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

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. o

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

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 29, 2012, the last business day of the registrant's most recently completed second fiscal quarter, was US$233,053,557 (based on the closing price of such stock).

There were 85,366,283 shares of the registrant's common stock, par value US$0.01 per share, outstanding as of March 8, 2013.

Portions of the registrant's definitive proxy statement relating to the 2013 Annual Meeting of Stockholders to be filed pursuant to Regulation 14A within 120 days after the registrant's fiscal year ended December 31, 2012 are incorporated by reference into Part III of this Form 10-K.

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.

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.

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

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.

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.

As of December 31, 2012, our proved reserves, as estimated by DeGolyer and MacNaughton, our independent reserves engineers, were approximately 188 Bcfe, of which approximately 59% were oil and natural gas liquids ("NGLs"), approximately 41% were natural gas and approximately 63% were classified as proved developed reserves. As of December 31, 2012, we had approximately 147 gross (134 net) proved undeveloped drilling locations and approximately 1.2 million gross (0.9 million net) acres of land (approximately 84% of which was undeveloped). The following table presents summary data for each of our significant properties as of December 31, 2012:

During the past five years, we have primarily focused on the development of our Deep Basin and Evi areas. Beginning in 2009, we applied multi-zone slick-water fracture completion technology to our Narraway/Ojay fields. In April 2011, we completed an acquisition of approximately 35,700 net acres in the Narraway field, which increased our acreage position to approximately 120,329 net acres at December 31, 2012.

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, 2012, we have drilled a total of 103 gross 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 82,015 net acres at December 31, 2012.

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, 2012. From 2007 through 2010, we participated in the drilling of ten exploration wells. However, on June 13, 2011, legislation known as Bill 18 was implemented in Quebec 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 revoked, without compensation, oil and gas rights previously issued for that area. We held exploration licenses to 33,460 net acres of undeveloped lands under the St. Lawrence River that were revoked by Bill 18. On November 8, 2012, we filed a Notice of Intent to Submit a Claim to Arbitration under the North American Free Trade Agreement against the Government of Canada in response to the expropriation without compensation effected by the Province of Quebec through Bill 18. See"—Significant Properties—Shales" below.

In addition to our large shale gas position in Quebec, as of December 31, 2012, we had approximately 52,995 contiguous net acres in the Liard Basin, located in the Northwest Territories, that are prospective for the Muskwa Shale. In the first quarter of 2012, we submitted an application to the National Energy Board of Canada (the "National Energy Board") for a commercial discovery declaration that we believe could potentially lead to the continuation of our leases in the area for up to an additional 21 years. We believe that our acreage in the Liard Basin is analogous to the Muskwa Shale in the Horn River Basin.

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 large hydrocarbon in place reservoirs and our diversified undeveloped acreage positions. We intend to execute this strategy while managing our debt levels relative to our estimated proved reserves and cash flow. In the current depressed natural gas price environment, our near term strategy has been focused on the following:

We operate our business as a single segment with similar economic characteristics, technology, customers, distribution and marketing strategies and regulatory environments. We operate in one industry segment, and our oil and gas exploration and production activities are exclusively within Canada. Our financial information, including net sales volumes and long-lived assets by geographical area, is included in our consolidated financial statements included in Item 8 of this Form 10-K and the related notes contained elsewhere in this Form 10-K are incorporated herein by reference.

As of December 31, 2012, we had approximately 82,015 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 light oil. From 2006 through December 31, 2012, we have drilled a total of 103 horizontal wells in the Evi area. We acquired our initial acreage position in the Evi field in 2004 and we have significantly expanded our acreage position through Crown leasing and acquisitions from approximately 11,000 net acres at December 31, 2004 to 82,015 net acres at December 31, 2012. As of December 31, 2012, our acreage position in the Evi area consists of 139 gross (128 net) sections on which we have 175 gross (141 net) productive wells, of which 103 are horizontal wells in the Slave Point horizon. As of December 31, 2012, we had 109 Bcfe of total estimated proved reserves at Evi, including 39 Bcfe that are classified as proved developed reserves. As of December 31, 2012, we had 147 gross (134 net) proved undeveloped drilling locations in the Evi area. We currently drill eight to ten horizontal wells per section, although we have received regulatory approval to downspace certain sections in the central area of Evi to up to 16 wells per section.

In 2012, we drilled 32 gross (28 net) horizontal wells in the Evi area as compared to 47 gross (47 net) wells in 2011. On average our working interest in the wells drilled in 2012 is 87%. During 2012, we had average daily net sales volumes of 3,161 bbls/d from production in the Evi area. 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.

As of December 31, 2012, we had approximately 120,329 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 120,329 net acres at December 31, 2012. As of December 31, 2012, our land holding was 280 gross (188 net) sections. Regulatory spacing in the Narraway field currently provides for four wells per section. Our acreage position in the Ojay field as of December 31, 2012 consisted of 56 gross (23 net) sections on which we had 12 gross (5 net) productive wells. Regulatory spacing in the Ojay field currently provides for one well per section.

From the fourth quarter of 2008 to the fourth quarter of 2012, we have increased our net sales volumes from the Narraway/Ojay fields from 5 to 34 MMcf/d, with a peak rate of approximately 50 MMcf/d achieved in September 2009. 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 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.

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 and to improve timely takeaway of our gas.

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.

In the fourth quarter of 2012, we sold all of our interests in the Wild River area of Alberta for total gross cash proceeds of $82 million, subject to normal course closing adjustments. At the time the divestiture was announced, the properties had a net production rate of approximately 17.4 MMcfe/d.

As of December 31, 2012, 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 will be in close proximity to major markets in Canada and the northeastern United States, which historically has provided 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.

On March 8, 2011, the Government of Quebec announced that it would move forward with 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"), which had been asked 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. A committee was appointed in May 2011 to conduct the SEA, which was expected to take 18 to 30 months, during which the

government indicated that hydraulic fracturing would only be permitted in Quebec for scientific data gathering purposes if required for the SEA and on the committee's recommendation. The SEA committee was to report annually 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 known as Bill 18 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 revoked, without compensation, oil and gas rights previously issued for that area. We held exploration licenses to 33,460 net acres of undeveloped lands under the St. Lawrence River, representing approximately 14% of our overall net acres in Quebec, that were revoked by Bill 18. On November 8, 2012, we filed a Notice of Intent to Submit a Claim to Arbitration under the North American Free Trade Agreement against the Government of Canada in response to the expropriation without compensation affected by Province of Quebec through Bill 18.

On February 6, 2013, the Quebec Minister of Sustainable Development, Environment, Wildlife and Parks announced that the SEA committee's mandate would be amended and that studies commissioned pursuant to the SEA would be transferred to BAPE and form the basis for further public hearings on the exploration and development of shale gas. Such hearings are expected to convene sometime in 2014. The Minister also announced that the Government of Quebec intends to bring in legislation that formally imposes a moratorium on shale gas exploration and exploitation pending the enactment of a new legislative framework for hydrocarbon activities. New hydrocarbon legislation is not expected until after the further public hearings are completed and the results of that review process are available. 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, 2012, 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 for a commercial discovery declaration that we believe could potentially lead to the continuation of our leases in the area for up to an additional 21 years.

The following table summarizes our estimated quantities of 100% of our proved reserves as of December 31, 2012 and 2011. Our estimated proved reserves as of December 31, 2012 are based on the NYMEX Henry Hub price of US$2.75 per MMBtu and AECO price of $2.37 per MMBtu for natural gas and the NYMEX West Texas Intermediate price of US$94.71 per barrel and Edmonton Light price of $87.90 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, 2012. 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. See "—Preparation of Estimated Proved Reserves" below, and note 24 to our consolidated financial statements included elsewhere in this Form 10-K for additional information regarding our estimated proved reserves.

As of December 31, 2012, we had estimated proved reserves of 188 Bcfe. As of December 31, 2012, proved undeveloped reserves ("PUDs") were estimated to be 70 Bcfe, or 37% of total estimated proved reserves, compared to 187 Bcfe, or 47% of total estimated proved reserves, as of December 31, 2011. The decrease of 117 Bcfe was primarily due to reduced natural gas prices that deemed certain future natural gas drilling locations as uneconomic and required those locations to be removed from our reserves. We intend to convert the remaining PUD reserves disclosed as of December 31, 2012 to proved developed reserves within five years of when they were initially disclosed as PUDs.

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

Our estimated proved reserves at December 31, 2012 are based on a report dated February 25, 2013 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 38 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.

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.

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 18 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 Interim Chief Executive Officer, David M. Fitzpatrick.

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.

The following table summarizes the number of wells drilled during the years ended December 31, 2012, 2011 and 2010, excluding any wells drilled under farmout agreements, royalty interest ownership or any other wells in which we do not have a working interest.

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, 2012.

The following table summarizes developed and undeveloped acreage in which we owned a working interest or held an exploration license as of December 31, 2012. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary, as well as acreage related to any options held by us to acquire additional leasehold interests. At December 31, 2012, approximately 1%,

5% and 6% of our net undeveloped acreage was held under leases that will expire in 2013, 2014 and 2015, respectively, if not extended by exploration or production activities.

	Year Ended December 31,

	2012		2011		2010
Liquids:
Oil:
Average sales price (per bbl)	$	81.96	$	83.89	$	69.88
Net sales volumes (Mbbls)		1,347		1,110		828
Natural gas liquids:
Average sales price (per bbl)	$	54.08	$	61.43	$	53.65
Net sales volumes (Mbbls)		71		82		134
Total liquids:
Average sales price (per bbl)	$	78.13	$	82.34	$	67.62
Net sales volumes (Mbbls)		1,418		1,192		962
Natural Gas:
Average sales price (per MMbtu)	$	2.16	$	3.42	$	3.84
Net sales volumes (MMcf)		21,968		27,167		22,436
Total liquids and natural gas:
Average sales price (per Mcfe)	$	5.31	$	5.57	$	5.36
Total net sales volumes (MMcfe)		30,476		34,319		28,208
Production costs (per Mcfe):
Lease operating expenses	$	1.69	$	1.13	$	0.94
Production and property taxes		0.10		0.07		0.09
Transportation and processing costs		0.51		0.50		0.39

Total production costs	$	2.30	$	1.70	$	1.42

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, 2012, 2011 and 2010.

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 8, 2013, we have a delivery commitment of approximately 21,000 MMBtu of natural gas, which provides for a price equal to the greater of (1) the NYMEX Henry Hub price less US$1.49 per MMBtu 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. All of our current natural gas production in Alberta and British Columbia is available to be used as source gas for this delivery commitment.

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."

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.

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.

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 our operations in a manner significantly different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record, we are unable to predict what regulatory controls or restrictions may be enacted.

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 gross production. The value of production and the rate of royalties payable depend on prescribed reference prices, well productivity, geographical location, field discovery rate and the type of product produced.

Royalties payable on production from privately-owned lands are determined by negotiations between us and the resource owners, although production from such lands is subject to certain provincial taxes and royalties. 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.

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 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.

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:

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:

In conjunction with the release of the new royalty curves for the ARF, the Alberta government also announced its Emerging Resources and Technology Initiative ("ERTI") intended to accelerate new technologies and encourage the development of unconventional resources. The ERTI will be will be reviewed in 2014 and the Government of Alberta has committed to providing the industry with three years' notice if it intends to discontinue the program.

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:

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, postponed the adoption of new rules for shale gas exploration and development pending completion of the SEA announced on March 8, 2011 and is not currently expected to act until after completion of further public hearings by BAPE announced on February 6, 2013. See "—Environmental Regulation" below.

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 had been completed and the legal and regulatory framework had 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 proposed royalty regime contemplated a progressive royalty rate, calculated on a per well basis, ranging from 5% to 35% for shale gas, with the applicable rate to be determined according to a formula 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). The proposal also suggested certain incentive programs. It is unclear whether the 2011 royalty proposal will be a feature of any legislative and regulatory initiatives undertaken by the current Government of Quebec concerning shale gas activities in that province.

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.

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.

Lands in petroleum and natural gas license are earned by the drilling of a well. A lease is proven productive at the end of its five-year term by drilling, producing, mapping, being part of a unit agreement or by paying offset compensation. If a lease is proven productive, it will continue indefinitely beyond the initial term of the lease. The tenure only comes to an end when the holder can no longer prove his agreement is capable of producing oil or gas.

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.

Oil and natural gas can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

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, British Columbia and Alberta, with respect to shale gas exploration and development. In Quebec, the provincial government announced in March 2011 SEA of shale gas activities in the province during which hydraulic fracturing would be allowed only if required for SEA purposes, and in February 2013 an intention to bring in legislation that formally imposes a moratorium on shale gas exploration and

exploitation pending the enactment of a new legislative framework for hydrocarbon activities following completion of the SEA and further public hearings. 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. See "—Significant Properties—Shales" above. 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. In December 2012, the Energy Resources Conservation Board ("ERCB") also updated their provincial data filing requirements used in hydraulic fracturing operations to increase public disclosure of hydraulic fracturing fluid ingredients. 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.

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 United Nations Framework Convention on Climate Change 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 to the Kyoto Protocol. 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 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 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.

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 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, which sets out reporting requirements for facilities emitting 10,000 tonnes or more of carbon dioxide equivalent emissions per year. 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 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.

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 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.

As of December 31, 2012, we had 69 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.

The following information is provided with respect to our executive officers as of March 8, 2013.

Officers are elected by our Board of Directors and hold office at the pleasure of our Board of Directors until their successors are elected and qualified. The following biographies describe the business experience of our executive officers:

David M. Fitzpatrick. Mr. Fitzpatrick was appointed as our Interim Chief Executive Officer in February 2013, and has been a member of the Board of Directors since completion of the Company's initial public offering in June 2011. Mr. Fitzpatrick is an independent businessman and from 1996 to 2007, he served as President, Chief Executive Officer and Director of Shiningbank Energy Ltd. (acquired by PrimeWest Energy Trust), an oil and gas company. From June 2008 to September 2008, Mr. Fitzpatrick was a principal at Richardson Capital Ltd., the private equity division of Richardson Financial Group. Mr. Fitzpatrick serves as a director of Twin Butte Energy Ltd. (since July 2008) and Eagle Energy Trust (since November 2010). Prior directorships include Strike Petroleum Ltd., Pinecrest Energy Inc., PrimeWest Energy Trust, Enerchem International Inc. and Compton Petroleum Corporation. Mr. Fitzpatrick is a member of the Society of Petroleum Engineers, the Association of Professional Engineers, Geologists and Geophysicists of Alberta and has a Chartered Director designation.

Shane K. Abel. Mr. Abel was appointed as our Vice President, Finance & Treasurer in July 2011. From July 2003 to June 2011, Mr. Abel worked at BMO Capital Markets, a Canadian bank-owned full service investment dealer, where he most recently held the position of Vice President, Investment & Corporate Banking. Mr. Abel graduated with a Bachelor of Commerce degree in Honours Finance and Accounting from the University of Saskatchewan in 2003 and is a CFA Charterholder.

Douglas W. Axani. Mr. Axani was appointed as our Vice President, Exploration in March 2011. Mr. Axani served as Exploration Manager of LPR Canada since February 2009. From April 2008 to October 2008, Mr. Axani worked for Terralliance Technologies Canada Inc., an oil and gas exploration and development company, as Manager of Exploration, where he managed the Canadian operations within the Calgary office. Mr. Axani worked for Kereco Energy Ltd., an oil and gas exploration and development company, from February 2005 to January 2008, where he started as a senior exploration geologist and moved into the position of Manager of Exploration for the Northern Business District. Mr. Axani's responsibilities at Kereco Energy Ltd. included mapping and developing new prospects and selecting well locations to add to corporate production and reserves. Mr. Axani received a Bachelor of

Science degree in Geology from the University of Alberta in 1994. He is a Professional Geologist and a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta.

Lyle H. Burke. Mr. Burke was appointed as our Vice President, New Ventures & Technology in November 2011. Mr. Burke has over 30 years of petroleum engineering experience and joined us from RPS Energy, an international petroleum consulting firm, where he worked from 2007 to 2011 and where he most recently held the position of Vice President, Consulting Services. Prior to joining RPS Energy's predecessor APA Petroleum Engineering in 1987, Mr. Burke held various engineering positions with Petro-Canada. Mr. Burke received a Bachelor of Science in Civil Engineering from the University of Calgary and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and the Society of Petroleum Engineers.

Mark E. Bush. Mr. Bush was appointed as our Vice President, Operations in October 2011. Prior to joining us, Mr. Bush held various operational positions with Forest, most recently as Vice President of the Eastern Business Unit, a position he held since May 2007. Prior to joining Forest in 1997, Mr. Bush worked as an Operations Engineer for Sun Exploration and Production Company and its successor, Oryx Energy Company. Mr. Bush received a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines. He is a Registered Professional Engineer in the State of Texas and a 32 year member of the International Society of Petroleum Engineers.

Charles R. Kraus. Mr. Kraus was appointed as our Vice President, General Counsel & Corporate Secretary in September 2011. Mr. Kraus is a Canadian and U.S. qualified lawyer. From August 2005 to September 2011, Mr. Kraus was a lawyer in the Calgary office of Stikeman Elliott LLP, where he focused on cross-border public and private capital markets transactions, mergers and acquisitions and corporate governance. As a member of the Company's executive team, Mr. Kraus is responsible for several business functions, including Legal, Human Resources and Corporate Governance. Mr. Kraus received his law degree (J.D., magna cum laude) from Hamline University School of Law in St. Paul, Minnesota in 2001 and his undergraduate degree (B.A., departmental distinction) from Northwestern College in St. Paul, Minnesota in 1998. Mr. Kraus is admitted to the bars of Alberta, Washington and Minnesota.

Shona F. Mackenzie. Ms. Mackenzie was appointed as our Vice President, Engineering & Exploitation in March 2011. Ms. Mackenzie has served as Manager of Engineering and Exploitation of LPR Canada since October 2009. Prior to joining LPR Canada, Ms. Mackenzie served as the Reservoir Engineering Manager of RPS Group Plc, a petroleum engineering consultancy company, from February 2007 to October 2009, where she managed a team working in field development planning, field rehabilitation, reserves evaluation and reservoir simulation. From August 1999 to February 2007, Ms. Mackenzie worked for APA Petroleum Engineering Inc., a petroleum engineering consultancy company, as the Integrated Studies Manager, where she managed the construction and application of Integrated Field Models. Ms. Mackenzie received a Bachelor of Engineering degree in Offshore (Civil) Engineering from Heriot-Watt University in 1992 and a Master of Engineering degree in Petroleum Engineering from Heriot-Watt University in 1994. She is a certified Professional Engineer and a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta.

As of December 31, 2012, we leased approximately 52,194 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.

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.

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.

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

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.

boe. bbl equivalents, calculated as six Mcf of gas equaling one bbl of oil.

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

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

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.

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.

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.

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 volumes.

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 volumes.

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.

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. In the second quarter of 2012, natural gas prices reached ten year lows. As of March 8, 2013, the spot price for natural gas was US$3.63 per MMBtu for NYMEX Henry Hub and $3.33 per MMBtu for AECO, and the spot price for crude oil was US$91.95 per barrel for NYMEX West Texas Intermediate and $86.44 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:

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 41% of our estimated proved reserves at December 31, 2012 were natural gas.

Natural gas prices have declined substantially in the last year and are expected to remain depressed for the foreseeable future. Approximately 72% of our 2012 production, on an MMcfe basis, was natural gas. Sustained depressed prices of natural gas will adversely affect our assets, development plans, results of operations and financial position, perhaps materially.

Natural gas prices have declined from an average NYMEX Henry Hub price of $4.00 per MMBtu in 2011 to $2.75 per MMBtu in 2012. The reduction in prices has been caused by many factors, including recent increases in gas production from non-conventional (shale) reserves, warmer than normal weather and high levels of natural gas in storage. As of December 31, 2012, we had hedged approximately 100% of our expected natural gas production in 2013 using collar structures at prices that are in line with those currently prevailing. Because prices for natural gas have continued to remain depressed for lengthy periods, in 2012 we were required to write down the value of our oil and natural gas properties and revise our development plans which caused a 131 Bcfe decrease in proved undeveloped natural gas reserves. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to reinvest in or business, pay expenses, and service our indebtedness.

The continuing decline of natural gas prices, a future decline in oil prices and concern about the global financial markets could limit our ability to obtain funding in the capital and credit markets on terms we find acceptable, obtain additional or continued funding under our credit facility or obtain funding at all.

During 2011 and 2012, we were able to access the debt and equity capital markets. However, the continuing decline of natural gas prices or a future decline in oil prices could significantly increase the cost of obtaining money in the capital and credit markets and limit our ability to access those markets as a source of funding in the future.

Historically, we have used our cash flow from operations, borrowings under our bank credit facility and issuance of senior notes to fund our capital expenditures and acquisitions. The continuing decline of natural gas prices or a future decline in oil prices could ultimately decrease our net revenue and

profitability. The recent natural gas price declines have negatively impacted our revenues and cash flows.

These events affect our ability to access capital in a number of ways, which include the following:

Due to these factors, we cannot be certain that funding will be available, if needed and to the extent required, on acceptable terms. If funding is not available when needed, or if funding is available only on unfavorable terms, we may be unable to meet our obligations as they come due or be required to post collateral to support our obligations, or we may be unable to implement our development plans, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, results of operations, or financial condition. Moreover, if we are unable to obtain funding to make acquisitions of additional properties containing proved oil or natural gas reserves, our total level of estimated proved reserves may decline as a result of our production, and we may be limited in our ability to maintain our level of production and cash flow.

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 intend to rely on cash flow from operating activities, borrowings under our bank credit facility and proceeds from asset dispositions 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 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:

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."

Recent credit concerns 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.

Our substantial indebtedness could adversely affect our financial condition.

We have a significant amount of indebtedness. As of December 31, 2012, we had US$200 million of Senior Notes outstanding and $148 million outstanding under our bank credit facility, and we had unused commitments of approximately $125.0 million under our bank credit facility (after deducting $2.0 million of outstanding letters of credit). As of March 8, 2013, we had US$200 million of Senior Notes outstanding and $151 million outstanding under our bank credit facility, and we had unused commitments of approximately $122.0 million under our bank credit facility (after deducting $2.0 million of outstanding letters of credit).

Subject to the limits contained in the indenture governing the US$200 million aggregate principal amount of 10.375% senior notes due 2017 (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:

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:

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 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:

In addition, the credit agreement governing our bank credit facility provides that we will not permit our ratio of total debt outstanding to Adjusted EBITDA (as adjusted for divestitures with a transaction value in excess of US$25 million) for a trailing 12-month period to be greater than 4.00 to 1.00. At December 31, 2012, this ratio was 3.8 to 1.0.

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 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:

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:

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 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. On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") was enacted that 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"), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court for the District of Columbia in September of 2012, although the CFTC has stated that it will appeal the District Court's decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of "swap", "security-based swap", "swap dealer" and "major swap participant." The Dodd-Frank Act and CFTC Rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us and the timing of such effects. The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. 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.

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 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 non-cash ceiling test write-downs of approximately $128.8 million in the second quarter of 2012, and $142.9 million in the third quarter of 2012. These write-downs were 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.

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.

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:

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.

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.

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:

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 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.

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, 2012, we had 147 gross (134 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, 2012, approximately 1%, 5% and 6% of our net undeveloped acreage was held under leases that will expire in 2013, 2014 and 2015, respectively, if not extended by exploration or production activities.

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.

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."

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, announced in March 2011 a SEA of shale gas activities in the province during which hydraulic fracturing would only be allowed if required for SEA purposes, and in February 2013, an intention to bring in legislation that formally imposes a moratorium on shale gas exploration and exploitation pending the enactment of a new legislative framework for hydrocarbon activities following completion of the SEA and further public hearings by BAPE. 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 of undeveloped lands under the St. Lawrence River that were revoked by this legislation. On November 8, 2012, we filed a Notice of Intent to Submit a Claim to Arbitration under the North American Free Trade Agreement against the Government of Canada in response to the expropriation without compensation effected by Province of Quebec through Bill 18. 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. In December 2012, the ERCB also updated their provincial data filing requirements used in hydraulic fracturing operations to increase public disclosure of hydraulic fracturing fluid ingredients, See Part I, "Item 1. Business—Significant Properties—Shales" and "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, impose new permitting burdens on hydraulic fracturing activities and require disclosure of chemicals used in the fracturing process. The U.S. Environmental Protection Agency (the "EPA") has commenced a comprehensive study of the potential environmental impacts of hydraulic fracturing practices, and the agency has indicated that it expects to

issue its study report in late 2014. The EPA study and report may provide a basis for seeking to regulate hydraulic fracturing at the federal level. 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 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.

Resolution of litigation could materially affect our financial position and results of operations.

We have been named as a defendant in certain lawsuits. See Item 3. "Legal Proceedings." In some of these suits, our liability for potential loss upon resolution may be mitigated by insurance coverage. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we could incur losses that could be material to our financial position or results of operations in future periods.

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 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.

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 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 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.

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:

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 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:

As a result of the Distribution, Forest has no remaining ownership interest in us; however, the Chairman of our Board of Directors is also the President & Chief Executive Officer and a director of Forest. As a result, Forest may gain the benefit of corporate opportunities that are presented to this director.

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 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:

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.

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."

The Company is a defendant in a consolidated putative class action lawsuit captioned In re Lone Pine Resources, Inc., No. 12-cv-4839-GBD (SDNY) that is pending in the United States District Court for the Southern District of New York. This lawsuit names as defendants the Company, certain of the Company's current and former directors and officers (the "Individual Defendants"), certain underwriters (the "Underwriter Defendants") of the Company's IPO in May 2011 and Forest. It alleges that the Company's registration statement and prospectus issued in connection with the IPO contained untrue statements of material fact or omitted to state material facts relating to the rupture of a third-party oil sales pipeline in Northern Alberta in April 2011. The complaint claims that that the alleged misstatements or omissions violated Section 11 of the Securities Act of 1933, as amended (the "Securities Act"), and that the Company, the Individual Defendants and the Underwriter Defendants are liable for such violations. The complaint further alleges that the Underwriter Defendants offered and sold the Company's securities in violation of Section 12(a)(2) of the Securities Act, and the putative class members seek rescission of the securities purchased in the IPO that they continue to own and rescissionary damages for securities that they have sold. Finally, the complaint asserts a claim against Forest under Section 15 of the Securities Act, alleging that Forest was a "control person" of the Company at the time of the IPO. The Company has existing obligations to indemnify the Individual Defendants, the Underwriter Defendants and Forest in connection with the lawsuit. The Company believes that the claims are without merit and, in accordance with a schedule established by the court, intends to file a motion to dismiss the complaint in its entirety on March 22, 2013. The court's schedule calls for all briefing to be completed by June 25, 2013, after which the court will decide the motion. During the pendency of the motion, all discovery in the lawsuit is stayed.

