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Item 8. Financial Statements and Supplementary Data.

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

FORM 10-K

Commission file number: 001-35191

LONE PINE RESOURCES INC.
(Exact name of registrant as specified in its charter)

Registrant's telephone number, including area code: (403) 292-8000

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

         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 o    No ý

         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 ý

         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 ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Date 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 ý    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. ý

         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.

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

         The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2011, the last business day of the registrant's most recently completed second fiscal quarter, was US$159,300,000 (based on the closing price of such stock).

         There were 85,026,202 shares of the registrant's common stock, par value US$0.01 per share, outstanding as of March 20, 2012.

DOCUMENTS INCORPORATED BY REFERENCE:

         Portions of the registrant's notice of annual meeting of stockholders and proxy statement to be filed pursuant to Regulation 14A within 120 days after the registrant's fiscal year ended December 31, 2011 are incorporated by reference into Part III of this Form 10-K.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        Certain statements and information in this Annual Report on Form 10-K (this "Form 10-K") may constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. The words "believe," "expect," "anticipate," "plan," "intend," "foresee," "should," "would," "could" or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, "Item 1A. Risk Factors."

        Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

MONETARY AMOUNTS AND EXCHANGE RATE DATA

        In this Form 10-K, references to "dollars," "$" or "Cdn$" are to Canadian dollars and references to "U.S. dollars" or "US$" are to United States dollars. We changed our reporting currency from the U.S. dollar to the Canadian dollar effective October 1, 2011. Prior to changing our reporting currency, we obtained a no objection letter from the Securities and Exchange Commission ("SEC"). See Part I, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2 of our consolidated financial statements for more information about our change in reporting currency, including the reasons for the change, the manner in which the change has been and will be applied to recast prior period financial statements, and a discussion of the major categories of items in the balance sheet, and statements of income and cash flows, that are denominated in Canadian or U.S. dollars.

        The noon-day Canadian to U.S. dollar exchange rates for Cdn$1.00, as reported by the Bank of Canada, were:

        On March 20, 2012, the noon-day exchange rate was US$1.0067 for Cdn$1.00.

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PART I

Item 1.    Business.

        In this Form 10-K, unless otherwise indicated or the context otherwise requires, references to "we," "us," "our," "our company," "the Company" or "Lone Pine" when used in reference to periods prior to June 1, 2011 refer to Lone Pine Resources Canada Ltd. and its consolidated subsidiary, and when used in reference to periods after June 1, 2011, refer to Lone Pine Resources Inc., a Delaware corporation, and its consolidated subsidiaries, including Lone Pine Resources Canada Ltd. Unless the context otherwise requires, references in this Form 10-K to "LPR Canada" or "our predecessor" refer to Lone Pine Resources Canada Ltd., formerly Canadian Forest Oil Ltd., an Alberta corporation and a wholly-owned subsidiary of Lone Pine Resources Inc., which was the predecessor of Lone Pine Resources Inc., and its consolidated subsidiary. Certain oil and gas industry terms used in this Form 10-K are defined in the "—Glossary of Oil and Gas Terms" below.

Overview

        We are an independent oil and gas exploration, development and production company with operations in Canada. Our reserves, producing properties and exploration prospects are located in the provinces of Alberta, British Columbia and Quebec and the Northwest Territories. We were incorporated under the laws of the State of Delaware on September 30, 2010, and prior to our initial public offering ("IPO") on June 1, 2011, we were a wholly-owned subsidiary of Forest Oil Corporation ("Forest"). Our predecessor, Lone Pine Resources Canada Ltd., was acquired by Forest in 1996 and transferred to us prior to completion of our IPO. On September 30, 2011, Forest distributed all of the outstanding shares of our common stock that it owned to its shareholders (the "Distribution"). As a result of the Distribution, Forest has no remaining ownership interest in us.

        DeGolyer and MacNaughton, our independent reserves engineers, estimated our proved reserves to be approximately 401 Bcfe as of December 31, 2011, of which approximately 26% was oil and natural gas liquids ("NGLs"), approximately 74% was natural gas and approximately 53% was classified as proved developed reserves. As of December 31, 2011, we had approximately 151 gross (125 net) proved undeveloped drilling locations and approximately 1.1 million gross (0.8 million net) acres of

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land (approximately 79% of which was undeveloped). The following table presents summary data for each of our significant properties as of December 31, 2011:

Our History

        During the past five years, we have primarily focused on the development of our Deep Basin and Evi areas, which were acquired in connection with Forest's acquisition of The Wiser Oil Company ("Wiser") in 2004. More recently, we have applied our experience from the Wild River field to the development and expansion of our Narraway/Ojay fields and furthered the development of our light oil assets in the Evi area.

        Beginning in 2009, we applied multi-zone slick-water fracture completion technology to our Narraway/Ojay fields that yielded improved results. As a result, we undertook a significant leasing campaign in the Narraway/Ojay area and completed an acquisition in April 2011 of approximately 35,700 net acres in the Narraway field, which increased our acreage position from approximately 21,000 net acres at December 31, 2008 to approximately 121,088 net acres at December 31, 2011. We also increased our oil drilling activity in our Evi area in 2009, accelerating our horizontal drilling program that began in 2006. From 2006 through December 31, 2011, we have drilled a total of 72 gross

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horizontal oil wells in the Evi area. Due to the success of our initial horizontal wells, we undertook a significant leasing campaign in the Evi area, which increased our net acreage position from approximately 11,000 net acres at December 31, 2004 to approximately 57,382 net acres at December 31, 2011.

        Through our leasing efforts in Quebec, which began in 2007, we have acquired approximately 240,320 net acres in the Utica Shale play as of December 31, 2011. From 2007 through 2010, we participated in the drilling of ten exploration wells. We intend to continue to evaluate our acreage for future development while working with the Quebec Oil & Gas Association and provincial government agencies as the province undertakes a strategic environmental assessment ("SEA") of shale gas drilling in the province as recommended by the province's environmental public hearing board, the Bureau d'audienees publiques sur l'environnement ("BAPE").

        In addition to our large shale gas position in Quebec, as of December 31, 2011, we had approximately 52,995 contiguous net acres in the Liard Basin, located in the Northwest Territories, that are prospective for the Muskwa Shale. We believe that our acreage in the Liard Basin is analogous to the Muskwa Shale in the Horn River Basin.

        As we have expanded into new plays, we also have divested assets that did not meet our development growth strategy. Starting in the fourth quarter of 2009 and through December 31, 2011, we divested approximately $159 million of certain non-core or non-operated oil and gas properties, primarily in December 2009 and April 2010, that, at the time the divestitures occurred, had a combined net production rate of 16 MMcfe/d.

Our Business Strategy

        Our business strategy is to increase stockholder value by efficiently increasing production, reserves and cash flow by applying horizontal drilling and new completion technologies to our significant and diversified undeveloped acreage positions. We expect to execute this strategy while managing our debt levels relative to our estimated proved reserves and cash flow. We endeavor to execute this strategy as follows:

•

Exploit and develop resource plays by applying horizontal drilling and new completion technologies.  We intend to apply the latest exploitation technologies to our resource plays, including horizontal drilling and multi-stage hydraulic fracture stimulation techniques. Each of our Evi and Deep Basin areas has a large number of remaining drilling locations where delineation drilling has established the existence of a consistent geologic trend, creating what we believe are repeatable development opportunities through horizontal and vertical drilling.



•

Enhance returns by focusing on operational control and cost efficiencies.  We plan to develop and execute large-scale, repeatable drilling programs in areas where we have high working interests, concentrated land positions, large drilling inventories and operational control to reduce costs and achieve economies of scale, thereby attaining higher rates of return on invested capital.



•

Maintain a diversified commodity mix.  Our current asset base is composed of both light oil and natural gas opportunities. Our diversified portfolio allows us to focus on one commodity over another when disparity between commodity prices dictates. In 2011, we were able to successfully increase our average liquids production weighting from 14% in the first quarter to 27% in the fourth quarter by focusing our capital investment on light oil. In 2012, we again plan to focus our capital budget on light oil by allocating approximately 80% of our total budget to light oil opportunities. Based on this focus, we expect to increase our average liquids production weighting from 21% in 2011 to 35% in 2012 and to approximately 40% by the end of 2012. We plan on continuing a diversified approach over the long term, with the majority of our capital allocated in the short term to assets with the highest rates of return.

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•

Develop, expand and rationalize our asset base through leasehold and property acquisitions, divestitures and exploration.  We intend to pursue leasehold and property acquisitions to enhance existing business operations in our core areas and to gain entrance into new, complementary resource plays, with a preference for liquids-rich hydrocarbon prospects. We also plan to pursue a measured exploration drilling program in these areas in order to expand the ultimate scope of commercial development of our asset base. As economic conditions permit, we intend to divest assets that do not fit our primary business strategy, including those without significant development opportunities.



•

Maintain financial flexibility.  We plan to maintain a strong liquidity position to successfully execute our growth strategy through the application of budget controls and disciplined financial management. We intend to focus on managing our debt levels relative to our estimated proved reserves and cash flow. We intend to also support our future cash flow through the management of a measured commodity hedging program.

Our Competitive Strengths

        We believe we have a number of competitive strengths that will help us to execute our business strategy:

•

Large, contiguous acreage positions, with multi-year, diversified drilling inventory.  Our leasing efforts, which have included early identification and leasehold acquisitions of acreage in prospective areas, have enabled us to develop large, contiguous acreage positions. In total, we have accumulated approximately 1.1 million gross (0.8 million net) acres in prospective areas, with approximately 79% of the acreage classified as undeveloped as of December 31, 2011. We have a commodity-diverse drilling portfolio with approximately 84 gross (77 net) proved undeveloped drilling locations as of December 31, 2011 in our Evi area targeting premium-priced light oil, and approximately 62 gross (44 net) proved undeveloped drilling locations as of December 31, 2011 in the Deep Basin targeting natural gas and NGLs. Our acreage positions allow us to be more competitive in our development efforts through the execution of large-scale drilling and multi-stage hydraulic fracture stimulation programs and the establishment of centralized gathering systems and associated facilities.



•

Established light oil resource with future development upside.  The Evi area has historically been produced extensively from a deeper Granite Wash horizon with over 2,500 vertical wells drilled into the play. Since 2006, the focus in the Evi area has been on a shallower Slave Point horizon that has been exploited through horizontal drilling and multi-stage hydraulic fracture stimulation. The presence of the deeper producing horizon has provided extensive well control and formed the basis of a specific geological model that we use in the development of the area. Recent developments in the area have focused on increasing the number of hydraulic fracture stages placed into a horizontal well. In 2011, we increased the average fracture density from six stages to ten stages and realized an increase in well productivity of over 60%. We believe that further improvement in well design combined with additional downspacing across our acreage provides for extensive future development opportunities.



•

Multi-stacked intervals in the Deep Basin, which yield low-risk incremental development opportunities.  The Deep Basin has historically been a highly prospective area for the production of natural gas and NGLs. The Deep Basin fields produce from a minimum of ten different stacked producing intervals, many of which have not been exploited horizontally. With the advancement of drilling and completion technology, many of these intervals now have the potential to be developed with favorable economic results. We believe our interests in over 250 productive wells in the Deep Basin, completed in multiple zones, and our understanding of the geology of the basin, give us a competitive advantage in the development of these unexploited intervals. Our primary focus in the Deep Basin will be in the Narraway/Ojay and Wild River fields. We believe that the application of horizontal drilling and multi-stage fracturing technologies, while more expensive

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than vertical wells, will allow us to develop this and other intervals at enhanced economic rates of return.

•

Management and technical team with demonstrated operational and technical skills.  Our management and technical team has extensive expertise in the oil and gas industry. We believe that our team is one of our principal competitive strengths, as evidenced by our track record in establishing, developing and expanding our core assets with profitable rates of return. Our team has successfully implemented horizontal drilling and multi-stage hydraulic fracturing technologies and plans to expand the application of these technologies across our resource plays. From the completion of our first horizontal well in the Evi area in 2006 through December 31, 2011, we have drilled a total of 72 gross horizontal wells, improved production rates and recoveries by increasing the number of fracturing stages and reduced drilling times and drilling costs through efficiency gains. We expect to continue to pursue the application of horizontal drilling and multi-stage fracturing technologies on our extensive resource bases.



•

Operating control over a majority of our properties, with limited near-term lease expiries.  We have high working interests in our properties and currently operate over 80% of our production. Further, we operated all of our 2011 drilling program and expect to operate substantially all of our planned 2012 drilling program. As the designated operator, we believe we can maintain control over capital expenditures, operating costs and the pace of exploration and development. We also have limited near-term lease expiries. As of December 31, 2011, approximately 85% of our net acreage was held by leases whose terms extend beyond the next three years.



•

Strong balance sheet.  We have a $500 million credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. As of December 31, 2011, our borrowing base under the bank credit facility was $425 million and we had approximately $331 million in borrowings under our bank credit facility. In February 2012, our wholly-owned subsidiary, Lone Pine Resources Canada Ltd., issued US$200 million of 10.375% Senior Notes due 2017 (the "Senior Notes"). The net proceeds of approximately $192 million, after deduction of original issue and initial purchaser discounts and estimated offering expenses, were used to partially repay borrowings outstanding under our bank credit facility. As of March 20, 2012, we had approximately $185 million of secured indebtedness outstanding under our bank credit facility and secured borrowing capacity of approximately $188 million (after deducting $1.6 million of outstanding letters of credit).



•

Strong hedging positions.  As of March 20, 2012, we had 25,000 MMBtu/d, representing approximately 40% of our forecasted 2012 average daily net natural gas production volumes hedged at an average NYMEX Henry Hub price of US$5.09 per MMBtu/d and 3,000 bbls/d of crude oil, representing approximately 55% of our forecasted 2012 average daily net crude oil production volumes hedged at US$102.35 (as to 2,000 bbls/d) and $100.98 (as to 1,000 bbls/d). We also had 1,000 bbls/d of 2013 crude oil production hedged at $102.00 (as to 500 bbls/d) and US$101.00 (as to 500 bbls/d).

Financial Information About Segments and Geographical Areas

        We operate our business as a single segment with similar economic characteristics, technology, manufacturing processes, customers, distribution and marketing strategies, regulatory environments and shared infrastructures. We operate in one industry segment, and our oil and gas exploration and production activities are exclusively within Canada. Our financial information, including our net sales and long-lived assets by geographical area, is included in our consolidated financial statements and the related notes contained elsewhere in this Form 10-K.

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Significant Properties

Evi Area

        As of December 31, 2011, we had approximately 57,382 net acres in and near the Evi field, located in the Peace River Arch area of northern Alberta. This position offers us a significant development opportunity for premium-priced light oil. From 2006 through December 31, 2011, we have drilled a total of 72 horizontal wells in the Evi area. We acquired our initial acreage position in the Evi field in 2004 as part of Forest's acquisition of Wiser, and we have significantly expanded our acreage position through Crown leasing and acquisitions from approximately 11,000 net acres at December 31, 2004 to 57,382 net acres at December 31, 2011. As of December 31, 2011, our acreage position in the Evi area consists of 100 gross (89 net) sections on which we have 133 gross (102 net) productive wells in the Slave Point formation, of which 72 are horizontal wells. As of December 31, 2011, we had 94 Bcfe of total estimated proved reserves at Evi, including 40 Bcfe that are classified as proved developed reserves. As of December 31, 2011, we had 84 gross (77 net) proved undeveloped drilling locations in the Evi area. Initially, we plan to drill six horizontal wells per section, although regulatory spacing in the Evi field for the Slave Point formation generally provides for eight wells per section and we have received regulatory approval to downspace certain sections in the central area of Evi to up to 16 wells per section.

        In 2011, we drilled 47 gross (47 net) horizontal wells in the Evi area as compared to 25 gross (17 net) wells in 2010 and increased the number of fracture stimulation stages from an average of six to ten stages. Our working interest in all of the wells drilled in 2011 is 100%. During 2011, we had average daily net sales volumes of 2,357 bbls/d from production in the Evi area. We plan to drill up to 48 horizontal wells in the Evi area in 2012. We believe that we can ultimately enhance production rates and recoveries in the Evi area through further development drilling, including further downspacing of our acreage, completion optimization and secondary recovery techniques, such as waterflooding. We intend to continue to expand our facilities in the Evi area to accommodate the growing crude oil volumes in the area and continue to invest in our operated waterflood pilot project that we initiated in 2011. In 2012, we plan to focus our capital budget on light oil by allocating approximately 80% of our total capital budget or, approximately $165 million, to the Evi area. Our historical costs to drill and complete horizontal wells have ranged from $1.9 million to $5.2 million per well and have averaged $2.9 million per well. We expect that wells drilled in 2012 will have an average cost of $2.9 million per well.

