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05-22-12 12:06 AM - Post#6233
Description Lone Pine Rsrcs. Director Donald McKenzie bought 84700 shares on 5-17-2012 at $ 3.49 BUSINESS OVERVIEW We are an independent oil and gas exploration, development and production company with operations in Canada. Our reserves, producing properties and exploration prospects are located in the provinces of Alberta, British Columbia and Quebec and the Northwest Territories. We were incorporated under the laws of the State of Delaware on September 30, 2010, and prior to our initial public offering ("IPO") on June 1, 2011, we were a wholly-owned subsidiary of Forest Oil Corporation ("Forest"). Our predecessor, Lone Pine Resources Canada Ltd., was acquired by Forest in 1996 and transferred to us prior to completion of our IPO. On September 30, 2011, Forest distributed all of the outstanding shares of our common stock that it owned to its shareholders (the "Distribution"). As a result of the Distribution, Forest has no remaining ownership interest in us. Our History During the past five years, we have primarily focused on the development of our Deep Basin and Evi areas, which were acquired in connection with Forest's acquisition of The Wiser Oil Company ("Wiser") in 2004. More recently, we have applied our experience from the Wild River field to the development and expansion of our Narraway/Ojay fields and furthered the development of our light oil assets in the Evi area. Beginning in 2009, we applied multi-zone slick-water fracture completion technology to our Narraway/Ojay fields that yielded improved results. As a result, we undertook a significant leasing campaign in the Narraway/Ojay area and completed an acquisition in April 2011 of approximately 35,700 net acres in the Narraway field, which increased our acreage position from approximately 21,000 net acres at December 31, 2008 to approximately 121,088 net acres at December 31, 2011. We also increased our oil drilling activity in our Evi area in 2009, accelerating our horizontal drilling program that began in 2006. From 2006 through December 31, 2011, we have drilled a total of 72 gross horizontal oil wells in the Evi area. Due to the success of our initial horizontal wells, we undertook a significant leasing campaign in the Evi area, which increased our net acreage position from approximately 11,000 net acres at December 31, 2004 to approximately 57,382 net acres at December 31, 2011. Through our leasing efforts in Quebec, which began in 2007, we have acquired approximately 240,320 net acres in the Utica Shale play as of December 31, 2011. From 2007 through 2010, we participated in the drilling of ten exploration wells. We intend to continue to evaluate our acreage for future development while working with the Quebec Oil & Gas Association and provincial government agencies as the province undertakes a strategic environmental assessment ("SEA") of shale gas drilling in the province as recommended by the province's environmental public hearing board, the Bureau d'audienees publiques sur l'environnement ("BAPE"). In addition to our large shale gas position in Quebec, as of December 31, 2011, we had approximately 52,995 contiguous net acres in the Liard Basin, located in the Northwest Territories, that are prospective for the Muskwa Shale. We believe that our acreage in the Liard Basin is analogous to the Muskwa Shale in the Horn River Basin. As we have expanded into new plays, we also have divested assets that did not meet our development growth strategy. Starting in the fourth quarter of 2009 and through December 31, 2011, we divested approximately $159 million of certain non-core or non-operated oil and gas properties, primarily in December 2009 and April 2010, that, at the time the divestitures occurred, had a combined net production rate of 16 MMcfe/d. Our Business Strategy Our business strategy is to increase stockholder value by efficiently increasing production, reserves and cash flow by applying horizontal drilling and new completion technologies to our significant and diversified undeveloped acreage positions. We expect to execute this strategy while managing our debt levels relative to our estimated proved reserves and cash flow. We endeavor to execute this strategy as follows: • Exploit and develop resource plays by applying horizontal drilling and new completion technologies. We intend to apply the latest exploitation technologies to our resource plays, including horizontal drilling and multi-stage hydraulic fracture stimulation techniques. Each of our Evi and Deep Basin areas has a large number of remaining drilling locations where delineation drilling has established the existence of a consistent geologic trend, creating what we believe are repeatable development opportunities through horizontal and vertical drilling. • Enhance returns by focusing on operational control and cost efficiencies. We plan to develop and execute large-scale, repeatable drilling programs in areas where we have high working interests, concentrated land positions, large drilling inventories and operational control to reduce costs and achieve economies of scale, thereby attaining higher rates of return on invested capital. • Maintain a diversified commodity mix. Our current asset base is composed of both light oil and natural gas opportunities. Our diversified portfolio allows us to focus on one commodity over another when disparity between commodity prices dictates. In 2011, we were able to successfully increase our average liquids production weighting from 14% in the first quarter to 27% in the fourth quarter by focusing our capital investment on light oil. In 2012, we again plan to focus our capital budget on light oil by allocating approximately 80% of our total budget to light oil opportunities. Based on this focus, we expect to increase our average liquids production weighting from 21% in 2011 to 35% in 2012 and to approximately 40% by the end of 2012. We plan on continuing a diversified approach over the long term, with the majority of our capital allocated in the short term to assets with the highest rates of return. • Develop, expand and rationalize our asset base through leasehold and property acquisitions, divestitures and exploration. We intend to pursue leasehold and property acquisitions to enhance existing business operations in our core areas and to gain entrance into new, complementary resource plays, with a preference for liquids-rich hydrocarbon prospects. We also plan to pursue a measured exploration drilling program in these areas in order to expand the ultimate scope of commercial development of our asset base. As economic conditions permit, we intend to divest assets that do not fit our primary business strategy, including those without significant development opportunities. • Maintain financial flexibility. We plan to maintain a strong liquidity position to successfully execute our growth strategy through the application of budget controls and disciplined financial management. We intend to focus on managing our debt levels relative to our estimated proved reserves and cash flow. We intend to also support our future cash flow through the management of a measured commodity hedging program. Our Competitive Strengths We believe we have a number of competitive strengths that will help us to execute our business strategy: • Large, contiguous acreage positions, with multi-year, diversified drilling inventory. Our leasing efforts, which have included early identification and leasehold acquisitions of acreage in prospective areas, have enabled us to develop large, contiguous acreage positions. In total, we have accumulated approximately 1.1 million gross (0.8 million net) acres in prospective areas, with approximately 79% of the acreage classified as undeveloped as of December 31, 2011. We have a commodity-diverse drilling portfolio with approximately 84 gross (77 net) proved undeveloped drilling locations as of December 31, 2011 in our Evi area targeting premium-priced light oil, and approximately 62 gross (44 net) proved undeveloped drilling locations as of December 31, 2011 in the Deep Basin targeting natural gas and NGLs. Our acreage positions allow us to be more competitive in our development efforts through the execution of large-scale drilling and multi-stage hydraulic fracture stimulation programs and the establishment