activities of continuing operations (291,841) (123,023) (8,190) (423,054)

Financing activities:

Redemption of senior notes (152,038) — — (152,038)

Change in bank overdrafts 7,834 (1,334) (122) 6,378

Net activity in investments in subsidiaries (63,126) (70,162) 133,288 —

Other, net 3,450 — (1) 3,449

Net cash (used) provided by financing activities of continuing operations (203,880) (71,496) 133,165 (142,211)

Cash flows of discontinued operations:

Operating cash flows — — 86,204 86,204

Investing cash flows — — (218,155) (218,155)

Financing cash flows — — 1,692 1,692

Net cash used by discontinued operations — — (130,259) (130,259)

Effect of exchange rate changes on cash — — (277) (277)

Net decrease in cash and cash equivalents (240,398) (376) (8,302) (249,076)

Net decrease in cash and cash equivalents of discontinued operations — — 8,370 8,370

Net (decrease) increase in cash and cash equivalents of continuing operations (240,398) (376) 68 (240,706)

Cash and cash equivalents of continuing operations at beginning of period 456,978 379 918 458,275

Cash and cash equivalents of continuing operations at end of period $ 216,580 $ 3 $ 986 $ 217,569

103
Table of Contents

(15) SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited):

Supplemental unaudited information regarding Forest’s oil and gas producing activities is presented in this Note. This supplemental information

excludes amounts for all periods presented related to Forest’s discontinued operations.

Estimated Proved Reserves

Proved reserves are those quantities of oil, natural gas liquids, and natural gas, which, by analysis of geoscience and engineering data, can be

estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic

conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates

that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the

hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic

conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price for oil, natural

gas liquids, and natural gas during the twelve month period prior to the end of the reporting period, determined as an unweighted arithmetic average of the firstday-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future

conditions. Prices do not include the effects of commodity derivatives. Existing economic conditions include year-end cost estimates.

Proved developed reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating

methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment

and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a

relatively major expenditure is required for recompletion.

The following table sets forth the Company’s estimates of its net proved, net proved developed, and net proved undeveloped oil, natural gas liquids,

and natural gas reserves as of December 31, 2012, 2011, and 2010 and changes in its net proved reserves for the years then ended. For the years presented, the

Company engaged DeGolyer and MacNaughton, an independent petroleum engineering firm, to perform reserve audit services.

104
Table of Contents

Oil Natural Gas Liquids Natural Gas

(MBbls) (MBbls) (MMcf)

United

States Italy Total

United

States Italy Total

United

States Italy Total

Total

MMcfe(1)

Total

MBoe(1)

Balance at January 1, 2010 16,932 — 16,932 38,236 — 38,236 1,415,431 51,738 1,467,169 1,798,177 299,696

Revisions of previous estimates 1,276 — 1,276 (278) — (278) (38,515) — (38,515) (32,527) (5,421)

Extensions and discoveries 4,591 — 4,591 9,051 — 9,051 199,790 — 199,790 281,642 46,940

Production (2,357) — (2,357) (3,589) — (3,589) (101,346) — (101,346) (137,022) (22,837)

Sales of reserves in place (183) — (183) (292) — (292) (45,783) — (45,783) (48,633) (8,106)

Purchases of reserves in place 59 — 59 256 — 256 4,154 — 4,154 6,044 1,007

Balance at December 31, 2010 20,318 — 20,318 43,384 — 43,384 1,433,731 51,738 1,485,469 1,867,681 311,280

Revisions of previous estimates (1,061) — (1,061) (3,716) — (3,716) (91,721) — (91,721) (120,383) (20,064)

Extensions and discoveries 17,816 — 17,816 8,262 — 8,262 144,094 — 144,094 300,562 50,094

Production (2,491) — (2,491) (3,154) — (3,154) (88,497) — (88,497) (122,367) (20,395)

Sales of reserves in place (2,989) — (2,989) (347) — (347) (1,091) — (1,091) (21,107) (3,518)

Purchases of reserves in place — — — — — — — — — — —

Balance at December 31, 2011 31,593 — 31,593 44,429 — 44,429 1,396,516 51,738 1,448,254 1,904,386 317,398

Revisions of previous estimates (6,151) — (6,151) (6,023) — (6,023) (479,009) (51,738) (530,747) (603,791) (100,632)

Extensions and discoveries 16,574 — 16,574 6,929 — 6,929 93,643 — 93,643 234,661 39,110

Production (3,146) — (3,146) (3,489) — (3,489) (81,008) — (81,008) (120,818) (20,136)

Sales of reserves in place (5,168) — (5,168) (591) — (591) (17,309) — (17,309) (51,863) (8,644)

Purchases of reserves in place — — — — — — — — — — —

Balance at December 31, 2012 33,702 — 33,702 41,255 — 41,255 912,833 — 912,833 1,362,575 227,096

Proved developed reserves at:

January 1, 2010 11,327 — 11,327 23,037 — 23,037 916,005 — 916,005 1,122,189 187,032

December 31, 2010 13,421 — 13,421 24,120 — 24,120 886,644 25,869 912,513 1,137,759 189,627

December 31, 2011 14,149 — 14,149 23,170 — 23,170 814,160 — 814,160 1,038,074 173,012

December 31, 2012 12,315 — 12,315 25,518 — 25,518 710,288 — 710,288 937,286 156,214

Proved undeveloped reserves at:

January 1, 2010 5,605 — 5,605 15,199 — 15,199 499,426 51,738 551,164 675,988 112,665

December 31, 2010 6,897 — 6,897 19,264 — 19,264 547,087 25,869 572,956 729,922 121,654

December 31, 2011 17,444 — 17,444 21,259 — 21,259 582,356 51,738 634,094 866,312 144,385

December 31, 2012 21,387 — 21,387 15,737 — 15,737 202,545 — 202,545 425,289 70,882

___________________________________________

(1) Oil and natural gas liquids are converted to gas-equivalents using a conversion of six Mcf “equivalent” per barrel of oil or natural gas liquids. Likewise, natural gas is

converted to oil-equivalents using a conversion of one barrel of oil “equivalent” per six Mcf of natural gas. These conversions are based on energy equivalence and not price

equivalence.

105
Table of Contents

Revisions of previous estimates

In 2012, net negative revisions of 604 Bcfe were primarily associated with lower natural gas and natural gas liquids prices, which caused certain

natural gas-weighted projects to no longer meet economic investment criteria based on the unweighted arithmetic average of the first-day-of-the-month

commodity prices utilized in calculating our reserve estimates. In addition, lower natural gas prices also delayed Forest’s initial expected development time

frame for drilling certain of its proved undeveloped natural gas locations beyond five years from the time the associated reserves were originally recorded.

Accordingly, these proved undeveloped reserves (“PUDs”) were reclassified to probable undeveloped reserves in 2012. Additionally, all 52 Bcfe of the

Company’s Italian PUDs were reclassified to probable due to an Italian regional regulatory body’s denial of the Company’s environmental impact assessment

associated with the Company’s proposal to commence natural gas production from wells that it drilled and completed in 2007. The Company is currently

appealing the region’s denial; however, until the region’s denial is reversed or overturned, the Company determined that it could no longer conclude with

reasonable certainty that its Italian natural gas reserves are producible. In 2011, net negative revisions of 120 Bcfe were primarily the result of the write-off of

PUDs pursuant to the five year limitation and the write-off of natural gas reserves associated with a deep gas project in South Louisiana. In 2010, the net

negative revisions of 33 Bcfe were primarily the result of performance in existing producing wells.

Extensions and discoveries

In 2012, the Company had 235 Bcfe of extensions and discoveries, which were primarily due to exploration and development activities in the Texas

Panhandle Area and the Eagle Ford Shale in South Texas. In 2011, the Company had 301 Bcfe of extensions and discoveries, which were also primarily due to

exploration and development activities in the Texas Panhandle Area and the Eagle Ford Shale in South Texas. In 2010, the Company had 282 Bcfe of

extensions and discoveries, which were primarily due to successful drilling results in the Texas Panhandle Area and North Louisiana.

Sales of reserves in place

Sales of reserves in place for each of the years presented in the table above represent the sale of oil and gas property interests. See Note 2 for a

description of these sales.

Aggregate Capitalized Costs

The aggregate capitalized costs relating to oil and gas producing activities were as follows as of the dates indicated:

December 31,

2012 2011

(In Thousands)

Costs related to proved properties $ 9,696,498 $ 8,825,142

Costs related to unproved properties 277,798 675,995

9,974,296 9,501,137

Less accumulated depletion (8,237,186) (6,901,997)

$ 1,737,110 $ 2,599,140

106
Table of Contents

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

The following costs were incurred in oil and gas property acquisition, exploration, and development activities during the years ended December 31,

2012, 2011, and 2010:

United

States Italy Total

(In Thousands)

2012

Property acquisition costs:

Proved properties $ — $ — $ —

Unproved properties 64,123 — 64,123

Exploration costs 268,153 700 268,853

Development costs 398,941 182 399,123

Total costs incurred(1)

$ 731,217 $ 882 $ 732,099

2011

Property acquisition costs:

Proved properties $ — $ — $ —

Unproved properties 204,484 — 204,484

Exploration costs 286,412 1,003 287,415

Development costs 417,469 366 417,835

Total costs incurred(1)

$ 908,365 $ 1,369 $ 909,734

2010

Property acquisition costs:

Proved properties $ 5,823 $ — $ 5,823

Unproved properties 64,593 — 64,593

Exploration costs 190,553 2,386 192,939

Development costs 319,510 317 319,827

Total costs incurred(1)

$ 580,479 $ 2,703 $ 583,182

____________________________________________

(1) Includes amounts relating to changes in estimated asset retirement obligations of $6.1 million, $3.1 million, and $(1.1) million recorded during the years ended December 31,

2012, 2011, and 2010, respectively.

107
Table of Contents

Results of Operations from Oil and Gas Producing Activities

Results of operations from oil and gas producing activities for the years ended December 31, 2012, 2011, and 2010 are presented below.

United

States Italy Total

(In Thousands, except per Mcfe amounts)

2012

Oil, natural gas, and natural gas liquids sales $ 605,523 $ — $ 605,523

Expenses:

Production expense 156,909 — 156,909

Depletion expense 275,886 — 275,886

Ceiling test write-down of oil and natural gas properties 957,587 34,817 992,404

Accretion of asset retirement obligations 6,487 62 6,549

Income tax 173,437 — 173,437

Total expenses 1,570,306 34,879 1,605,185

Results of operations from oil and gas producing activities $ (964,783) $ (34,879) $ (999,662)

Depletion rate per Mcfe $ 2.28 $ — $ 2.28

2011

Oil, natural gas, and natural gas liquids sales $ 703,531 $ — $ 703,531

Expenses:

Production expense 153,518 — 153,518

Depletion expense 213,866 — 213,866

Accretion of asset retirement obligations 5,973 44 6,017

Income tax expense 89,135 — 89,135

Total expenses 462,492 44 462,536

Results of operations from oil and gas producing activities $ 241,039 $ (44) $ 240,995

Depletion rate per Mcfe $ 1.75 $ — $ 1.75

2010

Oil, natural gas, and natural gas liquids sales $ 707,692 $ — $ 707,692

Expenses:

Production expense 149,292 — 149,292

Depletion expense 179,656 — 179,656

Accretion of asset retirement obligations 6,057 41 6,098

Income tax expense 134,801 — 134,801

Total expenses 469,806 41 469,847

Results of operations from oil and gas producing activities $ 237,886 $ (41) $ 237,845

Depletion rate per Mcfe $ 1.31 $ — $ 1.31

Standardized Measure of Discounted Future Net Cash Flows

Future oil, natural gas, and NGL sales are calculated applying the prices used in estimating the Company’s proved oil, natural gas, and NGL

reserves to the year-end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence

at each year-end. Future production and development costs, which include costs related to plugging of wells, removal of facilities and equipment, and

108
Table of Contents

site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved reserves at the end of each year, based on

year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end

statutory tax rates to the estimated future pretax net cash flows relating to proved reserves, less the tax bases of the properties involved. The future income tax

expenses give effect to tax deductions, credits, and allowances relating to the proved reserves. All cash flow amounts, including income taxes, are discounted at

10%.

Changes in the demand for oil, natural gas, and NGLs, inflation, and other factors make such estimates inherently imprecise and subject to

substantial revision. This table should not be construed to be an estimate of the current market value of the Company’s proved reserves. Management does not

rely upon the information that follows in making investment decisions.

December 31, 2012

United States Italy Total

(In Thousands)

Future oil, natural gas, and natural gas liquids sales $ 6,929,652 $ — $ 6,929,652

Future production costs (2,166,681) — (2,166,681)

Future development costs (1,444,144) — (1,444,144)

Future income taxes (142,383) — (142,383)

Future net cash flows 3,176,444 — 3,176,444

10% annual discount for estimated timing of cash flows (1,779,347) — (1,779,347)

Standardized measure of discounted future net cash flows $ 1,397,097 $ — $ 1,397,097

December 31, 2011

United States Italy Total

(In Thousands)

Future oil, natural gas, and natural gas liquids sales $ 10,427,716 $ 576,364 $ 11,004,080

Future production costs (2,692,993) (199,054) (2,892,047)

Future development costs (2,008,824) (18,692) (2,027,516)

Future income taxes (940,526) (130,836) (1,071,362)

Future net cash flows 4,785,373 227,782 5,013,155

10% annual discount for estimated timing of cash flows (2,499,631) (125,783) (2,625,414)

Standardized measure of discounted future net cash flows $ 2,285,742 $ 101,999 $ 2,387,741

December 31, 2010

United States Italy Total

(In Thousands)

Future oil, natural gas, and natural gas liquids sales $ 9,029,839 $ 904,902 $ 9,934,741

Future production costs (2,546,332) (192,013) (2,738,345)

Future development costs (1,462,832) (17,100) (1,479,932)

Future income taxes (860,047) (260,541) (1,120,588)

Future net cash flows 4,160,628 435,248 4,595,876

10% annual discount for estimated timing of cash flows (2,195,708) (229,722) (2,425,430)

Standardized measure of discounted future net cash flows $ 1,964,920 $ 205,526 $ 2,170,446

109
Table of Contents

Changes in the Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows:

December 31, 2012

United States Italy Total

(In Thousands)

Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and

NGL reserves, at beginning of year $ 2,285,742 $ 101,999 $ 2,387,741

Changes resulting from:

Sales of oil, natural gas, and NGL net of production costs (448,614) — (448,614)

Net changes in prices and future production costs (1,226,494) (9,264) (1,235,758)

Net changes in future development costs (4,188) — (4,188)

Extensions, discoveries, and improved recovery 572,516 — 572,516

Development costs incurred during the period 140,111 — 140,111

Revisions of previous quantity estimates (203,987) (151,578) (355,565)

Changes in production rates, timing, and other (34,665) — (34,665)

Sales of reserves in place (213,683) — (213,683)

Purchases of reserves in place — — —

Accretion of discount on reserves at beginning of year 259,393 3,923 263,316

Net change in income taxes 270,966 54,920 325,886

Total change for year (888,645) (101,999) (990,644)

Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and

NGL reserves, at end of year $ 1,397,097 $ — $ 1,397,097

The computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2012 was based on

average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior

to December 31, 2012 were $2.76 per MMBtu and $94.79 per barrel, respectively.

110
Table of Contents

December 31, 2011

United States Italy Total

(In Thousands)

Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and

NGL reserves, at beginning of year $ 1,964,920 $ 205,526 $ 2,170,446

Changes resulting from:

Sales of oil, natural gas, and NGL net of production costs (550,013) — (550,013)

Net changes in prices and future production costs 272,027 (153,313) 118,714

Net changes in future development costs (55,725) (697) (56,422)

Extensions, discoveries, and improved recovery 667,323 — 667,323

Development costs incurred during the period 231,270 — 231,270

Revisions of previous quantity estimates (220,389) — (220,389)

Changes in production rates, timing, and other (132,714) (40,508) (173,222)

Sales of reserves in place (107,742) — (107,742)

Purchases of reserves in place — — —

Accretion of discount on reserves at beginning of year 226,354 31,949 258,303

Net change in income taxes (9,569) 59,042 49,473

Total change for year 320,822 (103,527) 217,295

Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and

NGL reserves, at end of year $ 2,285,742 $ 101,999 $ 2,387,741

The computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2011 was based on

average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior

to December 31, 2011 were $4.12 per MMBtu and $96.08 per barrel, respectively.