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Deep Basin Area

        As of December 31, 2011, we had approximately 157,779 net acres in the Deep Basin, including approximately 121,088 net acres in the Narraway/Ojay fields, located in Alberta and British Columbia, and approximately 12,853 net acres in the Wild River field, located in the southeast portion of the Deep Basin. In 2011, we drilled and completed 6 gross (5.5 net) wells in the Narraway/Ojay fields, including 1 gross (1 net) horizontal well. In the fourth quarter of 2011, we had average daily net sales volumes of 66 MMcfe/d from production in the Deep Basin. Our development of these assets is primarily focused on our Narraway/Ojay and Wild River fields. Geologically, these fields have a minimum of ten different stacked producing intervals, and we are able to produce from multiple intervals within an individual wellbore. We currently have no significant near-term expiries or drilling obligations in the Deep Basin, which has allowed us to be flexible with our 2012 capital budget and defer significant natural gas investment until natural gas prices improve from their existing multi-year lows. In 2012, we are allocating approximately 7% of our total capital budget, or approximately $15 million, to the Deep Basin, where we plan to focus primarily on recompletion opportunities.

Narraway/Ojay Fields

        As of December 31, 2011, we had approximately 121,088 net acres in the Narraway/Ojay fields, located in Alberta and British Columbia. This acreage position establishes us as one of the top acreage holders in the area. Following positive drilling results in the Narraway/Ojay fields during 2009, we undertook a significant leasing campaign in the Narraway/Ojay area, which increased our acreage position from approximately 21,000 net acres at December 31, 2008 to approximately 121,088 net acres at December 31, 2011. As of December 31, 2011, our land holding was 206 gross (162 net) sections, and we had 29 gross (24 net) proved undeveloped drilling locations in the Narraway field. Regulatory spacing in the Narraway field currently provides for four wells per section. Our acreage position in the Ojay field as of December 31, 2011 consisted of 56 gross (23 net) sections on which we had 9 gross (4 net) productive wells. As of December 31, 2011, we had 3 gross (1.5 net) proved undeveloped drilling locations in the Ojay field. Regulatory spacing in the Ojay field currently provides for one well per section.

        From the fourth quarter of 2008 to the fourth quarter of 2011, we have increased our net sales volumes from the Narraway/Ojay fields from 5 to 44 MMcfe/d, which we believe demonstrates the significant growth potential of the Narraway/Ojay fields. Our wells in the Narraway/Ojay fields provide multi-zone completion opportunities, with the Nikanassin formation as the anchor zone, and with numerous gas bearing formations in zones above, or uphole of, the anchor zone. These uphole zones can be commingled for production purposes. The Nikanassin is the anchor formation in the fields, and we sometimes refer to the Narraway/Ojay fields as part of the Nikanassin Resource Play.

        On April 29, 2011, we completed the acquisition of certain natural gas properties located in the Narraway/Ojay fields. The acquisition increased our working interests in certain properties that we already owned and operated in the Narraway field from approximately 50% to 100% and provided us with additional capacity in gathering systems and a gas plant in the Narraway field. In addition, the acquisition increased our acreage position by approximately 85,100 gross (35,700 net) acres.

Wild River Field

        We have approximately 12,853 net acres in the Wild River field, located in the southeast portion of the Deep Basin. We acquired our position in 2004 as part of Forest's acquisition of Wiser. As of December 31, 2011, our acreage position in the Wild River field consisted of 41 gross (20 net) sections on which we have 156 gross (92 net) productive wells. As of December 31, 2011, we had 26 gross (17 net) proved undeveloped drilling locations in the Wild River field. Regulatory spacing in the Wild River field currently provides for eight wells per section. We have drilled 143 wells in the Wild River

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field since our acquisition in 2004 through the fourth quarter of 2011. During this same period, we also reduced the average number of days to drill each well by approximately 30%. We have targeted multiple-zone intervals, with the Cadomin formation as the anchor zone. The stacked pay in our Wild River field has provided drilling opportunities that have been vertically developed; however, we believe the application of horizontal drilling and multi-stage fracturing technology, while more expensive than vertical wells, will further enhance the economic development of this field. Industry activity in the area has demonstrated horizontal success targeting the uphole, liquids-rich Cardium interval, and we believe our acreage is also prospective for this interval.

Shales

        As of December 31, 2011, we had approximately 240,320 net acres in Quebec that are prospective for the Utica Shale. No reserves are attributed to our Quebec properties. Natural gas produced from this area is in close proximity to major markets in Canada and the northeastern United States, which generally provides for premium product pricing compared to the NYMEX Henry Hub pricing. The Utica Shale is relatively shallow compared to other shale plays in North America, which we believe will provide for an economic advantage relative to the drilling costs associated with developing the resource.

        In 2006 and 2007, we took cores from three vertical test wells targeting a section of the upper Utica Shale, or the Upper Utica, and tested two of these wells at a peak rate of 1,000 Mcfe/d. We then drilled three horizontal test wells (each with 2,000 foot laterals and four fracture stimulation stages), which had similar initial production test rates. Our historical costs to drill and complete these horizontal wells in the Utica Shale have ranged from US$5.8 million to US$7.0 million. We participated in a vertical well in the area during the fourth quarter of 2010 and took samples to further confirm the rock properties associated with the Middle Utica.

        Subject to minimal capital commitment, approximately 50% of our acreage is under leases that will expire in 2019, approximately 4% of our acreage is under leases that will expire in 2022 and approximately 46% of our acreage is under leases that will expire in 2023. Furthermore, transportation infrastructure is already in place in the Utica Shale, which should lower development expenditures. We believe that these factors, coupled with the area's premium natural gas prices, provide favorable development economics.

        On March 8, 2011, the Government of Quebec announced that it would move forward with the SAE of shale gas drilling in the province as recommended by the BAPE, in a report delivered to the Quebec Minister of Sustainable Development, Environment and Parks. A committee was appointed in May 2011 to conduct the SEA, which is expected to take 18 to 30 months, during which the government has indicated that hydraulic fracturing will only be permitted in Quebec for scientific data gathering purposes if required for the SEA and on the committee's recommendation. The SEA committee is to report annually, with its first report due in May 2012, and ultimately propose changes to the current legislative and regulatory framework for oil and gas exploration and development in Quebec.

        On June 13, 2011, in response to concerns over the impact of the SEA on the terms of existing exploration licenses, legislation was implemented to exempt holders of licenses to explore for petroleum, natural gas and underground reservoirs from prescribed exploration work requirements until a date to be determined by the government (but not later than July 13, 2014), and effectively extend the term of such licenses for the same period. The legislation also, however, prohibits oil and gas activities in the St. Lawrence River upstream of Anticosti Island and on the islands situated in that part of the river and revokes, without compensation, oil and gas rights previously issued for that area. We held exploration licenses to 33,460 net acres under the St. Lawrence River, representing approximately 14% of our overall net acres in Quebec, that were revoked by this legislation and are considering

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available alternatives with respect to the government's action. The revoked acreage consists entirely of undeveloped lands. No reserves are attributed to our Quebec properties.

        During the SEA period, we will be able to explore and gather scientific data on our remaining undeveloped shale acreage positions. The Ministry of Natural Resources is expected to provide interim regulations to act under during the SEA committee's undertakings. See Part I, "Item 1A. Risk Factors—Risks Related to Our Business—New laws or regulatory requirements relating to hydraulic fracturing could make it more difficult or costly for us to perform fracturing of producing formations and could have an adverse effect on our ability to produce oil and gas from new wells" and "—Environmental Regulation."

        As of December 31, 2011, we had approximately 52,995 net acres in the Liard Basin, located in the Northwest Territories, that are prospective for the Muskwa Shale. No reserves are attributed to our Liard Basin properties. This is a newly developing natural gas shale play adjacent to the producing Horn River Basin. We believe that our acreage in the Liard Basin is analogous to the Muskwa Shale in the Horn River Basin. Our acreage is located in close proximity to a pipeline in the Northwest Territories providing for the sale and distribution of any natural gas produced. In the third and fourth quarters of 2011, we re-entered and recompleted a well in the Liard Basin, and in February 2012, we submitted an application to the National Energy Board to potentially continue the lease for up to 21 more years.

Infrastructure

        During 2010, we spent $49 million on the construction of key infrastructure and the purchase of related equipment in the Narraway/Ojay fields. In late November 2010, we completed construction of a natural gas pipeline connecting shut-in wells from our Ojay acreage in British Columbia to sales meters in western Alberta. Our gas gathering system and associated facilities at the Narraway/Ojay fields were expanded in order to alleviate capacity restrictions, improve timely takeaway of our gas and enable us to proceed with our development plan. We believe that we have installed sufficient capacity to meet our near-term drilling plans for our assets in those fields and accommodate third-party volumes. At the Evi area, we have installed infrastructure that allows us to transport by pipeline the majority of our oil production, which has minimized the cost of trucking and the downtime associated with weather-dependent access to some locations. We intend to install, as needed, additional infrastructure in our core areas, which should allow us to continue to substantially control the pace of development, ensure timely takeaway of our production volumes and continue our commitment to improving operational efficiencies and cost control.

Reserves

        The following table summarizes our estimated quantities of proved reserves as of December 31, 2011 and 2010. Our estimated proved reserves as of December 31, 2011 are based on the NYMEX Henry Hub price of US$4.15 per MMBtu and AECO price of $3.77 per MMBtu for natural gas and the NYMEX West Texas Intermediate price of US$96.13 per barrel and Edmonton Light price of $96.98 per barrel for oil, each of which represents the unweighted arithmetic average of the first-day-of-the-month prices during the 12-month period prior to December 31, 2011. Our estimated proved reserves as of December 31, 2010 are based on the NYMEX Henry Hub price of US$4.38 per MMBtu and AECO price of $3.93 per MMBtu for natural gas and the NYMEX West Texas Intermediate price of US$79.81 per barrel and Edmonton Light price of $77.80 per barrel for oil, each of which represents the unweighted arithmetic average of the first-day-of-the-month prices during the 12-month period prior to December 31, 2010. See "—Preparation of Estimated Proved Reserves as of December 31, 2011" below, "—Preparation of Estimated Proved Reserves as of December 31, 2010" below

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and note 25 to our consolidated financial statements included elsewhere in this Form 10-K for additional information regarding our estimated proved reserves.

        As of December 31, 2011, we had estimated proved reserves of 401 Bcfe. Our estimated proved reserves have a reserve life of 12 years, and our estimated proved developed reserves have a reserve life of six years. During 2011, we added a total of 24.2 Bcfe of estimated proved reserves. Additions were primarily due to additional reserve bookings in our Evi area associated with positive drilling results, and our acquisition of certain natural gas properties in the Narraway/Ojay fields on April 29, 2011. These additions were partially offset by revisions of previous estimates primarily due to the performance of existing wells and by production. As of December 31, 2011, proved undeveloped reserves ("PUDs") were estimated to be 187 Bcfe, or 47% of total estimated proved reserves, compared to 168 Bcfe, or 45% of total estimated proved reserves, as of December 31, 2010. The net increase of 19 Bcfe was primarily due to successful drilling results in our Evi area. The additional PUD bookings were primarily from direct offsets to existing wells. We intend to convert the PUD reserves disclosed as of December 31, 2011 to proved developed reserves within five years of when they were initially disclosed as PUDs.

        Our reserve estimates as of December 31, 2011 and 2010 presented herein were made in accordance with the SEC's "Modernization of Oil and Gas Reporting" rules, which were effective for fiscal years ending on or after December 31, 2009. The new SEC rules include updated definitions of proved oil and gas reserves, proved undeveloped oil and gas reserves, oil and gas producing activities and other terms used in estimating proved oil and gas reserves. Pursuant to the SEC rules, proved oil and gas reserves as of December 31, 2011 and 2010 were calculated based on the prices for oil and natural gas during the 12-month period before the reporting date, determined as the unweighted arithmetic averages of the first-day-of-the-month prices for each month within such period, rather than the year-end spot prices, which had been used in years prior to 2009. Undrilled locations can be classified as having PUD reserves 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. The new SEC rules broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of oil and gas producing activities to include the extraction of non-traditional resources, including bitumen extracted from oil sands, as well as oil and natural gas extracted from shales.

        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 and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve 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

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such estimates. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserve estimates.

Preparation of Estimated Proved Reserves as of December 31, 2011

Independent Petroleum Engineers

        Our estimated proved reserves at December 31, 2011 are based on a report dated February 3, 2012 prepared by DeGolyer and MacNaughton, our independent reserves engineers, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and current guidelines established by the SEC. DeGolyer and MacNaughton is a Delaware corporation with offices in Dallas, Houston, Calgary and Moscow. The firm's more than 140 professionals include engineers, geologists, geophysicists, petrophysicists and economists engaged in the appraisal of oil and gas properties, evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. These services have been provided since 1936. DeGolyer and MacNaughton restricts its activities exclusively to consultation; it does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties or securities or notes of clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm. The Senior Vice President at DeGolyer and MacNaughton primarily responsible for overseeing the preparation of the reserve estimates is a Registered Petroleum Engineer in the State of Texas with more than 37 years of experience in oil and gas reservoir studies and reserve evaluations. He graduated with a Bachelor of Science degree in Petroleum Engineering from Texas A&M University in 1974, and he is a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists.

Technology Used To Establish Proved Reserves

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

        In order to establish reasonable certainty with respect to our estimated proved reserves, DeGolyer and MacNaughton employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well-test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and were completed using similar techniques.

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Internal Controls Over Reserves Estimation Process

        We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timelines of data furnished to our independent reserves engineers in their reserves estimation process. Our Vice President, Engineering and Exploitation, Shona F. Mackenzie, is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Ms. Mackenzie has over 17 years of industry experience with positions of increasing responsibility in engineering and evaluations and holds both a Bachelor of Engineering degree and a Master of Engineering degree in petroleum engineering. Ms. Mackenzie reports directly to our President and Chief Executive Officer, David M. Anderson.

        Throughout each fiscal year, our technical team meets with representatives of our independent reserves engineers to review properties and discuss methods and assumptions used in the preparation of the proved reserves estimates. In addition, our management reports on a quarterly basis to our Audit and Reserves Committee, and our Audit and Reserves Committee meets privately with personnel from DeGolyer and MacNaughton on an annual basis to confirm that DeGolyer and MacNaughton has not identified any concerns or issues relating to its reserves estimates.

Preparation of Estimated Proved Reserves as of December 31, 2010

        Our estimated proved reserves as of December 31, 2010 were prepared by the internal staff of engineers of Forest and LPR Canada, with significant consultation with internal geologists and geophysicists. The reserves estimates were based on production performance and data acquired remotely or in wells and were guided by petrophysical, geologic, geophysical and reservoir engineering models. Moreover, new reserves estimates and significant changes to existing reserves were reviewed and approved by various levels of management, depending on their magnitude. Proved reserves estimates were reviewed and approved by Forest's Senior Vice President, Business Development and Engineering, Glen Mizenko, and audited by independent reserve personnel from DeGolyer and MacNaughton to confirm that DeGolyer and MacNaughton had not identified any concerns or issues relating to the audit and maintained independence. In addition, Forest's internal audit department randomly selected a sample of new reserves estimates or changes made to existing reserves and tested to ensure that they were properly documented and approved.

        As of December 31, 2010, Forest's Senior Vice President, Business Development and Engineering, Mr. Mizenko, had over 25 years of experience in oil and gas exploration and production and had served in this position at Forest since May 2007. Prior to that time, Mr. Mizenko held positions of increasing responsibility since joining Forest in early 2001. Prior to joining Forest, Mr. Mizenko held various positions in reservoir engineering, development planning and operations management with Shell Oil Company, Benton Oil and Gas Company and British Borneo Oil and Gas PLC. Mr. Mizenko received a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1985 and a Masters of Business Administration from the University of Houston in 1993. As of December 31, 2010, he was a 26-year member of the Society of Petroleum Engineers.

        In the past, Forest engaged independent reserves engineers to audit a substantial portion of our reserves. Forest's audit procedures required the independent reserves engineers to prepare their own estimates of proved reserves for fields comprising at least 80% of the aggregate net present value of our year-end proved reserves, discounted to net present value ("NPV") at 10% per annum. The fields selected for audit also were required to comprise at least 80% of our fields based on the discounted present value of such fields and a minimum of 80% of the NPV added during the year through discoveries, extensions and acquisitions. The procedures prohibited exclusions of any fields, or any part of a field, that comprised part of the top 80%. The independent reserves engineers compared their estimates to those prepared by Forest's internal staff of engineers. Forest's audit guidelines required its

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internal estimates, which were used for financial reporting purposes, to be within ten percent of the independent reserves engineers' quantity estimates in each country in which proved reserves were reported. The independent reserves audit was conducted based on the definition of reserves and cost and price parameters specified by the SEC.

        For the years ended December 31, 2010 and 2009, we engaged DeGolyer and MacNaughton to perform reserve audit services. For the year ended December 31, 2010, DeGolyer and MacNaughton independently audited estimates relating to properties in our Narraway/Ojay, Wild River and Evi fields constituting approximately 81% of our reserves as of December 31, 2010. In the aggregate, Forest's and LPR Canada's estimates of total proved reserves for the fields audited were within ten percent of DeGolyer and MacNaughton's aggregate estimate of proved reserves. When compared on a field-by-field basis, Forest's and LPR Canada's estimates of proved reserves in our Narraway, Wild River and Evi fields were greater than the estimates prepared by DeGolyer and MacNaughton, and Forest's and LPR Canada's estimates of proved reserves in our Ojay field were less than the estimates prepared by DeGolyer and MacNaughton. In the aggregate, Forest's and LPR Canada's estimates of total proved reserves for the fields audited were 9.2 percent greater than the estimates prepared by DeGolyer and MacNaughton when compared on a net gas-equivalent basis. In its audit report, DeGolyer and MacNaughton stated that, in its opinion, the net proved reserves estimates prepared by Forest on the properties reviewed by DeGolyer and MacNaughton were reasonable. The lead technical person at DeGolyer and MacNaughton primarily responsible for overseeing the audit of our reserves was a Registered Professional Engineer in the State of Texas, was a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists and had in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations.

