UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2013

o	TRANSITION 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		(I.R.S. Employer
Incorporation or Organization)		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 x

Non-accelerated filer o		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 May 3, 2013, there were 86,208,786 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

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

	March 31, 2013			December 31, 2012
ASSETS
Current assets:
Cash	$	170		$	28
Accounts receivable	11,688			16,502
Derivative instruments	—			4,409
Prepaid expenses and other current assets	5,077			4,947
Total current assets	16,935			25,886
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion of $1,608,156 and $1,590,015	373,156			376,203
Unproved	150,866			148,956
Net oil and natural gas properties	524,022			525,159
Other property and equipment, net of accumulated depreciation and amortization of $11,570 and $10,658	64,253			65,096
Net property and equipment	588,275			590,255
Other assets	6,319			6,662
	$	611,529		$	622,803
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Bank overdraft	$	6,762		$	4,872
Accounts payable and accrued liabilities	44,420			32,468
Accrued interest	2,608			7,742
Derivative instruments	2,951			—
Capital lease obligation	1,232			1,217
Other current liabilities	906			2,564
Total current liabilities	58,879			48,863
Long-term debt	346,677			340,310
Asset retirement obligations	11,999			12,839
Capital lease obligation	4,207			4,521
Other liabilities	1,677			1,308
Total liabilities	423,439			407,841
Stockholders’ equity:
Common stock, 86,029,148 and 85,192,955 shares issued and outstanding	843			835
Capital surplus	985,891			984,438
Accumulated deficit	(798,758		)	(770,494		)
Accumulated other comprehensive income	114			183
Total stockholders’ equity	188,090			214,962
	$	611,529		$	622,803

See accompanying notes to condensed consolidated financial statements.

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LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

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

	Three months ended March 31,
	2013			2012

Revenues:
Oil and natural gas	$	28,846		$	44,329
Interest and other	2			6
Total revenues	28,848			44,335
Costs, expenses and other:
Lease operating expenses	9,016			14,449
Production and property taxes	569			853
Transportation and processing	3,239			4,153
General and administrative	7,301			4,106
Depreciation, depletion and amortization	19,061			26,430
Interest expense	7,433			5,751
Accretion of asset retirement obligations	192			336
Foreign currency exchange losses (gains)	4,068			(296		)
Losses on derivative instruments	6,472			107
Other, net	(165		)	11
Total costs, expenses and other	57,186			55,900
Loss before income taxes	(28,338		)	(11,565		)
Income tax expense (recovery)	(74		)	(2,057		)
Net loss	$	(28,264	)	$	(9,508	)
Basic and diluted loss per common share	$	(0.33	)	$	(0.11	)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands of Canadian dollars)

	Three Months Ended March 31,
	2013			2012

Net loss	$	(28,264	)	$	(9,508	)
Other comprehensive income (loss):
Amortization of accumulated actuarial (loss) gain, net of tax	(69		)	5
	(69		)	5
Comprehensive income (loss)	$	(28,333	)	$	(9,503	)

See accompanying notes to condensed consolidated financial statements.

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LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands of Canadian dollars)

	Three Months Ended March 31,
	2013			2012

Operating activities:
Net loss	$	(28,264	)	$	(9,508	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	19,061			26,430
Amortization of deferred costs	605			481
Accretion of asset retirement obligations	192			336
Deferred income tax recovery	(74		)	(2,057		)
Unrealized foreign currency exchange losses (gains)	3,997			(296		)
Unrealized losses on derivative instruments	7,548			5,169
Stock-based compensation	2,139			719
Other, net	(2,578		)	21
Changes in operating assets and liabilities:
Accounts receivable	4,814			6,174
Prepaid expenses and other current assets	(139		)	(308		)
Accounts payable and accrued liabilities	1,369			(13,556		)
Accrued interest and other current liabilities	(5,844		)	3,609
Net cash provided by operating activities	2,826			17,214
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	(20,131		)	(73,688		)
Other fixed assets	(68		)	(912		)
Proceeds from divestiture of assets, net	13,734			—
Net cash used in investing activities	(6,465		)	(74,600		)
Financing activities:
Repayment of long-term debt	(1,819		)	—
Issuance of common stock	8			—
Net proceeds from issuance of long-term debt	—			192,052
Debt issuance costs	—			(1,225		)
Proceeds from bank borrowings	487,000			785,000
Repayments of bank borrowings	(483,000		)	(929,000		)
Change in bank overdrafts	1,890			11,312
Capital lease payments	(298		)	(284		)
Net cash provided by financing activities	3,781			57,855
Net increase in cash	142			469
Cash at beginning of period	28			276
Cash at end of period	$	170		$	745

See accompanying notes to condensed consolidated financial statements.

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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, 2012	85,193	$	835	$	984,438		$	(770,494	)	$	183		$	214,962
Issuance of common stock, net of tax	836	8		2,374			—			—			2,382
Amortization of stock-based compensation		—		2,044			—			—			2,044
Capital surplus related to vested stock-based compensation		—		(2,965		)	—			—			(2,965		)
Comprehensive income (loss):
Net loss	—	—		—			(28,264		)	—			(28,264		)
Other comprehensive income (loss)	—	—		—			—			(69		)	(69		)
Balances at March 31, 2013	86,029	$	843	$	985,891		$	(798,758	)	$	114		$	188,090

See accompanying notes to condensed consolidated financial statements.

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Future Accounting Pronouncements

In the first quarter of 2013, the U.S. Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“ASU 2013-04”), which clarifies guidance for the recognition, measurement and disclosure of liabilities resulting from joint and several liability arrangements. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and are to be applied retrospectively. If the Company enters into obligations affected by ASU 2013-04, the accounting and disclosure requirements will be applied.

In the first quarter of 2013, the FASB issued Accounting Standards Update 2013-05, Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity (“ASU 2013-05”), which clarifies the applicable guidance for certain transactions that result in the release of the cumulative translation adjustment into net earnings. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and are to be applied prospectively. If the Company enters into any transactions affected by ASU 2013-05, the accounting and disclosure requirements will be applied.

(3) DISPOSITIONS

In February 2013, Lone Pine completed the divestiture of certain non-core properties in Alberta for proceeds of $13.7 million, after closing adjustments and costs of disposition. The proceeds reduced the net book value of the oil and natural gas proved properties, and no gain or loss was recognized in net earnings for the sale.

(4) LONG-TERM DEBT

The components of the Company’s long-term debt were as follows.

	At March 31, 2013						At December 31, 2012
	(In thousands)
	Principal		Unamortized Discount		Total		Principal		Unamortized Discount		Total
Bank credit facility	$	152,000	$	—	$	152,000	$	148,000	$	—	$	148,000
Senior Notes	201,097		6,420		194,677		198,985		6,675		192,310
Total Long-term debt	$	353,097	$	6,420	$	346,677	$	346,985	$	6,675	$	340,310

Senior Notes

On February 14, 2012, LPR Canada issued US$200 million aggregate principal amount of 10.375% senior notes due 2017 (the “Senior Notes”). The Senior Notes were issued pursuant to an indenture, dated February 14, 2012 (the “Indenture”), among LPR Canada, certain guarantors and U.S. Bank National Association, as trustee. In March 2013, LPR Canada repurchased US$2.0 million of Senior Notes at a cost of $1.8 million (US$1.8 million), including accrued interest, resulting in a gain on extinguishment of debt of $0.2 million, including related discount and deferred costs. The gain is included in other, net on the condensed consolidated statements of operations.

Bank Credit Facility

Lone Pine maintains a $500 million credit facility with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch (the “Credit Facility”). The Credit Facility will mature on March 18, 2016 and its availability is governed by a borrowing base, which was $275 million at March 31, 2013 (December 31, 2012 - $275 million). At March 31, 2013, the Company had $152 million (December 31, 2012 - $148 million) outstanding at a weighted average interest rate of 3.53%. On April 15, 2013, the Company’s borrowing base was revised from $275 million to $185 million.

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borrowing amount under the 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, 2013. In addition to the scheduled semi-annual redeterminations, LPR Canada and the lenders each have discretion at any time, but not more often than once during any calendar year, to have the borrowing base redetermined.

