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 September 30, 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 November 4, 2013, there were 86,859,497 shares of the registrant’s common stock, par value $0.01 per share, outstanding.

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MONETARY AMOUNTS AND EXCHANGE RATE DATA

In this Quarterly Report on Form 10-Q for the three- and nine-month periods ended September 30, 2013 (the “Quarterly Report”), references to “dollars,” “$” or “Cdn$” are to Canadian dollars and references to “U.S. dollars” or “US$” are to United States dollars. The noon-day Canadian to U.S. dollar exchange rates for Cdn$1.00, as reported by the Bank of Canada, were:

	Three Months Ended September 30,		Nine Months Ended September 30,		Year Ended December 31,
	2013	2012	2013	2012	2012
	US$	US$	US$	US$	US$
Highest rate during the period	0.9768	1.0299	1.0164	1.0299	1.0299
Lowest rate during the period	0.9455	0.9790	0.9455	0.9599	0.9599
Average noon spot rate during the period(1)	0.9629	1.0047	0.9770	0.9977	1.0004
Rate at the end of the period	0.9723	1.0166	0.9723	1.0166	1.0051

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

On November 4, 2013, the noon-day exchange rate was US$0.9602 for Cdn$1.00.

iii

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Under Creditor Protection Proceedings as of September 25, 2013 — See Notes 1, 2, 6 and 13)

(Unaudited)

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

	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash	$	8,308		$	28
Accounts receivable	11,591			16,502
Derivative instruments	—			4,409
Prepaid expenses and other current assets	6,911			4,947
Total current assets	26,810			25,886
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion of $1,641,670 and $1,590,015	344,579			376,203
Unproved	146,872			148,956
Net oil and natural gas properties	491,451			525,159
Other property and equipment, net of accumulated depreciation and amortization of $13,379 and $10,658	62,523			65,096
Net property and equipment	553,974			590,255
Other assets	2,223			6,662
	$	583,007		$	622,803
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Bank overdraft	$	—		$	4,872
Accounts payable and accrued liabilities	—			32,468
Accrued interest	—			7,742
Current portion of long-term debt - secured	182,477			—
Capital lease obligation - secured	1,309			1,217
Other current liabilities	983			2,564
Total current liabilities not subject to compromise	184,769			48,863

Current liabilities subject to compromise (Note 2)	222,588			—

Long-term debt	—			340,310
Asset retirement obligations	13,982			12,839
Capital lease obligation — secured	2,547			4,521
Other liabilities	1,222			1,308
Total long-term liabilities not subject to compromise	17,751			358,978
Stockholders’ equity:
Common stock, 86,859,497 and 85,192,955 shares issued and outstanding	852			835
Capital surplus	986,450			984,438
Accumulated deficit	(829,527		)	(770,494		)
Accumulated other comprehensive income	124			183
Total stockholders’ equity	157,899			214,962
	$	583,007		$	622,803

See accompanying notes to condensed consolidated financial statements.

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LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Under Creditor Protection Proceedings as of September 25, 2013 — See Notes 1, 2, 6 and 13)

(Unaudited)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012

Revenues:
Oil and natural gas	$	26,366		$	38,188		$	86,254		$	124,937
Interest and other	6			8			11			18
Total revenues	26,372			38,196			86,265			124,955
Costs, expenses and other:
Lease operating expenses	7,732			11,961			24,651			40,570
Production and property taxes	703			831			1,842			2,516
Transportation and processing	3,035			3,510			9,716			11,974
General and administrative	2,486			4,050			14,706			13,996
Depreciation, depletion and amortization	17,228			30,236			54,473			88,548
Ceiling test write-down of oil and natural gas properties	—			142,879			—			271,749
Interest expense	7,674			8,181			22,716			22,174
Accretion of asset retirement obligations	337			350			861			1,027
Foreign currency exchange (gains) losses	(4,383		)	(6,996		)	6,613			(3,023		)
Losses (gains) on derivative instruments	4,233			7,278			7,634			(10,990		)
Other, net	232			138			78			190
Reorganization costs	2,082			—			2,082			—
Total costs, expenses and other	41,359			202,418			145,372			438,731
Loss before income taxes	(14,987		)	(164,222		)	(59,107		)	(313,776		)
Income tax recovery	—			(39,921		)	(74		)	(74,932		)
Net loss	$	(14,987	)	$	(124,301	)	$	(59,033	)	$	(238,844	)
Basic and diluted loss per common share	$	(0.17	)	$	(1.46	)	$	(0.69	)	$	(2.81	)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Under Creditor Protection Proceedings as of September 25, 2013 — See Notes 1, 2, 6 and 13)

(Unaudited)

(In thousands of Canadian dollars)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012

Net loss	$	(14,987	)	$	(124,301	)	$	(59,033	)	$	(238,844	)
Other comprehensive income (loss):
Amortization of accumulated actuarial loss, net of tax	5			4			(59		)	14
Total other comprehensive income (loss)	5			4			(59		)	14
Comprehensive loss	$	(14,982	)	$	(124,297	)	$	(59,092	)	$	(238,830	)

See accompanying notes to condensed consolidated financial statements.