December 31, 2010

United States Italy Total

(In Thousands)

Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and

NGL reserves, at beginning of year $ 1,328,889 $ 225,420 $ 1,554,309

Changes resulting from:

Sales of oil, natural gas, and NGL net of production costs (558,400) — (558,400)

Net changes in prices and future production costs 603,003 2,040 605,043

Net changes in future development costs (29,183) 17,586 (11,597)

Extensions, discoveries, and improved recovery 445,546 — 445,546

Development costs incurred during the period 134,451 — 134,451

Revisions of previous quantity estimates 48,960 — 48,960

Changes in production rates, timing, and other 115,768 (65,068) 50,700

Sales of reserves in place (34,108) — (34,108)

Purchases of reserves in place 6,530 — 6,530

Accretion of discount on reserves at beginning of year 139,179 33,175 172,354

Net change in income taxes (235,715) (7,627) (243,342)

Total change for year 636,031 (19,894) 616,137

Standardized measure of discounted future net cash flows relating to proved oil, natural gas, and

NGL reserves, at end of year $ 1,964,920 $ 205,526 $ 2,170,446

111
Table of Contents

The computation of the standardized measure of discounted future net cash flows relating to proved reserves at December 31, 2010 was based on

average prices and year-end costs. The Henry Hub average natural gas price and West Texas Intermediate average oil price during the twelve-month period prior

to December 31, 2010 were $4.38 per MMBtu and $79.81 per barrel, respectively.

112
Table of Contents

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures.

We have established disclosure controls and procedures to ensure that material information relating to Forest and its consolidated subsidiaries is

made known to the Officers who certify Forest’s financial reports and the Board of Directors.

Our Chief Executive Officer, Patrick R. McDonald, and our Chief Financial Officer, Michael N. Kennedy, evaluated the effectiveness of our

disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of the end of the period covered by this Annual

Report on Form 10-K (the “Evaluation Date”). Based on this evaluation, they believe that as of the Evaluation Date our disclosure controls and procedures were

effective to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act (i) is recorded, processed,

summarized, and reported within the time periods specified in the SEC’s rules and forms; and (ii) is accumulated and communicated to Forest’s management,

including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the

Exchange Act, Rules 13a-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief

Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control

—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework

in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31,

2012. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Ernst & Young LLP, an independent

registered public accounting firm, as stated in their report which is included herein.

Changes in Internal Control Over Financial Reporting.

There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended December 31, 2012

that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

113
Table of Contents

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Forest Oil Corporation

We have audited Forest Oil Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal

Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Forest Oil

Corporation’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of

internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our

responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards

require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all

material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness

exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we

considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial

reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal

control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and

fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to

permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are

being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or

timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any

evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of

compliance with the policies or procedures may deteriorate.

In our opinion, Forest Oil Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31,

2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated

balance sheets of Forest Oil Corporation as of December 31, 2012 and 2011 and the related consolidated statements of operations, comprehensive income,

shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012 and our report dated February 22, 2013 expressed an

unqualified opinion thereon.

/s/ Ernst & Young LLP 

Denver, Colorado

February 22, 2013

114
Table of Contents

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The following persons were serving as executive officers of Forest as of February 21, 2013.

Name Age

Years

with

Forest Office(1)

Patrick R. McDonald 55 1 President and Chief Executive Officer since September 2012 after serving as our Interim Chief Executive Officer since

June 2012, and has been a member of the Board since 2004. He was appointed as the Chief Executive Officer,

President and as a Director and Chairman of the Board of Directors of Carbon Natural Gas Co. on February 14, 2011

and served as Chief Executive Officer, President and Director of its predecessor company, Nytis USA, since 2004. In

March 2011, Mr. McDonald was elected as a director of Lone Pine Resources Inc., an oil and gas exploration,

development and production company. From 1998 to 2003, Mr. McDonald served as President, Chief Executive

Officer, and Director of Carbon Energy Corporation, an oil and gas exploration and production company. From 1987 to

1997, Mr. McDonald served as Chief Executive Officer, President and Director of Interenergy Corporation, a natural

gas gathering, processing, and marketing company. Prior to that he worked as an exploration geologist with Texaco, Inc.

where he was responsible for oil and gas exploration efforts in the Middle and Far East.

Michael N. Kennedy 38 12 Executive Vice President and Chief Financial Officer since December 2009 and previously as Vice President, Finance

and Treasurer since April 2008. He joined Forest in February 2001 and served as Senior Financial Analyst until April

2003, at which time he became Manager - Investor Relations. Mr. Kennedy served in that role until November 2005, at

which time he became Managing Director, Capital Markets and Treasurer. Prior to joining Forest, he worked for Arthur

Andersen as a member of their audit and business advisory practice.

Frederick B. Dearman II 55 3 Senior Vice President, Southern Region since August 2012. Mr. Dearman joined Forest in August 2010 as Managing

Director, New Ventures, a role he filled until October 2011, when he was promoted to Vice President of that business

unit. Prior to joining Forest Mr. Dearman served as Special Projects Manager at Apache Corporation, an oil and gas

company, from 2001 to 2010. He also held the positions of Corporate Reservoir Engineering Manager from 1998 to 2001

and Senior Staff Reservoir Engineer 1996 to 1997 at Apache Corporation. He was employed by Amerada Hess

Corporation, also an oil and gas company, as a petroleum engineer from 1987 to 1996.

Michael J. Dern 58 13 Senior Vice President, Corporate Engineering and Technology, since January 2013. Mr. Dern served as Forest’s Vice

President, Corporate Engineering, from July 2011 until January 2013, as Manager, Reservoir Engineering, Eastern

Region, from May 2005 until July 2011, and as Manager, Corporate Planning, from May 2001 until May 2005. Prior to

joining Forest, he had more than 20 years of industry experience in corporate planning, reservoir engineering, and

reservoir engineering management at Phillips Petroleum, Exeter Exploration, Midcon Exploration, Apache Corporation,

and Gulf Canada Resources.

Cyrus D. Marter IV 49 11 Senior Vice President, General Counsel and Secretary since November 2007. Mr. Marter served as Vice President,

General Counsel and Secretary from January 2005 to November 2007, as Associate General Counsel from October 2004

to January 2005, and as Senior Counsel from June 2002 until October 2004. Prior to joining Forest, Mr. Marter was a

partner in the law firm of Susman Godfrey L.L.P. in Houston, Texas.

Glen J. Mizenko 50 12 Senior Vice President, Mid-Continent Region since August, 2012, when he assumed responsibility for Forest’s new

Mid-Continent Region, created through the combination of the former Eastern and Western Regions into a single

business unit. Mr. Mizenko joined Forest in January 2001 as Manager Corporate Development and New Ventures. In

October 2003 he was promoted to the position of Director, Business Development. In May 2005, he was promoted to

Vice President, Business Development, and in May 2007 to Senior Vice President, Business Development and

Corporate Engineering. From June 2011 until August 2012, Mr. Mizenko served as Senior Vice President, Eastern

Region. Prior to joining Forest, Mr. Mizenko held various positions in reservoir engineering, reserves reporting,

development planning, and operations management with Shell Oil, Benton Oil & Gas, and British Borneo Oil and Gas

PLC.

Victor A. Wind 39 8 Senior Vice President, Chief Accounting Officer, Corporate Controller, and Treasurer since January 2013; Senior Vice

President, Chief Accounting Officer and Corporate Controller from December 2009 until January 2013; Vice President,

Chief Accounting Officer and Corporate Controller from May until December 2009. Mr. Wind joined Forest in January

2005 as our Corporate Controller. Mr. Wind was previously employed by Evergreen Resources, Inc. from July 2001 to

December 2004. He served in various management positions during this period, including Director of Financial Reporting

and Controller. From 1997 to 2001, he served in various capacities at BDO Seidman, LLP.

____________________________________________

(1) Officers are appointed annually to serve for one-year terms at the board meeting immediately following the annual shareholder meeting, or until their death, resignation, or

removal from office, whichever first occurs.

115
Table of Contents

The following information will be included in Forest’s Notice of Annual Meeting of Shareholders and Proxy Statement (the “Proxy Statement”) to be

filed with the SEC within 120 days after Forest’s fiscal year end of December 31, 2012 and is incorporated herein by reference:

• Information concerning Forest’s directors is incorporated by reference to the information under the caption “Proposal No. 1—Election of

Directors”

• Information concerning the procedures for shareholders of Forest to recommend nominees to the Board is set forth under the caption “Corporate

Governance Principles and Information about the Board and its Committees—Consideration of Director Nominees— Shareholder Nominees”

• Information concerning Forest’s Audit Committee and designated “audit committee financial expert” is set forth under the caption “Corporate

Governance Principles and Information about the Board and its Committees—Board Structure; Committee Composition; Meetings”

• Information about Forest’s code of ethics for directors, officers, and employees is set forth under the caption “Corporate Governance Principles

and Information about the Board and its Committees—Corporate Governance Guidelines and Code of Business Ethics”

• Information about compliance with Section 16(a) of the Exchange Act is set forth under the caption “Section 16(a) Beneficial Ownership

Reporting Compliance”

Item 11. Executive Compensation.

Information regarding Forest’s compensation of its named executive officers and directors is set forth under the captions “Executive Compensation”

in the Proxy Statement, which information is incorporated herein by reference. See also “Executive Compensation—Compensation Committee Report” and

“Corporate Governance Principles and Information About the Board and Its Committees—Compensation Committee Interlocks and Insider Participation” for

additional information, which information is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Information regarding security ownership of certain beneficial owners, directors, and executive officers is set forth under the caption “Security

Ownership of Certain Beneficial Owners and Management” in the Proxy Statement, which information is incorporated herein by reference.

Information regarding Forest’s equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the Proxy

Statement, which information is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Information regarding certain relationships and related transactions is set forth under the caption “Transactions with Related Persons, Promoters and

Certain Control Persons,” and information regarding director independence is set forth under the caption “Corporate Governance Principles and Information

about the Board and its Committees—Board Independence” in the Proxy Statement, which information is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

Information regarding principal accounting fees and services is set forth under the caption “Principal Accountant Fees and Services” in the Proxy

Statement, which information is incorporated herein by reference.

116
Table of Contents

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) The following documents are filed as part of this report or are incorporated by reference:

(1) Financial Statements:

1. Report of Independent Registered Public Accounting Firm

2. Consolidated Balance Sheets—December 31, 2012 and 2011

3. Consolidated Statements of Operations—Years Ended December 31, 2012, 2011, and 2010

4. Consolidated Statements of Comprehensive Income—Years Ended December 31, 2012, 2011, and 2010

5. Consolidated Statements of Shareholders’ Equity—Years Ended December 31, 2012, 2011, and 2010

6. Consolidated Statements of Cash Flows—Years Ended December 31, 2012, 2011, and 2010

7. Notes to Consolidated Financial Statements—Years Ended December 31, 2012, 2011, and 2010

(2) Financial Statement Schedules: All schedules have been omitted because the information is either not required or is set forth in the financial

statements or the notes thereto.

(3) Exhibits: See the Index of Exhibits listed in Item 15(b) hereof for a list of those exhibits filed as part of this Annual Report on Form 10-K.

117
Table of Contents

(b) Index of Exhibits:

Exhibit

Number Description

3.1 Restated Certificate of Incorporation of Forest Oil Corporation, as amended to date, incorporated herein by reference to Exhibit 3.2 to Form

8-K for Forest Oil Corporation filed October 12, 2012 (File No. 001-13515).

3.2 Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, and No.

5, incorporated herein by reference to Exhibit 3.6 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2011 (File

No. 001-13515).

4.1 Indenture dated December 7, 2001 between Forest Oil Corporation and State Street Bank and Trust Company, including the form of

notes issued thereunder, incorporated herein by reference to Exhibit 4.5 to Forest Oil Corporation Registration Statement on Form S-4

dated February 6, 2002 (File No. 333-82254).

4.2 Indenture dated as of April 25, 2002 between Forest Oil Corporation and State Street Bank and Trust Company, including the form of

notes issued thereunder, incorporated herein by reference to Exhibit 4.6 to Forest Oil Corporation Registration Statement on Form S-4

dated June 11, 2002 (File No. 333-90220).

4.3 Indenture dated as of June 6, 2007 between Forest Oil Corporation and U.S. Bank National Association, including the form of notes

issued thereunder, incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30,

2007 (File No. 001-13515).

4.4 Indenture dated as of February 17, 2009 between Forest Oil Corporation, Forest Oil Permian Corporation and U.S. Bank National

Association, including the form of notes issued thereunder, incorporated herein by reference to Exhibit 4.4 to Form 10-K for Forest Oil

Corporation for the year ended December 31, 2008 (File No. 001-13515).

4.5 Indenture, dated as of September 17, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and U.S. Bank

National Association, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation filed September 17, 2012

(File No. 001-13515).

4.6 First Amended and Restated Rights Agreement, dated as of October 17, 2003, between Forest Oil Corporation and Mellon Investor

Services LLC, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation, dated October 17, 2003 (File

No. 001-13515).

4.7 Second Amended and Restated Credit Agreement dated as of June 6, 2007 among Forest Oil Corporation, each of the lenders that is party

thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, BNP Paribas, BMO Capital Markets

Financing, Inc., Credit Suisse, Cayman Islands Branch, and Deutsche Bank Securities, Inc., as Co-U.S. Documentation Agents, and

JPMorgan Chase Bank, N.A., as Global Administrative Agent, incorporated herein by reference to Exhibit 4.4 to Form 10-Q for Forest

Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).

4.8 First Amendment dated May 9, 2008 to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among Forest

Oil Corporation, Canadian Forest Oil Ltd., each of the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative

Agent, and JPMorgan Chase Bank N.A., Toronto Branch, as Canadian Administrative Agent, incorporated by reference to Exhibit 10.1

to Form 8-K for Forest Oil Corporation dated May 9, 2008 (File No. 001-13515).

4.9 Second Amendment dated March 16, 2009, to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among

Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders that is party thereto, JPMorgan Chase Bank, N.A., as Global

Administrative Agent, and JPMorgan Chase Bank, N.A., Toronto Branch, as Canadian Administrative Agent, incorporated herein by

reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation dated March 16, 2009 (File No. 001-13515).

118
Table of Contents

Exhibit

Number Description

4.10 Third Amendment to Second Amended and Restated U.S. Credit Agreement and Termination of Second Amended and Restated Canadian

Credit Agreement, dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., JPMorgan Chase Bank, N.A.,

Toronto branch, as Canadian Administrative Agent, JPMorgan Chase Bank, N.A., as global administrative agent, and the Lenders

named therein, incorporated by reference to Exhibit 4.1 to Form 8-K to Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

4.11 Third Amended and Restated Credit Agreement, dated as of June 30, 2011, among Forest Oil Corporation, the Lenders party thereto,

BNP Paribas and Wells Fargo Bank, N.A., as Co-Syndication Agents, Bank of America, N.A., The Bank of Nova Scotia, Credit

Suisse AG, Cayman Islands branch, Deutsche Bank Securities, Inc. and Toronto Dominion (Texas) LLC, as Co-Documentation Agents,

and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil

Corporation filed July 6, 2011 (File No. 001-13515).

10.1 * Forest Oil Corporation 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 4.1 to Registration Statement on Form S-8

for Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).

10.2 * Amendment No. 1 to Forest Oil Corporation’s 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q

for Forest Oil Corporation for the quarter ended June 30, 2003 (File No. 001-13515).

10.3 * Amendment No. 2 to Forest Oil Corporation’s 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q

for Forest Oil Corporation for the quarter ended March 31, 2004 (File No. 001-13515).

10.4 * Amendment No. 3 to Forest Oil Corporation 2001 Stock Incentive Plan, dated January 10, 2006, incorporated herein by reference to

Exhibit 10.8 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2005 (File No. 001-13515).

10.5 * Amendment No. 4 to Forest Oil Corporation 2001 Stock Incentive Plan dated June 5, 2007, incorporated herein by reference to

Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2007 (File No. 001-13515).