Drilling Activities

        The following table summarizes the number of wells drilled during the years ended December 31, 2011, 2010 and 2009, 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, 2011, we had 2 gross (2 net) wells in progress. Our 2011 horizontal drilling program achieved a 100% success rate, and our 2010 drilling program achieved a 100% success rate due to the multiple number of reservoirs our wells penetrated during drilling in these particular fields.

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Oil and Gas Wells and Acreage

Productive Wells

        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. The following table summarizes our productive wells as of December 31, 2011.

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, 2011. 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, 2011, approximately 8%, 1% and 6% of our net undeveloped acreage was held under leases that will expire in 2012, 2013 and 2014, respectively, if not extended by exploration or production activities.

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Production, Average Sales Prices and Production Costs

        The following table sets forth the net sales volumes (MMcfe) attributable to fields that contain 15% or more of our total estimated proved reserves as of the years ended December 31, 2011, 2010 and 2009.

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 and is typically sold at or near the wellhead. Our natural gas liquids production is typically sold under term agreements at gas processing facilities at prices based on the average of posted prices less pipeline tariffs and fractionation fees. 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. As of March 20, 2012, we have a delivery commitment of approximately 21 BBtu/d of natural gas, which provides for a price equal to the greater of (1) the NYMEX Henry Hub price less US$1.49 and (2) US$1.00 per MMBtu to a buyer through

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October 31, 2014, unless the NYMEX Henry Hub price exceeds US$6.50 per MMBtu, at which point we share the amount of the excess equally with the buyer. Approximately 90% of our current natural gas production, or approximately 60 MMcfe/d, in Alberta and British Columbia is available to be used as source gas for this delivery commitment.

Competition

        We encounter competition in all aspects of our business, including acquisition of properties and oil and gas leases, marketing oil, natural gas and NGLs, obtaining services and labor and securing drilling rigs and other equipment 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. See Part I, "Item 1A. Risk Factors—Risks Related to Our Business—Competition within our industry is intense and may have a material adverse effect on our business, financial condition, cash flows and results of operations."

Seasonality

        The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of drilling rigs and other heavy equipment, thereby limiting or temporarily halting our drilling and producing activities and other oil and gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the winter months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

Industry Regulation

        The oil and gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government, and our oil and gas operations are subject to various Canadian federal, provincial, territorial and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions, and regulate, among other things, land tenure, the exploration and development of hydrocarbon resources and production, handling, storage, transportation and disposal of oil and gas, oil and gas by-products and other substances and materials produced or used in connection with oil and gas operations. More particularly, matters subject to current governmental regulation and/or pending legislative or regulatory changes include the licensing for drilling and completion of wells, the method and ability to produce from wells, surface usage, transportation of production, conservation matters, the discharge or other release into the environment of wastes and other substances in connection with drilling and production activities (including fracture stimulation operations), bonds 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 and royalties and taxation. 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, loss or cancellation of governmental or regulatory approvals and the issuance of injunctions or similar orders that could delay, limit or prohibit certain of our operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations.

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        Federal authorities do not regulate the price of oil and gas in export trade. Legislation exists, however, that regulates the quantities of oil, natural gas and NGLs that may be removed from the provinces and exported from Canada in certain circumstances. At various times, regulatory agencies have imposed price controls and limitations on oil and natural gas production. In order to conserve supplies of oil and natural gas, these agencies may also restrict the rates of flow of oil and natural gas wells below actual production capacity. Further, a significant spill from one of our facilities could have a material adverse effect on our business, financial condition, cash flows and results of operations.

        We do not expect that any of these regulatory controls and restrictions will affect us in a manner significantly different from other oil and gas companies of similar size with operations in Canada.

Royalties

General

        Each of the provinces and territories in which we operate has legislation and regulations governing royalties, land tenure, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime applicable in the provinces and territories in which we operate is a significant factor in the profitability of our production. Crown royalties payable in respect of production from Crown, or public, lands are determined by government regulation and are typically calculated as a percentage of the value of production. The value of production and the rate of royalties payable depend on prescribed reference prices, well productivity, geographical location and the type of product produced.

        Royalties payable on production from privately-owned lands are determined by negotiations between us and the resource owners. Any such royalties (or royalty-like interests) are carved out of the working interest owner's interest through non-public transactions and are often referred to as overriding royalties, gross overriding royalties, net profit interests or net carried interests.

        Governments sometimes adopt incentive programs to stimulate oil and gas exploration and development activity in their jurisdictions, which may include royalty rate reductions, drilling credits, royalty holidays or royalty tax credits. Such programs are often of limited duration and target specified types of oil and gas activities.

Alberta

        The majority of our current oil and gas production is from properties located in Alberta.

        On October 25, 2007, the Government of Alberta released its New Royalty Framework ("NRF") proposals, which included significant changes to Alberta's oil and gas royalty system. The NRF was implemented on January 1, 2009. On March 11, 2010, the Government of Alberta announced further adjustments to the royalty framework, reducing maximum royalty rates and making certain temporary incentive programs permanent effective January 1, 2011, and re-naming the NRF the Alberta Royalty Framework ("ARF").

        The NRF established new royalties for conventional oil, natural gas and bitumen that are linked to price and production levels and apply to both new and existing conventional oil and gas activities and oil sands projects. Under the NRF (now ARF), the royalties payable for conventional oil and natural gas are derived using sliding rate formulae, which incorporate a market price component and a production volume component.

        In November 2008, in connection with the implementation and phase-in of the NRF, the Government of Alberta announced a five-year program of "transitional" royalty rates providing for lower royalties at certain price points in the initial years of a qualifying well's life. Under the transitional royalty program, companies drilling new natural gas and conventional oil deep wells at

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depths between 1,000 meters and 3,500 meters (3,281 feet and 11,483 feet, respectively) spud after November 19, 2008 had a one-time option, on a well-by-well basis, to elect for the production from such wells to be subject to the transitional royalty rates or those provided for under the NRF. The option for producers to elect for transitional royalties in respect of qualifying deep wells ended on December 31, 2010. Any wells spudded on or after January 1, 2011 are subject to the royalty rates provided for under the ARF. Wells that are subject to transitional royalty rates will automatically revert to ARF rates on January 1, 2014.

        Under the ARF, royalty rates for conventional oil currently range from 0% to 40%, and royalty rates for natural gas (methane and ethane) currently range from 5% to 36%. ARF rates for propane and butane are fixed at 30%, and the rate for pentane is fixed at 40%. Condensate royalties under the ARF are calculated on a basis similar to royalties for conventional oil and currently range from 0% to 40%.

        The Government of Alberta has also introduced a number of royalty reduction and credit incentive programs to encourage oil and gas exploration and development in Alberta, which include the following programs currently in effect:

•

The New Well Royalty Rate ("NWRR") creates incentives for new wells that commence production on or after April 1, 2009. Other wells may also qualify for the NWRR depending on the periods for which they were previously shut-in or producing prior to April 1, 2009. Eligible wells under the NWRR are subject to a flat royalty rate of 5% for the first 12 months of production to a maximum of 500 MMcf of natural gas or 50,000 bbls of oil. The NWRR was originally announced in March 2009 as a temporary measure but was made permanent (subject to the same 12-month time and specified volume limitations) on March 11, 2010.



•

The Deep Oil Exploration Program provides royalty relief of up to $1,000,000 or 12 months of production, whichever comes first, for qualifying deep exploration oil wells with a true vertical depth greater than 2,000 meters (6,562 feet) that spud on or after January 1, 2009. Wells drilled after December 31, 2013 will not qualify for relief under this program, and the relief will expire on December 31, 2018.



•

The Natural Gas Deep Drilling Program, as revised effective May 1, 2010, provides for a sliding scale production royalty credit for qualifying deep exploration and development gas wells with a true vertical depth greater than 2,000 meters (6,562 feet) that spud on or after May 1, 2010. The production credit is calculated according to the measured (drilled) depth to the bottom of the lowest producing interval of the qualifying wells and increases at certain trigger depths. The credit ranges from $625 per meter ($191 per foot) to a maximum of $3,000 per meter ($914 per foot) for a qualifying development well and $3,750 per meter ($1,143 per foot) for a qualifying exploration well. A minimum 5% royalty will apply to these gas wells.

        On May 27, 2010, the Government of Alberta announced a number of additional incentive programs for qualifying wells coming on production after May 1, 2010, as follows:

•

the Shale Gas New Well Royalty Rate, which extends the 5% NWRR on qualifying shale gas wells from 12 months to 36 months and removes the 500 MMcf volume limit;



•

the Coalbed Methane New Well Royalty Rate, which extends the 5% NWRR on qualifying coalbed methane wells from 12 months to 36 months and increases the 500 MMcf volume limit to 750 MMcf;



•

the Horizontal Gas New Well Royalty Rate, which extends the 5% NWRR on qualifying horizontal gas wells from 12 months to 18 months and maintains the 500 MMcf volume limit; and

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•

the Horizontal Oil New Well Royalty Rate, which extends the 5% NWRR on qualifying horizontal oil wells from 12 months to a minimum of 18 months and increases producing time and volume limits according to the measured depth of the well's qualifying interval to a maximum of 48 months or 100,000 bbls, respectively.

British Columbia

        After Alberta, the remainder of our current oil and gas production is from properties located in British Columbia.

        The British Columbia royalty regime for natural gas produced on Crown lands is price-sensitive and determined by a sliding scale formula based on a reference price, which is the greater of the producer price and a prescribed minimum price. The Government of British Columbia determines the producer price by averaging the actual selling prices for gas sales with shared characteristics for each company minus applicable costs. Natural gas in British Columbia is classified as either "conservation gas" or "non-conservation gas." There are three royalty categories applicable to non-conservation gas (not produced in association with oil), which are dependent on the date on which title was acquired from the Crown and the date on which the well was drilled. The royalty rate may also be impacted by the select price, a parameter in the royalty rate formula to account for inflation. The base royalty rate for non-conservation gas ranges from 9% to 15%. A lower base royalty rate of 8% is applied to conservation gas as an incentive to produce gas that might otherwise have been flared. The royalty rate may be reduced for low productivity wells.

        The British Columbia royalty regime for oil is dependent on the type and age of the oil and the quantity produced. Oil is classified as "old," "new" or "third tier" depending on the discovery date of the pool from which the oil is produced, and a different formula is used to determine the royalty rate depending on the classification. Royalty rates are further varied depending on production. Lower royalty rates apply to low productivity wells and third-tier oil (produced from pools discovered after June 1, 1998) to reflect the increased cost of exploration and extraction.

        As with the Government of Alberta, the Government of British Columbia has introduced a number of oil and natural gas royalty reduction and credit incentive programs to encourage oil and gas exploration and development in British Columbia. Currently included among these programs are the following:

•

The Summer Royalty Program provides a royalty credit of 10% of drilling and completion costs to a maximum of $100,000 per well for qualifying wells spud between April 1 and November 30 of each year.



•

The Deep Royalty Program and Deep Re-Entry Royalty Program provide royalty credits for qualifying deep vertical wells with a true vertical depth greater than 2,500 meters (8,202 feet) and horizontal wells with a true vertical depth greater than 1,900 meters (6,234 feet), which spud after August 31, 2009, and for deep re-entry wells with a true vertical depth greater than 2,300 meters (7,546 feet) and a re-entry date after December 31, 2003. The royalty credit is calculated according to the measured (drilled) depth of the qualifying well and associated drilling costs.



•

The Deep Discovery Royalty Program provides for a three-year royalty holiday or 283,000,000 m3 (10,000 MMcf) of royalty-free gas production, whichever comes first, for qualifying deep discovery wells with a true vertical depth greater than 4,000 meters (13,123 feet) that have finished drilling after November 2003 and whose surface locations are at least 20 kilometers (12.4 miles) away from the surface location of any well in a recognized pool of the same formation.



•

The Coalbed Gas Royalty Program provides a royalty reduction for coalbed gas wells with average daily production less than 17,000 m3 (0.6 MMcf), as well as a royalty credit for coalbed

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gas wells equal to $50,000 for wells drilled on Crown land and a tax credit equal to $30,000 for coalbed gas wells drilled on freehold land.

•

The Marginal Royalty Program provides a royalty reduction for low productivity natural gas wells with an average production rate of under 25,000 m3/d (0.88 MMcf/d) during the first 12 months of production and an average daily production rate of less than 23 m3/d (0.80 Mcf/d) for every 1 meter (3.28 feet) of depth to the applicable zone.



•

The Ultra-Marginal Royalty Program provides additional royalty breaks for low productivity, shallow natural gas wells with a true vertical depth of less than 2,300 meters (7,546 feet) if horizontal or less than 2,500 meters (8,202 feet) if vertical, an average production volume of under 60,000 m3/d (2,130 Mcf/d) during the first 12 months of production and an average daily production rate of less than 11.5 m3/d (0.4 Mcf/d) for development wells or 17 m3/d (0.6 Mcf/d) for exploratory wildcat wells, for every 1 meter (3.28 feet) of depth to the applicable zone.



•

The Net Profit Royalty Program targets the development and commercialization of technically complex resources in British Columbia, such as coalbed gas, tight gas, shale gas, enhanced oil recovery or resources that are remote from existing infrastructure, and provides for a reduction in initial royalty rates while a producer is recovering capital costs in exchange for higher royalty rates once these costs have been recovered. The program allows for the calculation of royalties based on the net profits of a particular project.



•

The Infrastructure Royalty Credit Program provides royalty credits for up to 50% of the cost of certain approved road construction or pipeline infrastructure projects.

Quebec

        Although oil and gas exploration and development in Quebec is subject to regulation under various laws and regulations, there is not yet a legislative and regulatory regime in Quebec that is specific to the oil and gas industry. Royalties are currently set pursuant to regulation made under the province's mining laws, which prescribe that royalty rates of 5% to 12.5% for crude oil and 10% to 12.5% for natural gas apply, depending on the quantity produced.

        The Government of Quebec, which had been expected to introduce new oil and gas legislation sometime in the spring of 2011, has postponed the adoption of new rules for shale gas exploration and development pending completion of the SEA announced on March 8, 2011. See "—Environmental Regulation" below. It is unclear whether any portions of the new legislation will be introduced before completion of the SEA, which is currently expected to take 18 to 30 months to complete. The first SEA committee report is due in May 2012.

        The Government of Quebec also announced on March 17, 2011, a proposal to introduce a new shale gas royalty regime that would come into effect once the SEA has been completed and the legal and regulatory framework has been adapted to its conclusions. The details of this proposal are summarized in "A Fair and Competitive Royalty System for Responsible Shale Gas Production," which was presented as part of the 2011-2012 budget proposal.

        The proposal includes the following measures:

•

The new royalty regime proposes a progressive royalty rate, calculated on a per well basis, ranging from 5% to 35% for shale gas. The applicable rate will be determined according to a formula that is based on the price of natural gas (with the price component expected to take into account market price, transportation cost, processing cost and other items, with terms and conditions still to be specified) and the well's productivity (with the production component expected to be based on average daily production volume for a given month).

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•

The current provincial 15% tax credit for resources will be eliminated with respect to shale gas exploration and replaced by a non-refundable royalty credit for exploration, the exact terms and conditions of which will be announced at a later date but are expected to apply to an individual well and generally provide for a royalty credit of up to 15% of eligible exploration expenses, subject to a minimum royalty rate of 5% and an ability to carry forward any unused portion of the credit to a subsequent year for the same well.



•

Businesses that have completed wells before introduction of the new system will be able to continue operating under the current royalty regime throughout the production life of those wells, even after the new royalty regime takes effect.



•

The government will also introduce a gas development program, the stated objective of which is to encourage exploration by allowing businesses to pay lower royalties in the initial development and commercialization stages of authorized projects in exchange for progressively higher royalties once they have recouped their investments. The program would provide for a minimum royalty of 2% of gross revenue starting at the time that a well is brought into production until eligible investment and operating costs plus interest have been recouped (subject to a maximum of ten years of rate relief), and increased rates thereafter. After eligible investment and operating costs plus interest have been recouped or ten years, whichever comes first, royalty rates would increase to the higher of 5% of gross revenue and (1) 15% of net revenue, until the business has achieved a 25% rate of return plus interest on its initial investment, (2) 20% of net revenue, until the business has achieved a 100% rate of return plus interest on its initial investment and (3) 25% of net revenue after the business has achieved a 100% rate of return plus interest on its initial investment.



