Lone Pine Resources (LPRIQ) 10-Q 2012 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2012

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                to

Commission File Number 1-35191

LONE PINE RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware	27-3779606
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

Suite 1100, 640-5th Avenue SW Calgary, Alberta Canada	T2P 3G4
(Address of Principal Executive Offices)	(Zip Code)

(403) 292-8000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o No

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

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

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

As of August 9, 2012, there were 85,098,773 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

LONE PINE RESOURCES INC.

INDEX TO FORM 10-Q

June 30, 2012

Monetary Amounts and Exchange Rate Data	ii
Part I - FINANCIAL INFORMATION	1
Item 1 - Financial Statements	1
Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	1
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011	2
Condensed Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2012 and 2011	2
Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2012 and 2011	3
Condensed Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2012	4
Notes to Condensed Consolidated Financial Statements	5
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 3 - Quantitative and Qualitative Disclosures About Market Risk	43
Item 4 - Controls and Procedures	45
Part II - OTHER INFORMATION	45
Item 1 - Legal Proceedings	45
Item 1A - Risk Factors	46
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 6 - Exhibits	46
Signatures	48
Exhibit Index	49

i

MONETARY AMOUNTS AND EXCHANGE RATE DATA

In this Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2012 (the “Quarterly Report”), references to “dollars,” “$” or “Cdn$” are to Canadian dollars and references to “U.S. dollars” or “US$” are to United States dollars. Effective October 1, 2011, we changed our reporting currency from the U.S. dollar to the Canadian dollar. Prior to changing our reporting currency, we obtained a no objection letter from the Securities and Exchange Commission (“SEC”). See Part I, “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and note 2 of our financial statements for more information about our change in reporting currency, including the reasons for the change, the manner in which the change has been and will be applied to recast prior period financial statements, and a discussion of the major categories of items in the balance sheet, and statements of operations, comprehensive income and cash flows that are denominated in Canadian or U.S. dollars.

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

	Three Months Ended June 30,		Six Months Ended June 30,		Year Ended
	2012	2011	2012	2011	December 31, 2011
	US$	US$	US$	US$	US$
Highest rate during the period	1.0197	1.0542	1.0197	1.0542	1.0583
Lowest rate during the period	0.9599	1.0141	0.9599	0.9978	0.9430
Average noon spot rate during the period(1)	0.9897	1.0331	0.9943	1.0238	1.0117
Rate at the end of the period	0.9813	1.0370	0.9813	1.0370	0.9833

(1) Determined by averaging the rates on each business day during the respective period.

On August 9, 2012, the noon-day exchange rate was US$1.0077 for Cdn$1.00.

ii

PART I—FINANCIAL INFORMATION

Item 1.  Financial Statements.

LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands of Canadian dollars)

	June 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash	$	880		$	276
Accounts receivable	18,453			28,804
Derivative instruments	21,595			19,786
Prepaid expenses and other current assets	5,194			5,560
Total current assets	46,122			54,426
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion of $1,390,445 and $1,203,755	618,628			704,232
Unproved	148,558			138,727
Net oil and natural gas properties	767,186			842,959
Other property and equipment, net of accumulated depreciation and amortization of $9,375 and $8,647	65,863			66,413
Net property and equipment	833,049			909,372
Derivative instruments	2,562			—
Goodwill	17,328			17,328
Other assets	12,145			11,175
	$	911,206		$	992,301
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	39,795		$	75,702
Accrued interest	7,989			—
Capital lease obligation	1,186			1,156
Deferred income taxes	4,694			4,946
Other current liabilities	3,079			2,686
Total current liabilities	56,743			84,490
Long-term debt	425,343			331,000
Asset retirement obligations	15,279			15,412
Deferred income taxes	35,225			69,981
Capital lease obligation	5,137			5,738
Other liabilities	1,521			1,818
Total liabilities	539,248			508,439
Stockholders’ equity:
Common stock, 85,098,773 and 85,026,202 shares issued and outstanding	834			833
Capital surplus	981,508			978,880
Accumulated deficit	(610,502		)	(495,959		)
Accumulated other comprehensive income	118			108
Total stockholders’ equity	371,958			483,862
	$	911,206		$	992,301

See accompanying notes to condensed consolidated financial statements.

1

LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
				(Recast*)						(Recast*)
Revenues:
Oil and natural gas	$	42,420		$	49,236		$	86,749		$	84,798
Interest and other	4			8			10			20
Total revenues	42,424			49,244			86,759			84,818
Costs, expenses and other:
Lease operating expenses	14,160			8,615			28,609			16,664
Production and property taxes	832			598			1,685			1,189
Transportation and processing	4,311			4,216			8,464			7,766
General and administrative	5,840			2,497			9,946			5,887
Depreciation, depletion and amortization	31,882			19,919			58,312			38,560
Ceiling test write-down of oil and natural gas properties	128,870			—			128,870			—
Interest expense	8,242			2,237			13,993			3,590
Accretion of asset retirement obligations	341			267			677			537
Foreign currency exchange losses (gains)	4,269			2,564			3,973			(4,970		)
Losses (gains) on derivative instruments	(18,375		)	(4,948		)	(18,268		)	(4,948		)
Other, net	41			458			52			503
Total costs, expenses and other	180,413			36,423			236,313			64,778
Earnings (loss) before income taxes	(137,989		)	12,821			(149,554		)	20,040
Income tax expense (recovery)	(32,954		)	7,455			(35,011		)	9,383
Net earnings (loss)	$	(105,035	)	$	5,366		$	(114,543	)	$	10,657
Basic earnings (loss) per common share	$	(1.24	)	$	0.07		$	(1.35	)	$	0.15
Diluted earnings (loss) per common share	$	(1.24	)	$	0.07		$	(1.35	)	$	0.15

*      see notes 1 and 2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands of Canadian dollars)

	Three��Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
				(Recast*)						(Recast*)
Net earnings (loss)	$	(105,035	)	$	5,366		$	(114,543	)	$	10,657
Other comprehensive income (loss)
Amortization of minimum postretirement benefits liability, net of tax	5			—			10			—
Foreign currency translation adjustments, net of tax	—			(14		)	—			28
	5			(14		)	10			28
Comprehensive income (loss)	$	(105,030	)	$	5,352		$	(114,533	)	$	10,685

*      see notes 1 and 2

See accompanying notes to condensed consolidated financial statements.

2

LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands of Canadian dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
				(Recast*)						(Recast*)
Operating activities:
Net earnings (loss)	$	(105,035	)	$	5,366		$	(114,543	)	$	10,657
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	31,882			19,919			58,312			38,560
Amortization of deferred costs	621			349			1,102			434
Ceiling test write-down of oil and natural gas properties	128,870			—			128,870			—
Accretion of asset retirement obligations	341			267			677			537
Deferred income tax expense (recovery)	(32,954		)	7,455			(35,011		)	9,383
Unrealized foreign currency exchange losses (gains)	4,228			2,564			3,932			(4,970		)
Unrealized losses (gains) on derivative instruments	(9,540		)	(4,948		)	(4,371		)	(4,948		)
Stock-based compensation	1,001			19			1,720			19
Other, net	(738		)	29			(717		)	47
Changes in operating assets and liabilities:
Accounts receivable	4,177			(1,085		)	10,351			4,285
Prepaid expenses and other current assets	1,496			2,884			1,188			2,676
Accounts payable and accrued liabilities	(8,196		)	(4,145		)	(21,752		)	(4,578		)
Accrued interest and other current liabilities	4,541			(24,457		)	8,150			(23,833		)
Net cash provided by operating activities	20,694			4,217			37,908			28,269
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	(56,567		)	(139,566		)	(130,255		)	(187,730		)
Other fixed assets	(737		)	(1,062		)	(1,649		)	(9,899		)
Proceeds from divestiture of assets	280			62			280			468
Net cash used in investing activities	(57,024		)	(140,566		)	(131,624		)	(197,161		)
Financing activities:
Net proceeds from issuance of long-term debt	—			—			192,052			—
Debt issuance costs	(70		)	(4,078		)	(1,295		)	(4,078		)
Proceeds from bank borrowings	681,000			553,000			1,466,000			589,000
Repayments of bank borrowings	(639,000		)	(282,000		)	(1,568,000		)	(318,000		)
Proceeds from Forest Oil Corporation	—			72,833			—			108,677
Repayments to Forest Oil Corporation	—			(366,494		)	—			(366,494		)
Cash distribution to Forest Oil Corporation	—			(28,711		)	—			(28,711		)
Proceeds from issuance of common stock, net of offering costs	—			173,415			—			173,415
Change in bank overdrafts	(5,011		)	13,130			6,301			11,576
Proceeds from sale-leaseback	—			7,450			—			7,450
Capital lease payments	(454		)	—			(738		)	—
Other, net	—			17			—			7
Net cash provided by financing activities	36,465			138,562			94,320			172,842
Effect of exchange rate changes on cash	—			309			—			309
Net increase (decrease) in cash	135			2,522			604			4,259
Cash at beginning of period	745			2,310			276			573
Cash at end of period	$	880		$	4,832		$	880		$	4,832

*        see notes 1 and 2

See accompanying notes to condensed consolidated financial statements.

3

LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

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

											Accumulated
											Other		Total
	Common Stock				Capital			Accumulated			Comprehensive		Stockholders’
	Shares		Amount		Surplus			Deficit			Income		Equity
	(In thousands)
Balances at December 31, 2011	85,026		$	833	$	978,880		$	(495,959	)	$	108	$	483,862
Issuance of common stock	68		1		(1		)	—			—		—
Vesting of Phantom Stock Units	8		—		46			—			—		46
Tax withheld on vesting of Phantom Stock Units	(3	)	—		(18		)	—			—		(18		)
Amortization of stock-based compensation	—		—		2,601			—			—		2,601
Comprehensive income (loss):
Net earnings (loss)	—		—		—			(114,543		)	—		(114,543		)
Other comprehensive income	—		—		—			—			10		10
Balances at June 30, 2012	85,099		$	834	$	981,508		$	(610,502	)	$	118	$	371,958

See accompanying notes to condensed consolidated financial statements.

4

LONE PINE RESOURCES INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) ORGANIZATION AND BASIS OF PRESENTATION

Organization

Lone Pine Resources Inc. (“Lone Pine” or the “Company”) is an independent oil and natural gas exploration, development and production company with operations in Canada. Lone Pine’s reserves, producing properties and exploration prospects are located in the provinces of Alberta, British Columbia and Quebec, and in the Northwest Territories. Lone Pine conducts operations in one industry segment, liquids and natural gas exploration, development and production, and in one country, Canada. The Company’s operations are primarily carried out by its operating subsidiary, Lone Pine Resources Canada Ltd. (“LPR Canada”).

Basis of Presentation

These financial statements are presented in conformity with U.S. generally accepted accounting principles (“GAAP”). In these financial statements, unless otherwise indicated, all amounts are expressed in Canadian dollars. Certain amounts in prior periods’ financial statements have been reclassified to conform to the current period’s financial statement presentation.

The accompanying financial statements of the Company have been prepared in accordance with the instructions to Form 10-Q as prescribed by the U.S. Securities Exchange Commission (“SEC”). Lone Pine’s Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Annual Report”) includes additional information related to the Company’s initial public offering (“IPO”) on June 1, 2011 as well as the Company’s spin-off from Forest Oil Corporation (“Forest”) on September 30, 2011 (the “Distribution”). The 2011 Annual Report also includes a summary of significant accounting policies and should be read in conjunction with this Quarterly Report. All material adjustments (consisting solely of normal recurring adjustments) that, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. The results for the three and six month periods ended June 30, 2012 are not necessarily indicative of the results to be expected for the full year.

The financial statements relating to the period from Lone Pine’s inception (September 30, 2010) through the completion of the 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 Lone Pine’s 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.

(2) CHANGE IN REPORTING AND FUNCTIONAL CURRENCY

Reporting Currency

The Company’s financial statements for periods up to and including September 30, 2011 were reported using the U.S. dollar, as this was the reporting currency used by Forest. Effective October 1, 2011, the Company changed its reporting currency to the Canadian dollar to better reflect the business of Lone Pine, which is primarily conducted in Canadian dollars. This change in reporting currency was also considered appropriate since there were only two major financial statement categories denominated in U.S. dollars at the time. One category was the liability to Forest (for periods prior to June 1, 2011) and the second category was the Stockholders’ Equity of Lone Pine (for periods after the IPO date of June 1, 2011).

With the change in reporting currency, all comparative financial information has been recast from U.S. dollars to Canadian dollars to reflect the Company’s financial statements as if they had been historically reported in Canadian dollars, consistent with the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) 830, Foreign Currency Matters.

The statements of operations, comprehensive income and cash flows for the three and six month periods ended June 30, 2011 were translated into Canadian dollars using the weighted average foreign 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.

5

Functional Currency

The Company changed the functional currency of Lone Pine prospectively from October 1, 2011 from the U.S. dollar to the Canadian dollar. The change in functional currency did not have a significant impact on the Company’s financial statements as Lone Pine’s operations are primarily carried out by LPR Canada. The functional currency of LPR Canada has not changed and continues to be the Canadian dollar.

As a result of this change in functional currency, there is no difference between the reporting currency and the functional currency of the Company and any of its subsidiaries.

(3) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

The Company’s significant accounting policies have not changed materially from those reported in its 2011 Annual Report. The following information supplements those policies.

Long-Term Debt

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

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 financial statements prepared under GAAP and International Financial Reporting Standards 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.  Lone Pine is currently evaluating the impact that the adoption of this authoritative guidance will have on its financial statements.

In December 2011, the FASB issued Accounting Standards Update No. 2011-12, Comprehensive Income, Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”), which defers indefinitely the requirements in Accounting Standards Update No. 2011-05, Comprehensive Income, Presentation of Comprehensive Income (“ASU 2011-05”) to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income (see note 4 for additional information).  The adoption of this authoritative guidance will not have an impact on the Company’s financial statements until the specific changes that were proposed under ASU 2011-05 are finalized and issued by the FASB.

(4) ADOPTION OF NEW ACCOUNTING STANDARDS

In the fourth quarter of 2011, Lone Pine 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 the Company to present items of net income and 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.  Lone Pine 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 the Company’s financial statements.

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

6

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

(5) BUSINESS COMBINATION

On April 29, 2011, the Company completed the acquisition of certain natural gas properties located in the Narraway/Ojay area for $74.4 million. The acquisition increased the Company’s working interests in certain properties already owned and operated by the Company, and provided additional capacity in gathering systems and a natural gas plant in the area. The following table shows the final estimates of fair value for the acquisition, which were based on an analysis of the properties acquired (in thousands).