On November 8, 2012, Lone Pine filed a Notice of Intent to Submit a Claim to Arbitration (the "Notice of Intent") under the North American Free Trade Agreement ("NAFTA") relating to the expropriation without compensation by the Government of Quebec of certain of the Company's oil and gas mining rights in the Saint Lawrence Valley in Quebec. Lone Pine holds numerous exploration permits in the Saint Lawrence Valley issued by the Quebec Ministry of Natural Resources and Wildlife. On June 13, 2011, the National Assembly of Quebec adopted Bill 18, An act to limit oil and gas activities, which suspended all oil and gas exploration activities beneath the Saint Lawrence River upstream of the Anticosti Islands and on the islands situated in that part of the river, and revoked all previously issued mining rights under that stretch of the Saint Lawrence River, including an exploration permit covering 33,460 acres previously held by Lone Pine.

Although there is no guarantee regarding the outcome and receipt of fair compensation pursuant to the claim, we believe that the expropriation of our exploration permit pursuant to Bill 18 was a violation of NAFTA by the Government of Quebec, for which the Government of Canada is responsible, and that Lone Pine (a Delaware corporation) is entitled to full compensation for the expropriation. The Notice of Intent asserts that the expropriation was arbitrary, capricious and without justification, and we are seeking in excess of $250 million in compensation for the expropriated rights

(based on development plans), plus additional costs and further relief as the Arbitral Tribunal may deem just and appropriate. We have asserted in the Notice of Intent that the expropriation breaches Canada's NAFTA obligations on a number of grounds, including among other things: (i) the criteria for expropriation are not met in Bill 18; (ii) Bill 18 expressly prohibits the payment of compensation for the expropriation; and (iii) Bill 18 violates Canada's obligation to afford the investments of NAFTA investors fair and equitable treatment and full protection and security.

Lone Pine has filed the Notice of Intent as part of the dispute resolution mechanism available under NAFTA and intends to submit the claim to arbitration at the appropriate time pursuant to the relevant NAFTA provisions. Although we believe that the Government of Canada will be required to compensate us for the fair market value of the expropriated permit, we have not recognized any asset for such claim in our consolidated financial statements.

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

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 8, 2013, the last sale price of our common stock, as reported on the NYSE and the TSX, was US$1.07 per share and $1.09 per share, respectively.

The number of stockholders of record of our common stock was approximately 512 on March 8, 2013.

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 8 to our consolidated financial statements.

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, 2012.

The information required by this item is included in our Current Report on Form 8-K filed on February 15, 2012. See also note 8 of the consolidated financial statements included in this Form 10-K.

Neither we nor any "affiliated purchaser" repurchased any of our equity securities in the year ended December 31, 2012.

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 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:

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, 2012.

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 reflect 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 three-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. 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."

	Year ended December 31,

	2012			2011		2010		2009			2008
	(In thousands of Canadian dollars, except per share data)
Statement of operations data:
Revenues	$	161,757		$	191,200	$	151,208	$	127,209		$	263,484
Net earnings (loss)		(274,535	)		34,803		32,825		(177,746	)		48,877
Earnings (loss) per share		(3.23	)		0.44		0.47		(2.54	)		0.70
Balance sheet data (at period end):
Total assets		622,803			992,301		711,351		541,919			885,378
Long-term debt(1)		340,310			331,000		—		—			115,000
Capital lease obligations		5,738			6,894		—		—			—
Amounts due to Forest(2)		—			252		287,669		164,714			129,187

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our 2012 consolidated financial statements and the related notes contained elsewhere in our Annual Report on Form 10-K for the year ended December 31, 2012 ("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" in this "Management's Discussion and Analysis of Financial Condition and Results of Operations" ("MD&A"). Our actual results may differ materially as a result of a number of risks and uncertainties. See Part I, "Item 1A. Risk Factors" in our Form 10-K for additional information regarding known material risks.

In this MD&A, unless otherwise indicated or the context otherwise requires, references to "we," "us," "our" or "Lone Pine" when used in reference to periods prior to June 1, 2011 refer to Lone Pine Resources Canada Ltd. ("LPR Canada") 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 LPR Canada. Unless the context otherwise requires, references in this Form 10-K to "LPR Canada" or "our predecessor" refer to LPR Canada, 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.

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

("Forest"). Our predecessor, LPR Canada, 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. As a result of the Distribution, Forest had no remaining ownership interest in us.

DeGolyer and MacNaughton, our independent reserves engineers, estimated 100% of our proved reserves to be approximately 188 billion cubic feet equivalent ("Bcfe") as of December 31, 2012, of which approximately 59% was oil and natural gas liquids ("NGLs") , approximately 41% was natural gas and approximately 63% was classified as proved developed reserves. As of December 31, 2012, we had approximately 147 gross (134 net) proved undeveloped drilling locations and approximately 1.2 million gross (0.9 million net) acres of land (approximately 84% of which was undeveloped).

Our financial and operating performance for 2012 included the following highlights.

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

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

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. New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("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 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 39 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.

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 8, 2013, we had a delivery commitment of approximately 21,000 million British Thermal Units per day ("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 per MMBtu 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. Conversely, the contract guarantees a floor price of US$1.00 per MMBtu after deducting US$1.49 per MMBtu from the NYMEX Henry Hub price and our reported differential would narrow in this case.

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 four marketable components, which, ordered from lightest to heaviest, are: (1) ethane, (2) propane, (3) butanes and (4) pentanes. The heavier liquid components normally realize higher prices than the lighter components.

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

Production costs are the costs incurred in the operation of producing our oil, natural gas and NGLs and primarily comprise lease operating expenses, production and property taxes, and transportation and processing costs. In general, lease operating expenses, which include the cost of

workovers and the trucking of emulsion to batteries, 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 comprise 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 expenses 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 the periods they are performed.

We also evaluate our performance using a non-generally accepted accounting principles ("non-GAAP") measure, Adjusted EBITDA, which is calculated as net earnings (loss) before interest expense, income tax expense (recovery), DD&A expense, impairment of goodwill, impairment of assets, 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 stock-settled portion of stock-based compensation expense, as this amount 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 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, rating agencies, 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. Adjusted EBITDA does not account for these and other expenses, and therefore its utility as a measure of our performance has material limitations. As a result of these limitations, our management does not view Adjusted EBITDA in isolation and uses other measurements, such as net earnings (loss) and revenues, to measure performance. In the first quarter of 2012, we revised the calculation of Adjusted EBITDA to exclude the amortization of deferred costs. Adjusted EBITDA for 2011 and 2010 has been restated to be consistent with the presentation used in 2012.

For a reconciliation of this non-GAAP measure to its most directly comparable GAAP measure, see "—Reconciliation of Non-GAAP Measure", which reconciles net earnings (loss) to Adjusted EBITDA.

Selected financial results for the years ended December 31, 2012, 2011 and 2010 are as follows.

We recorded a net loss of $274.5 million for the year ended December 31, 2012 compared to net earnings of $34.8 million for the year ended December 31, 2011. The net loss was primarily due to ceiling test write-downs of oil and natural gas properties in the second and third quarters of 2012 which were primarily caused by the reduction in the 12-month average trailing natural gas price. Other factors that contributed to our net loss included higher interest expense, which was associated with the Senior Notes issued in February 2012, higher DD&A expense due to higher per-unit DD&A rates in 2012, as well as lower revenues primarily due to lower natural gas prices. Adjusted EBITDA decreased $21.2 million for the year ended December 31, 2012 compared to the year ended December 31, 2011, primarily due to the decrease in natural gas revenues as well as higher production expenses, due in part to our strategy of increasing liquids production, and higher general and administrative expenses, primarily as a result of our transition to being a public company. These decreases were partially offset by an increase in our realized gains on derivatives.

Net earnings were $34.8 million for the year ended December 31, 2011 compared to $32.8 million for the year ended December 31, 2010. The increase was primarily due to increases in oil and natural gas revenues primarily due to higher production volumes as well as higher oil prices, and an increase in gains on derivative instruments as a result of prices in our commodity derivatives being higher than benchmark prices. The increases were partially offset by higher production expense as a result of an increase in production volumes and workovers, as well as increased costs for maintenance, water hauling, utilities and chemicals. Other expenses that were higher in 2011 included DD&A expense, due to higher DD&A per-unit rates, and higher income tax expense due to higher earnings before income taxes. In addition, net earnings were impacted by higher general and administrative costs related to the costs of being a public company as well as incremental costs for our IPO and the Distribution. Adjusted EBITDA increased $26.3 million for the year ended December 31, 2011 compared to the year ended December 31, 2010, due to the increase in oil and natural gas revenues, partially offset by the higher production expense.

A discussion of the components of the changes in our results of operations follows.

The table below presents our sales volumes by product for the years ended December 31, 2012, 2011 and 2010.

	Year Ended December 31,

	2012			2011			2010
Working interest sales volumes⁽¹⁾:
Oil (Mbbls)		1,487			1,252			957
NGLs (Mbbls)		100			115			185
Natural gas (MMcf)		22,044			28,634			23,961
Total equivalent (MMcfe)		31,566			36,836			30,813
Total equivalent daily sales volumes (MMcfe/d)		86.2			100.9			84.4
Total equivalent daily sales volumes (boe/d)		14,374			16,820			14,070
Average liquids weighting		30	%		22	%		22	%
Net sales volumes⁽²⁾:
Oil (Mbbls)		1,347			1,110			828
NGLs (Mbbls)		71			82			134
Natural gas (MMcf)		21,968			27,167			22,436
Total equivalent (MMcfe)		30,476			34,319			28,208
Total equivalent daily sales volumes (MMcfe/d)		83.3			94.0			77.3
Total equivalent daily sales volumes (boe/d)		13,878			15,667			12,883
Average liquids weighting		28	%		21	%		20	%
Royalties (percentage of working interest sales volumes)		3.5	%		6.8	%		8.5	%

Net sales volumes for the year ended December 31, 2012 decreased 11% to 83.3 MMcfe/d from 94.0 MMcfe/d in 2011. However, crude oil net sales volumes for the year ended December 31, 2012 increased 21% to 1,347 Mbbls (3,680 bbls/d) from 1,110 Mbbls (3,041 bbls/d) in 2011. The increase was primarily due to the advancement of our light oil development at Evi. Consistent with our strategy of focusing on light oil development in order to drive higher liquids production, we also increased our average net liquids weighting to 28% during the year ended December 31, 2012 from 21% during the year ended December 31, 2011. Our natural gas production decreased by 19% in the year ended December 31, 2012 when compared to the same period in 2011, as we have suspended new investment in natural gas drilling activities since October 2011 in response to the outlook for low natural gas prices. We expect this decrease in natural gas production to continue while we focus our capital program on light oil development.

Net sales volumes for the year ended December 31, 2011 were 94.0 MMcfe/d compared to 77.3 MMcfe/d in 2010. Excluding the volumes relating to properties sold in 2009 and 2010, the increase would have been 24% for the year ended December 31, 2011. The increases were primarily due to new drilling activity in our Evi and Narraway/Ojay fields, as well as the acquisition of additional Narraway/Ojay producing properties in April 2011, partially offset by natural declines in other areas.

The table below presents our revenues, various benchmark prices, as well as the prices that we received per unit for each of our products for the periods indicated.

	Year Ended December 31,

	2012			2011			2010
Revenues (in thousands):
Oil		110,403			93,112			57,863
Natural gas		47,460			93,020			86,132
NGLs		3,840			5,038			7,189
Total		161,703			191,170			151,184
Average prices per unit:
NYMEX WTI (US$ per bbl)		94.15			95.12			79.61
NYMEX WTI ($ per bbl)		94.11			94.01			81.99
Edmonton Par ($ per bbl)		86.29			95.04			77.55
Average oil sales price ($ per bbl)		81.96			83.89			69.88
Differential to NYMEX WTI ($ per bbl)		12.15			10.12			12.11
Differential to Edmonton Par ($ per bbl)		4.33			11.15			7.67
NYMEX Henry Hub (US$ per MMBtu)		2.79			4.04			4.39
NYMEX Henry Hub ($ per MMBtu)		2.79			3.99			4.52
AECO ($ per MMBtu)		2.40			3.67			4.13
Average natural gas sales price ($ per MMBtu)		2.16			3.42			3.84
Differential to NYMEX Henry Hub ($ per MMBtu)		0.63			0.57			0.68
Differential (premium) to AECO ($ per MMBtu)		0.24			0.25			0.29
Average NGL sales price ($ per bbl)		54.08			61.43			53.65
Percentage of NYMEX WTI		57	%		65	%		65	%
Total equivalent realized sales price ($ per Mcfe)		5.31			5.57			5.36
Total equivalent realized sales price ($ per boe)		31.84			33.42			32.16

Oil and natural gas revenues were $161.7 million and $191.2 million for the years ended December 31, 2012 and 2011, respectively. The decrease was primarily due to lower natural gas revenues as a result of lower benchmark natural gas prices, which have remained significantly lower throughout 2012 compared to 2011. The lower benchmark prices reduced our average realized natural gas price by 37% in 2012. Natural gas revenues were also lower in 2012 due to a decrease in natural gas volumes of 19% from the previous year, primarily due to natural declines. Our crude oil revenues increased 19% in 2012 compared to 2011 due to higher crude oil volumes, partially offset by slightly lower realized prices. Although the benchmark Edmonton Par crude oil price was 9% lower in the year ended December 31, 2012 compared to the year ended December 31, 2011, our average realized crude oil sales price only decreased by 2%. As a result, our average differential to Edmonton Par narrowed to $4.33 per barrel of oil ("bbl") in 2012, primarily due to a higher proportion of our crude oil production coming from light oil properties.

Oil and natural gas revenues were $191.2 million for the year ended December 31, 2011 compared to $151.2 million for the year ended December 31, 2010. The increase in revenues was due to an increase in oil and natural gas sales volumes as well as higher realized oil prices, partially offset by lower realized natural gas prices.

The table below presents the detail of production expense for the periods indicated.

	Year Ended December 31,

	2012		2011		2010
	(In thousands, except per Mcfe data)
Production expense:
Lease operating expenses	$	51,406	$	38,789	$	26,547
Production and property taxes		3,083		2,337		2,513
Transportation and processing costs		15,600		17,252		11,104

Total	$	70,089	$	58,378	$	40,164

Production expense per Mcfe:
Lease operating expenses	$	1.69	$	1.13	$	0.94
Production and property taxes		0.10		0.07		0.09
Transportation and processing costs		0.51		0.50		0.39

Total	$	2.30	$	1.70	$	1.42

Lease operating expenses for the year ended December 31, 2012 were $51.4 million, or $1.69 per Mcfe, compared to $38.8 million, or $1.13 per Mcfe, for the year ended December 31, 2011. The $12.6 million increase in lease operating expenses was primarily due to an increase of $17.3 million at Evi, partially offset by a decrease at other properties. The increase at Evi was related to a 35% increase in crude oil volumes in the area compared to 2011, together with higher per unit costs for wells drilled at Evi in 2012. As part of our capital development, pipeline infrastructure is typically built to enable the majority of our oil emulsion production to be transported by pipeline to processing and for subsequent sales to a shipper in the Evi area, which minimizes the cost of trucking emulsion to operated processing batteries. However, for many of the new wells drilled in 2012, we elected to install single-well batteries instead of building capital-intensive pipelines. As a result of this decision, we transport more of our emulsion production by truck at a higher cost than transporting by pipeline. Lease operating expenses were also higher due to temporary operational issues at a jointly owned oil battery in the Evi area operated by a third party, including issues with the allocation of crude oil volumes, constrained water-handling capability and longer wait times for our trucks. As a result of these issues at the battery, we elected to transport a portion of our emulsion to other batteries in the area. These factors increased our trucking costs to $6.9 million in 2012 compared to $2.8 million in 2011. As of March 8, 2013, it appears that these temporary operational issues at the jointly owned oil battery have been resolved, although we are seeking restitution from the operator of the facility for the resulting damages. In 2012, we also incurred an increase of $3.6 million for the cost of workovers, an increase of $3.4 million for the rental of certain equipment at our single-well batteries, as well as increase of $1.2 million for the cost of chemicals.

Lease operating expenses in the year ended December 31, 2011 were $38.8 million, or $1.13 per Mcfe, compared to $26.5 million, or $0.94 per Mcfe, in 2010. The increase in lease operating expenses was primarily due to an increase in production volumes and costs associated with workovers, maintenance, water hauling, utilities and chemicals. Maintenance costs increased primarily due to start-up costs associated with bringing a large number of wells on-line in late 2010, which were previously shut-in due to infrastructure constraints. Maintenance costs at Evi also increased due to the heightened activity in the area combined with some difficult weather conditions. Utility costs increased primarily

due to higher utility rates as well as an increase in usage. Other increases were generally related to variable costs associated with increased production.

Production and property taxes primarily consist of production taxes levied on freehold production and property taxes (ad valorem taxes) assessed by local governments. The increase for the year ended December 31, 2012 was due to higher property taxes on new development in the Evi area, partially offset by lower production taxes on declining production on freehold properties. Production and property taxes were lower in 2011 compared to 2010, primarily due to the divestiture of properties with freehold production as well as declining production from existing freehold properties.

Transportation and processing costs primarily consist of natural gas transportation costs and field-level natural gas gathering and processing costs. Transportation and processing costs for the year ended December 31, 2012 were $15.6 million compared to $17.3 million for the year ended December 31, 2011. The decrease was primarily related to the decline in natural gas production volumes as well as the renegotiation of certain contracts, which reduced our natural gas transportation and processing costs by approximately $2.8 million. This decrease was partially offset by an increase of approximately $1.1 million related to the processing of our crude oil production at Evi as a result of the operational issues at a jointly owned oil battery, discussed above. Transportation and processing costs for the year ended December 31, 2011 were $17.3 million compared to $11.1 million for the year ended December 31, 2010. The increase was primarily due to additional capacity purchased for our Narraway/Ojay production as well as higher fees for gathering and processing in the area.

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

General and administrative costs primarily consist of the salaries and related benefit costs for our employees, professional fees and office lease costs. General and administrative costs increased in 2012 compared to 2011 primarily as a result of increases in staffing to absorb the additional corporate functions that were historically provided to us by Forest, our former parent company, as well as a full year of costs related to being a public company. General and administrative costs increased in the year

ended December 31, 2011 compared to the corresponding period in 2010 as a result of direct costs we incurred in preparation for our IPO.

Until the date of the Distribution, stock-based compensation costs primarily represented the amortization of the value of stock options and performance and phantom stock units awarded by Forest as part of its incentive plans. Beginning in 2011, we established our own stock-based compensation plans. Stock-based compensation costs relate to amortization of the fair value of units granted under these long-term incentive plans. These plans include units granted in 2011, which will primarily be settled in cash and are accounted for as a liability, the fair value of which is adjusted each reporting period based on our share price. The costs also include units issued in 2012, all of which are accounted for as stock-settled units, the fair value of which was determined and fixed at their grant date.

In addition to higher stock-based compensation costs as a result of increases in staffing, costs were also higher for the year ended December 31, 2012 compared to 2011 due to a decrease in Forest's stock price during 2011 which had lowered stock-based compensation costs for that year. Our increased stock-based compensation costs in 2012 were partially offset by a recovery of stock-based compensation costs for the cash-settled units granted in 2011 as a result of the decrease in our stock price during 2012.

The decrease in stock-based compensation costs for the year ended December 31, 2011, compared to the same period in 2010, was primarily due to the decrease in Forest's stock price during 2011, partially offset by the additional costs associated with accelerated vesting resulting from completion of the Distribution.

Management fees charged by Forest were intended to cover various costs incurred by Forest on our behalf, including, among other items, legal, accounting and treasury services, and insurance costs. The increase in the year ended December 31, 2011 compared to the corresponding period in 2010 was primarily due to the costs Forest incurred in preparation for our IPO and the Distribution, which we were obligated to reimburse Forest under the separation and distribution agreement. This includes charges from Forest under the transition services agreement of $0.3 million. No management fees were paid to Forest in 2012.

Under the full cost method of accounting, general and administrative costs directly related to exploration and development activities are capitalized. The percentage of general and administrative costs capitalized ranged from 26% to 38% during the periods presented.

The following table summarizes DD&A expense incurred during the periods indicated.

For the year ended December 31, 2012, DD&A was $116.2 million, or $3.81 per Mcfe, compared to $85.8 million, or $2.50 per Mcfe, in 2011 and $65.8 million or $2.33 per Mcfe in 2010. The increases

were primarily due to the addition of proved reserves to our depletable base at higher per-unit rates, since the majority of our capital expenditures are being directed towards crude oil projects and the capital costs associated with crude oil development are higher than natural gas. The per-unit rate also increased in 2012 due to the decrease in our natural gas proved reserve volumes which occurred as a result of the reduction in the 12-month average trailing natural gas price.

Under the full cost method of accounting, the carrying amount of our oil and natural gas properties is subject to a ceiling test performed quarterly, as prescribed by the U.S. Securities and Exchange Commission ("SEC"). A ceiling test impairment is recognized in net earnings when the carrying amount of a cost center exceeds the cost center ceiling. We operate only one cost center, the carrying amount of which includes capitalized costs of proved oil and natural gas properties, net of accumulated depletion and the related deferred income taxes. The cost center ceiling is the sum of the estimated after-tax future net cash flows from proved reserves, using the 12-month average trailing prices and unescalated future development and production costs, discounted at 10 percent, plus unproved property costs. The 12-month average trailing price is calculated as the average of the price on the first day of each month within the trailing 12-month period. Any excess of the carrying amount over the calculated ceiling amount is recognized as an impairment in net earnings.

In performing our quarterly ceiling tests during 2012, we updated our internal estimates of proved oil and natural gas reserves, and the present value of future net revenue from those reserves using AECO natural gas prices and Edmonton Par crude oil prices, which are typically lower than the corresponding NYMEX Henry Hub natural gas prices and WTI crude oil prices, respectively. The table below summarizes the 12-month average trailing prices.

As noted in the above table, the 12-month average trailing natural gas price continued to decline in 2012, which reduced our proved reserve volumes. The lower commodity prices and reserve volumes also reduced the estimate of the present value of future net revenue from proved reserves, which resulted in non-cash ceiling test write-downs of $271.7 million ($204.1 million after tax) in 2012. During the years ended December 31, 2011 and 2010, we did not recognize any ceiling test write-downs.

We believe that the discounted after-tax future net cash flows from proved reserves required to be used in the ceiling test calculation are not indicative of the fair value of our crude oil and natural gas properties or of the future net cash flows expected to be generated from such properties. The discounted after-tax future net cash flows do not include the fair market value of probable or possible crude oil or natural gas reserves. Also, there is no consideration given to the effect of future changes in commodity prices. We manage our business using estimates of reserves and resources based on forecast prices and costs.

In the fourth quarter of 2012, our market capitalization remained lower than the book value of our net assets, and therefore we performed both steps of the goodwill impairment test. Our estimated fair

value was determined using a combination of comparable external market transactions and an internal estimate of the present value of future cash flows using the income approach.

After the estimated fair value was assigned to our other assets and liabilities, we determined that the fair value of goodwill was nil. Accordingly, we recognized a $17.3 million goodwill impairment loss in the consolidated statements of operations for the year ended December 31, 2012.

The following table summarizes interest expense incurred during the periods indicated.

From December 2009 through the completion of our IPO on June 1, 2011, we primarily utilized borrowings from Forest to supplement our working capital needs. On June 1, 2011, we used the proceeds from our IPO and borrowings under our bank credit facility to repay the intercompany note and advances to Forest. In February 2012, we issued the Senior Notes and significantly reduced the borrowings under our bank credit facility.

The increase in interest costs in 2012 compared to 2011 was due to a higher weighted average interest rate on our borrowings, as well as a higher level of borrowings. The interest rate on our Senior Notes is fixed at 10.375%, while the interest rate on our bank credit facility, which floats based on market interest rates, was less than 4% in 2012. The increase in interest costs for the year ended December 31, 2011 compared to the comparable period in 2010 was primarily due to an increase in the level of borrowings, partially offset by lower average interest rates on the note payable to Forest.

Interest costs capitalized in 2011 and 2010 relate to our investment in unproved acreage in the Narraway/Ojay fields as a result of our leasing activities in late 2009 and early 2010. Under the full cost method of accounting, significant investments in unproved properties on which exploration or development activities are in progress are assets qualifying for capitalization of interest costs.

The table below includes unrealized and realized losses (gains) on derivatives recognized during the periods indicated.

We enter into derivative instruments to manage our exposure to commodity price risk caused by fluctuations in commodity prices and to protect and provide certainty on a portion of our cash flows. We realized gains of $29.6 million and $8.4 million on these instruments in 2012 and 2011, respectively, primarily due to the NYMEX Henry Hub and NYMEX WTI prices being significantly lower than the prices in our contracts. The unrealized gains at December 31, 2012 were also primarily due to the forward NYMEX WTI prices being lower than the prices in our contracts. We recognize changes in the fair value of outstanding derivative instruments at each balance sheet date as unrealized gains or losses. Changes in this fair value are related to the volatility of the forward prices for commodities as well as to changes in the balance of unsettled contracts between periods. Our credit risk exposure related to derivative instruments was the unrealized net asset of $4.4 million at December 31, 2012.

In 2012, we recorded foreign currency exchange gains of $0.9 million. The gains primarily related to the translation of the Senior Notes from U.S. to Canadian dollars. The Canadian dollar strengthened in the period between February 14, 2012, which was the date we issued the Senior Notes, and December 31, 2012. In 2011, we realized foreign currency exchange gains of $32.7 million on the repayment of amounts due to Forest since the note and advances had been denominated in U.S. dollars, and the Canadian dollar had strengthened in recent years. In 2010, we recognized $13.9 million of foreign currency exchange gains, primarily on the translation of the outstanding indebtedness and advances, which were also due to a strengthening of the Canadian dollar. See Part I, "Item 1A. Risk Factors—Risks Related to Our Business—Our business, financial condition, cash flows and results of operations may be adversely affected by foreign currency fluctuations and economic and political developments."

In the fourth quarter of 2012, we recognized an impairment of $0.5 million on our capital inventory related to material and supplies purchased for natural gas development projects. Our near-term capital programs are expected to focus on crude oil development and therefore we concluded that it was appropriate to reduce the carrying value of inventory related to natural gas projects down to its current estimate of fair value, based on estimated selling prices. In the fourth quarter of 2011, we also recognized an impairment of $2.3 million on our capital inventory on the basis that our 2012 capital program would be focused on crude oil development.

Our total income tax and effective income tax rates for the periods indicated are as follows.