of centralized gathering systems and associated facilities. • Established light oil resource with future development upside. The Evi area has historically been produced extensively from a deeper Granite Wash horizon with over 2,500 vertical wells drilled into the play. Since 2006, the focus in the Evi area has been on a shallower Slave Point horizon that has been exploited through horizontal drilling and multi-stage hydraulic fracture stimulation. The presence of the deeper producing horizon has provided extensive well control and formed the basis of a specific geological model that we use in the development of the area. Recent developments in the area have focused on increasing the number of hydraulic fracture stages placed into a horizontal well. In 2011, we increased the average fracture density from six stages to ten stages and realized an increase in well productivity of over 60%. We believe that further improvement in well design combined with additional downspacing across our acreage provides for extensive future development opportunities. • Multi-stacked intervals in the Deep Basin, which yield low-risk incremental development opportunities. The Deep Basin has historically been a highly prospective area for the production of natural gas and NGLs. The Deep Basin fields produce from a minimum of ten different stacked producing intervals, many of which have not been exploited horizontally. With the advancement of drilling and completion technology, many of these intervals now have the potential to be developed with favorable economic results. We believe our interests in over 250 productive wells in the Deep Basin, completed in multiple zones, and our understanding of the geology of the basin, give us a competitive advantage in the development of these unexploited intervals. Our primary focus in the Deep Basin will be in the Narraway/Ojay and Wild River fields. We believe that the application of horizontal drilling and multi-stage fracturing technologies, while more expensive than vertical wells, will allow us to develop this and other intervals at enhanced economic rates of return. • Management and technical team with demonstrated operational and technical skills. Our management and technical team has extensive expertise in the oil and gas industry. We believe that our team is one of our principal competitive strengths, as evidenced by our track record in establishing, developing and expanding our core assets with profitable rates of return. Our team has successfully implemented horizontal drilling and multi-stage hydraulic fracturing technologies and plans to expand the application of these technologies across our resource plays. From the completion of our first horizontal well in the Evi area in 2006 through December 31, 2011, we have drilled a total of 72 gross horizontal wells, improved production rates and recoveries by increasing the number of fracturing stages and reduced drilling times and drilling costs through efficiency gains. We expect to continue to pursue the application of horizontal drilling and multi-stage fracturing technologies on our extensive resource bases. • Operating control over a majority of our properties, with limited near-term lease expiries. We have high working interests in our properties and currently operate over 80% of our production. Further, we operated all of our 2011 drilling program and expect to operate substantially all of our planned 2012 drilling program. As the designated operator, we believe we can maintain control over capital expenditures, operating costs and the pace of exploration and development. We also have limited near-term lease expiries. As of December 31, 2011, approximately 85% of our net acreage was held by leases whose terms extend beyond the next three years. • Strong balance sheet. We have a $500 million credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. As of December 31, 2011, our borrowing base under the bank credit facility was $425 million and we had approximately $331 million in borrowings under our bank credit facility. In February 2012, our wholly-owned subsidiary, Lone Pine Resources Canada Ltd., issued US$200 million of 10.375% Senior Notes due 2017 (the "Senior Notes"). The net proceeds of approximately $192 million, after deduction of original issue and initial purchaser discounts and estimated offering expenses, were used to partially repay borrowings outstanding under our bank credit facility. As of March 20, 2012, we had approximately $185 million of secured indebtedness outstanding under our bank credit facility and secured borrowing capacity of approximately $188 million (after deducting $1.6 million of outstanding letters of credit). • Strong hedging positions. As of March 20, 2012, we had 25,000 MMBtu/d, representing approximately 40% of our forecasted 2012 average daily net natural gas production volumes hedged at an average NYMEX Henry Hub price of US$5.09 per MMBtu/d and 3,000 bbls/d of crude oil, representing approximately 55% of our forecasted 2012 average daily net crude oil production volumes hedged at US$102.35 (as to 2,000 bbls/d) and $100.98 (as to 1,000 bbls/d). We also had 1,000 bbls/d of 2013 crude oil production hedged at $102.00 (as to 500 bbls/d) and US$101.00 (as to 500 bbls/d). Financial Information About Segments and Geographical Areas We operate our business as a single segment with similar economic characteristics, technology, manufacturing processes, customers, distribution and marketing strategies, regulatory environments and shared infrastructures. We operate in one industry segment, and our oil and gas exploration and production activities are exclusively within Canada. Our financial information, including our net sales and long-lived assets by geographical area, is included in our consolidated financial statements and the related notes contained elsewhere in this Form 10-K. Evi Area As of December 31, 2011, we had approximately 57,382 net acres in and near the Evi field, located in the Peace River Arch area of northern Alberta. This position offers us a significant development opportunity for premium-priced light oil. From 2006 through December 31, 2011, we have drilled a total of 72 horizontal wells in the Evi area. We acquired our initial acreage position in the Evi field in 2004 as part of Forest's acquisition of Wiser, and we have significantly expanded our acreage position through Crown leasing and acquisitions from approximately 11,000 net acres at December 31, 2004 to 57,382 net acres at December 31, 2011. As of December 31, 2011, our acreage position in the Evi area consists of 100 gross (89 net) sections on which we have 133 gross (102 net) productive wells in the Slave Point formation, of which 72 are horizontal wells. As of December 31, 2011, we had 94 Bcfe of total estimated proved reserves at Evi, including 40 Bcfe that are classified as proved developed reserves. As of December 31, 2011, we had 84 gross (77 net) proved undeveloped drilling locations in the Evi area. Initially, we plan to drill six horizontal wells per section, although regulatory spacing in the Evi field for the Slave Point formation generally provides for eight wells per section and we have received regulatory approval to downspace certain sections in the central area of Evi to up to 16 wells per section. In 2011, we drilled 47 gross (47 net) horizontal wells in the Evi area as compared to 25 gross (17 net) wells in 2010 and increased the number of fracture stimulation stages from an average of six to ten stages. Our working interest in all of the wells drilled in 2011 is 100%. During 2011, we had average daily net sales volumes of 2,357 bbls/d from production in the Evi area. We plan to drill up to 48 horizontal wells in the Evi area in 2012. We believe that we can ultimately enhance production rates and recoveries in the Evi area through further development drilling, including further downspacing of our acreage, completion optimization and secondary recovery techniques, such as waterflooding. We intend to continue to expand our facilities in the Evi area to accommodate the growing crude oil volumes in the area and continue to invest in our operated waterflood pilot project that we initiated in 2011. In 2012, we plan to focus our capital budget on light oil by allocating approximately 80% of our total capital budget or, approximately $165 million, to the Evi area. Our