•

During the transition period leading to introduction of the new royalty regime, businesses will have the option of continuing under the current royalty system or participating in the new gas development program. Businesses participating in the SEA will also be allowed to make their wells subject retroactively to the gas development program.



•

In addition to royalty-related measures, the government announced that municipalities will be compensated for quantifiable additional costs attributable to shale gas exploration and production and would also receive $100,000 for each shale gas well operated on its territory, to be paid over a ten-year period, in each case to be financed by industry in a manner yet to be determined.

Northwest Territories

        Royalties payable on production from Crown land in the Northwest Territories are reserved to the Canadian federal government and are payable once production from project lands has commenced (being the time at which the petroleum products become marketable). Royalties are not payable during the pre-production period when activities such as exploration, testing and drilling are being conducted.

        Crown royalty rates are calculated with reference to whether payout (being the point at which the cumulative adjusted gross revenue from the property exceeds adjusted cumulative costs) has been reached. Prior to payout, royalties are payable on a graduated monthly basis. For the first 18 months of production, the royalty rate is 1% of gross revenues, increasing to 2% of gross revenues from the 19^th to the 36^th month after production has commenced, to 3% of gross revenues from the 37^th to the 54^th month, to 4% of gross revenues from the 55^th to the 72^nd month and to 5% of gross revenues from the 73^rd month until payout is achieved. Once payout is achieved, the monthly royalty is fixed at the greater of 30% of net revenues and 5% of the gross revenues of the project.

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Land Tenure

        The majority of oil and natural gas resources located in the provinces of Alberta, British Columbia and Quebec and in the Northwest Territories are owned by the respective provincial governments and, in the case of the Northwest Territories, the Canadian federal government. Rights are granted to energy companies to explore for and produce oil and natural gas pursuant to leases, licenses and permits and regulations as issued by the applicable governments. Lease terms vary in length from two years and longer. Other terms and conditions to maintain a mineral lease are set forth in the relevant legislation or are negotiated.

        Jurisdictions in Canada, including the provinces of Alberta and British Columbia, have legislation in place for mineral rights reversion to the Crown of both shallow and deep formations that cannot be shown to be capable of production at the end of their primary lease term. Such legislation may also include mechanisms available to energy companies to "continue" lease terms for non-productive lands, having met certain criteria as laid out in the relevant legislation.

Environmental Regulation

        As an operator of oil and gas properties in Canada, we are subject to stringent federal, provincial, territorial and local laws and regulations relating to environmental protection, as well as controlling the manner in which various substances, including wastes, generated in connection with oil and gas exploration, production and transportation operations, are released into the environment. 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 abandonment 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 capital or increased operating costs to comply with governmental standards 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 natural gas. Although we utilize and have utilized standard industry operating and disposal practices, 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 and 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 plugging or pit closure or other actions of a remedial nature to prevent future contamination.

        We believe that it is reasonably 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 currently in effect and that continued compliance with existing requirements will not have a material adverse impact on us, we cannot give any assurance with respect to the effect on us of future legislative or regulatory initiatives or changes or that we will not be adversely affected in the future by new requirements, whether as a result of the direct or indirect costs of compliance or restrictions on the extent to which exploration and development may be allowed. Examples of such initiatives or changes and new requirements have occurred in Quebec and British Columbia with respect to shale gas exploration and development. In Quebec, the government announced in March 2011 an 18- to 30-month SEA of shale gas activities in the province during which hydraulic fracturing will be allowed only if required for SEA purposes. The particulars of any further

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prohibitions, restrictions or other requirements, including their duration, transitional provisions and exceptions, if any, that may arise from the SEA are not yet known. In June 2011, Quebec enacted legislation that revokes previously issued exploration licenses for the St. Lawrence River upstream of Anticosti Island and the islands therein. In British Columbia, the government introduced mandatory public disclosure of hydraulic fracturing fluid ingredients as of January 1, 2012 and established an online registry providing public access to information on fractured well locations and hydraulic fracturing fluid ingredients. At a media briefing held in late February 2012 regarding current regulations governing hydraulic fracturing operations in Alberta, representatives of the province's principal oil and gas regulatory agency, the Energy Resources Conservation Board ("ERCB"), were reported to have advised that the ERCB expects to implement rules requiring public disclosure of hydraulic fracturing fluid ingredients before the end of 2012. We have established internal guidelines to be followed in order to comply with environmental laws and regulations in the jurisdictions in which we operate. 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.

Climate Change Regulation

Federal (Canada)

        Internationally, Canada is a signatory to the United Nations Framework Convention on Climate Change ("Framework Convention") and previously ratified the Kyoto Protocol established thereunder, which set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other greenhouse gases ("GHGs"). The first commitment period under the Kyoto Protocol is the five-year period from 2008 to 2012. In December 2011, however, the Canadian federal government announced that it would not agree to a second commitment period under the Kyoto Protocol after 2012. The federal government instead endorsed the Durban Platform, a broad agreement reached among the 194 countries that are party to the Framework Convention during a conference held in Durban, South Africa in December 2011. The Durban Platform sets forth a process for negotiating a new climate change treaty that would create binding commitments for all major GHG emitters. The Canadian government expressed cautious optimism that agreement on a new treaty can be reached by 2015. The Durban Platform followed the Copenhagen Accord reached in December 2009 as the parties to the Kyoto Protocol met in Copenhagen, Denmark to negotiate a successor. Although no binding agreement was reached, several countries, including Canada and the United States, committed to the Copenhagen Accord, which represents a broad political consensus and reinforces commitments to reducing GHG emissions but is not a legally binding international treaty. Canada has committed under the Copenhagen Accord to reduce its GHG emissions by 17% from 2005 levels by 2020, which is consistent with the commitment of the United States, but the target is not legally binding. The impact of Canada's withdrawal from the Kyoto Protocol on prior GHG emission reduction initiatives is uncertain.

        Domestically, the Canadian federal government released in 2007 its Regulatory Framework for Air Emissions, which was updated in March 2008 in a document entitled "Turning the Corner: Regulatory Framework for Industrial Greenhouse Emissions" that set out a GHG emission reduction target of 20% from 2006 levels by 2020. On January 30, 2010, the Canadian federal government announced a new GHG emission reduction target, consistent with its commitment under the Copenhagen Accord, to reduce GHG emissions by 17% from 2005 levels by 2020. Canada's regulatory framework proposes mandatory reduction obligations on GHG emissions intensity (i.e., the quantity of GHG emissions per unit of production) on a sector-by-sector basis. Although implementing regulations are required, to date only regulations for Canada's transportation and electricity sectors have been developed. In 2009, the

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Canadian federal government announced its commitment to work with the provincial governments to implement a North America-wide cap and trade system for GHG emissions, in cooperation with the United States, under which Canada would have its own cap-and-trade market for Canadian-specific industrial sectors that could be integrated into a North American market for carbon permits. The Canadian federal government currently proposes to enter into equivalency agreements with provinces to establish a consistent regulatory regime for GHGs, but the success of any such plan is uncertain, possibly leaving overlapping levels of regulation. It is uncertain whether or when either Canadian federal GHG regulations for the oil and gas industry or an integrated North American cap-and-trade system will be implemented, what obligations might be imposed under any such systems or how they may ultimately affect our operations and financial results.

Alberta

        Alberta introduced the Climate Change and Emissions Management Act, which provides a framework for managing GHG emissions by reducing specified gas emissions, relative to gross domestic product, to an amount that is equal to or less than 50% of 1990 levels by December 31, 2020. The accompanying regulation, the Specified Gas Emitters Regulation ("SGER"), effective July 1, 2007, applies to facilities in Alberta that have produced 100,000 or more tonnes of GHG emissions in 2003 or any subsequent year and requires reductions in GHG emissions intensity from emissions intensity baselines that are established in accordance with the SGER. The SGER distinguishes between "established" facilities that completed their first year of commercial operation before January 1, 2000 or have completed eight years of commercial operation, and "new" facilities that completed their first year of commercial operation on December 31, 2000 or a subsequent year and have completed less than eight years of commercial operation. Generally, the baseline for an established facility reflects the average of emissions intensity in 2003, 2004 and 2005, and for a new facility emissions intensity in the third year of commercial operation. For an established facility, the required reduction in GHG emissions intensity is 12% per year from its baseline, and such reduction must be maintained over time. For a new facility, the required reduction from its baseline is phased in by annual 2% increments beginning in the fourth year of commercial operation until the annual 12% reduction requirement is reached, and once reached, such 12% reduction must be maintained over time.

        There are three methods for operators of facilities that are subject to the SGER to comply with the annual emission intensity reduction requirements: improve emissions intensity at the facility; purchase emission performance or emission offset credits in the open market, which are generated from Alberta-based projects; and/or purchase "fund credits" by contributing to the Alberta Climate Change and Emissions Management Fund run by the Government of Alberta. Contribution costs to this fund have historically been $15 per tonne of carbon dioxide equivalent ("CO₂e") but are now set by provincial government order. Compliance reports for facilities subject to the SGER are due to Alberta Environment on March 31 annually.

        The Specified Gas Reporting Regulation imposes GHG emissions reporting requirements on facilities that have GHG emissions of 50,000 tonnes or more in a year. In addition, Alberta facilities must currently report emissions of industrial air pollutants and comply with obligations in permits and under other environmental regulations. Alberta announced in January 2008 a new climate change plan setting out a goal of achieving a 14% absolute reduction in GHG emissions below 2005 levels in the province by 2050. The direct and indirect costs of these regulations or any amendments thereto may adversely affect our operations and financial results.

British Columbia

        Pursuant to the Greenhouse Gas Reduction Targets Act, British Columbia has set a goal of reducing its GHG emissions to 33% below 2007 levels by 2020, with interim targets of 6% below 2007 levels by 2012 and 18% below 2007 levels by 2016. The provincial government is required under that

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legislation to report every second year on the amount of reductions achieved in the province. In June 2008, British Columbia released its Climate Action Plan, which outlines a number of strategies and initiatives to take British Columbia approximately 73% towards meeting the goal of reducing GHG emissions by 33% below 2007 levels by 2020. The province has also enacted framework legislation providing for a provincial cap and trade system and has imposed GHG emissions reporting requirements under the Greenhouse Gas Reduction (Cap and Trade) Act and the Reporting Regulation. Additionally, British Columbia has implemented a carbon tax on the purchase or use of fossil fuels within the province, starting at $10 per tonne of CO₂e emissions from the combustion of each fuel commencing on July 1, 2008 and rising by $5 per year to $30 per tonne in 2012. Requirements that may be imposed in British Columbia may have adverse operational or financial consequences for our business.

Quebec

        Quebec recently indicated that, following a consultation period that ended in late February 2012, it is nearing completion of a 2013-2020 Climate Change Action Plan that will include measures for reducing GHG emissions, with a previously-announced GHG emission reduction target of 20% below 1990 levels by 2020. The new plan is to build on the current 2006-2012 Climate Change Action Plan, which called for governmental actions to reduce GHG emissions to 6% below 1990 levels by 2012 and included fuel oil energy efficiency measures, measures to encourage cleaner energy alternatives and tightened fuel oil sulphur level standards but no enforceable GHG emission reduction targets. Pursuant to regulation under the Environmental Quality Act, Quebec is implementing a cap-and-trade system for GHG emission allowances with the initial compliance period to commence January 1, 2013 for certain operators with annual GHG emissions of 25,000 tonnes or more of CO²e. Prior to implementation of the initial capping and reduction requirements, emitters and participants will be able to take part in pilot auctions and trade GHG emission allowances. Quebec has also enacted a carbon tax on the consumption of fossil fuels in the province. The effect of Quebec's cap-and-trade system and other measures undertaken in furtherance of its Climate Change Action Plan on the oil and gas industry is uncertain at this time, and such actions may have adverse operational or financial consequences for our business.

Northwest Territories

        In August 2011, the Government of the Northwest Territories released "A Greenhouse Gas Strategy for the NWT 2011-2015," which targets to stabilize GHG emissions at 2005 levels by 2015, to limit GHG emission increases to 66% above 2005 levels by 2020 and to return GHG emissions to 2005 levels by 2030. The effect of any implementation of this policy on oil and gas operations is not clear, and governmental action taken to fulfill it could adversely affect our operations and financial results.

Title to Properties

        Title to our oil and gas properties may be subject to royalty, overriding royalty, carried, net profits, working and similar interests customary in the oil and gas industry. Under the terms of the credit agreement governing our bank credit facility, LPR Canada granted the lenders a lien on substantially all 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. Our 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 for our account.

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Employees

        As of December 31, 2011, we had 71 employees. None of our employees is currently represented by a union for collective bargaining purposes. We consider our relations with our employees to be satisfactory. From time to time, we utilize the services of independent contractors to perform various field and other services.

Offices

        As of December 31, 2011, we leased approximately 43,495 square feet of office space in Calgary, Alberta at 640-5^th Avenue SW, where our principal offices are located. The lease for our Calgary office expires February 1, 2022. We also lease or own field offices in the areas in which we conduct our operations.

Internet Web Site and Availability of Public Filings

        Our internet address is www.lonepineresources.com. We file and furnish Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and amendments to these reports, with the SEC, which are available free of charge through our website as soon as reasonably practicable after such reports are filed with or furnished to the SEC.

        Materials we file with the SEC may be read and copied at the SEC's Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding our company that we file with and furnish electronically to the SEC.

        We may from time to time provide important disclosures to investors by posting them in the investor relations section of our website, as allowed by SEC rules. Information on our internet website is not incorporated by reference into this Form 10-K, and you should not consider information on our website as part of this Form 10-K.

Glossary of Oil and Gas Terms

        The terms defined in this section are used throughout this Form 10-K. 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. The entire definitions of those terms can be viewed on the website of the SEC at http://www.sec.gov.

        AECO.    The Alberta gas trading price.

        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 barrel 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.    Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

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        Developed acreage.    The number of acres that are allocated or 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.

        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 or a service 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.

        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.

        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, a common energy measurement.

        MMcf.    Million cubic feet of natural gas.

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

        MMcfe/d.    MMcfe per day.

        NGL.    Natural gas liquids.

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

        Net production.    The working interest production less the amount of production attributable to royalty burdens.

        NYMEX.    New York Mercantile Exchange.

        Productive wells.    Producing wells and wells that are capable of production, including injection wells, salt water disposal wells, service wells and wells that are shut-in.

        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 that are 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.

        Proved undeveloped reserves.    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 recovery to occur.

        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 of discounted future net cash flows.    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 rules and 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.

        Working interest production.    The working interest share of production before the impact of royalty burdens.

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Item 1A.    Risk Factors.

        We are subject to certain risks and hazards due to the nature of the business activities we conduct, including the risks discussed below. 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. If any of the following risks actually occurs, our business, financial condition, cash flows and results of operations could suffer materially and adversely, and our ability to implement business plans or complete development activities as scheduled could be impaired. In that case, the market price of the Company's common stock could decline.

Risks Related to Our Business

Oil, natural gas and NGL prices and related differentials are volatile. Declines in commodity prices have adversely affected our business, financial condition, cash flows, results of operations and ability to grow and in the future may adversely affect our business, financial condition, cash flows, results of operations, access to the capital markets and ability to grow.

        Our financial condition, operating results and future rate of growth depend upon the prices that we receive for our oil, natural gas and NGLs. Prices also affect our cash flow available for capital expenditures and our ability to access funds under our bank credit facility and through the capital markets. The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in oil, natural gas and NGL prices may adversely impact the value of our estimated proved reserves and, in turn, the bank pricing used by our lenders to determine our borrowing base. See Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facility" for more details. Further, because we have elected to use the full cost accounting method, each quarter we must perform a "ceiling test" that is impacted by declining prices. Significant price declines could cause us to take one or more ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See "—Lower oil, natural gas and NGL 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."

        Further, the differentials between (1) the prices that we realize for our oil, natural gas and NGLs and (2) commonly used benchmark prices for each product, are volatile and will change over time.

        In addition, significant or extended price declines may also adversely affect the amount of oil, natural gas and NGLs that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

        The markets for oil, natural gas and NGLs have been volatile historically, and we expect them to remain volatile in the future. Oil and natural gas spot prices reached at or near historical highs in July 2008. Prices have declined since that time and may continue to fluctuate widely in the future. During the fourth quarter of 2011 and continuing into 2012, natural gas prices declined to ten year lows. As of March 20, 2012, the spot price for natural gas was US$2.32 per MMBtu for NYMEX Henry Hub and $1.89 per MMBtu for AECO, and the spot price for crude oil was US$105.61 per barrel for NYMEX

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West Texas Intermediate and $94.76 per barrel for Edmonton Light. The prices we receive for our oil, natural gas and NGLs depend upon factors beyond our control, including, among others:

•

domestic and global supplies, consumer demand for oil, natural gas and NGLs and market expectations regarding supply and demand;



•

domestic and worldwide economic conditions;



•

the impact of the U.S. dollar and the Canadian dollar exchange rate on oil, natural gas and NGL prices;



•

the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines, processing, gathering and other transportation facilities;



•

weather conditions;



•

political conditions, instability and armed conflicts in oil-producing and gas-producing regions;



•

actions by the Organization of Petroleum Exporting Countries directed at maintaining prices and production levels;



•

the price and availability of imports of oil, natural gas and NGLs;



•

the impact of energy conservation efforts and the price and availability of alternative fuels;



•

domestic and foreign governmental regulations and taxes; and



•

technological advances affecting energy consumption and supply.