The agreement governing the Credit Facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends and mergers and acquisitions, and also includes a financial covenant. The agreement governing the Credit Facility provides that the Company will not permit its ratio of total debt outstanding to consolidated earnings before interest, taxes, depreciation and amortization (“EBITDA”), as defined by the terms of the agreement governing the Credit Facility and adjusted for non-cash charges, for a trailing 12-month period to exceed a specified amount (the “Financial Covenant”). At March 31, 2013, the permitted debt to EBITDA ratio was 4.0 to 1.0. On April 15, 2013, the Financial Covenant was amended so that the Company’s permitted total debt to EBITDA ratio shall not exceed 4.5 to 1.0, for any quarterly period ending on or before June 30, 2013 (including the quarter ending March 31, 2013), and 4.0 to 1.0 for all periods thereafter. At March 31, 2013, the total debt to EBITDA ratio was 4.3 to 1.0.

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

(5) 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. Lone Pine has elected not to designate its derivatives as hedging instruments for accounting purposes, and recognizes all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the condensed consolidated statements of operations.

Commodity Swaps

Lone Pine’s outstanding commodity swaps as of March 31, 2013 were as follows.

	Natural Gas (NYMEX Henry Hub) (1)			Oil (NYMEX WTI) (2)
Term	MMBtu/d(1)	Weighted Average Price per MMBtu		bbls/d(2)	Weighted Average Price per bbl
Calendar 2013	—	—		2,000	$	98.60
Calendar 2013	—	—		500	US$		101.00
Calendar 2014	5,000	US$	4.37	250	$	93.50

(1) Million British thermal units per day with price taken from the New York Mercantile Exchange (NYMEX)

(2) Barrels per day using price of West Texas Intermediate (WTI)

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Fair Value Amounts

The table below summarizes the location of the gross and net fair value amounts of Lone Pine’s derivative instruments reported in the condensed consolidated balance sheets as of the dates indicated. Due to the volatility of oil and natural gas prices, the estimated fair values of Lone Pine’s commodity derivative instruments are subject to large fluctuations from period to period. In the condensed consolidated balance sheets, Lone Pine offsets asset and liability fair value amounts recognized for derivative instruments with the same counterparty under master netting arrangements. See note 6 for additional information on the fair value of Lone Pine’s derivative instruments.

	At March 31, 2013			At December 31, 2012
	(In thousands)
Derivatives - Gross Amounts
Current assets	$	1,694		$	5,703
Current liabilities	(4,645		)	(1,294		)
Derivative instruments - current (liabilities) assets	(2,951		)	4,409

Long-term assets	220			—
Long-term liabilities	(408		)	—
Other long-term liabilities	(188		)	—

Net (liabilities) assets	$	(3,139	)	$	4,409

The table below shows the amounts reported in the condensed consolidated statements of operations as gains and losses on derivative instruments for the periods indicated.

	Three months ended March 31,
	2013			2012
	(In thousands)
Realized gains on derivative instruments	$	(1,076	)	$	(5,062	)
Unrealized losses on derivative instruments	7,548			5,169
Losses on derivative instruments	$	6,472		$	107

6) FAIR VALUE MEASUREMENTS

FASB’s Accounting Standards Codification 820 Fair Value Measurement establishes a three-tier fair value hierarchy that 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.

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

	Fair Value	At March 31, 2013				At December 31, 2012
	Hierarchy Level	Carrying Amount		Fair Value		Carrying Amount		Fair Value
		(In thousands)
Assets:
Cash	—	$	170	$	170	$	28	$	28
Accounts receivable	—	11,688		11,688		16,502		16,502
Derivative instruments	2	1,914		1,914		5,703		5,703
Liabilities:
Bank overdraft	—	6,762		6,762		4,872		4,872
Accounts payable and accrued liabilities	—	44,420		44,420		32,468		32,468
Accrued interest	—	2,608		2,608		7,742		7,742
Derivative instruments	2	5,053		5,053		1,294		1,294
Long-term debt:
Bank credit facility	2	152,000		152,000		148,000		148,000
Senior Notes	1	194,677		177,085		192,310		186,046
Total long-term debt		346,677		329,085		340,310		334,046
Capital lease obligation	2	5,439		5,439		5,738		5,738

The Company uses various assumptions and methods in estimating the fair values of its financial instruments. All of the estimates of fair value were determined using significant other observable inputs (Level 2), except for the fair value of the Senior Notes, which was determined based on the unadjusted quoted price in an active market (Level 1) given that the Senior Notes are actively traded in a private market with an independent quoted price available from a third party. The carrying amount of the Senior Notes has been reduced by the original issue discount and commissions, while the fair value of the Senior Notes at March 31, 2013 is based on its face amount of US$198 million (December 31, 2012 - US$200 million) and market price of US$88.06 per US$100 face amount (December 31, 2012 — US$93.50 per US$100). 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 are commodity derivatives. See note 5 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, bank overdraft, accounts payable and accrued liabilities, and accrued interest approximate their carrying amount due to their short-term nature.

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(7) LOSS PER SHARE

The Company calculates basic and diluted loss per common share as follows.

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Net loss	$	(28,264	)	$	(9,508	)
Net earnings attributable to participating securities	—			—
Net loss attributable to common stock for basic and diluted earnings per share	$	(28,264	)	$	(9,508	)
Weighted average number of common shares outstanding during the period for basic earnings per share	85,375			85,000
Dilutive effects 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	85,375			85,000
Basic loss per common share	$	(0.33	)	$	(0.11	)
Diluted loss per common share	$	(0.33	)	$	(0.11	)

At March 31, 2013, approximately 2.8 million (March 31, 2012 — 1.6 million) shares were excluded from the diluted loss per common share calculation as the effect was anti-dilutive.

(8) 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 three months ended March 31, 2013 and 2012.

	Phantom Stock Units – Stock		Phantom Stock Units – Cash or Cash or Stock		Performance Units		Stock Options		Restricted Stock	Total
Outstanding as of December 31, 2012	979,530		400,551		—		644,706		67,935	2,092,722
Awarded	310,078		3,831,494		2,164,470		—		—	6,306,042
Vested	(550,635	)	(713,914	)	(755,370	)	—		—	(2,019,919	)
Forfeited	(54,124	)	(74,755	)	—		(152,574	)	—	(281,453	)
Outstanding as of March 31, 2013	684,849		3,443,376		1,409,100		492,132		67,935	6,097,392

	Phantom Stock Units – Stock	Phantom Stock Units – Cash or Cash or Stock	Performance Units	Stock Options	Restricted Stock	Total
Outstanding as of December 31, 2011	43,701	657,249	—	—	26,202	727,152
Awarded	889,684	—	—	646,636	—	1,536,320
Vested	—	—	—	—	—	—
Forfeited	—	—	—	—	—	—
Outstanding as of March 31, 2012	933,385	657,249	—	646,636	26,202	2,263,472

At March 31, 2013, the Company had 492,132 stock options outstanding, of which 193,406 had vested with the majority being exercisable no later than the second quarter of 2013.

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In the first quarter of 2013, the Company’s executives were issued performance units that will settle in stock. Lone Pine expects to issue new shares of the Company to settle the performance units. The weighted average grant date fair value of the performance units was determined using the expected closing price of a share of Lone Pine common stock at December 31, 2015 and using an expected payout of between 0% and 200%, which would reflect the Company’s performance. The payout depends on the total return of the Company’s stock compared to the total return of a defined set of peer companies. The performance units vest on December 31, 2015.

(9) INCOME TAXES

The Company’s combined Canadian federal and provincial statutory income tax rate was 25% and 25% for the three months ended March 31, 2013 and 2012, respectively. The effective income tax rate for the three months ended March 31, 2013 and 2012 was 0.3% and 18%, respectively. The effective income tax rate for the three months ended March 31, 2013 reflected the Company offsetting its additional deferred income tax asset of $6.5 million with a valuation allowance since it was determined that it is more likely than not that the Company will not be able to realize the benefit of the asset.