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LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Under Creditor Protection Proceedings as of September 25, 2013 — See Notes 1, 2, 6 and 13)

(Unaudited)

(In thousands of Canadian dollars)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012

Operating activities:
Net loss	$	(14,987	)	$	(124,301	)	$	(59,033	)	$	(238,844	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	17,228			30,236			54,473			88,548
Ceiling test write-down of oil and natural gas properties	—			142,879			—			271,749
Amortization of deferred costs	660			648			1,921			1,750
Accretion of asset retirement obligations	337			350			861			1,027
Deferred income tax recovery	—			(39,921		)	(74		)	(74,932		)
Unrealized foreign currency exchange (gains) losses	(4,545		)	(6,963		)	6,515			(3,031		)
Unrealized losses (gains) on derivative instruments	(254		)	15,412			4,409			11,041
Stock-based compensation	231			1,141			3,009			2,861
Other, net	864			327			(2,928		)	(390		)
Changes in operating assets and liabilities:
Accounts receivable	132			1,587			4,913			11,938
Prepaid expenses and other current assets	187			(423		)	156			765
Accounts payable and accrued liabilities	(1,544		)	4,228			(9,838		)	(17,524		)
Accrued interest and other liabilities	4,813			(5,307		)	5,046			2,843
Net cash provided by operating activities	3,122			19,893			9,430			57,801
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	(2,877		)	(30,196		)	(39,965		)	(160,451		)
Other fixed assets	(65		)	(425		)	(148		)	(2,074		)
Proceeds from divestiture of assets, net	28			8,238			16,208			8,518
Net cash used in investing activities	(2,914		)	(22,383		)	(23,905		)	(154,007		)
Financing activities:
Repayment of long-term debt	—			—			(4,589		)	—
Net proceeds from issuance of long-term debt	—			—			—			192,052
Debt issuance costs	(189		)	—			(275		)	(1,295		)
Proceeds from bank borrowings	208,477			924,000			1,228,477			2,390,000
Repayments of bank borrowings	(204,000		)	(916,000		)	(1,194,000		)	(2,484,000		)
Change in bank overdrafts	—			(5,847		)	(4,872		)	454
Issuance of common stock	2			—			17			—
Capital lease payments	(1,281		)	(369		)	(1,882		)	(1,107		)
Other, net	27			1			(121		)	1
Net cash provided by financing activities	3,036			1,785			22,755			96,105
Net increase (decrease) in cash	3,244			(705		)	8,280			(101		)
Cash at beginning of period	5,064			880			28			276
Cash at end of period	$	8,308		$	175		$	8,308		$	175

See accompanying notes to condensed consolidated financial statements.

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LONE PINE RESOURCES INC.

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Under Creditor Protection Proceedings as of September 25, 2013 — See Notes 1, 2, 6 and 13)

(Unaudited)

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

										Accumulated
										Other			Total
	Common Stock			Capital			Accumulated			Comprehensive			Stockholders’
	Shares	Amount		Surplus			Deficit			Income(Loss)			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	1,666	17		3,449			—			—			3,466
Amortization of stock-based compensation	—	—		2,608			—			—			2,608
Capital surplus related to vested stock-based compensation	—	—		(4,045		)	—			—			(4,045		)
Comprehensive income (loss):
Net loss	—	—		—			(59,033		)	—			(59,033		)
Other comprehensive (loss)	—	—		—			—			(59		)	(59		)
Balances at September 30, 2013	86,859	$	852	$	986,450		$	(829,527	)	$	124		$	157,899

See accompanying notes to condensed consolidated financial statements.

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certain holders of LPR Canada’s outstanding 10.375% Senior Notes due 2017 (the “Senior Notes”), who in the aggregate hold approximately 75% of the Senior Notes (the “Supporting Noteholders”). Pursuant to the Support Agreements, the Company has agreed to pursue a restructuring through a plan of compromise and arrangement under the CCAA, which will be subject to creditor and CCAA Court approval, and ancillary proceedings under Chapter 15 of the United States Bankruptcy Code for recognition of the CCAA proceedings. Subject to the terms and conditions of the Support Agreement, each of the Supporting Noteholders has agreed to support the restructuring plan and vote their claims under the Senior Notes in favor of its approval at any meeting of creditors to be held for that purpose.