Our combined federal and provincial statutory tax rate for the periods presented ranged from 25% to 28%, however, our effective tax rate varied from 19% to 34%. Our effective income tax rate in any period is a function of the relationship between total income tax expense and the amount of earnings before income taxes for the period. The effective income tax rate differs from the statutory tax rate as it takes into consideration permanent differences (such as stock-based compensation that will be settled in shares of common stock of the Company), adjustments for changes in income tax rates and other income tax legislation, valuation allowances on our deferred tax assets, foreign currency exchange gains and losses taxed at 50% of the statutory rate as well as the impact of enacted statutory income tax rate reductions in Canada.

At December 31, 2012, we had a deferred income tax asset primarily as a result of the ceiling test write-downs recognized in 2012, which reduced the net book value of our proved properties. We recorded a valuation allowance against this asset since it was determined that it is more likely than not that we will not be able to realize the benefit.

We have Canadian tax pools relating to the exploration, development and production of oil and natural gas that are available to reduce future Canadian income taxes. These tax pool balances are deductible on a declining balance basis ranging from 4% to 100% of the balance annually, and are composed of costs incurred for oil and natural gas properties, and developmental and exploration expenditures, as follows.

Other federal Canadian tax pools available to reduce future income taxes were approximately $10.2 million at December 31, 2012, of which $2.1 million are deductible on a declining balance basis ranging from 10% to 100% of the balance annually, and $8.1 million are deductible over the next four years. Other provincial tax pools available to reduce future income taxes were approximately $39.8 million at December 31, 2012. At December 31, 2012, we also had U.S. federal operating loss carryforwards totaling US$3.5 million, of which US$2.6 million is scheduled to expire in 2031 and US$0.9 million is scheduled to expire in 2032.

Our exploration, development and acquisition activities require us to make significant operating and capital expenditures, and we have historically used the following as our primary sources of liquidity:

Changes in the market prices for oil, natural gas and NGLs directly impact our level of cash provided by operating activities. During the year ended December 31, 2012, natural gas comprised approximately 72% of our production. As a result, our operations and cash flows have historically been more sensitive to fluctuations in the market price for natural gas than in the market price for oil. Since June 2011, we have entered into derivative instruments to manage our exposure to commodity price risk caused by fluctuations in commodity prices, which protect and provide certainty on a portion of our cash provided by operating activities. As of March 8, 2013, we had entered into commodity swaps to hedge approximately 3,000 bbls/d of crude oil and commodity collars to hedge approximately 30,000 MMBtu/d of natural gas (total of 17.5 Bcfe) for 2013. This level of hedging will provide a measure of certainty of the cash flows that we expect to receive for a portion of our production. In the future, we may determine to increase or decrease our hedging positions. See Part II, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk" in our Form 10-K for more information on our derivative contracts.

We have no debt maturities until 2016. In August 2012, we announced that we were actively considering methods of debt reduction, including the divestiture of non-core assets. In 2012, we completed the sale of certain non-core natural gas weighted properties for cash proceeds after closing adjustments of $97.5 million. We are also considering potential transactions to accelerate the value of certain of our core assets, such as farm-ins and joint ventures. However, no assurance can be made regarding our ability to identify or complete any such potential transactions.

As of December 31, 2012, our bank credit facility had a borrowing base of $275 million and remaining borrowing capacity of $125.0 million (after deducting $2.0 million of outstanding letters of credit). We reduced the borrowings outstanding under our bank credit facility by $183.0 million during 2012, primarily through the issuance of the Senior Notes in February 2012. As of March 8, 2013, we had $151 million outstanding under our bank credit facility at a weighted average interest rate of 3.55% and remaining borrowing capacity of $122 million (after deducting $2.0 million of outstanding letters of credit).

We expect the public and private equity and debt capital markets to serve as another source of liquidity. For example, in June 2011 we completed our IPO for net proceeds of $173 million. Our ability to access the equity capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our equity securities, prevailing commodity prices and other macroeconomic factors outside of our control. In February 2012, we completed an offering of Senior Notes for net proceeds of $192 million. However, given our focus on reducing balance sheet leverage, we do not expect to utilize debt markets in the near term.

In connection with our IPO, we entered into a tax-sharing agreement with Forest under which, for a two year period following the Distribution, we will be restricted in our ability, among other things, to divest of 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 (in either case, taking into account shares issued in our IPO). Therefore, until September 30, 2013, we may take certain actions otherwise subject to these restrictions 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 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 Distribution.

Net cash provided by operating activities, net cash used in investing activities and net cash provided by financing activities for the years ended December 31, 2012, 2011 and 2010 were as follows.

Net cash provided by operating activities is primarily affected by sales volumes, commodity prices and production costs. The decrease in net cash provided by operating activities in 2012 compared to 2011 was primarily due to lower revenues because of lower natural gas prices as well as higher cash-based expenditures including interest and lease operating expenses, partially offset by higher realized gains on derivative instruments. The increase in net cash provided by operating activities in 2011 compared to 2010 was primarily due to higher production volumes and liquids prices, partially offset by lower natural gas prices.

We had a working capital deficit of approximately $23.0 million at December 31, 2012, compared to $30.1 million at December 31, 2011. The decrease was primarily due to lower accounts payable and accrued liabilities as a result of a reduced level of capital expenditures, partially offset by lower accounts receivable due to lower revenues and a reduction in the net asset related to derivative instruments.

Net cash used in investing activities primarily comprises the exploration and development of oil and natural gas properties, net of the divestiture of oil and natural gas properties. The components of net cash used in investing activities were as follows.

The cash paid for exploration, development and acquisition costs as reflected in the statements of cash flows differs from the table below under "Capital Expenditures" due to the timing of when the capital expenditures are incurred and when the actual cash payment is made. The decrease in net cash used in investing activities in 2012 compared to 2011 was due to significantly lower capital expenditures as well as cash proceeds received from the divestiture of certain non-core assets. The increase in net cash used by investing activities in 2011 compared to 2010 was due to the acquisition of additional interests in the Narraway/Ojay area and increased exploration and development expenditures in the Evi and Narraway/Ojay areas. There were no significant proceeds from the divestiture of non-core assets in 2011.

The following table summarizes costs related to our capital program for the periods presented.

Primary factors impacting the level of our capital expenditures include oil, natural gas and NGL prices, the volatility in these prices, the cost and availability of field services, general economic and market conditions and weather disruptions. In 2012, although our capital expenditures were lower than the previous two years in order to focus on reducing our level of debt, we drilled 31.1 net wells, completed 31.6 net wells and tied-in 38.6 net wells. Our capital program was primarily focused on light oil development in the Evi area of Alberta. However, as part of our New Ventures activity in Alberta,

we also acquired $10.3 million of undeveloped land which we expect will support future light oil exploration and development. In 2011, we acquired additional interests in certain natural gas properties in the Narraway/Ojay area for $74.4 million and also increased our drilling activity with a focus on light oil and natural gas development projects. In 2010, our capital expenditures were related to the development of both crude oil and natural gas properties.

In September 2012, we completed the sale of non-core oil properties in the Kaybob area of Alberta for cash proceeds after closing adjustments of approximately $8.0 million, and in October 2012, we completed the sale of non-core natural gas properties in the Kaybob area of Alberta for cash proceeds after closing adjustments of approximately $10.4 million. In December 2012, we completed the sale of non-core properties in the Wild River area of Alberta for cash proceeds after closing adjustments of approximately $79.1 million. At the time that the divestitures occurred, the properties had a combined net production rate of approximately 20 million cubic feet equivalent per day ("MMcfe/d"). During the year ended December 31, 2012, we generated approximately 21.0 MMcfe/d of net sales volumes and $24.2 million of revenue, and incurred production expenses of approximately $9.6 million, which contributed $14.6 million to Adjusted EBITDA, from the properties divested in 2012.

In February 2013, we also completed the sale of additional non-core assets in the Herronton area of Alberta for cash proceeds after closing adjustments of approximately $13.9 million.

In 2012, we increased our Evi land position to 89,120 gross (82,015 net) acres primarily through purchases at Crown land sales. The acquired acreage increased our existing contiguous land holdings in the Evi field and our future light oil drilling inventory. We also acquired $10.3 million of undeveloped land as part of our New Ventures activity in Alberta.

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 in the Narraway field to 100% from approximately 50% and provided us with additional capacity in gathering systems and a natural gas plant in the Narraway field. This acquisition also increased our acreage position by approximately 85,100 gross (35,700 net) acres.

	Year Ended December 31,

	2012			2011			2010
	(In thousands)
Net proceeds from issuance of long-term debt	$	192,052			—			—
Debt issuance costs		(1,295	)		(4,700	)		—
Proceeds from bank borrowings	$	3,086,000		$	2,531,000		$	151,000
Repayments of bank borrowings		(3,269,000	)		(2,200,000	)		(151,000	)
Proceeds from Forest Oil Corporation		—			106,512			128,703
Repayments to Forest Oil Corporation		—			(368,385	)		(1,264	)
Cash distribution to Forest Oil Corporation		—			(28,711	)		—
Proceeds from issuance of common stock, net of offering costs		—			173,086			—
Change in bank overdrafts		2,866			440			1,566
Proceeds from sale-leaseback		—			7,723			—
Capital lease payments		(1,156	)		(829	)		—
Other, net		2			(43	)		(60	)

Net cash provided by financing activities	$	9,469		$	216,093		$	128,945

In February 2012, we issued Senior Notes and used the net proceeds to reduce borrowings outstanding under our bank credit facility. In 2011, net cash provided by financing activities was primarily derived from net proceeds from the issuance of common stock in our IPO and bank borrowings, both of which were used to repay amounts owing to Forest. Net cash provided by financing activities for 2010 primarily comprised borrowings from Forest.

On March 18, 2011, we entered into a $500 million credit facility among Lone Pine, as parent, LPR Canada, as borrower, and a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. Our bank credit facility became effective upon the closing of our IPO and replaced the existing LPR Canada bank credit facility at such time. Our bank credit facility will mature on March 18, 2016. Availability under our bank credit facility is governed by a borrowing base, which was $275 million at March 8, 2013. The determination of the borrowing base is made by the lenders, in their sole discretion, taking into consideration the estimated value of LPR Canada's oil and natural gas properties in accordance with the lenders' customary practices for oil and gas loans. The borrowing base will be redetermined semi-annually, and the available borrowing amount under our bank credit facility could increase or decrease based on such redetermination. In September 2011, we entered into an amendment to increase the borrowing base from $350 million to $425 million, at the first redetermination of the borrowing base. At December 31, 2011, our bank credit facility had a borrowing base of $425 million, which was automatically reduced to $375 million in February 2012 upon the completion of our offering of the Senior Notes. In May 2012, the borrowing base was reaffirmed at $375 million and on October 18, 2012, the borrowing base was reduced to $325 million in the second semi-annual redetermination to account for the divestiture of $19 million of non-core assets together with a slower development schedule associated with our revised 2012 capital budget. On December 14, 2012, the borrowing base was further reduced by $50 million to $275 million in connection with the completion of the Wild River divestiture. The next scheduled redetermination of the borrowing base is expected to occur on or about May 1, 2013. In addition to the scheduled semi-annual redeterminations,

we and the lenders each have discretion at any time, but not more often than once during any calendar year, to have the borrowing base redetermined.

At December 31, 2012, borrowings under our bank credit facility decreased to $148.0 million from $331.0 million at December 31, 2011, primarily due to the use of proceeds from the issuance of the Senior Notes. As of March 8, 2013, we had $151 million outstanding under our bank credit facility at a weighted average interest rate of 3.55% and remaining borrowing capacity of $122 million (after deducting $2.0 million of outstanding letters of credit).

The borrowing base is also subject to change in the event (1) Lone Pine or any of its restricted subsidiaries issue senior unsecured notes, in which case the borrowing base will immediately be reduced by an amount equal to 25% of the stated principal amount of such issued senior unsecured notes, excluding any senior unsecured notes that Lone Pine or any of its restricted subsidiaries may issue to refinance then-existing senior notes, (2) LPR Canada divests of oil and natural gas properties included in the borrowing base having a fair market value in excess of 10% of the borrowing base then in effect or (3) if there is a casualty event related to oil and natural gas properties included in the borrowing base. The borrowing base is subject to other automatic adjustments under our bank credit facility. A lowering of the borrowing base could require us to repay indebtedness in excess of the borrowing base in order to cover a deficiency.

Borrowings under our bank credit facility bear interest at one of two rates that we elect. Borrowings bear interest at a rate that may be based on either:

Our bank credit facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends and mergers and acquisitions and also includes a financial covenant. Our bank credit facility provides that Lone Pine will not permit its ratio of total debt outstanding to Adjusted EBITDA for a trailing 12-month period to be greater than 4.0 to 1.0. For purposes of calculating this ratio, Adjusted EBITDA is reduced by the Adjusted EBITDA that has been generated by any divested property that has a transaction value in excess of US$25 million. As a result of our 2012 divestiture program, Adjusted EBITDA for the year ended December 31, 2012 has been reduced from $106.0 million to $94.1 million, resulting in a ratio of approximately 3.8 to 1.0 at December 31, 2012. As a result of our debt to Adjusted EBITDA ratio at December 31, 2012, this financial covenant acts to effectively limit our available borrowing capacity under our bank credit facility to an amount lower than our stated available borrowing base.

Under certain conditions, amounts outstanding under our bank credit facility may be accelerated. Bankruptcy and insolvency events with respect to Lone Pine, LPR Canada or certain of Lone Pine's or LPR Canada's subsidiaries will result in an automatic acceleration of the indebtedness under our bank credit facility. Subject to notice and cure periods, certain events of default under our bank credit facility will result in acceleration of the indebtedness under the facility at the option of the lenders. Such other events of default include non-payment, breach of warranty, non-performance of obligations under our bank credit facility (including the financial covenant), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control and a failure of the liens securing our bank credit facility.

Our bank credit facility is collateralized by the assets of LPR Canada and certain of its restricted subsidiaries. Under our bank credit facility, LPR Canada is required to mortgage and grant a security

interest in 75% of the present value of the proved oil and natural gas properties and related assets of LPR Canada and its restricted subsidiaries. LPR Canada is required to pledge, and has pledged, the stock of its subsidiary to the lenders to secure our bank credit facility. Under certain circumstances, LPR Canada could be obligated to pledge additional assets as collateral. The stock of all of Lone Pine's subsidiaries has been pledged to the lenders to secure our bank credit facility. Lone Pine and certain of its other subsidiaries have guaranteed the obligations of LPR Canada under our bank credit facility.

Of the $500 million total nominal amount under our bank credit facility, JPMorgan Chase Bank, N.A., Toronto Branch and eight other banks hold 100% of the total commitments, with JPMorgan Chase, N.A., Toronto Branch and one other lender each holding 16.7%, three lenders holding 11.7% each, one lender holding 10%, one lender holding 8.3% and the other lenders holding 6.7% each of the total commitments.

From time to time, we and our affiliates have engaged or may engage in other transactions with a number of the lenders under our bank credit facility. Such lenders or their affiliates have served as underwriters in connection with our IPO or initial purchasers in connection with our offering of the Senior Notes, serve as counterparties to LPR Canada's commodity derivative agreements and may, in the future, act as agent or directly purchase LPR Canada's production.

Since the process for determining the borrowing base under our bank credit facility involves evaluating the estimated value of our oil and natural gas properties using pricing models determined by the lenders at that time, we believe that if there is a further decline in commodity prices, there may be a decrease in the available borrowing amount at the time of the next scheduled redetermination. A significant reduction in our borrowing base, together with the covenants and other restrictions in our bank credit facility, may reduce our ability to finance future operations or capital needs or expand our business activities. 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 a waiver or amendment from our lenders, refinance our bank credit facility, sell assets or issue 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.

If our revenue and cash flows decrease in the future as a result of a further deterioration in domestic and global economic conditions, including a significant decline in crude oil prices or a continuation of depressed natural gas prices, or if we experience a significant reduction in our borrowing base under our bank credit facility, we may further decrease our level of capital spending. A further reduction in our capital expenditures could also result in a corresponding reduction in our cash flows, which could in turn result in a reduction of Adjusted EBITDA and a breach of the financial covenant described above. In the event that we are in default of the financial covenant under the bank credit facility, we could request a waiver of the financial covenant from the syndicate of banks. Should the banks deny our request to waive the covenant requirement, the outstanding borrowings under the bank credit facility would become payable on demand and would be reclassified as a component of current liabilities on our Consolidated Balance Sheets. See Part I, "Item 1A. Risk Factors" in our Form 10-K for a discussion of the risks and uncertainties that affect our business and financial and operating results.

On February 14, 2012, LPR Canada issued US$200.0 million aggregate principal amount of 10.375% senior notes due 2017 (the "Senior Notes"). Interest is payable on the Senior Notes semi-annually in arrears on each February 15 and August 15. The first interest payment was made on August 15, 2012. The Senior Notes are guaranteed on a senior unsecured basis by Lone Pine and all of

Lone Pine's subsidiaries other than LPR Canada (together, the "Guarantors"). These guarantees are full and unconditional, and joint and several among the Guarantors. After deducting the original issue discount and commissions, the issuance of the Senior Notes resulted in net proceeds to the Company of $192 million, which we used to partially repay borrowings outstanding under our bank credit facility.

The Senior Notes were issued pursuant to an indenture dated February 14, 2012 (the "Indenture"), among LPR Canada, the Guarantors and U.S. Bank National Association, as trustee.

On or prior to February 15, 2015, we may, from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of a public or private equity offering at a redemption price of 110.375% of the principal amount of the Senior Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Senior Notes issued under the Indenture remains outstanding after such redemption and the redemption occurs within 180 days after the closing of such equity offering. Prior to February 15, 2015, we may redeem all or part of the Senior Notes at a redemption price equal to the sum of (i) the principal amount thereof; plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after February 15, 2015, we may redeem all or part of the Senior Notes at redemption prices (expressed as percentages of principal amount of the Senior Notes) equal to 105.188% for the 12-month period beginning on February 15, 2015 and 100.00% for the 12-month period beginning on February 15, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the Senior Notes.

The Indenture contains customary covenants that restrict our ability to: (i) sell assets, including equity interests in subsidiaries; (ii) pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred stock; (v) create or incur certain liens; (vi) make certain acquisitions and investments; (vii) redeem or prepay other debt; (viii) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; (ix) consolidate, merge or transfer all or substantially all of our assets; (x) engage in transactions with affiliates; (xi) create unrestricted subsidiaries; (xii) enter into sale and leaseback transactions; or (xiii) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from both of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the Indenture) has occurred and is continuing, many of these covenants will terminate. The Indenture also contains customary events of default.

On November 2, 2012, LPR Canada completed an exchange offer whereby we offered to exchange our privately-placed Senior Notes for like principal amounts of 10.375% Senior Notes due 2017 that have been registered under the Securities Act of 1933, as amended. The exchange offer fulfilled our obligations under the registration rights agreement that we entered into as part of the February 2012 issuance.

We are aware that our outstanding Senior Notes have recently been trading at a discount to par value. In order to reduce future cash interest payments, as well as future amounts due at maturity or upon redemption, we may, from time to time, purchase such debt for cash, in exchange for common stock, or for a combination of cash and common stock, in each case in open market purchases and/or privately negotiated transactions. We will evaluate any such transactions in light of then-existing market conditions, taking into account our current liquidity and prospects for future access to capital. The amounts involved in any such transactions, individually or in the aggregate, may be material.

For the first two quarters of 2013, our Board of Directors has approved a capital budget of approximately $35 million focused on light oil development in the Evi area. Subject to the variability of

production levels and commodity prices that impact our operating cash flows, anticipated timing of our capital projects and unanticipated expenditures, we plan to fund the first half of our 2013 capital program with operating cash flows and proceeds from previously completed divestitures of non-core assets. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on available opportunities, industry conditions, net cash provided by operating activities and the availability of capital.

The following table summarizes our contractual obligations as of December 31, 2012.

	2013			2014			2015			2016			2017			Thereafter			Total

	(In thousands)
Bank credit facility(1)	$	5,910		$	5,910		$	5,910		$	149,243			—			—		$	166,973
Senior notes(2)		20,645			20,645			20,645			20,645			209,307			—			291,887
Operating leases(3)		2,037			2,065			2,014			1,992			2,076			8,545			18,729
Capital lease(4)		1,476			1,476			1,476			1,914			—			—			6,342
Unconditional purchase obligations(5)		4,269			2,821			2,427			1,811			917			—			12,245
Other liabilities(6)		56			54			57			60			62			15,586			15,875

Total contractual obligations	$	34,393		$	32,971		$	32,529		$	175,665		$	212,362		$	24,131		$	512,051

Sub-lease recoveries(7)		(432	)		(472	)		(472	)		(472	)		(472	)		(39	)		(2,359	)

(1): Bank credit facility amounts include the anticipated interest payments and commitment fees due under the terms of our bank credit facility using the interest rate in effect, borrowings outstanding and the borrowing base at December 31, 2012. Our bank credit facility matures in March 2016.
(2): Amounts include interest payments and principal repayments.
(3): Operating leases consist of leases for office facilities and vehicles.
(4): Our capital lease is for compressors and surface equipment.
(5): Unconditional purchase obligations consist of firm transportation commitments and the purchase of electricity.
(6): Other liabilities comprise post-retirement benefit obligations and AROs, for which neither the timing nor the amount of ultimate settlement can be precisely determined in advance. See "—Critical Accounting Policies, Estimates, Judgments and Assumptions" below for a more detailed discussion of the nature of accounting estimates involved in estimating AROs.
(7): Sub-lease recoveries relate to a portion of our operating leases for office facilities.

As of March 8, 2013, we did not have any off-balance sheet arrangements, as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See "Contractual Obligations" above and Note 13 to our audited consolidated financial statements for a description of our commitments and contingencies. We do not believe that any of these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.

The 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. The 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. The consolidated financial statements relating to the period subsequent to and including 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 wholly owned consolidated subsidiaries.

The accounting for our business is subject to special rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas activities: the full cost method and the successful efforts method. The differences between the two methods can lead to significant variances in the amounts reported in financial statements. We have elected to follow the full cost method, which is described below.

Since we operate in one country, Canada, under the full cost method, we maintain one cost center. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, dry holes and overhead directly related to exploration and development activities) are capitalized to this cost center. The fair value of estimated future costs of site restoration, dismantlement and abandonment activities is capitalized, and a corresponding ARO liability is recorded. Costs capitalized to the full cost center are depleted using the units-of-production method, based on conversion to common units of measure, using one barrel of oil as an equivalent to six thousand cubic feet of natural gas.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test each quarter for each cost center. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value-based measurement, but rather a standardized mathematical calculation. The test determines a limit, or ceiling, on the net book value of oil and natural gas properties. That limit is basically the after tax present value of the future net cash flows from proved oil and natural gas reserves, discounted at 10%. This ceiling is compared to the net book value of the oil and natural gas properties, reduced by any related net deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write-down is required. In 2012, we recorded ceiling test write-downs totaling $271.7 million before tax ($204.1 million after tax). We did not incur any ceiling test write-downs from January 1, 2010 through December 31, 2011.

In areas where the existence of proved reserves has not yet been determined, leasehold costs, seismic costs and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. Investments in unproved properties are not depleted, pending the determination of the existence of proved reserves. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to DD&A and the application of the ceiling limitation. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess properties

whose costs are not individually significant, such properties are grouped for purposes of assessing impairment. The amount of impairment is added to the costs to be amortized in the full cost pool.

Under the alternative successful efforts method of accounting, surrendered, abandoned and impaired leases, delay lease rentals, exploratory dry holes and overhead costs are expensed as incurred. Capitalized costs are depleted on a property-by-property basis. Impairments are also assessed on a property-by-property basis and are charged to expense when assessed.

The full cost method is used to account for our oil and natural gas exploration and development activities because we believe it appropriately reports the costs of our exploration programs as part of an overall investment in discovering and developing proved reserves.

Goodwill is not subject to amortization and therefore we perform an annual impairment assessment. In addition, we test goodwill for impairment if events or circumstances change between annual tests indicating a possible impairment.

In the first step of testing for goodwill impairment, we estimate the fair value of the reporting unit and compare the fair value with the carrying value of the net assets of the reporting unit. If the fair value of the reporting unit is greater than the carrying value of the net assets of the reporting unit, then no impairment is recorded. If the fair value is less than its carrying value, then we would perform a second step and determine the fair value of the goodwill. In this second step, the fair value of goodwill is determined by deducting the fair value of the reporting unit's identifiable assets and liabilities from the fair value of the reporting unit as a whole, as if that reporting unit had just been acquired and the purchase price were being initially allocated. If the fair value of the goodwill is less than its carrying value for a reporting unit, an impairment charge would be recorded to earnings in our consolidated statement of operations.

To estimate the fair value of the reporting unit, we primarily use an internal discounted cash flow model to value our total estimated reserves, which include proved, probable and possible reserves. This approach relies on significant judgments about the quantity of reserves, the timing of the expected production, the pricing that will be in effect at the time of production and the appropriate discount rates to be used. Our discount rate assumptions are based on an assessment of our weighted average cost of capital. Our estimate of the fair value of the reporting unit also considers external information and metrics, such as market transactions that are comparable to the composition of our oil and gas properties.

Our estimates of proved reserves are based on the quantities of oil and natural gas that geoscience and engineering data demonstrate, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, production and property taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent uncertainty in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units-of-production method to amortize our oil and natural gas properties, the quantity of reserves could significantly impact our DD&A expense. Our oil and natural gas properties are also subject to the ceiling test limitation (discussed above), based in part on the quantity and value of our proved reserves. See Part I, "Item 1. Business—Reserves" and the notes to our consolidated financial statements included elsewhere in this Form 10-K for more information regarding our estimated proved reserves as of December 31, 2012, 2011, 2010 and 2009.

We follow the liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the enacted income tax rates and laws expected to apply when the assets are realized and liabilities are settled. Current income taxes are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates and laws enacted at the end of the reporting period. The effect of a change in the enacted tax rates or laws is recognized in net earnings in the period of enactment.

Deferred income tax assets are routinely assessed for realizability. If it is more likely than not that deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets. We consider available positive and negative evidence when assessing the realizability of deferred tax assets including historic and expected future taxable earnings, available tax planning strategies and carry forward periods.

Our interim income tax expense is determined using an estimated annual effective income tax rate applied to year-to-date net earnings before income tax. The estimated annual effective income tax rate is impacted by the expected annual earnings along with the tax benefits and expenses resulting from items including any tax on divestitures and transactions and related pool adjustments and the non-taxable portions of capital gains or losses.

We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. A recognized tax position is initially and subsequently measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon settlement with a taxing authority.