Proved properties	$	40,454
Unproved properties	26,285
Natural gas plant/pipelines	8,000
Asset retirement obligations	(292		)
	$	74,447

The statements of operations for the three and six month periods ended June 30, 2011 include $2.1 million of revenue from these properties since their acquisition date of April 29, 2011, and increased net earnings by approximately $0.1 million. The disclosure of supplemental pro forma information, which would disclose Lone Pine’s consolidated revenue and earnings as though the business combination had occurred at January 1, 2010, is impractical. The disclosure is impractical since the Company does not have sufficient information regarding the revenues and costs related to the properties in previous periods and therefore, the pro forma disclosures would require significant estimates that could not be objectively or independently verified.

(6) PROPERTY AND EQUIPMENT

Full Cost Method of Accounting

The Company uses the full cost method of accounting for oil and natural gas activities. Under the full cost method of accounting for oil and natural gas activities, the ceiling test calculation uses prices that are based on the average of the first-day-of-the-month prices during the 12 month period prior to the reporting date.

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

Investments in unproved properties, including capitalized interest costs, are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, geographic and geologic data obtained relating to the properties and estimated discounted future net cash flows from the properties. Estimated discounted future net cash flows are based on discounted future net revenues associated with probable and possible reserves, risk adjusted as appropriate. Where it is not practicable to assess individually the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. If an impairment is identified, the amount of the impairment assessed is added to the costs to be amortized.

The Company performs a ceiling test each quarter. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is not a fair value based measurement. Rather, it is a standardized

7

mathematical calculation. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for a cost center may not exceed the sum of: (1) the present value of future net revenue from estimated production of proved oil and natural gas reserves using 12 month average trailing prices (as discussed below), excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, at a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and natural gas properties. Should the net capitalized costs for a cost center exceed the sum of the components noted above, a ceiling test write-down would be recognized to the extent of the excess capitalized costs.

The prices used in the ceiling test are based on an average of the first-day-of-the-month prices during the 12 month period prior to the reporting date, pursuant to the SEC's Modernization of Oil and Gas Reporting rule, which was first effective for the ceiling test calculated as of December 31, 2009.

As required under the quarterly ceiling test calculation, the Company updated its internal estimate of proved oil and natural gas reserves, and the present value of future net revenue from those reserves. As a result of a decline in the 12 month average trailing natural gas price, the Company’s internal estimate of its proved undeveloped natural gas volumes decreased significantly at June 30, 2012. This decrease in natural gas volume reduced the Company’s internal estimate of the present value of future net revenue from proved reserves and resulted in the Company recognizing a ceiling test write-down of $128.9 million before tax for the three and six months ended June 30, 2012.

The Company 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 exceeds the discounted future net cash flows from the additional reserves.

(7) LONG-TERM DEBT

The Company’s long-term debt consisted of the following at June 30, 2012 and December 31, 2011.

	June 30, 2012							December 31, 2011
	(In thousands)
	Principal		Unamortized Discount			Total		Principal		Unamortized Discount		Total
Bank credit facility	$	229,000	$	—		$	229,000	$	331,000	$	—	$	331,000
Senior Notes	203,811		(7,468		)	196,343		—		—		—
Total Long-term Debt	$	432,811	$	(7,468	)	$	425,343	$	331,000	$	—	$	331,000

Bank Credit Facility

Lone Pine maintains a $500 million bank credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The bank credit facility became effective upon the closing of the IPO and will mature on March 18, 2016. Availability under the bank credit facility is governed by a borrowing base. As of June 30, 2012, the borrowing base was set at $375 million and the Company had $229.0 million outstanding under its bank credit facility at a weighted average interest rate of 3.6162%, and remaining borrowing capacity of $144.4 million (after deducting $1.6 million of outstanding letters of credit). The determination of the borrowing base is made by the lenders, in their sole discretion, taking into consideration the estimated value of the Company’s oil and natural gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base will be redetermined semi-annually and the available borrowing amount under the bank credit facility could increase or decrease based on such redetermination. The next scheduled redetermination of the borrowing base is expected to

8

occur on or about November 1, 2012. In addition to the scheduled semi-annual redeterminations, the Company 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.

The agreement governing the 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. The bank credit facility provides that Lone Pine will not permit its ratio of total debt outstanding to consolidated earnings before interest, income taxes, depreciation and amortization (as defined by the terms of the bank credit facility and adjusted for non-cash charges) for a trailing 12 month period to be greater than 4.0 to 1.0. As at June 30, 2012, this ratio was approximately 3.3 to 1.0. If Lone Pine were to fail to perform its obligations under these covenants or other covenants and obligations, it could cause an event of default and the bank credit facility could be terminated and amounts outstanding could be declared immediately due and payable by the lenders, subject to notice and cure periods in certain cases. Such events of default include non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, change of control and a failure of the liens securing the bank credit facility. In addition, bankruptcy and insolvency events with respect to Lone Pine will result in an automatic acceleration of the indebtedness under the bank credit facility. An acceleration of the Company’s indebtedness under the bank credit facility could in turn result in an event of default under the indenture governing Lone Pine’s Senior Notes (discussed below), which in turn could result in the acceleration of payment of the Senior Notes. For example, the indenture governing Lone Pine’s Senior Notes includes as an event of default, among others, a default on indebtedness that results in the acceleration of indebtedness in an amount greater than US$20 million.

Borrowings under the Company’s bank credit facility bear interest at one of two rates that the Company elects. 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 the 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 Lone Pine’s bank credit facility) plus 75 to 175 basis points, depending on borrowing base utilization.

Senior Notes

On February 14, 2012, LPR Canada (the “Subsidiary Issuer”), an Alberta corporation and a wholly-owned subsidiary of the Company, issued US$200 million aggregate principal amount of 10.375% Senior Notes due February 15, 2017 (the “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 the Company (the “Parent Guarantor”) and all of the Company’s subsidiaries, other than LPR Canada (together, the “Guarantors”). These guarantees are full and unconditional, and joint and several among the Guarantors. After the original issue discount of 1.423% and commissions of approximately $4.9 million, the issuance of the Senior Notes resulted in net proceeds to the Company of $192 million.

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

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

The Senior Notes were offered and sold to qualified institutional buyers in reliance on SEC Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), and non-U.S. persons in reliance on SEC Regulation S under the Securities Act. The Senior Notes have not been registered under the Securities Act, or any state securities laws. In connection with the issuance of the Senior Notes, LPR Canada and the Guarantors entered into a Registration Rights Agreement that requires LPR Canada and the Guarantors to file a registration statement with respect to an offer to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act. LPR Canada and the Guarantors agreed to use their commercially reasonable efforts to cause such exchange offer registration statement to become effective under the Securities Act.

9

In addition, LPR Canada and the Guarantors agreed to use their commercially reasonable efforts to cause the exchange offer to be consummated not later than 365 days after February 14, 2012. Under some circumstances, in lieu of, or in addition to, a registered exchange offer, LPR Canada and the Guarantors have agreed to file a shelf registration statement with respect to the Senior Notes. LPR Canada and the Guarantors are required to pay additional interest if they fail to comply with their obligations to register the Senior Notes within the specified time period.

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

The Indenture contains customary events of default, including:

·default in any payment of interest on any Senior Note when due, continued for 30 days;

·default in the payment of principal of or premium, if any, on any Senior Note when due;

·failure by LPR Canada or any Guarantor to comply with its other obligations under the Indenture, in certain cases subject to notice and grace periods;

·default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Parent Guarantor or any of its restricted subsidiaries (or the payment of which is guaranteed by the Parent Guarantor or any of its restricted subsidiaries), other than indebtedness owed to the Parent Guarantor or a restricted subsidiary, whether such indebtedness or guarantee now exists, or is created after the date of the Indenture;

·certain events of bankruptcy, insolvency or reorganization of the Parent Guarantor, LPR Canada or a significant subsidiary or group of restricted subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Parent Guarantor and its restricted subsidiaries), would constitute a significant subsidiary;

·failure by the Parent Guarantor, LPR Canada or any significant subsidiary or group of restricted subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Parent Guarantor and its restricted subsidiaries), would constitute a significant subsidiary to pay final judgments aggregating in excess of US$20.0 million, within 60 days; and

·any guarantee of the Senior Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

(8) DERIVATIVE INSTRUMENTS

Commodity Derivatives

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

10

The table below sets forth Lone Pine’s outstanding commodity swaps as of June 30, 2012.

	Commodity Swaps
	Natural Gas (NYMEX Henry Hub)			Oil (NYMEX WTI)
Term	MMBtu/d	Weighted Average Price per MMBtu		bbls/d	Weighted Average Price per bbl
July 1 — December 31, 2012	25,000	US$	5.09	2,000	US$	102.35
July 1 — December 31, 2012	—		—	1,000	$	100.98
Calendar 2013	—		—	1,500	$	100.37
Calendar 2013	—		—	500	US$	101.00

In connection with a commodity swap entered into during the second quarter of 2012, the Company sold a call option to the counterparty in exchange for the Company receiving a premium fixed price on the commodity swap. The table below sets forth the outstanding option as of June 30, 2012.

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

The Company also enters into commodity collar agreements with third parties. A collar agreement is similar to a swap agreement, except that the Company receives the difference between the floor price and the index price only if the index price is below the floor price, and the Company pays the difference between the ceiling price and the index price only if the index price is above the ceiling price. The table below sets forth the Company’s outstanding commodity collars as of June 30, 2012.

	Commodity Collars
	Natural Gas (NYMEX Henry Hub)
Term	MMBtu/d	Weighted Average Floor Price per MMBtu		Weighted Average Ceiling Price per MMBtu
Calendar 2013	15,000	US$	3.00	US$	4.00

Fair Value Amounts

The table below summarizes the location and fair value amounts of the Company’s derivative instruments reported in the balance sheets as of the dates indicated. See note 9 for additional information on the fair value of the Company’s derivative instruments.

	June 30, 2012		December 31, 2011
	(In thousands)
Assets:
Current assets	$	21,595	$	19,786
Long-term assets	2,562		—
	$	24,157	$	19,786

The table below shows the derivative instrument gains and losses reported in the statements of operations as “Losses (gains) on derivative instruments” for the periods indicated. Due to the volatility of oil and natural gas prices, the estimated fair values of Lone Pine’s commodity derivative instruments are subject to large fluctuations from period to period.

	Three Months Ended  June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Realized losses (gains) on derivative instruments	$	(8,835	)	$	—		$	(13,897	)	$	—
Unrealized losses (gains) on derivative instruments	(9,540		)	(4,948		)	(4,371		)	(4,948		)
Losses (gains) on derivative instruments	$	(18,375	)	$	(4,948	)	$	(18,268	)	$	(4,948	)

11

(9) FAIR VALUE MEASUREMENTS

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

The fair values and carrying amounts of the Company’s financial instruments are summarized below.

	Fair value	June 30, 2012				December 31, 2011
	measurement Level	Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(In thousands)
Assets:
Cash	—	$	880	$	880	$	276	$	276
Accounts receivable	—	18,453		18,453		28,804		28,804
Derivative instruments	2	24,157		24,157		19,786		19,786
Liabilities:
Accounts payable and accrued liabilities	—	39,795		39,795		75,702		75,702
Accrued interest	—	7,989		7,989		—		—
Long-term debt
Bank credit facility	2	229,000		229,000		331,000		331,000
Senior Notes	1	196,343		192,738		—		—
Total Long-term debt		425,343		421,738		331,000		331,000
Capital lease obligation	2	6,323		6,323		6,894		6,894

The Company uses various assumptions and methods in estimating the fair values of its financial instruments. All of the estimates of fair value were determined using significant other observable inputs (Level 2), except for the fair value of the Senior Notes, which was determined based on the unadjusted quoted price in an active market (Level 1) given that the Senior Notes are actively traded in a private market with an independent quoted price available from a third party. The carrying amount of the Senior Notes has been reduced by the original issue discount of 1.423% and commissions of approximately $4.9 million, while the fair value of the Senior Notes is based on its face amount of US$200 million and June 30, 2012 market price of US$94.563 per US$100 face amount. The carrying amount of the bank credit facility approximates fair value since the borrowings bear interest at variable market rates. The carrying amount of the capital lease obligation approximates fair value, as interest rates have not materially changed since the lease was executed.

The Company’s derivative instrument assets and liabilities include commodity derivatives. See note 8 for additional information on these instruments.  The Company utilizes present value techniques to value its derivatives.  Inputs to the valuations include published forward prices and credit risk considerations, including the incorporation of published interest rates and credit spreads.  All of the significant inputs are observable, therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy.

The fair values of the other financial instruments, including cash, accounts receivable, accrued interest, accounts payable and accrued liabilities, approximate their carrying amount due to their short-term nature.

12

(10) EARNINGS (LOSS) PER SHARE

The following sets forth the calculation of basic and diluted earnings (loss) per common share for the periods presented.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Net earnings (loss)	$	(105,035	)	$	5,366		$	(114,543	)	$	10,657
Net earnings attributable to participating securities	—			(1		)	—			(1		)
Net earnings (loss) attributable to common stock	$	(105,035	)	$	5,365		$	(114,543	)	$	10,656
Weighted average number of common shares outstanding during the period for basic earnings per share	85,008			74,945			85,004			72,486
Dilutive effect of potential common shares	—			—			—			—
Weighted average number of common shares outstanding during the period, including the effects of dilutive potential common shares, for diluted earnings per share	85,008			74,945			85,004			72,486
Basic earnings (loss) per common share	$	(1.24	)	$	0.07		$	(1.35	)	$	0.15
Diluted earnings (loss) per common share	$	(1.24	)	$	0.07		$	(1.35	)	$	0.15

At June 30, 2012, approximately 1.8 million potential shares were excluded from the diluted earnings (loss) per common share calculation as the effect of their inclusion was anti-dilutive.  At June 30, 2011, no potential common shares were excluded from the diluted earnings per common share calculation.

(11) STOCK-BASED COMPENSATION

The following tables reconcile the change in number of units outstanding for each of Lone Pine’s long-term incentive plans for the six months ended June 30, 2012 and 2011.

	Phantom Stock Units		StockOptions		Restricted Stock		Total
Outstanding as of December 31, 2011	700,950		—		26,202		727,152
Awarded	1,007,130		650,636		67,935		1,725,701
Vested	(165,849	)	—		(11,539	)	(177,388	)
Forfeited	(36,800	)	(9,500	)	—		(46,300	)
Outstanding as of June 30, 2012	1,505,431		641,136		82,598		2,229,165

	Phantom Stock Units	StockOptions	Restricted Stock	Total
Outstanding as of December 31, 2010	—	—	—	—
Awarded	460,385	—	19,232	479,617
Outstanding as of June 30, 2011	460,385	—	19,232	479,617

(12) INCOME TAXES

The Company calculates its income tax expense for the period by estimating the annual effective income tax rate and applying that rate to the year-to-date earnings (loss) at the end of each period.