(10) SUBSEQUENT EVENTS

Repurchase of Senior Notes

In April 2013, LPR Canada repurchased US$3.0 million of Senior Notes at a cost of $2.8 million (US$2.7 million), including accrued interest.

(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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 (the “Subsidiary Guarantors”, and together with the Parent Guarantor, the “Guarantors”). These guarantees are full and unconditional, and joint and several among the Guarantors. See note 4 for further information on the Senior Notes.

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

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

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(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Balance Sheet

(In thousands of Canadian dollars)

	As at March 31, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries		Subsidiary Issuer			Eliminations			Consolidated

ASSETS
Current assets:
Cash	$	—		$	—	$	170		$	—		$	170
Accounts receivable	4,101			493		11,310			(4,216		)	11,688
Prepaid expenses and other current assets	114			—		4,963			—			5,077
Total current assets	4,215			493		16,443			(4,216		)	16,935
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion	—			—		373,156			—			373,156
Unproved	—			—		150,866			—			150,866
Net oil and natural gas properties	—			—		524,022			—			524,022
Other property and equipment, net of accumulated depreciation and amortization	—			—		64,253			—			64,253
Net property and equipment	—			—		588,275			—			588,275
Investment in affiliate	84,082			58,063		—			(142,145		)	—
Other assets	—			—		6,319			—			6,319
	$	88,297		$	58,556	$	611,037		$	(146,361	)	$	611,529
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Bank overdraft	$	153		$	—	$	6,609		$	—		$	6,762
Accounts payable and accrued liabilities	579			—		48,057			(4,216		)	44,420
Accrued interest	—			—		2,608			—			2,608
Derivative instruments	—			—		2,951			—			2,951
Capital lease obligation	—			—		1,232			—			1,232
Other current liabilities	407			—		499						906
Total current liabilities	1,139			—		61,956			(4,216		)	58,879
Long-term debt	—			—		346,677			—			346,677
Asset retirement obligations	—			—		11,999			—			11,999
Capital lease obligation	—			—		4,207			—			4,207
Other liabilities	289			—		1,388			—			1,677
Total liabilities	1,428			—		426,227			(4,216		)	423,439
Stockholders’ equity:
Common stock	843			39,135		832,750			(871,885		)	843
Capital surplus	366,444			19,027		143,138			457,282			985,891
Retained earnings (accumulated deficit)	(280,823		)	394		(790,787		)	272,458			(798,758		)
Accumulated other comprehensive income (loss)	405			—		(291		)	—			114
Total stockholders’ equity	86,869			58,556		184,810			(142,145		)	188,090
	$	88,297		$	58,556	$	611,037		$	(146,361	)	$	611,529

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(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Balance Sheet

(In thousands of Canadian dollars)

	As at December 31, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries		Subsidiary			Eliminations			Consolidated
ASSETS:
Current assets:
Cash	$	—		$	—	$	28		$	—		$	28
Accounts receivable	3,198			486		16,129			(3,311		)	16,502
Derivative instruments	—			—		4,409			—			4,409
Prepaid expenses and other current assets	148			—		4,799			—			4,947
Total current assets	3,346			486		25,365			(3,311		)	25,886
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion	—			—		376,203			—			376,203
Unproved	—			—		148,956			—			148,956
Net oil and natural gas properties	—			—		525,159			—			525,159
Other property and equipment, net of accumulated depreciation and amortization	—			—		65,096			—			65,096
Net property and equipment	—			—		590,255			—			590,255
Investment in affiliate	110,882			58,063		—			(168,945		)	—
Other assets	—			—		6,662			—			6,662
	$	114,228		$	58,549	$	622,282		$	(172,256	)	$	622,803
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Bank overdraft	$	44		$	—	$	4,828		$	—		$	4,872
Accounts payable and accrued liabilities	241			—		35,538			(3,311		)	32,468
Accrued interest	—			—		7,742			—			7,742
Capital lease obligation	—			—		1,217			—			1,217
Other current liabilities	164			—		2,400			—			2,564
Total current liabilities	449			—		51,725			(3,311		)	48,863
Long-term debt	—			—		340,310			—			340,310
Asset retirement obligations	—			—		12,839			—			12,839
Capital lease obligation	—			—		4,521			—			4,521
Other liabilities	107			—		1,201			—			1,308
Total liabilities	556			—		410,596			(3,311		)	407,841
Stockholders’ equity:
Common stock	835			39,135		832,750			(871,885		)	835
Capital surplus	364,991			19,027		143,138			457,282			984,438
Retained earnings (accumulated deficit)	(252,559		)	387		(763,980		)	245,658			(770,494		)
Accumulated other comprehensive income (loss)	405			—		(222		)	—			183
Total stockholders’ equity	113,672			58,549		211,686			(168,945		)	214,962
	$	114,228		$	58,549	$	622,282		$	(172,256	)	$	622,803

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(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Operations

(In thousands of Canadian dollars)

	Three Months Ended March 31, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Revenues:
Oil and natural gas	$	—		$	—		$	28,846		$	—		$	28,846
Interest and other	—			—			2			—			2
Total revenues	—			—			28,848			—			28,848
Costs, expenses and other:
Lease operating expenses	—			—			9,016			—			9,016
Production and property taxes	—			—			569			—			569
Transportation and processing	—			—			3,239			—			3,239
General and administrative	1,507			2			5,792			—			7,301
Depreciation, depletion and amortization	—			—			19,061			—			19,061
Interest expense	—			—			7,433			—			7,433
Accretion of asset retirement obligations	—			—			192			—			192
Foreign currency exchange losses (gains)	(43		)	(9		)	4,120			—			4,068
Losses on derivative instruments	—			—			6,472			—			6,472
Equity loss in affiliates	26,800			—			—			(26,800		)	—
Other, net	—			—			(165		)	—			(165		)
Total costs, expenses and other	28,264			(7		)	55,729			(26,800		)	57,186
Earnings (loss) before income taxes	(28,264		)	7			(26,881		)	26,800			(28,338		)
Income tax expense (recovery)	—			—			(74		)	—			(74		)
Net earnings (loss)	$	(28,264	)	$	7		$	(26,807	)	$	26,800		$	(28,264	)

Condensed Consolidating Statement of Comprehensive Income

(In thousands of Canadian dollars)

	Three Months Ended March 31, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries		Subsidiary Issuer			Eliminations		Consolidated

Net earnings (loss)	$	(28,264	)	$	7	$	(26,807	)	$	26,800	$	(28,264	)
Other comprehensive income (loss):
Amortization of accumulated actuarial loss, net of tax	—			—		(69		)	—		(69		)
Total other comprehensive income	—			—		(69		)	—		(69		)
Comprehensive income (loss)	$	(28,264)		$	7	$	(26,876	)	$	26,800	$	(28,333	)

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(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Operations

(In thousands of Canadian dollars)

	Three Months Ended March 31, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Revenues:
Oil and natural gas	$	—		$	—		$	44,329		$	—		$	44,329
Interest and other	—			—			6			—			6
Total revenues	—			—			44,335			—			44,335
Costs, expenses and other:
Lease operating expenses	—			—			14,449			—			14,449
Production and property taxes	—			—			853			—			853
Transportation and processing	—			—			4,153			—			4,153
General and administrative	627			—			3,479			—			4,106
Depreciation, depletion and amortization	—			—			26,430			—			26,430
Interest expense	—			—			5,751			—			5,751
Accretion of asset retirement obligations	—			—			336			—			336
Foreign currency exchange losses (gains)	(16		)	11			(291		)	—			(296		)
Losses on derivative instruments	—			—			107			—			107
Equity loss in affiliates	8,861			—			—			(8,861		)	—
Other, net	36			—			(25		)	—			11
Total costs, expenses and other	9,508			11			55,242			(8,861		)	55,900
Earnings (loss) before income taxes	(9,508		)	(11		)	(10,907		)	8,861			(11,565		)
Income tax expense (recovery)	—			—			(2,057		)	—			(2,057		)
Net loss	$	(9,508	)	$	(11	)	$	(8,850	)	$	8,861		$	(9,508	)

Condensed Consolidating Statement of Comprehensive Income

(In thousands of Canadian dollars)