10.6 * Form of Employee Stock Option Agreement, incorporated herein by reference to Exhibit 4.2 to Registration Statement on Form S-8 for

Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).

10.7 * Form of Non-Employee Director Stock Option Agreement, incorporated herein by reference to Exhibit 4.3 to Registration Statement on

Form S-8 for Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).

10.8 * Form of Restricted Stock Agreement, incorporated herein by reference to Exhibit 10.6 to Form 10-Q for Forest Oil Corporation for the

quarter ended September 30, 2004 (File No. 001-13515).

10.9 * Form of Restricted Stock Agreement, incorporated herein by reference to Exhibit 10.12 to Form 10-K for Forest Oil Corporation for the

year ended December 31, 2005 (File No. 001-13515).

10.10 * Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2001 Stock Incentive Plan, incorporated herein by reference to

Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).

10.11 * Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2001 Stock Incentive Plan, as amended, incorporated

herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).

10.12 * Forest Oil Corporation 2007 Stock Incentive Plan, incorporated by reference to Annex E to Forest Oil Corporation’s Registration Statement

on Form S-4, dated April 30, 2007 (File No. 333-140532).

119
Table of Contents

Exhibit

Number Description

10.13 * Amendment No. 1 to Forest Oil Corporation 2007 Stock Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 10-Q for Forest

Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).

10.14 * Amendment No. 2 to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K

for Forest Oil Corporation dated May 12, 2010 (File No. 001-13515).

10.15 * Amendment No. 3 to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K

for Forest Oil Corporation dated February 18, 2011 (File No. 001-13515).

10.16 * Amendment No. 4 to Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.6 to Form 8-K for

Forest oil Corporation filed December 21, 2012 (File No. 001-13515).

10.17 * Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to

Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).

10.18 * Form of Non-Employee Director Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan,

incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2008 (File

No. 001-13515).

10.19 * Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2001 and 2007 Stock Incentive Plans, incorporated by

reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).

10.20 * Form of Restricted Stock Inducement Award Agreement, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil

Corporation filed October 1, 2012 (File No. 001-13515).

10.21 * Form of CEO Restricted Stock Award Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein

by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.22 *† Form of 2013 Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - Cliff Vest.

10.23 *† Form of 2013 Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - One-Third Vest.

10.24 * Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2001 and 2007 Stock Incentive Plans, incorporated by

reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).

10.25 * Form of Non-Employee Director Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan,

incorporated by reference to Exhibit 10.4 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-

13515).

10.26 * Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated

herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2009 (File No. 001-13515).

10.27 * Form of Phantom Stock Unit Agreement (Cash Only Three Vesting Tranches) pursuant to the Forest Oil Corporation 2007 Stock

Incentive Plan, as amended, incorporated by reference to Exhibit 10.3 to form 10-Q for Forest Oil Corporation for the quarter ended

September 30, 2011 (File No. 001-13515).

10.28 * Form of Phantom Stock Unit Agreement (4-Year Pro-Rated Vesting) pursuant to the Forest Oil Corporation 2007 Stock incentive Plan, as

amended, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed November 14, 2012 (File No. 001-

13515).

120
Table of Contents

Exhibit

Number Description

10.29 *† Form of 2013 Cash Only Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - Cliff Vest.

10.30 *† Form of 2013 Cash Only Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - One-Third

Vest.

10.31 * Form of Performance Unit Award Agreement (US) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended,

incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated May 21, 2010 (File No. 001-13515).

10.32 * Form of Forest Oil Corporation Performance Unit Award Agreement - 2012, pursuant to the Forest Oil Corporation 2007 Stock Incentive

Plan, as amended, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed March 16, 2012 (File No. 001-

13515).

10.33 * Form of CEO Plan Performance Unit Award Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended,

incorporated herein by reference to Exhibit 10.2 to Form 8-K to Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.34 * Form of Performance Unit Inducement Award Agreement, incorporated herein by reference to Exhibit 10.3 to Form 8-K for Forest Oil

Corporation filed October 1, 2012 (File No. 001-13515).

10.35 * Form of Cash-Based Award Agreement, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed June

13, 2011 (File No. 001-13515).

10.36 * Form of Forest Oil Corporation Cash-Based Award Agreement - 2012, incorporated herein by reference to Exhibit 10.3 to Form 8-K for

Forest Oil Corporation filed May 16, 2012 (File No. 001-13515).

10.37 * Form of Time-Based Cash Award Agreement, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation

filed November 14, 2012 (File No. 001-13515).

10.38 * Form of Severance Agreement for Grandfathered Executive Officer, incorporated herein by reference to Exhibit 10.1 to Form 8-K for

Forest Oil Corporation dated December 17, 2007 (File No. 001-13515).

10.39 * Form of Amendment to Form of Severance Agreement for Grandfathered Executive Officer, incorporated herein by reference to

Exhibit 10.30 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2008 (File No. 001-13515).

10.40 * Form of 409A Amendment to Severance Agreement for Grandfathered Vice President and Senior Vice President – No 5-Day Release

Provision, incorporated herein by reference to Exhibit 10.6 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2012

(File No. 001-13515).

10.41 * Form of CEO Severance Agreement, incorporated herein by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed October

1, 2012 (File no. 001-13515).

10.42 * Amendment to CEO Severance Agreement, incorporated herein by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed

December 21, 2012 (File No. 001-13515).

10.43 * Form of SVP Best Net Severance Agreement, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed

December 21, 2012 (File No. 001-13515).

10.44 * Form of SVP Best Net Grandfathered Severance Agreement, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil

Corporation filed December 21, 2012 (File No.001-13515).

10.45 * Form of VP Best Net Severance Agreement, incorporated herein by reference to Exhibit 10.3 to Form 8-K for Forest Oil Corporation filed

December 21, 2012 (File No. 001-13515).

10.46 * Forest Oil Corporation Pension Trust Agreement dated as of January 1, 2002 by and between Forest Oil Corporation and the trustees

named therein or their successors, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter

ended September 30, 2002, dated November 14, 2002 (File No. 001-13515).

121
Table of Contents

Exhibit

Number Description

10.47 * First Amendment to Forest Oil Corporation Pension Trust Agreement as Amended and Restated January 1, 2002, effective as of May 10,

2005, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2005 (File

No. 001-13515).

10.48 * Second Amendment to Forest Oil Corporation Pension Trust Agreement as Amended and Restated January 1, 2002, effective as of

May 10, 2006, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation dated August 9, 2006 (File

No. 001-13515).

10.49 * First Amendment to Forest Oil Corporation Executive Deferred Compensation Plan as Amended and Restated Effective as of January 1,

2005, incorporated herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2007

(File No. 001-13515).

10.50 * Forest Oil Corporation Executive Deferred Compensation Plan (as Amended and Restated, effective as of December 1, 2008), incorporated

herein by reference to Exhibit 10.41 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2008 (File No. 001-13515).

10.51 * First Amendment to Forest Oil Corporation Executive Deferred Compensation Plan (as Amended and Restated, effective as of December 1,

2008), incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated November 9, 2009 (File No. 001-

13515).

10.52 * Second Amendment to Forest Oil Corporation Executive Deferred Compensation Plan (as Amended and Restated, effective as of

December 1, 2008), incorporated by reference to Exhibit 10.50 to form 10-K for Forest Oil Corporation for the fiscal year ended

December 31, 2011 (File No. 001-13515).

10.53 * Third Amendment to Forest Oil Corporation Executive Deferred Compensation Plan, incorporated herein by reference to Exhibit 10.5 to

Form 8-K for Forest Oil Corporation filed December 21, 2012 (File No. 001-13515).

10.54 * Forest Oil Corporation 2010 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil

Corporation dated February 18, 2010 (File No. 001-13515).

10.55 * Forest Oil Corporation 2011 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed

August 16, 2011 (File No. 001-13515).

10.56 * Forest Oil Corporation 2012 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed

January 10, 2012 (File No. 001-13515).

10.57 Agreement for Purchase and Sale of Assets, dated as of August 5, 2009, by and among Forest Oil Corporation, Forest Oil Permian

Corporation, Linn Operating, Inc. and Linn Energy Holdings, LLC, incorporated herein by reference to Exhibit 10.1 to Form 8-K for

Forest Oil Corporation dated August 10, 2009 (File No. 001-13515).

10.58 Agreement for Purchase and Sale of Assets, dated as of November 25, 2009, by and among Forest Oil Corporation, Forest Oil Permian

Corporation and SandRidge Exploration and Production, LLC, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest

Oil Corporation dated November 25, 2009 (File No. 001-13515).

10.59 Separation and Distribution Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone

Pine Resources Inc., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-

13515).

10.60 Transition Services Agreement dated June 1, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated by

reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

10.61 Tax Sharing Agreement dated May 25, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated by

reference to Exhibit 10.3 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

122
Table of Contents

Exhibit

Number Description

10.62 Employee Matters Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone Pine

Resources Inc., incorporated by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

10.63 Registration Rights Agreement dated June 1, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated by

reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

10.64 Registration Rights Agreement, dated as of September 17, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation

and J.P. Morgan Securities LLC, as representative for the Initial Purchasers, incorporated herein by reference to Exhibit 4.2 to Form 8-K

for Forest Oil Corporation filed September 17, 2012 (File No. 001-13515).

10.65 Share Purchase and Sale Agreement, effective as of March 31, 2012, by and among African International Energy PLC, Forest Oil

Corporation, Anschutz South Africa Corporation, Forest Exploration International (South Africa) (Proprietary) Ltd and Anschutz

Overseas (South Africa) (Proprietary) ltd, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed

April 13, 2012 (File No. 001-13515).

10.66 Share Purchase and Sale Agreement, effective as of March 31, 2012, by and between African International Energy PLC and Forest Oil

Netherlands BV, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed April 13, 2012 (File No.

001-13515).

10.67 Agreement for Purchase and Sale of Assets, dated as of October 11, 2012, by and between Forest Oil Corporation and Texas Petroleum

Investment Company, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 12, 2012

(File No. 001.13515).

10.68 Agreement, dated as of October 22, 2012, by and among Forest Oil Corporation, Richard J. Carty, West Face Capital Inc. and West Face

Long Term Opportunities Global Market L.P., incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation

filed October 24, 2012 (File No. 001-13515).

10.69 Confidentiality Agreement, dated October 22, 2012, by and between Forest Oil Corporation and West Face Capital Inc., incorporated

herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed October 24, 2012 (File no. 001-13515).

10.70 Agreement for Purchase and Sale of Assets, dated as of January 2, 2012, by and between Forest Oil Corporation, Forest Oil Permian

Corporation, and Forcenergy Onshore Inc. (as Seller) and Hilcorp Energy I, L.P. (as Purchaser), incorporated herein by reference to

Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed January 3, 2012 (File No. 001-13515).

10.71 Purchase Agreement, dated as of September 12, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and the

Initial purchasers named therein, incorporated herein by reference to Exhibit 1.1 to Form 8-K for Forest Oil Corporation filed September

17, 2012 (File No. 001-13515).

21.1 † List of Subsidiaries of Registrant.

23.1 † Consent of Ernst & Young LLP.

23.2 † Consent of DeGolyer and MacNaughton.

24.1 † Powers of Attorney (included on the signature pages hereof).

31.1 † Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of

1934.

31.2 † Certification of Principal Financial Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of

1934.

32.1 ** Certification of Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

32.2 ** Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

123
Table of Contents

Exhibit

Number Description

99.1 † Reserves Audit Report of DeGolyer and MacNaughton, independent petroleum engineering consulting firm, dated January 28, 2013.

101.INS ± XBRL Instance Document.

101.SCH ± XBRL Taxonomy Extension Schema Document.

101.CAL ± XBRL Taxonomy Calculation Linkbase Document.

101.LAB ± XBRL Label Linkbase Document.

101.PRE ± XBRL Presentation Linkbase Document.

101.DEF ± XBRL Treasury Extension Definition

*Contract or compensatory plan or arrangement in which directors and/or officers participate.

**Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

†Indicates Exhibits filed with this Annual Report on Form 10-K.

±The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or

prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, are deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise, are not

subject to liability under these sections.

124
Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on

its behalf by the undersigned, thereunto duly authorized.

FOREST OIL CORPORATION

(Registrant)

February 22, 2013 By: /s/ PATRICK R. MCDONALD

Patrick R. McDonald

President and Chief Executive Officer

_____________________________________________________________________________________________________________________

Power of Attorney

The officers and directors of Forest Oil Corporation, whose signatures appear below, hereby constitute and appoint Patrick R. McDonald, Michael

N. Kennedy, Cyrus D. Marter IV, and Victor A. Wind and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to

sign and execute, on behalf of the undersigned, any amendment(s) to this Annual Report on Form 10-K for the year ended December 31, 2012, and any

instrument or document filed as part of, as an exhibit to or in connection with any amendment, and each of the undersigned does hereby ratify and confirm as

his own act and deed all that said attorneys shall do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the

registrant in the capacities and on the dates indicated.

Signatures Title Date

/s/ PATRICK R. MCDONALD President and Chief Executive Officer and Director (Principal

Executive Officer)

February 22, 2013

Patrick R. McDonald

/s/ MICHAEL N. KENNEDY Executive Vice President and Chief Financial Officer (Principal

Financial Officer)

February 22, 2013

Michael N. Kennedy

/s/ VICTOR A. WIND Senior Vice President, Chief Accounting Officer, Corporate Controller,

and Treasurer (Principal Accounting Officer)

February 22, 2013

Victor A. Wind

/s/ JAMES D. LIGHTNER Chairman of the Board February 22, 2013

James D. Lightner

/s/ LOREN K. CARROLL Director February 22, 2013

Loren K. Carroll

/s/ RICHARD J. CARTY Director February 22, 2013

Richard J. Carty

/s/ DOD A. FRASER Director

February 22, 2013

Dod A. Fraser

/s/ JAMES H. LEE Director February 22, 2013

James H. Lee

/s/ RAYMOND I. WILCOX Director February 22, 2013

Raymond I. Wilcox

125
Table of Contents

Index to Exhibits

Exhibit

Number Description

3.1 Restated Certificate of Incorporation of Forest Oil Corporation, as amended to date, incorporated herein by reference to Exhibit 3.2 to Form

8-K for Forest Oil Corporation filed October 12, 2012 (File No. 001-13515).

3.2 Bylaws of Forest Oil Corporation Restated as of February 14, 2001, as amended by Amendments No. 1, No. 2, No. 3, No. 4, and No.

5, incorporated herein by reference to Exhibit 3.6 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2011 (File

No. 001-13515).

4.1 Indenture dated December 7, 2001 between Forest Oil Corporation and State Street Bank and Trust Company, including the form of

notes issued thereunder, incorporated herein by reference to Exhibit 4.5 to Forest Oil Corporation Registration Statement on Form S-4

dated February 6, 2002 (File No. 333-82254).

4.2 Indenture dated as of April 25, 2002 between Forest Oil Corporation and State Street Bank and Trust Company, including the form of

notes issued thereunder, incorporated herein by reference to Exhibit 4.6 to Forest Oil Corporation Registration Statement on Form S-4

dated June 11, 2002 (File No. 333-90220).

4.3 Indenture dated as of June 6, 2007 between Forest Oil Corporation and U.S. Bank National Association, including the form of notes

issued thereunder, incorporated herein by reference to Exhibit 4.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30,

2007 (File No. 001-13515).

4.4 Indenture dated as of February 17, 2009 between Forest Oil Corporation, Forest Oil Permian Corporation and U.S. Bank National

Association, including the form of notes issued thereunder, incorporated herein by reference to Exhibit 4.4 to Form 10-K for Forest Oil

Corporation for the year ended December 31, 2008 (File No. 001-13515).

4.5 Indenture, dated as of September 17, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and U.S. Bank

National Association, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation filed September 17, 2012

(File No. 001-13515).

4.6 First Amended and Restated Rights Agreement, dated as of October 17, 2003, between Forest Oil Corporation and Mellon Investor

Services LLC, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation, dated October 17, 2003 (File

No. 001-13515).