The Company’s effective income tax rate in any period is a function of the relationship between total income tax expense and the amount of earnings before income taxes for the period. The effective income tax rate differs from the statutory tax rate as it takes into consideration permanent differences (such as stock-based compensation that will be settled in shares of the Company), adjustments for changes in income tax rates and other income tax legislation, and the differences between the provision and the actual amounts subsequently reported on the income tax returns.

The Company’s combined Canadian federal and provincial statutory income tax rate was approximately 25% for the three and six months ended June 30, 2012 and 26.5% for the three and six months ended 2011. However, the Company’s effective income tax rates of 24% for the three months ended June 30, 2012 and 23% for the six months ended June 30, 2012 were lower than the Canadian statutory tax rate of 25%, primarily due to an increase in a valuation allowance (relating to deferred tax assets) that reduced the loss for income tax purposes, foreign exchange losses on the Senior Notes that are taxed at 50% of the statutory tax rate, as well as non-deductible stock-based

13

compensation expense. The Company’s effective income tax rates of 58% for the three months ended June 30, 2011 and 47% for the six months ended June 30, 2011 were higher than the Canadian statutory tax rate of 26.5% primarily due to an increase in a valuation allowance (relating to deferred tax assets) that increased taxable income.

(13) SUBSEQUENT EVENTS

Commodity Derivatives

The following table summarizes additional commodity swaps that were entered into between July 1, 2012 and August 9, 2012.

	Commodity Swaps
	Natural Gas (NYMEX Henry Hub)			Oil (NYMEX WTI)
Term	MMBtu/d	Weighted Average Price per MMBtu		bbls/d	Weighted Average Price per bbl
September 1 — December 31, 2012	10,000	US$	3.31	—	—
Calendar 2013	—	—		500	$	93.30

The following table summarizes additional commodity collars that were entered into between July 1, 2012 and August 9, 2012.

	Commodity Collars
	Natural Gas (NYMEX Henry Hub)
Term	MMBtu/d	Weighted Average Floor Price per MMBtu		Weighted Average Ceiling Price per MMBtu
Calendar 2013	15,000	US$	3.50	US$	3.85

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On February 14, 2012, LPR Canada issued US$200 million of Senior Notes (see note 7 — Long-term Debt for more information on the Senior Notes), which are guaranteed on a senior unsecured basis by the Guarantors. These guarantees are full and unconditional, and joint and several among the Guarantors.

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

14

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Balance Sheet

(In thousands of Canadian dollars)

	As of June 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries		SubsidiaryIssuer			Eliminations			Consolidated
ASSETS
Current assets:
Cash	$	35		$	—	$	845		$	—		$	880
Accounts receivable	30			502		18,423			(502		)	18,453
Derivative instruments	—			—		21,595			—			21,595
Prepaid expenses and other current assets	500			—		4,694			—			5,194
Total current assets	565			502		45,557			(502		)	46,122
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion	—			—		618,628			—			618,628
Unproved	—			—		148,558			—			148,558
Net oil and natural gas properties	—			—		767,186			—			767,186
Other property and equipment, net of accumulated depreciation and amortization	—			—		65,863			—			65,863
Net property and equipment	—			—		833,049			—			833,049
Investment in affiliate	356,913			58,063		—			(414,976		)	—
Derivative instruments	—			—		2,562			—			2,562
Goodwill	—			—		17,328			—			17,328
Other assets	—			—		12,145			—			12,145
	$	357,478		$	58,565	$	910,641		$	(415,478	)	$	911,206
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	704		$	—	$	39,593		$	(502	)	$	39,795
Accrued interest	—			—		7,989			—			7,989
Capital lease obligation	—			—		1,186			—			1,186
Deferred income taxes	—			—		4,694			—			4,694
Other current liabilities	—			—		3,079			—			3,079
Total current liabilities	704			—		56,541			(502		)	56,743
Long-term debt	—			—		425,343			—			425,343
Asset retirement obligations	—			—		15,279			—			15,279
Deferred income taxes	—			—		35,225			—			35,225
Capital lease obligation	—			—		5,137			—			5,137
Other liabilities	—			—		1,521			—			1,521
Total liabilities	704			—		539,046			(502		)	539,248
Stockholders’ equity:
Common stock	834			39,135		832,750			(871,885		)	834
Capital surplus	362,061			19,027		143,138			457,282			981,508
Retained earnings (accumulated deficit)	(6,526		)	403		(604,006		)	(373		)	(610,502		)
Accumulated other comprehensive income (loss)	405			—		(287		)	—			118
Total stockholders’ equity	356,774			58,565		371,595			(414,976		)	371,958
	$	357,478		$	58,565	$	910,641		$	(415,478	)	$	911,206

15

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Balance Sheet

(In thousands of Canadian dollars)

	As of December 31, 2011
	Parent Guarantor			Combined Guarantor  Subsidiaries		SubsidiaryIssuer			Eliminations			Consolidated
ASSETS
Current assets:
Cash	$	273		$	—	$	3		$	—		$	276
Accounts receivable	—			504		28,804			(504		)	28,804
Derivative instruments	—			—		19,786			—			19,786
Prepaid expenses and other current assets	180			—		5,380			—			5,560
Total current assets	453			504		53,973			(504		)	54,426
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion	—			—		704,232			—			704,232
Unproved	—			—		138,727			—			138,727
Net oil and natural gas properties	—			—		842,959			—			842,959
Other property and equipment, net of accumulated depreciation and amortization	—			—		66,413			—			66,413
Net property and equipment	—			—		909,372			—			909,372
Investment in affiliate	356,913			58,063		—			(414,976		)	—
Goodwill	—			—		17,328			—			17,328
Other assets	—			—		11,175			—			11,175
	$	357,366		$	58,567	$	991,848		$	(415,480	)	$	992,301
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	1,369		$	—	$	74,837		$	(504	)	$	75,702
Capital lease obligation	—			—		1,156			—			1,156
Deferred income taxes	—			—		4,946			—			4,946
Other current liabilities	—			—		2,686			—			2,686
Total current liabilities	1,369			—		83,625			(504		)	84,490
Long-term debt	—			—		331,000			—			331,000
Asset retirement obligations	—			—		15,412			—			15,412
Deferred income taxes	—			—		69,981			—			69,981
Capital lease obligation	—			—		5,738			—			5,738
Other liabilities	—			—		1,818			—			1,818
Total liabilities	1,369			—		507,574			(504		)	508,439
Stockholders’ equity:
Common stock	833			39,135		832,750			(871,885		)	833
Capital surplus	359,433			19,027		143,138			457,282			978,880
Retained earnings (accumulated deficit)	(4,674		)	405		(491,317		)	(373		)	(495,959		)
Accumulated other comprehensive income (loss)	405			—		(297		)	—			108
Total stockholders’ equity	355,997			58,567		484,274			(414,976		)	483,862
	$	357,366		$	58,567	$	991,848		$	(415,480	)	$	992,301

16

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Operations

(In thousands of Canadian dollars)

	Three Months Ended June 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			SubsidiaryIssuer			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	—		$	42,420		$	—	$	42,420
Interest and other	—			—			4			—		4
Total revenues	—			—			42,424			—		42,424
Costs, expenses and other:
Lease operating expenses	—			—			14,160			—		14,160
Production and property taxes	—			—			832			—		832
Transportation and processing	—			—			4,311			—		4,311
General and administrative	1,138			3			4,699			—		5,840
Depreciation, depletion, and amortization	—			—			31,882			—		31,882
Ceiling test write-down of oil and natural gas properties	—			—			128,870			—		128,870
Interest expense	—			—			8,242			—		8,242
Accretion of asset retirement obligations	—			—			341			—		341
Foreign currency exchange losses (gains)	53			(12		)	4,228			—		4,269
Losses (gains) on derivative instruments	—			—			(18,375		)	—		(18,375		)
Other, net	14			—			27			—		41
Total costs, expenses and other	1,205			(9		)	179,217			—		180,413
Earnings (loss) before income taxes	(1,205		)	9			(136,793		)	—		(137,989		)
Income tax expense (recovery)	—			—			(32,954		)	—		(32,954		)
Net earnings (loss)	$	(1,205	)	$	9		$	(103,839	)	$	—	$	(105,035	)

Condensed Consolidating Statement of Comprehensive Income

(In thousands of Canadian dollars)

	Three Months Ended June 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries		Subsidiary Issuer			Eliminations		Consolidated
Net earnings (loss)	$	(1,205	)	$	9	$	(103,839	)	$	—	$	(105,035	)
Other comprehensive income (loss)
Amortization of minimum postretirement benefits liability, net of tax	—			—		5			—		5
Comprehensive income (loss)	$	(1,205	)	$	9	$	(103,834	)	$	—	$	(105,030	)

17

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Operations

(In thousands of dollars)

	Three Months Ended June 30, 2011
	Parent Guarantor US$			Combined GuarantorSubsidiaries US$			Parent and Combined Guarantor Subsidiaries US$			Parent and Combined Guarantor Subsidiaries CDN$			SubsidiaryIssuer CDN$			Eliminations CDN$			Consolidated CDN$
Revenues:
Oil and natural gas	$	—		$	—		$	—		$	—		$	49,236		$	—		$	49,236
Interest and other	—			—			—			—			8			—			8
Total revenues	—			—			—			—			49,244			—			49,244
Costs, expenses and other:
Lease operating expenses	—			���			—			—			8,615			—			8,615
Production and property taxes	—			—			—			—			598			—			598
Transportation and processing	—			—			—			—			4,216			—			4,216
General and administrative	817			—			817			801			1,696			—			2,497
Depreciation, depletion, and amortization	—			—			—			—			19,919			—			19,919
Interest expense	—			—			—			—			2,237			—			2,237
Accretion of asset retirement obligations	—			—			—			—			267			—			267
Foreign currency exchange losses (gains)	—			—			—			—			2,564			—			2,564
Losses (gains) on derivative instruments	—			—			—			—			(4,948		)	—			(4,948		)
Other, net	474			(17		)	457			449			(8		)	17			458
Total costs, expenses and other	1,291			(17		)	1,274			1,250			35,156			17			36,423
Earnings (loss) before income taxes	(1,291		)	17			(1,274		)	(1,250		)	14,088			(17		)	12,821
Income tax expense (recovery)	—			—			—			—			7,455			—			7,455
Net earnings (loss)	$	(1,291	)	$	17		$	(1,274	)	$	(1,250	)	$	6,633		$	(17	)	$	5,366

Condensed Consolidating Statement of Comprehensive Income

(In thousands of dollars)

	Three Months Ended June 30, 2011
	Parent Guarantor US$			Combined GuarantorSubsidiaries US$		Parent and Combined Guarantor Subsidiaries US$			Parent and Combined Guarantor Subsidiaries CDN$			Subsidiary Issuer CDN$		Eliminations CDN$			Consolidated CDN$
Net earnings (loss)	$	(1,291	)	$	17	$	(1,274	)	$	(1,250	)	$	6,633	$	(17	)	$	5,366
Other comprehensive income (loss)
Foreign currency translation adjustments, net of tax	—			—		—			(14		)	—		—			(14		)
Comprehensive income (loss)	$	(1,291	)	$	17	$	(1,274	)	$	(1,264	)	$	6,633	$	(17	)	$	5,352

18

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Operations

(In thousands of Canadian dollars)

	Six Months Ended June 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			SubsidiaryIssuer			Eliminations		Consolidated
Revenues:
Oil and natural gas	$	—		$	—		$	86,749		$	—	$	86,749
Interest and other	—			—			10			—		10
Total revenues	—			—			86,759			—		86,759
Costs, expenses and other:
Lease operating expenses	—			—			28,609			—		28,609
Production and property taxes	—			—			1,685			—		1,685
Transportation and processing	—			—			8,464			—		8,464
General and administrative	1,765			3			8,178			—		9,946
Depreciation, depletion, and amortization	—			—			58,312			—		58,312
Ceiling test write-down of oil and natural gas properties	—			—			128,870			—		128,870
Interest expense	—			—			13,993			—		13,993
Accretion of asset retirement obligations	—			—			677			—		677
Foreign currency exchange losses (gains)	37			(1		)	3,937			—		3,973
Losses (gains) on derivative instruments	—			—			(18,268		)	—		(18,268		)
Other, net	50			—			2			—		52
Total costs, expenses and other	1,852			2			234,459			—		236,313
Earnings (loss) before income taxes	(1,852		)	(2		)	(147,700		)	—		(149,554		)
Income tax expense (recovery)	—			—			(35,011		)	—		(35,011		)
Net earnings (loss)	$	(1,852	)	$	(2	)	$	(112,689	)	$	—	$	(114,543	)

Condensed Consolidating Statement of Comprehensive Income

(In thousands of Canadian dollars)

	Six Months Ended June 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations		Consolidated
Net earnings (loss)	$	(1,852	)	$	(2	)	$	(112,689	)	$	—	$	(114,543	)
Other comprehensive income (loss)
Amortization of minimum postretirement benefits liability, net of tax	—			—			10			—		10
Comprehensive income (loss)	$	(1,852	)	$	(2	)	$	(112,679	)	$	—	$	(114,533	)

19

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Operations

(In thousands of dollars)

	Six Months Ended June 30, 2011
	Parent Guarantor US$			Combined GuarantorSubsidiaries US$			Parent and Combined Guarantor Subsidiaries US$			Parent and Combined Guarantor Subsidiaries CDN$			SubsidiaryIssuer CDN$			Eliminations CDN$			Consolidated CDN$
Revenues:
Oil and natural gas	$	—		$	—		$	—		$	—		$	84,798		$	—		$	84,798
Interest and other	—			—			—			—			20			—			20
Total revenues	—			—			—			—			84,818			—			84,818
Costs, expenses and other:
Lease operating expenses	—			—			—			—			16,664			—			16,664
Production and property taxes	—			—			—			—			1,189			—			1,189
Transportation and processing	—			—			—			—			7,766			—			7,766
General and administrative	1,874			—			1,874			1,843			4,044			—			5,887
Depreciation, depletion, and amortization	—			—			—			—			38,560			—			38,560
Interest expense	—			—			—			—			3,590			—			3,590
Accretion of asset retirement obligations	—			—			—			—			537			—			537
Foreign currency exchange losses (gains)	—			—			—			—			(4,970		)	—			(4,970		)
Losses (gains) on derivative instruments	—			—			—			—			(4,948		)	—			(4,948		)
Other, net	474			(17		)	457			449			37			17			503
Total costs, expenses and other	2,348			(17		)	2,331			2,292			62,469			17			64,778
Earnings (loss) before income taxes	(2,348		)	17			(2,331		)	(2,292		)	22,349			(17		)	20,040
Income tax expense (recovery)	—			—			—			—			9,383			—			9,383
Net earnings (loss)	$	(2,348	)	$	17		$	(2,331	)	$	(2,292	)	$	12,966		$	(17	)	$	10,657