	Three Months Ended March 31, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations		Consolidated

Net earnings (loss)	$	(9,508	)	$	(11	)	$	(8,850	)	$	8,861	$	(9,508	)
Other comprehensive income (loss):
Amortization of accumulated actuarial gain, net of tax	—			—			5			—		5
Total other comprehensive income	—			—			5			—		5
Comprehensive income (loss)	$	(9,508	)	$	(11	)	$	(8,845	)	$	8,861	$	(9,503	)

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(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Cash Flows

(In thousands of Canadian dollars)

	Three Months Ended March 31, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Operating activities:
Net earnings (loss)	$	(28,264	)	$	7		$	(26,807	)	$	26,800		$	(28,264	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	—			—			19,061			—			19,061
Amortization of deferred costs	—			—			605			—			605
Accretion of asset retirement obligations	—			—			192			—			192
Deferred income tax recovery	—			—			(74		)	—			(74		)
Unrealized foreign currency exchange losses (gains)	(7		)	—			4,004			—			3,997
Unrealized losses on derivative instruments	—			—			7,548			—			7,548
Stock-based compensation	162			—			1,977			—			2,139
Equity loss in affiliates	26,800			—			—			(26,800		)	—
Other, net	—			—			(2,578		)	—			(2,578		)
Changes in operating assets and liabilities:
Accounts receivable	(5		)	—			4,819			—			4,814
Prepaid expenses and other current assets	34			—			(173		)	—			(139		)
Accounts payable and accrued liabilities	335			—			1,034			—			1,369
Accrued interest and other current liabilities	—			—			(5,844		)	—			(5,844		)
Net cash provided by (used in) operating activities	(945		)	7			3,764			—			2,826
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			(20,131		)	—			(20,131		)
Other fixed assets	—			—			(68		)	—			(68		)
Proceeds from divestiture of assets, net	—			—			13,734			—			13,734
Net cash used in investing activities	—			—			(6,465		)	—			(6,465		)
Financing activities:
Repayment of long-term debt	—			—			(1,819		)	—			(1,819		)
Issuance of common stock	8			—			—			—			8
Proceeds from bank borrowings	—			—			487,000			—			487,000
Repayments of bank borrowings	—			—			(483,000		)	—			(483,000		)
Change in intercompany balances	828			(7		)	(821		)	—			—
Change in bank overdrafts	109			—			1,781			—			1,890
Capital lease payments	—			—			(298		)	—			(298		)
Net cash provided by (used in) financing activities	945			(7		)	2,843			—			3,781
Net increase in cash	—			—			142			—			142
Cash at beginning of period	—			—			28			—			28
Cash at end of period	$	—		$	—		$	170		$	—		$	170

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(11) CONDENSED CONSOLIDATING FINANCIAL INFORMATION (continued)

Condensed Consolidating Statement of Cash Flows

(In thousands of Canadian dollars)

	Three Months Ended March 31, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Operating activities:
Net earnings (loss)	$	(9,508	)	$	(11	)	$	(8,850	)	$	8,861		$	(9,508	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			—			26,430			—			26,430
Amortization of deferred costs	—			—			481			—			481
Accretion of asset retirement obligations	—			—			336						336
Deferred income tax recovery	—			—			(2,057		)	—			(2,057		)
Unrealized foreign currency exchange gains	—			—			(296		)	—			(296		)
Unrealized losses on derivative instruments	—			—			5,169			—			5,169
Stock-based compensation	162			—			557			—			719
Equity loss in affiliates	8,861			—			—			(8,861		)	—
Other, net	—			—			21			—			21
Changes in operating assets and liabilities:
Accounts receivable	—			—			6,174			—			6,174
Prepaid expenses and other current assets	1			—			(309		)	—			(308		)
Accounts payable and accrued liabilities	(414		)	—			(13,142		)	—			(13,556		)
Accrued interest and other current liabilities	—			—			3,609			—			3,609
Net cash provided by (used in) operating activities	(898		)	(11		)	18,123			—			17,214
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			(73,688		)	—			(73,688		)
Other fixed assets	—			—			(912		)	—			(912		)
Net cash used in investing activities	—			—			(74,600		)	—			(74,600		)
Financing activities:
Net proceeds from issuance of long-term debt	—			—			192,052			—			192,052
Debt issuance costs	—			—			(1,225		)	—			(1,225		)
Proceeds from bank borrowings	—			—			785,000			—			785,000
Repayments of bank borrowings	—			—			(929,000		)	—			(929,000		)
Change in intercompany balances	867			11			(878		)	—			—
Change in bank overdrafts	24			—			11,288			—			11,312
Capital lease payments	—			—			(284		)	—			(284		)
Net cash provided by financing activities	891			11			56,953			—			57,855
Net increase (decrease) in cash	(7		)	—			476			—			469
Cash at beginning of period	273			—			3			—			276
Cash at end of period	$	266		$	—		$	479		$	—		$	745

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· Maintaining financial flexibility. We have historically funded growth through cash flow from operations, debt and equity security issuances, and divestments of non-core assets. We actively manage our exposure to commodity price fluctuations by hedging meaningful portions of our expected production through the use of derivatives, including fixed price swaps, swaptions and collars. The level of our hedging activity and the duration of the instruments employed depend upon our view of market conditions, available hedge prices, our anticipated production volumes and our operating strategy.

· Retaining long-term optionality of our core natural gas assets. We maintain natural gas properties with a large identified resource potential, particularly in the Narraway/Ojay areas of Alberta and British Columbia, and in our shale plays in the Utica Shale formation in Quebec and in the Liard Basin in the Northwest Territories. At this time, we plan to retain these assets, which provide us with the option for further development in these regions when natural gas prices improve. Although we have not committed a material amount of capital to our natural gas assets since the fourth quarter of 2011, the Narraway/Ojay assets had net natural gas sales volumes of 25.7 million cubic feet equivalent per day (“MMcfe/d”) in the first quarter of 2013 and generated cash flow for the business.

· Pursuing selective divestitures of non-core assets to increase margins, operational focus and liquidity. In 2013, we completed the sale of an additional non-core property in the Herronton area of Alberta aimed at simplifying our portfolio of assets and generating cash proceeds for deleveraging purposes, and we will continue to pursue selected non-core dispositions to further our focus and generate additional liquidity to be used for deleveraging purposes and for capital expenditures at our core properties.

Financial and Operating Performance

Our financial and operating performance for the first quarter of 2013 included the following highlights.

· Increased the average net liquids weighting of our net sales volumes to 35% in the first quarter of 2013 from 26% in the first quarter of 2012.

· Invested $31.8 million on capital expenditures, primarily related to the drilling of 8 gross (6.8 net) horizontal light oil wells at Evi.

· Completed the disposition of an additional non-core asset in the Herronton area of Alberta for cash proceeds after closing adjustments of approximately $13.7 million, as part of our previously announced asset portfolio review process.

Results of Operations

Selected financial results for the three months ended March 31, 2013 and 2012 are as follows.

	Three Months Ended March 31,
	2013			2012
	(In thousands, except volumes and per unit data)
Oil and natural gas revenues	$	28,846		$	44,329
Net sales volumes (MMcfe)(1)	4,443			8,301
Realized equivalent sales price (per thousand cubic feet equivalent (“Mcfe”))	$	6.49		$	5.34
Net loss	$	(28,264	)	$	(9,508	)
Adjusted EBITDA(2)	$	11,300		$	26,544

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

(2) Adjusted EBITDA is a non-GAAP measure. See “—Reconciliation of Non-GAAP Measure” for a reconciliation of net earnings (loss) to Adjusted EBITDA, which is its most directly comparable measure calculated and presented in accordance with GAAP.

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We recorded a net loss of $28.3 million for the three months ended March 31, 2013 compared to a net loss of $9.5 million for the three months ended March 31, 2012.

In the first quarter of 2013, our revenues less production expenses decreased by $8.9 million from the first quarter of 2012, which was primarily related to the divestiture of non-core properties that had generated revenues less production expenses of $5.1 million in the first quarter of 2012. Other factors that increased our net loss included higher losses on derivative instruments caused by improving commodity prices, foreign currency exchange losses as a result of a lower Canadian dollar, as well as an increase in general and administrative expenses. These increases were partially offset by lower depreciation, depletion and amortization expense (“DD&A”) due to lower net sales volumes.