historical costs to drill and complete horizontal wells have ranged from $1.9 million to $5.2 million per well and have averaged $2.9 million per well. We expect that wells drilled in 2012 will have an average cost of $2.9 million per well. Deep Basin Area As of December 31, 2011, we had approximately 157,779 net acres in the Deep Basin, including approximately 121,088 net acres in the Narraway/Ojay fields, located in Alberta and British Columbia, and approximately 12,853 net acres in the Wild River field, located in the southeast portion of the Deep Basin. In 2011, we drilled and completed 6 gross (5.5 net) wells in the Narraway/Ojay fields, including 1 gross (1 net) horizontal well. In the fourth quarter of 2011, we had average daily net sales volumes of 66 MMcfe/d from production in the Deep Basin. Our development of these assets is primarily focused on our Narraway/Ojay and Wild River fields. Geologically, these fields have a minimum of ten different stacked producing intervals, and we are able to produce from multiple intervals within an individual wellbore. We currently have no significant near-term expiries or drilling obligations in the Deep Basin, which has allowed us to be flexible with our 2012 capital budget and defer significant natural gas investment until natural gas prices improve from their existing multi-year lows. In 2012, we are allocating approximately 7% of our total capital budget, or approximately $15 million, to the Deep Basin, where we plan to focus primarily on recompletion opportunities. Narraway/Ojay Fields As of December 31, 2011, we had approximately 121,088 net acres in the Narraway/Ojay fields, located in Alberta and British Columbia. This acreage position establishes us as one of the top acreage holders in the area. Following positive drilling results in the Narraway/Ojay fields during 2009, we undertook a significant leasing campaign in the Narraway/Ojay area, which increased our acreage position from approximately 21,000 net acres at December 31, 2008 to approximately 121,088 net acres at December 31, 2011. As of December 31, 2011, our land holding was 206 gross (162 net) sections, and we had 29 gross (24 net) proved undeveloped drilling locations in the Narraway field. Regulatory spacing in the Narraway field currently provides for four wells per section. Our acreage position in the Ojay field as of December 31, 2011 consisted of 56 gross (23 net) sections on which we had 9 gross (4 net) productive wells. As of December 31, 2011, we had 3 gross (1.5 net) proved undeveloped drilling locations in the Ojay field. Regulatory spacing in the Ojay field currently provides for one well per section. From the fourth quarter of 2008 to the fourth quarter of 2011, we have increased our net sales volumes from the Narraway/Ojay fields from 5 to 44 MMcfe/d, which we believe demonstrates the significant growth potential of the Narraway/Ojay fields. Our wells in the Narraway/Ojay fields provide multi-zone completion opportunities, with the Nikanassin formation as the anchor zone, and with numerous gas bearing formations in zones above, or uphole of, the anchor zone. These uphole zones can be commingled for production purposes. The Nikanassin is the anchor formation in the fields, and we sometimes refer to the Narraway/Ojay fields as part of the Nikanassin Resource Play. On April 29, 2011, we completed the acquisition of certain natural gas properties located in the Narraway/Ojay fields. The acquisition increased our working interests in certain properties that we already owned and operated in the Narraway field from approximately 50% to 100% and provided us with additional capacity in gathering systems and a gas plant in the Narraway field. In addition, the acquisition increased our acreage position by approximately 85,100 gross (35,700 net) acres. Wild River Field We have approximately 12,853 net acres in the Wild River field, located in the southeast portion of the Deep Basin. We acquired our position in 2004 as part of Forest's acquisition of Wiser. As of December 31, 2011, our acreage position in the Wild River field consisted of 41 gross (20 net) sections on which we have 156 gross (92 net) productive wells. As of December 31, 2011, we had 26 gross (17 net) proved undeveloped drilling locations in the Wild River field. Regulatory spacing in the Wild River field currently provides for eight wells per section. We have drilled 143 wells in the Wild River field since our acquisition in 2004 through the fourth quarter of 2011. During this same period, we also reduced the average number of days to drill each well by approximately 30%. We have targeted multiple-zone intervals, with the Cadomin formation as the anchor zone. The stacked pay in our Wild River field has provided drilling opportunities that have been vertically developed; however, we believe the application of horizontal drilling and multi-stage fracturing technology, while more expensive than vertical wells, will further enhance the economic development of this field. Industry activity in the area has demonstrated horizontal success targeting the uphole, liquids-rich Cardium interval, and we believe our acreage is also prospective for this interval. Shales As of December 31, 2011, we had approximately 240,320 net acres in Quebec that are prospective for the Utica Shale. No reserves are attributed to our Quebec properties. Natural gas produced from this area is in close proximity to major markets in Canada and the northeastern United States, which generally provides for premium product pricing compared to the NYMEX Henry Hub pricing. The Utica Shale is relatively shallow compared to other shale plays in North America, which we believe will provide for an economic advantage relative to the drilling costs associated with developing the resource. In 2006 and 2007, we took cores from three vertical test wells targeting a section of the upper Utica Shale, or the Upper Utica, and tested two of these wells at a peak rate of 1,000 Mcfe/d. We then drilled three horizontal test wells (each with 2,000 foot laterals and four fracture stimulation stages), which had similar initial production test rates. Our historical costs to drill and complete these horizontal wells in the Utica Shale have ranged from US$5.8 million to US$7.0 million. We participated in a vertical well in the area during the fourth quarter of 2010 and took samples to further confirm the rock properties associated with the Middle Utica. Subject to minimal capital commitment, approximately 50% of our acreage is under leases that will expire in 2019, approximately 4% of our acreage is under leases that will expire in 2022 and approximately 46% of our acreage is under leases that will expire in 2023. Furthermore, transportation infrastructure is already in place in the Utica Shale, which should lower development expenditures. We believe that these factors, coupled with the area's premium natural gas prices, provide favorable development economics. On March 8, 2011, the Government of Quebec announced that it would move forward with the SAE of shale gas drilling in the province as recommended by the BAPE, in a report delivered to the Quebec Minister of Sustainable Development, Environment and Parks. A committee was appointed in May 2011 to conduct the SEA, which is expected to take 18 to 30 months, during which the government has indicated that hydraulic fracturing will only be permitted in Quebec for scientific data gathering purposes if required for the SEA and on the committee's recommendation. The SEA committee is to report annually, with its first report due in May 2012, and ultimately propose changes to the current legislative and regulatory framework for oil and gas exploration and development in Quebec. On June 13, 2011, in response to concerns over the impact of the SEA on the terms of existing exploration licenses, legislation was implemented to exempt holders of licenses to explore for petroleum, natural gas and underground reservoirs from prescribed exploration work requirements until a date to be determined by the government (but not later than July 13, 2014), and effectively extend the term of such licenses for the same period. The legislation also, however, prohibits oil and gas activities in the St. Lawrence River upstream of Anticosti Island and on the islands situated in that part of the river and revokes, without