Tax interpretations, regulations and legislation in the various jurisdictions in which we operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through the income tax expense arising from changes in deferred income tax assets or liabilities.

We have obligations to remove tangible equipment and restore locations at the end of the oil and natural gas production operations. Estimating the future restoration and removal costs, or ARO, is difficult and requires management to make estimates and judgments, because most of the obligations are many years in the future, and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

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

We use the income approach in determining the fair value of our derivative instruments, utilizing present value techniques for valuing our swaps and option-pricing models for valuing our collars, swaptions, puts and calls. Inputs to these valuation techniques include published forward prices, volatilities and credit risk considerations, including the incorporation of published interest rates and

credit spreads. We also utilize the counterparties' valuations to assess the reasonableness of our internal valuations. The values we report in our financial statements change as these estimates are revised to reflect changes in market conditions or other factors, many of which are beyond our control.

The accounting treatment for changes in fair value of a derivative instrument is dependent upon whether or not a derivative instrument is designated as a hedge or a trading instrument. If it is designated as a hedge, it may be classified as a cash flow hedge or a fair value hedge. Changes in fair value of a derivative designated as a cash flow hedge are recognized, to the extent the hedge is effective, in other comprehensive income until the hedged item or underlying is settled and then the gain or loss is recognized in earnings. Changes in fair value of a derivative instrument designated as a fair value hedge, to the extent the hedge is effective, have no effect on the consolidated statement of operations, because changes in fair value of the derivative offset the changes in fair value of the hedged item. Where hedge accounting is not elected, or if a derivative instrument does not qualify as either a fair value hedge or a cash flow hedge, changes in fair value are recognized in the statement of operations.

We have elected not to use hedge accounting to account for our derivative instruments and, as a result, all changes in fair value of our unsettled derivative instruments are recognized as unrealized gains or losses in our consolidated statements of operations. Gains or losses from settled derivative instruments are included in our consolidated statement of operations.

Due to the volatility of oil and natural gas prices and interest rates, the estimated fair values of our derivative instruments are subject to large fluctuations from period to period. See Part II, "Item 7A. Quantitative and Qualitative Disclosures about Market Risk" for a sensitivity analysis of the change in net fair values of our derivative instruments based on a hypothetical change in commodity prices.

For stock-based compensation that will be settled in stock, rather than cash, compensation cost is measured based on the fair value of the award on the grant date. The compensation cost is recognized net of estimated forfeitures over the requisite service period. GAAP requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. We utilize the Black-Scholes-Merton valuation model to measure fair value, which requires judgment with respect to expected life, volatility, expected returns and other factors.

Beginning in the fourth quarter of 2012, the method of depreciating certain gas-gathering assets was changed to the straight-line method from the units-of-production method. The change in method of depreciation was to better reflect the estimated useful life of these assets. As a result of the change in accounting estimate effected by a change in accounting principle, we began accounting for the new method of depreciation prospectively in the fourth quarter of 2012. In the fourth quarter of 2012, depreciation for these assets under the straight-line method was approximately $0.6 million higher than it would have been using the units-of-production method. If the straight-line method had been used for the full year of 2012, depreciation would have been approximately $2.1 million higher than using the units-of-production method.

In the first quarter of 2012, we adopted Accounting Standards Update 2011-04, Fair Value Measurement and Disclosure Requirements ("ASU 2011-04"), which revised the existing guidance on fair value measurement under GAAP as part of the FASB's joint project with the International Accounting Standards Board. Under the revised standard, we were required to provide additional disclosures about

fair value measurements, including information about the unobservable inputs and assumptions used in Level 3 fair value measurements, a description of the valuation methodologies used in Level 3 fair value measurements and the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. The adoption of ASU 2011-04 did not have a significant impact on our financial statements.

In the first quarter of 2012, we adopted Accounting Standards Update No. 2011-08, Intangibles—Goodwill and Other (Topic 350), Testing Goodwill for Impairment ("ASU 2011-08"), which permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount to determine whether it is necessary to perform the two-step goodwill impairment test. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step goodwill impairment test is unnecessary. However, if an entity concludes otherwise, it is required to perform the first step of the two-step goodwill impairment test, which may then lead an entity to perform the second step as well. Entities have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to the first step of the two-step goodwill impairment test. As a result of adopting ASU 2011-08, we will only consider qualitative factors for impairment testing purposes in our interim periods, but will continue to perform the full two-step goodwill impairment test at December 31 of each year.

In February 2013, the FASB issued Accounting Standards Update 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures about amounts reclassified out of accumulated other comprehensive income. The pronouncement is effective for annual reporting periods beginning after December 15, 2012 and will be applied prospectively. The amendments are not expected to affect our disclosures.

The FASB has issued Accounting Standards Update No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities and Accounting Standards Update 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which require disclosure of both gross and net information about certain financial instruments and transactions eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement. These pronouncements are effective for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We do not expect the adoption of these amendments to have a material impact on our financial statements.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12, Comprehensive Income, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 ("ASU 2011-12"), which defers indefinitely the requirements in Accounting Standards Update No. 2011-05, Comprehensive Income, Presentation of Comprehensive Income ("ASU 2011-05") to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income. The adoption of this authoritative guidance will not have an impact on our financial statements until ASU 2011-05 is finalized and issued by the FASB.

In addition to reporting net earnings as defined under GAAP, we also present Adjusted EBITDA, a non-GAAP measure calculated as net earnings (loss) before interest expense, income tax expense (recovery), DD&A expense, impairment of goodwill, impairment of assets, ceiling test write-downs of oil and natural gas properties, accretion of ARO, unrealized losses (gains) on derivative instruments

and foreign currency exchange (gains) losses. Adjusted EBITDA also excludes the stock-settled portion of stock-based compensation expense, as this amount 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 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, rating agencies, 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. Adjusted EBITDA does not account for these and other expenses and therefore its utility as a measure of our performance has material limitations. As a result of these limitations, our management does not view Adjusted EBITDA in isolation and uses other measurements, such as net earnings (loss) and revenues, to measure performance. In the first quarter of 2012, we revised the calculation of Adjusted EBITDA to exclude the amortization of deferred costs. Adjusted EBITDA for 2011 and 2010 has been restated to be consistent with the presentation used in 2012.

The following table reconciles net earnings (loss) to Adjusted EBITDA. Net earnings (loss) is the most directly comparable measure calculated and presented in accordance with GAAP.

	Year Ended December 31,

	2012			2011			2010
	(In thousands)
Net earnings (loss):	$	(274,535	)	$	34,803		$	32,825
Add back (deduct):
Interest expense		30,215			10,034			7,190
Income tax expense (recovery)		(74,952	)		17,724			7,911
Depreciation, depletion, and amortization		116,215			85,751			65,811
Impairment of goodwill		17,328			—			—
Impairment of inventory		538			2,262			—
Ceiling test write-down of oil and natural gas properties		271,749			—			—
Accretion of asset retirement obligations		1,305			1,071			1,073
Unrealized losses (gains) on derivative instruments		15,377			(19,786	)		—
Foreign currency exchange (gains) losses		(903	)		(4,976	)		(13,924	)
Stock-based compensation (stock-settled portion)		3,636			269			—

Adjusted EBITDA	$	105,973		$	127,152		$	100,886

We are exposed to market risk, including the effects of adverse changes in commodity prices, interest rates and foreign currency exchange rates as discussed below.

We produce and sell crude oil, natural gas and NGLs. As a result, our financial results are affected when prices for these commodities fluctuate, and the effects can be significant. We enter into derivative instruments to manage our exposure to commodity price risk and to protect and provide certainty on a portion of our cash flows. Under this strategy, we enter into contracts with counterparties who are participants in our bank credit facility. These arrangements, which are based on prices available in the

financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons.

In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published, third-party index if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our current swaps are settled in cash on a monthly basis. As of December 31, 2012, we had entered into the following swaps.

In connection with one of the commodity swaps above, we sold a call option to the counterparty in exchange for us receiving a premium fixed price on the commodity swap. The outstanding option as of December 31, 2012 was as follows.

We also enter into commodity collar agreements with third parties. A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only if the index price is below the floor price, and we pay the difference between the ceiling price and the index price only if the index price is above the ceiling price. The outstanding commodity collars as of December 31, 2012 were as follows.

The estimated fair value of all our commodity derivative instruments at December 31, 2012 was an asset of approximately $4.4 million.

Due to the volatility of oil, natural gas and NGL prices, the estimated fair values of our commodity derivative instruments are subject to large fluctuations from period to period. For example, a hypothetical 10% increase in the forward oil, natural gas and NGL prices used to calculate the fair

value of our commodity derivative instruments at December 31, 2012 would have decreased the fair value of our commodity derivative instruments at December 31, 2012 from a net asset of $4.4 million to a net liability of approximately $8.0 million. It has been our experience that commodity prices are subject to large fluctuations, and we expect this volatility to continue. Actual gains or losses recognized related to our commodity derivative instruments will likely differ from those estimated at December 31, 2012 and will depend exclusively on the price of the commodities on the specified settlement dates provided by the derivative contracts.

The changes that occurred in the fair values of our derivative contracts during the year ended December 31, 2012 were as follows.

As of March 8, 2013, 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 per MMBtu 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.

At December 31, 2012, we had $148 million in outstanding borrowings on our bank credit facility, and the weighted average interest rate on the facility was 3.54%. Given that the interest rate on the facility is based on market rates, we are exposed to interest rate risk on these borrowings. We have not entered into any derivative financial instruments to manage this risk. If market interest rates had been 0.5% higher during the year ended December 31, 2012, we would have incurred approximately $1.1 million of additional interest expense on the bank credit facility.

Although we do not have any exposure to interest rate risk on the Senior Notes, given that the interest rate is fixed for the term of the Senior Notes, changes in interest rates do affect the fair value of the Senior Notes. We are exposed to foreign currency exchange risk on the actual interest payments since these payments will be made in U.S. dollars.

Our most significant foreign currency exchange rate risk relates to the Senior Notes because they are denominated in U.S. dollars and we are exposed to foreign currency exchange rate risk on the translation and repayment of this debt as well as the interest payments every six months. We have not entered into any foreign currency forward contracts or other similar financial instruments to manage this risk.

We are also exposed to foreign currency exchange rate risk relating to 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.

If the exchange rate between the Canadian and U.S. dollar had been 10% higher/lower during the year ended December 31, 2012, this would have increased/decreased our earnings (loss) before income taxes by approximately $3.7 million.

We have audited the accompanying consolidated balance sheets of Lone Pine Resources Inc. and subsidiaries as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, stockholders' equity and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Lone Pine Resources Inc. and subsidiaries at December 31, 2012 and 2011, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Lone Pine Resources Inc. and subsidiaries' internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 14, 2013 expressed an unqualified opinion thereon.

We have audited Lone Pine Resources Inc. and subsidiaries' (collectively, the "Company") internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Lone Pine Resources Inc. and subsidiaries, maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Lone Pine Resources Inc. as of December 31, 2012 and 2011 and the related consolidated statements of operations, comprehensive income, stockholders' equity and cash flows for each of the years in the two year period ended December 31, 2012, and our report dated March 14, 2013 expressed an unqualified opinion thereon.

We have audited the accompanying consolidated statements of operations, comprehensive income, cash flows and stockholders' equity of Lone Pine Resources Inc. for the year ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of Lone Pine Resources Inc. for the year ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

LONE PINE RESOURCES INC.

CONSOLIDATED BALANCE SHEETS

(In thousands of Canadian dollars)

	December 31, 2012			December 31, 2011

ASSETS
Current assets:
Cash	$	28		$	276
Accounts receivable		16,502			28,804
Derivative instruments		4,409			19,786
Prepaid expenses and other current assets		4,947			5,560

Total current assets		25,886			54,426
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion		376,203			704,232
Unproved		148,956			141,332

Net oil and natural gas properties		525,159			845,564
Other property and equipment, net of accumulated depreciation and amortization		65,096			66,413

Net property and equipment		590,255			911,977
Goodwill		—			17,328
Other assets		6,662			8,570

	$	622,803		$	992,301

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Bank overdraft	$	4,872		$	2,006
Accounts payable and accrued liabilities		32,468			75,090
Accrued interest		7,742			—
Capital lease obligation		1,217			1,156
Deferred income taxes		—			4,946
Other current liabilities		2,564			1,292

Total current liabilities		48,863			84,490
Long-term debt		340,310			331,000
Asset retirement obligations		12,839			15,412
Deferred income taxes		—			69,981
Capital lease obligation		4,521			5,738
Other liabilities		1,308			1,818

Total liabilities		407,841			508,439
Stockholders' equity:
Common stock, 85,192,955 and 85,026,202 shares issued and outstanding		835			833
Capital surplus		984,438			978,880
Accumulated deficit		(770,494	)		(495,959	)
Accumulated other comprehensive income		183			108

Total stockholders' equity		214,962			483,862

	$	622,803		$	992,301

Commitments and contingencies (Note 13)

LONE PINE RESOURCES INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands of Canadian dollars, except per share amounts)

	Year Ended December 31,

	2012			2011			2010
Revenues:
Oil and natural gas	$	161,703		$	191,170		$	151,184
Interest and other		54			30			24

Total revenues		161,757			191,200			151,208
Costs, expenses and other:
Lease operating expenses		51,406			38,789			26,547
Production and property taxes		3,083			2,337			2,513
Transportation and processing		15,600			17,252			11,104
General and administrative		18,694			13,115			9,590
Depreciation, depletion and amortization		116,215			85,751			65,811
Ceiling test write-down of oil and natural gas properties		271,749			—			—
Impairment of goodwill		17,328			—			—
Interest expense		30,215			7,177			437
Interest expense on borrowings from Forest Oil Corporation		—			2,857			6,753
Accretion of asset retirement obligations		1,305			1,071			1,073
Foreign currency exchange gains		(903	)		(4,976	)		(13,924	)
Gains on derivative instruments		(14,272	)		(28,167	)		—
Other, net		824			3,467			568

Total costs, expenses and other		511,244			138,673			110,472

Earnings (loss) before income taxes		(349,487	)		52,527			40,736
Income tax expense (recovery)		(74,952	)		17,724			7,911

Net earnings (loss)	$	(274,535	)	$	34,803		$	32,825

Basic and diluted earnings (loss) per common share	$	(3.23	)	$	0.44		$	0.47

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands of Canadian dollars)

LONE PINE RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands of Canadian dollars)

	Year Ended December 31,

	2012			2011			2010
Operating activities:
Net earnings (loss)	$	(274,535	)	$	34,803		$	32,825
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		116,215			85,751			65,811
Amortization of deferred costs		2,399			1,095			411
Ceiling test write-down of oil and natural gas properties		271,749			—			—
Impairment of goodwill		17,328			—			—
Accretion of asset retirement obligations		1,305			1,071			1,073
Deferred income tax expense (recovery)		(74,952	)		17,724			7,911
Unrealized foreign currency exchange gains		(803	)		(4,976	)		(13,655	)
Unrealized losses (gains) on derivative instruments		15,377			(19,786	)		—
Stock-based compensation		3,371			269			—
Other, net		(1,640	)		2,459			(128	)
Changes in operating assets and liabilities:
Accounts receivable		12,302			4,322			(10,747	)
Prepaid expenses and other current assets		922			3,005			(4,111	)
Accounts payable and accrued liabilities		(16,222	)		19,284			(732	)
Accrued interest and other current liabilities		7,742			(24,198	)		8,723

Net cash provided by operating activities		80,558			120,823			87,381
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs		(184,833	)		(325,095	)		(208,869	)
Other fixed assets		(3,189	)		(12,841	)		(44,310	)
Proceeds from divestiture of assets, net		97,747			343			28,024

Net cash used in investing activities		(90,275	)		(337,593	)		(225,155	)
Financing activities:
Net proceeds from issuance of long-term debt		192,052			—			—
Debt issuance costs		(1,295	)		(4,700	)		—
Proceeds from bank borrowings		3,086,000			2,531,000			151,000
Repayments of bank borrowings		(3,269,000	)		(2,200,000	)		(151,000	)
Proceeds from Forest Oil Corporation		—			106,512			128,703
Repayments to Forest Oil Corporation		—			(368,385	)		(1,264	)
Cash distribution to Forest Oil Corporation		—			(28,711	)		—
Proceeds from issuance of common stock, net of offering costs		—			173,086			—
Change in bank overdrafts		2,866			440			1,566
Proceeds from sale-leaseback		—			7,723			—
Capital lease payments		(1,156	)		(829	)		—
Other, net		2			(43	)		(60	)

Net cash provided by financing activities		9,469			216,093			128,945
Effect of exchange rate changes on cash		—			380			—

Net decrease in cash		(248	)		(297	)		(8,829	)
Cash at beginning of year		276			573			9,402

Cash at end of year	$	28		$	276		$	573

Supplemental cash flow disclosures:
Interest paid during the year	$	19,805		$	7,723		$	479
Interest paid during the year on borrowings from Forest Oil Corporation	$	—		$	23,359		$	136
Income taxes paid during the year	$	—		$	—		$	—
Change in non-cash working capital related to property and equipment	$	26,417		$	13,748		$	4,636

LONE PINE RESOURCES INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands of Canadian dollars, except number of shares)

	Common Stock								Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)

	Common Stock					Capital Surplus									Total Stockholders' Equity
	Shares			Amount		Capital Surplus									Total Stockholders' Equity
	(In thousands)
Balances at December 31, 2009		2		$	—	$	267,260		$	3,769		$	(346	)	$	270,683
Comprehensive income (loss):
Net earnings (loss)		—			—		—			32,825			—			32,825
Other comprehensive income		—			—		—			—			236			236

Balances at December 31, 2010		2			—		267,260			36,594			(110	)		303,744
Stock dividend to Forest Oil Corporation		—			—		567,356			(567,356	)		—			—
Stock issued to Forest Oil Corporation for its contribution of its direct and indirect interests in Lone Pine Resources Canada Ltd.		70,000			687		(687	)		—			—			—
Elimination of common shares of Lone Pine Resources Canada Ltd.		(2	)		—		—			—			—			—
Cash distribution to Forest Oil Corporation		—			—		(28,711	)		—			—			(28,711	)
Issuance of common stock, net of offering costs and tax		15,000			146		172,940			—			—			173,086
Capital contribution from Forest Oil Corporation		—			—		414			—			—			414
Restricted stock issued (net of forfeitures)		26			—		—			—			—			—
Amortization of stock-based compensation		—			—		308			—			—			308
Comprehensive income (loss):
Net earnings (loss)		—			—		—			34,803			—			34,803
Other comprehensive income		—			—		—			—			218			218

Balances at December 31, 2011		85,026			833		978,880			(495,959	)		108			483,862
Issuance of common stock, net of tax		167			2		827			—			—			829
Amortization of stock-based compensation		—			—		5,603			—			—			5,603
Capital surplus related to vested stock-based compensation		—			—		(872	)		—			—			(872	)
Comprehensive income (loss):
Net earnings (loss)		—			—		—			(274,535	)		—			(274,535	)
Other comprehensive income		—			—		—			—			75			75

Balances at December 31, 2012		85,193		$	835	$	984,438		$	(770,494	)	$	183		$	214,962

Lone Pine Resources Inc. ("Lone Pine" or the "Company") is an independent oil and natural gas exploration, development and production company with operations in Canada. Its reserves, producing properties and exploration prospects are located in the provinces of Alberta, British Columbia and Quebec, and in the Northwest Territories. Lone Pine was incorporated on September 30, 2010 by Forest Oil Corporation ("Forest") in contemplation of an initial public offering by Lone Pine (the "IPO") of Lone Pine's common stock with Forest subscribing for one share of Lone Pine common stock. Lone Pine's predecessor, Lone Pine Resources Canada Ltd. ("LPR Canada"), formerly known as Canadian Forest Oil Ltd. ("CFOL"), was a wholly owned subsidiary of Forest and certain of Forest's other wholly owned subsidiaries and was originally acquired by Forest in 1996. Forest contributed its direct and indirect ownership interests in LPR Canada to Lone Pine in conjunction with the IPO in exchange for 69,999,999 shares of common stock of Lone Pine and $28.7 million in cash. The IPO was completed on June 1, 2011, with Forest retaining a controlling interest in Lone Pine, owning 70 million shares of Lone Pine common stock representing approximately 82% of the outstanding shares of Lone Pine common stock.

On September 30, 2011, Forest paid a special stock dividend to its shareholders of the 70 million shares of common stock of Lone Pine owned by Forest (the "Distribution").

These consolidated financial statements are presented in conformity with U.S. generally accepted accounting principles ("GAAP"). In these consolidated financial statements, unless otherwise indicated, all amounts are expressed in Canadian dollars. Lone Pine conducts operations in one industry segment, liquids and natural gas exploration, development and production, and in one country, Canada.

The consolidated financial statements reflect the financial position, results of operations, cash flows or other information of:

Certain amounts in prior years' financial statements have been reclassified to conform to the current year's financial statement presentation.

These consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. Substantially all of the Company's operations are conducted jointly with others. The consolidated financial statements reflect only Lone Pine's proportionate share of assets, liabilities, revenues and expenses. All intercompany accounts and transactions have been eliminated.

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could materially differ from amounts previously established. In the opinion of management, all adjustments have been made that are necessary for a fair presentation of the financial position of Lone Pine and the results of its operations, its cash flows and changes in its stockholders' equity for the periods presented.

The more significant areas requiring the use of assumptions, judgments and estimates relate to:

Business combinations are accounted for using the acquisition method. The acquired identifiable net assets are measured at their fair value at the date of acquisition. Any excess of the consideration transferred over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price below the fair value of the net assets acquired is recorded as a gain in net earnings. Associated transaction costs are expensed when incurred.

The Company's oil and natural gas operations are conducted in Canada and are accounted for using the full cost method of accounting. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, dry holes and overhead directly related to exploration and development activities) and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities are capitalized. Interest costs related to significant unproved properties that are under development are also capitalized to oil and natural gas properties.

Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed separately 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. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. If an impairment is identified, the amount of the impairment assessed is added to the costs to be amortized.

Under the full cost method of accounting for oil and natural gas activities, a ceiling test calculation is performed each quarter. The ceiling test is a limitation on capitalized costs prescribed by the Securities Exchange Commission ("SEC") Regulation S-X Rule 4-10. The ceiling test is not a fair-value based measurement. It is a standardized mathematical calculation using oil and natural gas prices based on the average of the first-day-of-the-month prices during the 12-month period prior to the reporting date. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for a cost center may not exceed the sum of: (1) the present value of future net revenue from estimated production of proved oil and natural gas reserves using the 12-month average trailing prices, excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and natural gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs.

Gains or losses on the sale of oil and natural gas properties are typically included in proved properties balances. These gains or losses are not recognized in earnings unless the sale significantly alters the relationship between capitalized costs and estimated proved oil and natural gas reserves attributable to a cost center.

The Company computes depletion of oil and natural gas properties on a quarterly basis using the unit-of-production method based on production for the period and estimates of proved reserve quantities. Future development costs related to properties with proved reserves are also included in the amortization base for computation of depletion.

Beginning in the fourth quarter of 2012, the method of depreciating certain gas-gathering assets was changed to the straight-line method from the units-of-production method. The change in method of depreciation was to better reflect the estimated useful life of these assets. As a result of the change in accounting estimate effected by a change in accounting principle, Lone Pine began accounting for the new method of depreciation prospectively in the fourth quarter of 2012. In the fourth quarter of 2012, depreciation for these assets using the straight-line method instead of the units-of-production method resulted in an increase to depreciation expense of approximately $0.6 million, or approximately $0.01 per share, which resulted in a decrease to net income and a decrease to proved oil and natural gas properties of the same amount. If the straight-line method instead of the units-of-production method had been used for the full year of 2012, depreciation expense would have increased approximately $2.1 million, or approximately $0.02 per share, resulting in an increase to net loss and a decrease to proved oil and natural gas properties of the same amount.

Furniture and fixtures, computer hardware and software, other equipment and leasehold improvements are depreciated on the straight-line or declining balance method based upon their estimated useful lives.

The carrying value of long-term assets, excluding goodwill and oil and natural gas properties but including other property and equipment, are assessed for impairment when indicators suggest that the carrying value of an asset or asset group may not be recoverable. If the carrying amount exceeds the sum of the undiscounted cash flows expected to result from the continued use and eventual disposition of the asset or asset group, an impairment is recognized in earnings for the excess of the carrying amount over its estimated fair value.

Leases entered into for the use of an asset are classified as either capital or operating leases. Capital leases transfer to the Company substantially all risks and benefits incidental to ownership of the leased item. Capital leases are also capitalized upon commencement of the lease term if the lease arrangement contains a bargain purchase option or ownership of the leased asset transfers at the end of the lease term. Assets recorded under capital leases are capitalized at the lower of the fair value of the leased asset or the present value of the minimum lease payments, and are amortized over the estimated useful life of the assets. Amortization of capitalized leased assets is included in depreciation, depletion and amortization in the consolidated statements of operations. All other leases are classified as operating leases and the payments are recognized on a straight-line basis over the lease term.

The Company recognizes revenues when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (1) persuasive evidence of an arrangement exists, (2) delivery has occurred, (3) the seller's price to the buyer is fixed or determinable and (4) collectability is reasonably assured. Revenue represents the Company's share and is recorded net of royalty payments.

Costs paid by the Company for the transportation and processing of natural gas, oil and natural gas liquids are recognized when the product is delivered and the services provided.

Lone Pine has cash and stock-based compensation plans under which it may issue stock options, restricted stock units, phantom stock units and performance units to its directors, officers and employees.

Stock options, restricted stock units, performance units and stock-settled phantom stock units are accounted for as equity instruments, which are measured at fair value on the grant date using the Black-Scholes-Merton valuation model and are not revalued at each reporting date. The fair value is recognized as compensation costs over the required service period with a corresponding increase recorded in contributed surplus. When these units or options vest, the par value of the shares is recorded as share capital.

Phantom stock units that may be settled in cash or in cash or shares are accounted for as liability instruments and are included in other current liabilities and other non-current liabilities on the consolidated balance sheets. The units are measured at fair value based on the market value of Lone Pine's common shares at each period end. The fair value is recognized as compensation costs over the required service period. Fluctuations in the fair value are recognized as compensation costs in the period in which they occur.

The Company recognizes stock-based compensation expense for all awards over the service period required to earn the award, which is the shorter of the vesting period or the time period an employee becomes eligible to retain the award at retirement or termination. Awards that have graded vesting service provisions are amortized on a straight-line basis over each requisite service period. As stock-based compensation expense recognized in the consolidated statements of operations is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if actual or estimated forfeitures differ from those estimates.