Adjusted EBITDA decreased $15.2 million for the three months ended March 31, 2013 compared to the three months ended March 31, 2012, primarily due to the decline in our revenues less production expenses and a reduction in the realized gains on derivative instruments, as well as higher general and administrative expenses.

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

Volumes and Revenues

The table below presents our sales volumes by product for the three months ended March 31, 2013 and 2012.

	Three Months Ended March 31,
	2013		2012
Working interest sales volumes(1):
Oil (Mbbls)	279		374
NGLs (Mbbls)	7		25
Natural gas (MMcf)	3,405		6,234
Total equivalent (MMcfe)	5,121		8,628
Total equivalent daily sales volumes (MMcfe/d)	56.9		94.8
Total equivalent daily sales volumes (boe/d)	9,483		15,802
Average liquids weighting	34	%	28	%

Net sales volumes(2):
Oil (Mbbls)	251		339
NGLs (Mbbls)	5		18
Natural gas (MMcf)	2,907		6,159
Total equivalent (MMcfe)	4,443		8,301
Total equivalent daily sales volumes (MMcfe/d)	49.4		91.2
Total equivalent daily sales volumes (boe/d)	8,228		15,203
Average liquids weighting	35	%	26	%

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

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

Net sales volumes for the three months ended March 31, 2013 decreased to 49.4 MMcfe/d from 91.2 MMcfe/d in 2012, which was a decrease of 41.8 MMcfe/d. Most of the decrease in net sales volumes related to natural gas, which accounted for approximately 35.4 MMcf/d, while crude oil accounted for approximately 5.6 MMcfe/d. Our average net liquids weighting increased from 26% for the three months ended March 31, 2012 to 35% for the three months ended March 31, 2013.

The decrease in our natural gas volumes was due largely to the divestiture of non-core properties in the fourth quarter of 2012. These properties had generated net sales volumes of approximately 23.8 MMcfe/d in the first quarter of 2012, of which approximately 90% was natural gas. Natural gas volumes were also lower due to the continued natural decline of our natural gas production as a result of a continued decision to suspend new investment in natural gas drilling

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activities. We expect this decrease in natural gas volumes to continue while we focus our capital program on light oil development. The decrease in our crude oil volumes was primarily due to lower capital expenditures in the fourth quarter of 2012, resulting in fewer horizontal wells being drilled and brought on-stream in the first quarter of 2013.

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

	Three Months Ended March 31,
	2013			2012
Revenues (in thousands):
Oil	$	21,085		$	29,786
Natural gas	7,570			13,455
NGLs	191			1,088
	$	28,846		$	44,329

Average prices per unit:
NYMEX WTI (US$ per bbl)	94.36			103.03
NYMEX WTI ($ per bbl)	95.15			103.14
Edmonton Par ($ per bbl)	88.49			93.40
Average oil sales price ($ per bbl)	84.00			87.86
Differential — NYMEX WTI to average oil sales price ($ per bbl)	11.15			15.28
Differential — Edmonton Par to average oil sales price ($ per bbl)	4.49			5.54

NYMEX Henry Hub (US$ per MMBtu)	3.34			2.74
NYMEX Henry Hub ($ per MMBtu)	3.37			2.74
AECO ($ per MMBtu)	3.08			2.52
Average natural gas sales price ($ per MMBtu)	2.60			2.18
Differential — NYMEX Henry Hub to average natural gas sales price ($ per MMBtu)	0.77			0.56
Differential — AECO to average natural gas sales price ($ per MMBtu)	0.48			0.34

Average NGL sales price ($ per bbl)	38.20			60.44
Percentage of NYMEX WTI	40		%	59		%

Total equivalent realized sales price ($ per Mcfe)	6.49			5.34
Total equivalent realized sales price ($ per barrel of oil equivalent (“boe”))	38.95			32.04

Our revenues decreased from $44.3 million for the three months ended March 31, 2012 to $28.8 million for the three months ended March 31, 2013.

Our natural gas revenues decreased 44% in the first quarter of 2013 compared to the first quarter of 2012 primarily due to the decrease in natural gas net sales volumes following the divestiture of non-core natural gas-weighted properties in the fourth quarter of 2012. The decrease in volumes was partially offset by a 19% increase in our realized natural gas price from $2.18 per MMBtu in the first quarter of 2012 to $2.60 per MMBtu in the first quarter of 2013, consistent with the increase in the benchmark AECO natural gas price.

Our natural gas revenue was negatively impacted by our delivery commitment of approximately 21,000 MMBtu/d of natural gas under a long-term sales contract in both 2012 and 2013. However, the impact was more pronounced in 2013 since the contract represented a larger proportion of our overall natural gas volumes. For the three months ended March 31, 2013, we estimate that this delivery commitment reduced our natural gas revenue by approximately $2.3 million, which equates to a reduction of approximately $0.79 per MMBtu.

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Our crude oil revenues decreased 29% in the first quarter of 2013 compared to 2012 primarily due to the decrease in crude oil net sales volumes discussed above. Crude oil revenues were also lower due to a 4% decrease in our realized crude oil price from $87.86 per bbl in the first quarter of 2012 to $84.00 per bbl in the first quarter of 2013, consistent with the decrease in the benchmark Edmonton Par crude oil price.

Production Expense

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

	Three Months Ended March 31,
	2013		2012
	(In thousands, except per Mcfe data)
Production expense:
Lease operating expenses	$	9,016	$	14,449
Production and property taxes	569		853
Transportation and processing costs	3,239		4,153
	$	12,824	$	19,455
Production expense per Mcfe:
Lease operating expenses	$	2.03	$	1.74
Production and property taxes	0.13		0.10
Transportation and processing costs	0.73		0.50
	$	2.89	$	2.34

Lease Operating Expenses

Lease operating expenses for the three months ended March 31, 2013 were $9.0 million, or $2.03 per Mcfe, compared to $14.4 million, or $1.74 per Mcfe, for the three months ended March 31, 2012. The $5.4 million decrease in lease operating expenses was primarily due to a lower level of workovers and the divestiture of non-core properties as well as a general reduction in expenses consistent with lower production volumes.

The cost of workovers decreased by $2.7 million from $4.6 million in the first quarter of 2012 to $1.9 million in the first quarter of 2013, primarily as a result of optimized completion techniques that reduced the need for additional proppant clean-outs that were required for some wells drilled in the first quarter of 2012, which reduced the cost of workovers at Evi by $1.6 million in the first quarter of 2013. The cost of workovers also decreased by $0.9 million in 2013 at our heavy oil property because we performed fewer workovers in light of wider differentials that resulted in lower realized heavy oil prices.

In the first quarter of 2013, lease operating expenses (excluding workovers) at our other properties decreased by approximately $1.5 million. This decrease is consistent with lower production volumes at these properties.

In the fourth quarter of 2012, we sold non-core properties that had incurred lease operating expenses (excluding workovers) of $1.2 million in the first quarter of 2012.

Although total lease operating expenses decreased, there was an overall increase in the cost per Mcfe. This increase was partly due to the increase in our net liquids weighting to 35% in the first quarter of 2013, since crude oil properties have higher per unit operating costs than natural gas properties. The increase in the first quarter of 2013 also resulted from lower operating costs in the first quarter of 2012 of approximately $0.78 per Mcfe associated with the divested properties.

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Production and Property Taxes

Production and property taxes primarily consist of production taxes levied on freehold production and property taxes (ad valorem taxes) assessed by local governments. The decrease for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 was primarily due to the taxes associated with the divested non-core properties.

Transportation and Processing Costs

Transportation and processing costs primarily consist of natural gas transportation costs and field-level natural gas gathering and crude oil processing costs. Transportation and processing costs for the three months ended March 31, 2013 were $3.2 million compared to $4.2 million for the three months ended March 31, 2012.