        These factors make it very difficult to predict future commodity price movements with any certainty. We sell the majority of our oil, natural gas and NGL production at current spot prices rather than through fixed-price contracts. However, we enter into, and we intend in the future to enter into, additional derivative instruments to reduce our exposure to fluctuations in oil, natural gas and NGL prices. See "—Our use of hedging transactions could result in financial losses or reduce our income." Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Approximately 74% of our estimated proved reserves at December 31, 2011 were natural gas, and, as a result, our financial results will be more sensitive to fluctuations in natural gas prices.

We require substantial capital expenditures to conduct our operations, engage in acquisition activities and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to execute our operating strategy.

        We require substantial capital expenditures to conduct our exploration, development and production operations, engage in acquisition activities and replace our production. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the drilling of a vertical well, sometimes more than three times the cost. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores. We have established a capital budget for 2012 of approximately $200 million to $220 million, which includes approximately $165 million for our capital program in the Evi area in 2012. We plan to use cash flow from operating activities and borrowings under our bank credit facility to fund our capital expenditures in 2012. We also may engage in asset sale transactions to fund capital expenditures when market conditions permit us to complete transactions on terms we find acceptable.

        We intend to rely on cash flow from operating activities and borrowings under our bank credit facility as our primary sources of liquidity. There can be no assurance that such sources will be sufficient to fund our exploration, development and acquisition activities. Our ability to access the

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private or public equity capital markets or complete asset sales to fund such activities is subject to certain limitations related to our spin-off from Forest. If our revenues and cash flows decrease in the future as a result of a decline in commodity prices or a reduction in production levels, however, and we are unable to obtain additional equity or debt financing in the private or public capital markets or access alternative sources of funds, we may be required to reduce the level of our capital expenditures and may lack the capital necessary to replace our reserves or maintain our production levels.

        Our future revenues, cash flows and spending levels are subject to a number of factors, including commodity prices, the level of production from existing wells and our success in developing and producing new wells. Further, our ability to access funds under our bank credit facility is based on a borrowing base, which is subject to periodic redeterminations based on our estimated proved reserves and prices that will be determined by our lenders using the bank pricing prevailing at such time. If the prices for oil and natural gas decline, or if we have a downward revision in estimates of our proved reserves, our borrowing base may be reduced. See Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Credit Facility" for more details.

        Our ability to access the private and public equity and debt markets and complete future asset monetization transactions is also dependent upon oil, natural gas and NGL prices, in addition to a number of other factors, some of which are outside our control. These factors include, among others:

•

the value and performance of our equity securities;



•

domestic and global economic conditions; and



•

conditions in the domestic and global financial markets.

        In addition, in connection with the completion of our IPO, we entered into separation agreements with Forest to preserve the tax-free status of our spin-off from Forest. As a result, we are restricted in our ability to sell assets outside the ordinary course of business, to issue or sell our common stock or certain other securities (including securities convertible into our common stock but excluding certain compensation arrangements) or to enter into any other corporate transaction that would cause us to undergo either a 50% or greater change in the ownership of our voting stock or a 50% or greater change in the ownership (measured by value) of all classes of our stock. See "—Risks Related to Our Separation from Forest—The separation agreements may limit our ability to obtain additional financing or make acquisitions and may require us to pay significant tax liabilities."

        The credit crisis and related turmoil in the global financial markets have had an impact on our business and our financial condition, and we may face additional challenges if economic and financial market conditions worsen. The weakened economic conditions also may adversely affect the collectability of our trade receivables. For example, our accounts receivable are primarily from purchasers of our oil, natural gas and NGL production and other exploration and production companies that own working interests in the properties that we operate. This industry concentration could adversely impact our overall credit risk because our customers and working interest owners may be similarly affected by changes in economic and financial market conditions, commodity prices and other conditions. Further, a credit crisis and turmoil in the financial markets in the future could cause our commodity derivative instruments to be ineffective in the event a counterparty was unable to perform its obligations or sought bankruptcy protection.

        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 business, financial condition, cash flows and results of operations.

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Our substantial indebtedness could adversely affect our financial condition.

        We have a significant amount of indebtedness. As of December 31, 2011, our total long-term debt was $331 million, and we had unused commitments of approximately $92.4 million under our bank credit facility (after deducting $1.6 million of outstanding letters of credit). As of March 20, 2012, our total long-term debt was approximately $384 million, and we had unused commitments of approximately $188 million under our bank credit facility (after deducting $1.6 million of outstanding letters of credit).

        Subject to the limits contained in the indenture governing the Senior Notes and our other debt instruments, we may be able to incur substantial additional debt from time to time to finance working capital, capital expenditures, investments or acquisitions or for other purposes. If we do so, the risks related to our high level of debt could intensify. Specifically, our high level of debt could have important consequences, including the following:

•

making it more difficult for us to satisfy our obligations with respect to the Senior Notes and our other debt instruments;



•

limiting our ability to obtain additional financing to fund future working capital, capital expenditures, investments, acquisitions or other general corporate requirements;



•

requiring a substantial portion of our cash flows to be dedicated to debt service payments instead of other purposes, thereby reducing the amount of cash flows available for working capital, capital expenditures, investments, acquisitions and other general corporate purposes;



•

increasing our vulnerability to general adverse economic and industry conditions;



•

exposing us to the risk of increased interest rates as certain of our borrowings are at variable rates of interest;



•

limiting our flexibility in planning for and reacting to changes in the oil and gas industry;



•

placing us at a disadvantage compared to other, less leveraged competitors; and



•

increasing our cost of borrowing.

We may not be able to generate enough cash flow to meet our debt obligations.

        We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance and, as a result, our ability to generate cash flow from operating activities and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operating activities to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

•

selling assets;



•

reducing or delaying capital investments;



•

seeking to raise additional capital; or



•

refinancing or restructuring our debt.

        If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at

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that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the Senior Notes. If amounts outstanding under our bank credit facility or the Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

The indenture governing the Senior Notes and our bank credit facility contain substantial operating and financial restrictions that may restrict our business and financing activities and could have a material adverse effect on our business, financial condition, cash flows and results of operations.

        The indenture governing the Senior Notes and the credit agreement governing our bank credit facility contain, and any future indebtedness that we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

•

sell assets, including equity interests in our subsidiaries;



•

pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt;



•

make investments;



•

incur or guarantee additional indebtedness or issue preferred stock;



•

create or incur certain liens;



•

make certain acquisitions and investments;



•

redeem or prepay other debt;



•

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;



•

consolidate, merge or transfer all or substantially all of our assets;



•

engage in transactions with affiliates;



•

create unrestricted subsidiaries;



•

enter into sale and leaseback transactions; and



•

engage in certain business activities.

        In addition, the credit agreement governing our bank credit facility provides that we will not permit our ratio of total debt outstanding to consolidated EBITDA (as adjusted for non-cash charges) for a trailing 12-month period to be greater than 4.00 to 1.00.

        As a result of these covenants and restrictions, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs. Our ability to comply with these covenants and restrictions in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.

        The credit agreement governing our bank credit facility also limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion taking into account the estimated value of our oil and gas properties. Outstanding borrowings in excess of the borrowing base must be repaid. If we do not have sufficient funds on hand for repayment, we may be required to seek

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a waiver or amendment from our lenders, refinance our bank credit facility or sell assets, debt or common stock. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in an event of default under the credit agreement governing our bank credit facility.

        A failure to comply with the requirements of the credit agreement governing our bank credit facility or any future indebtedness could result in an event of default under the credit agreement governing our bank credit facility or our future indebtedness, which, if not cured or waived, could have a material adverse effect on our business, financial condition, cash flows and results of operations. If an event of default under the credit agreement governing our bank credit facility occurs and remains uncured, the lenders thereunder:

•

would not be required to lend any additional amounts to us;



•

could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;



•

may have the ability to require us to apply all of our available cash to repay these borrowings; or



•

may prevent us from making debt service payments under our other agreements.

        A payment default or an acceleration under the credit agreement governing our bank credit facility could result in an event of default and an acceleration under the indenture for the Senior Notes.

        If the indebtedness under the Senior Notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under the credit agreement governing our bank credit facility are secured by substantially all of our assets, and if we are unable to repay our outstanding indebtedness under our bank credit facility, the lenders could seek to foreclose on our assets. Please see Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

Our use of hedging transactions could result in financial losses or reduce our income.

        To reduce our exposure to fluctuations in oil, natural gas and NGL prices, we enter into derivative instruments (or hedging agreements) for a portion of our oil, natural gas and NGL production. We expect that our commodity hedging agreements will be limited in duration, usually for periods of two years or less; however, in conjunction with acquisitions, we may enter into or acquire hedges for longer periods. Our hedging transactions expose us to certain risks and financial losses, including, among others, the risk that:

•

we may be limited in receiving the full benefit of increases in oil, natural gas and NGL prices as a result of these transactions;



•

we may hedge too much or too little production, depending on how oil, natural gas and NGL prices fluctuate in the future;



•

there is a change to the expected differential between the underlying price and the actual price received; and



•

a counterparty to a hedging arrangement may default on its obligations to us.

        Our hedging transactions will impact our earnings in various ways. Due to the volatility of oil, natural gas and NGL prices, we may be required to recognize mark-to-market gains and losses on derivative instruments, as the estimated fair value of our commodity derivative instruments is subject to significant fluctuations from period to period. The amount of any actual gains or losses recognized will likely differ from our period-to-period estimates and will be a function of the actual price of the commodities on the settlement date of the derivative instrument. We expect that commodity prices will

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continue to fluctuate in the future, and, as a result, our periodic financial results will be subject to fluctuations related to our derivative instruments.

The implementation of financial reform legislation and regulations could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

        To reduce our exposure to fluctuations in oil, natural gas and NGL prices, we enter into additional derivative instruments (or hedging agreements) for a portion of our oil, natural gas and NGL production. Over-the-counter derivatives have been the subject of recent legislative and regulatory initiatives. In the United States, comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), was adopted in 2010. This legislation, among other things, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including businesses like ours, that participate in that market. The Dodd-Frank Act requires the U.S. Commodity Futures Trading Commission (the "CFTC") and the SEC to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions are exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. In Canada, securities regulatory authorities have since November 2010 published a series of consultation papers on over-the-counter derivatives regulation, which present high-level proposals and recommendations on derivatives market regulation that are similar, in certain respects, to matters provided for under the Dodd-Frank Act. New regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities, although the application of those provisions to us is uncertain at this time, and may also require the counterparties to our derivative instruments to spin-off some of their derivatives activities to a separate entity, which may not be as creditworthy as such counterparty. Such legislative and regulatory initiatives could significantly increase the cost of derivatives contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure any derivatives contracts and increase our exposure to less creditworthy counterparties. If we limit our use of derivatives as a result of any such legislative and regulatory initiatives, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGLs. Our revenues could, therefore, be adversely affected if a consequence of any new legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Lower oil, natural gas and NGL 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 gas operations. Under this method, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of proved oil and 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 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

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write-down would not impact cash flow from operating activities, but it would reduce our stockholders' equity. See Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies, Estimates, Judgments and Assumptions—Full Cost Method of Accounting" for further details.

        Investments in unproved properties, including capitalized interest costs, 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. If an impairment of unproved properties results in a reclassification to proved oil and gas properties, the amount by which the ceiling limit exceeds the net capitalized costs of proved oil and gas properties would be reduced.

        The risk that we will be required to write-down the carrying value of our oil and gas properties, our unproved properties or goodwill increases when oil, natural gas and NGL prices are low. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. For example, we recorded a non-cash ceiling test write-down of approximately $251.0 million in the first quarter of 2009. This write-down was reflected as a charge to net earnings. Additional ceiling test write-downs may be required if oil, natural gas and NGL prices decline further or the current decline in natural gas prices continues, 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. Based on the recent decline of natural gas prices, there is an increased risk that we may be required to record a non-cash ceiling test write-down in the future.

Our proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of our oil and natural gas reserves, and our revenue, profitability and cash flow, to be materially different from our estimates.

        Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.

        In connection with the preparation of our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

        Actual future production, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and net present value of our reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing commodity prices and other factors, many of which are beyond our control.

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You should not assume that the present value of future net revenues from our estimated proved reserves is the current market value of our estimated proved reserves. We are required to base the estimated discounted future net cash flows from our estimated proved reserves on 12-month average prices and costs as of the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

        We have based our estimated discounted future net revenues from our estimated proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

•

actual prices we receive for oil, natural gas and NGLs;



•

actual cost and timing of development and production expenditures;



•

the amount and timing of actual production; and



•

changes in governmental regulations or taxation.

        The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

        Actual future prices and costs may differ materially from those used in the present value estimates included in this Form 10-K.

Our failure to replace our reserves could result in a material decline in our reserves and production, which could have a material adverse effect on our business, financial condition, cash flows and results of operations.

        In general, our proved reserves decline when oil and natural gas is produced, unless we are able to conduct successful exploitation, exploration and development activities or acquire additional properties containing proved reserves, or both. Our future performance, therefore, is dependent upon our ability to find, develop and acquire additional oil and natural gas reserves that are economically recoverable. Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or may not be able to make the necessary capital investments if our cash provided by operating activities decline or external sources of capital become limited or unavailable. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. See "—We require substantial capital expenditures to conduct our operations, engage in acquisition activities and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to execute our operating strategy" for a discussion of the impact of financial market conditions on our access to financing.

Our actual production could differ materially from our forecasts.

        From time to time, we provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts assume that none of the risks associated with our oil and gas operations summarized in this Form 10-K occur, such as facility or equipment malfunctions, adverse weather effects or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.

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As part of our ongoing operations, we plan to explore in new or emerging plays. As a result, our drilling in these areas is subject to greater risk and uncertainty.

        We sometimes explore in new or emerging plays. These activities are more uncertain than drilling in areas that are developed and have established production. Because emerging plays and new formations have limited or no production history, we are less able to use past drilling results to help predict future results. The lack of historical information may result in our being unable to fully execute our expected drilling programs in these areas, or the return on investment in these areas may turn out to not be as attractive as anticipated. We cannot assure you that our future drilling activities in the Utica Shale in Quebec, the Liard Basin in the Northwest Territories or other emerging plays will be successful or, if successful, will achieve the potential resource levels that we currently anticipate based on the drilling activities that have been completed or will achieve the anticipated economic returns based on our current cost models.

Exploration and drilling activities involve substantial risks and may not result in commercially productive reserves.

        We do not always encounter commercially productive reservoirs through our drilling operations. The seismic data and other technologies that we use when drilling wells do not allow us to conclusively determine prior to drilling a well whether oil, natural gas or NGLs are present or can be produced economically. As a result, we may drill new wells or participate in new wells that are dry wells or are productive but not commercially productive, and, as a result, we may not recover all or any portion of our investment in the wells we drill or in which we participate.

        The costs and expenses of drilling, completing and operating wells are often uncertain. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling costs to be significantly higher than expected or cause our drilling activities to be unsuccessful or result in the total loss of our investment. Also, our development and exploration operations may be shortened, delayed or canceled or we may incur significant expenditures that are not provided for in our capital budget as a result of a variety of factors, many of which are beyond our control, including, among others:

•

unexpected drilling conditions;



•

geological irregularities or pressure in formations;



•

mechanical difficulties and equipment failures or accidents;



•

increases in the costs of, or shortages or delays in the availability of, drilling rigs and related equipment;



•

shortages in labor;



•

adverse weather conditions;



•

compliance with environmental and other governmental requirements;



•

fires, explosions, blow-outs or cratering; and



•

restricted access to land necessary for drilling or laying pipelines.

        Drilling activities are subject to many risks, including well blow-outs, cratering, explosions, pipe failures, fires, uncontrollable flows of oil, natural gas, brine or well fluids, other environmental hazards and risks outside of our control, including the factors described above and other risks associated with conducting drilling activities. Among other things, these risks include the risk of natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases and extensive abandonment, reclamation and remediation costs, any of which could result in substantial losses, personal injuries or loss of life, severe

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damage to or destruction of property, natural resources and equipment, extensive pollution or other environmental damage, clean-up responsibilities, regulatory investigations, administrative, civil and criminal penalties and injunctions resulting in the suspension of our operations. If any of these risks occur, we could sustain substantial losses.

Drilling locations that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.

        We describe drilling locations that are not proved undeveloped drilling locations, and our plans to explore those drilling locations in this Form 10-K. These non-proved drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively, prior to drilling, whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil, natural gas or NGLs exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our other identified drilling locations. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates. In summary, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

Our drilling locations are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the significant amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

        Our management has identified and scheduled drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. As of December 31, 2011, we had 151 gross (125 net) drilling locations with proved undeveloped reserves attributed to them. All of our drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGL prices, costs and drilling results. Because of these uncertainties, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas or NGLs from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. If natural gas prices remain depressed for an extended period of time, it might not be economic for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have a material adverse effect on our business, financial condition, cash flows and results of operation.

        Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, the leases for such acreage may expire. As of December 31, 2011, we had leases representing 64,211 net acres expiring in 2012, 10,127 net acres expiring in 2013 and 47,524 net acres expiring in 2014, representing 8%, 1% and 6% of our total net acreage, respectively.

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Competition within our industry is intense and may have a material adverse effect on our business, financial condition, cash flows and results of operations.

        We operate in a highly competitive environment. We compete with major and independent oil and gas companies in acquiring desirable oil and gas properties and in obtaining the equipment and labor required to develop and operate such properties. We also compete with major and independent oil and gas companies in the marketing and sale of oil, natural gas and NGLs. Many of these competitors are larger, including some of the fully integrated energy companies, and have financial, staff and other resources substantially greater than ours. As a result, these companies may have greater access to capital and may be able to pay more for development prospects and producing properties, or evaluate and bid for a greater number of properties and prospects, than our financial and staffing resources permit. Also, from time to time, we have to compete with financial investors in the property acquisition market, including private equity sponsors with more funds and access to additional liquidity. Factors that affect our ability to acquire properties include availability of desirable acquisition targets, staff and resources to identify and evaluate properties, available funds and internal standards for minimum projected return on investment. In addition, while costs for equipment, services and labor in the industry, as well as the cost of properties available for acquisition, tend to fluctuate with oil, natural gas and NGL prices, these costs often do not decrease proportionately to, or their decreases lag behind, decreases in commodity prices. This disconnect can negatively impact our cash flows and may put us at a competitive disadvantage with respect to companies that have greater financial and operational resources. In addition, oil and gas producers are increasingly facing competition from providers of non-fossil energy, and government policy may favor those competitors in the future. Many of these competitors have financial and other resources substantially greater than ours. We can give no assurance that we will be able to compete effectively in the future and that our business, financial condition, cash flows and results of operations will not suffer as a result.

Our business, financial condition, cash flows and results of operations may be adversely affected by foreign currency fluctuations and economic and political developments.

        Currently, all of our oil and gas properties and operations are located in Canada. As a result, we are exposed to the risks associated with operating as a foreign company in Canada, including political and economic developments, royalty and tax increases, changes in laws or policies affecting our exploration and development activities and currency exchange risks, as well as changes in the policies of Canada affecting trade, taxation, investment and the environment.

        Our operations are impacted by the regulatory requirements in the provinces and territories in which our operations are located, and our project economics are influenced by the differing royalty regimes in each of these locations. Any adverse regulatory developments relating to the royalty regimes applicable to our operations or the laws or policies affecting our exploration and development activities could have a material adverse effect on our business, financial condition, cash flows and results of operations. See "—Our oil and gas operations are subject to various environmental and other governmental laws and regulations that materially affect our operations" below and "—New laws or regulatory requirements relating to hydraulic fracturing could make it more difficult or costly for us to perform fracturing of producing formations and could have an adverse effect on our ability to produce oil and gas from new wells" below and "Business—Industry Regulation," "Business—Royalties," "Business—Land Tenure" and "Business—Environmental Regulation—Climate Change Regulation," in Part I, "Item I. Business" for more detail on the Canadian regulatory framework.

        Effective October 1, 2011, Lone Pine changed its functional currency and reporting currency from the U.S. dollar to the Canadian dollar. Following the changes in functional currency and reporting currency, we will be subject to foreign currency exchange rate risk relating to the Senior Notes, certain of our derivative instruments and our delivery commitment of approximately 21,000 MMBtu/d of natural gas under a long-term sales contract expiring in 2014.

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Our oil and gas operations are subject to various environmental and other governmental laws and regulations that materially affect our operations.

        Our oil and gas operations are subject to various Canadian federal, provincial, territorial and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions, and regulate, among other things, land tenure, the exploration and development of hydrocarbon resources and 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. Federal authorities do not regulate the price of oil and gas in export trade. However, Canadian law regulates the quantities of oil, natural gas and NGLs that may be removed from the provinces and exported from Canada in certain circumstances. Significant regulatory requirements also exist related to licensing for drilling and completion of wells, the method and ability to produce from wells, surface usage, transportation of production and conservation matters. In addition, the provinces and territories in which we operate have laws and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdiction. Compliance with these laws and regulations can affect the location or size of leases and facilities, prohibit or limit the extent to which exploration and development may be allowed and require proper abandonment of wells and restoration of properties when production ceases. Failure to comply with laws and regulations in effect from time to time may result in the assessment of administrative, civil or criminal penalties, imposition of remedial obligations, loss or cancellation of governmental or regulatory approvals and issuance of injunctions or similar orders that could delay, limit or prohibit certain of our operations, any of which could have a material adverse effect on our business, financial condition, cash flows and results of operations. We are subject to stringent rules concerning the release into the environment of substances in connection with drilling and production activities (including fracture stimulation operations), and a significant spill or other discharge from one of our facilities could have a material adverse effect on our business, financial condition, cash flows and results of operations. We cannot predict the ultimate cost of compliance with these requirements or their effect on our operations. We may not be able to recover some or any of these costs from insurance.

        Most oil and natural gas resources located in the Canadian provinces and territories in which we operate are owned by the government, and are explored for and produced pursuant to leases, licenses, permits and regulations issued by that government or its agencies. Any governmental action to unilaterally cancel, limit or otherwise adversely change any such lease, license, permit or regulation pursuant to which we explore for or produce oil or natural gas, which action could include termination of our property interests or other rights in affected lands, with or without compensation, could have a material adverse effect on our business, financial condition, cash flows and results of operations.

        Our operations are, and will continue to be, affected to varying degrees by laws and regulations regarding environmental protection, which may be changed to impose higher standards and potentially more costly obligations on us. Future environmental laws or regulations or approvals or processes required thereunder, the direct and indirect costs of complying with such laws, regulations, approvals or processes, and the consequences of any non-compliance, may adversely affect our business, financial condition, cash flows and results of operations. We believe that it is reasonably likely that the trend in environmental legislation and regulation will continue toward stricter standards. See Part I, "Item 1. Business—Environmental Regulation." Canadian federal, provincial and territorial governments are continuing to assess and develop GHG emission reduction strategies. The direct and indirect costs of complying with any GHG emission reduction requirements arising from the implementation of any such strategies or any related laws or regulations imposed either federally, provincially, territorially or locally may adversely affect our business, financial condition, cash flows and results of operations. See Part I, "Item 1. Business—Environmental Regulation—Climate Change Regulation."

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New laws or regulatory requirements relating to hydraulic fracturing could make it more difficult or costly for us to perform fracturing of producing formations and could have an adverse effect on our ability to produce oil and gas from new wells.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons. The process involves the injection of fluid, sand and chemicals under pressure into a hydrocarbon-bearing geological formation to fracture the surrounding rock and stimulate production. Some concern has been expressed over the potential environmental impact of hydraulic fracturing operations, including with respect to the qualitative and quantitative effect on water resources, as large quantities of water are used and injected fluids either remain underground or flow back to the surface to be collected, treated and disposed of. Governmental and regulatory authorities in certain jurisdictions have announced initiatives in response to such concerns. In Quebec, the provincial government, acting upon recommendations of BAPE, which had been requested to review environmental and health and safety issues concerning the development of the shale gas industry in Quebec in connection with the government's consideration of a new oil and gas regulatory regime for the province, has commissioned a SEA of shale gas drilling, pending which hydraulic fracturing will only be allowed if required for SEA purposes. A committee was appointed in May 2011 to conduct the SEA, which is expected to take 18 to 30 months to complete, and is to report annually, with the first report due in May 2012. On June 13, 2011, Quebec enacted legislation that prohibits oil and gas activities in the St. Lawrence River upstream of Anticosti Island and on the islands situated in that part of the river and revokes, without compensation, oil and gas rights previously issued for that area. We held exploration licenses to 33,460 net acres under the St. Lawrence River that were revoked by this legislation and are considering available alternatives with respect to the Quebec government's action. The revoked acreage consists entirely of undeveloped lands. No reserves are attributed to our Quebec properties. In British Columbia, public disclosure of hydraulic fracturing fluid ingredients became mandatory as of January 1, 2012, and the provincial government established an online registry providing public access to information on fractured well locations and hydraulic fracturing fluid ingredients. At a media briefing held in late February 2012 regarding current regulations governing hydraulic fracturing operations in Alberta, representatives of the ERCB were reported to have advised that the ERCB expects to implement rules requiring public disclosure of hydraulic fracturing fluid ingredients before the end of 2012. See Part I, "Item 1. Business—Environmental Regulation."

        Regulatory initiatives relating to hydraulic fracturing have also commenced or been announced in the United States, where some states have adopted or are considering the adoption of regulations that could restrict hydraulic fracturing in certain circumstances and require disclosure of chemicals used in the fracturing process, and the U.S. Environmental Protection Agency and a committee of the U.S. House of Representatives have both initiated reviews of hydraulic fracturing practices. If new laws or regulatory requirements that prohibit or otherwise significantly restrict hydraulic fracturing are adopted in any jurisdiction in which we operate, whether as a consequence of environmental concerns or otherwise, it may become more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, additional permitting, disclosure or other regulatory obligations may make it more difficult for us to complete oil and natural gas wells and cause permitting delays and potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of oil, natural gas and NGLs that we are ultimately able to produce from our reserves.

Aboriginal peoples have claimed aboriginal title and rights in portions of Canada.

        Aboriginal peoples have claimed aboriginal title and rights in portions of Canada. We are not aware that any claims have been made against us in respect of our properties and assets; however, if a claim arose and was successful, such claim may have a material adverse effect on our business, financial condition, cash flows and results of operations. Our operations may be delayed or interrupted to the extent that they are deemed to encroach on the traditional rights of aboriginal peoples to hunt, trap or

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otherwise have access to natural resources. For example, in 2010, we encountered certain infrastructure constraints in our Ojay field in British Columbia, due in part to a several-month delay in permitting required for gathering pipelines installed in the field, while an aboriginal people considered the installation's potential impact on their traditional land use. We may face similar delays and interruptions in the future.

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

        The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. Any significant change in market factors affecting these infrastructure facilities, as well as delays in the construction of new infrastructure facilities, could harm our business. We deliver a majority of our oil, natural gas and NGLs through gathering facilities and downstream infrastructure that we either do not own or do not 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. For example, we experienced shut-in production due to infrastructure constraints in our Ojay field in British Columbia in 2010, due in part to a several-month delay in permitting required for gathering pipelines recently installed in the field, while an aboriginal people considered the installation's potential impact on their traditional land use. If we experience interruptions or loss of pipelines or access to gathering systems that impact a substantial amount of our production, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.

We may not be insured against all of the operating risks to which our business is exposed.

        The exploration, development and production of oil, natural gas and NGLs involve operating risks. These risks include the risk of fire, explosions, blow-outs, pipe failure, damaged drilling and oil field equipment, abnormally pressured formations, weather-related issues and environmental hazards. Environmental hazards include oil spills, natural gas leaks, pipeline ruptures or discharges of toxic gases and extensive abandonment, reclamation and remediation costs. If any of these industry-operating risks occur, we could have substantial losses. 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. Consistent with industry practice, 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 adequate to fully cover our losses or liabilities. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase.

We have incurred, and will in the future incur, increased legal, accounting and other costs as a result of being a public company.

        Prior to our IPO, as a subsidiary of a public company, we were not directly responsible for the corporate governance and financial reporting practices, policies and disclosure required of a public company. As a public company, we have incurred, and will continue to incur in the future, significant legal, accounting and other expenses that we did not directly incur in the past. In addition, the Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act"), the Dodd-Frank Act and applicable Canadian securities laws, as well as new rules implemented by the SEC, Canadian securities regulators and the New York Stock Exchange (the "NYSE"), require or may require changes in corporate governance practices of public companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly. All of the

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foregoing may cause our costs to be higher than the historical costs associated with these areas reflected in our financial statements.

Our results as a separate, stand-alone public company could be materially different from those portrayed in our historical financial results.

        Certain of the historical financial information included in this Form 10-K has been derived from the consolidated financial statements of LPR Canada before it became a subsidiary of Lone Pine Resources Inc. The historical costs and expenses reflected in LPR Canada's consolidated financial statements for the periods prior to our IPO include a management fee intended to reimburse Forest for certain corporate functions provided by Forest on our behalf, including, among other things, executive oversight, insurance and risk management, treasury, information technology, legal, accounting, tax, marketing, corporate engineering and human resources services. The management fee was based on what Forest considered to be reasonable reflections of the historical utilization levels of these services required in support of our business. In addition, a portion of the interest costs reflected in LPR Canada's consolidated financial statements was associated with a note payable to and advances from Forest, which provided for interest rates that may not have been comparable with the rates we would have negotiated with a third party. Other significant changes may occur in our cost structure, management, financing and business operations as a result of operating as a separate, stand-alone public company. For additional information, see Part II, "Item 6. Selected Financial Data" and Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the consolidated financial statements and the notes thereto included elsewhere in this Form 10-K.

If we are unable to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, or our internal controls over financial reporting are not effective, the reliability of our financial statements may be questioned, and our share price may suffer.

        Section 404 of the Sarbanes-Oxley Act requires any company subject to the reporting requirements of the U.S. securities laws to perform a comprehensive evaluation of its and its subsidiaries' internal controls over financial reporting. Similar requirements apply to reporting issuers under Canadian securities laws. To comply with these requirements, we are required to document and test our internal control procedures, our management is required to assess and issue a report concerning our internal controls over financial reporting, and, under the Sarbanes-Oxley Act, our independent auditors are required to issue an opinion on management's assessment and the effectiveness of our internal controls over financial reporting. Our compliance with Section 404 of the Sarbanes-Oxley Act will first be reported on in connection with the filing of our Annual Report on Form 10-K for the fiscal year ending December 31, 2012. The rules governing the standards that must be met for management to assess our internal controls over financial reporting are complex and require significant documentation, testing and possible remediation. During the course of its testing, our management may identify material weaknesses or significant deficiencies, which may not be remedied in time to meet the deadline imposed by the SEC rules implementing Section 404. If our management cannot favorably assess the effectiveness of our internal controls over financial reporting, or our auditors identify material weaknesses in our internal controls, investor confidence in our financial results may weaken, and our share price may suffer.

Risks Related to Our Separation from Forest

Our separation agreements with Forest require us to assume the past, present and future liabilities related to our business and may be less favorable to us than if they had been negotiated with unaffiliated third parties.

        We entered into agreements with Forest related to the separation of our business operations from Forest, including a separation and distribution agreement, a tax sharing agreement, a transition services agreement, an employee matters agreement and a registration rights agreement. We negotiated our

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separation agreements with Forest as a wholly-owned subsidiary of Forest and entered into these agreements immediately prior to the completion of our IPO. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. Pursuant to these agreements, we have agreed to indemnify Forest for, among other matters, all past, present and future liabilities (other than tax liabilities, which will be governed by our tax sharing agreement with Forest) related to our business, and we have assumed these liabilities under the separation agreements. Such liabilities include unknown liabilities that could be significant. The allocation of liabilities between Forest and us may not reflect the allocation that would have been reached between two unaffiliated parties.

The separation agreements may limit our ability to obtain additional financing or make acquisitions and may require us to pay significant tax liabilities.

        We may engage, or desire to engage, in future financings or acquisitions. However, because the separation agreements are designed to preserve the tax-free status of the spin-off, we have agreed to certain restrictions in those agreements that may severely limit our ability to effect future financings or acquisitions. For a period of two years after the date of the spin-off, we have agreed to be subject to certain restrictions under which we will be permitted to take certain actions only if Forest consents to the taking of such action or if we obtain and provide to Forest a private letter ruling from the Internal Revenue Service ("IRS") and/or an opinion from a law firm or accounting firm, in either case acceptable to Forest in its sole discretion, to the effect that such action would not jeopardize the tax-free status of the contribution and the spin-off. Thus, for that two-year period, these covenants will restrict our ability to sell assets outside the ordinary course of business, to issue or sell our common stock or other securities (including securities convertible into our common stock but excluding certain compensation arrangements) or to enter into any other corporate transaction that would cause us to undergo either a 50% or greater change in the ownership of our voting stock or a 50% or greater change in the ownership (measured by value) of all classes of our stock. We are also required to indemnify Forest against certain tax-related liabilities incurred by Forest relating to the spin-off, to the extent caused by us. These liabilities include the substantial tax-related liability (calculated without regard to any net operating loss or other tax attribute of Forest) that would result if the spin-off failed to qualify as a tax-free transaction.

        Finally, we are required to indemnify Forest against any additional Canadian tax-related liabilities incurred by Forest with respect to the contribution to us of its ownership interests in, and certain indebtedness of, LPR Canada and the transactions completed in conjunction with such contribution. As a result of these transactions, Forest determined that it was required to pay Canadian taxes in an amount consistent with an opinion of Forest's outside tax advisor and paid such taxes. To the extent that the Canadian tax authorities disagree with Forest's determination of the amount of Canadian taxes due and attempt to assess and recover additional Canadian taxes from Forest, we will be required to indemnify, and if necessary reimburse, Forest with respect to such additional taxes, costs incurred in contesting such additional taxes and any penalties and interest associated with such additional taxes. We believe that our maximum monetary exposure relating to this indemnity is approximately $47 million, plus interest. The triggering of this indemnity could have a material adverse impact on our liquidity and our ability to execute our business plan.