For stock-based compensation related to Forest's plans, costs were recorded in the amount payable to Forest as each was satisfied by Forest with Forest common stock. Phantom stock unit compensation cost was recorded to a separate liability since the units were settled in cash or shares. When phantom stock units were settled in stock, the liability was transferred to the amount payable to Forest since the units were settled by Forest with Forest common stock.

Transactions in a currency different from the Canadian dollar are translated into Canadian dollars at the period end rate for assets and liabilities, and at the average rate for the period for revenue and expenses, with gains or losses included in earnings. Gains or losses that arose from remeasuring Lone Pine's financial statements from U.S. dollars, the reporting currency at that time, into Canadian dollars, the functional currency, were included in accumulated other comprehensive income.

The Company recognizes deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. Income tax amounts related to different tax jurisdictions are not offset. The tax benefits of tax loss carryforwards and other deferred tax benefits are recorded as an asset to the extent that management assesses the utilization of such assets to be more likely than not. When the future utilization of some portion of the deferred tax asset is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax assets.

Original issue discounts and commissions associated with the issuance of long-term debt are recorded as a reduction in the carrying value of long-term debt and are amortized using the effective interest rate method over the term of the debt. Direct and incremental costs related to the issuance of

long-term debt are capitalized in other assets and amortized over the term of the debt using the straight-line method, which approximates the effective interest rate method.

Incremental costs associated with the Company's bank credit facility are capitalized in other assets and are amortized over the term of the specific facility.

Lone Pine's asset retirement obligations include costs related to the plugging of wells, the removal of facilities and equipment and site restoration of oil and natural gas properties. The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The liability is initially measured at fair value using the Company's credit-adjusted risk-free interest rate to discount the obligation and the same amount is capitalized to oil and natural gas properties. Subsequent to initial measurement, the asset retirement obligations are accreted each period to their present value. Capitalized asset retirement costs are depleted as a component of the full cost pool using the units-of-production method and recognized as part of depletion, depreciation and amortization on the consolidated statements of operations. If estimated future costs of asset retirement obligations change, an adjustment is recorded to both the asset retirement obligations and the oil and natural gas properties. Revisions to the estimated asset retirement obligation can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment. Actual expenditures incurred are charged against the accumulated asset retirement obligation.

Lone Pine sponsors a group savings plan ("GSP") for its employees. Prior to January 1, 2012, the Company also sponsored a defined contribution pension plan ("DCPP"). Pension expense for the GSP and DCPP is recorded as the benefits are earned by the employees.

The Company also sponsors a post-retirement benefits plan to certain retirees. The plan is closed to new entrants. Expense for the post-retirement benefits plan includes the cost of post-retirement benefits earned during the current year, the interest cost on post-retirement benefits obligations, the amortization of adjustments arising from plan amendments and the amortization of the excess of the net actuarial gain or loss over 10 percent of the benefit obligation. Amortization is recognized on a straight-line basis over a period covering the expected average remaining lifetime of the retired members covered by the plan.

The liability of the post-retirement benefits plan is actuarially determined using the projected unit credit actuarial cost method prorated on service and reflects the Company's best estimate of salary escalation, retirement ages of employees and expected future health care costs. The accrued benefit obligation is discounted using the market interest rate on high-quality corporate debt instruments as at the measurement date.

The Company accounts for its post-retirement benefits plan by recognizing the underfunded status of the plan as an asset or liability in its consolidated balance sheet and recognizing changes in that funded status in the year in which the changes occur through other comprehensive income.

The Company estimates losses on receivables based on known uncollectible accounts, if any, and historical experience of losses incurred.

Materials inventory, which primarily comprises materials and supplies that have been acquired for use in future capital development, is valued at the lower of cost or net realizable value on a first-in, first-out basis. Materials inventory is included on the consolidated balance sheet in unproved properties if it will be used for replacement parts for upstream operations or in other non-current assets if it will be held for resale.

Crude oil inventories are valued at the lower of cost and net realizable value on a first-in, first-out or weighted average cost basis. The cost of inventory includes all direct costs incurred in the normal course of business, including depletion. Net realizable value is the estimated selling price in the ordinary course of business less any expected selling costs. If the carrying amount exceeds net realizable value, a write-down is recognized in other, net on the consolidated statements of operations.

Goodwill is not subject to amortization, and therefore the Company performs an annual impairment assessment, which is performed in the fourth quarter of each year. In addition, the Company tests goodwill for impairment if events or circumstances change between annual tests indicating a possible impairment. The impairment assessment requires the Company to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. Although the Company bases its fair value estimate on assumptions it believes to be reasonable, those assumptions are inherently unpredictable and uncertain. If the fair value of goodwill is less than its carrying value, the difference is recognized as an impairment loss in the consolidated statements of operations.

The Company records all derivative instruments as either assets or liabilities at fair value, other than the derivative instruments that meet the normal purchases and sales exception. The Company has elected to not designate its derivative instruments as hedges and, therefore, records in earnings all changes in fair value of its derivative instruments, which are reported as a single line item on the consolidated statements of operations together with realized gains and losses on the derivative instruments. In the consolidated statements of cash flows, realized gains and losses are recorded within net cash provided by operating activities.

The Company considers cash equivalents to be highly liquid investments with original maturities of three months or less. Cash equivalents are recorded at cost, which approximates fair value. Bank overdraft balances are calculated as checks in excess of actual funds and are presented separately on the consolidated balance sheet as a current liability.

Basic earnings (loss) per share is computed using the two-class method by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. The two-class method of computing earnings per share is required for those entities that have participating securities or multiple classes of common stock. The two-class method is an earnings allocation formula that determines earnings per share for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. Holders of restricted stock issued under Lone Pine's stock incentive plan have the right to receive non-forfeitable cash dividends, participating on an equal basis with common stock. Holders of phantom stock units issued to directors under Lone Pine's stock incentive plan also have the right to receive non-forfeitable cash dividends, participating on an equal basis with common stock, while phantom stock units issued to employees do not participate in dividends. In summary, Lone Pine restricted stock units and director phantom stock units are participating securities, and earnings are allocated to both common stock and these participating securities under the two-class method. However, these participating securities do not have a contractual obligation to share in Lone Pine's losses. Therefore, in periods of net loss, none of the loss is allocated to these participating securities.

Diluted earnings per share is calculated giving effect to the potential dilution that would occur if outstanding stock options or potentially dilutive share units were exercised or converted to common stock. Potentially dilutive share units include phantom stock units settled in shares and unvested restricted stock units. For share units issued that may be settled in cash or shares at the Company's option, the share units are included in diluted earnings per share if the effect is dilutive. Shares issued or issuable under the Company's employee stock purchase plan ("ESPP") are included in basic earnings per share.

Diluted earnings per share is the more dilutive calculation using either the two-class method or the treasury stock method. Under the treasury stock method, diluted earnings (loss) per share is computed by dividing (a) net earnings (loss), adjusted for the effects of certain contracts, if any, that provide the issuer or holder with a choice between settlement methods, by (b) the weighted average number of common shares outstanding, adjusted for the dilutive effect, if any, of potential common shares. The treasury stock method assumes that the proceeds received from the exercise of all potentially dilutive instruments are used to repurchase common shares at the average market price.

In the first quarter of 2012, the Company adopted Accounting Standards Update 2011-04, Fair Value Measurement and Disclosure Requirements ("ASU 2011-04"), which revised the existing guidance on fair value measurement under GAAP as part of the U.S. Financial Accounting Standards Board's ("FASB") joint project with the International Accounting Standards Board. Under the revised standard, the Company is required to provide additional disclosures about fair value measurements, including information about the unobservable inputs and assumptions used in Level 3 fair value measurements, a description of the valuation methodologies used in Level 3 fair value measurements and the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. The adoption of ASU 2011-04 did not have a significant impact on the Company's financial statements.

In the first quarter of 2012, the Company adopted Accounting Standards Update No. 2011-08, Intangibles—Goodwill and Other (Topic 350), Testing Goodwill for Impairment ("ASU 2011-08"), which permits entities to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount to determine whether it is necessary to perform the two-step goodwill impairment test. If, after assessing the totality of events or circumstances, an entity determines it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, then performing the two-step goodwill impairment test is unnecessary. However, if an entity concludes otherwise, it is required to perform the first step of the two-step goodwill impairment test, which may then lead an entity to perform the second step as well. Entities have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to the first step of the two-step goodwill impairment test. As a result of adopting ASU 2011-08, the Company only considered qualitative factors for impairment testing purposes in its interim periods, but performed the full goodwill impairment test at December 31, 2012.

The FASB has issued Accounting Standards Update No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities and Accounting Standards Update 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which require disclosure of both gross and net information about certain financial instruments and transactions eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement. These pronouncements are effective for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. Lone Pine does not expect the adoption of these amendments to have a material impact on its financial statements.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12, Comprehensive Income, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 ("ASU 2011-12"), which defers indefinitely the requirements in Accounting Standards Update No. 2011-05, Comprehensive Income, Presentation of Comprehensive Income ("ASU 2011-05") to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income. The adoption of this authoritative guidance will not have an impact on the Company's financial statements until ASU 2011-05 is finalized and issued by the FASB.

Lone Pine's accounts receivable are primarily from purchasers of the Company's oil, natural gas and natural gas liquids, and from other exploration and production companies that own working interests in the properties the Company operates. At December 31, 2012, three (December 31, 2011—three) customers individually accounted for more than 10% of total accounts receivable, which accounted for $8.0 million (December 31, 2011—$12.3 million) of accounts receivable. Trade receivables are non-interest bearing. In determining the recoverability of trade receivables, the Company considers the age of the outstanding receivable and the credit worthiness of the counterparties.

The Company's materials inventory, which is included in other non-current assets on the consolidated balance sheets, comprised $3.7 million of materials and supplies at December 31, 2012 as compared to $3.5 million as of December 31, 2011. In the fourth quarters of 2012 and 2011, Lone Pine recognized reductions in the carrying value of certain inventory of $0.5 million ($0.4 million after tax) and $2.3 million ($1.7 million after tax), respectively, which were recorded in other, net on the consolidated statements of operations. The reductions were based on estimated selling prices and related primarily to material and supplies purchased for natural gas development projects. The Company was not required to take an impairment charge on the carrying value of its inventory during the year ended December 31, 2010.

During the year ended December 31, 2012, Lone Pine completed the divestiture of certain non-core properties in Alberta for proceeds of $97.5 million after closing adjustments. The proceeds reduced the net book value of oil and natural gas properties, and no gain or loss was recognized on any of the divestitures.

On April 29, 2011, the Company completed the acquisition of certain natural gas properties located in the Narraway/Ojay fields of Alberta and British Columbia. The acquisition increased the Company's working interests in certain properties already owned and operated by the Company in the area and provided additional capacity in gathering systems and a gas plant in the area. The business combination was accounted for using the acquisition method.

The following table outlines the final allocation of the purchase price for the properties acquired.

The consolidated statement of operations for the year ended December 31, 2011 included $7.9 million of revenue from these properties since their acquisition date of April 29, 2011 and reduced net earnings by approximately $0.8 million. The disclosure of supplemental pro forma information, which would disclose Lone Pine's consolidated revenue and net earnings as though the business combination had occurred January 1, 2010, is not available because it has been impractical for the Company to obtain sufficient information regarding the revenues and costs related to the properties in previous periods. As a result, the required pro forma disclosures would require significant estimates which could not be objectively or independently verified.

Under the full cost method of accounting, Lone Pine capitalized the following amounts for the years indicated.

In order to perform the quarterly ceiling test calculations during the year ended December 31, 2012, the Company used internal estimates of its proved oil and natural gas reserves, and the present value of future net revenue from those reserves. As a result of a decline in the 12-month average trailing natural gas price, the Company's quarterly internal estimates of proved undeveloped natural gas volumes decreased significantly during the year ended December 31, 2012. The decreases in natural gas volumes also reduced the present value of future net revenue from proved reserves and resulted in the Company recognizing ceiling test write-downs totaling $271.7 million before tax for the year ended December 31, 2012.

In order to perform the ceiling test calculations at December 31, 2012 and 2011, the Company used external estimates prepared by DeGolyer and MacNaughton, an independent petroleum engineering firm. No ceiling test write-downs were recorded for the years ended December 31, 2011 and 2010.

Net property and equipment consisted of the following as of the dates indicated:

	At December 31,

	2012			2011
	(In thousands)
Oil and natural gas properties:
Proved	$	1,966,218		$	1,907,987
Unproved		148,956			141,332
Accumulated depletion		(1,590,015	)		(1,203,755	)

Net oil and natural gas properties		525,159			845,564

Other property and equipment:
Gas gathering, furniture and fixtures, computer hardware and software and other equipment		75,754			75,060
Accumulated depreciation and amortization		(10,658	)		(8,647	)

Net other property and equipment		65,096			66,413

Total net property and equipment	$	590,255		$	911,977

The following table summarizes Lone Pine's investment in unproved properties as of December 31, 2012, by the year in which such costs were incurred.

Unproved oil and natural gas property costs include oil and natural gas property acquisitions and leasehold acquisition costs, and the Company expects that substantially all of these costs will be reclassified to proved properties within ten years. Unproved oil and natural gas property costs also include work-in-progress on various projects, including the Utica Shale in Quebec and the Liard Basin in the Northwest Territories, although the timing of reclassifying these costs to proved properties is unknown as of December 31, 2012.

The following table summarizes the activity for the Company's asset retirement obligations for the years indicated.

	Year Ended December 31,

	2012			2011
	(In thousands)
Balance at beginning of year	$	16,015		$	14,105
Accretion expense		1,305			1,071
Liabilities incurred		315			155
Liabilities assumed on acquisition		—			292
Liabilities settled		(940	)		(148	)
Divestiture of properties		(1,456	)		—
Revisions of estimated liabilities		—			540

Balance at end of year		15,239			16,015
Less: current portion of asset retirement obligations		2,400			603

Long-term asset retirement obligations	$	12,839		$	15,412

The current portion of asset retirement obligations is included in other current liabilities on the consolidated balance sheets.

On February 14, 2012, LPR Canada (the "Subsidiary Issuer"), an Alberta corporation and a wholly owned subsidiary of the Company, issued US$200 million aggregate principal amount of 10.375% senior notes due 2017 (the "Senior Notes"). Interest is payable on the Senior Notes semi-annually in arrears on each February 15 and August 15. The first interest payment was made on August 15, 2012. The Senior Notes are guaranteed on a senior unsecured basis by the Company (the "Parent Guarantor") and all of the Company's subsidiaries, other than LPR Canada (together with the Parent Guarantor, the "Guarantors"). These guarantees are full and unconditional, and joint and several among the Guarantors. After the original issue discount of 1.423% and commissions of approximately $4.9 million, the issuance of the Senior Notes resulted in net proceeds to the Company of $192 million. The Senior Notes have an effective interest rate of 11.40%.

The Senior Notes were issued pursuant to an indenture, dated February 14, 2012 (the "Indenture"), among LPR Canada, the Guarantors and U.S. Bank National Association, as trustee.

On or prior to February 15, 2015, LPR Canada may, from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of a public or private equity offering at a redemption price of 110.375% of the principal amount of the Senior Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Senior Notes issued under the Indenture remains outstanding after such redemption, and the redemption occurs within 180 days after the closing of such equity offering. Prior to February 15, 2015, LPR Canada may redeem all or part of the Senior Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. On or after February 15, 2015, LPR Canada may redeem all or part of the Senior Notes at redemption prices (expressed as percentages of principal amount of the Senior Notes) equal to 105.188% for the 12-month period beginning on February 15, 2015 and 100.00% for the 12-month period beginning on February 15, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the Senior Notes.

The Indenture contains customary covenants that restrict Lone Pine's ability and the ability of certain of its subsidiaries to: (i) sell assets, including equity interests in its subsidiaries; (ii) pay distributions on, redeem or repurchase its common stock or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred stock; (v) create or incur certain liens; (vi) make certain acquisitions and investments; (vii) redeem or prepay other debt; (viii) enter into agreements that restrict distributions or other payments from its restricted subsidiaries to it; (ix) consolidate, merge or transfer all or substantially all of its assets; (x) engage in transactions with affiliates; (xi) create unrestricted subsidiaries; (xii) enter into sale and leaseback transactions; or (xiii) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from both of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services, and no Default (as defined in the Indenture) has occurred and is continuing, many of these covenants will terminate.

On November 2, 2012, LPR Canada completed an exchange offer whereby it offered to exchange its privately-placed Senior Notes for like principal amounts of 10.375% Senior Notes due 2017 that have been registered under the Securities Act of 1933, as amended. The exchange offer fulfilled the Company's obligations under the registration rights agreement that it entered into as part of the February 2012 issuance.

Lone Pine maintains a $500 million credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch (the "Credit Facility"). The Credit Facility became effective upon the closing of the IPO and will mature on March 18, 2016. Availability under the Credit Facility is governed by a borrowing base, which was $275 million at December 31, 2012. At December 31, 2012, the Company had $148 million (December 31, 2011—$331 million) outstanding at a weighted average interest rate of 3.54%, and remaining borrowing capacity of $125 million (after deducting $2 million of outstanding letters of credit).

The determination of the borrowing base is made by the lenders, in their sole discretion, taking into consideration the estimated value of LPR Canada's oil and natural gas properties in accordance with the lenders' customary practices for oil and gas loans. The borrowing base is redetermined semi-annually, and the available borrowing amount under the Credit Facility could increase or decrease based on such redetermination. In September 2011, at the first redetermination of the borrowing base, Lone Pine entered into an amendment to increase the borrowing base to $425 million from $350 million. In February 2012, the borrowing base was automatically reduced to $375 million upon completion of the offering of the Senior Notes. In May 2012, the borrowing base was reaffirmed at $375 million and on October 18, 2012, the borrowing base was reduced to $325 million in the second semi-annual redetermination with the divestiture of non-core assets. On December 14, 2012, the borrowing base was reduced to $275 million with further divestitures of non-core assets. The next scheduled redetermination of the borrowing base is expected to occur on or about May 1, 2013. In addition to the scheduled semi-annual redeterminations, LPR Canada and the lenders each have discretion at any time, but not more often than once during any calendar year, to have the borrowing base redetermined.

in the borrowing base having a fair market value in excess of 10% of the borrowing base then in effect or (3) if there is a casualty event related to oil and natural gas properties included in the borrowing base. The borrowing base is subject to other automatic adjustments under the Credit Facility. A lowering of the borrowing base could require LPR Canada and Lone Pine to repay indebtedness in excess of the borrowing base in order to cover a deficiency.

Borrowings under the Credit Facility bear interest at one of two rates that may be elected by LPR Canada. Borrowings bear interest at a rate based on either:

The Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends and mergers and acquisitions, and also includes a financial covenant. The Credit Facility provides that LPR Canada will not permit its ratio of total debt outstanding to consolidated earnings before interest, taxes, depreciation and amortization (as defined by the terms of the bank credit facility and adjusted for non-cash charges) for a trailing 12-month period to be greater than 4.00 to 1.00. As at December 31, 2012, this ratio was 3.8 to 1.00.

Under certain conditions, amounts outstanding under the Credit Facility may be accelerated. Acceleration of the indebtedness under the Credit Facility would occur automatically in the case of a bankruptcy or insolvency event with respect to Lone Pine or its subsidiaries. Subject to notice and cure periods, certain events of default under the Credit Facility will result in acceleration of the indebtedness under the facility at the option of the lenders. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the Credit Facility (including the financial covenant), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control and a failure of the liens securing the Credit Facility.

The Credit Facility is collateralized by the assets of LPR Canada and certain of its restricted subsidiaries. Under the Credit Facility, LPR Canada is required to mortgage and grant a security interest in 75% of the present value of the proved oil and natural gas properties and related assets of LPR Canada and its restricted subsidiaries. LPR Canada is required to pledge, and has pledged, the stock of its subsidiary to the lenders to secure the Credit Facility. Under certain circumstances, LPR Canada could be obligated to pledge additional assets as collateral. The stock of all of Lone Pine's subsidiaries has been pledged to the lenders to secure the Credit Facility. Lone Pine and certain of its other subsidiaries have guaranteed the obligations of LPR Canada under the Credit Facility.

Of the $500 million total nominal amount under the Credit Facility, JPMorgan Chase Bank, N.A., Toronto Branch and eight other banks hold 100% of the total commitments, with JPMorgan Chase Bank, N.A., Toronto Branch and one other lender holding 16.7% each, three lenders holding 11.7% each, one lender holding 10%, one lender holding 8.3% and the other lenders holding 6.7% each of the total commitments.

From time to time, Lone Pine and its affiliates have engaged or may engage in other transactions with a number of the lenders under the Credit Facility. Such lenders or their affiliates have served as underwriters in connection with Lone Pine's IPO or initial purchasers in connection with Lone Pine's offering of the Senior Notes, serve as counterparties to LPR Canada's commodity derivative agreements, and may, in the future, act as agent or directly purchase LPR Canada's production.

As at December 31, 2012, the commitment fee on the unused portion of the borrowing base was 0.5%.

The following table summarizes interest costs incurred, including interest expense on borrowings from Forest, and the amount capitalized during the years indicated.

Lone Pine leases certain compressors and surface equipment under a capital lease. The capital lease obligation is secured by the leased assets. The net book value of the Company's assets recorded under capital leases is as follows.

The Company's future minimum lease payments under capital leases and the present value of the net minimum lease payments are as follows.

Lone Pine sponsored a DCPP under which the Company made contributions equal to $0.4 million in each of the years ended December 31, 2011 and 2010. The Company discontinued its DCPP on December 31, 2011. The Company also sponsors a GSP under which it makes contributions on behalf of employees. In 2012, the Company contributed $0.9 million to the GSP.

Lone Pine provides post-retirement benefits to former employees of LPR Canada, their beneficiaries and covered dependents. The plan, which consists primarily of medical benefits payable on behalf of retirees, is closed to new participants.

As of December 31, 2012, it is anticipated that the Company will be required to fund the following estimated benefit payments for the post-retirement benefits plan in the following years.

The estimated benefit obligations associated with the Company's post-retirement benefits plan are as follows.

There are no assets set aside under the post-retirement benefit plan. Any benefit plan payments made by the Company are treated as contributions. The fair value of the plan assets is as follows.

The excess of benefit obligation over plan assets is recognized in other long-term liabilities on the consolidated balance sheets and the net actuarial loss is recognized in accumulated other comprehensive income.

The components of net periodic expense and the underlying weighted average actuarial assumptions are as follows.

Interest cost is included in general and administrative on the consolidated statements of operations and amortization of net accumulated actuarial loss is recognized in other comprehensive income.

In 2010, the discount rates were determined by adjusting the Moody's Aa Corporate bond yield to reflect the difference between the duration of the future estimated cash flows of the post-retirement benefit obligations and the duration of the Moody's Aa index. In 2011, the Company refined its methodology used to determine the discount rate and used the rates produced by Natcan Investment Management ("Natcan") for December 31, 2011, which are also based on AA-rated corporate bonds. Natcan was retained by the Canadian Institute of Actuaries to produce the rates for the intended purpose of determining an appropriate rate for companies to value pension and other post-retirement benefit plan liabilities. The Company followed the same methodology in 2012 as in 2011.

The Company estimates that net periodic expense for the year ended December 31, 2013 will include expense of $20,100 resulting from the amortization of accumulated actuarial loss included in accumulated other comprehensive income at December 31, 2012.

The assumed health care cost trend rates that were used to measure the expected cost of benefits covered by the post-retirement benefits plan were as follows.

Assumed health care cost trend rates have a significant effect on the amounts reported for post-retirement benefits. A one-percentage-point change in assumed health care cost trend rates would

have resulted in the following increases (decreases) to the net periodic expense and benefit obligation for 2012.

Lone Pine enters into derivative instruments to manage its exposure to commodity price risk caused by fluctuations in commodity prices, which protects and provides certainty on a portion of the Company's cash flows. Lone Pine's commodity derivative instruments generally serve as effective economic hedges of commodity price exposure. Lone Pine has elected not to designate its derivatives as hedging instruments for accounting purposes, and recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the consolidated statements of operations

Lone Pine's outstanding commodity swaps as of December 31, 2012 were as follows.

In connection with one of the commodity swaps, the Company sold a call option to the counterparty in exchange for the Company receiving a premium fixed price on the commodity swap. Lone Pine's outstanding option as of December 31, 2012 was as follows.

The Company also enters into commodity collar agreements with third parties. A collar agreement is similar to a swap agreement, except that the Company receives the difference between the floor price and the index price only if the index price is below the floor price, and the Company pays the

difference between the ceiling price and the index price only if the index price is above the ceiling price. The Company's outstanding commodity collars as of December 31, 2012 were as follows.

The table below summarizes the location of the gross and net fair value amounts of Lone Pine's derivative instruments reported in the consolidated balance sheets as of the dates indicated. Due to the volatility of oil and natural gas prices, the estimated fair values of Lone Pine's commodity derivative instruments are subject to large fluctuations from period to period. In the consolidated balance sheet, Lone Pine offsets asset and liability fair value amounts recognized for derivative instruments with the same counterparty under master netting arrangements. See note 12 for additional information on the fair value of Lone Pine's derivative instruments.

The table below shows the amount reported in the consolidated statements of operations as gains and losses on commodity derivative instruments for the years indicated.

Lone Pine executes with each of its derivative counterparties an International Swap and Derivatives Association, Inc. ("ISDA") Master Agreement, which is a standard industry form contract containing general terms and conditions applicable to many types of derivative transactions. Additionally, Lone Pine executes, with each of its derivative counterparties, a Schedule, which modifies the terms and conditions of the ISDA Master Agreement according to the parties' requirements and the specific types of derivatives to be traded. As of December 31, 2012, all of the derivative counterparties are lenders, or affiliates of lenders, under the Credit Facility, which provides that any security granted under the Credit Facility shall also extend to and be available to those lenders that are counterparties to derivative transactions with Lone Pine. None of these counterparties require collateral beyond that already pledged under the Credit Facility.

The ISDA Master Agreements and Schedules contain cross-default provisions whereby a default under the Credit Facility will also cause a default under the derivative agreements. Such events of default include non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain pension plan events, certain adverse judgments, change of control and a failure of the liens securing the Credit Facility. In addition, bankruptcy and insolvency events with respect to Lone Pine or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the Credit Facility. None of these events of default are specifically credit-related, but some could arise if there were a general deterioration of Lone Pine's credit. The ISDA Master Agreements and Schedules contain a further credit-related termination event that would occur if Lone Pine were to merge with another entity and the creditworthiness of the resulting entity was materially weaker than that of Lone Pine.