Condensed Consolidating Statement of Comprehensive Income

(In thousands of dollars)

	Six Months Ended June 30, 2011
	Parent Guarantor US$			Combined GuarantorSubsidiaries US$		Parent and Combined Guarantor Subsidiaries US$			Parent and Combined Guarantor Subsidiaries CDN$			Subsidiary Issuer CDN$		Eliminations CDN$			Consolidated CDN$
Net earnings (loss)	$	(2,348	)	$	17	$	(2,331	)	$	(2,292	)	$	12,966	$	(17	)	$	10,657
Other comprehensive income (loss)
Foreign currency translation adjustments, net of tax	—			—		—			28			—		—			28
Comprehensive income (loss)	$	(2,348	)	$	17	$	(2,331	)	$	(2,264	)	$	12,966	$	(17	)	$	10,685

20

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Cash Flows

(In thousands of Canadian dollars)

	Three Months Ended June 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			SubsidiaryIssuer			Eliminations		Consolidated
Operating activities:
Net earnings (loss)	$	(1,205	)	$	9		$	(103,839	)	$	—	$	(105,035	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	—			—			31,882			—		31,882
Amortization of deferred costs	—			—			621			—		621
Ceiling test write-down of oil and natural gas properties	—			—			128,870			—		128,870
Accretion of asset retirement obligations	—			—			341			—		341
Deferred income tax expense (recovery)	—			—			(32,954		)	—		(32,954		)
Unrealized foreign currency exchange losses (gains)	—			—			4,228			—		4,228
Unrealized losses (gains) on derivative instruments	—			—			(9,540		)	—		(9,540		)
Stock-based compensation	218			—			783			—		1,001
Other, net	1			—			(739		)	—		(738		)
Changes in operating assets and liabilities:
Accounts receivable	(30		)	—			4,207			—		4,177
Prepaid expenses and other current assets	(321		)	—			1,817			—		1,496
Accounts payable and accrued liabilities	27			—			(8,223		)	—		(8,196		)
Accrued interest and other current liabilities	—			—			4,541			—		4,541
Net cash provided by (used in) operating activities	(1,310		)	9			21,995			—		20,694
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			(56,567		)	—		(56,567		)
Other fixed assets	—			—			(737		)	—		(737		)
Proceeds from divestiture of assets	—			—			280			—		280
Net cash used in investing activities	—			—			(57,024		)	—		(57,024		)
Financing activities:
Debt issuance costs	—			—			(70		)	—		(70		)
Proceeds from bank borrowings	—			—			681,000			—		681,000
Repayments of bank borrowings	—			—			(639,000		)	—		(639,000		)
Change in intercompany balances	1,022			(9		)	(1,013		)	—		—
Change in bank overdrafts	57			—			(5,068		)	—		(5,011		)
Capital lease payments	—			—			(454		)	—		(454		)
Net cash provided by (used in) financing activities	1,079			(9		)	35,395			—		36,465
Net increase (decrease) in cash	(231		)	—			366			—		135
Cash at beginning of period	266			—			479			—		745
Cash at end of period	$	35		$	—		$	845		$	—	$	880

21

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Cash Flows

(In thousands of dollars)

	Three Months Ended June 30, 2011
	Parent Guarantor US$			Combined GuarantorSubsidiaries US$			Parent and Combined Guarantor Subsidiaries US$			Parent and Combined Guarantor Subsidiaries CDN$			SubsidiaryIssuer CDN$			Eliminations CDN$			Consolidated CDN$
Operating activities:
Net earnings (loss)	$	(1,291	)	$	17		$	(1,274	)	$	(1,250	)	$	6,633		$	(17	)	$	5,366
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	—			—			—			—			19,919			—			19,919
Amortization of deferred costs	—			—			—			—			349			—			349
Accretion of asset retirement obligations	—			—			—			—			267			—			267
Deferred income tax expense (recovery)	—			—			—			—			7,455			—			7,455
Unrealized foreign currency exchange losses (gains)	—			—			—			—			2,564			—			2,564
Unrealized losses (gains) on derivative instruments	—			—			—			—			(4,948		)	—			(4,948		)
Stock-based compensation	19			—			19			19			—			—			19
Other, net	—			—			—			—			29			—			29
Changes in operating assets and liabilities:
Accounts receivable	—			—			—			—			(1,085		)	—			(1,085		)
Prepaid expenses and other current assets	3,093			—			3,093			2,993			(109		)	—			2,884
Accounts payable and accrued liabilities	403			—			403			390			(4,535		)	—			(4,145		)
Accrued interest and other current liabilities	14			—			14			13			(24,470		)	—			(24,457		)
Net cash provided by (used in) operating activities	2,238			17			2,255			2,165			2,069			(17		)	4,217
Investing activities:
Investment in subsidiaries	(145,000		)	19,488			(125,512		)	(121,928		)	—			121,928			—
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			—			—			(139,566		)	—			(139,566		)
Other fixed assets	—			—			—			—			(1,062		)	—			(1,062		)
Proceeds from divestiture of assets	—			—			—			—			62			—			62
Net cash provided by (used in) investing activities	(145,000		)	19,488			(125,512		)	(121,928		)	(140,566		)	121,928			(140,566		)
Financing activities:
Debt issuance costs	—			—			—			—			(4,078		)	—			(4,078		)
Proceeds from bank borrowings	—			—			—			—			553,000			—			553,000
Repayments of bank borrowings	—			—			—			—			(282,000		)	—			(282,000		)
Proceeds from Forest	2,748			—			2,748			2,659			70,174			—			72,833
Repayments to Forest	(6,742		)	—			(6,742		)	(6,524		)	(359,970		)	—			(366,494		)
Cash distribution to Forest	(29,219		)	—			(29,219		)	(28,711		)	—			—			(28,711		)
Change in intercompany balances	29			(19,488		)	(19,459		)	(18,830		)	(28		)	18,858			—
Intercompany dividend.	—			(17		)	(17		)	(17		)	—			17			—
Capital contribution	—			—			—			—			140,859			(140,859		)	—
Proceeds from issuance of common stock, net of offering costs	178,502			—			178,502			173,415			—			—			173,415
Change in bank overdrafts	—			—			—			—			13,130			—			13,130
Proceeds from sale-leaseback	—			—			—			—			7,450			—			7,450
Other, net	—			—			—			—			17			—			17
Net cash provided by (used in) financing activities	145,318			(19,505		)	125,813			121,992			138,554			(121,984		)	138,562
Effect of exchange rate changes on cash	—			—			—			236			—			73			309
Net increase in cash	2,556			—			2,556			2,465			57			—			2,522
Cash at beginning of period	—			—			—			—			2,310			—			2,310
Cash at end of period	$	2,556		$	—		$	2,556		2,465			$	2,367		$	—		$	4,832

22

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Cash Flows

(In thousands of Canadian dollars)

	Six Months Ended June 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			SubsidiaryIssuer			Eliminations		Consolidated
Operating activities:
Net earnings (loss)	$	(1,852	)	$	(2	)	$	(112,689	)	$	—	$	(114,543	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	—			—			58,312			—		58,312
Amortization of deferred costs	—			—			1,102			—		1,102
Ceiling test write-down of oil and natural gas properties	—			—			128,870			—		128,870
Accretion of asset retirement obligations	—			—			677			—		677
Deferred income tax expense (recovery)	—			—			(35,011		)	—		(35,011		)
Unrealized foreign currency exchange losses (gains)	—			—			3,932			—		3,932
Unrealized losses (gains) on derivative instruments	—			—			(4,371		)	—		(4,371		)
Stock-based compensation	380			—			1,340			—		1,720
Other, net	1			—			(718		)	—		(717		)
Changes in operating assets and liabilities:
Accounts receivable	(30		)	—			10,381			—		10,351
Prepaid expenses and other current assets	(320		)	—			1,508			—		1,188
Accounts payable and accrued liabilities	(387		)	—			(21,365		)	—		(21,752		)
Accrued interest and other current liabilities	—			—			8,150			—		8,150
Net cash provided by (used in) operating activities	(2,208		)	(2		)	40,118			—		37,908
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			(130,255		)	—		(130,255		)
Other fixed assets	—			—			(1,649		)	—		(1,649		)
Proceeds from divestiture of assets	—			—			280			—		280
Net cash used in investing activities	—			—			(131,624		)	—		(131,624		)
Financing activities:
Net proceeds from issuance of long-term debt	—			—			192,052			—		192,052
Debt issuance costs	—			—			(1,295		)	—		(1,295		)
Proceeds from bank borrowings	—			—			1,466,000			—		1,466,000
Repayments of bank borrowings	—			—			(1,568,000		)	—		(1,568,000		)
Change in intercompany balances	1,889			2			(1,891		)	—		—
Change in bank overdrafts	81			—			6,220			—		6,301
Capital lease payments	—			—			(738		)	—		(738		)
Net cash provided by financing activities	1,970			2			92,348			—		94,320
Net increase (decrease) in cash	(238		)	—			842			—		604
Cash at beginning of period	273			—			3			—		276
Cash at end of period	$	35		$	—		$	845		$	—	$	880

23

(14) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Cash Flows

(In thousands of dollars)

	Six Months Ended June 30, 2011
	Parent Guarantor US$			Combined GuarantorSubsidiaries US$			Parent and Combined Guarantor Subsidiaries US$			Parent and Combined Guarantor Subsidiaries CDN$			SubsidiaryIssuer CDN$			Eliminations CDN$			Consolidated CDN$
Operating activities:
Net earnings (loss)	$	(2,348	)	$	17		$	(2,331	)	$	(2,292	)	$	12,966		$	(17	)	$	10,657
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	—			—			—			—			38,560			—			38,560
Amortization of deferred costs	—			—			—			—			434			—			434
Accretion of asset retirement obligations	—			—			—			—			537			—			537
Deferred income tax expense (recovery)	—			—			—			—			9,383			—			9,383
Unrealized foreign currency exchange losses (gains)	—			—			—			—			(4,970		)	—			(4,970		)
Unrealized losses (gains) on derivative instruments	—			—			—			—			(4,948		)	—			(4,948		)
Stock-based compensation	19			—			19			19			—			—			19
Other, net	—			—			—			—			47			—			47
Changes in operating assets and liabilities:
Accounts receivable	—			—			—			—			4,285			—			4,285
Prepaid expenses and other current assets	1,521			—			1,521			1,443			1,233			—			2,676
Accounts payable and accrued liabilities	403			—			403			390			(4,968		)	—			(4,578		)
Accrued interest and other current liabilities	14			—			14			13			(23,846		)	—			(23,833		)
Net cash provided by (used in) operating activities	(391		)	17			(374		)	(427		)	28,713			(17		)	28,269
Investing activities:
Investment in subsidiaries	(145,000		)	19,488			(125,512		)	(121,928		)	—			121,928			—
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			—			—			(187,730		)	—			(187,730		)
Other fixed assets	—			—			—			—			(9,899		)	—			(9,899		)
Proceeds from divestiture of assets	—			—			—			—			468			—			468
Net cash provided by (used in) investing activities	(145,000		)	19,488			(125,512		)	(121,928		)	(197,161		)	121,928			(197,161		)
Financing activities:
Debt issuance costs	—			—			—			—			(4,078		)	—			(4,078		)
Proceeds from bank borrowings	—			—			—			—			589,000			—			589,000
Repayments of bank borrowings	—			—			—			—			(318,000		)	—			(318,000		)
Proceeds from Forest	5,377			—			5,377			5,251			103,426			—			108,677
Repayments to Forest	(6,742		)	—			(6,742		)	(6,524		)	(359,970		)	—			(366,494		)
Cash distribution to Forest	(29,219		)	—			(29,219		)	(28,711		)	—			—			(28,711		)
Change in intercompany balances	29			(19,488		)	(19,459		)	(18,830		)	(28		)	18,858			—
Intercompany dividend	—			(17		)	(17		)	(17		)	—			17			—
Intercompany capital contribution	—			—			—			—			140,859			(140,859		)	—
Proceeds from issuance of common stock, net of offering costs	178,502			—			178,502			173,415			—			—			173,415
Change in bank overdrafts	—			—			—			—			11,576			—			11,576
Proceeds from sale-leaseback	—			—			—			—			7,450			—			7,450
Other, net	—			—			—			—			7			—			7
Net cash provided by (used in) financing activities	147,947			(19,505		)	128,442			124,584			170,242			(121,984		)	172,842
Effect of exchange rate changes on cash	—			—			—			236			—			73			309
Net increase in cash	2,556			—			2,556			2,465			1,794			—			4,259
Cash at beginning of period	—			—			—			—			573			—			573
Cash at end of period	$	2,556		$	—		$	2,556		2,465			$	2,367		$	—		$	4,832

24

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”) contained in our 2011 Annual Report, as well as the condensed consolidated financial statements and the related notes included in this Quarterly Report.  All expectations, forecasts, assumptions and beliefs about our future financial results, condition, operations, strategic plans and performance are forward-looking statements, as described in more detail under “Cautionary Note Regarding Forward-Looking Statements” in this MD&A. Our actual results may differ materially because of a number of risks and uncertainties. See Part I, Item 1A, “Risk Factors” in our 2011 Annual Report and Part II, “Item 1A. Risk Factors” in this Quarterly Report for additional information regarding known material risks.

In this Quarterly Report, unless otherwise indicated or the context otherwise requires, references to “we,” “us,” “our” or “Lone Pine” when used in reference to periods prior to June 1, 2011 refer to Lone Pine Resources Canada Ltd. and its consolidated subsidiary, and when used in reference to periods after June 1, 2011, refer to Lone Pine Resources Inc., a Delaware corporation, and its consolidated subsidiaries, including Lone Pine Resources Canada Ltd. Unless the context otherwise requires, references in this Quarterly Report to “LPR Canada” or “our predecessor” refer to Lone Pine Resources Canada Ltd., formerly Canadian Forest Oil Ltd., an Alberta corporation and a wholly-owned subsidiary of Lone Pine Resources Inc., which was the predecessor of Lone Pine Resources Inc., and its consolidated subsidiary.