compensation, oil and gas rights previously issued for that area. We held exploration licenses to 33,460 net acres under the St. Lawrence River, representing approximately 14% of our overall net acres in Quebec, that were revoked by this legislation and are considering available alternatives with respect to the government's action. The revoked acreage consists entirely of undeveloped lands. No reserves are attributed to our Quebec properties. During the SEA period, we will be able to explore and gather scientific data on our remaining undeveloped shale acreage positions. The Ministry of Natural Resources is expected to provide interim regulations to act under during the SEA committee's undertakings. See Part I, "Item 1A. Risk Factors—Risks Related to Our Business— New laws or regulatory requirements relating to hydraulic fracturing could make it more difficult or costly for us to perform fracturing of producing formations and could have an adverse effect on our ability to produce oil and gas from new wells " and "—Environmental Regulation." As of December 31, 2011, we had approximately 52,995 net acres in the Liard Basin, located in the Northwest Territories, that are prospective for the Muskwa Shale. No reserves are attributed to our Liard Basin properties. This is a newly developing natural gas shale play adjacent to the producing Horn River Basin. We believe that our acreage in the Liard Basin is analogous to the Muskwa Shale in the Horn River Basin. Our acreage is located in close proximity to a pipeline in the Northwest Territories providing for the sale and distribution of any natural gas produced. In the third and fourth quarters of 2011, we re-entered and recompleted a well in the Liard Basin, and in February 2012, we submitted an application to the National Energy Board to potentially continue the lease for up to 21 more years. Infrastructure During 2010, we spent $49 million on the construction of key infrastructure and the purchase of related equipment in the Narraway/Ojay fields. In late November 2010, we completed construction of a natural gas pipeline connecting shut-in wells from our Ojay acreage in British Columbia to sales meters in western Alberta. Our gas gathering system and associated facilities at the Narraway/Ojay fields were expanded in order to alleviate capacity restrictions, improve timely takeaway of our gas and enable us to proceed with our development plan. We believe that we have installed sufficient capacity to meet our near-term drilling plans for our assets in those fields and accommodate third-party volumes. At the Evi area, we have installed infrastructure that allows us to transport by pipeline the majority of our oil production, which has minimized the cost of trucking and the downtime associated with weather-dependent access to some locations. We intend to install, as needed, additional infrastructure in our core areas, which should allow us to continue to substantially control the pace of development, ensure timely takeaway of our production volumes and continue our commitment to improving operational efficiencies and cost control. CEO BACKGROUND Dale J. Hohm. Mr. Hohm was appointed to our Board in November 2011. Mr. Hohm has served as the Chief Financial Officer of MEG Energy Corp., a Canadian oil sands company, since March 2004. Mr. Hohm has over 30 years of corporate finance and accounting experience with 14 years of experience as the Vice President, Finance/CFO of Toronto Stock Exchange ("TSX")-listed companies engaged in oil and gas, upstream and services businesses. Mr. Hohm's experience includes working for Deloitte & Touche, Chartered Accountants from 1980 until 1990. He also worked for Numac Oil & Gas Ltd., serving as the Vice President, Treasurer and Corporate Secretary from 1990 until 1993, Vice President, Audit and later as the Vice President, Finance and Corporate Secretary, from 1994 until 2001. Mr. Hohm then served as the Chief Financial Officer of Enerflex Systems Ltd. from April 2001 until February 2004. Mr. Hohm received a Bachelor of Commerce from the University of Alberta in 1980 and received the designation of Chartered Accountant in 1983. We believe that Mr. Hohm is well qualified to serve as a director of our company for several reasons. Mr. Hohm has held leadership positions with a number of public companies engaged in oil and gas exploration and production and with a major accounting firm and has extensive experience with energy company audits and audit committees and related risk management matters. We believe that Mr. Hohm's many years of corporate finance and accounting experience specializing in the oil and gas exploration and production industry is essential in order to quickly identify, understand and address new trends, challenges and opportunities that we will face. Mr. Hohm has also gained knowledge and understanding of corporate governance issues through his years of working as an executive officer of numerous public companies. We believe that Mr. Hohm's financial background and extensive knowledge and experience with exploration and production companies make him an excellent resource for our management and our other directors. Loyola G. Keough. Mr. Keough was appointed to our Board in June 2011, upon the completion of our IPO. Mr. Keough has served as a partner of Bennett Jones LLP, a Canadian law firm, since 1990, chairs that firm's regulatory department and represents utility companies, pipelines, project developers, industry associations, gas buyers, producers and banks. He has particular experience in oil, gas, electricity, liquefied natural gas and compressed natural gas matters. Mr. Keough has also served as a member of the board of directors of WBI Canadian Pipeline, Ltd. and Nytis Exploration Company since 2000 and 2003, respectively. We believe that Mr. Keough is well qualified to serve as a director of our company for several reasons. As chair of his law firm's regulatory department, Mr. Keough has extensive knowledge of Canadian regulatory matters. Mr. Keough has many years of experience advising companies in the oil and gas exploration and production industry, and we believe that such experience is essential in order to quickly identify, understand and address new trends, challenges and opportunities that we will face. In addition, Mr. Keough has gained knowledge and understanding of corporate governance issues through prior service as a board member. We believe that Mr. Keough's regulatory expertise and extensive knowledge and experience with exploration and production companies with operations focused mainly in Canada make him an excellent resource for our management and our other directors. Donald McKenzie. Mr. McKenzie was appointed to our Board in September 2011, upon completion of the Distribution. From January 2006 to December 2009, Mr. McKenzie served as President and Chief Executive Officer of M-I SWACO, a joint venture between Smith International ("Smith") and Schlumberger Limited. From January 1, 2010 to September 2010, Mr. McKenzie served as advisor to the Chief Executive Officer, President and Chief Operating Officer of Smith. Mr. McKenzie retired from Smith in September 2010. Mr. McKenzie served as Senior Vice President, Eastern Hemisphere Operations of M-I SWACO from April 1994 to January 2007. From March 2008 to September 2010, Mr. McKenzie served on the board of directors of CE Franklin Ltd. Mr. McKenzie is a member of the Society of Petroleum Engineers, the International Association of Drilling Contractors and the Institute of Corporate Directors. We believe that Mr. McKenzie is well qualified to serve as a director of our company for several reasons. Mr. McKenzie has many years of experience in the oil and gas exploration and production industry, and we believe that such experience is essential in order to quickly identify, understand and address new trends, challenges and opportunities that we will face. Mr. McKenzie has also gained knowledge and understanding of corporate governance issues through his years of serving as a public company senior executive and board member. We believe that Mr. McKenzie's geologic training and extensive knowledge and experience with exploration and production companies with operations focused mainly in the United States and Canada make him an excellent resource for our management and our other directors. MANAGEMENT DISCUSSION FROM LATEST 