4.7 Second Amended and Restated Credit Agreement dated as of June 6, 2007 among Forest Oil Corporation, each of the lenders that is party

thereto, Bank of America, N.A. and Citibank, N.A., as Co-Global Syndication Agents, BNP Paribas, BMO Capital Markets

Financing, Inc., Credit Suisse, Cayman Islands Branch, and Deutsche Bank Securities, Inc., as Co-U.S. Documentation Agents, and

JPMorgan Chase Bank, N.A., as Global Administrative Agent, incorporated herein by reference to Exhibit 4.4 to Form 10-Q for Forest

Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).

4.8 First Amendment dated May 9, 2008 to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among Forest

Oil Corporation, Canadian Forest Oil Ltd., each of the lenders party thereto, JPMorgan Chase Bank, N.A., as Global Administrative

Agent, and JPMorgan Chase Bank N.A., Toronto Branch, as Canadian Administrative Agent, incorporated by reference to Exhibit 10.1

to Form 8-K for Forest Oil Corporation dated May 9, 2008 (File No. 001-13515).

4.9 Second Amendment dated March 16, 2009, to Second Amended and Restated Combined Credit Agreements dated June 6, 2007, among

Forest Oil Corporation, Canadian Forest Oil Ltd., each of the lenders that is party thereto, JPMorgan Chase Bank, N.A., as Global

Administrative Agent, and JPMorgan Chase Bank, N.A., Toronto Branch, as Canadian Administrative Agent, incorporated herein by

reference to Exhibit 4.1 to Form 8-K for Forest Oil Corporation dated March 16, 2009 (File No. 001-13515).

126
Table of Contents

Exhibit

Number Description

4.10 Third Amendment to Second Amended and Restated U.S. Credit Agreement and Termination of Second Amended and Restated Canadian

Credit Agreement, dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., JPMorgan Chase Bank, N.A.,

Toronto branch, as Canadian Administrative Agent, JPMorgan Chase Bank, N.A., as global administrative agent, and the Lenders

named therein, incorporated by reference to Exhibit 4.1 to Form 8-K to Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

4.11 Third Amended and Restated Credit Agreement, dated as of June 30, 2011, among Forest Oil Corporation, the Lenders party thereto,

BNP Paribas and Wells Fargo Bank, N.A., as Co-Syndication Agents, Bank of America, N.A., The Bank of Nova Scotia, Credit

Suisse AG, Cayman Islands branch, Deutsche Bank Securities, Inc. and Toronto Dominion (Texas) LLC, as Co-Documentation Agents,

and JPMorgan Chase Bank, N.A., as Administrative Agent, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil

Corporation filed July 6, 2011 (File No. 001-13515).

10.1 * Forest Oil Corporation 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 4.1 to Registration Statement on Form S-8

for Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).

10.2 * Amendment No. 1 to Forest Oil Corporation’s 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q

for Forest Oil Corporation for the quarter ended June 30, 2003 (File No. 001-13515).

10.3 * Amendment No. 2 to Forest Oil Corporation’s 2001 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 10-Q

for Forest Oil Corporation for the quarter ended March 31, 2004 (File No. 001-13515).

10.4 * Amendment No. 3 to Forest Oil Corporation 2001 Stock Incentive Plan, dated January 10, 2006, incorporated herein by reference to

Exhibit 10.8 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2005 (File No. 001-13515).

10.5 * Amendment No. 4 to Forest Oil Corporation 2001 Stock Incentive Plan dated June 5, 2007, incorporated herein by reference to

Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2007 (File No. 001-13515).

10.6 * Form of Employee Stock Option Agreement, incorporated herein by reference to Exhibit 4.2 to Registration Statement on Form S-8 for

Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).

10.7 * Form of Non-Employee Director Stock Option Agreement, incorporated herein by reference to Exhibit 4.3 to Registration Statement on

Form S-8 for Forest Oil Corporation dated June 6, 2001 (File No. 333-62408).

10.8 * Form of Restricted Stock Agreement, incorporated herein by reference to Exhibit 10.6 to Form 10-Q for Forest Oil Corporation for the

quarter ended September 30, 2004 (File No. 001-13515).

10.9 * Form of Restricted Stock Agreement, incorporated herein by reference to Exhibit 10.12 to Form 10-K for Forest Oil Corporation for the

year ended December 31, 2005 (File No. 001-13515).

10.10 * Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2001 Stock Incentive Plan, incorporated herein by reference to

Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).

10.11 * Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2001 Stock Incentive Plan, as amended, incorporated

herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).

10.12 * Forest Oil Corporation 2007 Stock Incentive Plan, incorporated by reference to Annex E to Forest Oil Corporation’s Registration Statement

on Form S-4, dated April 30, 2007 (File No. 333-140532).

127
Table of Contents

Exhibit

Number Description

10.13 * Amendment No. 1 to Forest Oil Corporation 2007 Stock Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 10-Q for Forest

Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).

10.14 * Amendment No. 2 to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K

for Forest Oil Corporation dated May 12, 2010 (File No. 001-13515).

10.15 * Amendment No. 3 to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K

for Forest Oil Corporation dated February 18, 2011 (File No. 001-13515).

10.16 * Amendment No. 4 to Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.6 to Form 8-K for

Forest oil Corporation filed December 21, 2012 (File No. 001-13515).

10.17 * Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein by reference to

Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2007 (File No. 001-13515).

10.18 * Form of Non-Employee Director Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan,

incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2008 (File

No. 001-13515).

10.19 * Form of Restricted Stock Agreement pursuant to the Forest Oil Corporation 2001 and 2007 Stock Incentive Plans, incorporated by

reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).

10.20 * Form of Restricted Stock Inducement Award Agreement, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil

Corporation filed October 1, 2012 (File No. 001-13515).

10.21 * Form of CEO Restricted Stock Award Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, incorporated herein

by reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.22 *† Form of 2013 Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - Cliff Vest.

10.23 *† Form of 2013 Restricted Stock Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - One-Third Vest.

10.24 * Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2001 and 2007 Stock Incentive Plans, incorporated by

reference to Exhibit 10.3 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-13515).

10.25 * Form of Non-Employee Director Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan,

incorporated by reference to Exhibit 10.4 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2008 (File No. 001-

13515).

10.26 * Form of Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended, incorporated

herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2009 (File No. 001-13515).

10.27 * Form of Phantom Stock Unit Agreement (Cash Only Three Vesting Tranches) pursuant to the Forest Oil Corporation 2007 Stock

Incentive Plan, as amended, incorporated by reference to Exhibit 10.3 to form 10-Q for Forest Oil Corporation for the quarter ended

September 30, 2011 (File No. 001-13515).

10.28 * Form of Phantom Stock Unit Agreement (4-Year Pro-Rated Vesting) pursuant to the Forest Oil Corporation 2007 Stock incentive Plan, as

amended, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed November 14, 2012 (File No. 001-

13515).

128
Table of Contents

Exhibit

Number Description

10.29 *† Form of 2013 Cash Only Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - Cliff Vest.

10.30 *† Form of 2013 Cash Only Phantom Stock Unit Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan - One-Third

Vest.

10.31 * Form of Performance Unit Award Agreement (US) pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended,

incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated May 21, 2010 (File No. 001-13515).

10.32 * Form of Forest Oil Corporation Performance Unit Award Agreement - 2012, pursuant to the Forest Oil Corporation 2007 Stock Incentive

Plan, as amended, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed March 16, 2012 (File No. 001-

13515).

10.33 * Form of CEO Plan Performance Unit Award Agreement pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended,

incorporated herein by reference to Exhibit 10.2 to Form 8-K to Forest Oil Corporation filed October 1, 2012 (File No. 001-13515).

10.34 * Form of Performance Unit Inducement Award Agreement, incorporated herein by reference to Exhibit 10.3 to Form 8-K for Forest Oil

Corporation filed October 1, 2012 (File No. 001-13515).

10.35 * Form of Cash-Based Award Agreement, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed June

13, 2011 (File No. 001-13515).

10.36 * Form of Forest Oil Corporation Cash-Based Award Agreement - 2012, incorporated herein by reference to Exhibit 10.3 to Form 8-K for

Forest Oil Corporation filed May 16, 2012 (File No. 001-13515).

10.37 * Form of Time-Based Cash Award Agreement, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation

filed November 14, 2012 (File No. 001-13515).

10.38 * Form of Severance Agreement for Grandfathered Executive Officer, incorporated herein by reference to Exhibit 10.1 to Form 8-K for

Forest Oil Corporation dated December 17, 2007 (File No. 001-13515).

10.39 * Form of Amendment to Form of Severance Agreement for Grandfathered Executive Officer, incorporated herein by reference to

Exhibit 10.30 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2008 (File No. 001-13515).

10.40 * Form of 409A Amendment to Severance Agreement for Grandfathered Vice President and Senior Vice President – No 5-Day Release

Provision, incorporated herein by reference to Exhibit 10.6 to Form 10-Q for Forest Oil Corporation for the quarter ended March 31, 2012

(File No. 001-13515).

10.41 * Form of CEO Severance Agreement, incorporated herein by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed October

1, 2012 (File no. 001-13515).

10.42 * Amendment to CEO Severance Agreement, incorporated herein by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed

December 21, 2012 (File No. 001-13515).

10.43 * Form of SVP Best Net Severance Agreement, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed

December 21, 2012 (File No. 001-13515).

10.44 * Form of SVP Best Net Grandfathered Severance Agreement, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil

Corporation filed December 21, 2012 (File No.001-13515).

10.45 * Form of VP Best Net Severance Agreement, incorporated herein by reference to Exhibit 10.3 to Form 8-K for Forest Oil Corporation filed

December 21, 2012 (File No. 001-13515).

10.46 * Forest Oil Corporation Pension Trust Agreement dated as of January 1, 2002 by and between Forest Oil Corporation and the trustees

named therein or their successors, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter

ended September 30, 2002, dated November 14, 2002 (File No. 001-13515).

129
Table of Contents

Exhibit

Number Description

10.47 * First Amendment to Forest Oil Corporation Pension Trust Agreement as Amended and Restated January 1, 2002, effective as of May 10,

2005, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation for the quarter ended June 30, 2005 (File

No. 001-13515).

10.48 * Second Amendment to Forest Oil Corporation Pension Trust Agreement as Amended and Restated January 1, 2002, effective as of

May 10, 2006, incorporated herein by reference to Exhibit 10.1 to Form 10-Q for Forest Oil Corporation dated August 9, 2006 (File

No. 001-13515).

10.49 * First Amendment to Forest Oil Corporation Executive Deferred Compensation Plan as Amended and Restated Effective as of January 1,

2005, incorporated herein by reference to Exhibit 10.2 to Form 10-Q for Forest Oil Corporation for the quarter ended September 30, 2007

(File No. 001-13515).

10.50 * Forest Oil Corporation Executive Deferred Compensation Plan (as Amended and Restated, effective as of December 1, 2008), incorporated

herein by reference to Exhibit 10.41 to Form 10-K for Forest Oil Corporation for the year ended December 31, 2008 (File No. 001-13515).

10.51 * First Amendment to Forest Oil Corporation Executive Deferred Compensation Plan (as Amended and Restated, effective as of December 1,

2008), incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation dated November 9, 2009 (File No. 001-

13515).

10.52 * Second Amendment to Forest Oil Corporation Executive Deferred Compensation Plan (as Amended and Restated, effective as of

December 1, 2008), incorporated by reference to Exhibit 10.50 to form 10-K for Forest Oil Corporation for the fiscal year ended

December 31, 2011 (File No. 001-13515).

10.53 * Third Amendment to Forest Oil Corporation Executive Deferred Compensation Plan, incorporated herein by reference to Exhibit 10.5 to

Form 8-K for Forest Oil Corporation filed December 21, 2012 (File No. 001-13515).

10.54 * Forest Oil Corporation 2010 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil

Corporation dated February 18, 2010 (File No. 001-13515).

10.55 * Forest Oil Corporation 2011 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed

August 16, 2011 (File No. 001-13515).

10.56 * Forest Oil Corporation 2012 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed

January 10, 2012 (File No. 001-13515).

10.57 Agreement for Purchase and Sale of Assets, dated as of August 5, 2009, by and among Forest Oil Corporation, Forest Oil Permian

Corporation, Linn Operating, Inc. and Linn Energy Holdings, LLC, incorporated herein by reference to Exhibit 10.1 to Form 8-K for

Forest Oil Corporation dated August 10, 2009 (File No. 001-13515).

10.58 Agreement for Purchase and Sale of Assets, dated as of November 25, 2009, by and among Forest Oil Corporation, Forest Oil Permian

Corporation and SandRidge Exploration and Production, LLC, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest

Oil Corporation dated November 25, 2009 (File No. 001-13515).

10.59 Separation and Distribution Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone

Pine Resources Inc., incorporated by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-

13515).

10.60 Transition Services Agreement dated June 1, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated by

reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

10.61 Tax Sharing Agreement dated May 25, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated by

reference to Exhibit 10.3 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

10.62 Employee Matters Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone Pine

Resources Inc., incorporated by reference to Exhibit 10.4 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

130
Table of Contents

Exhibit

Number Description

10.63 Registration Rights Agreement dated June 1, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated by

reference to Exhibit 10.5 to Form 8-K for Forest Oil Corporation filed June 1, 2011 (File No. 001-13515).

10.64 Registration Rights Agreement, dated as of September 17, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation

and J.P. Morgan Securities LLC, as representative for the Initial Purchasers, incorporated herein by reference to Exhibit 4.2 to Form 8-K

for Forest Oil Corporation filed September 17, 2012 (File No. 001-13515).

10.65 Share Purchase and Sale Agreement, effective as of March 31, 2012, by and among African International Energy PLC, Forest Oil

Corporation, Anschutz South Africa Corporation, Forest Exploration International (South Africa) (Proprietary) Ltd and Anschutz

Overseas (South Africa) (Proprietary) ltd, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed

April 13, 2012 (File No. 001-13515).

10.66 Share Purchase and Sale Agreement, effective as of March 31, 2012, by and between African International Energy PLC and Forest Oil

Netherlands BV, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed April 13, 2012 (File No.

001-13515).

10.67 Agreement for Purchase and Sale of Assets, dated as of October 11, 2012, by and between Forest Oil Corporation and Texas Petroleum

Investment Company, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed October 12, 2012

(File No. 001.13515).

10.68 Agreement, dated as of October 22, 2012, by and among Forest Oil Corporation, Richard J. Carty, West Face Capital Inc. and West Face

Long Term Opportunities Global Market L.P., incorporated herein by reference to Exhibit 10.1 to Form 8-K for Forest Oil Corporation

filed October 24, 2012 (File No. 001-13515).

10.69 Confidentiality Agreement, dated October 22, 2012, by and between Forest Oil Corporation and West Face Capital Inc., incorporated

herein by reference to Exhibit 10.2 to Form 8-K for Forest Oil Corporation filed October 24, 2012 (File no. 001-13515).

10.70 Agreement for Purchase and Sale of Assets, dated as of January 2, 2012, by and between Forest Oil Corporation, Forest Oil Permian

Corporation, and Forcenergy Onshore Inc. (as Seller) and Hilcorp Energy I, L.P. (as Purchaser), incorporated herein by reference to

Exhibit 10.1 to Form 8-K for Forest Oil Corporation filed January 3, 2012 (File No. 001-13515).

10.71 Purchase Agreement, dated as of September 12, 2012, by and among Forest Oil Corporation, Forest Oil Permian Corporation and the

Initial purchasers named therein, incorporated herein by reference to Exhibit 1.1 to Form 8-K for Forest Oil Corporation filed September

17, 2012 (File No. 001-13515).

21.1 † List of Subsidiaries of Registrant.

23.1 † Consent of Ernst & Young LLP.

23.2 † Consent of DeGolyer and MacNaughton.

24.1 † Powers of Attorney (included on the signature pages hereof).

31.1 † Certification of Principal Executive Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of

1934.

31.2 † Certification of Principal Financial Officer of Forest Oil Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of

1934.

32.1 ** Certification of Chief Executive Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

32.2 ** Certification of Chief Financial Officer of Forest Oil Corporation pursuant to 18 U.S.C. §1350.

131
Table of Contents

Exhibit

Number Description

99.1 † Reserves Audit Report of DeGolyer and MacNaughton, independent petroleum engineering consulting firm, dated January 28, 2013.

101.INS ± XBRL Instance Document.

101.SCH ± XBRL Taxonomy Extension Schema Document.