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

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 initial public offering (“IPO”) on June 1, 2011, we were a wholly-owned subsidiary of Forest Oil Corporation (“Forest”). 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 billion cubic feet equivalent (“Bcfe”) as of December 31, 2011, of which approximately 26% was oil and natural gas liquids (“NGLs”) and 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 condensed consolidated financial statements as if they had been historically reported in Canadian dollars, consistent with the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“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 million British thermal units per day (“MMBtu/d”) of natural gas under a long-term sales contract expiring in 2014.  See “—Change in Functional and Reporting Currency” in this MD&A and note 2 to our financial statements for more information about our change in functional and reporting currency.

25

Second Quarter 2012 Summary

Our financial and operating performance for the second quarter of 2012 included the following highlights:

·Average daily net sales volumes for the second quarter of 2012 were 89.0 million cubic feet equivalent per day (“MMcfe/d”) with crude oil and NGLs net sales volumes weighting increasing to 30%;

·Average daily net liquids sales volumes for the second quarter of 2012 increased 45% to 4,440 barrels per day (“bbls/d”) from the corresponding period in 2011, primarily due to our strategy to focus on light oil development;

·Total revenue plus realized hedging gains was $51.3 million, an increase of 4% from the first quarter of 2012;

·Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”) was $27.1 million, a sequential increase of 2% from the first quarter of 2012;

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

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

In the second quarter of 2012, we continued with our successful strategy of focusing on the development of our crude oil properties in the Evi area. We recognized over $31.2 million of crude oil revenue and our average net liquids weighting in the second quarter of 2012 increased to 30% from 19% in the corresponding period in 2011.

Outlook for the Second Half of 2012

Natural gas prices remain near 10 year lows and our average realized natural gas sales price declined by 50% in the second quarter of 2012 compared to the corresponding 2011 period. Similarly, crude oil prices have been trending lower over the last few months which, when combined with widening differentials, has resulted in our average realized crude oil sales price declining by 10% in the second quarter of 2012 compared to the corresponding 2011 period. These declines in commodity prices have negatively impacted our cash flow, and resulted in the ceiling test write-down of our oil and natural gas properties in the second quarter of 2012.

In response to these conditions, we have reduced our full-year capital budget for 2012 from $200 million to $220 million as previously announced on January 9, 2012, to approximately $160 million to $175 million, or approximately $50 million to $65 million for the second half of 2012. We believe that a lower capital expenditure program for the second half of 2012 is the prudent course of action given current commodity price volatility.  We intend to continue developing our crude oil properties in the Evi area and plan to drill up to 35 gross (31.7 net) wells in 2012. Activity for the second half of 2012 will be focused on infield drilling in the central sections of Evi where existing infrastructure allows for the flowlining of wells to our jointly owned central battery, which we expect will result in lower production expenses. We have downspacing approval in place to drill up to 16 wells per section in this area of Evi and are currently drilling an infill pilot to 10 wells per section.

As of August 9, 2012, we had $240.0 million outstanding under our bank credit facility at a weighted average interest rate of 3.6455%, remaining borrowing capacity of $133.4 million (after deducting $1.6 million of outstanding letters of credit) and borrowing base of $375 million. The next scheduled redetermination of the borrowing base is expected to occur 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.  Adjusting our capital spending rate for the remainder of 2012 is the first step in improving our financial strength and flexibility. We are also considering methods of debt reduction, including the divestiture of non-core assets and other potential transactions to accelerate the value of our assets, such as farm-ins and joint ventures. However, no assurance can be made regarding our ability to identify or complete any such potential transactions.

26

Results of Operations—Three and Six Months Ended June 30, 2012 and 2011

The following table sets forth selected financial results for the three and six month periods ended June 30, 2012 and 2011.

	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
	(In thousands)
Oil and natural gas revenues	$	42,420		$	49,236	$	86,749		$	84,798
Net earnings (loss)	(105,035		)	5,366		(114,543		)	10,657
Adjusted EBITDA(1)	27,076			32,879		53,620			52,828
Adjusted Discretionary Cash Flow(1)	18,676			31,020		39,971			49,719

(1)Adjusted EBITDA and Adjusted Discretionary Cash Flow are non-GAAP performance measures. See “—Reconciliation of Non-GAAP Measures” in this MD&A for a reconciliation of net earnings (loss) to Adjusted EBITDA and net cash provided by operating activities to Adjusted Discretionary Cash Flow. Non-GAAP measures are reconciled to the most directly comparable financial measures calculated and presented in accordance with U.S. generally accepted accounting principles (“GAAP”).

In the second quarter of 2012, we recognized a net loss of $105.0 million compared with net earnings of $5.4 million in the second quarter of 2011. In the first six months of 2012, we recognized a net loss of $114.5 million compared with net earnings of $10.7 million in the first six months of 2011. The net losses in the three and six month periods ended June 30, 2012 are almost entirely due to the $128.9 million ceiling test write-down ($96.8 million after tax) recognized in the second quarter of 2012, which was primarily related to the decline in the 12 month average trailing natural gas price.

Adjusted EBITDA decreased $5.8 million in the second quarter of 2012 compared to the second quarter of 2011, primarily due to lower natural gas revenues combined with higher production and general and administrative expenses, partially offset by an increase in realized gains on derivative instruments and higher crude oil revenues.

Adjusted EBITDA increased $0.8 million in the first six months of 2012 compared to the first six months of 2011. The increase was primarily due to higher crude oil revenues as a result of increased volumes and realized gains on derivative instruments, partially offset by lower natural gas revenues as well as higher production and general and administrative expenses.

Adjusted Discretionary Cash Flow decreased $12.3 million and $9.7 million in the three and six months of 2012, respectively, compared to the same periods in 2011. The decreases in Adjusted Discretionary Cash Flow were primarily due to higher production and interest expenses, partially offset by an increase in realized gains on derivative instruments. In the second quarter of 2012, compared to the second quarter of 2011, a decline in revenues that was primarily due to lower natural gas prices also contributed to the decrease.

27

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

Oil and Natural Gas Volumes and Revenues

Our sales volumes, revenues and average prices by product for the three and six month periods ended June 30, 2012 and 2011 are set forth in the tables below.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Working interest sales volumes(1):
Oil (Mbbls)	428			297			802			476
NGLs (Mbbls)	25			26			50			54
Natural gas (MMcf)	5,692			7,368			11,926			14,169
Total equivalent (MMcfe)	8,410			9,306			17,038			17,349
Total equivalent daily sales volumes (MMcfe/d)	92.4			102.3			93.6			95.9
Total equivalent daily sales volumes (boe/d)	15,403			17,044			15,603			15,975
Average liquids weighting	32		%	21		%	30		%	18		%
Net sales volumes(2):
Oil (Mbbls)	387			259			726			413
NGLs (Mbbls)	17			19			35			39
Natural gas (MMcf)	5,677			6,938			11,836			13,424
Total equivalent (MMcfe)	8,101			8,606			16,402			16,136
Total equivalent daily sales volumes (MMcfe/d)	89.0			94.6			90.1			89.1
Total equivalent daily sales volumes (boe/d)	14,837			15,762			15,020			14,858
Average liquids weighting	30		%	19		%	28		%	17		%
Revenues (in thousands):
Oil	$	31,221		$	23,096		$	61,007		$	35,288
NGLs	1,027			1,210			2,115			2,377
Natural gas	10,172			24,930			23,627			47,133
Total oil and natural gas revenues	$	42,420		$	49,236		$	86,749		$	84,798

(1) “Working interest sales volumes” represents our working interest share of sales volumes before the impact of royalties.

(2) “Net sales volumes” represents our working interest sales volumes less the volumes attributable to royalties.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Average prices per unit:
NYMEX WTI (US$ per bbl)	93.35		102.34		98.15		98.50
NYMEX WTI ($ per bbl)	94.33		99.06		98.71		96.21
Edmonton Par ($ per bbl)	84.05		102.76		88.80		95.09
Average oil sales price ($ per bbl)	80.67		89.17		84.03		85.44
Differential to NYMEX WTI ($ per bbl)	13.66		9.89		14.68		10.77
Differential to Edmonton Par ($ per bbl)	3.38		13.59		4.77		9.65
Average NGLs sales price ($ per bbl)	60.41		63.68		60.43		60.95
Percentage of NYMEX WTI	64	%	64	%	61	%	63	%
NYMEX Henry Hub (US$ per MMBtu)	2.22		4.31		2.48		4.21
NYMEX Henry Hub ($ per MMBtu)	2.24		4.18		2.49		4.11
AECO ($ per MMBtu)	1.84		3.74		2.18		3.76
Average natural gas sales price ($ per MMBtu)	1.79		3.59		2.00		3.51
Differential to NYMEX Henry Hub ($ per MMBtu)	0.45		0.59		0.49		0.60
Differential to AECO ($ per MMBtu)	0.05		0.15		0.18		0.25
Total equivalent realized sales price ($ per Mcfe)	5.24		5.72		5.29		5.26
Total equivalent realized sales price ($ per boe)	31.42		34.33		31.73		31.53

Oil and natural gas revenues were $42.4 million in the second quarter of 2012, a 14% decrease as compared to $49.2 million in the second quarter of 2011, primarily due to lower natural gas prices and production, partially offset by higher crude oil

28

revenues. Oil and natural gas revenues were $86.7 million in the first six months of 2012, a 2% increase as compared to $84.8 million in the first six months of 2011 primarily due to higher crude oil revenues as a result of higher volumes, partially offset by lower natural gas revenues, which was largely due to lower prices.

Crude oil net sales volumes increased 49% in the second quarter of 2012 compared to the second quarter of 2011, and increased 76% in the six months ended June 30, 2012 compared to the six months ended June 30, 2011. The increases were primarily due to the advancement of our light oil development at Evi. Consistent with our strategy of higher liquids production, we also increased our average net liquids weighting from 19% in the second quarter of 2011 to 30% in the second quarter of 2012, and from 17% in the six months ended June 30, 2011 to 28% in the six months ended June 30, 2012. Our natural gas production decreased by 18% in the second quarter of 2012 and 12% in the six months ended June 30, 2012 when compared to the same periods in 2011, as we have temporarily suspended new investment in natural gas drilling activities in response to the low natural gas prices. We expect this decrease in natural gas production to continue while we focus our capital program on light oil development. In addition, our natural gas volumes will be negatively impacted in the near term due to unscheduled downtime at a third-party natural gas processing plant located in Southern Alberta, which went offline in the last week of June 2012. In the second quarter of 2012, we recognized approximately 2.6 MMcf/day (net) of natural gas production through this plant. Operations at the plant are not expected to resume until October 2012 at the earliest.

The average realized sales price in the second quarter of 2012 decreased 8% to $5.24 from $5.72 per thousand cubic feet equivalent (“Mcfe”) in the second quarter of 2011, and increased 1% to $5.29 per Mcfe in the six months ended June 30, 2012 from $5.26 per Mcfe in the six months ended June 30, 2011. The benchmark Edmonton Par crude oil price was 18% and 7% lower in the three and six months ended June 30, 2012, respectively, compared to the corresponding periods in 2011, which caused a decrease in the average realized crude oil sales price of 10% and 2% in the three and six months ended June 30, 2012, respectively, compared to the corresponding periods in 2011. However, the average differential to Edmonton Par narrowed by $10.21 per barrel of oil (“bbl”) in the second quarter of 2012 and $4.88 per bbl in the six months ended June 30, 2012 compared to the same periods in 2011, primarily due to a higher proportion of our crude oil production resulting from light oil properties. Benchmark natural gas prices were significantly lower in the second quarter of 2012 and the six months ended June 30, 2012 compared to the same periods in 2011, which reduced the average realized natural gas sales price by 50% in the second quarter of 2012 and 43% in the six months ended June 30, 2012, compared to the corresponding 2011 periods.

Oil and Gas Production Expense

The following table sets forth the detail of production expense for the three and six month periods ended June 30, 2012 and 2011.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands, except per Mcfe data)
Production expense:
Lease operating expenses	$	14,160	$	8,615	$	28,609	$	16,664
Production and property taxes	832		598		1,685		1,189
Transportation and processing	4,311		4,216		8,464		7,766
Total	$	19,303	$	13,429	$	38,758	$	25,619
Production expense per Mcfe:
Lease operating expenses	$	1.75	$	1.00	$	1.74	$	1.03
Production and property taxes	0.10		0.07		0.10		0.07
Transportation and processing	0.53		0.49		0.52		0.48
Total	$	2.38	$	1.56	$	2.36	$	1.58

Lease Operating Expenses

Lease operating expenses in the second quarter of 2012 were $14.2 million, or $1.75 per Mcfe, compared to $8.6 million, or $1.00 per Mcfe, in the second quarter of 2011. The $5.6 million increase in lease operating expenses was primarily due to an increase of $7.2 million at Evi, partially offset by a decrease at other properties. The increase at Evi was related to our growing crude oil volumes in the area, primarily due to the higher operating costs associated with the wells that were drilled in 2012. While we have installed infrastructure that allows us to transport by pipeline the majority of our oil production from the Evi area, which has minimized the cost of trucking and the downtime associated with weather-dependent access to some locations, the

29

location of these new wells is farther away from crude oil processing facilities and therefore we incurred higher costs for the trucking of emulsion. Trucking costs were also higher because of operational issues at a jointly owned oil battery in the Evi area that is operated by a third party, including issues with allocation of crude oil volumes, constrained water handling capability, longer wait times for our trucks and higher operating costs. Therefore, we elected to transport a portion of our emulsion to other batteries in the area in order to mitigate our exposure to these issues, which are in the process of being resolved. We also incurred higher trucking costs because transportation and lease road repair is more costly during spring break up. In the second quarter of 2012, the cost of workovers, including cleanouts, flushbys, pump changes and coil rig cleanouts was approximately $2.9 million, which was an increase from approximately $1.8 million in the second quarter of 2011, primarily because of our strategy to increase liquids production by drilling additional crude oil wells. We also incurred higher costs for the rental of some equipment at our single well batteries at our new Evi wells in lieu of incurring capital expenditures to tie-in these wells, as well as higher maintenance costs.

