CALGARY, ALBERTA--(Marketwire - Nov. 13, 2012) - Lone Pine Resources Inc. ("Lone Pine" or the "Company") (NYSE:LPR) (TSX:LPR) today announced financial and operational results for the third quarter of 2012.
Selected highlights for the third quarter of 2012 include:
- Average net sales volumes of 82.4 MMcfe/d with oil and NGLs weighting increasing to 28% from 22% in the third quarter of 2011
- Oil and NGLs net sales volumes of 3,826 bbls/d increased 8% from the third quarter of 2011
- Adjusted EBITDA of $27.0 million, which matched the level from the previous quarter
- Adjusted discretionary cash flow of $19.8 million increased 6% from the previous quarter
- Invested $36.7 million in the quarter, which included drilling 7 gross (5.7 net) wells, completing 8 gross (6.7 net) wells and bringing onstream 8 gross (6.7 net) wells
- Entered into definitive agreements to divest of $19.0 million of non-core assets with $8.2 million completed in the third quarter of 2012 and $10.8 million completed in October 2012
- Completed an independent assessment of the Company's unrisked natural gas resources in the Narraway/Ojay area with a best estimate of contingent resources of 2.1 Tcf and prospective resources of 1.5 Tcf
- Subsequent to the end of the quarter, the borrowing base available under the Company's syndicated credit facility was redetermined to $325 million after giving effect to the Kaybob non-core asset divestitures
David M. Anderson, President and CEO of Lone Pine, stated, "The third quarter was a success for Lone Pine from an operational, strategic and financial perspective. On the operational side, total net sales volumes of 82.4 MMcfe/d, including total liquids volumes of over 3,800 bbls/d, were achieved with a single rig drilling at Evi. We made great strides in the quarter at Evi where we have completed our downspacing pilot project to 10 wells per section and have further advanced the waterflood pilot and are seeing very encouraging results with 200 - 300% increases in productivity from offsetting producers. Both of these initiatives will be core to the Company in 2013 and beyond.
From a strategic standpoint, Lone Pine announced a plan in the third quarter aimed at strengthening the Company's balance sheet and providing additional liquidity to fund development of our portfolio of high quality assets. This process was very active in the third quarter as we successfully divested our first non-core asset package, advanced our larger Wild River asset divestiture and initiated our core asset funding review.
Lastly, from a financial perspective, the non-core asset sales that we completed in the quarter and have announced subsequent to the quarter have improved our balance sheet liquidity and enhanced our financial flexibility going into 2013. Those asset sales combined with our revised 2012 capital budget have contributed to a reduction in debt compared to the second quarter and we expect to further reduce it at year-end."
The Company has filed its Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2012 with the U.S. Securities and Exchange Commission and on SEDAR in Canada. Selected financial and operational information is outlined below and should be read in conjunction with the Quarterly Report on Form 10-Q, which is available for review at www.sec.gov, at www.sedar.com, and on the Company's website at www.lonepineresources.com.
Financial and Operational Results
Financial Results
Lone Pine's adjusted EBITDA for the third quarter of 2012 of $27.0 million was approximately flat from the second quarter of 2012 and adjusted discretionary cash flow for the third quarter of 2012 of $19.8 million was 6% higher than the previous period. Lone Pine reported an adjusted net loss in the third quarter of 2012 of $11.6 million or $(0.14) per diluted share compared to an adjusted net loss of $11.7 million or $(0.14) per diluted share in the second quarter of 2012. Net loss for the third quarter of 2012 was impacted by the non-cash effect of a ceiling test write-down of $142.9 million before tax ($107.3 million after tax).
See "Non-GAAP Financial Measures" at the end of this news release and in the Quarterly Report on Form 10-Q for a reconciliation of adjusted EBITDA, adjusted discretionary cash flow and adjusted net earnings (loss), which are non-GAAP measures, to their most directly comparable GAAP measures.
Average Daily Sales Volumes
Lone Pine's average daily net sales volumes for the third quarter of 2012 were 82.4 MMcfe/d, which was 17% lower than the corresponding 2011 period and a decrease of 7% from the second quarter of 2012. Lone Pine's average daily oil and NGLs net sales volumes for the third quarter of 2012 were 3,826 bbls/d, which was 8% higher than the corresponding 2011 period and 14% lower than the second quarter of 2012 as the Company reduced the pace of capital expenditures in the third quarter of 2012 as part of its focus on balance sheet management. Lone Pine's natural gas sales volumes in the third quarter of 2012 were 59.4 MMcf/d, which was 23% lower than the corresponding 2011 period and 5% lower than the second quarter of 2012 as the Company has continued to focus its capital spending on its oil assets.