10K Overview We are an independent oil and gas exploration, development and production company with operations in Canada. Our reserves, producing properties and exploration prospects are located in the provinces of Alberta, British Columbia and Quebec and the Northwest Territories. We were incorporated under the laws of the State of Delaware on September 30, 2010, and prior to our IPO on June 1, 2011, we were a wholly-owned subsidiary of Forest. Our predecessor, LPR Canada, was acquired by Forest in 1996 and transferred to us prior to completion of our IPO. Upon completion of our IPO, Forest retained the controlling interest in us, owning 82% of the outstanding shares of our common stock. On September 30, 2011, Forest distributed all of the outstanding shares of our common stock that it owned to its shareholders. As a result of the Distribution, Forest has no remaining ownership interest in us. DeGolyer and MacNaughton, our independent reserves engineers, estimated our proved reserves to be approximately 401 Bcfe as of December 31, 2011, of which approximately 26% was oil and natural gas liquids, approximately 74% was natural gas and approximately 53% was classified as proved developed reserves. As of December 31, 2011, we had approximately 151 gross (125 net) proved undeveloped drilling locations and approximately 1.1 million gross (0.8 million net) acres of land (approximately 79% of which was undeveloped). Financial and other information disclosed herein relating to the time prior to our inception (September 30, 2010) reflects the financial position, results of operations, cash flows or other information, as the case may be, of our predecessor, LPR Canada. Financial and other information disclosed relating to the period from our inception through the completion of our IPO (June 1, 2011) reflects the financial position, results of operations, cash flows or other information, as the case may be, of Lone Pine and its predecessor, LPR Canada, on a combined basis. Financial and other information disclosed relating to the period subsequent to and including June 1, 2011 reflects the financial position, results of operations, cash flows or other information, as the case may be, of Lone Pine and its consolidated subsidiaries. Change in Functional Currency and Reporting Currency Effective October 1, 2011, Lone Pine changed its functional currency and reporting currency from the U.S. dollar to the Canadian dollar. The change in functional currency did not have a significant impact on our consolidated financial statements for either the fourth quarter of 2011 or the year ended December 31, 2011 as Lone Pine's operations are primarily carried out by its operating subsidiary, LPR Canada. The functional currency of LPR Canada has not changed and continues to be the Canadian dollar. Prior to the Distribution, Lone Pine used the same reporting currency as Forest, which was the U.S. dollar, in its consolidated financial statements. However, after the Distribution, our management determined that our financial statements should be presented using the Canadian dollar, in order to present Lone Pine's financial statements in the same currency as its functional currency, and to minimize the impact of changes in foreign currency exchange rates on our financial statements. The determination to change Lone Pine's reporting currency was based on a number of factors, which included the following: (1) Lone Pine has no assets or operations in the United States, (2) substantially all of Lone Pine's operations are conducted in a single functional currency, the Canadian dollar, and (3) the reporting currency selected, the Canadian dollar, is the same as the functional currency. Prior to the change in reporting currency, our consolidated statements of operations were translated from Canadian dollars using the weighted average exchange rate for the period. The resulting foreign currency translation adjustment was reported as a component of other comprehensive income and accumulated other comprehensive income. As a result of our change in reporting currency, all comparative financial information has been recast from U.S. dollars to Canadian dollars to reflect our consolidated financial statements as if they had been historically reported in Canadian dollars, consistent with ASC 830, Foreign Currency Matters . The consolidated U.S. dollar balance sheet at December 31, 2010 was translated into Canadian dollars by translating assets and liabilities at the end-of-period exchange rate and translating equity balances at historical exchange rates. As a result of our change in functional currency and reporting currency, there is no difference between the reporting currency and the functional currency of Lone Pine Resources Inc. and any of its operating subsidiaries. Following the changes in functional currency and reporting currency, we will be subject to foreign currency exchange rate risk relating to the Senior Notes, certain of our derivative instruments and our delivery commitment of approximately 21,000 MMBtu/d of natural gas under a long-term sales contract expiring in 2014. See "—Critical Accounting Policies, Estimates, Judgments and Assumptions —Change in Reporting and Functional Currency" for more information about our change in reporting currency, including the reasons for the change, the manner in which the change has been applied to recast prior period financial statements and the major financial statement categories that are denominated in U.S. dollars, and for certain U.S. dollar financial information as of and for the year ended December 31, 2011. See also note 2 to our consolidated financial statements. Financial and Operating Performance Our financial and operating performance for 2011 included the following highlights: • On June 1, 2011, we completed our IPO of 15 million shares of our common stock. In connection with our IPO and pursuant to our separation and distribution agreement with Forest, Forest contributed to us its ownership interest in LPR Canada in exchange for 69,999,999 shares of our common stock and a cash distribution of $28.7 million. We received net proceeds from our IPO of approximately $173.1 million and used these net proceeds to pay $28.7 million to Forest as partial consideration for Forest's contribution to us of Forest's direct and indirect interests in its Canadian operations. We used the remaining net proceeds and borrowings under our bank credit facility to repay outstanding indebtedness owed to Forest, including intercompany advances and accrued interest. • Our average daily net sales volumes for the fourth quarter of 2011 and for the year ended December 31, 2011 were 99 MMcfe/d and 94 MMcfe/d respectively, and our average daily oil and NGLs net sales volumes for the fourth quarter of 2011 increased 27% to 4,499 bbls/d, compared to 3,544 bbls/d in the third quarter of 2011 as our average net liquids percentage increased from 22% to 27%. • We drilled a total of 47 gross (47 net) horizontal light oil wells at Evi and 6 gross (5.5 net) natural gas wells in the Deep Basin with a 100% success rate. • We generated Adjusted EBITDA of $128.2 million, a 27% increase over 2010 and Adjusted Discretionary Cash Flow of $118.4 million, a 26% increase over 2010. During February 2012, LPR Canada completed the Senior Notes offering. The net proceeds of approximately $192 million were used to partially repay borrowings outstanding under our bank credit facility. The Senior Notes are guaranteed by Lone Pine and all of Lone Pine's wholly-owned subsidiaries (other than LPR Canada). Recent Trends and Outlook for 2012 Beginning in the second half of 2008 and continuing throughout 2011, Canada, the United States and other industrialized countries experienced a significant economic slowdown. During the same time period, North American natural gas supply increased as a result of increased domestic unconventional natural gas development and associated natural gas from oil development. In the second half of 2008, oil and natural gas prices declined dramatically. While oil and NGL prices have steadily improved since the first quarter of 2009, North American natural gas prices have remained at low levels and declined further in late 2011 as a result of increased supply and weak domestic demand in the United States. We do not expect natural gas prices to improve significantly in 2012. As a