Lease operating expense in the first six months of 2012 was $28.6 million, or $1.74 per Mcfe, compared to $16.7 million, or $1.03 per Mcfe, in the first six months of 2011. For the six months ended June 30, 2012 compared to the same period in 2011, the increase in lease operating expenses of $11.9 million was primarily attributable to an increase of $13.7 million at Evi, partially offset by a decrease at other properties. The increases were primarily due to higher costs associated with the production of crude oil, including a higher number of workovers related to sand cleanouts, primarily in the first quarter of 2012 at Evi. In the six months ended June 30, 2012, we incurred approximately $7.4 million of workovers, which was an increase from approximately $2.9 million in the six months ended June 30, 2011. Similar to the second quarter of 2012, we also incurred higher costs for trucking, rental of some equipment at our single well batteries at our new Evi wells and higher maintenance costs.

Production and Property Taxes

Production and property taxes, which primarily consist of property taxes (ad valorem taxes) assessed by local governments, were relatively consistent during the periods presented, ranging from $0.07 to $0.10 per Mcfe.

Transportation and Processing

Transportation and processing costs primarily consist of natural gas transportation costs and field-level natural gas gathering and processing costs. Transportation and processing costs in the second quarter of 2012 were $4.3 million, or $0.53 per Mcfe, compared to $4.2 million, or $0.49 per Mcfe, in the second quarter of 2011. Transportation and processing costs in the first six months of 2012 were $8.5 million, or $0.52 per Mcfe, compared to $7.8 million, or $0.48 per Mcfe, in the first six months of 2011. The increase in per unit costs for both the second quarter of 2012 and the six months ended June 30, 2012, compared to the same periods in 2011, was primarily due to lower natural gas volumes, higher per unit rates for the Narraway/Ojay properties that were acquired in April 2011, as well as additional processing costs related to our crude oil production at Evi.

General and Administrative Expense

The following table summarizes the components of general and administrative expense during the three and six months ended June 30, 2012 and 2011.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands, except per Mcfe data)
Stock-based compensation costs	$	779		$	(597	)	$	2,387		$	154
Other general and administrative costs	7,137			3,263			11,115			7,201
General and administrative costs capitalized (including stock-based compensation)	(2,076		)	(169		)	(3,556		)	(1,468		)
General and administrative expense	$	5,840		$	2,497		$	9,946		$	5,887
General and administrative expense per Mcfe	$	0.72		$	0.29		$	0.61		$	0.36

Stock-Based Compensation Costs

Stock-based compensation costs for the periods presented primarily represent the amortization of the fair value of units awarded as part of our long-term incentive plans. This amortization includes units issued in 2011, which are primarily accounted for as liability-settled units, the fair value of which is adjusted quarterly based on our share price. The amortization also includes the fair value of units issued in 2012, all of which are accounted for as equity-settled units, the fair value of which was determined

30

and fixed at their grant date. In the three and six months ended June 30, 2011, stock-based compensation costs primarily represented the amortization of the fair value of units awarded by Forest as part of its equity incentive plans.

Other General and Administrative Costs

Other general and administrative costs primarily comprise salaries and related benefit costs for our employees as well as professional fees and office lease costs. Our staffing and overhead costs increased in the three and six months ended June 30, 2012 mainly as a result of Lone Pine incurring costs for corporate expenditures that were historically provided to us by Forest as well as increased salaries and other benefits, including stock-based compensation, and higher professional fees relating to our status as a stand-alone public company. These increases were partially offset by incremental costs that were incurred in 2011 in preparation for the IPO and spin-off from Forest, and an increase in costs capitalized for exploration and development activities.

General and Administrative Costs Capitalized

Under the full cost method of accounting, general and administrative costs directly related to exploration and development activities are capitalized. The percentage of general and administrative costs capitalized in the three and six months ended June 30, 2012 was consistent at approximately 26%. However, for the three and six month periods ended June 30, 2011, the capitalization rates were lower at 6% and 20%, respectively, primarily due to a significant decrease in Forest’s stock price in the second quarter of 2011, which resulted in a credit to stock-based compensation rather than an expense that effectively lowered the capitalization rate.

Depreciation, Depletion and Amortization

The following table summarizes depreciation, depletion and amortization (“DD&A”) expense incurred during the three and six months ended June 30, 2012 and 2011.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands, except per Mcfe data)
DD&A	$	31,882	$	19,919	$	58,312	$	38,560
DD&A per Mcfe	$	3.94	$	2.31	$	3.56	$	2.39

The DD&A expense in the second quarter of 2012 was $31.9 million, or $3.94 per Mcfe, compared to $19.9 million, or $2.31 per Mcfe, in the second quarter of 2011. For the six months ended June 30, 2012, DD&A expense was $58.3 million, or $3.56 per Mcfe, compared to $38.6 million, or $2.39 per Mcfe, for the six months ended June 30, 2011. The increases were primarily due to our higher investment in the development of our oil assets, which are more capital-intensive than our natural gas properties. The increase in the second quarter of 2012 was also due to a significant decrease in proved undeveloped natural gas volumes pursuant to the ceiling test calculation mentioned below, partially offset by a corresponding decrease in future development costs.

31

Full Cost Method of Accounting

As required under the quarterly ceiling test calculation, at the end of the second quarter of 2012, we updated our internal estimates of proved oil and natural gas reserves, and the present value of future net revenue from those reserves using the 12 month average trailing prices for AECO and Edmonton Par, which are typically lower than the corresponding New York Mercantile Exchange (“NYMEX”) Henry Hub natural gas prices and West Texas Intermediate (“WTI”) crude oil prices. The table below summarizes these benchmark prices, which were also used in the ceiling test calculation at June 30, 2012.

	Natural Gas	Crude Oil
	AECO $/MMBtu	Edmonton Par $/bbl
June 30, 2012	2.77	92.90
March 31, 2012	3.33	98.78
December 31, 2011	3.77	96.98
June 30, 2011	3.95	90.67

As a result of the 17% decline in the 12 month average trailing natural gas price from $3.33 per MMBtu at March 31, 2012 to $2.77 per MMBtu at June 30, 2012, our internal estimate of proved undeveloped natural gas volumes decreased significantly at June 30, 2012. This decrease in proved undeveloped natural gas volumes was not related to the performance of any of our natural gas assets. The decrease in the 12 month average trailing crude oil price did not have a significant impact on our proved crude oil volumes.  This decrease in natural gas volumes reduced our internal estimate of the present value of future net revenue from proved reserves, which resulted in the recognition of a ceiling test write-down under the full cost method of accounting of $128.9 million before tax for the three and six months ended June 30, 2012.

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. See Part II, Item 1A,—“Risk Factors”—“Lower oil and gas prices and other factors have resulted, and in the future may result, in ceiling test write-downs and other impairments of our asset carrying values.” in our 2011 Annual Report. We did not record a ceiling test write-down in the first six months of 2011.

Accretion of Asset Retirement Obligations

The table below summarizes accretion expense for the asset retirement obligations (“ARO”) for the three and six months ended June 30, 2012 and 2011.

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands)
Accretion of ARO	$	341	$	267	$	677	$	537

Accretion of ARO is the expense recognized to increase the carrying amount of the liability associated with our ARO as a result of the passage of time. The accretion of ARO of $0.3 million in the second quarter of 2012 was consistent with the second quarter of 2011. For the six months ended June 30, 2012, accretion of ARO was $0.7 million compared to $0.5 million for the first six months ended June 30, 2011.

Interest Expense

The following table summarizes interest expense incurred during the three and six months ended June 30, 2012 and 2011.

	Three Months Ended June 30,					Six Months Ended June 30,
	2012		2011			2012		2011
	(In thousands)
Interest costs — Bank credit facility	$	2,636	$	2,497		$	5,572	$	4,109
Interest costs — Senior Notes	5,606		—			8,421		—
Interest costs capitalized	—		(260		)	—		(519		)
Interest expense	$	8,242	$	2,237		$	13,993	$	3,590

Interest expense of $8.2 million and $14.0 million in the three and six months ended June 30, 2012, respectively, was primarily associated with the interest cost on our Senior Notes and borrowings under our bank credit facility, as well as the amortization of debt issue costs. The average interest rate on our bank credit facility, which is floating based on market interest rates, was less than 4% for the three and six month periods ended June 30, 2012, while the interest rate on the Senior Notes is fixed at 10.375%.  Interest expense for the three and six month periods ended June 30, 2011 was primarily associated with a note payable to Forest.

The increase in interest costs for the three and six month periods ended June 30, 2012 compared to the same periods in 2011 was due to a higher interest rate on our borrowings, as well as a higher level of borrowings. For the three and six month periods ended June 30, 2011, we capitalized $0.3 million and $0.5 million, respectively, of interest related to our investment in unproved acreage in the Narraway/Ojay fields.

32

Losses (Gains) on Derivative Instruments

The table below sets forth unrealized and realized losses (gains) on derivatives recognized during the three and six months ended June 30, 2012 and 2011.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Unrealized losses (gains) on derivatives
Oil	$	(17,820	)	$	(738	)	$	(12,087	)	$	(738	)
Natural gas	8,280			(4,210		)	7,716			(4,210		)
Unrealized losses (gains) on derivatives	$	(9,540	)	$	(4,948	)	$	(4,371	)	$	(4,948	)
Realized losses (gains) on derivatives
Oil	$	(2,255	)	$	—		$	(1,957	)	$	—
Natural gas	(6,580		)	—			(11,940		)	—
Realized losses (gains) on derivatives	$	(8,835	)	$	—		$	(13,897	)	$	—

We enter into derivative instruments to manage our exposure to commodity price risk caused by fluctuations in commodity prices, which protects and provides certainty on a portion of our cash flows. We realized gains of $8.8 million and $13.9 million on these instruments in the three and six months ended June 30, 2012, primarily because the NYMEX Henry Hub natural gas price and WTI crude oil price were significantly lower than the fixed prices in our contracts. The unrealized gains on derivatives are due to the change in the net asset position of derivative instruments from $19.8 million at December 31, 2011 to $14.6 million at March 31, 2012 and $24.2 million at June 30, 2012.

Foreign Currency Exchange Losses (Gains)

In the second quarter of 2012 and the six month period ended June 30, 2012, we recorded foreign currency exchange losses of $4.3 million and $4.0 million, respectively. The losses primarily relate to the translation of the Senior Notes, since the Canadian dollar weakened in both the second quarter of 2012 as well as during the period between February 14, 2012, which was the date we issued the Senior Notes, and June 30, 2012.

In the second quarter of 2011, we recorded foreign currency exchange losses of $2.6 million and in the first six months of 2011 we recognized foreign currency exchange gains of $5.0 million related to the amounts due to Forest. Since the amounts due to Forest were denominated in U.S. dollars, the foreign currency exchange losses (gains) arose due to the effect of the fluctuation in the Canadian dollar on this loan during each of the respective periods.

Income Tax Expense (Recovery)

The table below sets forth our total income tax expense (recovery) and effective tax rates for the three and six month periods ended June 30, 2012 and 2011.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Current income tax	$	—		$	—		$	—		$	—
Deferred income tax expense (recovery)	(32,954		)	7,455			(35,011		)	9,383
Total income tax expense (recovery)	$	(32,954	)	$	7,455		$	(35,011	)	$	9,383
Effective tax rate	24		%	58		%	23		%	47		%

Our combined Canadian federal and provincial statutory tax rate was approximately 25% for the three and six months ended June 30, 2012 and 26.5% for the three and six months ended June 30, 2011. However, our effective income tax rates of 24% for the three months ended June 30, 2012 and 23% for the six months ended June 30, 2012 were lower than the Canadian statutory tax rate of 25%, primarily due to an increase in a valuation allowance (relating to deferred tax assets) that reduced our loss for income tax purposes, foreign exchange losses on the Senior Notes that are taxed at 50% of the statutory tax rate, as well as non-deductible stock-based compensation expense. Our effective income tax rates of 58% for the three months ended June 30, 2011 and 47% for the six months ended June 30, 2011 were higher than the Canadian statutory tax rate of 26.5% primarily due to an increase in a valuation allowance (relating to deferred tax assets) that increased our taxable income.

33

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. Following the completion of our IPO and the Distribution, we no longer borrow from Forest. As market conditions have permitted, we have also engaged in non-core asset divestitures and have also accessed the equity and debt capital markets.

Changes in the market prices for oil, natural gas and NGLs directly impact our level of cash provided by operating activities. During the year ended December 31, 2011, natural gas comprised approximately 79% of our production. As a result, our operations and cash flows have historically been more sensitive to fluctuations in the market price for natural gas than to fluctuations in the market price for oil. Since June 2011, we have entered into derivative instruments to manage our exposure to commodity price risk caused by fluctuations in commodity prices, which protect and provide certainty on a portion of our cash flows. As of August 9, 2012, we had entered into commodity swaps to hedge approximately 3,000 bbls/d of crude oil and 35,000 MMBtu/d of natural gas (total of 9.8 Bcfe) of our production for the remainder of 2012. We have also entered into commodity swaps for 2013 to hedge 2,500 bbls/d of crude oil as well as commodity collars for 30,000 MMBtu/d of natural gas (total of 16.4 Bcfe). This level of hedging will provide a measure of certainty of the cash flows that we expect to receive for a portion of our production. In the future, we may determine to increase or decrease our hedging positions. See Part I, “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk” in this Quarterly Report for more information on our derivative contracts.

As noted above, a primary source of liquidity is our bank credit facility. The borrowing base for the bank credit facility is subject to redetermination and to other automatic adjustments; see “—Bank Credit Facility” below for further details. 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. In May 2012, the borrowing base was reaffirmed at $375 million. The next scheduled redetermination of the borrowing base is expected to occur 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 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.  A significant reduction in our borrowing base, together with the covenants and other restrictions in our bank credit facility, may reduce our ability to finance future operations or capital needs or expand our business activities.  Outstanding borrowings in excess of the borrowing base must be repaid. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our bank credit facility, sell assets or issue debt or common stock. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in an event of default under the credit agreement governing our bank credit facility.

In the second quarter of 2012, borrowings under our bank credit facility increased to $229.0 million at June 30, 2012 from $187.0 million at March 31, 2012, primarily due to the reduction of accounts payable in the second quarter of 2012, together with planned capital expenditures. As of August 9, 2012, we had $240.0 million outstanding under our bank credit facility at a weighted average interest rate of 3.6455% and remaining borrowing capacity of $133.4 million (after deducting $1.6 million of outstanding letters of credit).

One of our most significant expenditures relates to our capital program, and in early 2012, we established a capital budget range for 2012 of approximately $200 million to $220 million. However, in light of continued low natural gas prices as well as more recent decreases in crude oil prices and widening differentials, we have reduced our full-year 2012 capital budget to approximately $160 million to $175 million. Our capital expenditures for the six month period ended June 30, 2012 were approximately $111 million, and therefore we expect the remaining approximately $50 million to $65 million of capital expenditures for 2012 to primarily focus on the infill drilling of our light oil properties at Evi. These capital expenditures are expected to be primarily funded through cash provided by operating activities, with the objective of minimizing additional borrowings under our bank credit facility over the remainder of 2012.