101.CAL ± XBRL Taxonomy Calculation Linkbase Document.

101.LAB ± XBRL Label Linkbase Document.

101.PRE ± XBRL Presentation Linkbase Document.

101.DEF ± XBRL Treasury Extension Definition

*Contract or compensatory plan or arrangement in which directors and/or officers participate.

**Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

†Indicates Exhibits filed with this Annual Report on Form 10-K.

±The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or

prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, are deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise, are not

subject to liability under these sections.

132
 

RESTRICTED STOCK AGREEMENT

THIS RESTRICTED STOCK AGREEMENT (this “Agreement”) is made as of the ____ day of _________, 20__,

between Forest Oil Corporation, a New York corporation (the “Company”), and __________________ (the “Employee”).

1. Award. Pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended (the “Plan”), as of the date of this

Agreement, _____ shares of the Company’s common stock, par value $.10 per share (the “Restricted Stock”), shall be issued as

hereinafter provided in the Employee’s name subject to certain restrictions thereon, in consideration of services that the Employee has

performed for the Company in 20__ and services to be provided to the Company in the future. The Restricted Stock shall be issued upon

acceptance of this Agreement by the Employee and upon satisfaction of the conditions of this Agreement. This award of Restricted

Stock shall be subject to all of the terms and provisions of the Plan, including future amendments thereto, if any, which is available on

http://corpweb1/. For paper copies of the Plan and prospectus please contact Stock Administration, 707 Seventeenth Street, Suite 3600,

Denver, CO 80202, or call 303.812.1502. In the event of any conflict between the terms of this Agreement and the Plan, the Plan shall

control.

2. Restricted Stock. The Employee hereby accepts the Restricted Stock when issued and agrees with respect thereto as

follows:

(a) Forfeiture Restrictions. The Restricted Stock may not be sold, assigned, pledged, exchanged, hypothecated or

otherwise transferred, encumbered or disposed of to the extent then subject to the Forfeiture Restrictions (as hereinafter defined), and

in the event of termination of the Employee’s employment with the Company for any reason other than death, Disability, or

Involuntary Termination (as such terms are hereinafter defined), the Employee shall, for no consideration, forfeit to the Company all

Restricted Stock to the extent then subject to the Forfeiture Restrictions. The prohibition against transfer and the obligation to forfeit and

surrender Restricted Stock to the Company upon termination of employment are herein referred to as the “Forfeiture Restrictions.”

The Forfeiture Restrictions shall be binding upon and enforceable against any transferee of Restricted Stock. For purposes of this

Agreement, the following capitalized words and terms shall have the meanings indicated below:

(i) “Board” shall mean the Board of Directors of the Company.

(ii) “Code” shall mean the Internal Revenue Code of 1986, as amended.

(iii) “Committee” shall mean the committee of the Board that is selected by the Board to administer the Plan

as provided in the Plan.

(iv) “Corporate Change” shall mean the occurrence of any one or more of the following events:

(A) the Company shall not be the surviving entity in any merger, consolidation or other reorganization

(or survives only as a subsidiary of an entity other than a
previously wholly-owned subsidiary of the Company);

(B) the Company sells, leases or exchanges all or substantially all of its assets to any other person or

entity (other than a wholly-owned subsidiary of the Company);

(C) the Company is to be dissolved and liquidated;

(D) any person or entity, including a “group” as contemplated by Section 13(d)(3) of the Securities

Exchange Act of 1934, as amended, acquires or gains ownership or control (including, without limitation, power to vote) of more than

40% of the outstanding shares of the Company’s voting stock (based upon voting power); or

(E) as a result of or in connection with a contested election of directors, the persons who were

directors of the Company before such election shall cease to constitute a majority of the Board.

Notwithstanding the foregoing, the term “Corporate Change” shall not include any reorganization, merger or

consolidation involving solely the Company and one or more previously wholly-owned subsidiaries of the Company.

(v) “Disability” shall have the meaning set forth in the Severance Agreement, or if there is no Severance

Agreement or if the Severance Agreement contains no such definition, “Disability” shall mean that, as a result of the Employee’s

incapacity due to physical or mental illness, he shall have been absent from the full-time performance of his duties for six consecutive

months, and he shall not have returned to full-time performance of his duties within 30 days after written notice of termination is given

to the Employee by the Company (provided, however, that such notice may not be given prior to 30 days before the expiration of such

six-month period).

(vi) “Involuntary Termination” shall have the meaning set forth in the Severance Agreement, or if there is no

Severance Agreement or if the Severance Agreement contains no such definition, “Involuntary Termination” shall mean any

termination of the Employee’s employment with the Company which does not result from a resignation by the Employee; provided,

however, that the term “Involuntary Termination” shall not include a termination as a result of death, Disability, or a termination of the

Employee’s employment by the Company (or its subsidiaries) by reason of the Employee’s unsatisfactory performance of his duties, to

be determined by the Company in its sole discretion, or final conviction of a misdemeanor involving moral turpitude or a felony.

(vii) “Section 16 Person” shall mean an officer, director or affiliate of the Company or a former officer,

director or affiliate of the Company who is subject to section 16 of the Securities Exchange Act of 1934, as amended.

(viii) “Severance Agreement” means any Severance Agreement solely between the Employee and the

Company in effect as of the date of this Agreement, as such may be amended or superseded from time to time.

(b) Lapse of Forfeiture Restrictions. The Forfeiture Restrictions shall lapse

Page 2
as to the Restricted Stock in accordance with the following schedule provided that the Employee has been continuously employed by

the Company from the date of this Agreement through the lapse date:

Percentage of Total Number of

 Shares of Restricted Stock as to

 Lapse Date Which Forfeiture Restrictions Lapse

 

Notwithstanding the foregoing, the Forfeiture Restrictions shall lapse as to all of the Restricted Stock then

subject to the Forfeiture Restrictions on (i) the date of a Corporate Change if the successor entity does not assume, convert or replace

the Restricted Stock governed by this Agreement with an equity or equity-based award that is substantially the same in all material

economic respects, (ii) the date the Employee’s employment with the Company is terminated by reason of death, Disability or

Involuntary Termination, or (iii) at the Committee's discretion, as of the date determined by the Committee. For the avoidance of doubt,

if, in connection with a Corporate Change, the successor entity assumes, converts or replaces this Agreement with an agreement that is

substantially the same in all material economic respects, any Forfeiture Restrictions continuing after such Corporate Change with

respect to such assumed, converted or replaced award shall lapse on the earliest to occur of (i) the lapse date set forth above or (ii) date of

Employee's Involuntary Termination following such a Corporate Change.

(c) Certificates. A certificate evidencing the Restricted Stock shall be issued by the Company in Employee’s name,

pursuant to which Employee shall have all of the rights of a shareholder of the Company with respect to the Restricted Stock,

including, without limitation, voting rights and the right to receive dividends; provided, however, that dividends paid in shares of the

Company’s stock shall be subject to the Forfeiture Restrictions. The Employee may not sell, transfer, pledge, exchange, hypothecate or

otherwise dispose of the Restricted Stock until the Forfeiture Restrictions have expired and a breach of the terms of this Agreement

shall cause a forfeiture of the Restricted Stock. The Company, in its discretion, may elect to complete the delivery of the Restricted

Stock by means of electronic, book-entry statement, instead of issuing physical share certificates.

Certificates, if any, shall be delivered upon issuance to the Secretary of the Company or to such other

depository as may be designated by the Committee as a depository for safekeeping until the forfeiture of such Restricted Stock occurs or

the Forfeiture Restrictions lapse pursuant to the terms of the Plan and this award. Upon the lapse of the Forfeiture Restrictions, the

Company shall cause a new certificate or certificates to be issued without legend (except for any legend required pursuant to applicable

securities laws or any other agreement to which the Employee is a party) in the name of the Employee in exchange for the certificate

evidencing the Restricted Stock, or, as may be the case, it shall issue appropriate instructions to the transfer agent if the electronic, bookentry method is utilized. In any event, the Company, in its discretion, may elect to deliver the shares in certificate form or electronically

to a brokerage account established for the Employee’s benefit at a brokerage financial institution selected by the Company. At the

Company’s request, the Employee shall deliver to the Company a stock power, endorsed in blank, relating to

Page 3
the Restricted Stock and the Employee agrees to complete and sign any other documents and take additional action that the Company

may request to enable it to deliver the Restricted Stock on the Employee’s behalf.

(d) Corporate Acts. The existence of the Restricted Stock shall not affect in any way the right or power of the

Board or the shareholders of the Company to make or authorize any adjustment, recapitalization, reorganization or other change in the

Company’s capital structure or its business, any merger or consolidation of the Company, any issue of debt or equity securities, the

dissolution or liquidation of the Company or any sale, lease, exchange or other disposition of all or any part of its assets or business or any

other corporate act or proceeding. The prohibitions of Section 2(a) hereof shall not apply to the transfer of Restricted Stock pursuant to a

plan of reorganization of the Company, but the stock, securities or other property received in exchange therefore shall also become

subject to the Forfeiture Restrictions and provisions governing the lapsing of such Forfeiture Restrictions applicable to the original

Restricted Stock for all purposes of this Agreement and the certificates representing such stock, securities or other property shall

include a legend to show such restrictions.

3. Withholding of Tax. To the extent that the receipt of the Restricted Stock or the lapse of any Forfeiture Restrictions

results in compensation income or wages to the Employee for federal, state or local income tax purposes, the Employee shall deliver to

the Company at the time of such receipt or lapse, as the case may be, such amount of shares of common stock of the Company or

money as the Company may require to meet its obligation under applicable tax laws or regulations, in accordance with the sub-sections

below.

(a) Non Section 16 Persons. The Employee shall automatically surrender to the Company shares of stock of the

Company subject to this Agreement and with respect to which the Forfeiture Restrictions lapse (valued at their fair market value on the

date of surrender of such shares) to satisfy any tax required to be withheld by reason of compensation income or wages resulting under

this Agreement, unless the Employee elects to deliver to the Company a check in the amount of the required taxes at the time of the

lapse of the Forfeiture Restrictions. An election pursuant to the preceding sentence shall be referred to herein as a “Withholding

Election,” and the Company retains the right to impose conditions on the withholding election right. All Withholding Elections shall be

made by written notice to the Company at its principal executive office addressed to the attention of the Secretary. So long as the

Employee is not a Section 16 Person, the Employee may revoke such election by delivering to the Secretary written notice of such

revocation at least 5 business days prior to the date such election is implemented through actual surrender or withholding of shares of

stock of the Company.

(b) Section 16 Persons. Notwithstanding the foregoing, if the Employee is a Section 16 Person, the Employee must

provide the Company with an election form that must:

(i) be in writing, signed, irrevocable and delivered at least six months prior to the date any tax withholding is

required by reason of this Agreement (the “Withholding Date”) and either (1) authorize the surrender to the Company by the Employee

of shares of stock of the Company subject to this Agreement and with respect to which the Forfeiture Restrictions lapse sufficient to

satisfy any tax required to be withheld by reason of compensation income or

Page 4
wages resulting under this Agreement, or (2) confirm that the Employee will deliver to the Company a check in the amount of the

required taxes at the time of the lapse of the Forfeiture Restrictions, or

(ii) (a) be approved by the Committee, either before or after such election is made, (b) be made, and the

Withholding Date occur, during a period beginning on the third business day following the date of release by the Company for publication

of quarterly and annual summary statements of sales and earnings and ending on the thirtieth day following such date, and (c) be made

more than six months after the effective date of this Agreement.

(c) If the Employee fails to pay the required amount to the Company or fails to make an election pursuant to the

foregoing sub-sections (a) or (b), the Company is authorized to withhold from any cash remuneration (or, if the Employee is not a

Section 16 Person, stock remuneration, including withholding any Restricted Stock distributable to the Employee under this

Agreement) then or thereafter payable to the Employee any tax required to be withheld by reason of compensation income or wages

resulting under this Agreement or the disposition of Restricted Stock acquired under this Agreement.

4. Status of Stock. The Employee agrees that the Restricted Stock issued under this Agreement will not be sold or

otherwise disposed of in any manner which would constitute a violation of any applicable federal or state securities laws. The Employee

also agrees that (i) certificates, if any, representing the Restricted Stock may bear such legend or legends as the Committee deems

appropriate in order to reflect the Forfeiture Restrictions and to assure compliance with applicable securities laws, (ii) the Company may

refuse to register the transfer of the Restricted Stock on the stock transfer records of the Company if such proposed transfer would

constitute a violation of the Forfeiture Restrictions or, in the opinion of counsel satisfactory to the Company, of any applicable securities

law, and (iii) the Company may give related instructions to its transfer agent, if any, to stop registration of the transfer of the Restricted

Stock.

5. Employment Relationship. For purposes of this Agreement, the Employee shall be considered to be in the employment

of the Company as long as the Employee remains an employee of either the Company, an Affiliate (as such term is defined in the Plan),

or any successor entity. Without limiting the scope of the preceding sentence, it is expressly provided that the Employee shall be

considered to have terminated employment with the Company at the time of the termination of the “Affiliate” status under the Plan of

the entity or other organization that employs the Employee. Nothing in the adoption of the Plan, nor the award of the Restricted Stock

thereunder pursuant to this Agreement, shall confer upon the Employee the right to continued employment by the Company or affect

in any way the right of the Company to terminate such employment at any time. Unless otherwise provided in a written employment

agreement or by applicable law, the Employee’s employment by the Company shall be on an at-will basis, and the employment

relationship may be terminated at any time by either the Employee or the Company for any reason whatsoever, with or without cause.

Any question as to whether and when there has been a termination of such employment, and the cause of such termination, shall be

determined by the Committee, and its determination shall be final.

6. Notices. Any notices or other communications provided for in this Agreement shall

Page 5
be sufficient if in writing. In the case of the Employee, such notices or communications shall be effectively delivered if hand delivered

to the Employee at his principal place of employment or if sent by registered or certified mail to the Employee at the last address the

Employee has filed with the Company. In the case of the Company, such notices or communications shall be effectively delivered if

sent by registered or certified mail to the Company at its principal executive offices.

7. Parachute Payment. If, in connection with a Corporate Change, the lapse of Forfeiture Restrictions on one or more shares

of Restricted Stock pursuant to this Agreement comprises part of any "parachute payment" as defined in Code Section 280G(a)(2), the

number of shares of Restricted Stock to which such accelerated lapse of Forfeiture Restrictions would otherwise apply may be reduced

in accordance with the terms of the Severance Agreement, to the extent applicable.

8. Entire Agreement; Amendment. This Agreement replaces and merges all previous agreements and discussions relating to

the same or similar subject matters between the Employee and the Company and constitutes the entire agreement between the

Employee and the Company with respect to the subject matter of this Agreement. This Agreement may not be modified in any respect

by any verbal statement, representation or agreement made by any employee, officer, or representative of the Company or by any

written agreement unless signed by an officer of the Company who is expressly authorized by the Company to execute such document.

Except as provided below, any modification of this Agreement shall be effective only if it is in writing and signed by both the Employee

and an authorized officer of the Company.

9. Binding Effect. This Agreement shall be binding upon and inure to the benefit of any successors to the Company and all

persons lawfully claiming under the Employee.

10. Controlling Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of New

York.

IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly

authorized, and the Employee has executed this Agreement, all as of the date first above written.

FOREST OIL CORPORATION

 

By: ____________________________________

[Name] 

[Title]

EMPLOYEE

________________________________________

[EMPLOYEE NAME]

SS#: _____________ 

Page 6
RESTRICTED STOCK AGREEMENT

THIS RESTRICTED STOCK AGREEMENT (this “Agreement”) is made as of the ____ day of _________, 20__,

between Forest Oil Corporation, a New York corporation (the “Company”), and __________________ (the “Employee”).

1. Award. Pursuant to the Forest Oil Corporation 2007 Stock Incentive Plan, as amended (the “Plan”), as of the date of this

Agreement, _____ shares of the Company’s common stock, par value $.10 per share (the “Restricted Stock”), shall be issued as

hereinafter provided in the Employee’s name subject to certain restrictions thereon, in consideration of services that the Employee has

performed for the Company in 20__ and services to be provided to the Company in the future. The Restricted Stock shall be issued upon

acceptance of this Agreement by the Employee and upon satisfaction of the conditions of this Agreement. This award of Restricted

Stock shall be subject to all of the terms and provisions of the Plan, including future amendments thereto, if any, which is available on

http://corpweb1/. For paper copies of the Plan and prospectus please contact Stock Administration, 707 Seventeenth Street, Suite 3600,

Denver, CO 80202, or call 303.812.1502. In the event of any conflict between the terms of this Agreement and the Plan, the Plan shall

control.