Lone Pine's derivative counterparties are all financial institutions that are engaged in similar activities and have similar economic characteristics that, in general, could cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions. Lone Pine does not require the posting of collateral for its benefit under its derivative agreements. However, Lone Pine's ISDA Master Agreements and Schedules generally contain netting provisions whereby if on any date amounts would otherwise be payable by each party to the other, then on such date the party that owes the larger amount will pay the excess of that amount over the smaller amount owed by the other party, thus satisfying each party's obligations. These provisions generally apply to all derivative transactions, or all derivative transactions of the same type (e.g., commodity, interest rate, etc.), with the particular counterparty. If all counterparties failed, Lone Pine would be exposed to a risk of loss equal to this net amount owed to Lone Pine, the fair value of which was $4.4 million at December 31, 2012 (December 31, 2011—$19.8 million). If Lone Pine suffered an event of default, each counterparty could demand immediate payment, subject to notification periods, of the net obligations due to it under the derivative agreements. At December 31, 2012, Lone Pine owed a net derivative liability of $1.3 million. In the absence of netting provisions, at December 31, 2012, Lone Pine would be exposed to an aggregate risk of loss of $5.7 million (December 31, 2011—$19.8 million) under its derivative agreements and Lone Pine's derivative counterparties would be exposed to an aggregate risk of loss of $1.3 million.

On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") was enacted which, as part of a broader financial regulatory reform, includes

derivatives reform that may impact Lone Pine's business. Congress delegated many of the details of the Dodd-Frank Act to federal regulatory agencies, which are in the process of writing and implementing new rules. Lone Pine is monitoring the impact, if any, that the Dodd-Frank Act and related rules will have on its existing derivative transactions under its outstanding ISDA Master Agreements and Schedules, as well as its ability to enter into such transactions and agreements in the future.

Lone Pine's accounts receivable are primarily from purchasers of the Company's oil, natural gas and natural gas liquids, and from other exploration and production companies that own working interests in the properties the Company operates. This industry concentration could adversely impact Lone Pine's exposure to credit risk because the Company's customers and working interest owners may be similarly affected by changes in economic and financial market conditions, commodity prices and other conditions. Lone Pine's production is sold to various purchasers in accordance with the Company's credit policies and procedures. These policies and procedures take into account, among other things, the creditworthiness of potential purchasers and concentrations of credit risk. Lone Pine generally requires letters of credit or parental guarantees for receivables from parties that are deemed to have sub-standard credit or other financial concerns, unless the Company can otherwise mitigate the perceived credit exposure. Lone Pine believes that the loss of one or more of the Company's current purchasers would not have a material adverse effect on the Company's ability to sell its production, because any individual purchaser could be readily replaced by another purchaser, absent a broad market disruption. At December 31, 2012, Lone Pine's accounts receivable totaled $17.0 million, of which the Company believed that $0.5 million was at risk of being uncollectible.

The authoritative accounting guidance regarding fair value measurements for assets and liabilities measured at fair value establishes a three-tier fair value hierarchy, which prioritizes the inputs used to measure fair value. These tiers consist of Level 1, defined as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

The Company uses various assumptions and methods in estimating the fair values of its financial instruments. All of the estimates of fair value were determined using significant other observable inputs (Level 2), except for the fair value of the Senior Notes, which was determined based on the unadjusted quoted price in an active market (Level 1) given that the Senior Notes are actively traded in a private market with an independent quoted price available from a third party. The carrying amount of the Senior Notes has been reduced by the original issue discount and commissions, while the fair value of the Senior Notes is based on its face amount of US$200 million and December 31, 2012 market price of US$93.50 per US$100 face amount.

The Company's financial instruments include commodity derivatives. See note 11 for additional information on these instruments. The Company utilizes present value techniques to value its derivatives. Inputs to the valuations include published forward prices and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable; therefore, the Company's derivative instruments are included within the Level 2 fair value hierarchy. The Company's commodity derivative assets are measured at fair value on a recurring basis, which were valued at $4.4 million as at December 31, 2012 (December 31, 2011—$19.8 million). The Company had no liabilities measured at fair value on a recurring basis at December 31, 2012 and 2011.

The carrying amount of the bank credit facility approximates fair value since the borrowings bear interest at variable market rates. The carrying amount of the capital lease obligation approximates fair value, as interest rates have not materially changed since the lease was executed. The fair values of the other financial instruments, including cash, accounts receivable, bank overdraft, accounts payable and accrued liabilities, approximate their carrying values due to their short-term nature.

The fair values and carrying amounts of the Company's financial instruments are summarized below as of the dates indicated.

			At December 31,

			2012				2011
	Fair Value Measurement Level		Carrying Amount		Fair Value		Carrying Amount		Fair Value
			(In thousands)
Assets:
Cash		—	$	28	$	28	$	276	$	276
Accounts receivable		—		16,502		16,502		28,804		28,804
Derivative instruments		2		5,703		5,703		19,786		19,786
Liabilities:
Bank overdraft		—		4,872		4,872		2,006		2,006
Accounts payable and accrued liabilities		—		32,468		32,468		75,090		75,090
Accrued interest		—		7,742		7,742		—		—
Derivative instruments		2		1,294		1,294		—		—
Long-term debt
Bank credit facility		2		148,000		148,000		331,000		331,000
Senior Notes		1		192,310		186,046		—		—
Total Long-term debt				340,310		334,046		331,000		331,000
Capital lease obligation		2		5,738		5,738		6,894		6,894

The table below includes the Company's future rental payments under non-cancelable operating leases and unconditional purchase obligations as of December 31, 2012.

The Company has operating leases for office space and vehicles. The office space leases include rental for space plus certain building operating costs and expire January 31, 2023. In February 2013, a portion of the office space was sub-leased to a third party until January 31, 2018. Leasehold improvements pertaining to this office space are currently being amortized over the lease term of 10 years. The vehicle leases are mainly 36 months in duration and expire between 2013 and 2016.

Rental payments under non-cancelable operating leases applicable to exploration and development activities and capitalized to oil and natural gas properties approximated $0.6 million, $0.4 million and $0.4 million in each of the years ended December 31, 2012, 2011 and 2010, respectively. Rental payments under non-cancelable operating leases charged to expense approximated $1.1 million, $0.7 million and $0.8 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Payments charged to expense for purchase obligations were $7.4 million, $7.8 million and $6.5 million for the years ended December 31, 2012, 2011 and 2010, respectively.

The Company has 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 per MMBtu; and (2) US$1.00 per MMBtu to a buyer through October 31, 2014, unless the Henry Hub price exceeds US$6.50 per MMBtu, at which point Lone Pine shares the amount of the excess equally with the buyer.

At December 31, 2012, there were outstanding letters of credit totaling $2.0 million (December 31, 2011—$1.6 million) issued as security for performance under certain transportation agreements.

Lone Pine is involved in various legal claims and actions arising in the course of the Company's operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Lone Pine's financial position, cash

flows or results of operations. If an unfavourable outcome were to occur, there exists the possibility of a material adverse impact on the Company's consolidated net earnings (loss) in the period in which the outcome is determined. Accruals for litigation and claims are recognized if the Company determines that the loss is probable and the amount can be reasonably estimated. Contingencies with a favourable outcome are recognized in the consolidated statements of operations in the period in which the outcome is determined. The Company believes it has made adequate provision for such legal claims.

The following table summarizes Lone Pine's customers who individually account for more than 10% of total revenues.

Lone Pine's revenue is earned from purchases of the Company's oil, natural gas and natural gas liquids. Lone Pine believes that the loss of one or more of the Company's current customers would not have a material adverse effect on the Company's ability to sell its production, since any individual purchaser could be readily replaced by another customer, absent a broad market disruption.

Calculation of basic and diluted earnings (loss) per share for the years presented was as follows.

	Year Ended December 31,

	2012			2011			2010
	(In thousands)
Net earnings (loss)	$	(274,535	)	$	34,803		$	32,825
Net earnings attributable to participating securities		—			(12	)		—

Net earnings (loss) attributable to common stock for basic and diluted earnings per share	$	(274,535	)	$	34,791		$	32,825

Weighted average number of common shares outstanding during the year for basic earnings per share		85,030			78,795			70,000
Dilutive effects of potential common shares		—			—			—

Weighted average number of common shares outstanding during the year, including the effects of dilutive potential common shares, for diluted earnings per share		85,030			78,795			70,000

Basic earnings (loss) per share	$	(3.23	)	$	0.44		$	0.47

Diluted earnings (loss) per share	$	(3.23	)	$	0.44		$	0.47

At December 31, 2012, 1,750,691 shares (December 31, 2011—69,903 shares) were excluded from the diluted earnings per share calculation as the effect was anti-dilutive. At December 31, 2010, no shares were excluded from the diluted earnings per share calculation.

The changes in accumulated other comprehensive income (loss) for the years presented are as follows. The income tax amounts relate to the accumulated actuarial gains or losses.

	Foreign Currency Translation		Accumulated Actuarial Gains or Losses			Income Taxes			Accumulated Other Comprehensive Income (Loss)

	(In thousands)
Balance at December 31, 2009	$	—	$	(462	)	$	116		$	(346	)
2010 activity		44		256			—			300
Income tax		—		—			(64	)		(64	)

Balance at December 31, 2010		44		(206	)		52			(110	)
2011 activity		361		(190	)		—			171
Income tax		—		—			47			47

Balance at December 31, 2011		405		(396	)		99			108
2012 activity		—		100			—			100
Income tax		—		—			(25	)		(25	)

Balance December 31, 2012	$	405	$	(296	)	$	74		$	183

The table below summarizes the total stock-based compensation expense recorded during the years ended December 31, 2012, 2011 and 2010. Stock-based compensation costs for 2011 and 2010 include costs for Lone Pine employees participating in Forest's stock incentive plans. The years ended December 31, 2012 and 2011 also include costs associated with Lone Pine employees and directors participating in Lone Pine's incentive plans. The table below also discloses the remaining unamortized amounts and weighted average amortization period as of December 31, 2012.

	Restricted Stock		Phantom Stock Units—Stock			Phantom Stock Units—Cash only or Cash/Stock			Performance Units			Stock Options			Employee Stock Purchase Plan			Total

	(In thousands)
Year ended December 31, 2012:
Total stock-based compensation costs	$	295	$	4,430		$	(437	)	$	—		$	818		$	15		$	5,121
Less: stock-based compensation costs capitalized		—		(1,616	)		207			—			(337	)		(4	)		(1,750	)

Stock-based compensation costs expensed	$	295	$	2,814		$	(230	)	$	—		$	481		$	11		$	3,371

Year ended December 31, 2011:
Total stock-based compensation costs	$	113	$	156		$	1,831		$	309		$	—		$	—		$	2,409
Less: stock-based compensation costs capitalized		—		—			(829	)		(131	)		—			—			(960	)

Stock-based compensation costs expensed	$	113	$	156		$	1,002		$	178		$	—		$	—		$	1,449

Year ended December 31, 2010:
Total stock-based compensation costs	$	—	$	—		$	3,546		$	98		$	—		$	—		$	3,644
Less: stock-based compensation costs capitalized		—		—			(2,036	)		(42	)		—			—			(2,078	)

Stock-based compensation costs expensed	$	—	$	—		$	1,510		$	56		$	—		$	—		$	1,566

At December 31, 2012:
Unamortized stock-based compensation costs	$	93	$	2,455		$	181		$	—		$	487		$	—		$	3,216

Weighted average amortization period remaining (years)		0.4		1.5			1.2			—			1.6			—			1.4

The following tables summarize the activity in Lone Pine's plans for the years ended December 31, 2012 and 2011. There were no Lone Pine plans for the year ended December 31, 2010.

The restricted stock and phantom stock units granted to non-employee directors vest on the first anniversary of the date awarded, while the phantom stock units granted to officers and employees vest in equal tranches over a period of three years. The following table summarizes the activity for the Company's restricted stock and phantom stock units plans.

	Restricted Stock Units							Phantom Stock Units—Stock							Phantom Stock Units—Cash only or Cash/Stock

	Number of Units			Weighted Average Grant Date Fair Value per Unit		Vest Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value per Unit		Vest Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value per Unit		Vest Date Fair Value
						(In thousands)							(In thousands)							(In thousands)
Unvested at December 31, 2010		—							—							—
Awarded		33,895		$	10.23				43,701		$	9.16				676,049		$	10.60
Vested		—		$	—				—		$	—				—		$	—
Forfeited		(7,693	)	$	12.63				—		$	—				(18,800	)	$	12.09

Unvested at December 31, 2011		26,202		$	9.53				43,701		$	9.16				657,249		$	10.56
Awarded		67,935		$	3.72				1,066,480		$	6.43				—
Vested		(26,202	)	$	9.53	$	61		(63,551	)	$	8.51	$	150		(224,717	)	$	10.61	$	528
Forfeited		—		$	—				(67,100	)	$	6.84				(31,981	)	$	12.06

Unvested at December 31, 2012		67,935		$	3.72				979,530		$	6.39				400,551		$	10.41

For phantom stock units that will be settled in stock, Lone Pine expects to issue new shares of the Company. The weighted average grant date fair value of the restricted stock and phantom stock units

was determined using the average of the high and low price of a share of Lone Pine common stock as published in U.S. dollars by the New York Stock Exchange on the date of grant, translated to Canadian dollars at the foreign exchange rate on the grant date.

Phantom stock units that will be settled in cash and stock or cash are recorded at fair value at each reporting date. The fair value at the reporting date is determined by averaging the high and low price of a share of common stock as published in U.S. dollars by the New York Stock Exchange at the reporting date, translated to Canadian dollars at the foreign exchange rate at the reporting date. At December 31, 2012, the consolidated balance sheets included a liability of $0.3 million with respect to these phantom stock units.

Stock options granted vest in equal tranches over a period of three years with the participant able to exercise the options up to five years after the date of grant.The following table summarizes the activity for the Company's stock option plan.

The stock options are valued at the grant date fair value, which was estimated using the Black-Scholes-Merton option pricing model. Fair value of the options was calculated using the average of the high and low price of a share of Lone Pine common stock as published in U.S. dollars by the New York Stock Exchange on the grant date, translated to Canadian dollars at the foreign exchange rate at grant date. Volatility was estimated using implied volatility. The following assumptions were used to compute the weighted average fair value of the stock options at grant date.

On July 1, 2012, the Company implemented its ESPP, under which it is authorized to issue up to 750,000 shares of Lone Pine common stock. Employees may elect each three-month period to have up to 15% of their annual base earnings withheld to purchase common stock, up to a limit of 7,500 shares per quarterly period or $25,000 of common stock per employee per year. Participants may purchase

stock at 85% of the lower of the market price for a Lone Pine share of common stock at the beginning or at the end of each three-month period. ESPP participants are restricted from selling shares of common stock purchased under the ESPP for a period of six months after purchase. Shares issued under the ESPP may be new shares or reacquired shares. The Company had the following shares issued and issuable under the ESPP.

The fair value of stock purchase rights granted under the ESPP was estimated using the Black-Scholes-Merton option pricing model. Fair value of the stock purchase rights was calculated using the closing price on grant date of a share of Lone Pine common stock as published in U.S. dollars by the New York Stock Exchange on the date of grant, translated to Canadian dollars at the foreign exchange rate at grant date.

The following assumptions were used to compute the weighted average fair value of the purchase rights granted. Volatility was estimated using implied volatility.

Stock-based Compensation—Forest's Performance and Phantom Stock Unit Plans

The following table summarizes the activity for Lone Pine employees in Forest's performance and phantom stock unit plans for the years ended December 31, 2011 and 2010. There was no activity in the Forest plans for the year ended December 31, 2012.

	Performance Units							Phantom Stock Units

	Number of Units			Weighted Average Grant Date Fair Value		Vest Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value		Vest Date Fair Value
						(In thousands)							(In thousands)
Unvested at December 31, 2009		—							236,545		$	38.71
Awarded		12,500		$	31.87				153,085		$	27.07
Exercised		—							(64,250	)	$	44.74	$	1,948
Forfeited		—							(42,550	)	$	40.89

Unvested at December 31, 2010		12,500							282,830		$	30.71
Awarded		—		$	—				500		$	27.52
Exercised		—							(46,050	)	$	62.42	$	1,220
Forfeited		—							(11,775	)	$	23.26

Unvested at September 30, 2011		12,500							225,505		$	24.62
Distribution adjustment factor(1)		1.52							1.52

Adjusted Units		19,000		$	20.97				342,765		$	16.20
Exercised on Distribution		(19,000	)	$	20.97	$	—		(342,765	)	$	16.20	$	3,404

Balance at December 31, 2011 and 2012		—							—

The performance units were not paid because the performance criteria were not met.

In 2011, prior to the Distribution, the Company paid $1.2 million ($0.9 million after tax) on the vesting of phantom stock units, of which all of the amounts were paid in cash with the exception of 300 units, which were settled in shares of Forest common stock. As a result of the Distribution, Lone Pine's employees were deemed to have been involuntarily terminated and therefore their phantom stock units vested in full. All of these units were subsequently settled in cash and the aggregate amount paid pursuant to the vesting of such awards was $3.4 million ($2.6 million after tax), which was paid by Lone Pine under the terms of the employee matters agreement with Forest.

In 2010, 500 phantom stock units were settled in cash and 63,750 were settled in shares. The Company did not recognize a tax benefit on the settlement in 2010 since the units were primarily settled in shares.

The weighted average grant date fair value of the phantom stock units was determined using the average of the high and low stock price of a share of Forest common stock as published in U. S. dollars by the New York Stock Exchange on the date of grant, translated to Canadian dollars at the foreign exchange rate on the grant date.

The following table summarizes activity for Lone Pine employees in Forest's stock option plan for the years ended December 31, 2012, 2011 and 2010. There was no activity in the Forest plan for the year ended December 31, 2012.

			Weighted Average Exercise Price of Forest Common Shares (US$)		Aggregate Intrinsic Value

					(In thousands)
Unvested at December 31, 2009	108,918		$	21.75	$	338	108,918
Exercised	(45,949	)	$	20.52	$	388
Cancelled	(10,000	)	$	36.87

Unvested at December 31, 2010	52,969		$	19.97	$	957	52,969
Exercised	(14,038	)	$	18.35	$	81

Unvested at September 30, 2011	38,931		$	20.55	$	—	38,931
Distribution adjustment factor(1)	1.52

Adjusted Units	59,175		$	13.52	$	—	59,175
Exercised	(29,287	)	$	12.18	$	108
Cancelled	(29,888	)	$	15.81

Balance at December 31, 2011 and 2012	—						—

Stock options were granted at an exercise price equivalent to the fair market value of Forest common stock on the date of grant and had a term of 10 years. Options granted to non-employee directors vested immediately and options granted to officers and other employees vested in increments of 25% on each of the first four anniversary dates of the date of grant.

During the year ended December 31, 2012, Lone Pine recorded total foreign currency exchange gains of $0.9 million, including realized gains of $0.1 million related primarily to the payment of interest for the Senior Notes. The unrealized gains of $0.8 million related primarily to translation of principal of the Senior Notes. During the year ended December 31, 2011, Lone Pine realized foreign currency exchange gains of $32.7 million in connection with the repayment of debt owed to Forest. During the year ended December 31, 2010, Lone Pine recorded $13.7 million of unrealized gains related to the note payable and advances due to Forest, which were denominated in U.S. dollars.

At December 31, 2012, the Company's market capitalization was lower than the book value of its net assets, therefore Lone Pine performed both steps of the goodwill impairment test. The Company's fair value was determined using a combination of comparable external market transactions and an internal estimate of the present value of future cash flows using the income approach.

After the estimated fair value of the Company was assigned to its other assets and liabilities, it was determined that the fair value of goodwill was nil. Accordingly, the Company recognized a $17.3 million goodwill impairment loss in the consolidated statements of operations for the year ended December 31, 2012. There was no tax benefit associated with this impairment charge.

Lone Pine is incorporated in Delaware, United States, and LPR Canada is incorporated in Alberta, Canada. All of the Company's activities are and have been conducted in Canada, and the Company expects that future cash flows generated by the Company will continue to be reinvested in Canada for exploration, development or acquisition activities or utilized to satisfy other obligations in Canada. As a result, no U.S. federal or state income taxes are included in the Company's provision for

income taxes. Accordingly, the reconciliation of income taxes presented in the table below was calculated by applying statutory rates to the total income tax provision using Canadian statutory rates.

	Year Ended December 31,

	2012			2011			2010
	(In thousands)
Canadian federal income tax at 15.0%, 16.5% and 18.0% for 2012, 2011 and 2010, respectively, of income before income taxes	$	(52,423	)	$	8,667		$	7,337
Canadian provincial income taxes at 10.0%, for each of 2012, 2011 and 2010, of income before income taxes		(34,949	)		5,253			4,082
Foreign currency translation gains and losses taxed at 50% of statutory rates		(104	)		(551	)		(1,682	)
Non-deductible stock-based compensation		1,473			—			—
Change in valuation allowance for deferred tax assets		6,393			4,857			(1,404	)
Non-deductible goodwill impairment charge		4,332			—			—
Effect of future Canadian statutory rate reductions		—			(728	)		(1,100	)
Other		326			226			678

Total income tax expense (recovery)	$	(74,952	)	$	17,724		$	7,911

The components of the net deferred tax assets and liabilities at December 31, 2012 and 2011 were as follows.

	At December 31,

	2012			2011
	(In thousands)
Deferred tax assets:
Property and equipment	$	1,516		$	—
Accrual for post-retirement benefits		300			318
Employee compensation accruals including stock-based compensation		304			679
Net operating loss carryforwards		1,205			855
Capital lease		1,434			1,723
Asset retirement obligations		3,810			4,004
Other		62			42

Total deferred tax assets		8,631			7,621
Less: valuation allowance		(7,343	)		(950	)

Net deferred tax assets		1,288			6,671
Deferred tax liabilities:
Property and equipment		—			(76,644	)
Unrealized gains on derivative contracts, net		(1,102	)		(4,946	)
Unrealized foreign exchange gains		(104	)		—
Other		(82	)		(8	)

Total deferred tax liabilities		(1,288	)		(81,598	)

Net deferred tax liabilities	$	—		$	(74,927	)

The net deferred tax assets and liabilities were reflected in the consolidated balance sheets as follows.

At December 31, 2012, Lone Pine had a deferred income tax asset of $8.6 million primarily as a result of the ceiling test write-downs recorded in 2012 that reduced the net book value of the proved properties. The Company recorded a valuation allowance against this asset since it was determined that it is more likely than not that the Company will not be able to realize the benefit. The increase in the

valuation allowance of $4.9 million in 2011 consisted of $3.9 million related to resource successor tax pools and $1.0 million related to U.S. Federal net operating losses. In 2010, the decrease in the valuation allowance of $1.4 million related primarily to the release of the valuation allowance placed on capital loss carryforwards in the amount of $1.9 million, offset by an amount of $0.5 million placed on U.S. Federal net operating losses.

The income tax amounts calculated for LPR Canada were based on the specific transactions related to LPR Canada and Canadian income tax regulations. Until the date of the Distribution, Lone Pine's U.S. federal income tax items and attributes were included in Forest's consolidated U.S. income tax return, and in connection with the Distribution, Lone Pine was allocated a portion of the unused Forest consolidated loss carryforwards based on the specific amounts recognized by Lone Pine.

The Company determined that it is not necessary to recognize a provision for uncertain tax benefits as of December 31, 2012 and 2011 and, accordingly, no liability was recorded.

The limitation period is closed for the Company's Canadian income tax returns for years ended on or before December 31, 2005.

At December 31, 2012, the Company had net operating loss carryforwards totaling US$3.5 million, of which US$2.6 million expires in 2031 and US$0.9 million expires in 2032.

At December 31, 2012 and 2011, Lone Pine had authorized 300 million shares of common stock at a par value of $0.01 per share and 15 million shares of preferred stock at a par value of $0.01 per share. At December 31, 2012, Lone Pine had 85,192,955 shares of common stock (December 31, 2011—85,026,202 shares of common stock) issued and outstanding, and no shares of preferred stock (December 31, 2011—nil) issued and outstanding.

On June 1, 2011, Lone Pine completed the IPO of 15 million shares of its common stock at a price of US$13.00 per share (US$12.22 per share, net of underwriting discounts and commissions). Upon completion of the IPO, Forest retained a controlling interest in Lone Pine, owning 82% of the outstanding shares of Lone Pine's common stock. The net proceeds from the IPO, after deducting underwriting discounts and commissions and offering expenses, received by Lone Pine were $173.1 million. Lone Pine used the net proceeds to pay $28.7 million to Forest as partial consideration for Forest's contribution of Forest's direct and indirect interest in its Canadian operations. Lone Pine used the remaining net proceeds and borrowings under the Credit Facility to repay outstanding indebtedness owed to Forest.

In May 2011, as part of a corporate restructuring in connection with the IPO and Distribution, LPR Canada declared a non-cash stock dividend to Forest in the amount of $567.4 million. As consideration for Forest's contribution of its direct and indirect interests in LPR Canada to Lone Pine, Lone Pine issued 69,999,999 million shares of common stock and paid $28.7 million in cash to Forest. The transfer of interests was a common control transaction, therefore, the cash distribution was recognized as a direct reduction of the capital surplus of Lone Pine. Forest also made an additional capital contribution of $0.4 million in 2011.

On September 30, 2011, Forest paid a special stock dividend to its shareholders of the 70 million shares of common stock of Lone Pine owned by Forest. The Distribution was made to all Forest shareholders of record as of the close of business on September 16, 2011, with Forest shareholders receiving 0.61248511 of a share of Lone Pine common stock for every share of Forest common stock held as of the record date. Forest shareholders received cash in lieu of fractional shares.

Prior to June 2011, Forest provided Lone Pine with corporate services for which Forest charged Lone Pine management and insurance fees. The fees and other costs incurred by Forest on Lone Pine's behalf were accrued as a payable due to Forest, which was classified as a current liability. Interest accrued on this balance at prime plus 5% per annum, except for a portion attributable to equity compensation awards. In addition, Lone Pine had a promissory note to Forest under which Lone Pine could borrow up to $500 million. This balance was paid off in June 2011 with the proceeds from the IPO and borrowings under the Credit Facility. In June 2011, Forest and Lone Pine entered into a transition services agreement, whereby Forest agreed to provide to Lone Pine, on a transitional basis, certain corporate services consistent with the services previously provided. The transition services agreement, which allowed Forest to fully recover costs directly associated with providing services to Lone Pine (without profit), was terminated on December 1, 2011. Lone Pine paid Forest $0.3 million under the transition services agreement in 2011. At December 31, 2011, Lone Pine had an amount payable to Forest of $0.3 million included in accounts payable and accrued liabilities on the balance sheet.