We will not have complete control over our tax decisions that relate to periods prior to the spin-off and could be liable for income taxes owed by Forest.

        We or one or more of our U.S. subsidiaries may be included in the combined, consolidated or unitary tax returns of Forest or one or more of its subsidiaries for U.S. federal, state or local income tax purposes for periods prior to the spin-off. Under the tax sharing agreement, we generally will pay to, or receive from, Forest the amount of U.S. federal, state and local income taxes that we would be

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required to pay to, or entitled to receive from, the relevant taxing authorities if we and our U.S. subsidiaries filed combined, consolidated or unitary income tax returns and were not included in the combined, consolidated or unitary tax returns of Forest or its subsidiaries. In addition, by virtue of the tax sharing agreement, Forest will effectively control all of our U.S. tax decisions in connection with any combined, consolidated or unitary income tax returns in which we or any of our subsidiaries are included. The tax sharing agreement provides that Forest will have sole authority to respond to and conduct all tax proceedings (including tax audits) relating to us, to file all tax returns on our behalf and to determine the amount of our liability to, or entitlement to payment from, Forest in connection with any combined, consolidated or unitary income tax returns in which we (or any of our subsidiaries) are included. This arrangement may result in conflicts of interest between Forest and us. For example, under the tax sharing agreement, Forest will be able to choose to contest, compromise or settle any adjustment or deficiency proposed by the relevant taxing authority in a manner that may be beneficial to Forest and detrimental to us. Moreover, notwithstanding the tax sharing agreement, U.S. federal law provides that each member of a consolidated group is liable for the group's entire tax obligation. Thus, to the extent Forest or other members of the group fail to make any U.S. federal income tax payments required by law for periods during which we were a member of such group, we could be liable for the shortfall. Similar principles may apply for foreign, state or local income tax purposes where we file combined, consolidated or unitary returns with Forest or its subsidiaries for federal, foreign, state or local income tax purposes.

If there is a determination that the spin-off is taxable for U.S. federal income tax purposes because the facts, assumptions, representations or undertakings underlying the IRS private letter ruling or tax opinion are incorrect or for any other reason, then Forest and its shareholders could incur significant income tax liabilities, and we could incur significant liabilities.

        Our IPO and the spin-off were conditioned upon, among other things, Forest's receipt of a private letter ruling from the IRS, and/or an opinion of its outside tax advisor, in either case reasonably acceptable to the Forest board of directors, to the effect that the contribution by Forest of its direct and indirect ownership interest in LPR Canada to us and the distribution by Forest of the shares of our common stock held by Forest after the offering should qualify for U.S. federal income tax purposes as a tax-free transaction under Sections 355 and 368(a)(1)(D) of the U.S. Internal Revenue Code of 1986, as amended (the "Code"). Forest obtained an opinion of its outside tax advisor that was acceptable to the Forest board of directors to the effect that the contribution by Forest of its direct and indirect ownership interest in LPR Canada to us and the distribution by Forest of the shares of our common stock held by Forest after our IPO should qualify for U.S. federal income tax purposes as a tax-free transaction under Sections 355 and 368(a)(1)(D) of the Code, which opinion satisfied the related condition to our IPO and the spin-off. Forest also received a private letter ruling from the IRS. The opinion and the ruling rely on certain facts, assumptions, representations and undertakings from Forest and us regarding the past and future conduct of the companies' respective businesses and other matters. If any of these facts, assumptions, representations or undertakings are incorrect or not otherwise satisfied, Forest and its shareholders may not be able to rely on the private letter ruling or the opinion of its tax advisor and could be subject to significant tax liabilities. Notwithstanding the private letter ruling or the opinion of Forest's tax advisor, the IRS could determine upon audit that the spin-off is taxable if it determines that any of these facts, assumptions, representations or undertakings are not correct or have been violated or if it disagrees with the conclusions in the opinion that are not covered by the private letter ruling, or for other reasons, including as a result of certain significant changes in the stock ownership of Forest or us after the spin-off. If the spin-off is determined to be taxable for U.S. federal income tax purposes, Forest and its shareholders could incur significant income tax liabilities, and we could incur significant liabilities.

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Third parties may seek to hold us responsible for liabilities of Forest that we did not assume in our agreements.

        Third parties may seek to hold us responsible for retained liabilities of Forest. Under the separation agreements, Forest has agreed to indemnify us for claims and losses relating to these retained liabilities. However, if those liabilities are significant and we are ultimately held liable for them, we cannot assure you that we will be able to recover the full amount of our losses from Forest.

Our prior relationship with Forest exposes us to risks attributable to businesses of Forest.

        Forest is obligated to indemnify us for losses that a party may seek to impose upon us or our affiliates for liabilities relating to the business of Forest that are incurred through a breach of the separation agreements or any ancillary agreement by Forest or its affiliates other than us, if losses are attributable to Forest in connection with our IPO or were not expressly assumed by us under the separation agreements. Any claims made against us that are properly attributable to Forest in accordance with these arrangements would require us to exercise our rights under the separation agreements to obtain payment from Forest. We are exposed to the risk that, in these circumstances, Forest cannot, or will not, make the required payment.

We may have potential business conflicts of interest with Forest regarding our past and ongoing relationships, and the resolution of these conflicts may not be favorable to us.

        Conflicts of interest may arise between Forest and us in a number of areas relating to our past and ongoing relationships, including:

•

labor, tax, employee benefit, indemnification and other matters arising under the separation agreements;



•

employee recruiting and retention; and



•

business opportunities that may be attractive to both Forest and us.

        We may not be able to resolve any potential conflicts, and, even if we do so, the resolution may not be favorable to us.

        For two years after the completion of our IPO, (1) Forest has agreed not to acquire any oil and gas properties in Canada, unless such oil and gas properties in Canada constitute less than a majority of the assets included in a particular business opportunity, and (2) we have agreed not to acquire any oil and gas properties in the United States, unless such oil and gas properties in the United States constitute less than a majority of the assets included in a particular business opportunity. However, during this two-year period, if Forest obtains our prior consent with respect to a defined area in Canada, it may engage in activities in that area, and, similarly, if we obtain Forest's prior consent with respect to a defined area in the United States, we may engage in activities in that area.

        For two years after the completion of our IPO, neither we nor Forest will be permitted to solicit each other's active employees for employment without the other's consent.

Pursuant to the terms of our certificate of incorporation, Forest is not required to offer corporate opportunities to us, and one of our directors is permitted to offer certain corporate opportunities to Forest before us.

        Our certificate of incorporation provides that, until both (1) Forest and its subsidiaries no longer beneficially own 50% or more of the voting power of all then outstanding shares of our capital stock

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generally entitled to vote in the election of our directors and (2) no person who is a director or officer of Forest or of a subsidiary of Forest is also a director or officer of ours:

•

Forest is free to compete with us in any activity or line of business, except as provided in the separation and distribution agreement or other written agreement between us and Forest;



•

we do not have any interest or expectancy in any business opportunity, transaction or other matter in which Forest engages or seeks to engage merely because we engage in the same or similar lines of business;



•

to the fullest extent permitted by law, Forest will have no duty to communicate its knowledge of, or offer, any potential business opportunity, transaction or other matter to us, and Forest is free to pursue or acquire such business opportunity, transaction or other matter for itself or direct the business opportunity, transaction or other matter to its affiliates and Forest will not, to the fullest extent permitted by law, be deemed to have (1) breached or acted in a manner inconsistent with or opposed to its fiduciary or other duties to us regarding the business opportunity, transaction or other matter or (2) acted in bad faith or in a manner inconsistent with the best interests of our company or our stockholders; and



•

to the fullest extent permitted by law, if any director or officer of Forest who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that business opportunity to us and will be permitted to communicate or offer that business opportunity to Forest (or its affiliates), and that director or officer will not, to the fullest extent permitted by law, be deemed to have (1) breached or acted in a manner inconsistent with or opposed to his or her fiduciary or other duties to us regarding the business opportunity, transaction or other matter or (2) acted in bad faith or in a manner inconsistent with the best interests of our company or our stockholders.

        As a result of the Distribution, Forest has no remaining ownership interest in us; however, the chairman of our Board of Directors is also an independent director of Forest. As a result, Forest may gain the benefit of corporate opportunities that are presented to this director.

Risks Relating to Ownership of Our Common Stock

Your percentage ownership in us may be diluted by future issuances of common stock or securities or instruments that are convertible into our common stock, which could reduce your influence over matters on which stockholders vote.

        Our Board of Directors has the authority, without action or vote of our stockholders, to issue all or any part of our authorized but unissued shares of common stock, including shares issuable upon the exercise of options, shares that may be issued to satisfy our obligations under our incentive plans, shares of our authorized but unissued preferred stock and securities and instruments that are convertible into our common stock. Issuances of common stock or voting preferred stock would reduce your influence over matters on which our stockholders vote and, in the case of issuances of preferred stock, likely would result in your interest in us being subject to the prior rights of holders of that preferred stock.

We do not anticipate paying any dividends on our common stock in the foreseeable future. As a result, you will need to sell your shares of common stock to receive any income or realize a return on your investment.

        We do not anticipate paying any dividends on our common stock in the foreseeable future. Any declaration and payment of future dividends to holders of our common stock may be limited by the provisions of the Delaware General Corporation Law, certain restrictive covenants in our bank credit

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facility and certain restrictive covenants in the indenture governing the Senior Notes. The future payment of dividends will be at the sole discretion of our Board of Directors and will depend on many factors, including our earnings, capital requirements, financial condition and other considerations that our Board of Directors deems relevant. As a result, to receive any income or realize a return on your investment, you will need to sell your shares of common stock. You may not be able to sell your shares of common stock at or above the price you paid for them.

Our certificate of incorporation, bylaws, stockholder rights plan and Delaware state law contain provisions that may have the effect of delaying or preventing a change in control of our company.

        Our certificate of incorporation authorizes our Board of Directors to issue preferred stock and to determine the designations, powers, preferences and relative, participating, optional or other special rights, if any, and the qualifications, limitations or restrictions of our preferred stock, including the number of shares, in any series, without any further vote or action by the stockholders. The rights of the holders of our common stock will be subject to the rights of the holders of any preferred stock that may be issued in the future. The issuance of preferred stock could delay, deter or prevent a change in control and could adversely affect the voting power or economic value of your shares.

        In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•

a classified Board of Directors, so that only approximately one-third of our directors are elected each year;



•

limitations on the removal of directors;



•

limitations on the ability of our stockholders to call special meetings;



•

limitations on the ability of our stockholders to act by written consent in certain circumstances;



•

a separate vote of 75% of the voting power of the outstanding shares of capital stock in order for stockholders to amend the bylaws in certain circumstances; and



•

advance notice provisions for stockholder proposals and nominations for elections to our Board of Directors to be acted upon at meetings of stockholders.

        In addition, the rights agreement will impose a significant penalty on any person or group that acquires, or begins a tender or exchange offer that would result in such person acquiring, 20% or more of our outstanding common stock without approval from our Board of Directors.

        Although we believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics and thereby provide an opportunity to receive a higher bid by requiring potential acquirers to negotiate with our Board of Directors, these provisions apply even if the offer may be considered beneficial by some stockholders. Further, these provisions may discourage potential acquisition proposals and may delay, deter or prevent a change of control of our company, including through unsolicited transactions that some or all of our stockholders might consider to be desirable. As a result, efforts by our stockholders to change our direction or our management may be unsuccessful.

Item 1B.    Unresolved Staff Comments.

        None.

Item 2.    Properties.

        Information regarding our properties is contained in Part I, "Item 1. Business" and Part II, "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."

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Item 3.    Legal Proceedings.

        In March 2001, a predecessor of LPR Canada acquired interests in certain heavy oil assets in the Eyehill Creek area of Alberta from certain predecessors of Encana Corporation ("Encana"). In 2003, IFP Technologies (Canada) Inc. ("IFP") filed a statement of claim with the Court of Queen's Bench of Alberta (the "Court") against Encana and certain of its predecessors and affiliates and against certain predecessors of LPR Canada, claiming, among other things, damages in the amount of $45.6 million or, in the alternative, for an accounting of 20% of the revenues that the predecessors of LPR Canada have received from the acquired properties. At the outset of the trial, IFP amended its claim to increase the damages being sought to $56.7 million, plus interests and costs. The trial of this action occurred in the first quarter of 2011, and we are awaiting the judgment of the Court. Although we are unable to predict the final outcome of this case, we believe that the allegations of this lawsuit are without merit, and in any event are largely covered by the terms of an indemnity between the predecessors of Encana and the predecessors of LPR Canada. We have and intend to continue to vigorously defend the action.

        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.

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PART II

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

Market Information

        Our common stock is listed on the NYSE, our principal United States market, and on the Toronto Stock Exchange ("TSX"), our principal Canadian market, in each case under the symbol "LPR."

        The following table sets forth the range of high and low sales prices of our common stock as reported by the NYSE:

        The following table sets forth the range of high and low sales prices of our common stock as reported by the TSX:

        On March 20, 2012, the last sale price of our common stock, as reported on the NYSE and the TSX, was US$6.96 per share and $6.91 per share, respectively.

Holders

        The number of stockholders of record of our common stock was approximately 518 on March 20, 2012.

Dividends

        We have not paid any cash dividends on our common stock since our IPO. The future payment of cash dividends, if any, on our common stock is within the discretion of our Board of Directors and will depend on our earnings, capital requirements, financial condition and other relevant factors. We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain our future earnings for use in the operation and expansion of our business. Additionally, our bank credit facility and the indenture governing the Senior Notes restrict our ability to pay dividends. For information regarding restrictions on our payment of dividends, see note 9 to our consolidated financial statements.

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Equity Compensation Plans

        See Part III, "Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters," for information regarding our equity compensation plans as of December 31, 2011.

Repurchase of Equity Securities

        Neither we nor any "affiliated purchaser" repurchased any of our equity securities in the quarter ended December 31, 2011.

Stock Performance Graph

        The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended ("Exchange Act"), except to the extent that we specifically request that such information be treated as "soliciting material" or specifically incorporate such information by reference into such a filing.

        The performance graph shown below compares the cumulative total return to Lone Pine Resources Inc.'s common stockholders as compared to the cumulative total returns on the Standard and Poor's 500 Index ("S&P 500") and the Standard and Poor's 500 Oil & Gas Exploration & Production Index ("S&P 500 O&G E&P") since the time of our IPO. The comparison was prepared based upon the following assumptions:

•

$100 was invested in our common stock and invested in the S&P 500 and the S&P 500 O&G E&P on May 26, 2011 at the closing prices on such date; and



•

Dividends are reinvested.

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Item 6.    Selected Financial Data.

        The following table sets forth selected financial data of Lone Pine as of and for each of the years in the five-year period ended December 31, 2011.

        Our consolidated financial statements relating to the periods prior to our inception (September 30, 2010) reflect the financial position, results of operations, cash flows or other information, as the case may be, of our predecessor, LPR Canada. Our consolidated financial statements relating to the period from our inception through the completion of our IPO (June 1, 2011) reflect the financial position, results of operations, cash flows or other information, as the case may be, of Lone Pine and its predecessor, LPR Canada, on a combined basis. Our consolidated financial statements relating to the period subsequent to and including June 1, 2011 reflects the financial position, results of operations, cash flows or other information, as the case may be, of Lone Pine and its consolidated subsidiaries.

        Our consolidated financial statements as of and for each of the years in the four-year period ended December 31, 2010 were reported using the U.S. dollar. Effective October 1, 2011, Lone Pine changed its reporting currency to the Canadian dollar. With the change in reporting currency, all comparative financial information has been recast from U.S. dollars to Canadian dollars to reflect our consolidated financial statements as if they had been historically reported in Canadian dollars, consistent with ASC 830, Foreign Currency Matters. The consolidated U.S. dollar balance sheet information was translated into the Canadian dollar reporting currency by translating assets and liabilities at the end-of-period exchange rate and translating equity balances at historical exchange rates. The consolidated statement of operations information was translated into Canadian dollars using the weighted average exchange rate for the period. The resulting foreign currency translation adjustment is reported as a component of other comprehensive income and accumulated other comprehensive income.

        The Company changed the functional currency of Lone Pine Resources Inc. prospectively from October 1, 2011 from the U.S. dollar to the Canadian dollar. The change in functional currency did not have a significant impact on our consolidated financial statements for the year ended December 31, 2011 as Lone Pine's operations are primarily carried out by its operating subsidiary, LPR Canada. The functional currency of LPR Canada has not changed and continues to be the Canadian dollar. As a result of this change in functional currency, there is no difference between the reporting currency and the functional currency of Lone Pine and any of its subsidiaries.

        For a detailed discussion of the selected financial data contained in the following table, refer to Part II, "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 8—Financial Statements and Supplementary Data."