Revenue and Expenses
The average realized natural gas price (before hedges) for the third quarter of 2012 increased 9% to $1.95 per MMBtu compared to $1.79 per MMBtu in the second quarter of 2012 but decreased 45% compared to the corresponding 2011 period. The average realized oil price (before hedges) for the third quarter of 2012 decreased 1% to $79.52 per bbl compared to $80.67 per bbl in the second quarter of 2012. Realized oil prices in the third quarter of 2012 benefited from a narrowing WTI to Edmonton Par differential, which averaged $8.46 per bbl in the quarter compared to $10.28 per bbl in the second quarter, but remained at a large discount to the $4.32 per bbl premium realized in the third quarter of 2011. The average realized NGL price for the third quarter of 2012 decreased 12% to $53.39 per bbl compared to $60.41 per bbl in the second quarter of 2012. On a total net sales volumes basis, the average realized price (before hedges) in the third quarter of 2012 decreased 4% to $5.04 per Mcfe compared to the second quarter of 2012. Lone Pine realized natural gas hedging gains of $5.4 million ($0.99 per Mcf) and oil hedging gains of $2.7 million ($8.07 per bbl) for a total realized hedging gain of $8.1 million ($1.07 per Mcfe) in the third quarter of 2012.
Lone Pine's total production expense per unit for the third quarter of 2012 decreased 10% to $2.15 per Mcfe compared to $2.38 per Mcfe in the second quarter of 2012, but increased 41% compared to $1.52 per Mcfe in the corresponding 2011 period, reflecting the Company's continued shift in focus to light oil development. Consistent with the light oil transition, Lone Pine's depreciation, depletion and amortization expense per unit for the third quarter of 2012 increased 77% to $3.99 per Mcfe compared to $2.25 per Mcfe in the corresponding 2011 period.
Financial and Operational Highlights
The following table highlights certain financial and operational highlights for the three months ended September 30, 2012, June 30, 2012 and September 30, 2011:
| Three Months Ended | |||||||||||
| (In $ thousands, unless otherwise noted) | Sept. 30, 2012 | June 30, 2012 | Sept. 30, 2011 | ||||||||
| Financial | |||||||||||
| Revenue | 38,188 | 42,420 | 50,015 | ||||||||
| Adjusted EBITDA | 26,981 | 27,076 | 36,234 | ||||||||
| Adjusted Discretionary Cash Flow | 19,808 | 18,676 | 35,260 | ||||||||
| Per Share | $ | 0.23 | $ | 0.22 | $ | 0.41 | |||||
| Adjusted Net Income | (11,560 | ) | (11,654 | ) | 9,591 | ||||||
| Per Share | $ | (0.14 | ) | $ | (0.14 | ) | $ | 0.11 | |||
| Capital Expenditures | 36,727 | 33,652 | 93,827 | ||||||||
| Long-Term Debt | 426,832 | 425,343 | 287,000 | ||||||||
| Operational | |||||||||||
| Average Daily Working Interest Sales Volumes | |||||||||||
| Oil (bbls/d) | 3,978 | 4,703 | 3,707 | ||||||||
| NGLs (bbls/d) | 283 | 275 | 370 | ||||||||
| Natural Gas (MMcf/d) | 58.3 | 62.5 | 81.8 | ||||||||
| Total (MMcfe/d) | 83.9 | 92.4 | 106.2 | ||||||||
| Total Equivalent (MMcfe) | 7,723 | 8,410 | 9,771 | ||||||||
| % Oil & NGLs | 30 | % | 32 | % | 23 | % | |||||
| Average Daily Net Sales Volumes | |||||||||||
| Oil (bbls/d) | 3,630 | 4,253 | 3,283 | ||||||||
| NGLs (bbls/d) | 196 | 187 | 261 | ||||||||
| Natural Gas (MMcf/d) | 59.4 | 62.4 | 77.6 | ||||||||
| Total (MMcfe/d) | 82.4 | 89.0 | 98.8 | ||||||||
| Total Equivalent (MMcfe) | 7,577 | 8,101 | 9,093 | ||||||||
| % Oil & NGLs | 28 | % | 30 | % | 22 | % | |||||
| Average Realized Prices | |||||||||||
| Oil ($/bbl) | $ | 79.52 | $ | 80.67 | $ | 77.24 | |||||
| NGLs ($/bbl) | 53.39 | 60.41 | 58.33 | ||||||||
| Natural Gas ($/Mcf) | 1.95 | 1.79 | 3.54 | ||||||||
| Average Realized Prices Before Hedges ($/Mcfe) | $ | 5.04 | $ | 5.24 | $ | 5.50 | |||||
| Realized Hedging Gains ($/Mcfe) | 1.07 | 1.09 | 0.39 | ||||||||
| Average Realized Prices Including Hedges ($/Mcfe) | $ | 6.11 | $ | 6.33 | $ | 5.89 | |||||
| Total Production Expense ($/Mcfe) | $ | 2.15 | $ | 2.38 | $ | 1.52 | |||||
| Depreciation, Depletion and Amortization ($/Mcfe) | $ | 3.99 | $ | 3.94 | $ | 2.25 | |||||
Operational Update
Evi
Net sales volumes from Evi decreased 15% in the third quarter of 2012 to 3,140 boe/d compared to 3,690 boe/d in the second quarter of 2012 due to the tempered drilling activity in the period. In the third quarter of 2012, Lone Pine drilled 6 gross (5.3 net) wells, completed 7 gross (6.3 net) wells and brought onstream 7 gross (6.3 net) wells at Evi. Through the first nine months of 2012, Lone Pine has drilled 29 gross (26.3 net) wells, completed 29 gross (26.3 net) wells and brought onstream 37 gross (33.8 net) wells at Evi.