The management fees and other reimbursable costs billed by Forest to Lone Pine and included in Lone Pine's consolidated statements of operations for the periods presented are shown in the table below. This table does not include amounts due to Forest for stock-based compensation costs or interest charges.

In connection with the IPO, Lone Pine entered into a tax-sharing agreement with Forest, which governs the respective rights, responsibilities and obligations of Lone Pine and Forest with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and other matters regarding taxes. Also under this agreement, for a two-year period following the Distribution, Lone Pine will be restricted in its ability, among other things, to divest of assets outside the ordinary course of business, to issue or sell its common stock or other securities (including securities convertible into common stock but excluding certain compensation arrangements) or to enter into any other corporate transaction that would cause the Company to undergo either a 50% or greater change in the ownership of its voting stock or 50% or greater change in the ownership (measured by value) of all classes of its stock (in either case, taking into account shares issued in the IPO).

The chart below provides certain quarterly information for the periods indicated.

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter

	(In thousands, except per share amounts)
2012
Oil and natural gas revenue	$	44,329		$	42,420		$	38,188		$	36,766
Ceiling test write-down of oil and natural gas properties		—			128,870			142,879			—
Impairment of goodwill		—			—			—			17,328
Net earnings (loss)(1)		(9,508	)		(105,035	)		(124,301	)		(35,691	)
Basic and diluted earnings (loss) per common share	$	(0.11	)	$	(1.24	)	$	(1.46	)	$	(0.42	)
2011
Oil and natural gas revenue	$	35,562		$	49,236		$	50,015		$	56,357
Net earnings (loss)		5,291			5,366			29,014			(4,868	)
Basic and diluted earnings (loss) per common share	$	0.08		$	0.07		$	0.34		$	(0.06	)

In January 2013, Lone Pine issued 147,464 shares (net of shares withheld for tax) of common stock to settle vested phantom stock units. In addition, the Company issued 3,831,494 cash-settled phantom stock units and 2,164,470 stock-settled performance units as long-term incentive awards. The phantom stock units are scheduled to vest in three equal annual installments beginning December 15, 2013. The performance units are scheduled to vest on December 31, 2015.

In March 2013, in connection with the termination of its Chief Executive Officer and Chief Financial Officer, Lone Pine issued an additional 84,037 shares of common stock in settlement of stock-settled stock-based compensation outstanding at December 31, 2012 and 578,734 shares of common stock in settlement of the performance units issued in January 2013, in each case net of shares withheld for tax. The Company also expects to make an aggregate cash payment for related severance and cash-settled stock-based compensation.

In February 2013, Lone Pine completed the divestiture of certain non-core properties in Alberta for proceeds of $13.9 million after closing adjustments. The proceeds reduced the net book value of the oil and natural gas proved properties, and no gain or loss was recognized in net earnings for the sale.

(25) SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited):

The reserve estimates presented herein were made in accordance with oil and natural gas reserve estimation and disclosure authoritative accounting guidance issued by the FASB effective for reporting periods ending on or after December 31, 2009. This guidance was issued to align the accounting oil and gas reserve estimation and disclosure requirements with the requirements in the SEC's "Modernization of Oil and Gas Reporting" rule.

The above-mentioned rules include updated definitions of proved oil and natural gas reserves, proved undeveloped oil and natural gas reserves, oil and natural gas producing activities and other terms used in estimating proved oil and natural gas reserves. Proved oil and natural gas reserves were calculated based on the prices for oil and gas during the 12-month period before the reporting date, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. This average price is also used in calculating the aggregate amount of and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. The authoritative guidance broadened the types of technologies that a company may use to establish reserve estimates and also broadened the definition of oil and natural 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.

Proved oil and natural gas 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 prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include the average prices for oil and natural gas during the 12-month period before the reporting date, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prices do not include the effects of commodity derivatives. Existing economic conditions include year-end cost estimates for all years presented.

Proved developed oil and natural gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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

(25) SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited): (Continued)

The following table includes the estimates of Lone Pine's net proved, net proved developed and net proved undeveloped oil and natural gas reserves, all of which are located in Canada, and changes in its net proved oil and natural gas reserves. For the years ended December 31, 2012 and 2011, the Company engaged DeGolyer and MacNaughton, an independent petroleum engineering firm, to prepare an independent evaluation of the Company's reserves. For the years ended December 31, 2010 and 2009, the Company engaged DeGolyer and MacNaughton to conduct an audit of its internal reserve estimates.



Balance at December 31, 2009	16,854		221,201		322,325
Revisions of previous estimates	195		(7,724	)	(6,554	)
Extensions and discoveries	2,772		86,028		102,660
Production	(962	)	(22,436	)	(28,208	)
Sales of reserves in place	(602	)	(10,183	)	(13,795	)

Balance at December 31, 2010	18,257		266,886		376,428
Revisions of previous estimates	(2,404	)	(51,496	)	(65,919	)
Extensions and discoveries	2,902		44,981		62,392
Production	(1,192	)	(27,047	)	(34,199	)
Purchase of reserves in place	—		62,145		62,145

Balance at December 31, 2011	17,563		295,469		400,847
Revisions of previous estimates	(7,372	)	(142,499	)	(186,731	)
Extensions and discoveries	10,888		912		66,240
Production	(1,429	)	(21,968	)	(30,542	)
Sales of reserves in place	(1,205	)	(54,081	)	(61,311	)

Balance at December 31, 2012	18,445		77,833		188,503

Proved developed reserves at:
January 1, 2010	6,202		169,740		206,952
December 31, 2010	6,594		169,292		208,856
December 31, 2011	8,363		163,530		213,708
December 31, 2012	6,832		77,061		118,053
Proved undeveloped reserves at:
January 1, 2010	10,652		51,461		115,373
December 31, 2010	11,663		97,594		167,572
December 31, 2011	9,200		131,939		187,139
December 31, 2012	11,613		772		70,450

(25) SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited): (Continued)

In 2012, the net negative revisions were primarily due to the decrease in the 12-month average trailing natural gas price. In 2011 and 2010, the net negative revisions were primarily due to the performance of existing wells.

In 2012, the positive extensions and discoveries were primarily due to continued success with horizontal drilling in the Evi area. In 2011, the positive extensions and discoveries were also due to horizontal drilling in the Evi area as well as the ongoing development of the Narraway and Ojay fields. In 2010, the positive extensions and discoveries were primarily due to successful drilling results in the Narraway and Ojay fields.

In 2011, the Company acquired proved reserves in our Narraway/Ojay fields as a result of the acquisition of certain natural gas properties.

In 2012, the Company divested certain non-core natural gas properties. In 2011, the Company did not divest any properties with associated reserves. In 2010, the Company divested certain non-core oil and natural gas properties.

The aggregate capitalized costs relating to oil and natural gas producing activities were as follows as of the dates indicated.

(25) SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited): (Continued)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following costs were incurred in oil and natural gas property acquisition, exploration and development activities during the years ended December 31, 2012, 2011 and 2010.

Results of operations from oil and natural gas producing activities for the years ended December 31, 2012, 2011 and 2010 are presented below.

	Year Ended December 31,

	2012			2011		2010
	(In thousands)
Oil and natural gas revenue	$	161,703		$	191,170	$	151,184
Expenses:
Production expense		70,089			58,378		40,164
Depletion expense		114,203			84,318		64,990
Ceiling test write-down of oil and natural gas properties		271,749			—		—
Accretion of asset retirement obligations		1,305			1,071		1,073

Revenue less expenses		(295,643	)		47,403		44,957
Income tax expense (recovery)		(73,911	)		12,562		12,588

Results of operations	$	(221,732	)	$	34,841	$	32,369

Depletion rate per Mcfe	$	3.75		$	2.47	$	2.32

Future oil and natural gas sales are calculated by applying the prices used in estimating the Company's proved oil and natural gas reserves to the year end quantities of those reserves. Future price changes were considered only to the extent provided by contractual arrangements in existence at each year-end. Future production and development costs, which include costs related to plugging of

(25) SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited): (Continued)

wells, removal of facilities and equipment and site restoration, are calculated by estimating the expenditures to be incurred in producing and developing the proved oil and natural gas reserves at the end of each year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to tax deductions, credits and allowances relating to the proved oil and natural gas reserves. All cash flow amounts, including income taxes, are discounted at 10%.

Changes in the demand for oil and natural gas, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. The following table should not be construed to be an estimate of the current market value of the Company's proved reserves. Management does not rely upon the following information when making investment decisions.

(25) SUPPLEMENTAL FINANCIAL DATA—OIL AND GAS PRODUCING ACTIVITIES (unaudited): (Continued)

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

An analysis of the changes in the standardized measure of discounted future net cash flows during each of the last three years is as follows.

	Year Ended December 31,

	2012			2011			2010
	(In thousands)
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves, at beginning of year	$	618,933		$	528,493		$	524,591
Changes resulting from:
Sales of oil and natural gas, net of production costs		(106,796	)		(149,122	)		(110,422	)
Net changes in prices and future production costs		(363,748	)		63,069			56,497
Net changes in future development costs		117,061			(53,264	)		(456	)
Extensions, discoveries and improved recovery		168,519			82,914			109,906
Development costs incurred		117,512			172,456			37,195
Revisions of previous quantity estimates		(204,991	)		(143,718	)		(14,527	)
Changes in production rates, timing and other		(67,497	)		(60,821	)		(104,064	)
Sales of reserves in place		(70,566	)		—			(14,998	)
Purchase of reserves in place		—			64,996			—
Accretion of discount on reserves at beginning of year		71,282			66,938			64,568
Net change in income taxes		75,390			46,992			(19,797	)

Total change for year		(263,834	)		90,440			3,902

Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves, at end of year	$	355,099		$	618,933		$	528,493

Each year's computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves was based on 12-month average commodity prices, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month, prior to December 31 and year end costs. The prices used in the computation were as follows.

On February 14, 2012, LPR Canada issued US$200 million of Senior Notes (see note 8—Long-term Debt for more information on the Senior Notes), which are guaranteed on a senior unsecured basis by the Guarantors. These guarantees are full and unconditional, and joint and several among the Guarantors.

A Subsidiary Guarantor's guarantee may be released automatically under the following customary circumstances: (i) in the event the Subsidiary Guarantor is sold or disposed of (whether by merger, amalgamation, consolidation, the sale of a sufficient amount of its capital stock so that it no longer qualifies as a "Subsidiary" of the Parent Guarantor or the sale of all or substantially all of its assets (other than by lease)) to a person which is not the Parent Guarantor or a Restricted Subsidiary; (ii) at such time as such Subsidiary Guarantor ceases to guarantee any other indebtedness of the Subsidiary Issuer, the Parent Guarantor or another Subsidiary Guarantor that resulted in the obligation of such Subsidiary Guarantor to guarantee the Senior Notes, except a discharge or release by or as a result of payment under such guarantee; (iii) if the Parent Guarantor designates that Subsidiary Guarantor as an unrestricted subsidiary in accordance with the applicable provisions of the Indenture; or (iv) upon covenant defeasance, legal defeasance or satisfaction and discharge of the Senior Notes as provided in the Indenture. The Parent Guarantor will be released from its obligations under the Indenture only in connection with any such legal defeasance or satisfaction and discharge of the Senior Notes as provided in the Indenture.

The following financial information reflects consolidating financial information of the Subsidiary Issuer and the Guarantors on a combined basis, prepared on the equity basis of accounting. The Parent Guarantor has no independent assets or operations. The Subsidiary Issuer and the Guarantors other than Lone Pine Resources Inc. (the "Combined Guarantor Subsidiaries"), are 100% owned by the Parent Guarantor. The information is presented in accordance with the requirements of SEC Rule 3-10 of Regulation S-X. The information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the guarantees provided by the Guarantors.

Effective October 1, 2011, the Company changed the reporting currency for its consolidated financial statements to the Canadian dollar from the U.S. dollar to better reflect its business, which is almost entirely conducted in Canadian dollars. With the change in reporting currency, the comparative financial information for 2010 was recast to Canadian dollars from U.S. dollars to reflect the Company's consolidated financial statements as if they had been historically reported in Canadian dollars. The Company also changed its functional currency prospectively from October 1, 2011 to the Canadian dollar from the U.S. dollar.

	As at December 31, 2012

	Parent Guarantor			Combined Guarantor Subsidiaries		Subsidiary			Eliminations			Consolidated
ASSETS:
Current assets:
Cash	$	—		$	—	$	28		$	—		$	28
Accounts receivable		3,198			486		16,129			(3,311	)		16,502
Derivative instruments		—			—		4,409			—			4,409
Prepaid expenses and other current assets		148			—		4,799			—			4,947

Total current assets		3,346			486		25,365			(3,311	)		25,886
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion		—			—		376,203			—			376,203
Unproved		—			—		148,956			—			148,956

Net oil and natural gas properties		—			—		525,159			—			525,159
Other property and equipment, net of accumulated depreciation and amortization		—			—		65,096			—			65,096

Net property and equipment		—			—		590,255			—			590,255
Investment in affiliate		110,882			58,063		—			(168,945	)		—
Goodwill		—			—		—			—			—
Other assets		—			—		6,662			—			6,662

	$	114,228		$	58,549	$	622,282		$	(172,256	)	$	622,803

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Bank overdraft	$	44		$	—	$	4,828		$	—		$	4,872
Accounts payable and accrued liabilities		241			—		35,538			(3,311	)		32,468
Accrued interest		—			—		7,742			—			7,742
Capital lease obligation		—			—		1,217			—			1,217
Other current liabilities		164					2,400			—			2,564

Total current liabilities		449			—		51,725			(3,311	)		48,863
Long-term debt		—			—		340,310			—			340,310
Asset retirement obligations		—			—		12,839			—			12,839
Capital lease obligation		—			—		4,521			—			4,521
Other liabilities		107			—		1,201			—			1,308

Total liabilities		556			—		410,596			(3,311	)		407,841
Stockholders' equity:
Common stock		835			39,135		832,750			(871,885	)		835
Capital surplus		364,991			19,027		143,138			457,282			984,438
Retained earnings (accumulated deficit)		(252,559	)		387		(763,980	)		245,658			(770,494	)
Accumulated other comprehensive income (loss)		405			—		(222	)		—			183

Total stockholders' equity		113,672			58,549		211,686			(168,945	)		214,962

	$	114,228		$	58,549	$	622,282		$	(172,256	)	$	622,803

	As at December 31, 2011

	Parent Guarantor		Combined Guarantor Subsidiaries		Subsidiary			Eliminations			Consolidated
ASSETS:
Current assets:
Cash	$	273	$	—	$	3		$	—		$	276
Accounts receivable		—		504		28,804			(504	)		28,804
Derivative instruments		—		—		19,786			—			19,786
Prepaid expenses and other current assets		180		—		5,380			—			5,560

Total current assets		453		504		53,973			(504	)		54,426
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion		—		—		704,232			—			704,232
Unproved		—		—		141,332			—			141,332

Net oil and natural gas properties		—		—		845,564			—			845,564
Other property and equipment, net of accumulated depreciation and amortization		—		—		66,413			—			66,413

Net property and equipment		—		—		911,977			—			911,977
Investment in affiliate		383,563		58,071		—			(441,634	)		—
Goodwill		—		—		17,328			—			17,328
Other assets		—		—		8,570			—			8,570

	$	384,016	$	58,575	$	991,848		$	(442,138	)	$	992,301

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Bank overdraft	$	—	$	—	$	2,006		$	—		$	2,006
Accounts payable and accrued liabilities		1,369		—		74,225			(504	)		75,090
Capital lease obligation		—		—		1,156			—			1,156
Deferred income taxes		—		—		4,946			—			4,946
Other current liabilities		—		—		1,292			—			1,292

Total current liabilities		1,369		—		83,625			(504	)		84,490
Long-term debt		—		—		331,000			—			331,000
Asset retirement obligations		—		—		15,412			—			15,412
Deferred income taxes		—		—		69,981			—			69,981
Capital lease obligation		—		—		5,738			—			5,738
Other liabilities		—		—		1,818			—			1,818

Total liabilities		1,369		—		507,574			(504	)		508,439
Stockholders' equity:
Common stock		833		39,135		832,750			(871,885	)		833
Capital surplus		359,529		18,931		143,138			457,282			978,880
Retained earnings (accumulated deficit)		21,880		509		(491,317	)		(27,031	)		(495,959	)
Accumulated other comprehensive income (loss)		405		—		(297	)		—			108

Total stockholders' equity		382,647		58,575		484,274			(441,634	)		483,862

	$	384,016	$	58,575	$	991,848		$	(442,138	)	$	992,301

Condensed Consolidating Statement of Operations

(In thousands of Canadian dollars)

	Year Ended December 31, 2012

	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	—		$	—		$	161,703		$	—		$	161,703
Interest and other		—			—			54			—			54

Total revenues		—			—			161,757			—			161,757
Costs, expenses and other:
Lease operating expenses		—			—			51,406			—			51,406
Production and property taxes		—			—			3,083			—			3,083
Transportation and processing		—			—			15,600			—			15,600
General and administrative		1,771			8			16,915			—			18,694
Depreciation, depletion and amortization		—			—			116,215			—			116,215
Ceiling test write-down of oil and natural gas properties		—			—			271,749			—			271,749
Impairment of goodwill		—			—			17,328			—			17,328
Interest expense		—			—			30,215			—			30,215
Accretion of asset retirement obligations		—			—			1,305			—			1,305
Foreign currency exchange losses (gains)		15			10			(928	)		—			(903	)
Gains on derivative instruments		—			—			(14,272	)		—			(14,272	)
Equity loss in affiliates		272,681			—			—			(272,681	)		—
Other, net		68			—			756			—			824

Total costs, expenses and other		274,535			18			509,372			(272,681	)		511,244

Loss before income taxes		(274,535	)		(18	)		(347,615	)		272,681			(349,487	)
Income tax recovery		—			—			(74,952	)		—			(74,952	)

Net loss	$	(274,535	)	$	(18	)	$	(272,663	)	$	272,681		$	(274,535	)

Condensed Consolidating Statement of Comprehensive Income

(In thousands of Canadian dollars)

Condensed Consolidating Statement of Operations

(In thousands of Canadian dollars)

	Year Ended December 31, 2011

	Parent Guarantor		Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated
Revenues:
Oil and natural gas	$	—	$	—		$	191,170		$	—		$	191,170
Equity income in affiliates		26,658		—			—			(26,658	)		—
Interest and other		—		—			30			—			30

Total revenues		26,658		—			191,200			(26,658	)		191,200
Costs, expenses and other:
Lease operating expenses		—		—			38,789			—			38,789
Production and property taxes		—		—			2,337			—			2,337
Transportation and processing		—		—			17,252			—			17,252
General and administrative		2,645		5			10,465			—			13,115
Depreciation, depletion and amortization		—		—			85,751			—			85,751
Interest expense		—		—			7,177			—			7,177
Interest expense on borrowings from Forest		—		—			2,857			—			2,857
Accretion of asset retirement obligations		—		—			1,071			—			1,071
Foreign currency exchange gains		—		—			(4,976	)		—			(4,976	)
Gains on derivative instruments		—		—			(28,167	)		—			(28,167	)
Other, net		750		(17	)		2,717			17			3,467

Total costs, expenses and other		3,395		(12	)		135,273			17			138,673

Earnings (loss) before income taxes		23,263		12			55,927			(26,675	)		52,527
Income tax expense		—		—			17,724			—			17,724

Net earnings (loss)	$	23,263	$	12		$	38,203		$	(26,675	)	$	34,803

Condensed Consolidating Statement of Comprehensive Income

(In thousands of Canadian dollars)

	Year Ended December 31, 2010

	Parent Guarantor US$			Combined Guarantor Subsidiaries US$		Parent and Combined Guarantor Subsidiaries US$			Parent and Combined Guarantor Subsidiaries CDN$			Subsidiary Issuer CDN$			Eliminations CDN$		Consolidated CDN$
Revenues:
Oil and natural gas	$	—		$	—	$	—		$	—		$	151,184		$	—	$	151,184
Interest and other		—			—		—			—			24			—		24

Total revenues		—			—		—			—			151,208			—		151,208
Costs, expenses and other:
Lease operating expenses		—			—		—			—			26,547			—		26,547
Production and property taxes		—			—		—			—			2,513			—		2,513
Transportation and processing		—			—		—			—			11,104			—		11,104
General and administrative		1,221			—		1,221			1,259			8,331			—		9,590
Depreciation, depletion and amortization		—			—		—			—			65,811			—		65,811
Interest expense		—			—		—			—			437			—		437
Interest expense on borrowings from Forest		—			—		—			—			6,753			—		6,753
Accretion of asset retirement obligations		—			—		—			—			1,073			—		1,073
Foreign currency exchange gains		—			—		—			—			(13,924	)		—		(13,924	)
Other, net		—			—		—			—			568			—		568

Total costs, expenses and other		1,221			—		1,221			1,259			109,213			—		110,472

Earnings (loss) before income taxes		(1,221	)		—		(1,221	)		(1,259	)		41,995			—		40,736
Income tax expense		—			—		—			—			7,911			—		7,911

Net earnings (loss)	$	(1,221	)	$	—	$	(1,221	)	$	(1,259	)	$	34,084		$	—	$	32,825

Condensed Consolidating Statement of Comprehensive Income

(In thousands of dollars)

Condensed Consolidating Statement of Cash Flows

(In thousands of Canadian dollars)

	Year Ended December 31, 2012

	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated
Operating activities:
Net loss	$	(274,535	)	$	(18	)	$	(272,663	)	$	272,681		$	(274,535	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depreciation, depletion and amortization		—			—			116,215			—			116,215
Amortization of deferred costs		—			—			2,399			—			2,399
Ceiling test write-down of oil and natural gas properties		—			—			271,749			—			271,749
Impairment of goodwill		—			—			17,328			—			17,328
Accretion of asset retirement obligations		—			—			1,305			—			1,305
Deferred income tax recovery		—			—			(74,952	)		—			(74,952	)
Unrealized foreign currency exchange gains		25			10			(838	)		—			(803	)
Unrealized losses on derivative instruments		—			—			15,377			—			15,377
Stock-based compensation		793			—			2,578			—			3,371
Equity loss in affiliates		272,681			—			—			(272,681	)		—
Other, net		—			—			(1,640	)		—			(1,640	)
Changes in operating assets and liabilities:
Accounts receivable		(373	)		—			12,675			—			12,302
Prepaid expenses and other current assets		32			—			890			—			922
Accounts payable and accrued liabilities		(241	)		—			(15,981	)		—			(16,222	)
Accrued interest and other current liabilities		—			—			7,742			—			7,742

Net cash provided by (used in) operating activities		(1,618	)		(8	)		82,184			—			80,558
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs		—			—			(184,833	)		—			(184,833	)
Other fixed assets		—			—			(3,189	)		—			(3,189	)
Proceeds from divestiture of assets, net		—			—			97,747			—			97,747

Net cash used in investing activities		—			—			(90,275	)		—			(90,275	)
Financing activities:
Proceeds from issuance of long-term debt		—			—			192,052			—			192,052
Debt issuance costs		—			—			(1,295	)		—			(1,295	)
Proceeds from bank borrowings		—			—			3,086,000			—			3,086,000
Repayments of bank borrowings		—			—			(3,269,000	)		—			(3,269,000	)
Change in intercompany balances		1,301			8			(1,309	)		—			—
Change in bank overdrafts		44			—			2,822			—			2,866
Capital lease payments		—			—			(1,156	)		—			(1,156	)
Other, net		0			—			2			—			2

Net cash provided by financing activities		1,345			8			8,116			—			9,469

Net increase (decrease) in cash		(273	)		—			25			—			(248	)
Cash at beginning of year		273			—			3			—			276

Cash at end of year	$	—		$	—		$	28		$	—		$	28

Condensed Consolidating Statement of Cash Flows

(In thousands of Canadian dollars)

	Year Ended December 31, 2011

	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated
Operating activities:
Net earnings (loss)	$	23,263		$	12		$	38,203		$	(26,675	)	$	34,803
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		—			—			85,751			—			85,751
Amortization of deferred costs		—			—			1,095			—			1,095
Accretion of asset retirement obligations		—			—			1,071			—			1,071
Deferred income tax expense		—			—			17,724			—			17,724
Unrealized foreign currency exchange gains		—			—			(4,976	)		—			(4,976	)
Unrealized gains on derivative instruments		—			—			(19,786	)		—			(19,786	)
Stock-based compensation		—			—			269			—			269
Equity income in affiliates		(26,658	)		—			—			26,658			—
Other, net		308			—			2,151			—			2,459
Changes in operating assets and liabilities:
Accounts receivable		—			—			4,322			—			4,322
Prepaid expenses and other current assets		1,344			—			1,661			—			3,005
Accounts payable and accrued liabilities		136			(1	)		19,149			—			19,284
Accrued interest and other current liabilities		—			—			(24,198	)		—			(24,198	)

Net cash provided by (used in) operating activities		(1,607	)		11			122,436			(17	)		120,823
Investing activities:
Investment in subsidiaries		(140,859	)		(18,931	)		—			159,790			—
Capital expenditures for property and equipment:
Exploration, development and acquisition costs		—			—			(325,095	)		—			(325,095	)
Other fixed assets		—			—			(12,841	)		—			(12,841	)
Proceeds from divestiture of assets, net		—			—			343			—			343

Net cash provided by (used in) investing activities		(140,859	)		(18,931	)		(337,593	)		159,790			(337,593	)
Financial activities:
Debt issuance costs		—			—			(4,700	)		—			(4,700	)
Proceeds from bank borrowings		—			—			2,531,000			—			2,531,000
Repayments of bank borrowings		—			—			(2,200,000	)		—			(2,200,000	)
Proceeds from Forest		5,999			—			100,513			—			106,512
Repayments to Forest		(8,009	)		—			(360,376	)		—			(368,385	)
Cash distribution to Forest		(28,711	)		—			—			—			(28,711	)
Change in intercompany balances		11			(11	)		—			—			—
Intercompany dividend		(17	)		—			—			17			—
Capital contribution		—			18,931			140,859			(159,790	)		—
Proceeds from issuance of common stock, net of offering costs		173,086			—			—			—			173,086
Change in bank overdrafts		—			—			440			—			440
Proceeds from sale-leaseback		—			—			7,723			—			7,723
Capital lease payments		—			—			(829	)		—			(829	)
Other, net		—			—			(43	)		—			(43	)

Net cash provided by (used in) financing activities		142,359			18,920			214,587			(159,773	)		216,093
Effect of exchange rate changes on cash		380			—			—			—			380

Net increase (decrease) in cash		273			—			(570	)		—			(297	)
Cash at beginning of year		—			—			573			—			573

Cash at end of year	$	273		$	—		$	3		$	—		$	276

	Year Ended December 31, 2010

	Parent Guarantor US$			Combined Guarantor Subsidiaries US$		Parent and Combined Guarantor Subsidiaries US$			Parent and Combined Guarantor Subsidiaries CDN$			Subsidiary Issuer CDN$			Eliminations CDN$		Consolidated CDN$
Operating activities:
Net earnings (loss)	$	(1,221	)	$	—	$	(1,221	)	$	(1,259	)	$	34,084		$	—	$	32,825
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		—			—		—			—			65,811			—		65,811
Amortization of deferred costs		—			—		—			—			411			—		411
Accretion of asset retirement obligations		—			—		—			—			1,073			—		1,073
Deferred income tax expense		—			—		—			—			7,911			—		7,911
Unrealized foreign currency exchange gains		—			—		—			—			(13,655	)		—		(13,655	)
Stock-based compensation		—			—		—			—			—			—		—
Other, net		—			—		—			44			(172	)		—		(128	)
Changes in operating assets and liabilities:
Accounts receivable		—			—		—			—			(10,747	)		—		(10,747	)
Prepaid expenses and other current assets		(1,522	)		—		(1,522	)		(1,513	)		(2,598	)		—		(4,111	)
Accounts payable and accrued liabilities		—			—		—			—			(732	)		—		(732	)
Accrued interest and other current liabilities		—			—		—			—			8,723			—		8,723

Net cash provided by (used in) operating activities:		(2,743	)		—		(2,743	)		(2,728	)		90,109			—		87,381
Investing activities:
Investment in subsidiaries		—			—		—			—			—			—		—
Capital expenditures for property and equipment:
Exploration, development and acquisition costs		—			—		—			—			(208,869	)		—		(208,869	)
Other fixed assets		—			—		—			—			(44,310	)		—		(44,310	)
Proceeds from divestiture of assets		—			—		—			—			28,024			—		28,024

Net cash used in investing activities		—			—		—			—			(225,155	)		—		(225,155	)
Financial activities:
Debt issuance costs		—			—		—			—			—			—		—
Proceeds from bank borrowings		—			—		—			—			151,000			—		151,000
Repayments of bank borrowings		—			—		—			—			(151,000	)		—		(151,000	)
Proceeds from Forest		2,743			—		2,743			2,728			125,975			—		128,703
Repayments to Forest		—			—		—			—			(1,264	)		—		(1,264	)
Change in bank overdrafts		—			—		—			—			1,566			—		1,566
Other, net		—			—		—			—			(60	)		—		(60	)

Net cash provided by financing activities		2,743			—		2,743			2,728			126,217			—		128,945

Net decrease in cash		—			—		—			—			(8,829	)		—		(8,829	)
Cash at beginning of year		—			—		—			—			9,402			—		9,402

Cash at end of year	$	—		$	—	$	—		$	—		$	573		$	—	$	573

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

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2012 at the reasonable assurance level.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Exchange Act, Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control—Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2012. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included herein.