The decrease was primarily related to the reduction in our natural gas production volumes as well as the renegotiation of certain contracts. Although total transportation and processing costs decreased, there was an increase in the cost per Mcfe because the transportation costs for the divested properties were lower than the average per Mcfe cost in the first quarter of 2012.

General and Administrative Expense

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

	Three Months Ended March 31,
	2013			2012
	(In thousands, except per Mcfe data)
General and administrative costs	$	6,742		$	3,978
Stock-based compensation costs	3,202			1,608
Total costs incurred	9,944			5,586
General and administrative costs capitalized (including stock-based compensation)	(2,643		)	(1,480		)
General and administrative expense	$	7,301		$	4,106
General and administrative expense per Mcfe	$	1.64		$	0.49

General and Administrative Costs

General and administrative costs primarily consist of the salaries and related benefit costs for our employees, professional fees and office lease costs. General and administrative costs increased in the first quarter of 2013 compared to the first quarter of 2012 due to an overall increase in activities for the Company, including legal costs associated with a purported securities class action lawsuit relating to our initial public offering (“IPO”) as well as higher costs for certain compliance functions including higher audit fees and internal audit costs. The increase was also partly due to $0.9 million of severance payments related to the termination of employment of our former Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”).

Stock-Based Compensation Costs

Our stock-based compensation plans include units that will primarily be settled in cash and are accounted for as a liability, the fair value of which is adjusted each reporting period based on our share price. Our plans also include stock-settled units, which will be settled in stock of the Company, the fair value of which was determined and fixed at their grant date.

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The increase in stock-based compensation costs from the first quarter of 2012 to the first quarter of 2013 was primarily related to the automatic vesting of units upon the termination of our CEO and CFO, which resulted in the acceleration of $1.5 million of compensation cost.

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 ranged from 26% to 27% during the periods presented.

Depreciation, Depletion and Amortization

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

	Three Months Ended March 31,
	2013		2012
	(In thousands, except per Mcfe data)
Depreciation, depletion and amortization	$	19,061	$	26,430
Depreciation, depletion and amortization per Mcfe	$	4.29	$	3.18

For the three months ended March 31, 2013, DD&A was $19.1 million, or $4.29 per Mcfe, compared to $26.4 million, or $3.18 per Mcfe, for the three months ended March 31, 2012. The increase was primarily due to the addition of proved reserves to our depletable base at higher per-unit rates, since the majority of our capital expenditures are being directed towards crude oil projects and the capital costs associated with crude oil development are higher than natural gas. The per-unit rate also increased from 2012 to 2013 due to the decrease in our natural gas proved reserve volumes during 2012, which occurred as a result of the continued decline in the 12-month average trailing natural gas price.

Interest Expense

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

	Three Months Ended March 31,
	2013		2012
	(In thousands)
Interest costs—Senior Notes(1)	$	5,619	$	2,815
Interest costs—Bank credit facility(1)	1,741		2,844
Interest costs—other	73		92
Interest expense	$	7,433	$	5,751

(1) Including amortization of debt issue costs.

The increase in interest costs on the Senior Notes in the first quarter of 2012 compared to the first quarter of 2013 is due to the Senior Notes only being outstanding for approximately half of the quarter in 2012 compared to the full quarter in 2013. The decrease in interest costs on our bank credit facility is due to a reduced level of borrowings in 2013 compared to 2012.

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Derivative Instruments

The table below summarizes our losses (gains) on derivatives recognized during the periods indicated.

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Oil	$	4,784		$	5,733
Natural gas	2,764			(564		)
Unrealized losses on derivative instruments	$	7,548		$	5,169
Oil	$	(897	)	$	298
Natural gas	(179		)	(5,360		)
Realized gains on derivative instruments	$	(1,076	)	$	(5,062	)
Losses on derivative instruments	$	6,472		$	107

We enter into derivative instruments to manage our exposure to commodity price risk caused by fluctuations in commodity prices and to protect and provide certainty on a portion of our cash flows. We realized gains on these instruments in the first quarter of 2013 primarily due to the NYMEX WTI crude oil prices being lower than the prices in our contracts, and in the first quarter of 2012 we realized gains primarily due to the NYMEX Henry Hub natural gas prices being significantly lower than the prices in our contracts.

During the three months ended March 31, 2013, we recognized unrealized losses on our derivative instruments of $7.5 million. These unrealized losses were primarily due to the forward NYMEX Henry Hub prices being higher than the ceiling prices in for our commodity collars. We recognize changes in the fair value of outstanding derivative instruments at each balance sheet date as unrealized gains or losses. Changes in fair value are related to the volatility of the forward prices for commodities as well as to changes in the volumes of unsettled contracts between periods.

Foreign Currency Exchange

In the three months ended March 31, 2013, we recorded foreign currency exchange losses of $4.1 million. The losses primarily related to the translation of the Senior Notes from U.S. to Canadian dollars, since the Canadian dollar weakened by approximately 2% during the first quarter of 2013. In the three months ended March 31, 2012, we recorded foreign currency exchange gains of $0.3 million, primarily related to our Senior Notes, due to the Canadian dollar strengthening between February 14, 2012 and March 31, 2012.

Income Tax Expense (Recovery)

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

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Current income tax	$	—		$	—
Deferred income tax expense (recovery)	(74		)	(2,057		)
Total income tax expense (recovery)	$	(74	)	$	(2,057	)
Effective income tax rate	0%			18%

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

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We expect the public and private equity and debt capital markets to serve as another source of liquidity. 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 connection with our IPO, we entered into a tax-sharing agreement with Forest Oil Corporation (“Forest”) under which, for a two year period following a distribution of our shares by Forest to its shareholders (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.

Cash Flows

Net cash provided by operating activities, net cash used in investing activities and net cash provided by financing activities for the three months ended March 31, 2013 and 2012 were as follows.

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Net cash provided by operating activities	$	2,826		$	17,214
Net cash used in investing activities	(6,465		)	(74,600		)
Net cash provided by financing activities	3,781			57,855

Net Cash Provided by Operating Activities

Net cash provided by operating activities is primarily affected by sales volumes, commodity prices and cash-based costs. The decrease in net cash provided by operating activities in the first quarter of 2013 compared to the first quarter of 2012 was primarily due to lower revenues resulting from a reduction in net sales volumes, lower realized gains on derivative instruments due to higher commodity prices as well as higher cash-based expenditures, including interest and general and administrative expenses.

Working Capital Deficit

We had a working capital deficit of approximately $41.9 million at March 31, 2013, compared to $23.0 million at December 31, 2012. The increase was primarily due to higher accounts payable and accrued liabilities as a result of increased capital expenditures in the first quarter of 2013 compared to the fourth quarter of 2012. The increase was also partly due to the fair value of our derivative instruments being in a net liability position at March 31, 2013 compared to a net asset position at December 31, 2012 and lower accounts receivable as a result of lower revenues.

Net Cash Used In Investing Activities

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

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	Three Months Ended March 31,
	2013			2012
	(In thousands)
Exploration and development of oil and natural gas properties and leasehold acquisitions	$	(20,131	)	$	(73,688	)
Other fixed assets	(68		)	(912		)
Proceeds from divestiture of assets	13,734			—
Net cash used in investing activities	$	(6,465	)	$	(74,600	)

The cash paid for exploration, development and acquisition costs as reflected in the statements of cash flows differs from 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 decrease in net cash used in investing activities in the first quarter of 2013 compared to the first quarter of 2012 was due to lower capital expenditures as well as cash proceeds received from the divestiture of certain non-core assets in the first quarter of 2013.

Capital Expenditures

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

	Three Months Ended March 31,
	2013		2012
	(In thousands)
Exploration and development	$	29,182	$	68,977
Property acquisitions	—		7,077
General and administrative costs capitalized	2,643		1,480
Total capital expenditures	$	31,825	$	77,534

Primary factors impacting the level of our capital expenditures include oil, natural gas and NGL prices and, the volatility in these prices, the cost and availability of field services, weather disruptions, general economic and market conditions as well as our financial position, including our current liquidity. Given the recent commodity price environment, our capital program has primarily been focused on light oil development in the Evi area of Alberta. We have recently focused on reducing our level of debt and therefore our capital expenditures were lower than in 2012. In the first quarter of 2013, we drilled 6.8 net wells, completed 7.3 net wells and tied-in 7.3 net wells in the Evi area, of which 4 were drilled at a lower average drilling and completion cost than previous individual wells due to the recent application of pad drilling and batch completions.