2. Restricted Stock. The Employee hereby accepts the Restricted Stock when issued and agrees with respect thereto as

follows:

(a) Forfeiture Restrictions. The Restricted Stock may not be sold, assigned, pledged, exchanged, hypothecated or

otherwise transferred, encumbered or disposed of to the extent then subject to the Forfeiture Restrictions (as hereinafter defined), and

in the event of termination of the Employee’s employment with the Company for any reason other than death, Disability, or

Involuntary Termination (as such terms are hereinafter defined), the Employee shall, for no consideration, forfeit to the Company all

Restricted Stock to the extent then subject to the Forfeiture Restrictions. The prohibition against transfer and the obligation to forfeit and

surrender Restricted Stock to the Company upon termination of employment are herein referred to as the “Forfeiture Restrictions.”

The Forfeiture Restrictions shall be binding upon and enforceable against any transferee of Restricted Stock. For purposes of this

Agreement, the following capitalized words and terms shall have the meanings indicated below:

(i) “Board” shall mean the Board of Directors of the Company.

(ii) “Code” shall mean the Internal Revenue Code of 1986, as amended.

(iii) “Committee” shall mean the committee of the Board that is selected by the Board to administer the Plan

as provided in the Plan.

(iv) “Corporate Change” shall mean the occurrence of any one or more of the following events:

0v01 Page 1
(A) the Company shall not be the surviving entity in any merger, consolidation or other reorganization

(or survives only as a subsidiary of an entity other than a previously wholly-owned subsidiary of the Company);

(B) the Company sells, leases or exchanges all or substantially all of its assets to any other person or

entity (other than a wholly-owned subsidiary of the Company);

(C) the Company is to be dissolved and liquidated;

(D) any person or entity, including a “group” as contemplated by Section 13(d)(3) of the Securities

Exchange Act of 1934, as amended, acquires or gains ownership or control (including, without limitation, power to vote) of more than

40% of the outstanding shares of the Company’s voting stock (based upon voting power); or

(E) as a result of or in connection with a contested election of directors, the persons who were

directors of the Company before such election shall cease to constitute a majority of the Board.

Notwithstanding the foregoing, the term “Corporate Change” shall not include any reorganization, merger or

consolidation involving solely the Company and one or more previously wholly-owned subsidiaries of the Company.

(v) “Disability” shall have the meaning set forth in the Severance Agreement, or if there is no Severance

Agreement or if the Severance Agreement contains no such definition, “Disability” shall mean that, as a result of the Employee’s

incapacity due to physical or mental illness, he shall have been absent from the full-time performance of his duties for six consecutive

months, and he shall not have returned to full-time performance of his duties within 30 days after written notice of termination is given

to the Employee by the Company (provided, however, that such notice may not be given prior to 30 days before the expiration of such

six-month period).

(vi) “Involuntary Termination” shall have the meaning set forth in the Severance Agreement, or if there is no

Severance Agreement or if the Severance Agreement contains no such definition, “Involuntary Termination” shall mean any

termination of the Employee’s employment with the Company which does not result from a resignation by the Employee; provided,

however, that the term “Involuntary Termination” shall not include a termination as a result of death, Disability, or a termination of the

Employee’s employment by the Company (or its subsidiaries) by reason of the Employee’s unsatisfactory performance of his duties, to

be determined by the Company in its sole discretion, or final conviction of a misdemeanor involving moral turpitude or a felony.

(vii) “Section 16 Person” shall mean an officer, director or affiliate of the Company or a former officer,

director or affiliate of the Company who is subject to section 16 of the Securities Exchange Act of 1934, as amended.

0v01 Page 2
(viii) “Severance Agreement” means any Severance Agreement solely between the Employee and the

Company in effect as of the date of this Agreement, as such may be amended or superseded from time to time.

(b) Lapse of Forfeiture Restrictions. The Forfeiture Restrictions shall lapse and cease to apply with respect to onethird of the shares of Restricted Stock on each of the first three anniversaries of the Date of Grant; provided that the Forfeiture

Restrictions shall lapse as to all shares of Restricted Stock then subject to Forfeiture Restrictions on the earlier of (i) the date upon which

a Corporate Change occurs if the successor entity does not assume, convert or replace the Restricted Stock governed by this Agreement

with an equity or equity-based award that is substantially the same in all material economic respects, (ii) the date upon which the

Employee’s employment with the Company is terminated by reason of death, Disability, or Involuntary Termination, or (iii) at the

Committee’s discretion, the date determined by the Committee. Any shares of Restricted Stock with respect to which the Forfeiture

Restrictions do not lapse in accordance with the preceding sentence shall be forfeited to the Company for no consideration as of the date

of the termination of the Employee’s employment with the Company. For the avoidance of doubt, if, in connection with a Corporate

Change, the successor entity assumes, converts or replaces this Agreement with an agreement that is substantially the same in all

material economic respects, any Forfeiture Restrictions continuing after such Corporate Change with respect to such assumed,

converted, or replaced award shall lapse on the earliest to occur of (a) the lapse dates set forth above or (b) the date of the Employee’s

Involuntary Termination following such Corporate Change.

(c) Certificates. A certificate evidencing the Restricted Stock shall be issued by the Company in Employee’s name,

pursuant to which Employee shall have all of the rights of a shareholder of the Company with respect to the Restricted Stock,

including, without limitation, voting rights and the right to receive dividends; provided, however, that dividends paid in shares of the

Company’s stock shall be subject to the Forfeiture Restrictions. The Employee may not sell, transfer, pledge, exchange, hypothecate or

otherwise dispose of the Restricted Stock until the Forfeiture Restrictions have expired and a breach of the terms of this Agreement

shall cause a forfeiture of the Restricted Stock. The Company, in its discretion, may elect to complete the delivery of the Restricted

Stock by means of electronic, book-entry statement, instead of issuing physical share certificates.

Certificates, if any, shall be delivered upon issuance to the Secretary of the Company or to such other

depository as may be designated by the Committee as a depository for safekeeping until the forfeiture of such Restricted Stock occurs or

the Forfeiture Restrictions lapse pursuant to the terms of the Plan and this award. Upon the lapse of the Forfeiture Restrictions, the

Company shall cause a new certificate or certificates to be issued without legend (except for any legend required pursuant to applicable

securities laws or any other agreement to which the Employee is a party) in the name of the Employee in exchange for the certificate

evidencing the Restricted Stock, or, as may be the case, it shall issue appropriate instructions to the transfer agent if the electronic, bookentry method is utilized. In any event, the Company, in its discretion, may elect to deliver the shares in certificate form or electronically

to a brokerage account established for the Employee’s benefit at a brokerage financial institution selected by the Company. At the

Company’s

0v01 Page 3
request, the Employee shall deliver to the Company a stock power, endorsed in blank, relating to the Restricted Stock and the

Employee agrees to complete and sign any other documents and take additional action that the Company may request to enable it to

deliver the Restricted Stock on the Employee’s behalf.

(d) Corporate Acts. The existence of the Restricted Stock shall not affect in any way the right or power of the

Board or the shareholders of the Company to make or authorize any adjustment, recapitalization, reorganization or other change in the

Company’s capital structure or its business, any merger or consolidation of the Company, any issue of debt or equity securities, the

dissolution or liquidation of the Company or any sale, lease, exchange or other disposition of all or any part of its assets or business or any

other corporate act or proceeding. The prohibitions of Section 2(a) hereof shall not apply to the transfer of Restricted Stock pursuant to a

plan of reorganization of the Company, but the stock, securities or other property received in exchange therefore shall also become

subject to the Forfeiture Restrictions and provisions governing the lapsing of such Forfeiture Restrictions applicable to the original

Restricted Stock for all purposes of this Agreement and the certificates representing such stock, securities or other property shall

include a legend to show such restrictions.

3. Withholding of Tax. To the extent that the receipt of the Restricted Stock or the lapse of any Forfeiture Restrictions

results in compensation income or wages to the Employee for federal, state or local income tax purposes, the Employee shall deliver to

the Company at the time of such receipt or lapse, as the case may be, such amount of shares of common stock of the Company or

money as the Company may require to meet its obligation under applicable tax laws or regulations, in accordance with the sub-sections

below.

(a) Non Section 16 Persons. The Employee shall automatically surrender to the Company shares of stock of the

Company subject to this Agreement and with respect to which the Forfeiture Restrictions lapse (valued at their fair market value on the

date of surrender of such shares) to satisfy any tax required to be withheld by reason of compensation income or wages resulting under

this Agreement, unless the Employee elects to deliver to the Company a check in the amount of the required taxes at the time of the

lapse of the Forfeiture Restrictions. An election pursuant to the preceding sentence shall be referred to herein as a “Withholding

Election,” and the Company retains the right to impose conditions on the withholding election right. All Withholding Elections shall be

made by written notice to the Company at its principal executive office addressed to the attention of the Secretary. So long as the

Employee is not a Section 16 Person, the Employee may revoke such election by delivering to the Secretary written notice of such

revocation at least 5 business days prior to the date such election is implemented through actual surrender or withholding of shares of

stock of the Company.

(b) Section 16 Persons. Notwithstanding the foregoing, if the Employee is a Section 16 Person, the Employee must

provide the Company with an election form that must:

(i) be in writing, signed, irrevocable and delivered at least six months prior to the date any tax withholding is

required by reason of this Agreement (the “Withholding Date”) and either (1) authorize the surrender to the Company by the Employee

of shares of stock

0v01 Page 4
of the Company subject to this Agreement and with respect to which the Forfeiture Restrictions lapse sufficient to satisfy any tax

required to be withheld by reason of compensation income or wages resulting under this Agreement, or (2) confirm that the Employee

will deliver to the Company a check in the amount of the required taxes at the time of the lapse of the Forfeiture Restrictions, or

(ii) (a) be approved by the Committee, either before or after such election is made, (b) be made, and the

Withholding Date occur, during a period beginning on the third business day following the date of release by the Company for publication

of quarterly and annual summary statements of sales and earnings and ending on the thirtieth day following such date, and (c) be made

more than six months after the effective date of this Agreement.

(c) If the Employee fails to pay the required amount to the Company or fails to make an election pursuant to the

foregoing sub-sections (a) or (b), the Company is authorized to withhold from any cash remuneration (or, if the Employee is not a

Section 16 Person, stock remuneration, including withholding any Restricted Stock distributable to the Employee under this

Agreement) then or thereafter payable to the Employee any tax required to be withheld by reason of compensation income or wages

resulting under this Agreement or the disposition of Restricted Stock acquired under this Agreement.

4. Status of Stock. The Employee agrees that the Restricted Stock issued under this Agreement will not be sold or

otherwise disposed of in any manner which would constitute a violation of any applicable federal or state securities laws. The Employee

also agrees that (i) certificates, if any, representing the Restricted Stock may bear such legend or legends as the Committee deems

appropriate in order to reflect the Forfeiture Restrictions and to assure compliance with applicable securities laws, (ii) the Company may

refuse to register the transfer of the Restricted Stock on the stock transfer records of the Company if such proposed transfer would

constitute a violation of the Forfeiture Restrictions or, in the opinion of counsel satisfactory to the Company, of any applicable securities

law, and (iii) the Company may give related instructions to its transfer agent, if any, to stop registration of the transfer of the Restricted

Stock.

5. Employment Relationship. For purposes of this Agreement, the Employee shall be considered to be in the employment

of the Company as long as the Employee remains an employee of either the Company, an Affiliate (as such term is defined in the Plan),

or any successor entity. Without limiting the scope of the preceding sentence, it is expressly provided that the Employee shall be

considered to have terminated employment with the Company at the time of the termination of the “Affiliate” status under the Plan of

the entity or other organization that employs the Employee. Nothing in the adoption of the Plan, nor the award of the Restricted Stock

thereunder pursuant to this Agreement, shall confer upon the Employee the right to continued employment by the Company or affect

in any way the right of the Company to terminate such employment at any time. Unless otherwise provided in a written employment

agreement or by applicable law, the Employee’s employment by the Company shall be on an at-will basis, and the employment

relationship may be terminated at any time by either the Employee or the Company for any reason whatsoever, with or without cause.

Any question as to whether and when there has been a termination of such

0v01 Page 5
employment, and the cause of such termination, shall be determined by the Committee, and its determination shall be final.

6. Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. In the case of

the Employee, such notices or communications shall be effectively delivered if hand delivered to the Employee at his principal place of

employment or if sent by registered or certified mail to the Employee at the last address the Employee has filed with the Company. In

the case of the Company, such notices or communications shall be effectively delivered if sent by registered or certified mail to the

Company at its principal executive offices.

7. Parachute Payment. If, in connection with a Corporate Change, the lapse of Forfeiture Restrictions on one or more shares

of Restricted Stock pursuant to this Agreement comprises part of any "parachute payment" as defined in Code Section 280G(a)(2), the

number of shares of Restricted Stock to which such accelerated lapse of Forfeiture Restrictions would otherwise apply may be reduced

in accordance with the terms of the Severance Agreement, to the extent applicable.

8. Entire Agreement; Amendment. This Agreement replaces and merges all previous agreements and discussions relating to

the same or similar subject matters between the Employee and the Company and constitutes the entire agreement between the

Employee and the Company with respect to the subject matter of this Agreement. This Agreement may not be modified in any respect

by any verbal statement, representation or agreement made by any employee, officer, or representative of the Company or by any

written agreement unless signed by an officer of the Company who is expressly authorized by the Company to execute such document.

Except as provided below, any modification of this Agreement shall be effective only if it is in writing and signed by both the Employee

and an authorized officer of the Company.

9. Binding Effect. This Agreement shall be binding upon and inure to the benefit of any successors to the Company and all

persons lawfully claiming under the Employee.

10. Controlling Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of New

York.

0v01 Page 6
IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly

authorized, and the Employee has executed this Agreement, all as of the date first above written.

FOREST OIL CORPORATION

 

By: ____________________________________

[Name] 

[Title]

EMPLOYEE

________________________________________

[EMPLOYEE NAME]

SS#: _____________ 

0v01 Page 7
(Cash Only)

FOREST OIL CORPORATION

PHANTOM STOCK UNIT AGREEMENT

THIS PHANTOM STOCK UNIT AGREEMENT (this “Agreement”) is made as of the ____ day of ____________

(the “Date of Grant”), between Forest Oil Corporation , a New York corporation (the “Company”), and [Employee Name]

(the “Employee”).

1. Award. Pursuant to the FOREST OIL CORPORATION 2007 STOCK INCENTIVE PLAN, as amended (the

“Plan”), the Company hereby makes a grant of phantom stock units with respect to _____ shares of the Company’s common stock, par

value $.10 per share (the “Phantom Stock Units”). The Employee agrees that this award of Phantom Stock Units constitutes a Phantom

Stock Award under the Plan and shall be subject to all of the terms and provisions of the Plan, including future amendments thereto, if

any, which is available on the Company’s intranet at the following site: http://corpweb1/. For paper copies of the Plan and prospectus, the

Employee may contact Stock Administration, 707 Seventeenth Street, Suite 3600, Denver, CO 80202, or call 303.812.1502. In the

event of any conflict between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall control.

2. Definitions. Capitalized terms used in this Agreement that are not defined below or in the body of this Agreement shall have

the meanings given to them in the Plan. In addition to the terms defined in the body of this Agreement, the following capitalized words

and terms shall have the meanings indicated below:

(a) “Corporate Change” shall mean the occurrence of any one or more of the following events:

(i) the Company shall not be the surviving entity in any merger, consolidation or other reorganization (or survives only

as a subsidiary of an entity other than a previously wholly-owned subsidiary of the Company);

(ii) the Company sells, leases or exchanges all or substantially all of its assets to any other person or entity (other than

a wholly-owned subsidiary of the Company);

(iii) the Company is to be dissolved and liquidated;

(iv) any person or entity, including a “group” as contemplated by Section 13(d)(3) of the Exchange Act, acquires or

gains ownership or control (including, without limitation, power to vote) of more than 40% of the outstanding shares of the

Company’s voting stock (based upon voting power); or

(v) as a result of or in connection with a contested election of directors, the persons who were directors of the

Company before such election shall cease to constitute a majority of the Board.
Notwithstanding the foregoing, the term “Corporate Change” shall not include any reorganization, merger or consolidation involving

solely the Company and one or more previously wholly-owned subsidiaries of the Company.