result, we plan to focus our capital expenditures in 2012 primarily on light oil opportunities. Capital Budget for 2012 We have established a capital budget of approximately $200 million to $220 million for 2012 and plan to focus our drilling program almost entirely on our light oil opportunities in the Evi area. We have elected to pursue a 2012 capital program designed to maintain financial flexibility, while focusing on high margin light oil projects. We plan to fund our 2012 capital budget primarily through cash flow from operating activities, as well as borrowings under our bank credit facility. We plan to allocate approximately $165 million, or approximately 80%, of our total capital budget to light oil development in the Evi area. We plan to drill and complete up to 48 gross (48 net) horizontal wells in the Evi area in 2012 and to continue to advance development through further downspacing and additional infill drilling. We expect to complete the planned drilling program in the Evi area with the two-rig program that we currently have in place. We also intend to continue to expand our facilities in the Evi area to accommodate the growing crude oil volumes in the area and continue investment in our operated waterflood pilot project that we initiated in 2011. Given the current disparity between oil and natural gas prices, we intend to allocate minimal capital towards our natural gas properties at this time. Since we have no significant near term lease expiries or drilling obligations on our natural gas assets, we plan to focus almost exclusively on light oil projects while North American natural gas prices continue to trade at multi-year lows. Should natural gas prices recover through 2012, we expect to be able to alter our spending plans and allocate capital to our drill-ready natural gas projects. Oil Differentials The primary factors influencing our oil differential to the NYMEX WTI price are (1) the quality of our oil and (2) the proximity of our oil production to major consuming and refining markets. Among other things, there are two characteristics that determine the quality of our oil: (1) the oil's American Petroleum Institute ("API") gravity and (2) the oil's sulfur content by weight. In general, lighter oil (with higher API gravity) sells at a higher price than heavier oil, because lighter oil produces a larger number of lighter liquid products, such as gasoline, that have a higher resale value. On average, the oil that we produce is approximately 35 degrees API. Oil with low sulfur content, or "sweet" crude oil, such as the oil we produce at Evi, is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil, or "sour" crude oil. The proximity of our oil production to major consuming and refining markets also impacts our oil differentials. Oil that is produced close to major consuming and/or refining markets, such as Edmonton or Hardisty in Alberta, is in higher demand than oil that is produced farther from these markets and, consequently, realizes a higher price due to the implied costs that must be incurred by the buyer of the oil at or near the wellhead to transport the oil to the consuming and refining markets. Natural Gas Differentials The primary factors influencing natural gas differentials include the proximity of natural gas production to consuming markets or, in instances when natural gas is produced in remote areas away from consuming markets, the amount of natural gas pipeline "takeaway capacity" available to transport natural gas produced to areas with higher demand. Generally, natural gas produced in close proximity to areas that consume large quantities of natural gas will command higher prices, as will natural gas produced in areas with adequate takeaway capacity to those consuming markets. The majority of the natural gas that we produce can access adequate takeaway capacity to major consuming markets and is transported to those markets under firm transportation contracts. As of March 20, 2012, we had a delivery commitment of approximately 21,000 MMBtu/d of natural gas, which provides for a price equal to the greater of (1) the NYMEX Henry Hub price less US$1.49 and (2) US$1.00 per MMBtu to a buyer through October 31, 2014, unless the NYMEX Henry Hub price exceeds US$6.50 per MMBtu, at which point we share the amount of the excess equally with the buyer. Accordingly, when the NYMEX Henry Hub price trades above US$6.50 per MMBtu, our reported differentials will widen, as was the case in 2008. Conversely, the contract guarantees a floor price of US$1.00 per MMBtu after deducting US$1.49 from the NYMEX Henry Hub price and our reported differential would narrow in this case. NGL Realizations NGL realizations, which are generally evaluated as a percentage of the NYMEX WTI price, are primarily driven by the relative composition of liquids. NGLs are primarily composed of five marketable components, which, ordered from lightest to heaviest, are: (1) methane, (2) ethane, (3) propane, (4) butanes and (5) pentanes. The heavier liquid components normally realize higher prices than the lighter components. Our NGL realizations were higher in 2011 and 2010 compared to 2009 because of the divestiture of oil and natural gas assets in April 2010, which resulted in a shift in our portfolio toward heavier, more valuable gas liquids components. Production Costs In evaluating our operations, we frequently monitor and assess our production expenses on a per unit of production basis, or "per Mcfe." This measure allows us to better evaluate our operating efficiency as production levels change. Production costs are the costs incurred in the operation of producing our oil, natural gas and NGLs and are primarily comprised of lease operating expense (including workover costs), production and property taxes and transportation and processing costs. In general, lease operating expense and workover costs represent the components of production costs over which we have management control, while production and property taxes are primarily driven by the assessed valuation of our property and equipment by the taxing authorities. Transportation and processing costs are comprised of pipeline transportation costs (primarily incurred to deliver natural gas to consuming regions in order to achieve a higher sales price) and processing costs, which include the cost of separating NGLs from the natural gas stream and compressing the residual natural gas to a pressure adequate to meet pipeline requirements. Certain components of lease operating expense are also impacted by energy and field services costs. For example, we incur power costs in connection with various production-related activities, such as pumping to recover oil and natural gas, and we purchase products, such as methanol, to prevent the freezing of gas lines. Although these costs are highly correlated with production volumes, they are also influenced by commodity prices. Certain items, however, such as direct labor and materials and supplies, generally remain fixed across broad sales volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased expenses in periods during which they are performed. Adjusted EBITDA and Adjusted Discretionary Cash Flow We also evaluate our performance using a non-GAAP financial measure, Adjusted EBITDA, which is calculated as net earnings (loss) plus interest expense, income tax expense (benefit), DD&A, ceiling test write-downs of oil and natural gas properties, accretion of asset retirement obligations ("ARO"), unrealized losses (gains) on derivative instruments and foreign currency exchange (gains) losses. Adjusted EBITDA also excludes the equity-accounted for portion of stock-based compensation expense, as these amounts will be settled in shares of our common stock rather than cash payments. By eliminating these items, we believe the result is a useful measure across time in evaluating our fundamental core operating performance. Our management also uses Adjusted EBITDA to manage our business, including in preparing our annual operating budget and financial projections. We believe that Adjusted EBITDA is also useful to investors because similar measures are frequently used by securities analysts, investors and other interested parties in their evaluation of companies in similar industries. As indicated, Adjusted EBITDA does not include interest expense on borrowed money, DD&A expense on capital assets