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

        You should read the following discussion and analysis of our financial condition and results of operations in conjunction with the consolidated financial statements and the related notes contained elsewhere in this Form 10-K. 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 under "Cautionary Note Regarding Forward-Looking Statements." Our actual results may differ materially because of a number of risks and uncertainties. See Part I, "Item 1A. Risk Factors" for additional information regarding known material risks.

        Unless the context otherwise requires, all operating data presented in this Form 10-K on a per unit basis is calculated based on net sales volumes, all references to "dollars," "$" or "Cdn$" in this Form 10-K are to Canadian dollars, and all references to "U.S. dollars" or "US$" are to United States dollars.

Overview

        We are an independent oil and gas exploration, development and production company with operations in Canada. Our reserves, producing properties and exploration prospects are located in the provinces of Alberta, British Columbia and Quebec and the Northwest Territories. We were incorporated under the laws of the State of Delaware on September 30, 2010, and prior to our IPO on June 1, 2011, we were a wholly-owned subsidiary of Forest. Our predecessor, LPR Canada, was acquired by Forest in 1996 and transferred to us prior to completion of our IPO. Upon completion of our IPO, Forest retained the controlling interest in us, owning 82% of the outstanding shares of our common stock. On September 30, 2011, Forest distributed all of the outstanding shares of our common stock that it owned to its shareholders. As a result of the Distribution, Forest has no remaining ownership interest in us.

        DeGolyer and MacNaughton, our independent reserves engineers, estimated our proved reserves to be approximately 401 Bcfe as of December 31, 2011, of which approximately 26% was oil and natural gas liquids, approximately 74% was natural gas and approximately 53% was classified as proved developed reserves. As of December 31, 2011, we had approximately 151 gross (125 net) proved undeveloped drilling locations and approximately 1.1 million gross (0.8 million net) acres of land (approximately 79% of which was undeveloped).

        Financial and other information disclosed herein relating to the time prior to our inception (September 30, 2010) reflects the financial position, results of operations, cash flows or other information, as the case may be, of our predecessor, LPR Canada. Financial and other information disclosed relating to the period from our inception through the completion of our IPO (June 1, 2011) reflects the financial position, results of operations, cash flows or other information, as the case may be, of Lone Pine and its predecessor, LPR Canada, on a combined basis. Financial and other information disclosed relating to the period subsequent to and including June 1, 2011 reflects the financial position, results of operations, cash flows or other information, as the case may be, of Lone Pine and its consolidated subsidiaries.

Change in Functional Currency and Reporting Currency

        Effective October 1, 2011, Lone Pine changed its functional currency and reporting currency from the U.S. dollar to the Canadian dollar. The change in functional currency did not have a significant impact on our consolidated financial statements for either the fourth quarter of 2011 or the year ended December 31, 2011 as Lone Pine's operations are primarily carried out by its operating subsidiary, LPR Canada. The functional currency of LPR Canada has not changed and continues to be the Canadian dollar.

        Prior to the Distribution, Lone Pine used the same reporting currency as Forest, which was the U.S. dollar, in its consolidated financial statements. However, after the Distribution, our management determined that our financial statements should be presented using the Canadian dollar, in order to

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present Lone Pine's financial statements in the same currency as its functional currency, and to minimize the impact of changes in foreign currency exchange rates on our financial statements. The determination to change Lone Pine's reporting currency was based on a number of factors, which included the following: (1) Lone Pine has no assets or operations in the United States, (2) substantially all of Lone Pine's operations are conducted in a single functional currency, the Canadian dollar, and (3) the reporting currency selected, the Canadian dollar, is the same as the functional currency.

        Prior to the change in reporting currency, our consolidated statements of operations were translated from Canadian dollars using the weighted average exchange rate for the period. The resulting foreign currency translation adjustment was reported as a component of other comprehensive income and accumulated other comprehensive income. As a result of our change in reporting currency, all comparative financial information has been recast from U.S. dollars to Canadian dollars to reflect our consolidated financial statements as if they had been historically reported in Canadian dollars, consistent with ASC 830, Foreign Currency Matters. The consolidated U.S. dollar balance sheet at December 31, 2010 was translated into Canadian dollars by translating assets and liabilities at the end-of-period exchange rate and translating equity balances at historical exchange rates.

        As a result of our change in functional currency and reporting currency, there is no difference between the reporting currency and the functional currency of Lone Pine Resources Inc. and any of its operating subsidiaries. Following the changes in functional currency and reporting currency, we will be subject to foreign currency exchange rate risk relating to the Senior Notes, certain of our derivative instruments and our delivery commitment of approximately 21,000 MMBtu/d of natural gas under a long-term sales contract expiring in 2014.

        See "—Critical Accounting Policies, Estimates, Judgments and Assumptions—Change in Reporting and Functional Currency" for more information about our change in reporting currency, including the reasons for the change, the manner in which the change has been applied to recast prior period financial statements and the major financial statement categories that are denominated in U.S. dollars, and for certain U.S. dollar financial information as of and for the year ended December 31, 2011. See also note 2 to our consolidated financial statements.

Financial and Operating Performance

        Our financial and operating performance for 2011 included the following highlights:

•

On June 1, 2011, we completed our IPO of 15 million shares of our common stock. In connection with our IPO and pursuant to our separation and distribution agreement with Forest, Forest contributed to us its ownership interest in LPR Canada in exchange for 69,999,999 shares of our common stock and a cash distribution of $28.7 million. We received net proceeds from our IPO of approximately $173.1 million and used these net proceeds to pay $28.7 million to Forest as partial consideration for Forest's contribution to us of Forest's direct and indirect interests in its Canadian operations. We used the remaining net proceeds and borrowings under our bank credit facility to repay outstanding indebtedness owed to Forest, including intercompany advances and accrued interest.



•

Our average daily net sales volumes for the fourth quarter of 2011 and for the year ended December 31, 2011 were 99 MMcfe/d and 94 MMcfe/d respectively, and our average daily oil and NGLs net sales volumes for the fourth quarter of 2011 increased 27% to 4,499 bbls/d, compared to 3,544 bbls/d in the third quarter of 2011 as our average net liquids percentage increased from 22% to 27%.



•

We drilled a total of 47 gross (47 net) horizontal light oil wells at Evi and 6 gross (5.5 net) natural gas wells in the Deep Basin with a 100% success rate.



•

We generated Adjusted EBITDA of $128.2 million, a 27% increase over 2010 and Adjusted Discretionary Cash Flow of $118.4 million, a 26% increase over 2010.

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        During February 2012, LPR Canada completed the Senior Notes offering. The net proceeds of approximately $192 million were used to partially repay borrowings outstanding under our bank credit facility. The Senior Notes are guaranteed by Lone Pine and all of Lone Pine's wholly-owned subsidiaries (other than LPR Canada).

Recent Trends and Outlook for 2012

        Beginning in the second half of 2008 and continuing throughout 2011, Canada, the United States and other industrialized countries experienced a significant economic slowdown. During the same time period, North American natural gas supply increased as a result of increased domestic unconventional natural gas development and associated natural gas from oil development. In the second half of 2008, oil and natural gas prices declined dramatically. While oil and NGL prices have steadily improved since the first quarter of 2009, North American natural gas prices have remained at low levels and declined further in late 2011 as a result of increased supply and weak domestic demand in the United States. We do not expect natural gas prices to improve significantly in 2012. As a result, we plan to focus our capital expenditures in 2012 primarily on light oil opportunities.

Capital Budget for 2012

        We have established a capital budget of approximately $200 million to $220 million for 2012 and plan to focus our drilling program almost entirely on our light oil opportunities in the Evi area. We have elected to pursue a 2012 capital program designed to maintain financial flexibility, while focusing on high margin light oil projects. We plan to fund our 2012 capital budget primarily through cash flow from operating activities, as well as borrowings under our bank credit facility.

        We plan to allocate approximately $165 million, or approximately 80%, of our total capital budget to light oil development in the Evi area. We plan to drill and complete up to 48 gross (48 net) horizontal wells in the Evi area in 2012 and to continue to advance development through further downspacing and additional infill drilling. We expect to complete the planned drilling program in the Evi area with the two-rig program that we currently have in place. We also intend to continue to expand our facilities in the Evi area to accommodate the growing crude oil volumes in the area and continue investment in our operated waterflood pilot project that we initiated in 2011.

        Given the current disparity between oil and natural gas prices, we intend to allocate minimal capital towards our natural gas properties at this time. Since we have no significant near term lease expiries or drilling obligations on our natural gas assets, we plan to focus almost exclusively on light oil projects while North American natural gas prices continue to trade at multi-year lows. Should natural gas prices recover through 2012, we expect to be able to alter our spending plans and allocate capital to our drill-ready natural gas projects.

        Our 2012 capital budget is detailed below.

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Acquisitions and Divestitures

        In 2011, we increased our Evi land position to 64,320 gross (57,382 net) acres through purchases at Crown land sales. The acquired acreage represents a significant addition to our existing contiguous land holdings in the Evi field and our future light oil drilling inventory.

        In April 2011, we acquired certain natural gas properties located in the Narraway/Ojay fields for $74.4 million. This acquisition increased our working interests in certain properties already owned and operated by LPR Canada in the Narraway field from approximately 50% to 100% and provided us with additional capacity in gathering systems and a gas plant in the Narraway field. In addition, this acquisition increased our acreage position by approximately 85,100 gross (35,700 net) acres.

        As we have expanded into new plays, we also have divested assets that did not meet our development growth strategy. Starting in the fourth quarter of 2009 and through December 31, 2011, we divested approximately $159 million of certain non-core or non-operated oil and gas properties, primarily in December 2009 and April 2010, which, at the time the divestitures occurred, had a combined net production rate of 16 MMcfe/d.

How We Evaluate Our Operations

        We use a variety of financial and operational measures to assess our performance, including:

•

volumes of oil, natural gas and NGLs produced and sold;



•

realized commodity prices;



•

production costs; and



•

earnings before interest, taxes, depreciation, depletion and amortization ("DD&A") and other non-cash items ("Adjusted EBITDA") and cash provided by operating activities before changes in working capital items ("Adjusted Discretionary Cash Flow").

Volumes of Oil, Natural Gas and NGLs Produced and Sold

        The volumes of oil, natural gas and NGLs that we produce and sell are driven by several factors, including:

•

the amount of capital we invest in the exploration, development and acquisition of oil and natural gas properties, including the drilling of new wells and the recompletion of existing wells;



•

the rate at which production volumes on our wells naturally decline;



•

the royalty percentage that is levied on our sales volumes by Canadian provinces; and



•

the amount of production volumes associated with oil and natural gas properties we may divest from time to time.

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        Average daily net sales volumes for the years ended December 31, 2011, 2010 and 2009 are set forth in the table below. See "Results of Operations—Years Ended December 31, 2011, 2010 and 2009—Oil and Natural Gas Volumes and Revenues" for an evaluation of the information presented.

Realized Commodity Prices

        We market our production to a variety of purchasers based on regional pricing, and the prices that we receive are determined by various factors but are primarily driven by global and regional supply and demand fundamentals. NYMEX WTI futures prices are widely-used benchmarks in the pricing of oil and NGLs, and NYMEX Henry Hub and AECO futures prices are used as benchmarks in the pricing of natural gas. The prices realized for each of our products compared to the NYMEX and AECO benchmark prices, or differential, will depend on various factors, which are discussed by product below.

        The table below sets forth the various benchmark prices in U.S. dollars, as well as the prices that we received per unit of volume for each of our products compared to the benchmark prices for the periods indicated. Given our change in reporting currency, we have also presented our realized prices in Canadian dollars.

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Oil Differentials

        The primary factors influencing our oil differential to the NYMEX WTI price are (1) the quality of our oil and (2) the proximity of our oil production to major consuming and refining markets.

        Among other things, there are two characteristics that determine the quality of our oil: (1) the oil's American Petroleum Institute ("API") gravity and (2) the oil's sulfur content by weight. In general, lighter oil (with higher API gravity) sells at a higher price than heavier oil, because lighter oil produces a larger number of lighter liquid products, such as gasoline, that have a higher resale value. On average, the oil that we produce is approximately 35 degrees API. Oil with low sulfur content, or "sweet" crude oil, such as the oil we produce at Evi, is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil, or "sour" crude oil.

        The proximity of our oil production to major consuming and refining markets also impacts our oil differentials. Oil that is produced close to major consuming and/or refining markets, such as Edmonton or Hardisty in Alberta, is in higher demand than oil that is produced farther from these markets and, consequently, realizes a higher price due to the implied costs that must be incurred by the buyer of the oil at or near the wellhead to transport the oil to the consuming and refining markets.

Natural Gas Differentials

        The primary factors influencing natural gas differentials include the proximity of natural gas production to consuming markets or, in instances when natural gas is produced in remote areas away from consuming markets, the amount of natural gas pipeline "takeaway capacity" available to transport natural gas produced to areas with higher demand. Generally, natural gas produced in close proximity to areas that consume large quantities of natural gas will command higher prices, as will natural gas produced in areas with adequate takeaway capacity to those consuming markets. The majority of the natural gas that we produce can access adequate takeaway capacity to major consuming markets and is transported to those markets under firm transportation contracts.

        As of March 20, 2012, we had a delivery commitment of approximately 21,000 MMBtu/d of natural gas, which provides for a price equal to the greater of (1) the NYMEX Henry Hub price less US$1.49 and (2) US$1.00 per MMBtu to a buyer through October 31, 2014, unless the NYMEX Henry Hub price exceeds US$6.50 per MMBtu, at which point we share the amount of the excess equally with the buyer. Accordingly, when the NYMEX Henry Hub price trades above US$6.50 per MMBtu, our reported differentials will widen, as was the case in 2008. Conversely, the contract guarantees a floor price of US$1.00 per MMBtu after deducting US$1.49 from the NYMEX Henry Hub price and our reported differential would narrow in this case.

NGL Realizations

        NGL realizations, which are generally evaluated as a percentage of the NYMEX WTI price, are primarily driven by the relative composition of liquids. NGLs are primarily composed of five marketable components, which, ordered from lightest to heaviest, are: (1) methane, (2) ethane, (3) propane, (4) butanes and (5) pentanes. The heavier liquid components normally realize higher prices than the lighter components. Our NGL realizations were higher in 2011 and 2010 compared to 2009 because of the divestiture of oil and natural gas assets in April 2010, which resulted in a shift in our portfolio toward heavier, more valuable gas liquids components.

Production Costs

        In evaluating our operations, we frequently monitor and assess our production expenses on a per unit of production basis, or "per Mcfe." This measure allows us to better evaluate our operating efficiency as production levels change.

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        Production costs are the costs incurred in the operation of producing our oil, natural gas and NGLs and are primarily comprised of lease operating expense (including workover costs), production and property taxes and transportation and processing costs. In general, lease operating expense and workover costs represent the components of production costs over which we have management control, while production and property taxes are primarily driven by the assessed valuation of our property and equipment by the taxing authorities. Transportation and processing costs are comprised of pipeline transportation costs (primarily incurred to deliver natural gas to consuming regions in order to achieve a higher sales price) and processing costs, which include the cost of separating NGLs from the natural gas stream and compressing the residual natural gas to a pressure adequate to meet pipeline requirements.

        Certain components of lease operating expense are also impacted by energy and field services costs. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas, and we purchase products, such as methanol, to prevent the freezing of gas lines. Although these costs are highly correlated with production volumes, they are also influenced by commodity prices. Certain items, however, such as direct labor and materials and supplies, generally remain fixed across broad sales volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed.

Adjusted EBITDA and Adjusted Discretionary Cash Flow

        We also evaluate our performance using a non-GAAP financial measure, Adjusted EBITDA, which is calculated as net earnings (loss) plus interest expense, income tax expense (benefit), DD&A, ceiling test write-downs of oil and natural gas properties, accretion of asset retirement obligations ("ARO"), unrealized losses (gains) on derivative instruments and foreign currency exchange (gains) losses. Adjusted EBITDA also excludes the equity-accounted for portion of stock-based compensation expense, as these amounts will be settled in shares of our common stock rather than cash payments. By eliminating these items, we believe the result is a useful measure across time in evaluating our fundamental core operating performance. Our 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. As indicated, Adjusted EBITDA does not include interest expense on borrowed money, DD&A expense on capital assets or the payment of income taxes, which are all necessary elements of our operations. Because Adjusted EBITDA does not account for these and other expenses, its utility as a measure of our operating performance has material limitations. Because of these limitations, our management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net earnings (loss) and revenues, to measure operating performance.

        In addition to reporting cash provided by operating activities as defined under GAAP, we also present Adjusted Discretionary Cash Flow, which is a non-GAAP liquidity measure. Adjusted Discretionary Cash Flow consists of cash provided by operating activities before changes in working capital items. Management uses Adjusted Discretionary Cash Flow as a measure of liquidity and believes it provides useful information to investors because it assesses cash flow from operating activities for each period before changes in working capital, which fluctuates due to the timing of collections of receivables and the settlements of liabilities. This measure does not represent the residual cash flow available for discretionary expenditures, since we have mandatory debt service requirements and other non-discretionary expenditures that are not deducted from the measure. Because of this, its utility as a measure of our operating performance has material limitations.

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