If our revenue and cash flows decrease in the future as a result of a further deterioration in domestic and global economic conditions, including a significant decline in commodity prices or a continuation of depressed commodity prices, or if we experience a significant reduction in our borrowing base under our bank credit facility, we may decide to further reduce our capital budget for 2012 and to adopt a reduced capital budget for 2013. 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. However, a further reduction in our capital expenditures could also result in a corresponding reduction in our cash flows, which could in turn result in a loss of petroleum and natural gas mineral tenure requiring drilling for retention.  The degree of any adverse impact on us would depend on the amount and timing of any further reduction. See Part II, “Item 1A. Risk Factors” in this Quarterly Report and Part I,

34

“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 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 million. Our ability to access the equity capital markets on economic terms in the future will be affected by general economic conditions, the domestic and global financial markets, our operational and financial performance, the value and performance of our equity securities, prevailing commodity prices and other macroeconomic factors outside of our control.

In February 2012, we completed an offering of Senior Notes for net proceeds of approximately $192 million. However, given our current overall debt position, we do not expect to utilize debt markets in the near term.

Adjusting our capital spending rate for the remainder of 2012 is the first step in improving our financial strength and flexibility. We are also considering methods of debt reduction, including the divestiture of non-core assets and potential transactions to accelerate the value of our assets, such as farm-ins and joint ventures. However, no assurance can be made regarding our ability to identify or complete any such potential transactions.

In connection with our IPO, we entered into a tax-sharing agreement with Forest under which, for a two year period following the Distribution, we will be restricted in our ability, among other things, to divest of assets outside the ordinary course of business, to issue or sell our common stock or other securities (including securities convertible into our common stock but excluding certain compensation arrangements) or to enter into any other corporate transaction that would cause us to undergo either a 50% or greater change in the ownership of our voting stock or a 50% or greater change in the ownership (measured by value) of all classes of our stock (in either case, taking into account shares issued in our IPO).  Therefore, until September 30, 2013, we may take certain actions otherwise subject to these restrictions only if Forest consents to the taking of such action or if we obtain, and provide to Forest, a private letter ruling from the Internal Revenue Service and/or an opinion from a law firm or accounting firm, in either case, acceptable to Forest in its sole discretion, to the effect that such action would not jeopardize the tax-free status of the Distribution.

Bank Credit Facility

On March 18, 2011, we entered into a $500 million credit facility among Lone Pine, as parent, LPR Canada, as borrower, and a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. Our bank credit facility became effective upon the closing of the IPO, and replaced the existing LPR Canada bank credit facility at such time. The credit facility will mature on March 18, 2016 and is secured by a portion of our assets. 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 Lone Pine’s oil and natural gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base will be redetermined semi-annually, and the available borrowing amount under 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.

We believe it is likely that the recent decline in oil and natural gas 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.  A significant reduction in our borrowing base, together with the covenants and other restrictions in our bank credit facility, may reduce our ability to finance future operations or capital needs or expand our business activities.  Outstanding borrowings in excess of the borrowing base must be repaid. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our bank credit facility, sell assets or issue debt or common stock. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in an event of default under the credit agreement governing our bank credit facility.

As of June 30, 2012, we had $229.0 million outstanding under our bank credit facility at a weighted average interest rate of 3.6162% and borrowing capacity of $144.4 million (after deducting $1.6 million of outstanding letters of credit). As of August 9, 2012, we had $240.0 million outstanding under our bank credit facility at a weighted average interest rate of 3.6455% and borrowing capacity of $133.4 million (after deducting $1.6 million of outstanding letters of credit).

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

35

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 Adjusted EBITDA for a trailing 12 month period to be greater than 4.0 to 1.0. As at June 30, 2012, this ratio was approximately 3.3 to 1.0. If oil and natural gas prices decline further, or remain depressed for an extended period, we believe it is possible that we could be in violation of this financial covenant in a future period.  If we were to fail to perform our obligations under these covenants or other covenants and obligations, it could cause an event of default and the bank credit facility could be terminated and amounts outstanding could be declared immediately due and payable by the lenders, subject to notice and cure periods in certain cases. Such events of default include non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, change of control and a failure of the liens securing the bank credit facility. In addition, bankruptcy and insolvency events with respect to Lone Pine will result in an automatic acceleration of the indebtedness under the bank credit facility. An acceleration of our indebtedness under the bank credit facility could in turn result in an event of default under an indenture for our Senior Notes (discussed below), which in turn could result in the acceleration of payment of the Senior Notes. For example, the indenture governing our Senior Notes includes as an event of default, among others, a default on indebtedness that results in the acceleration of indebtedness in an amount greater than US$20 million.

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

From time to time, 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.

10.375% Senior Notes due 2017

On February 14, 2012, LPR Canada issued US$200.0 million aggregate principal amount of 10.375% Senior Notes due 2017 (the “ Senior Notes”). Interest is payable on the Senior Notes semi-annually in arrears on each February 15 and August 15, 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 (together, the “Guarantors”). These guarantees are full and unconditional, and joint and several among the Guarantors. After the original issue discount of 1.423% and commissions of approximately $4.9 million, the issuance of the Senior Notes resulted in net proceeds to the Company of $192 million, which we used to partially repay borrowings outstanding under our bank credit facility.

The Senior Notes were issued pursuant to an indenture (the “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

36

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.

Working Capital Deficit

We had a working capital deficit of approximately $10.6 million at June 30, 2012, primarily due to a high level of accounts payable and accrued liabilities related to our capital program. However, our working capital deficit had decreased from $30.1 million at December 31, 2011 primarily due to a $35.9 million reduction in accounts payable and accrued liabilities.

Historical Cash Flow

Net cash provided by operating activities, net cash used in investing activities and net cash provided by financing activities for the three and six months ended June 30, 2012 and 2011 were as follows.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Net cash provided by operating activities	$	20,694		$	4,217		$	37,908		$	28,269
Net cash used in investing activities	(57,024		)	(140,566		)	(131,624		)	(197,161		)
Net cash provided by financing activities	36,465			138,562			94,320			172,842

The increase in net cash provided by operating activities in the three and six months ended June 30, 2012 compared to the same periods in 2011 was primarily due to a decrease in Adjusted Discretionary Cash Flow that was offset by a significant decrease in working capital items.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Exploration, development and acquisition costs	$	(56,567	)	$	(139,566	)	$	(130,255	)	$	(187,730	)
Other fixed assets	(737		)	(1,062		)	(1,649		)	(9,899		)
Proceeds from divestiture of assets	280			62			280			468
Net cash used in investing activities	$	(57,024	)	$	(140,566	)	$	(131,624	)	$	(197,161	)

The cash paid for exploration, development and acquisition costs as reflected in the statements of cash flows differs from the capital expenditures in the “Capital Expenditures” table below due to the timing of when the capital expenditures are incurred and when the actual cash payment is made. The decreases in net cash used in investing activities for the three and six months ended June 30, 2012 compared to the same periods in 2011 were primarily due to significantly lower capital expenditures. For the three months ended June 30, 2012 compared to the same period in 2011 the decrease in net cash used in investing activities was partially offset by a reduction in the non-cash accrual for capital expenditures. See “—Capital Expenditures” below for more information on our capital expenditures.

37

Net cash provided by financing activities was as follows.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Net proceeds from issuance of long-term debt	$	—		$	—		$	192,052		$	—
Debt issuance costs	(70		)	(4,078		)	(1,295		)	(4,078		)
Proceeds from bank borrowings	681,000			553,000			1,466,000			589,000
Repayments of bank borrowings	(639,000		)	(282,000		)	(1,568,000		)	(318,000		)
Proceeds from Forest Oil Corporation	—			72,833			—			108,677
Repayments to Forest Oil Corporation	—			(366,494		)	—			(366,494		)
Cash distribution to Forest Oil Corporation	—			(28,711		)	—			(28,711		)
Proceeds from issuance of common stock, net of offering costs	—			173,415			—			173,415
Change in bank overdrafts	(5,011		)	13,130			6,301			11,576
Proceeds from sale-leaseback	—			7,450			—			7,450
Capital lease payments	(454		)	—			(738		)	—
Other, net	—			17			—			7
Net cash provided by financing activities	$	36,465		$	138,562		$	94,320		$	172,842

The decrease in net cash provided by financing activities for the three and six months ended June 30, 2012  compared to the same periods in 2011 was primarily due to increases in the repayment of bank borrowings that were used to partially fund our capital program. For the six months ended June 30, 2012, net proceeds from the Senior Notes were used to partially repay our bank borrowings. Net cash provided by financing activities for the three and six month periods ended June 30, 2011 was primarily related to proceeds from bank borrowings as well as proceeds from our IPO, partially offset by net repayments to Forest.

Capital Expenditures

	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands)
Exploration and development	$	28,072	$	27,077	$	97,049	$	101,403
Acquisitions and leasehold costs	3,504		75,661		10,581		76,053
General and administrative costs capitalized	2,076		169		3,556		1,468
Interest capitalized	—		260		—		519
Total capital expenditures	$	33,652	$	103,167	$	111,186	$	179,443

For the three and six months ended June 30, 2012, our capital expenditures were lower than the same periods in 2011 and were primarily focused on light oil development in the Evi area of Alberta. The table below summarizes our drilling activity for the first and second quarters of 2012.

Number of Wells (Net)	Three Months Ended June 30, 2012	Three Months Ended March 31, 2012
Drilled	3.12	19.52
Completed	9.12	11.52
Tied-in	11.52	16.12

As part of our New Ventures activity in Alberta, we acquired $10.6 million of undeveloped land in the first six months of 2012, which we expect will support further light oil exploration and development. In the first three and six months of 2011, our capital expenditures were primarily related to the acquisition of certain natural gas properties located in the Narraway/Ojay area as well as drilling activity on light oil and natural gas development projects.

38

Contractual Obligations

There have not been any material changes in our contractual obligations since December 31, 2011, except for the issuance of the Senior Notes and the corresponding reduction to the borrowings outstanding under our bank credit facility. The following table summarizes our contractual obligations by calendar year as of June 30, 2012 for these two items.

	Remainder of
	2012		2013		2014		2015		2016		After 2016		Total
	(In thousands)
Bank credit facility(1)	$	4,538	$	9,052	$	9,052	$	9,052	$	230,910	$	—	$	262,604
Senior Notes(2)	$	10,631	$	21,145	$	21,145	$	21,145	$	21,145	$	214,384	$	309,595

(1) Bank credit facility amounts include the anticipated interest payments and commitment fees due under the terms of our bank credit facility using the interest rate in effect, borrowings outstanding and borrowing base at June 30, 2012.

(2) Amounts include interest payments and repayment of principal.

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 and cash flows were translated from Canadian dollars using the weighted average exchange rate for the period, and our balance sheets were translated at the period end exchange rates. 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 the FASB’s 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 financial 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 financial statements prepared under GAAP and International Financial Reporting Standards 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 defers indefinitely the requirements in Accounting Standards Update No. 2011-05, Comprehensive Income, Presentation of Comprehensive Income (“ASU 2011-05”) to present on the face of the financial statements the effects of reclassifications out of accumulated other comprehensive income on the components

39

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 and 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 FASB’s joint project with the International Accounting Standards Board. Under the revised standard, we were required to provide additional disclosures about fair value measurements, including information about the unobservable inputs and assumptions used in Level 3 fair value measurements, a description of the valuation methodologies used in Level 3 fair value measurements and the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. The adoption of ASU 2011-04 did not have a significant impact on our financial statements.

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

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report and other publicly available documents contain forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Quarterly Report regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Quarterly Report, the words “could,” “believe,” “anticipate,” “intend,” “plan,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements appear in a number of places in this Quarterly Report and may include statements with respect to, among other things:

·estimates of our oil and natural gas reserves;

·estimates of our future oil, natural gas and NGL production, including estimates of any increases or decreases in our production;

·estimates of future capital expenditures;

·our future financial condition and results of operations;

·our future revenues, cash flows and expenses;

·our access to capital and our anticipated liquidity;

·our future business strategy and other plans and objectives for future operations;

40

·our future development opportunities and production mix;

·our outlook on oil, natural gas and NGL prices;

·the amount, nature and timing of future capital expenditures, including future development costs;

·our ability to access the capital markets to fund capital and other expenditures;

·our assessment of our counterparty risk and the ability of our counterparties to perform their future obligations;

·the impact of federal, provincial, territorial and local political, legislative, regulatory and environmental developments in Canada, where we conduct business operations, and in the United States; and

·our estimates of additional costs and expenses we may incur as a separate stand-alone company.

We believe the expectations and forecasts reflected in our forward-looking statements are reasonable, but we can give no assurance that they will prove to be correct. We caution you that these forward-looking statements can be affected by inaccurate assumptions and are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. When considering forward-looking statements, you should keep in mind the assumptions, risk factors and other cautionary statements described in Part I, “Item 1A. Risk Factors” of our 2011 Annual Report and elsewhere in this Quarterly Report. These assumptions and risks include, among other things:

·the volatility of oil, natural gas and NGL prices, and the related differentials between realized prices and benchmark prices;

·a continuation of depressed natural gas prices;

·the availability of capital on economic terms to fund our significant capital expenditures and acquisitions;

·our ability to obtain adequate financing to pursue other business opportunities;

·our level of indebtedness;

·a significant reduction in the borrowing base under our bank credit facility;

·our ability to replace and sustain production;

·a lack of available drilling and production equipment, and related services and labor;

·increases in costs of drilling, completion, production equipment and related services and labor;

·unsuccessful exploration and development drilling activities;

·regulatory and environmental risks associated with exploration, drilling and production activities;

·declines in the value of our oil and natural gas properties, resulting in a decrease in our borrowing base under our bank credit facility and ceiling test write-downs;

·the adverse effects of changes in applicable tax, environmental and other regulatory legislation;

·a deterioration in the demand for our products;

·the risks and uncertainties inherent in estimating proved oil and natural gas reserves and in projecting future rates of production and the timing of expenditures;

·the risks of conducting exploratory drilling operations in new or emerging plays;

·intense competition with companies with greater access to capital and staffing resources;

·the risks of conducting operations in Canada and the impact of pricing differentials, fluctuations in foreign currency exchange rates and political developments on the financial results of our operations; and

·the uncertainty related to the pending litigation against us.

Should one or more of the risks or uncertainties described above or elsewhere in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

41

We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this Quarterly Report, and we undertake no obligation to update this information to reflect events or circumstances after the filing of this Quarterly Report with the SEC, except as required by law.  All forward-looking statements, expressed or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement.  This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we may make or persons acting on our behalf may issue.