During the three months ended December 31, 2012, there was no change in our system of internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

Certain information concerning our executive officers is set forth under the heading "Business—Executive Officers of the Registrant" in Item 1 of this Form 10-K.

We have adopted a Code of Business Conduct and Ethics for Employees and Officers ("Code") which covers a wide range of business practices and procedures. The Code represents the code of ethics applicable to our principal executive officer, principal financial officer and principal accounting officer or controller and persons performing similar functions ("senior financial officers"). A copy of the Code is available on our website at http://www.lonepineresources.com, and a copy will be mailed without charge, upon written request to Lone Pine Resources Inc., Suite 1100, 640-5^th Avenue SW, Calgary, Alberta T2P 3G4, attn: Corporate Secretary. We intend to disclose any amendments to or waivers of the Code on behalf of our senior financial officers on our website at http://www.lonepineresources.com promptly following the date of the amendment or waiver.

Pursuant to General Instruction G to Form 10-K, we incorporate by reference the remaining information required by this item from the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders, which will be filed with the SEC within 120 business days of December 31, 2012.

Pursuant to General Instruction G to Form 10-K, we incorporate by reference into this item the information to be disclosed in our definitive proxy statement for our 2013 Annual Meeting of Stockholders, which will be filed with the SEC within 120 business days of December 31, 2012.

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

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

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 14^th day of March, 2013.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities indicated on the 14^th day of March, 2013.

Exhibit No.			Description of Exhibit

	3.1		Amended and Restated Certificate of Incorporation of Lone Pine Resources Inc., incorporated herein by reference to Exhibit 3.1 to Amendment No. 5 to Form S-1 for Lone Pine Resources Inc. filed May 3, 2011 (File No. 333-171123).

	3.2		Second Amended and Restated Bylaws of Lone Pine Resources Inc., incorporated herein by reference to Exhibit 3.1 to Form 8-K for Lone Pine Resources Inc. filed October 13, 2011 (File No. 001-35191).

	4.1		Rights Agreement, incorporated herein by reference to Exhibit 4.1 to Amendment No. 7 to Form S-1 for Lone Pine Resources Inc. filed May 23, 2011 (File No. 333-171123).

	4.2		Certificate of Designation of Series A Junior Participating Preferred Stock of Lone Pine Resources Inc., dated May 11, 2011, incorporated herein by reference to Exhibit 4.2 to Amendment No. 7 to Form S-1 for Lone Pine Resources Inc. filed May 23, 2011 (File No. 333-171123).

	4.3		Indenture dated February 14, 2012, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., Lone Pine Resources (Holdings) Inc., Wiser Delaware LLC, Wiser Oil Delaware, LLC, and U.S. National Bank Association, as trustee, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Lone Pine Resources Inc. filed February 15, 2012 (File No. 001-35191).

	4.4		Registration Rights Agreement dated February 14, 2012, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., Lone Pine Resources (Holdings) Inc., Wiser Delaware LLC, Wiser Oil Delaware, LLC, and Credit Suisse Securities (USA) LLC, as representative of the Purchasers, incorporated herein by reference to Exhibit 4.2 to Form 8-K for Lone Pine Resources Inc. filed February 15, 2012 (File No. 001-35191).

	10.1		Separation and Distribution Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone Pine Resources Inc., incorporated herein by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed June 1, 2011 (File No. 001-35191).

	10.2		Transition Services Agreement dated June 1, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated herein by reference to Exhibit 10.2 to Form 8-K for Lone Pine Resources Inc. filed June 1, 2011 (File No. 001-35191).

	10.3		Tax Sharing Agreement dated May 25, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated herein by reference to Exhibit 10.4 to Form 8-K for Lone Pine Resources Inc. filed June 1, 2011 (File No. 001-35191).

	10.4		Employee Matters Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., and Lone Pine Resources Inc., incorporated herein by reference to Exhibit 10.5 to Form 8-K for Lone Pine Resources Inc. filed June 1, 2011 (File No. 001-35191).

	10.5		Registration Rights Agreement dated June 1, 2011, by and between Forest Oil Corporation and Lone Pine Resources Inc., incorporated herein by reference to Exhibit 10.3 to Form 8-K for Lone Pine Resources Inc. filed June 1, 2011 (File No. 001-35191).

		Description of Exhibit

10.6		Credit Agreement dated March 18, 2011 among Lone Pine Resources Inc., as parent, Canadian Forest Oil Ltd., as borrower, each of the lenders party thereto and JPMorgan Chase Bank, N.A., Toronto Branch as Administrative Agent, incorporated herein by reference to Exhibit No. 10.6 to Amendment No. 3 to Form S-1 for Lone Pine Resources Inc. filed April 8, 2011 (File No. 333-171123).

10.7		First Amendment dated April 29, 2011 to Credit Agreement dated March 18, 2011 among Lone Pine Resources Inc., as parent, Canadian Forest Oil Ltd., as borrower, each of the lenders party thereto and JPMorgan Chase Bank, N.A., Toronto Branch as Administrative Agent, incorporated herein by reference to Exhibit No. 10.6.1 to Amendment No. 5 to Form S-1 for Lone Pine Resources Inc. filed May 3, 2011 (File No. 333-171123).

10.8		Second Amendment dated September 21, 2011 to Credit Agreement dated March 18, 2011, among Lone Pine Resources Inc., as parent, Lone Pine Resources Canada Ltd., formerly known as Canadian Forest Oil Ltd., as borrower, each of the lenders party thereto and JPMorgan Chase Bank, N.A., Toronto Branch as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed September 22, 2011 (File No. 001-35191).

10.9		Third Amendment dated February 5, 2012 to Credit Agreement dated March 18, 2011, among Lone Pine Resources Inc., as parent, Lone Pine Resources Canada Ltd., formerly known as Canadian Forest Oil Ltd., as borrower, each of the lenders party thereto and JPMorgan Chase Bank, N.A., Toronto Branch as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed February 6, 2012 (File No. 001-35191).

10.10		Second Amended and Restated Promissory Note dated March 25, 2010 between Canadian Forest Oil Ltd. and Forest Oil Corporation, incorporated herein by reference to Exhibit 10.9 to Amendment No. 1 to Form S-1 for Lone Pine Resources Inc. filed January 31, 2011 (File No. 333-171123).

10.11		Amendment No. 1 dated May 13, 2010 to Second Amended and Restated Promissory Note dated March 25, 2010 between Canadian Forest Oil Ltd. and Forest Oil Corporation, incorporated herein by reference to Exhibit 10.10 to Amendment No. 1 to Form S-1 for Lone Pine Resources Inc. filed January 31, 2011 (File No. 333-171123).

10.12		Amendment No. 2 dated June 15, 2010 to Second Amended and Restated Promissory Note dated March 25, 2010 between Canadian Forest Oil Ltd. and Forest Oil Corporation, incorporated herein by reference to Exhibit 10.11 to Amendment No. 1 to Form S-1 for Lone Pine Resources Inc. filed January 31, 2011 (File No. 333-171123).

10.13	†	Lone Pine Resources Inc. 2011 Annual Incentive Plan, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed October 13, 2011 (File No. 001-35191).

10.14	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan, incorporated herein by reference to Exhibit 10.10 to Amendment No. 3 to Form S-1 for Lone Pine Resources Inc. filed April 8, 2011 (File No. 333-171123).

10.15	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Restricted Stock Agreement, incorporated herein by reference to Exhibit 10.13 to Amendment No. 4 to Form S-1 for Lone Pine Resources Inc. filed April 27, 2011 (File No. 333-171123).

		Description of Exhibit

10.16	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Phantom Stock Unit (in lieu of Restricted Stock) for Canadian Director Grantees, incorporated herein by reference to Exhibit 10.14 to Amendment No. 4 to Form S-1 for Lone Pine Resources Inc. filed April 27, 2011 (File No. 333-171123).

10.17	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Phantom Stock Unit (RSU Award) Agreement for Canadian Employee Grantees, incorporated herein by reference to Exhibit 10.15 to Amendment No. 4 to Form S-1 for Lone Pine Resources Inc. filed April 27, 2011 (File No. 333-171123).

10.18	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Phantom Stock Unit (SAR Award) Agreement for Canadian Employee Grantees, incorporated herein by reference to Exhibit 10.16 to Amendment No. 4 to Form S-1 for Lone Pine Resources Inc. filed April 27, 2011 (File No. 333-171123).

10.19	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Performance Unit Award Agreement for Canadian Grantees, incorporated herein by reference to Exhibit 10.17 to Amendment No. 4 to Form S-1 for Lone Pine Resources Inc. filed April 27, 2011 (File No. 333-171123).

10.20	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Stock Option Agreement for Canadian Grantees, incorporated herein by reference to Exhibit 10.18 to Amendment No. 4 to Form S-1 for Lone Pine Resources Inc. filed April 27, 2011 (File No. 333-171123).

10.21	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Phantom Stock Unit (RSU Award) Agreement for Canadian Employee Grantees (Cash Only), incorporated herein by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed June 6, 2011 (File No. 001-35191).

10.22	†	Form of Lone Pine Resources Inc. Severance Agreement for Chief Executive Officer, incorporated herein by reference to Exhibit 10.2 to Form 8-K for Lone Pine Resources Inc. filed June 6, 2011 (File No. 001-35191).

10.23	†	Form of Lone Pine Resources Inc. Severance Agreement for Executive Officers and Key Employees, incorporated herein by reference to Exhibit 10.3 to Form 8-K for Lone Pine Resources Inc. filed June 6, 2011 (File No. 001-35191).

10.24		Third Amendment to Second Amended and Restated U.S. Credit Agreement and Termination of Second Amended and Restated Canadian Credit Agreement dated May 25, 2011, by and among Forest Oil Corporation, Canadian Forest Oil Ltd., JPMorgan Chase Bank, N.A., Toronto branch, as Canadian administrative agent, JPMorgan Chase Bank, N.A., as global administrative agent, and the lenders named therein, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Lone Pine Resources Inc. filed June 1, 2011 (File No. 001-35191).

10.25	†	Form of First Amendment to the Lone Pine Resources Inc. Severance Agreement for Executive Officers and Key Employees, incorporated herein by reference to Exhibit 10.25 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

10.26	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Stock Option Agreement for Canadian Grantees, incorporated herein by reference to Exhibit 10.26 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

		Description of Exhibit

10.27	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Phantom Stock Unit (RSU Award) Agreement for Canadian Employee Grantees, incorporated herein by reference to Exhibit 10.27 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

10.28	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Phantom Stock Unit (SAR Award) Agreement for Canadian Employee Grantees, incorporated herein by reference to Exhibit 10.28 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

10.29	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Performance Unit Award Agreement for Canadian Grantees, incorporated herein by reference to Exhibit 10.29 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

10.30	†	Lone Pine Resources Inc. 2011 Stock Incentive Plan—Form of Phantom Stock Unit (RSU Award) Agreement for Canadian Employee Grantees (Cash Only), incorporated herein by reference to Exhibit 10.30 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

10.31	†	Amendment No. 1 dated March 21, 2012 to Tax Sharing Agreement dated May 25, 2011 by and between Forest Oil Corporation and Lone Pine Resources Inc, incorporated herein by reference to Exhibit 10.31 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

10.32	†	Lone Pine Resources Inc. 2012 Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed May 17, 2012 (File No. 001-35191).

10.33	†	Agreement for Purchase and Sale, dated as of November 13, 2012, by and between Lone Pine Resources Canada Ltd. and Canadian Natural Resources Limited, incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed November 13, 2012 (File No. 001-35191).

10.34	†	Employment Agreement dated February 28, 2013 between David Fitzpatrick and Lone Pine Resources Canada Ltd., incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed March 6, 2013 (File No. 001-35191).

10.35	†*	Settlement Agreement dated March 13, 2013 between David M. Anderson and Lone Pine Resources Inc.

10.36	†*	Settlement Agreement dated March 13, 2013 between Edward J. Bereznicki and Lone Pine Resources Inc.

14.1		Lone Pine Resources Inc. Code of Business Conduct and Ethics for Members of the Board of Directors (adopted as of March 17, 2011), incorporated herein by reference to Exhibit 14.1 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

14.2		Lone Pine Resources Inc. Code of Business Conduct and Ethics for Employees and Officers (adopted as of March 17, 2011), incorporated herein by reference to Exhibit 14.2 to Form 10-K for Lone Pine Resources Inc. filed March 23, 2012 (File No. 001-35191).

21.1	*	List of subsidiaries of Lone Pine Resources Inc.

23.1	*	Consent of Ernst & Young LLP.

23.2	*	Consent of Ernst & Young LLP.

		Description of Exhibit


23.3	*	Consent of DeGolyer and MacNaughton.

31.1	*	Certification of Principal Executive Officer of Lone Pine Resources Inc. as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

31.2	*	Certification of Principal Financial Officer of Lone Pine Resources Inc. as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.

32.1	**	Certifications of Principal Executive Officer and Principal Financial Officer of Lone Pine Resources Inc. pursuant to 18 U.S.C. §1350.

99.1	*	Reserves Evaluation Report of DeGolyer and MacNaughton, independent petroleum engineering consulting firm, dated February 25, 2013.

101.INS	††	XBRL Instance Document.

101.SCH	††	XBRL Taxonomy Extension Schema Document.

101.CAL	††	XBRL Taxonomy Calculation Linkbase Document.

101.LAB	††	XBRL Label Linkbase Document.

101.PRE	††	XBRL Presentation Linkbase Document.

101.DEF	††	XBRL Taxonomy Extension Definition.


ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to


Delaware (State or Other Jurisdiction of Incorporation or Organization)		27-3779606 (I.R.S. Employer Identification No.)
Suite 1100, 640-5th Avenue SW, Calgary, Alberta, Canada (Address of Principal Executive Offices)		T2P 3G4 (Zip Code)

Title of each class		Name of each exchange on which registered

Common Stock, Par Value US$0.01 Per Share		New York Stock Exchange
		Toronto Stock Exchange


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

	Year ended December 31,

	2012		2011		2010		2009
	US$		US$		US$		US$
Highest rate during the period		1.0299		1.0583		1.0054		0.9716
Lowest rate during the period		0.9599		0.9430		0.9278		0.7692
Average noon spot rate during the period(1)		1.0004		1.0111		0.9709		0.8757
Rate at the end of the period		1.0051		0.9833		1.0054		0.9555


PART I
Item 1.	Business	1
Item 1A.	Risk Factors	25
Item 1B.	Unresolved Staff Comments	48
Item 2.	Properties	48
Item 3.	Legal Proceedings	48
Item 4.	Mine Safety Disclosures	49
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	50
Item 6.	Selected Financial Data	52
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	53
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	82
Item 8.	Financial Statements and Supplementary Data	85
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	148
Item 9A.	Controls and Procedures	148
Item 9B.	Other Information	148
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	149
Item 11.	Executive Compensation	149
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	149
Item 13.	Certain Relationships and Related Transactions and Director Independence	149
Item 14.	Principal Accountant Fees and Services	149
PART IV
Item 15.	Exhibits and Financial Statement Schedules	150

	Estimated Proved Reserves (Bcfe)(1)		Estimated Proved Developed Reserves (Bcfe)(1)		Average Daily Net Sales Volumes (MMcfe/d)(1)(2)		Acreage				Proved Undeveloped Drilling Locations

	Net		Net		Net		Gross		Net		Gross		Net
Evi Area		109		39		19.0		89,120		82,015		147		134
Narraway/Ojay		62		62		34.3		179,315		120,329		—		—
Utica Shale		—		—		—		398,850		240,320		—		—
Liard Basin		—		—		—		53,788		52,995		—		—
Other		17		17		30.0		451,613		383,781		—		—

Total		188		118		83.3		1,172,686		878,781		147		134

	Estimated Proved Reserves(1)

	December 31, 2012						December 31, 2011
	Natural gas (MMcf)		Oil and liquids (Mbbls)		Total (MMcfe)		Natural gas (MMcf)		Oil and liquids (Mbbls)		Total (MMcfe)
Developed		77,061		6,831		118,050		163,530		8,363		213,708
Undeveloped		772		11,613		70,450		131,939		9,200		187,136

Total estimated proved reserves		77,833		18,445		188,500		295,469		17,563		400,844

	December 31, 2012

	Gross(1)		Net
Gas		331.0		208.3
Oil		377.0		314.0

Total		708.0		522.4

	December 31, 2012

	Developed Acreage				Undeveloped Acreage
Location	Gross		Net		Gross		Net
Evi		19,400		14,591		69,720		67,424
Narraway/Ojay		47,748		26,419		131,567		93,910
Utica Shale		0		0		398,850		240,320
Liard Basin		0		0		53,788		52,995
Other		133,831		103,318		317,782		279,804

Total		200,979		144,328		971,707		734,453

Name		Position(s)

David M. Fitzpatrick	54	Interim Chief Executive Officer and Director
Shane K. Abel	32	Vice President, Finance & Treasurer
Douglas W. Axani	42	Vice President, Exploration
Lyle H. Burke	55	Vice President, New Ventures & Technology
Mark E. Bush	53	Vice President, Operations
Charles R. Kraus	37	Vice President, General Counsel & Corporate Secretary
Shona F. Mackenzie	42	Vice President, Engineering & Exploitation

	High		Low

2011
Second Quarter(1)	US$	13.09	US$	10.15
Third Quarter	US$	12.30	US$	6.58
Fourth Quarter	US$	8.21	US$	5.38
2012
First Quarter	US$	7.80	US$	6.37
Second Quarter	US$	6.63	US$	2.25
Third Quarter	US$	2.78	US$	1.09
Fourth Quarter	US$	1.82	US$	0.91
2013
First Quarter (through and including March 8, 2013)	US$	1.45	US$	0.93

	High		Low

2011
Second Quarter(1)	$	12.68	$	10.25
Third Quarter	$	11.58	$	6.95
Fourth Quarter	$	8.23	$	5.74
2012
First Quarter	$	7.73	$	6.45
Second Quarter	$	6.49	$	2.35
Third Quarter	$	2.92	$	1.10
Fourth Quarter	$	1.78	$	0.88
2013
First Quarter (through and including March 8, 2013)	$	1.46	$	0.97



December 31, 2012	2.37	87.90
September 30, 2012	2.44	90.39
June 30, 2012	2.77	92.90
March 31, 2012	3.33	98.78
December 31, 2011	3.77	96.98

	Crude Oil (NYMEX WTI)

Swap Term	bbl/d		Weighted Average Hedged Price per bbl
Calendar 2013		2,000	$	98.60
Calendar 2013		500	US$	101.00

	Commodity Option

	Oil (NYMEX WTI)
Term	Option Expiration	Underlying Swap bbls/d		Weighted Average Price per bbl
Monthly in 2013	Monthly in 2013		500	$	95.05

	Commodity Collars

	Natural Gas (NYMEX Henry Hub)
Term	MMBtu/d		Weighted Average Floor Price per MMBtu	Weighted Average Ceiling Price per MMBtu
Calendar 2013		30,000	US$3.25	US$3.93

	Fair Value of Derivative Contracts

	(in thousands)
As of December 31, 2011	$	19,786
Net change in fair value		14,272
Net gains realized		(29,649	)

As of December 31, 2012	$	4,409


Report of Independent Registered Public Accounting Firm		86
Report of Independent Registered Public Accounting Firm		87
Report of Independent Registered Public Accounting Firm		88
Consolidated Balance Sheets as at December 31, 2012 and 2011		89
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010		90
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010		90
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010		91
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2012, 2011 and 2010		92
Notes to Consolidated Financial Statements		93

	(In thousands)

Proved properties	$	40,454
Unproved properties		26,285
Gas plant/pipelines		8,000
Asset retirement obligations		(292	)

	$	74,447

	Total		2012		2011		2010		2009 & Prior

			(In thousands)
Acquisition costs	$	85,161	$	10,300	$	37,383	$	20,724	$	16,754
Exploration costs		56,389		3,029		14,889		6,187		32,284
Development costs		6,552		5,260		1,088		5		199
Capitalized interest		854		—		401		453		—

Total	$	148,956	$	18,589	$	53,761	$	27,369	$	49,237

	At December 31, 2012						At December 31, 2011

	(In Thousands)
	Principal		Unamortized Discount		Total		Principal		Unamortized Discount		Total
Senior Notes	$	198,985	$	6,675	$	192,310	$	—	$	—	$	—
Bank credit facility		148,000		—		148,000		331,000		—		331,000

	$	346,985	$	6,675	$	340,310	$	331,000	$	—	$	331,000

	At December 31, 2012

	(In thousands)
2013	$	1,476
2014		1,476
2015		1,476
2016		1,914

Total minimum lease payments		6,342
Less: amount representing interest		(604	)

Present value of minimum lease payments		5,738
Less: current capital lease obligation		(1,217	)

	$	4,521

	1% Increase		1% Decrease

	(In thousands)
Effect on service and interest cost components	$	21	$	(17	)
Effect on post-retirement benefit obligation	$	226	$	(168	)

	Commodity Swaps

	Oil (NYMEX WTI)
Term	bbls/d(1)		Weighted Average Hedged Price per bbl
Calendar 2013		500	US$	101.00
Calendar 2013		2,000	$	98.60

	Commodity Collars

	Natural Gas (NYMEX Henry Hub)
Term	MMBtu/d(1)		Weighted Average Floor Price per MMBtu		Weighted Average Ceiling Price per MMBtu
Calendar 2013		30,000	US$	3.25	US$	3.93

	2013			2014			2015			2016			2017			Thereafter			Total

	(In thousands)
Operating leases(1)	$	2,037		$	2,065		$	2,015		$	1,992		$	2,076		$	8,545		$	18,730
Sub-lease recoveries(2)		(432	)		(472	)		(472	)		(472	)		(472	)		(39	)		(2,359	)
Purchase obligations(3)		4,269			2,821			2,427			1,811			917			—			12,245

	$	5,874		$	4,414		$	3,970		$	3,331		$	2,521		$	8,506		$	28,616

			Weighted Average Grant Date Fair Value per Option		Weighted Average Exercise Price		Aggregate Intrinsic Value			Average Exercise Price

Unvested at December 31, 2011	—		$	—	$	—	$	—	—	$	—
Awarded	686,606		$	1.97	$	6.80	$	—	—	$	—
Exercised	—		$	—	$	—	$	—	—	$	—
Forfeited	(41,900	)	$	2.05	$	7.08	$	—	—	$	—

Unvested at December 31, 2012	644,706		$	1.96	$	6.78	$	—	9,300	$	7.08


Expected term		4 years
Estimated volatility		35%
Risk-free interest rates		1.126% - 1.547%
Dividend yield		0%
Weighted average fair value		$0.34 - $2.05

At December 31, 2012

Shares authorized for issuance under the ESPP	750,000
Shares issued in 2012	(23,594	)
Shares issuable—issued in January 2013	(25,864	)

Shares available for future issuance	700,542


Expected rights life		3 months
Risk-free interest rates		0.87% - 0.97%
Estimated volatility		35%
Dividend yield		0%
Weighted average fair value		$0.43


		LONE PINE RESOURCES INC.
		By:		/s/ DAVID M. FITZPATRICK David M. Fitzpatrick Interim Chief Executive Officer

Signature		Title


/s/ DAVID M. FITZPATRICK David M. Fitzpatrick		Interim Chief Executive Officer and Director (Principal Executive Officer)
/s/ SHANE K. ABEL Shane K. Abel		Vice President, Finance & Treasurer (Principal Financial Officer)
/s/ CHRIS J. HOWE Chris J. Howe		Controller (Principal Accounting Officer)
/s/ DALE J. HOHM Dale J. Hohm		Director
/s/ LOYOLA G. KEOUGH Loyola G. Keough		Director
/s/ PATRICK R. MCDONALD Patrick R. McDonald		Director
/s/ DONALD MCKENZIE Donald McKenzie		Director
/s/ ROB WONNACOTT Rob Wonnacott		Director