Activity for the third quarter of 2012 was focused on infill drilling in the central sections of the Evi property where the Company has completed the drilling of the 10 well per section downspacing pilot and is currently monitoring the early positive results of that project. Early results lie within the same performance band as the initial six wells in the section with no indications of offset well production being negatively impacted. In addition, Lone Pine has begun to see encouraging results on its operated waterflood pilot project where two offsetting vertical and horizontal producing wells have shown 200 - 300% increases in productivity following sustained periods of continuous water injection. Lone Pine plans to continue with its infill drilling program at Evi while monitoring the sustained waterflood response with the intent to implement a pilot horizontal waterflood in the future.
Deep Basin
Net sales volumes from the Deep Basin averaged 49.4 MMcfe/d in the third quarter of 2012 compared to 50.8 MMcfe/d in the second quarter of 2012.
Lone Pine engaged Sproule Associates, Inc. to conduct an independent assessment of the Company's contingent and prospective multi-zone gas resources in the Narraway area of Alberta and the Ojay area of British Columbia (the "Sproule Resource Assessment") effective June 30, 2012. The Sproule Resource Assessment was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and Canadian National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities.
Sproule's best estimate of natural gas initially-in-place on the Company's land base is over 21 Tcf. Sproule's estimate of unrisked contingent natural gas resources ranges from 981 Bcf in the low estimate to 3.9 Tcf in the high estimate with a best estimate of 2.1 Tcf. Sproule's estimate of unrisked prospective natural gas resources ranges from 821 Bcf in the low estimate to 2.8 Tcf in the high estimate with a best estimate of 1.5 Tcf. As of September 30, 2012, Lone Pine held 180,344 gross (121,088 net) acres in the Narraway/Ojay area.
The table below sets out certain summary information from the Sproule Resource Assessment:
| Company Interest Unrisked Gas Resources | |||
| Category | Contingent Gas Resource (Bcf)(1) | Prospective Gas Resource (Bcf)(2) | |
| Low Estimate(3) | 981 | 821 | |
| Best Estimate(3) | 2,147 | 1,505 | |
| High Estimate(3) | 3,926 | 2,811 | |
| Notes: | |
| (1) Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. | |
| (2) Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. | |
| (3) "Uncertainty Ranges" as are described by the Canadian Oil and Gas Evaluation Handbook as low, best and high estimates for reserves and resources are as follows: | |
| a. Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. | |
| b. Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. | |
| c. High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. | |
Conference Call
A conference call to discuss the third quarter of 2012 results is scheduled for Wednesday, November 14, 2012, at 11:00 AM MT. To participate, please dial 1-866-277-1184 (toll-free for North America) or 1-617-597-5360 and request the Lone Pine teleconference (ID # 62684693) or listen to the webcast on Lone Pine's website at www.lonepineresources.com. A replay will be available through December 14, 2012 by dialing 1-888-286-8010 or 1-617-801-6888 and entering conference passcode #98552870.
Non-GAAP Financial Measures
Adjusted Net Earnings (Loss)
In addition to reporting net earnings (loss) as defined under GAAP, Lone Pine also presents adjusted net earnings (loss), which is a non-GAAP performance measure. Adjusted net earnings (loss) consists of net earnings (loss) after adjustment for those items described in the table below. Adjusted net earnings (loss) does not represent, and should not be considered an alternative to, GAAP measurements, such as net earnings (loss) (its most comparable GAAP financial measure), and Lone Pine's calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, Lone Pine believes the measure is useful to investors because similar measures are frequently used by securities analysts, ratings agencies, investors, and other interested parties in their evaluation of companies in similar industries. Lone Pine's management does not view adjusted net earnings in isolation and also uses other measurements, such as net earnings and revenues, to measure operating performance.
The following table provides a reconciliation of net earnings (loss), the most directly comparable GAAP measure, to adjusted net earnings (loss) for the periods presented (in thousands):
| Three Months Ended September 30, | ||||||
| 2012 | 2011 | |||||
| Net earnings (loss) | $ | (124,301 | ) | $ | 29,014 | |
| Ceiling test write-down of oil and natural gas properties, net of tax | 107,301 | 0 | ||||
| Unrealized losses (gains) on derivative instruments, net of tax | 11,559 | (19,400 | ) | |||
| Foreign currency exchange losses (gains), net of tax | (6,119 | ) | (23 | ) | ||
| Adjusted net earnings (loss) | $ | (11,560 | ) | $ | 9,591 | |
| Weighted average number of diluted shares outstanding | 85,016 | 85,000 | ||||
| Adjusted net earnings (loss) per diluted share | $ | (0.14 | ) | $ | 0.11 | |
Adjusted EBITDA
In addition to reporting net earnings (loss) 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 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 losses (gains). 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 operating performance and in estimating cash flows. 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 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 the first quarter of 2012, we revised the calculation of Adjusted EBITDA to exclude the adding back of amortization of deferred costs. Adjusted EBITDA for prior periods has been restated to be consistent with the current period's calculation.
The following table reconciles net earnings (loss) to Adjusted EBITDA. Net earnings (loss) is the most directly comparable financial measure calculated and presented in accordance with GAAP.
| Three Months Ended September 30, | |||||||
| 2012 | 2011 | ||||||
| Net earnings (loss) | $ | (124,301 | ) | $ | 29,014 | ||
| Interest expense | 8,181 | 3,068 | |||||
| Income tax expense (recovery) | (39,921 | ) | 9,736 | ||||
| Depreciation, depletion and amortization | 30,236 | 20,426 | |||||
| Ceiling test write-down of oil and natural gas properties | 142,879 | - | |||||
| Accretion of asset retirement obligations | 350 | 207 | |||||
| Unrealized losses (gains) on derivative instruments | 15,412 | (26,217 | ) | ||||
| Foreign currency exchange gains | (6,996 | ) | (30 | ) | |||
| Stock-based compensation (equity portion) | 1,141 | 30 | |||||
| Adjusted EBITDA | $ | 26,981 | $ | 36,234 | |||
Adjusted Discretionary Cash Flow
In addition to reporting net 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 net 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 net cash provided by 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. As a result, its utility as a measure of our operating performance has material limitations.
The following table reconciles net cash provided by operating activities to Adjusted Discretionary Cash Flow. Net cash provided by operating activities is the most directly comparable financial measure calculated and presented in accordance with GAAP:
| Three Months Ended September 30, | |||||||
| 2012 | 2011 | ||||||
| Net cash provided by operating activities | $ | 19,893 | $ | 43,385 | |||
| Changes in working capital: | |||||||
| Accounts receivable | (1,587 | ) | (2,763 | ) | |||
| Prepaid expenses and other current assets | 423 | 1,076 | |||||
| Accounts payable and accrued liabilities | (4,228 | ) | (5,483 | ) | |||
| Accrued interest and other current liabilities | 5,307 | (955 | ) | ||||
| Adjusted discretionary cash flow | $ | 19,808 | $ | 35,260 | |||
Forward-Looking Statements
This news release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and Canadian securities laws. All statements, other than statements of historical facts, that address activities that Lone Pine assumes, plans, expects, believes, projects, aims, estimates or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements provided in this news release are based on management's current belief, based on currently available information, as to the outcome and timing of future events. Lone Pine cautions that future natural gas and liquids production, revenues, cash flows, liquidity, plans for future operations, expenses, outlook for oil and natural gas prices, timing of capital expenditures and other forward-looking statements relating to Lone Pine are subject to all of the risks and uncertainties normally incident to its exploration for and development and production and sale of oil and natural gas.
These risks relating to Lone Pine include, but are not limited to, oil and natural gas price volatility, its access to cash flows and other sources of liquidity to fund its capital expenditures, its level of indebtedness, its ability to replace production, the impact of the current financial and economic environment on its business and financial condition, a lack of availability of, or increase in costs relating to, goods and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves and other risks as described in reports that Lone Pine files with the SEC, including its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and the other reports that Lone Pine files with the SEC and with Canadian securities regulators. Any of these factors could cause Lone Pine's actual results and plans to differ materially from those in the forward-looking statements.
Prices for Lone Pine's products are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and worldwide economic and political conditions, consumer product demand, weather, and other substantially variable factors. The cost of services and materials needed to produce Lone Pine's products are also determined by prevailing market conditions, both regional and worldwide. These factors are beyond Lone Pine's control and are difficult to predict. In addition, prices received by Lone Pine for its liquids and natural gas production may vary considerably due to differences between regional markets, transportation availability, and demand for different grades of products. Lone Pine's financial results and resources are highly influenced by this price volatility.
Estimates for Lone Pine's future production are based on assumptions of capital expenditure levels and the assumption that market demand, prices for liquids and natural gas, and the cost of required services and materials will continue at levels that allow for economic production of these products. The production, transportation, and marketing of liquids and natural gas are complex processes that are subject to disruption due to transportation and processing availability, mechanical failure, human error, and meteorological events. Lone Pine's estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Estimates of DD&A rates can vary according to reserve additions, capital expenditures, future development costs, and other factors. Therefore, Lone Pine can give no assurance that its future results will be as estimated.
Units of Equivalency
This news release discloses certain information on an "equivalency" basis with oil and NGL quantities converted to Mcfe (thousand cubic feet of gas equivalent) or MMcfe (million cubic feet of gas equivalent) based on a conversion ratio of one bbl of liquids to six Mcf of natural gas. Units of equivalency such as Mcfe and MMcfe may be misleading, particularly if used in isolation. A Mcfe conversion ratio of one bbl of crude oil or NGLs to six Mcf of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Although this conversion ratio is an industry accepted norm, it is not reflective of price or market value differentials between product types. Capital expenditure estimates are based on our current expectations as to the level of capital expenditures that will be justified based upon the other assumptions set forth in this news release as well as expectations about other operating and economic factors.
Disclosure of Reserves and Resource Information
In this news release, Lone Pine discloses estimates of "Natural Gas Initially-In-Place", "Contingent Natural Gas Resource" and "Prospective Natural Gas Resource", which have been prepared in accordance with the definitions and guidelines set forth in Canadian National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook, and which terms include quantities of oil and gas that do not meet the SEC's definitions of proved, probable or possible reserves, and which applicable U.S. federal securities law and applicable SEC rules and regulations (collectively, "SEC requirements") strictly prohibit Lone Pine from including in periodic filings. These estimates are by their nature more speculative than reserves determined under applicable SEC guidelines or NI 51-101, have not been risked by Lone Pine, and accordingly are subject to substantially greater risk of being recovered by Lone Pine. Additional information regarding Lone Pine's reserves estimates and other oil and gas information prepared in accordance with NI 51-101 is contained in Lone Pine's Statement of Reserves Data and Other Oil and Gas Information (Form 51-101F1) filed on SEDAR on March 22, 2012. In addition to being a reporting issuer in certain Canadian jurisdictions, Lone Pine is a registrant with the SEC and subject to domestic issuer reporting requirements under U.S. federal securities law, including with respect to the disclosure of reserves and other oil and gas information in accordance with SEC requirements. Disclosure of such information in accordance with SEC requirements is included in the Company's Annual Report on Form 10-K and in other reports and materials filed with or furnished to the SEC and, as applicable, Canadian securities regulatory authorities. The SEC permits oil and gas companies that are subject to domestic issuer reporting requirements under U.S. federal securities law, in their filings with the SEC, to disclose only estimated proved, probable and possible reserves that meet the SEC's definitions of such terms. Lone Pine has disclosed only estimated proved reserves in its filings with the SEC. In addition, Lone Pine prepares its financial statements in accordance with United States generally accepted accounting principles, which require that the notes to its annual financial statements include supplementary disclosure in respect of the Company's oil and gas activities, including estimates of its proved oil and gas reserves and a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. This supplementary financial statement disclosure is presented in accordance with FASB requirements, which align with corresponding SEC requirements concerning reserves estimation and reporting.
Lone Pine Resources Inc. is engaged in the exploration and development of natural gas and light oil in Canada. Lone Pine's principal reserves, producing properties and exploration prospects are located in Canada in the provinces of Alberta, British Columbia and Quebec and the Northwest Territories. Lone Pine's common stock trades on the New York Stock Exchange and the Toronto Stock Exchange under the symbol LPR. For more information about Lone Pine, please visit its website at www.lonepineresources.com.
Contact Information:
David Anderson
President & Chief Executive Officer
(403) 292-8000
Lone Pine Resources Inc.
Ed Bereznicki
Executive Vice President & Chief Financial Officer
(403) 292-8000
www.lonepineresources.com