or the payment of income taxes, which are all necessary elements of our operations. Because Adjusted EBITDA does not account for these and other expenses, its utility as a measure of our operating performance has material limitations. Because of these limitations, our management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net earnings (loss) and revenues, to measure operating performance. In addition to reporting cash provided by operating activities as defined under GAAP, we also present Adjusted Discretionary Cash Flow, which is a non-GAAP liquidity measure. Adjusted Discretionary Cash Flow consists of cash provided by operating activities before changes in working capital items. Management uses Adjusted Discretionary Cash Flow as a measure of liquidity and believes it provides useful information to investors because it assesses cash flow from operating activities for each period before changes in working capital, which fluctuates due to the timing of collections of receivables and the settlements of liabilities. This measure does not represent the residual cash flow available for discretionary expenditures, since we have mandatory debt service requirements and other non-discretionary expenditures that are not deducted from the measure. Because of this, its utility as a measure of our operating performance has material limitations. MANAGEMENT DISCUSSION FOR LATEST QUARTER Overview of Lone Pine We are an independent oil and natural 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 in the Northwest Territories. We were incorporated under the laws of the State of Delaware on September 30, 2010, and prior to our IPO on June 1, 2011, we were a wholly-owned subsidiary of Forest Oil Corporation. On September 30, 2011, Forest distributed all of the outstanding shares of our common stock that it owned to its shareholders (the “Distribution”). As a result of the Distribution, Forest has no remaining ownership interest in us. DeGolyer and MacNaughton, our independent reserves engineers, estimated our proved reserves to be approximately 401 Bcfe as of December 31, 2011, of which approximately 26% was oil and natural gas liquids, approximately 74% was natural gas and approximately 53% was classified as proved developed reserves. Our financial statements relating to the period from our inception (September 30, 2010) 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 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. Effective October 1, 2011, Lone Pine changed its functional currency and reporting currency from the U.S. dollar to the Canadian dollar. The functional currency of LPR Canada has not changed and continues to be the Canadian dollar. As a result of our change in reporting currency, all comparative financial information has been recast from U.S. dollars to Canadian dollars to reflect our consolidated financial statements as if they had been historically reported in Canadian dollars, consistent with ASC 830, Foreign Currency Matters . Following the changes in functional currency and reporting currency, we are subject to foreign currency exchange rate risk relating to the Senior Notes, certain of our derivative instruments and our delivery commitment of approximately 21,000 MMBtu/d of natural gas under a long-term sales contract expiring in 2014. See “—Change in Functional and Reporting Currency ” and note 2 to our financial statements for more information about our change in functional and reporting currency. First Quarter 2012 Highlights Our financial and operating performance for the first quarter of 2012 included the following highlights: • As part of our strategy to focus on light oil development in the current economic environment, we drilled a total of 20 gross (17.95 net) light oil wells at Evi with a 100% success rate. • Average daily net sales volumes were 91.2 MMcfe/d, which included 3,923 bbls/d of oil and NGLs, resulting in a net liquids production weighting of 26% compared to 14% in the first quarter of 2011. • Generated Adjusted EBITDA of $26.5 million, a 33% increase from the first quarter of 2011 and Adjusted Discretionary Cash Flow of $21.3 million, a 14% increase from the first quarter of 2011. • On February 14, 2012, LPR Canada completed the Senior Notes offering. The net proceeds of approximately $192.1 million were used to partially repay borrowings outstanding under our bank credit facility. • Invested $77.5 million in our asset base, including $7.0 million on undeveloped land. Natural gas prices have declined to ten-year lows during the first quarter of 2012, and therefore our near-term strategy continues to be primarily focused on light oil opportunities in the Evi area. We have allocated approximately 80% of our 2012 capital budget of approximately $200 million to $220 million towards light oil development in the Evi area, which we expect will be funded through cash provided by operating activities and borrowings under our bank credit facility. Liquidity and Capital Resources Our exploration, development and acquisition activities require us to make significant operating and capital expenditures. Historically, we have used cash provided by operating activities, our bank credit facility and borrowings from Forest as our primary sources of liquidity. Additionally, as market conditions have permitted, we have engaged in non-core asset divestitures. Following the completion of our IPO and the Distribution, we no longer borrow from Forest. We also have accessed the equity and debt capital markets as market conditions have permitted. Changes in the market prices for oil, natural gas and NGLs directly impact our level of cash provided by operating activities. Natural gas has historically comprised approximately 80% of our production; as a result, our operations and cash flows have been more sensitive to fluctuations in the market price for natural gas than to fluctuations in the market price for oil. In 2011 and the first quarter of 2012, we 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 flows. As of May 10, 2012, we had entered into commodity swaps to hedge approximately 825,000 barrels of oil and 6.875 Bcf of natural gas (total equivalent of 11.8 Bcfe) of our projected 2012 production for the remainder of the year. This level of hedging will provide a measure of certainty of the cash flows that we will receive for a portion of our production. In the future, we may determine to increase or decrease our hedging positions. See Part I, “Item 3. Quantitative and Qualitative Disclosures About Market Risk— Commodity Price Risk ” for more information on our derivative contracts. As noted above, a primary source of liquidity is our bank credit facility, which has been used to fund daily operations as needed. Our bank credit facility, which matures in March 2016, is secured by a portion of our assets. Our bank credit facility had a borrowing base of $425 million at December 31, 2011, which was automatically reduced to $375 million in February 2012 upon the completion of our offering of the Senior Notes. On May 10, 2012, the borrowing base was reaffirmed at $375 million. The borrowing base is subject to redetermination and to other automatic adjustments under our bank credit facility. See “— Bank Credit Facility ” below for further details. We have established a capital budget range of approximately $200 million to $220 million for 2012 and will focus our drilling program almost entirely on our light oil opportunities. We plan to fund our 2012 capital budget primarily through cash provided by operating activities and borrowings under our bank credit facility. During the first quarter of 2012, we invested $77.5 million in our asset base, which is on pace with our planned full year 2012 capital budget. We believe that our cash provided by operating activities and the funds available under our bank credit facility will be sufficient to fund our normal recurring operating needs, anticipated capital expenditures and our contractual obligations. However, if our revenue and cash flows decrease in the future as a result of a deterioration in domestic and global economic conditions, a significant decline in commodity prices or a continuation of depressed natural gas prices, we may elect to reduce our planned capital expenditures. We believe that this flexibility to adjust our spending levels will provide us with sufficient liquidity to meet our