(b) “Disability” shall have the meaning set forth in the Severance Agreement, or if there is no Severance Agreement or the

Severance Agreement contains no such definition, “Disability” shall mean that, as a result of the Employee’s incapacity due to physical

or mental illness, the Employee shall have been absent from the full-time performance of the Employee’s duties for six consecutive

months, and the Employee shall not have returned to full-time performance of the Employee’s duties within 30 days after written

notice of termination is given to the Employee by the Company (provided, however, that such notice may not be given prior to 30 days

before the expiration of such six-month period).

(c) “Forfeiture Restrictions” shall have the meaning set forth in the Severance Agreement, or if there is no Severance

Agreement or the Severance Agreement contains no such definition, “Forfeiture Restrictions” shall have the meaning specified in

Section 3(a) hereof.

(d) “Involuntary Termination” shall have the meaning set forth in the Severance Agreement, or if there is no Severance

Agreement or the Severance Agreement contains no such definition, “Involuntary Termination” shall mean any termination of the

Employee’s employment with the Company which does not result from a resignation by the Employee; provided, however, that the

term “Involuntary Termination” shall not include a termination as a result of death, Disability, or a termination of the Employee’s

employment by the Company by reason of the Employee’s unsatisfactory performance of the Employee’s duties, to be determined by

the Company in its sole discretion, or final conviction of a misdemeanor involving moral turpitude or a felony.

(e) “Severance Agreement” shall mean any Severance Agreement solely between the Employee and the Company in effect

as of the date of this Agreement, as such may be amended or superseded from time to time.

3. Phantom Stock Units. The Employee hereby accepts the Phantom Stock Units and agrees with respect thereto as follows:

(a) Forfeiture Restrictions. The Phantom Stock Units may not be sold, assigned, pledged, exchanged, hypothecated or

otherwise transferred, encumbered or disposed of, and in the event of termination of the Employee’s employment with the Company

for any reason other than death, Disability, or Involuntary Termination, the Employee shall, for no consideration, forfeit to the

Company all Phantom Stock Units to the extent then subject to the Forfeiture Restrictions. The prohibition against transfer and the

obligation to forfeit and surrender Phantom Stock Units to the Company upon termination of employment as provided in the preceding

sentence are herein referred to as the “Forfeiture Restrictions.” The Forfeiture Restrictions shall be binding upon and enforceable

against any transferee of Phantom Stock Units.

(b) Lapse of Forfeiture Restrictions. Provided that the Employee has been continuously employed by the Company from

the Date of Grant through the lapse date described in this sentence, the Forfeiture Restrictions shall lapse with respect to 100% of the

Phantom Stock

-2-
Units on the earlier of (i) the third anniversary of the Date of Grant, (ii) the date upon which a Corporate Change occurs if the successor

entity does not assume, convert or replace the Phantom Stock Units governed by this Agreement with an equity or equity-based award

that is substantially the same in all material economic respects, (iii) the date upon which the Employee’s employment with the

Company is terminated by reason of death, Disability, or Involuntary Termination, or (iv) at the Committee’s discretion, the date

determined by the Committee. Any Phantom Stock Units with respect to which the Forfeiture Restrictions do not lapse in accordance

with the preceding sentence shall be forfeited to the Company for no consideration as of the date of the termination of the Employee’s

employment with the Company. For the avoidance of doubt, if, in connection with a Corporate Change, the successor entity assumes,

converts or replaces this Agreement with an agreement that is substantially the same in all material economic respects, any Forfeiture

Restrictions continuing after such Corporate Change with respect to such assumed, converted, or replaced award shall lapse on the

earliest to occur of (a) the lapse dates set forth above or (b) the date of the Employee’s Involuntary Termination following such

Corporate Change.

(c) Payments. Subject to Section 4 hereof, as soon as reasonably practicable after the lapse of the Forfeiture Restrictions with

respect to any Phantom Stock Units as provided in Section 3(b) hereof (but in no event later than March 15 of the calendar year

following the calendar year in which the Forfeiture Restrictions so lapse), the Company shall pay to the Employee with respect to each

share of the Company’s common stock covered by such Phantom Stock Unit an amount in cash equal to the Fair Market Value of one

share of the Company’s common stock determined as of the date the Forfeiture Restrictions lapse.

(d) 

the shareholders of the Company to make or authorize any adjustment, recapitalization, reorganization or other change in the Company’s

capital structure or its business, any merger or consolidation of the Company, any issue of debt or equity securities, the dissolution or

liquidation of the Company or any sale, lease, exchange or other disposition of all or any part of its assets or business or any other

corporate act or proceeding.

4. Withholding of Tax. The Company may withhold from any payment made pursuant to this Agreement all federal, state,

city and other taxes and withholdings as may be required pursuant to any law or governmental regulation or ruling and all other

customary deductions made with respect to the Company’s employees generally. The Employee acknowledges and agrees that the

Company is making no representation or warranty as to the tax consequences to the Employee as a result of the receipt of the Phantom

Stock Units, the lapse of any Forfeiture Restrictions or the forfeiture of any Phantom Stock Units pursuant to the Forfeiture

Restrictions.

5. Rights as Stockholder. The Phantom Stock Units represent an unsecured and unfunded right to receive a cash payment,

which right is subject to the terms, conditions and restrictions set forth in this Agreement and the Plan. Accordingly, the Employee will

have no rights as a shareholder with respect to any shares covered by Phantom Stock Units granted under this Agreement. Without

limiting the scope of the preceding sentence, the Employee will have no rights to vote or receive dividend equivalents with respect to

any shares covered by Phantom Stock Units granted under this Agreement.

-3-
6. Employment Relationship. For purposes of this Agreement, the Employee shall be considered to be in the employment of

the Company as long as the Employee has not incurred a “separation from service” with the Company within the meaning of Section

409A(a)(2)(A)(i) of the Code and applicable administrative guidance issued thereunder. Nothing in the adoption of the Plan, nor the award

of the Phantom Stock Units thereunder pursuant to this Agreement, shall confer upon the Employee the right to continued

employment by the Company or affect in any way the right of the Company to terminate such employment at any time. Unless

otherwise provided in a written employment agreement or by applicable law, the Employee’s employment by the Company shall be on

an at-will basis, and the employment relationship may be terminated at any time by either the Employee or the Company for any reason

whatsoever or for no reason, with or without cause or notice. Any question as to whether and when there has been a termination of such

employment, and the cause of such termination, shall be determined by the Committee or its delegate, and its determination shall be

final.

7. Conditions to Plan Participation and Receipt of Phantom Stock Units . In consideration of the grant of the Phantom

Stock Units, and in order to protect the interests of the Company, its Affiliates, and their respective equity holders and employees, the

Employee acknowledges and agrees that it is a condition precedent to his or her right to participate in, continue to participate in, and

receive benefits under the Plan (including receipt of the Phantom Stock Units) that (a) the Employee shall at all times comply with laws

(whether domestic or foreign) applicable to the Employee’s actions on behalf of the Company or any Affiliate, (b) the Employee shall

not commit any action that results in the Employee’s employment being subject to a termination for cause, and (c) the Employee shall

at all times fully and faithfully comply with all material covenants and agreements set forth in this Agreement. By entering into this

Agreement, the parties hereto agree that the conditions to participation in the Plan set forth in this Section are an essential component of

the Plan and this Agreement, and it is their intent that such conditions not be severed from the other terms and provisions of the Plan and

this Agreement.

8. Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. In the case of

the Employee, such notices or communications shall be effectively delivered if hand delivered to the Employee at the Employee’s

principal place of employment or if sent by registered or certified mail to the Employee at the last address the Employee has filed with

the Company. In the case of the Company, such notices or communications shall be effectively delivered if sent by registered or

certified mail to the Company at its principal executive offices.

9. Parachute Payment. If, in connection with a Corporate Change, the lapse of Forfeiture Restrictions on one or more of the

Phantom Stock Units pursuant to this Agreement comprises part of any “parachute payment” as defined in Code Section 280G(a)(2), the

number of Phantom Stock Units to which such accelerated lapse of Forfeiture Restrictions would otherwise apply may be reduced in

accordance with the terms of the Severance Agreement, to the extent applicable.

10. Entire Agreement; Amendment. This Agreement replaces and merges all previous agreements and discussions relating

to the same or similar subject matters between the Employee

-4-
and the Company and constitutes the entire agreement between the Employee and the Company with respect to the subject matter of

this Agreement. This Agreement may not be modified in any respect by any verbal statement, representation or agreement made by any

employee, officer, or representative of the Company or by any written agreement unless signed by an officer of the Company who is

expressly authorized by the Company to execute such document.

11. Binding Effect. This Agreement shall be binding upon and inure to the benefit of any successors to the Company and all

persons lawfully claiming under the Employee.

12. Controlling Law. This Agreement shall be governed by, and construed in accordance with, the laws of the

State of New York, without regard to conflicts of law principles thereof, or, if applicable, the laws of the United States.

IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly

authorized, and the Employee has executed this Agreement, all as of the date first above written.

FOREST OIL CORPORATION

By: ____________________________________

[Name] 

[Title]

EMPLOYEE

________________________________________

[Employee Name]

-5-
(Cash Only)

FOREST OIL CORPORATION

PHANTOM STOCK UNIT AGREEMENT

THIS PHANTOM STOCK UNIT AGREEMENT (this “Agreement”) is made as of the ____ day of ____________

(the “Date of Grant”), between Forest Oil Corporation , a New York corporation (the “Company”), and [Employee Name]

(the “Employee”).

1. Award. Pursuant to the FOREST OIL CORPORATION 2007 STOCK INCENTIVE PLAN, as amended (the

“Plan”), the Company hereby makes a grant of phantom stock units with respect to _____ shares of the Company’s common stock, par

value $.10 per share (the “Phantom Stock Units”). The Employee agrees that this award of Phantom Stock Units constitutes a Phantom

Stock Award under the Plan and shall be subject to all of the terms and provisions of the Plan, including future amendments thereto, if

any, which is available on the Company’s intranet at the following site: http://corpweb1/. For paper copies of the Plan and prospectus, the

Employee may contact Stock Administration, 707 Seventeenth Street, Suite 3600, Denver, CO 80202, or call 303.812.1502. In the

event of any conflict between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall control.

2. Definitions. Capitalized terms used in this Agreement that are not defined below or in the body of this Agreement shall have

the meanings given to them in the Plan. In addition to the terms defined in the body of this Agreement, the following capitalized words

and terms shall have the meanings indicated below:

(a) “Corporate Change” shall mean the occurrence of any one or more of the following events:

(i) the Company shall not be the surviving entity in any merger, consolidation or other reorganization (or survives only

as a subsidiary of an entity other than a previously wholly-owned subsidiary of the Company);

(ii) the Company sells, leases or exchanges all or substantially all of its assets to any other person or entity (other than

a wholly-owned subsidiary of the Company);

(iii) the Company is to be dissolved and liquidated;

(iv) any person or entity, including a “group” as contemplated by Section 13(d)(3) of the Exchange Act, acquires or

gains ownership or control (including, without limitation, power to vote) of more than 40% of the outstanding shares of the

Company’s voting stock (based upon voting power); or

(v) as a result of or in connection with a contested election of directors, the persons who were directors of the

Company before such election shall cease to constitute a majority of the Board.

-1-
Notwithstanding the foregoing, the term “Corporate Change” shall not include any reorganization, merger or consolidation involving

solely the Company and one or more previously wholly-owned subsidiaries of the Company.

(b) “Disability” shall have the meaning set forth in the Severance Agreement, or if there is no Severance Agreement or the

Severance Agreement contains no such definition, “Disability” shall mean that, as a result of the Employee’s incapacity due to physical

or mental illness, the Employee shall have been absent from the full-time performance of the Employee’s duties for six consecutive

months, and the Employee shall not have returned to full-time performance of the Employee’s duties within 30 days after written

notice of termination is given to the Employee by the Company (provided, however, that such notice may not be given prior to 30 days

before the expiration of such six-month period).

(c) “Forfeiture Restrictions” shall have the meaning set forth in the Severance Agreement, or if there is no Severance

Agreement or the Severance Agreement contains no such definition, “Forfeiture Restrictions” shall have the meaning specified in

Section 3(a) hereof.

(d) “Involuntary Termination” shall have the meaning set forth in the Severance Agreement, or if there is no Severance

Agreement or the Severance Agreement contains no such definition, “Involuntary Termination” shall mean any termination of the

Employee’s employment with the Company which does not result from a resignation by the Employee; provided, however, that the

term “Involuntary Termination” shall not include a termination as a result of death, Disability, or a termination of the Employee’s

employment by the Company by reason of the Employee’s unsatisfactory performance of the Employee’s duties, to be determined by

the Company in its sole discretion, or final conviction of a misdemeanor involving moral turpitude or a felony.

(e) “Severance Agreement” shall mean any Severance Agreement solely between the Employee and the Company in effect

as of the date of this Agreement, as such may be amended or superseded from time to time.

3. Phantom Stock Units. The Employee hereby accepts the Phantom Stock Units and agrees with respect thereto as follows:

(a) Forfeiture Restrictions. The Phantom Stock Units may not be sold, assigned, pledged, exchanged, hypothecated or

otherwise transferred, encumbered or disposed of, and in the event of termination of the Employee’s employment with the Company

for any reason other than death, Disability, or Involuntary Termination, the Employee shall, for no consideration, forfeit to the

Company all Phantom Stock Units to the extent then subject to the Forfeiture Restrictions. The prohibition against transfer and the

obligation to forfeit and surrender Phantom Stock Units to the Company upon termination of employment as provided in the preceding

sentence are herein referred to as the “Forfeiture Restrictions.” The Forfeiture Restrictions shall be binding upon and enforceable

against any transferee of Phantom Stock Units.

(b) Lapse of Forfeiture Restrictions. Provided that the Employee has been continuously employed by the Company from

the Date of Grant through the lapse date described in this sentence, the Forfeiture Restrictions shall lapse and cease to apply with respect

to one-third

-2-
of the Phantom Stock Units on each of the first three anniversaries of the Date of Grant; provided that the Forfeiture Restrictions shall

lapse as to all Phantom Stock Units then subject to Forfeiture Restrictions on the earlier of (i) the date upon which a Corporate Change

occurs if the successor entity does not assume, convert or replace the Phantom Stock Units governed by this Agreement with an equity

or equity-based award that is substantially the same in all material economic respects, (ii) the date upon which the Employee’s

employment with the Company is terminated by reason of death, Disability, or Involuntary Termination, or (iii) at the Committee’s

discretion, the date determined by the Committee. Any Phantom Stock Units with respect to which the Forfeiture Restrictions do not

lapse in accordance with the preceding sentence shall be forfeited to the Company for no consideration as of the date of the termination

of the Employee’s employment with the Company. For the avoidance of doubt, if, in connection with a Corporate Change, the successor

entity assumes, converts or replaces this Agreement with an agreement that is substantially the same in all material economic respects,

any Forfeiture Restrictions continuing after such Corporate Change with respect to such assumed, converted, or replaced award shall

lapse on the earliest to occur of (a) the lapse dates set forth above or (b) the date of the Employee’s Involuntary Termination following

such Corporate Change.

(c) Payments. Subject to Section 4 hereof, as soon as reasonably practicable after the lapse of the Forfeiture Restrictions with

respect to any Phantom Stock Units as provided in Section 3(b) hereof (but in no event later than March 15 of the calendar year

following the calendar year in which the Forfeiture Restrictions so lapse), the Company shall pay to the Employee with respect to each

share of the Company’s common stock covered by such Phantom Stock Unit an amount in cash equal to the Fair Market Value of one

share of the Company’s common stock determined as of the date the Forfeiture Restrictions lapse.