Acquisitions and Divestitures

In February 2013, we completed the sale of non-core assets in the Herronton area of Alberta for cash proceeds after closing adjustments of approximately $13.7 million.

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Net Cash Provided by Financing Activities

The components of net cash provided by financing activities were as follows.

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Repayment of long-term debt	$	(1,819	)	$	—
Issuance of common stock	8			—
Net proceeds from issuance of long-term debt	—			192,052
Debt issuance costs	—			(1,225		)
Proceeds from bank borrowings	487,000			785,000
Repayments of bank borrowings	(483,000		)	(929,000		)
Change in bank overdrafts	1,890			11,312
Capital lease payments	(298		)	(284		)
Net cash provided by financing activities	$	3,781		$	57,855

In the first quarter of 2013, net cash provided by financing activities was primarily related to borrowings under our bank credit facility. In the first quarter of 2012, we issued Senior Notes and used the net proceeds to reduce borrowings outstanding under our bank credit facility.

Bank Credit Facility

Our bank credit facility will mature on March 18, 2016. At March 31, 2013, borrowings under our bank credit facility increased to $152.0 million from $148.0 million at December 31, 2012. As of May 3, 2013, we had $165.0 million outstanding under our bank credit facility at a weighted average interest rate of 3.81%. Availability under our bank credit facility is governed by a borrowing base, which was $185 million at May 3, 2013.

The determination of the borrowing base is made by the lenders, in their sole discretion, taking into consideration the estimated value of LPR Canada’s oil and natural gas properties in accordance with the lenders’ customary practices for oil and gas loans. The borrowing base will be redetermined semi-annually, and the available borrowing amount under our bank credit facility could increase or decrease based on such redetermination. The next scheduled redetermination of the borrowing base is expected to occur on or about November 1, 2013. In addition to the scheduled semi-annual redeterminations, Lone Pine 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.

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 a specified ratio, being 4.5 to 1.0 for all periods ending on or before June 30, 2013, and 4.0 to 1.0 for all periods thereafter (the “Financial Covenant”). For purposes of calculating this ratio, Adjusted EBITDA is reduced by the Adjusted EBITDA that has been generated by any divested property that has a transaction value in excess of US$25 million. As a result of our divestiture program, Adjusted EBITDA for the twelve months ended March 31, 2013 has been reduced from $90.7 million to $83.1 million, resulting in a ratio of 4.3 to 1.0 at March 31, 2013.

Under certain conditions, amounts outstanding under our bank credit facility may be accelerated. Bankruptcy and insolvency events with respect to Lone Pine, LPR Canada or certain of Lone Pine’s or LPR Canada’s subsidiaries will result in an automatic acceleration of the indebtedness under our bank credit facility. Subject to notice and cure periods, certain events of default under our bank credit facility will result in acceleration of the indebtedness under the facility at the option of the lenders. Such other events of default include non-payment, breach of warranty, non-performance of obligations under our bank credit facility (including the Financial

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Covenant), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control and a failure of the liens securing our bank credit facility.

Since the process for determining the borrowing base under our bank credit facility involves evaluating the estimated value of our oil and natural gas properties using pricing models determined by the lenders at that time, we believe that if there is a further decline in commodity prices, there may be a decrease in the available borrowing amount at the time of the next scheduled redetermination. A significant reduction in our borrowing base, together with the covenants and other restrictions in our bank credit facility, may reduce our ability to finance future operations or capital needs or expand our business activities. Outstanding borrowings in excess of the borrowing base must be repaid. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our bank credit facility, sell assets or issue debt or common stock. We may not be able to obtain such financing or complete such transactions on terms acceptable to us, or at all. Failure to make the required repayment could result in an event of default under the credit agreement governing our bank credit facility.

If our revenue and cash flows decrease in the future as a result of a further deterioration in domestic and global economic conditions, including a significant decline in crude oil prices or a continuation of depressed natural gas prices, or if we experience a significant reduction in our borrowing base under our bank credit facility, we may further decrease our level of capital spending. A further reduction in our capital expenditures could also result in a corresponding reduction in our cash flows, which could in turn result in a reduction of Adjusted EBITDA and a breach of the Financial Covenant described above. In the event that we are in default of the Financial Covenant under the bank credit facility, we could request a waiver of the Financial Covenant from the syndicate of banks. Should the banks deny our request to waive the covenant requirement, the outstanding borrowings under the bank credit facility would become payable on demand and would be reclassified as a component of current liabilities on our condensed consolidated balance sheets. See Part I, “Item 1A. Risk Factors” in our 2012 Annual Report for a discussion of the risks and uncertainties that affect our business and financial and operating results.

Senior Notes

At March 31, 2013 and December 31, 2012, we had outstanding US$198.0 million and US$200.0 million, respectively, 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. In March 2013, we used a portion of the proceeds from recently completed non-core asset sales to repurchase US$2.0 million of Senior Notes for $1.8 million (US$1.8 million), resulting in the recognition of a gain on debt extinguishment of approximately $0.2 million. During the period April 1, 2013 to May 3, 2013, we used additional proceeds from recently completed non-core asset sales to repurchase an additional US$3.0 million of Senior Notes for $2.8 million (US$2.7 million). We may, from time to time, make additional purchases of our Senior Notes for cash, in exchange for common stock, or for a combination of cash and common stock, in each case in open market purchases and/or privately negotiated transactions, in order to reduce future cash interest payments, as well as future amounts due at maturity or upon redemption. We will evaluate any such transactions in light of then-existing market conditions, taking into account our current liquidity and prospects for future access to capital. The amounts involved in any such transactions, individually or in the aggregate, may be material.

Future Capital Needs and Commitments

For the first two quarters of 2013, our Board of Directors has approved a capital budget of approximately $35 million focused on light oil development in the Evi area. Subject to the variability of production levels and commodity prices that impact our operating cash flows, anticipated timing of our capital projects and unanticipated expenditures, we plan to fund the first half of our 2013 capital program with operating cash flows and proceeds from previously completed divestitures of non-core assets. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on available opportunities, industry conditions, net cash provided by operating activities and the availability of capital.

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Contractual Obligations

There have not been any significant changes in our contractual obligations since December 31, 2012, other than the repurchase of Senior Notes discussed above.

Adoption of New Accounting Standards

In the first quarter of 2013, we adopted Accounting Standards Update 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities and Accounting Standards Update 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which require disclosure of both gross and net information about certain financial instruments and transactions eligible for offset in the balance sheet or subject to an agreement similar to a master netting agreement. The adoption of these amendments did not have a material impact on our financial statements.

In the first quarter of 2013, we adopted Accounting Standards Update 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures about significant amounts reclassified out of accumulated other comprehensive income. We determined that none of our amounts in accumulated other comprehensive income were significant and, therefore, the amendments did not affect our financial statements.

Future Accounting Pronouncements

In the first quarter of 2013, the US Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2013-04, Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (“ASU 2013-04”), which clarifies guidance for the recognition, measurement and disclosure of liabilities resulting from joint and several liability arrangements. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and are to be applied retrospectively. If we enter into obligations affected by ASU 2013-04, the accounting and disclosure requirements will be applied.

In the first quarter of 2013, the FASB issued Accounting Standards Update 2013-05, Parent’s Accounting for the Cumulative Translation Adjustment upon Derecognition of Certain Subsidiaries or Groups of Assets within a Foreign Entity or of an Investment in a Foreign Entity (“ASU 2013-05”), which clarifies the applicable guidance for certain transactions that result in the release of the cumulative translation adjustment into net earnings. This pronouncement is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013 and are to be applied prospectively. If we enter into any transactions affected by ASU 2013-05, the accounting and disclosure requirements will be applied.