financial obligations should economic conditions deteriorate. See Part II, “Item 1A. Risk Factors” in this Quarterly Report and Part I, “Item 1A. Risk Factors” in our 2011 Annual Report for a discussion of the risks and uncertainties that affect our business and financial and operating results. We expect the public and private debt and equity capital markets to serve as another source of liquidity. For example, in June 2011, we completed our IPO for net proceeds of approximately $173.1 million, and in February 2012, we completed an offering of Senior Notes for net proceeds of approximately $192.1 million. Our ability to access the debt and equity capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, credit ratings that may be assigned to our debt by independent credit rating agencies, 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 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 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). Bank Credit Facility On March 18, 2011, Lone Pine 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 the Offering, and replaced the existing LPR Canada bank credit facility at such time. The credit facility will mature on March 18, 2016. Availability under the credit facility is governed by a borrowing base, which was recently reaffirmed at $375 million on May 10, 2012. 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 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 the bank credit facility could increase or decrease based on such redetermination. The next scheduled redetermination of the borrowing base is expected to occur on or about November 1, 2012. 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. 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: (1) the sum of the applicable bankers’ acceptance rate (as determined in accordance with the terms of the credit agreement governing our bank credit facility), and a stamping fee of between 175 to 275 basis points, depending on borrowing base utilization; or (2) the Canadian Prime Rate (as determined in accordance with the terms of our bank credit facility) plus 75 to 175 basis points, depending on borrowing base utilization. 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 consolidated EBITDA (as adjusted for non-cash charges) for a trailing 12-month period to be greater than 4.00 to 1.00. As at March 31, 2012, this ratio was approximately 2.8 to 1.0. Of the $500 million total nominal amount under our bank credit facility, JPMorgan Chase Bank N.A., Toronto Branch and nine other banks hold 100% of the total commitments, with JPMorgan Chase Bank N.A., Toronto Branch holding 13.3% of the total commitments, one lender holding 16.7%, two lenders holding 11.7% each of the total commitments, two lenders holding 10% each of the total commitments, 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 or initial purchasers of Lone Pine’s equity and debt securities, 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 of March 31, 2012, we had $187 million outstanding under our bank credit facility at a weighted average interest rate of 3.3955%. As of May 10, 2012, we had $214 million outstanding under our bank credit facility at a weighted average interest rate of 3.5349% and borrowing capacity of approximately $159 million (after deducting $1.6 million of outstanding letters of credit). 10.375% Senior Notes due 2017 On February 14, 2012, LPR Canada issued US$200 million aggregate principal amount of Senior Notes. Interest is payable on the Senior Notes semi-annually in arrears on each February 15 and August 15, commencing 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. 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 approximately $192.1 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, 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. Change in Functional and Reporting Currency Effective October 1, 2011, Lone Pine changed its functional currency and reporting currency from the U.S. dollar to the Canadian dollar. The change in functional currency did not have a significant impact on our financial statements as Lone Pine’s operations are primarily carried out by its operating subsidiary, LPR Canada. The functional currency of LPR Canada has not changed and continues to be the Canadian dollar. Prior to the Distribution, Lone Pine used the same reporting currency as Forest, which was the U.S. dollar, in its financial statements. However, after the Distribution, our management determined that our financial statements should be presented using the Canadian dollar, in order to present Lone Pine’s financial statements in the same currency as its functional currency, and to minimize the impact of changes in foreign currency exchange rates on our financial statements. The determination to change Lone Pine’s reporting currency was based on a number of factors, which included the following: (1) Lone Pine has no assets or operations in the United States, (2) substantially all of Lone Pine’s operations are conducted in a single functional currency, the Canadian dollar, and (3) the reporting currency selected, the Canadian dollar, is the same as the functional currency. Prior to the change in reporting currency, our statements of operations were translated from Canadian dollars using the weighted average exchange rate for the period. The resulting foreign currency translation adjustment was reported as a component of other comprehensive income and accumulated other comprehensive income. As a result of our change in reporting currency, all comparative financial information has been recast from U.S. dollars to Canadian dollars to reflect our financial statements as if they had been historically reported in Canadian dollars, consistent with ASC 830, Foreign Currency Matters . As a result of our change in functional currency and reporting currency, there is no difference between the reporting currency and the functional currency of Lone Pine Resources Inc. and any of its subsidiaries. Following the change in functional currency and reporting currency, we will be subject to foreign currency exchange rate risk relating to our 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. Recent Accounting Pronouncements In December 2011, the FASB issued Accounting Standards Update No. 2011-11, “Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”), which requires that an entity disclose both gross and net information about instruments and transactions that are either eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement, including derivative instruments. ASU 2011-11 was issued in order to facilitate comparisons between GAAP and International Financial Reporting Standards financial statements by requiring enhanced disclosures, but does not change existing GAAP that permits balance sheet offsetting. This authoritative guidance is effective for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We are currently evaluating the impact that the adoption of this authoritative guidance will have 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 indefinitely defers the requirements in Accounting Standards Update No. 2011-05, “Comprehensive Income, Presentation of Comprehensive Income” 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 the specific changes that were proposed under ASU 2011-05 are finalized and issued by the FASB. Adoption of New Accounting Standards In the fourth quarter of 2011, we early adopted ASU 2011-05, except for the specific changes that have been deferred under ASU 2011-12, as noted above. The adoption of ASU 2011-05 required us to present items of net income, items of other comprehensive income and total comprehensive income either in a single continuous statement or in two separate consecutive statements and eliminated the option to report other comprehensive income and its components in the statement of stockholders’ equity. We elected to present two separate consecutive statements. Other than a change in presentation, the adoption of ASU 2011-05 did not have any impact on our financial statements. 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 Financial Accounting Standards Board’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 performing 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 its interim periods, but will continue to perform the full two-step goodwill impairment test at December 31 of each year. |