(d) 

the shareholders of the Company to make or authorize any adjustment, recapitalization, reorganization or other change in the Company’s

capital structure or its business, any merger or consolidation of the Company, any issue of debt or equity securities, the dissolution or

liquidation of the Company or any sale, lease, exchange or other disposition of all or any part of its assets or business or any other

corporate act or proceeding.

4. Withholding of Tax. The Company may withhold from any payment made pursuant to this Agreement all federal, state,

city and other taxes and withholdings as may be required pursuant to any law or governmental regulation or ruling and all other

customary deductions made with respect to the Company’s employees generally. The Employee acknowledges and agrees that the

Company is making no representation or warranty as to the tax consequences to the Employee as a result of the receipt of the Phantom

Stock Units, the lapse of any Forfeiture Restrictions or the forfeiture of any Phantom Stock Units pursuant to the Forfeiture

Restrictions.

5. Rights as Stockholder. The Phantom Stock Units represent an unsecured and unfunded right to receive a cash payment,

which right is subject to the terms, conditions and restrictions set forth in this Agreement and the Plan. Accordingly, the Employee will

have no rights as a shareholder with respect to any shares covered by Phantom Stock Units granted under this Agreement. Without

limiting the scope of the preceding sentence, the Employee will have no rights

-3-
to vote or receive dividend equivalents with respect to any shares covered by Phantom Stock Units granted under this Agreement.

6. Employment Relationship. For purposes of this Agreement, the Employee shall be considered to be in the employment of

the Company as long as the Employee has not incurred a “separation from service” with the Company within the meaning of Section

409A(a)(2)(A)(i) of the Code and applicable administrative guidance issued thereunder. Nothing in the adoption of the Plan, nor the award

of the Phantom Stock Units thereunder pursuant to this Agreement, shall confer upon the Employee the right to continued

employment by the Company or affect in any way the right of the Company to terminate such employment at any time. Unless

otherwise provided in a written employment agreement or by applicable law, the Employee’s employment by the Company shall be on

an at-will basis, and the employment relationship may be terminated at any time by either the Employee or the Company for any reason

whatsoever or for no reason, with or without cause or notice. Any question as to whether and when there has been a termination of such

employment, and the cause of such termination, shall be determined by the Committee or its delegate, and its determination shall be

final.

7. Conditions to Plan Participation and Receipt of Phantom Stock Units . In consideration of the grant of the Phantom

Stock Units, and in order to protect the interests of the Company, its Affiliates, and their respective equity holders and employees, the

Employee acknowledges and agrees that it is a condition precedent to his or her right to participate in, continue to participate in, and

receive benefits under the Plan (including receipt of the Phantom Stock Units) that (a) the Employee shall at all times comply with laws

(whether domestic or foreign) applicable to the Employee’s actions on behalf of the Company or any Affiliate, (b) the Employee shall

not commit any action that results in the Employee’s employment being subject to a termination for cause, and (c) the Employee shall

at all times fully and faithfully comply with all material covenants and agreements set forth in this Agreement. By entering into this

Agreement, the parties hereto agree that the conditions to participation in the Plan set forth in this Section are an essential component of

the Plan and this Agreement, and it is their intent that such conditions not be severed from the other terms and provisions of the Plan and

this Agreement.

8. Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. In the case of

the Employee, such notices or communications shall be effectively delivered if hand delivered to the Employee at the Employee’s

principal place of employment or if sent by registered or certified mail to the Employee at the last address the Employee has filed with

the Company. In the case of the Company, such notices or communications shall be effectively delivered if sent by registered or

certified mail to the Company at its principal executive offices.

9. Parachute Payment. If, in connection with a Corporate Change, the lapse of Forfeiture Restrictions on one or more of the

Phantom Stock Units pursuant to this Agreement comprises part of any “parachute payment” as defined in Code Section 280G(a)(2), the

number of Phantom Stock Units to which such accelerated lapse of Forfeiture Restrictions would otherwise apply may be reduced in

accordance with the terms of the Severance Agreement, to the extent applicable.

-4-
10. Entire Agreement; Amendment. This Agreement replaces and merges all previous agreements and discussions relating

to the same or similar subject matters between the Employee and the Company and constitutes the entire agreement between the

Employee and the Company with respect to the subject matter of this Agreement. This Agreement may not be modified in any respect

by any verbal statement, representation or agreement made by any employee, officer, or representative of the Company or by any

written agreement unless signed by an officer of the Company who is expressly authorized by the Company to execute such document.

11. Binding Effect. This Agreement shall be binding upon and inure to the benefit of any successors to the Company and all

persons lawfully claiming under the Employee.

12. Controlling Law. This Agreement shall be governed by, and construed in accordance with, the laws of the

State of New York, without regard to conflicts of law principles thereof, or, if applicable, the laws of the United States.

IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly

authorized, and the Employee has executed this Agreement, all as of the date first above written.

FOREST OIL CORPORATION

By: ____________________________________

[Name] 

[Title]

EMPLOYEE

________________________________________

[Employee Name]

-5-
FOREST OIL CORPORATION

List of Significant Subsidiaries of the Registrant

As of December 31, 2012

Subsidiaries State of Incorporation

Forest Oil Permian Corporation Delaware
Consent of Independent Registered Public Accounting Firm

 We consent to the incorporation by reference in (i) the Registration Statements (Nos. 333-81529, 333-127873 and 333-160153) on Form S-8 of Forest Oil

Corporation-Employee Stock Purchase Plan, (ii) the Registration Statements (Nos. 333-62408 and 333-108267) on Form S-8 of Forest Oil Corporation-2001

Stock Incentive Plan, (iii) the Registration Statements (Nos. 333-145726 and 333-167004) on Form S-8 of Forest Oil Corporation-2007 Stock Incentive Plan of

Forest Oil Corporation, (iv) the Registration Statement (No. 333-184213) on Form S-8 of Forest Oil Corporation-Patrick R. McDonald Restricted Stock

Inducement Agreement and Performance Unit Inducement Agreement, and (v) the Registration Statement (No. 333-182776) on Form S-3 of Forest Oil

Corporation of our reports dated February 22, 2013, with respect to the consolidated financial statements of Forest Oil Corporation, and the effectiveness of

internal control over financial reporting of Forest Oil Corporation, included in this Annual Report (Form 10-K) for the year ended December 31, 2012 .

/s/ Ernst & Young LLP

Denver, Colorado

February 22, 2013
DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

February 22, 2013

Forest Oil Corporation

707 Seventeenth Street

Suite 3600

Denver, Colorado 80202

Ladies and Gentlemen:

We hereby consent to the use of our name and the information regarding our review of Forest's estimates of reserves in the sections “Preparation of

Reserves Estimates”,“Independent Audit of Reserves” and “Risk Factors” and in Note 15 to the consolidated financial statements in the Annual Report on

Form 10-K of Forest Oil Corporation (the “Company”) for the year ended December 31, 2012 (the “10-K”), the filing of our reports dated January 28, 2013

with respect to our audit of net proved crude oil, condensate, natural gas liquids, and natural gas reserves of the Company as of December 31, 2012, as

exhibit 99.1 to the 10-K. We further consent to the incorporation by reference of the foregoing into the Company's Registration Statements as follows: (i) the

Registration Statements (Nos. 333-81529, 333-127873 and 333-160153) on Form S-8 of Forest Oil Corporation-Employee Stock Purchase Plan, (ii) the

Registration Statements (Nos. 333-62408 and 333-108267) on Form S-8 of Forest Oil Corporation-2001 Stock Incentive Plan, (iii) the Registration Statements

(Nos. 333-145726 and 333-167004) on Form S-8 of Forest Oil Corporation-2007 Stock Incentive Plan, (iv) the Registration Statement (No. 333-184213) on

Form S-8 of Forest Oil Corporation-Patrick R. McDonald Restricted Stock Inducement Agreement and Performance Unit Inducement Agreement, and (v) the

Registration Statement (No. 333-182776) on Form S-3 of Forest Oil Corporation.

Very truly yours,

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716
Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

I, Patrick R. McDonald, certify that:

1. I have reviewed this annual report on Form 10-K of Forest Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the

statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this

report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to

ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those

entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our

supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for

external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent

fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to

materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably

likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control

over financial reporting.

February 22, 2013 /s/ Patrick R. McDonald

(Date) Patrick R. McDonald

President and Chief Executive Officer
Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

I, Michael N. Kennedy, certify that:

1. I have reviewed this annual report on Form 10-K of Forest Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the

statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this

report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to

ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those

entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our

supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for

external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent

fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to

materially affect, the registrant’s internal control over financial reporting;

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the

registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably

likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control

over financial reporting.

February 22, 2013 /s/ Michael N. Kennedy

(Date) Michael N. Kennedy

Executive Vice President and

Chief Financial Officer
Exhibit 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF FOREST OIL CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350

Pursuant to 18 U.S.C. Section 1350 and in connection with the accompanying report on Form 10-K for the year ended December 31, 2012 that is being filed

concurrently with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned officer of Forest Oil Corporation (the

“Company”) hereby certifies that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 22, 2013 /s/ Patrick R. McDonald

(Date) Patrick R. McDonald

President and Chief Executive Officer
Exhibit 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF FOREST OIL CORPORATION

PURSUANT TO 18 U.S.C. SECTION 1350

Pursuant to 18 U.S.C. Section 1350 and in connection with the accompanying report on Form 10-K for the year ended December 31, 2012 that is being filed

concurrently with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned officer of Forest Oil Corporation (the

“Company”) hereby certifies that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 22, 2013 /s/ Michael N. Kennedy

(Date) Michael N. Kennedy

Executive Vice President and

Chief Financial Officer
DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

January 28, 2013

Forest Oil Corporation

707 Seventeenth Street

Suite 3600

Denver, Colorado 80202

Gentlemen:

Pursuant to your request, we have conducted a reserves audit of the estimates of net proved crude oil, condensate, natural gas liquids (NGL)

and natural gas reserves, as of December 31, 2012, prepared by the engineering staff of Forest Oil Corporation (Forest) for interests owned in 18

fields in the United States. This evaluation was completed on January 28, 2013. The reserves reviewed are from working and royalty interests in

properties located in Arkansas, Oklahoma, and Texas. Forest has represented that these properties account for 83.6 percent on a present worth at 10

percent basis of Forest’s net proved reserves in the United States as of December 31, 2012, and that the net proved reserves estimates have been

prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission

(SEC) of the United States. In accordance with the “Procedure Pertaining to the Auditing of Petroleum Reserve Information” of Forest, we have

prepared independent estimates of the proved reserves for the same properties as those which Forest evaluated . This report has been prepared to be

used in connection with the Forest 2012 Annual Report on Form 10-K and for other such purposes as may be requested.

Reserves included herein are expressed as net reserves as represented by Forest. Gross reserves are defined as the total estimated petroleum to

be produced from these properties after December 31, 2012. Net reserves are defined as that portion of the gross reserves attributable to the interests

owned by Forest after deducting all interests owned by others.

Forest has represented that estimated net proved reserves attributable to the reviewed properties are based on the definitions of proved reserves

of the SEC.
2

DEGOLYER AND MACNAUGHTON

Forest represents that its estimates of the net proved reserves attributable to these properties, 75.2 percent of Forest’s total reserves on a net equivalent

basis, are as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and millions of cubic feet equivalent (MMcfe):

Estimated by Forest

Net Proved Reserves

as of December 31, 2012

Oil

(Mbbl)

Natural Gas

Liquids

(Mbbl)

Natural Gas

(MMcf)

Gas Equivalent

(MMcfe)

Field Audited by DeGolyer and MacNaughton 31,041 34,323 632,053 1,024,235

Not Audited by DeGolyer and MacNaughton 2,661 6,932 280,780 338,342

Total United States Reserves 33,702 41,255 912,833 1,362,577

Note: Liquids are converted to gas equivalent using a factor of 1 barrel per 6,000 cubic feet of gas.

In our opinion, the information relating to estimated proved reserves audited by DeGolyer and MacNaughton of oil, condensate, natural gas

liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-

235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve

Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4–10(a) (1)–(32) of Regulation S–X and

Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the Securities and Exchange Commission; provided,

however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as

engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient

therefor.

In comparing the detailed net proved reserves estimates prepared by us and by Forest of the properties in the 18 fields audited, we have found

differences, both positive and negative in reserves estimates for individual properties. These differences appear to be compensating to a great extent

when considering the reserves of Forest, in total, for the properties reviewed, resulting in an overall difference of 2.3 percent when compared on a net

gas equivalent basis. It is our opinion that the net proved estimates prepared by Forest on the properties reviewed by us and referred to
3

DEGOLYER AND MACNAUGHTON

above do not differ materially from those prepared by us.

Estimates of oil, condensate, natural gas liquids, and natural gas should be regarded only as estimates that may change as further production

history and additional information become available. Not only are such reserves estimates based on that information which is currently available, but

such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Data used in this audit were obtained from reviews with Forest personnel, Forest files, from records on file with the appropriate regulatory

agencies, and from public sources. In the preparation of this report we have relied, without independent verification, upon such information furnished

by Forest with respect to property interests, production from such properties, current costs of operation and development, current prices for

production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as

represented. A field examination of the properties was not considered necessary for the purposes of this report.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geological and engineering methods that are in accordance with practices

generally recognized by the petroleum industry as presented in the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and

Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of

each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production

history. These assumptions, data, methods, and procedures are considered appropriate for the purpose for which this report has been prepared.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure

and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used

to prepare these maps as well as to estimate representative values for porosity and water saturation.
4

DEGOLYER AND MACNAUGHTON

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on

consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production

histories. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of

reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic

characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of

production‐decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Definition of Reserves

Petroleum reserves estimated by Forest included in this report are classified as proved. Only proved reserves have been evaluated for this

report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of

the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions

and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of productiondecline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using

prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual

arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and

engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known

reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts

providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or

probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be

reasonably certain that it will commence
5

DEGOLYER AND MACNAUGHTON

the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can,

with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available

geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as

seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with

reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an

associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,

engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to,

fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the

operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the

reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for

development by all necessary parties and entities, including governmental entities.
6

DEGOLYER AND MACNAUGHTON

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The

price shall be the average price during the 12 ‐month period prior to the ending date of the period covered by the report, determined as an

unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by

contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively

minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means

not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered

from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of

production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility

at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they

are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid

injection or
7

DEGOLYER AND MACNAUGHTON

other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same

reservoir or an analogous reservoir, as defined in section 210.4–10 (a) Definitions, or by other evidence using reliable technology

establishing reasonable certainty.

Primary Economic Assumptions

The following economic assumptions were used for estimating existing and future prices and costs:

Oil, Condensate, and NGL Prices

Forest has represented that the oil and condensate prices were based on a 12-month average price (reference price), calculated as the

unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the

reporting period, unless prices are defined by contractual arrangements. Forest supplied differentials by field to a West Texas

Intermediate reference price of $94.79 per barrel and the prices were held constant thereafter. The resulting weighted-average prices

were $98.83 per barrel for oil and condensate and $33.83 per barrel for NGL.

Natural Gas Prices

Forest has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the

first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are

defined by contractual arrangements. The gas prices were calculated for each property using differentials and BTU factors furnished by

Forest to the reference price of $2.76 per MMbtu and held constant thereafter. The resulting weighted-average price was $2.41 per

Mcf.
8

DEGOLYER AND MACNAUGHTON

Operating Expenses and Capital Costs

Operating expenses and capital costs, based on information provided by Forest, were used in estimating future costs required to operate

the properties. In certain cases, future costs, either higher or lower than existing costs, may have been used because of anticipated

changes in operating conditions. These costs were not escalated for inflation.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to

recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2012,

estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services

throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Forest. Our fees

were not contingent on the results of our evaluation. This letter report has been prepared at the request of Forest. DeGolyer and MacNaughton has

used all assumptions, data, procedures, and methods that it considers necessary to prepare this report.

Submitted,

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton
DEGOLYER AND MACNAUGHTON

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244

U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the letter report addressed to Forest dated

January 28, 2013, and that I, as Senior Vice President, was responsible for the preparation of this report.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1974;

that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers

and the American Association of Petroleum Geologists; and that I have in excess of 38 years of experience in oil and gas reservoir studies

and reserves evaluations.

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton