Exhibit 99.1

News Release

Lone Pine Resources Announces Second Quarter 2012 Results and
Updated 2012 Guidance

CALGARY, ALBERTA, August 13, 2012 — Lone Pine Resources Inc. (“Lone Pine” or the “Company”) (NYSE, TSX: LPR) today announced financial and operational results for the second quarter of 2012 and updated full year 2012 guidance.  Selected highlights for the second quarter of 2012 include:

·                              Average net sales volumes of 89.0 MMcfe/d with oil and NGLs net sales volumes weighting increasing to 30%

·                              Oil and NGLs net sales volumes of 4,440 bbls/d organically increased 13% from the first quarter of 2012

·                              Total net revenue, including realized hedging gains, of $51.3 million increased 4% from the first quarter of 2012

·                              Adjusted EBITDA of $27.1 million increased 2% from the first quarter of 2012

·                              Invested $33.7 million in the quarter, which included drilling 4 gross (3.1 net) wells, completing 11 gross (9.1 net) wells and bringing onstream 15 gross (11.5 net) wells

·                              Successfully modified the completion process at Evi with no recurring sign of proppant flowback

David M. Anderson, President and CEO of Lone Pine, stated, “In the second quarter of 2012, Lone Pine’s total net liquids weighting increased to 30% for the first time in the Company’s history.  Despite limited field activity for much of the quarter due to spring break-up in Canada, Lone Pine was able to increase its total liquids net sales volumes by 13% over the first quarter of 2012 to 4,440 bbls/d.  At Evi, we increased our second quarter net sales volumes to its highest quarterly level of over 3,600 boe/d (4,000 boe/d working interest).  Lone Pine remains focused on light oil development at Evi and we continue to be excited with the results we have seen from the play.

The second quarter saw a continued decline in WTI prices that were exacerbated by the persistent widening of Canadian crude oil differentials and the further deterioration of natural gas prices to levels not experienced in over 10 years.  Lone Pine has elected, in light of these depressed commodity prices and widening differentials, to reduce its 2012 capital budget by approximately $40 million to $160 - $175 million.  The remaining capital budget for 2012 will be focused on cost efficient infield drilling opportunities at Evi.

We are optimistic about Lone Pine’s assets, opportunities and long term prospects.  In the near term, we are focused on the continued light oil development at Evi and prudent management of our balance sheet including overall debt reduction.”

Second Quarter 2012 Results

Important Note:  Lone Pine reports its financial results in Canadian dollars in accordance with United States GAAP and presents sales volumes on a net after royalties basis, unless otherwise stated.  Lone Pine has historically reported its financial results in United States dollars.  Effective October 1, 2011, Lone Pine changed its reporting and functional currency from United States dollars to Canadian dollars. See “Change in Reporting and Functional Currency” for more information.  Lone Pine has recast the second quarter 2011 information contained in this news release from United States dollars to Canadian dollars.

Lone Pine’s adjusted EBITDA for the second quarter of 2012 of $27.1 million was 18% lower than the corresponding 2011 period and adjusted discretionary cash flow for the second quarter of 2012 of $18.7 million was 40% lower than the corresponding 2011 period.  The decrease in each of these amounts was primarily attributable to declines in natural gas sales volumes combined with the significant decrease in natural gas and crude oil realized prices in the period.

Lone Pine reported an adjusted net loss in the second quarter of 2012 of $11.7 million or $(0.14) per diluted share compared to adjusted net earnings of $3.9 million or $0.05 per diluted share in the corresponding 2011 period.  Net loss for the second

quarter of 2012 was impacted by the non-cash effect of a ceiling test write-down of $128.9 million before tax ($96.8 million after tax) due primarily to the continued decline in the 12 month trailing natural gas price that is used in the calculation.

See “Non-GAAP Financial Measures” 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 second quarter of 2012 were 89.0 MMcfe/d, which was 6% lower than the corresponding 2011 period and a decrease of 2% from the first quarter of 2012.  Lone Pine’s average daily oil and NGLs net sales volumes for the second quarter of 2012 were 4,440 bbls/d, which was 45% higher than the corresponding 2011 period and 13% higher than the first quarter of 2012.  Lone Pine’s natural gas sales volumes in the second quarter of 2012 were 62.4 MMcf/d, which was 18% lower than the corresponding 2011 period and 8% lower than the first quarter of 2012 as the Company has continued to focus its capital spending nearly entirely on its oil assets.  Lone Pine’s total net sales volumes in the second quarter of 2012 were comprised of 29% oil and 1% NGLs compared to 18% oil and 1% NGLs in the second quarter of 2011.

The following table details the components of average daily sales volumes for the three months ended June 30, 2012, March 31, 2012 and June 30, 2011:

Sales Volumes by Area

The following table highlights average daily sales volumes for each of Lone Pine’s core areas for the three months ended June 30, 2012 and March 31, 2012:

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Average Realized Prices and Revenues

The average realized natural gas price (before hedges) for the second quarter of 2012 decreased 18% to $1.79 per MMBtu compared to $2.18 per MMBtu in the first quarter of 2012 and 46% compared to the corresponding 2011 period.  The average realized oil price (before hedges) for the second quarter of 2012 decreased 8% to $80.67 per bbl compared to $87.86 per bbl in the first quarter of 2012.  Realized oil prices in the second quarter of 2012 were negatively affected by the combination of the decline in WTI price combined with the continued wider differentials between WTI and Edmonton Par, which averaged $10.28 per bbl in the second quarter of 2012 compared to a $3.70 per bbl premium in the corresponding 2011 period.  The average realized NGL price for the second quarter of 2012 decreased 5% to $60.41 per bbl compared to $63.68 per bbl in the second quarter of 2011.  On a total net sales volumes basis, the average realized price (before hedges) in the second quarter of 2012 decreased 2% to $5.24 per Mcfe compared to the first quarter of 2012 as reductions in realized pricing were offset by a higher overall liquids weighting for the Company.

In the second quarter of 2012, Lone Pine realized natural gas hedging gains of $6.6 million ($1.16 per Mcf) and oil hedging gains of $2.3 million ($5.83 per bbl) for a total realized hedging gain of $8.8 million ($1.09 per Mcfe).

The following table details the components of average realized prices and net revenues for the three months ended June 30, 2012, March 31, 2012 and June 30, 2011:

Production Expense and Cash Costs

Lone Pine’s total production expense per unit for the second quarter of 2012 increased 53% to $2.38 per Mcfe compared to $1.56 per Mcfe in the corresponding 2011 period.  The increase over the 2011 period is primarily due to the higher oil component in the Company’s production mix, which has higher per unit costs, but also has higher margins.  Production expenses in the second quarter of 2012 increased slightly from the previous quarter primarily as a result of the continued development to the northern end of the Evi property where wells were not flowlined to Lone Pine’s jointly owned central battery.  While Lone Pine has installed infrastructure that allows the Company to transport by pipeline the majority of its oil production from the Evi area, the lack of pipeline infrastructure in the northern end of the Evi property requires higher levels of emulsion trucking and results in higher per unit costs than production in other areas of the field.  As discussed in the Operational Update below, Lone Pine’s second half of 2012 activity will be focused on infield drilling in the central sections of the Evi property where existing infrastructure allows for the flowlining of wells to Lone Pine’s jointly owned central battery. 

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Total production expenses in the second quarter of 2012 were partially offset by a reduction in workover costs experienced in the previous quarter.

Lone Pine’s general and administrative expense (excluding stock-based compensation) per unit for the second quarter of 2012 increased 117% to $0.65 per Mcfe compared to $0.30 per Mcfe in the corresponding 2011 period as Lone Pine is now responsible for a number of incremental corporate expenditures related to Lone Pine’s status as a stand-alone company.  Lone Pine also incurred higher interest costs in the second quarter of 2012 as compared to the corresponding 2011 period, reflecting the higher interest costs associated with the US$200 million of 10.375% senior notes due 2017 issued in February 2012.

The following table details the components of production expense together with other cash costs for the three months ended June 30, 2012 and June 30, 2011:

(1)  Excluding stock-based compensation of $600 and $(91), respectively.

Total cash costs is a non-GAAP measure that is used by management to assess the Company’s cash operating performance.  Total cash costs do not represent, and should not be considered an alternative to, GAAP measures, and Lone Pine’s calculations thereof may not be comparable to similarly titled measures reported by other companies.  Lone Pine defines total cash costs as production expense, general and administrative expense (excluding stock-based compensation), interest expense and current income tax expense.

Netbacks

The following table details the components of operating and cash netbacks for the three months ended June 30, 2012 and June 30, 2011 (in $ per Mcfe):

Operating netback and cash netback are non-GAAP measures that are used by management to assess the Company’s costs associated with producing and selling one Mcfe.  Operating netback and cash netback do not represent, and should not be considered an alternative to, GAAP measurements, and Lone Pine’s calculations thereof may not be comparable to similarly titled measures reported by other companies.  Lone Pine calculates cash netbacks as realized prices per Mcfe (after royalties), including realized hedging gains or losses, less costs associated with bringing an Mcfe to market, including total production expenses, general and administrative expense (excluding stock-based compensation) and interest expense.

Depreciation, Depletion and Amortization (“DD&A”) Expense

Lone Pine’s DD&A expense per unit for the second quarter of 2012 increased 71% to $3.94 per Mcfe compared to $2.31 per Mcfe in the corresponding 2011 period.  The increase over the previous period was primarily the result of the Company’s transition to becoming more oil-focused as Lone Pine’s oil properties typically have higher per unit capital expenditures than Lone Pine’s natural gas properties.  In addition, the quantity of the Company’s overall depletion base fell in the second quarter

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of 2012 primarily as a result of the reduction in Lone Pine’s internal estimate of proved undeveloped natural gas reserves due to the decline in the 12-month trailing natural gas price and partially offset by lower future development costs.

Full Cost Method of Accounting

Lone Pine recorded a ceiling test write-down of $128.9 million before tax ($96.8 million after tax) in the second quarter of 2012 pursuant to the ceiling test limitation prescribed by the U.S. Securities and Exchange Commission for companies using the full cost method of accounting. The write-down was primarily a result of a significant decline in the 12 month average trailing natural gas price used in the ceiling test calculation from an AECO price of $3.33 per MMBtu as of March 31, 2012 to $2.77 per MMBtu as of June 30, 2012.  The ceiling test write-down does not affect cash flow or adjusted net earnings and is not reflective of the fair value of the reserves.  Lone Pine believes that additional write-downs may be required in subsequent periods if natural gas or oil prices decline from June 30, 2012 levels, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development or acquisition activities exceed the discounted future net cash flows from the additional reserves.

Capital Expenditures

Lone Pine’s total capital expenditures for the second quarter of 2012 were $33.7 million compared to $103.2 million in the second quarter of 2011.  Acquisitions and leasehold costs in the second quarter of 2012 included $3.5 million of investment in undeveloped land that the Company expects will support future light oil development.

The following table details the components of capital expenditures for the three months ended June 30, 2012 and June 30, 2011 (in thousands):

Long-Term Debt & Liquidity

The Company maintains a $500 million credit facility with a syndicate of banks that currently has a borrowing base of $375 million.  The borrowing base was reaffirmed on May 10, 2012 in a semi-annual redetermination.  The next redetermination of the borrowing base is scheduled for on or about November 1, 2012.  Since the process for determining the borrowing base under our bank credit facility involves evaluating the estimated value of our oil and natural gas properties using pricing models determined by the lenders at that time, we believe that it is likely that the recent decline in oil and natural gas commodity prices, or a further decline in those prices, will result in a redetermination of our borrowing base and a decrease in the available borrowing amount at the time of the next scheduled redetermination.  As of June 30, 2012, Lone Pine had $229 million outstanding under the credit facility.  As of August 9, 2012, Lone Pine had $240 million outstanding under the credit facility, with remaining availability of approximately $133 million.  In February 2012, Lone Pine issued US$200 million of 10.375% senior notes due 2017 and used the proceeds to pay down borrowings on the bank credit facility.

Adjusting Lone Pine’s capital spending rate for the remainder of 2012 is the first step in improving the Company’s financial strength and flexibility.  Lone Pine is also considering other methods of debt reduction including the divestiture of non-core assets.  However, no assurance can be made regarding the Company’s ability to identify or complete any such potential transaction.  In addition, Lone Pine has commissioned independent resource assessments of each of the Company’s core assets.  Work has commenced on each of these assessments, and one of them, discussed below, has been completed with the remaining reports expected to be finalized by the end of the third quarter of 2012.

Operational Update

Evi

Net sales volumes from Evi increased 19% in the second quarter of 2012 to 3,690 boe/d compared to 3,092 boe/d in the first quarter of 2012.  In the second quarter of 2012, Lone Pine drilled 3 gross (3 net) wells, completed 9 gross (9 net) wells and

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brought onstream 13 gross (11 net) wells at Evi.  The Company returned to the field to resume drilling operations following spring break-up in early June 2012.  Lone Pine has continued to optimize completion operations at Evi and no incremental proppant clean-outs have been required since the implementation of a new fracturing program that includes higher viscosity fracturing fluid and a new resin coated proppant and activator program.

Activity for the second half of 2012 will be focused on infield drilling in the central sections of the Evi property where existing infrastructure allows for the flowlining of wells to Lone Pine’s jointly owned central battery, which the Company expects will result in lower production expenses in the second half of the year.  Lone Pine has downspacing approval in place to drill up to 16 wells per section in this area of the Evi property and is currently drilling an infill pilot to 10 wells per section.  Lone Pine plans to continue the existing single rig program currently running in Evi and expects to drill up to 35 gross (31.7 net) total wells in 2012.

The Slave Point light oil play at Evi has provided Lone Pine with an attractive light oil growth engine since the Company drilled its first horizontal well into the play in 2006.  Since that time, and including the wells drilled through June 30, 2012, Lone Pine has drilled a total of 94 gross operated horizontal wells into the Slave Point play with a total success rate of over 95%.

As of June 30, 2012, Lone Pine held 88,480 gross (81,535 net) acres in the Evi area.

Deep Basin

Net sales volumes from the Deep Basin area averaged 50.8 MMcfe/d in the second quarter of 2012 compared to 56.0 MMcfe/d in the first quarter of 2012.  Lone Pine temporarily suspended investment in natural gas drilling in the fourth quarter of 2011 in response to the outlook for natural gas prices, which have further deteriorated since that time.  Lone Pine plans to continue to suspend its natural gas drilling investment until prices rebound, at which time the Company has a large inventory of drill-ready locations.

As of June 30, 2012, Lone Pine held 250,478 gross (156,617 net) acres in the Deep Basin.

Liard Basin

Recent industry activity in the Liard Basin by other operators has renewed industry focus in the area and validated Lone Pine’s view of the long-term commerciality of the area.  A recent horizontal well drilled approximately 60 miles south of Lone Pine’s acreage by a leading industry operator had a disclosed 30-day IP rate of over 20 MMcf/d.  Based on these early results combined with the developed infrastructure in the area and key proximity to potential future west coast LNG facilities, Lone Pine believes the area will become an attractive location for future natural gas development.

Lone Pine remains under application with the National Energy Board for a continuation of its landholdings based on development work it performed in 2011.

As of June 30, 2012, Lone Pine held 53,788 gross (52,995 net) acres in the Liard Basin in the Northwest Territories.

Utica Shale

Oil and natural gas development in the Province of Quebec continues to be under a strategic environmental assessment of shale gas drilling.  Lone Pine engaged Netherland, Sewell & Associates, Inc. (“NSAI”) to conduct an independent assessment of the Company’s unrisked Utica prospective and contingent shale gas resources (the “NSAI Resource Assessment”) in the Utica Shale in the Province of Quebec effective May 31, 2012.  The NSAI 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.

NSAI’s best estimate of undiscovered shale gas initially-in-place on the Company’s Utica Shale land base is over 55 Tcf.  NSAI’s estimate of unrisked prospective shale gas resources ranges from 867 Bcf in the low estimate to 7.9 Tcf in the high estimate with a best estimate of 2.6 Tcf.  NSAI’s estimate of unrisked contingent shale gas resources ranges from 12 Bcf in the low estimate to 109 Bcf in the high estimate with a best estimate of 36 Bcf.  As of June 30, 2012, Lone Pine held 398,850 gross (240,320 net) acres in the Utica Shale in Quebec.

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The table below sets out certain summary information from the NSAI Resource Assessment:

Notes:

(1)       “Discovered petroleum initially-in-place” (equivalent to discovered resources) is that quantity of petroleum that is estimated, on a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially-in-place includes production, reserves and contingent resources; the remainder as “unrecoverable”. No portion of the discovered shale gas initially-in-place estimates disclosed herein are attributable to past production or to reserves.

(2)       “Undiscovered petroleum initially-in-place” (equivalent to undiscovered resources) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially-in-place is referred to as “prospective resources”; the remainder as “unrecoverable”.

(3)       “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. The contingent resources in the NSAI Resource Assessment are contingent upon (1) demonstration of the economic viability of project development, (2) activity prior to expiration of leases, and (3) full development of the Lone Pine acreage.  If these contingencies are successfully addressed some portion of the contingent resources may be reclassified as reserves.  There is no certainty that it will be commercially viable to produce any portion of the contingent resources. The contingent resources have not been risked for chance of development.

(4)       “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. The prospective shale gas resources in the NSAI Resource Assessment indicate exploration opportunities and development potential in the event a shale gas discovery is made and should not be construed as reserves or contingent resources.  There is no certainty that any portion of the prospective resources will be discovered.  If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. The prospective resources have not been risked for chance of discovery or chance of development.

(5)       “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.

Second Half 2012 Capital Budget

Canadian oil & gas producers have experienced a significant drop in realized oil prices over the past quarter due to the decline in global crude oil prices combined with the continued widening of differentials between Edmonton Par pricing in Canada and WTI.  The lack of export infrastructure from Canada to the United States has continued to place pressure on Canadian price differentials, which remain in the $10 - $15 per barrel range and are forecasted to remain in this range through the end of 2012.  As a result of this reduced realized pricing outlook combined with continued volatility in crude oil markets, Lone Pine has elected to defer certain of its planned capital expenditures for the second half of 2012.

Lone Pine’s revised 2012 capital budget of $160 — $175 million represents an approximate 20% reduction in capital spending for the year from the previously guided $200 — $220 million.  Based on Lone Pine’s first half of 2012 capital spending of approximately $111 million, the Company expects total capital expenditures for the second half of the year will total approximately $50 — $65 million.  Lone Pine believes that a lower capital expenditure program for the second half of the year will maintain financial flexibility through 2012 and is the prudent course of action given current commodity price volatility.

Lone Pine plans to continue the existing single rig program currently running in Evi and expects to drill up to 35 gross (31.7 net) total wells in 2012.

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Revised 2012 Guidance

The information below represents Lone Pine’s updated guidance for capital expenditures and sales volumes for the full year 2012.  The guidance below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. Rather, the table simply sets forth our best estimate today for these matters based upon our current expectations about the future based upon both stated and unstated assumptions. Actual conditions and those assumptions may, and probably will, change over the course of the year.  The updated guidance remains subject to the cautionary statements and limitations in Lone Pine’s January 9, 2012 press release under the caption “2012  Guidance” as well as those stated below under the caption “Forward-Looking Statements.”

The following table summarizes selected guidance for 2012:

Based on US$90.00/bbl WTI oil prices, Edmonton Par to WTI differentials of $12.50/bbl and US$3.00/MMBtu NYMEX natural gas prices for the second half of 2012, Lone Pine expects adjusted discretionary cash flow to be approximately $40 - $45 million in the second half of 2012.

Hedging Update

As of August 9, 2012, Lone Pine had commodity derivatives in place for the remainder of 2012 and for 2013 covering the aggregate average daily volumes and weighted average prices shown below:

(1)   Includes 10,000 MMBtu/d hedged at US$3.31/MMBtu for September - December 2012 and 25,000 MMBtu/d hedged at US$5.09/MMBtu for July - December 2012.

(2)   In connection with receiving premium pricing on a calendar 2013 oil swap, Lone Pine granted a call option for the same period on 500 bbls/d with a strike price of CDN$95.05/bbl.

The total hedged volumes represent approximately 60% of the forecasted natural gas net sales volumes and 75% of the forecasted oil net sales volumes for the second half of 2012.

Conference Call

A conference call to discuss the second quarter of 2012 results is scheduled for Tuesday, August 14, 2012, at 11:00 AM MT.  To participate, please dial 1-800-659-2037 (toll-free for North America) or 1-617-614-2713 and request the Lone Pine teleconference (ID # 34612525) or listen to the webcast on Lone Pine’s website at www.lonepineresources.com.  A replay will be available through August 28, 2012 by dialing 1-888-286-8010 or 1-617-801-6888 and entering conference passcode #53303382.

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Change in Reporting and Functional Currency

Lone Pine elected to change its reporting currency from the United States dollar to the Canadian dollar effective October 1, 2011. The change in reporting currency results in a matching of Lone Pine’s reporting currency to its functional currency of the Canadian dollar and better reflects the business of Lone Pine, which is almost entirely conducted in Canadian dollars. All of Lone Pine’s financial reporting has since been presented in Canadian dollars.  Lone Pine has recast the second quarter 2011 information contained in this news release from United States dollars to Canadian dollars.

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):

Adjusted EBITDA

In addition to reporting net earnings as defined under GAAP, Lone Pine also presents adjusted earnings before interest, income taxes, depreciation, depletion, and amortization (“Adjusted EBITDA”), which is a non-GAAP performance measure.  Adjusted EBITDA consists of net earnings (loss) before interest expense, income taxes, depreciation, depletion and amortization, impairment of assets as well as other items such as unrealized gains on derivative instruments, realized and unrealized foreign currency exchange (gains) losses, ceiling test write-downs, accretion of asset retirement obligations, and other items presented in the table below.  Adjusted EBITDA does not represent, and should not be considered an alternative to, GAAP measurements, such as net earnings (loss) (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 interest, income taxes, depreciation, depletion and amortization, and other items from earnings, Lone Pine believes the result is a useful measure across time in evaluating its fundamental core operating performance.  Management also uses Adjusted EBITDA to manage its business, including in preparing its annual operating budget and financial projections.  Lone Pine believes that Adjusted EBITDA is also 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 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, Lone Pine 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 provides a reconciliation of net earnings (loss), the most directly comparable GAAP measure, to Adjusted EBITDA for the periods presented (in thousands):

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Adjusted Discretionary Cash Flow

In addition to reporting cash provided by operating activities as defined under GAAP, Lone Pine also presents 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 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 Lone Pine has 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 Lone Pine’s operating performance has material limitations.  The following table provides a reconciliation of net cash provided by operating activities, the most directly comparable GAAP measure, to adjusted discretionary cash flow for the periods presented (in thousands):

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, 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

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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 “Shale Gas Initially-In-Place”, “Contingent Shale Gas Resource” and “Prospective Shale 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.

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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.

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For further information please contact:

David Anderson

President & Chief Executive Officer

Tel.: (403) 292-8000

Ed Bereznicki

Executive Vice President & Chief Financial Officer

Tel.: (403) 292-8000

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SUPPLEMENTAL FINANCIAL INFORMATION

LONE PINE RESOURCES INC.

Condensed Consolidated Balance Sheets

(Unaudited)

(In thousands of Canadian dollars)

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LONE PINE RESOURCES INC.

Condensed Consolidated Statements of Operations

(Unaudited)

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

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LONE PINE RESOURCES INC.

Condensed Consolidated Statements of Cash Flows

(Unaudited)

(In thousands of Canadian dollars)

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