Reconciliation of Non-GAAP Measures

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 ARO, unrealized losses (gains) on derivative instruments and foreign currency exchange losses (gains). Adjusted EBITDA also excludes the equity-accounted-for 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. 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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Net earnings (loss)	$	(105,035	)	$	5,366		$	(114,543	)	$	10,657
Add back (deduct):
Interest expense	8,242			2,237			13,993			3,590
Income tax expense (recovery)	(32,954		)	7,455			(35,011		)	9,383
Depreciation, depletion and amortization	31,882			19,919			58,312			38,560
Ceiling test write-down of oil and natural gas properties	128,870			—			128,870			—
Accretion of asset retirement obligations	341			267			677			537
Unrealized losses (gains) on derivative instruments	(9,540		)	(4,948		)	(4,371		)	(4,948		)
Foreign currency exchange losses (gains)	4,269			2,564			3,973			(4,970		)
Stock-based compensation (equity portion)	1,001			19			1,720			19
Adjusted EBITDA	$	27,076		$	32,879		$	53,620		$	52,828

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.

42

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Net cash provided by operating activities	$	20,694		$	4,217		$	37,908		$	28,269
Add back (deduct) changes in working capital:
Accounts receivable	(4,177		)	1,085			(10,351		)	(4,285		)
Prepaid expenses and other current assets	(1,496		)	(2,884		)	(1,188		)	(2,676		)
Accounts payable and accrued liabilities	8,196			4,145			21,752			4,578
Accrued interest and other current liabilities	(4,541		)	24,457			(8,150		)	23,833
Adjusted Discretionary Cash Flow	$	18,676		$	31,020		$	39,971		$	49,719

Item 3.  Quantitative and Qualitative Disclosures About Market Risk.

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2011 Annual Report, as well as with the financial statements included in this Quarterly Report.

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

Commodity Price Risk

We produce and sell crude oil, natural gas and NGLs. As a result, our financial results are affected when prices for these commodities fluctuate, and the effects can be significant. We enter into derivative instruments to manage our exposure to commodity price risk caused by fluctuations in commodity prices, which protects and provides certainty on a portion of our cash flows. Under this strategy, we enter into contracts with counterparties who are participants in our bank credit facility. These arrangements, which are based on prices available in the financial markets at the time we enter into the contracts, are settled in cash and do not require physical deliveries of hydrocarbons.

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

As of June 30, 2012, we had entered into the following swaps.

	Commodity Swaps
	Natural Gas (NYMEX Henry Hub)			Oil (NYMEX WTI)
Term	MMBtu/d	Weighted Average Price per MMBtu		bbls/d	Weighted Average Price per bbl
July 1, 2012 - December 31, 2012	25,000	US$	5.09	2,000	US$		102.35
July 1, 2012 - December 31, 2012	—	—		1,000	$	100.98
Calendar 2013	—	—		1,500	$	100.37
Calendar 2013	—	—		500	US$		101.00

43

In connection with a commodity swap entered into during the second quarter, we sold a call option to the counterparty in exchange for us receiving a premium fixed price on the commodity swap.  The table below sets forth the outstanding option as of June 30, 2012.

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

We also enter into commodity collar agreements with third parties. A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only if the index price is below the floor price, and we pay the difference between the ceiling price and the index price only if the index price is above the ceiling price. The table below sets forth our commodity collars outstanding as of June 30, 2012.

	Commodity Collars
	Natural Gas (NYMEX Henry Hub)
Term	MMBtu/d	Weighted Average Floor Price per MMBtu		Weighted Average Ceiling Price per MMBtu
Calendar 2013	15,000	US$	3.00	US$	4.00

We recognize all changes in fair value of derivative instruments, and as of June 30, 2012, the estimated fair value of our commodity derivative instruments was a net asset of approximately $24.2 million.

The following table summarizes additional commodity swaps that were entered into between July 1, 2012 and August 9, 2012.

	Commodity Swaps
	Natural Gas (NYMEX Henry Hub)			Oil (NYMEX WTI)
Term	MMBtu/d	Weighted Average Price per MMBtu		bbls/d	Weighted Average Price per bbl
September 1 — December 31, 2012	10,000	US$	3.31	—	—
Calendar 2013	—	—		500	$	93.30

The following table summarizes additional commodity collars that were entered into between July 1, 2012 and August 9, 2012.

	Commodity Collars
	Natural Gas (NYMEX Henry Hub)
Term	MMBtu/d	Weighted Average Floor Price per MMBtu		Weighted Average Ceiling Price per MMBtu
Calendar 2013	15,000	US$	3.50	US$	3.85

Long-Term Sales Contract

As of August 9, 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.

Interest Rate Risk

At June 30, 2012, we had $229.0 million in outstanding borrowings on our bank credit facility, and the weighted average interest rate on the facility was 3.6162%. Given that the interest rate on the bank credit facility is based on market rates, we are exposed to interest rate risk on these borrowings. We have not entered into any derivative financial instruments to manage this risk.

44

We do not have any exposure to interest rate risk on the Senior Notes, given that the interest rate is fixed for the term of the Senior Notes.

Foreign Currency Exchange Rate Risk

Our most significant foreign currency exchange rate risk relates to the Senior Notes since they are denominated in U.S. dollars. We are exposed to foreign currency exchange rate risk on the translation and repayment of this debt as well as the interest payments. We have not entered into any derivative financial instruments to manage this risk. We are also exposed to foreign currency exchange rate risk relating to certain of our derivative instruments and the delivery commitment of approximately 21,000 MMBtu/d of natural gas.

Item 4.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2012 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

During the three months ended June 30, 2012, there was no change in our system of internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.  Legal Proceedings.

In addition to the information below, you should review the disclosure included in our 2011 Annual Report under Part I, “Item 3. Legal Proceedings.”

On May 25, 2012, a lawsuit was brought as a purported class action in the Supreme Court of the State of New York, New York County against the Company, certain of the Company’s current and former directors and officers (the “Individual Defendants”), certain underwriters (the “Underwriter Defendants”) of the Company’s IPO in May 2011, and Forest.  The complaint alleges that the Company’s registration statement and prospectus issued in connection with the IPO contained untrue statements of material fact or omitted to state material facts relating to forest fires that occurred in Northern Alberta in May 2011 and the rupture of a third-party oil sales pipeline in Northern Alberta in April 2011 and the impact of those events on the Company, that the alleged misstatements or omissions violated Section 11 of the Securities Act of 1933 (the “Securities Act”) and that the Company, the Individual Defendants and the Underwriter Defendants are liable for such violations.  The complaint further alleges that the Underwriter Defendants offered and sold the Company’s securities in violation of Section 12(a)(2) of the Securities Act, and the putative class members seek rescission of the securities purchased in the IPO that they continue to own and rescissionary damages for securities that they have sold.  Finally, the complaint asserts a claim against Forest under Section 15 of the Securities Act, alleging that Forest was a “control person” of the Company at the time of the IPO.  The complaint alleges that the putative class, which purchased shares of the Company’s common stock pursuant and/or traceable to the Company’s registration statement and prospectus, was damaged when the value of the stock declined in August 2011.  The complaint does not specify the amount of such damages.  On June 20, 2012, the defendants removed this lawsuit to federal court, and it is now pending under the caption Augenbaum v. Lone Pine Resources Inc. et al. 1:12-cv-04839-GBD: (S.D.N.Y.).  A related lawsuit making almost identical claims, Holl v. Lone Pine Resources Inc. et al., 1:12-cv-05192-UA (S.D.N.Y.), was subsequently filed, and the Company expects that at least one more related lawsuit may be filed.  The Company has existing obligations to indemnify the Individual Defendants, the Underwriter Defendants and Forest in connection with the lawsuits. The Company believes that the claims are without merit and intends to defend these lawsuits vigorously.

45

Item 1A.  Risk Factors.

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our 2011 Annual Report under Part I, “Item 1A. Risk Factors”, which risks could materially affect the Company’s business, financial condition or future results. There has been no material change in the Company’s risk factors from those described in our 2011 Annual Report.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds.

Issuer Purchases of Equity Securities

Lone Pine did not repurchase any of its equity securities during the period covered by this report.

Item 6. Exhibits.

(a)     Exhibits.

Exhibit No.	Description of Exhibit
3.1	Amended and Restated Certificate of Incorporation of Lone Pine Resources Inc., incorporated herein by reference to Exhibit 3.1 to Amendment No. 5 to Form S-1 for Lone Pine Resources Inc. filed May 3, 2011 (File No. 333-171123).
3.2	Second Amended and Restated Bylaws of Lone Pine Resources Inc., incorporated herein by reference to Exhibit 3.1 to Form 8-K for Lone Pine Resources Inc. filed October 13, 2011 (File No. 001-35191).
4.1	Rights Agreement, incorporated herein by reference to Exhibit 4.1 to Amendment No. 7 to Form S-1 for Lone Pine Resources Inc. filed May 23, 2011 (File No. 333-171123).
4.2	Certificate of Designation of Series A Junior Participating Preferred Stock of Lone Pine Resources Inc., dated May 11, 2011, incorporated herein by reference to Exhibit 4.2 to Amendment No. 7 to Form S-1 for Lone Pine Resources Inc. filed May 23, 2011 (File No. 333-171123).
4.3	Indenture dated February 14, 2012, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., Lone Pine Resources (Holdings) Inc., Wiser Delaware LLC, Wiser Oil Delaware, LLC, and U.S. National Bank Association, as trustee, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Lone Pine Resources Inc. filed February 15, 2012 (File No. 001-35191).
4.4	Registration Rights Agreement dated February 14, 2012, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., Lone Pine Resources (Holdings) Inc., Wiser Delaware LLC, Wiser Oil Delaware, LLC, and Credit Suisse Securities (USA) LLC, as representative of the Purchasers, incorporated herein by reference to Exhibit 4.2 to Form 8-K for Lone Pine Resources Inc. filed February 15, 2012 (File No. 001-35191).
10.1†	Lone Pine Resources Inc. 2012 Employee Stock Purchase Plan, incorporated by reference to Appendix A to Schedule 14A for Lone Pine Resources Inc. filed April 3, 2012 (File No. 001-35191).
10.2†	Lone Pine Resources Inc. Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed May 17, 2012 (File No. 001-35191).
31.1*	Certification of Principal Executive Officer of Lone Pine Resources Inc. as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
31.2*	Certification of Principal Financial Officer of Lone Pine Resources Inc. as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
32.1**	Certifications of Principal Executive Officer and Principal Financial Officer of Lone Pine Resources Inc. pursuant to 18 U.S.C. §1350.

46

Exhibit No.	Description of Exhibit
101.INS††	XBRL Instance Document.
101.SCH††	XBRL Taxonomy Extension Schema Document.
101.CAL††	XBRL Taxonomy Calculation Linkbase Document.
101.LAB††	XBRL Label Linkbase Document.
101.PRE††	XBRL Presentation Linkbase Document.
101.DEF††	XBRL Taxonomy Extension Definition.

*Filed herewith.

**Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

†Contract or compensatory plan or arrangement in which directors and/or officers participate.

††The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.

47

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	LONE PINE RESOURCES INC.
	(Registrant)
August 14, 2012	By:	/s/ DAVID M. ANDERSON
		David M. Anderson
		President and Chief Executive Officer
		(on behalf of the Registrant)
	By:	/s/ EDWARD J. BEREZNICKI
		Edward J. Bereznicki
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

48

Exhibit Index

Exhibit No.	Description of Exhibit
3.1	Amended and Restated Certificate of Incorporation of Lone Pine Resources Inc., incorporated herein by reference to Exhibit 3.1 to Amendment No. 5 to Form S-1 for Lone Pine Resources Inc. filed May 3, 2011 (File No. 333-171123).
3.2	Second Amended and Restated Bylaws of Lone Pine Resources Inc., incorporated herein by reference to Exhibit 3.1 to Form 8-K for Lone Pine Resources Inc. filed October 13, 2011 (File No. 001-35191).
4.1	Rights Agreement, incorporated herein by reference to Exhibit 4.1 to Amendment No. 7 to Form S-1 for Lone Pine Resources Inc. filed May 23, 2011 (File No. 333-171123).
4.2	Certificate of Designation of Series A Junior Participating Preferred Stock of Lone Pine Resources Inc., dated May 11, 2011, incorporated herein by reference to Exhibit 4.2 to Amendment No. 7 to Form S-1 for Lone Pine Resources Inc. filed May 23, 2011 (File No. 333-171123).
4.3	Indenture dated February 14, 2012, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., Lone Pine Resources (Holdings) Inc., Wiser Delaware LLC, Wiser Oil Delaware, LLC, and U.S. National Bank Association, as trustee, incorporated herein by reference to Exhibit 4.1 to Form 8-K for Lone Pine Resources Inc. filed February 15, 2012 (File No. 001-35191).
4.4	Registration Rights Agreement dated February 14, 2012, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., Lone Pine Resources (Holdings) Inc., Wiser Delaware LLC, Wiser Oil Delaware, LLC, and Credit Suisse Securities (USA) LLC, as representative of the Purchasers, incorporated herein by reference to Exhibit 4.2 to Form 8-K for Lone Pine Resources Inc. filed February 15, 2012 (File No. 001-35191).
10.1†	Lone Pine Resources Inc. 2012 Employee Stock Purchase Plan, incorporated by reference to Appendix A to Schedule 14A for Lone Pine Resources Inc. filed April 3, 2012 (File No. 001-35191).
10.2†	Lone Pine Resources Inc. Annual Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed May 17, 2012 (File No. 001-35191).
31.1*	Certification of Principal Executive Officer of Lone Pine Resources Inc. as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
31.2*	Certification of Principal Financial Officer of Lone Pine Resources Inc. as required by Rule 13a-14(a) of the Securities Exchange Act of 1934.
32.1**	Certifications of Principal Executive Officer and Principal Financial Officer of Lone Pine Resources Inc. pursuant to 18 U.S.C. §1350.
101.INS††	XBRL Instance Document.
101.SCH††	XBRL Taxonomy Extension Schema Document.
101.CAL††	XBRL Taxonomy Calculation Linkbase Document.
101.LAB††	XBRL Label Linkbase Document.
101.PRE††	XBRL Presentation Linkbase Document.
101.DEF††	XBRL Taxonomy Extension Definition.

49

*Filed herewith.

**Not considered to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

†Contract or compensatory plan or arrangement in which directors and/or officers participate.

††The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed as part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise are not subject to liability under these sections.

50