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, as amended, (the “Securities Act”) 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;

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· our future financial condition and results of operations;

· our future revenues, cash flows and expenses;

· our plans to dispose of non-core assets;

· our access to capital and our anticipated liquidity;

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

· 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 2012 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;

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

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Net earnings (loss):	$	(28,264	)	$	(9,508	)
Add back (deduct):
Interest expense	7,433			5,751
Income tax expense (recovery)	(74		)	(2,057		)
Depreciation, depletion, and amortization	19,061			26,430
Accretion of asset retirement obligations	192			336
Unrealized losses on derivative instruments	7,548			5,169
Foreign currency exchange losses (gains)	4,068			(296		)
Stock-based compensation (stock-settled portion)	1,336			719
Adjusted EBITDA	$	11,300		$	26,544

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

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 and to protect and provide certainty on a portion of our cash flows. Under this strategy, we enter into contracts with counterparties who are participants in our bank credit facility. These arrangements, which are based on prices available in the financial markets at the time the contracts are entered into, are settled in cash and do not require physical deliveries of hydrocarbons. The estimated fair value of all our commodity derivative instruments at March 31, 2013 was a liability of approximately $3.1 million.

Swaps

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 March 31, 2013, we had entered into the following swaps.

	Natural Gas (NYMEX Henry Hub)			Oil (NYMEX WTI)
Term	MMBtu/d	Weighted Average Price per MMBtu		bbls/d	Weighted Average Price per bbl
Calendar 2013	—	—		2,000	$	98.60
Calendar 2013	—	—		500	US$		101.00
Calendar 2014	5,000	US$	4.37	250	$	93.50

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Swaptions

In connection with certain commodity swaps, we sold call options to the counterparties in exchange for receiving a premium fixed price on the commodity swaps. Our outstanding options as of March 31, 2013 were as follows.

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

	Natural Gas (NYMEX Henry Hub)
Term	Option Expiration	Underlying Swap MMBtu/d	Weighted Average Price per MMBtu
Calendar 2014	December 2013	5,000	US$	4.37

Collars

A collar agreement is similar to a swap agreement, except that we receive the difference between the floor price and the index price only if the index price is below the floor price, and we pay the difference between the ceiling price and the index price only if the index price is above the ceiling price. The outstanding commodity collars as of March 31, 2013 were as follows.

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

Long-Term Sales Contract

As of May 3, 2013, we had a delivery commitment of approximately 21,000 MMBtu/d of natural gas, which provides for a price equal to the greater of (1) the NYMEX Henry Hub price less US$1.49 per MMBtu and (2) US$1.00 per MMBtu to a buyer through October 31, 2014, unless the NYMEX Henry Hub price exceeds US$6.50 per MMBtu, at which point we share the amount of the excess equally with the buyer.

Interest Rate Risk

At March 31, 2013, we had $152 million in outstanding borrowings on our bank credit facility, with a weighted average interest rate of 3.53%. Since the interest rate on the facility is based on market rates, we are exposed to interest rate risk on these borrowings. We have not entered into any derivative financial instruments to manage this risk.

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

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Foreign Currency Exchange Rate Risk

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

We are also exposed to foreign currency exchange rate risk relating to certain of our derivative instruments and our delivery commitment of approximately 21,000 MMBtu/d of natural gas under a long-term sales contract expiring in 2014.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (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 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 March 31, 2013 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

During the three months ended March 31, 2013, there was no change in our 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 disclosure included in our 2012 Annual Report under Part I, “Item 3. Legal Proceedings.”, we are a party to various lawsuits, claims and proceedings in the ordinary course of business. These proceedings are subject to uncertainties inherent in any litigation, and the outcome of these matters is inherently difficult to predict with any certainty. We believe that the amount of any potential loss associated with these proceedings would not be material to our consolidated financial position; however, in the event of an unfavorable outcome, the potential loss could have an adverse effect on our results of operations and cash flows.

Item 1A. Risk Factors.

In addition to the information below and the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our 2012 Annual Report under Part I, “Item 1A. Risk Factors”. These risks could materially affect the Company’s business, financial condition or future results. Other than as set forth below, there has been no material change in the Company’s risk factors from those described in our 2012 Annual Report.

Our substantial indebtedness and limited liquidity could adversely affect our financial condition.

We have a significant amount of indebtedness and limited liquidity. As of March 31, 2013, we had US$198 million of 10.375% senior notes due 2017 (the “Senior Notes”) outstanding and $152 million outstanding under our bank credit facility.

Subject to the limits contained in the indenture governing the Senior Notes and our other debt instruments, we may be able to incur substantial additional debt from time to time to finance working capital, capital expenditures, investments or acquisitions or for other purposes. If we do so, the risks related to our high level of debt could intensify. Specifically, our high level of debt could have important consequences, including the following:

· making it more difficult for us to satisfy our obligations with respect to the Senior Notes and our other debt instruments;

· limiting our ability to obtain additional financing to fund future working capital, capital expenditures, investments, acquisitions or other general corporate requirements;

· requiring a substantial portion of our cash flows to be dedicated to debt service payments instead of other purposes, thereby reducing the amount of cash flows available for working capital, capital expenditures, investments, acquisitions and other general corporate purposes;

· increasing our vulnerability to general adverse economic and industry conditions;

· exposing us to the risk of increased interest rates as certain of our borrowings are at variable rates of interest;

· limiting our flexibility in planning for and reacting to changes in the oil and gas industry;

· placing us at a disadvantage compared to other, less leveraged competitors; and

· increasing our cost of borrowing.

The indenture governing the Senior Notes and our bank credit facility contain substantial operating and financial restrictions that may restrict our business and financing activities and could have a material adverse effect on our business, financial condition,

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Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

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).

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

10.2†		Settlement Agreement dated March 13, 2013 between David M. Anderson and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.35 to Form 10-K for Lone Pine Resources Inc. filed March 14, 2013 (File No. 001-35191).

10.3†		Settlement Agreement dated March 13, 2013 between Edward J. Bereznicki and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.36 to Form 10-K for Lone Pine Resources Inc. filed March 14, 2013 (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.

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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).

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

10.2†		Settlement Agreement dated March 13, 2013 between David M. Anderson and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.35 to Form 10-K for Lone Pine Resources Inc. filed March 14, 2013 (File No. 001-35191).

10.3†		Settlement Agreement dated March 13, 2013 between Edward J. Bereznicki and Lone Pine Resources Inc., incorporated by reference to Exhibit 10.36 to Form 10-K for Lone Pine Resources Inc. filed March 14, 2013 (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.

Monetary Amounts and Exchange Rate Data	ii
Part I - FINANCIAL INFORMATION	1
Item 1 - Financial Statements	1
Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	1
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012	2
Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2013 and 2012	2
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012	3
Condensed Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2013	4
Notes to Condensed Consolidated Financial Statements	5
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
Item 3 - Quantitative and Qualitative Disclosures About Market Risk	35
Item 4 - Controls and Procedures	37
Part II - OTHER INFORMATION	37
Item 1 - Legal Proceedings	37
Item 1A - Risk Factors	37
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds	38
Item 3 - Defaults Upon Senior Securities	39
Item 4 - Mine Safety Disclosures	39
Item 5 - Other Information	39
Item 6 - Exhibits	39
Signatures	41
Exhibit Index	42

	Three Months Ended March 31,		Year Ended
	2013	2012	December 31, 2012
	US$	US$	US$
Highest rate during the period	1.0164	1.0153	1.0299
Lowest rate during the period	0.9696	0.9735	0.9599
Average noon spot rate during the period(1)	0.9917	0.9989	1.0004
Rate at the end of the period	0.9846	1.0009	1.0051

	LONE PINE RESOURCES INC.
	(Registrant)

May 9, 2013	By:	/s/ TIMOTHY S. GRANGER
		Timothy S. Granger
		President and Chief Executive Officer
		(on behalf of the Registrant)


	By:	/s/ SHANE K. ABEL
		Shane K. Abel
		Vice President, Finance and Treasurer
		(Principal Financial Officer)


	By:	/s/ CHRIS J. HOWE
		Chris J. Howe
		Controller
		(Principal Accounting Officer)

101.PRE††		XBRL Presentation Linkbase Document.

101.DEF††		XBRL Taxonomy Extension Definition.