Event of Default, Stay and Operation and Implication of the Creditor Protection Proceedings

The commencement of the Creditor Protection Proceedings constituted an event of default with respect to the following debt instruments:

· Indenture, dated February 14, 2012, among LPR Canada, as issuer, the other loan parties thereto, as guarantors, and U.S. National Bank Association, as trustee, under which approximately US$207.4 million principal and accrued interest was outstanding on the Senior Notes as of September 25, 2013; and

· Credit Agreement, dated March 18, 2011, among the Company, LPR Canada, JPMorgan Chase Bank, N.A., Toronto Branch as Administrative Agent and the other agents and lenders party thereto, as amended, under which approximately Cdn$180.0 million was outstanding as of September 25, 2013.

As a result of such event of default, all obligations under such instruments, by the terms thereof, became due and payable. However, under the CCAA and the United States Bankruptcy Code, initiation of the Creditor Protection Proceedings automatically stays most actions against a debtor, including most actions to collect indebtedness incurred prior to the initial CCAA filing date or to exercise control over property of a debtor. Accordingly, although commencement of the Creditor Protection Proceedings triggered defaults under these instruments, any efforts to enforce such payment obligations are stayed and the creditors’ rights of enforcement in respect thereof are subject to the applicable provisions of the CCAA and the United States Bankruptcy Code. Absent an order of the CCAA Court, substantially all pre-filing liabilities are subject to compromise under a plan of compromise and arrangement. As a result of the Creditor Protection Proceedings, the realization of assets and the satisfaction of liabilities are subject to uncertainty. For example, the Company may, subject to the terms of the Support Agreements and approval of the CCAA Court, sell or otherwise dispose of assets and liquidate or compromise liabilities for amounts other than those reflected in the consolidated financial statements. Further, a confirmed plan of compromise and arrangement may materially change the amounts and classifications in the Company’s historical consolidated financial statements.

In connection with the initial order of the CCAA Court (the “CCAA Initial Order”), the Company received approval from the CCAA Court to pay or otherwise honor certain pre-filing obligations generally designed to stabilize the Company’s operations including payment to certain critical suppliers and joint venture partners. The Company is paying, and intends to continue paying, claims arising after the initial CCAA filing date in the ordinary course of business. The Company has retained, pursuant to the Initial CCAA Initial Order, legal and financial professionals to advise the Company on the Creditor Protection Proceedings and certain other professionals to provide services and advice to the Company in the ordinary course of business. From time to time, the Company may seek CCAA Court approval to retain additional professionals.

The Company has incurred and expects to continue to incur significant costs associated with the restructuring and the Creditor Protection Proceedings. The amount of these expenses is expected to significantly affect the Company’s financial position and results of operations, but the Company cannot accurately predict the effect the Creditor Protection Proceedings will have on the Company’s business at this time.

Plan of Compromise and Arrangement

For the Company to successfully emerge from the Creditor Protection Proceedings, it must obtain the CCAA Court’s approval of a plan of compromise and arrangement, which will enable the Company to transition from the Creditor Protection Proceedings into ordinary course operations out of creditor protection. In connection with the plan of compromise and arrangement, the Company must also obtain a new credit facility, or “exit financing.” The Company’s ability to obtain such approval and financing will depend on, among other things, the timing and outcome of various ongoing matters in the Creditor Protection Proceedings. A plan of compromise and arrangement determines the rights and treatment of claims of various creditors and security holders, and is subject to the ultimate outcome of negotiations and CCAA Court decisions ongoing through the date on which the plan of compromise and arrangement is sanctioned.

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Although the Company has not filed a plan of compromise or arrangement or a related disclosure statement with the CCAA Court, the Company intends to propose a plan in accordance with the terms of the Support Agreements (the “Proposed Plan”). The Proposed Plan provides for the cancellation of all outstanding shares of Lone Pine common stock, the conversion of all Senior Notes into new common shares, and a new equity investment of US$100 million by holders of the Senior Notes (“Noteholders”) through an offering to eligible affected creditors (including the Noteholders), of convertible preferred shares (the “Share Offering”). The Company anticipates filing the Proposed Plan on or before November 29, 2013, unless otherwise extended by agreement of the Supporting Noteholders. Following submission of the Proposed Plan, the Company expects to take all actions necessary to obtain approval for it from the Company’s affected creditors and the CCAA Court on or before December 31, 2013. Under the Support Agreement, the outside date for implementation of the Proposed Plan is January 31, 2014, as contemplated by the terms of the Support Agreement. Generally, the Proposed Plan will provide, among other things, mechanisms for (i) settlement of claims against the Company; (ii) treatment of the Company’s existing equity and debt holders (including those treatments noted above); (iii) provision for exit financing; and (iv) certain corporate governance and administrative matters pertaining to the reorganized company.

The Company continues to have ongoing discussions with the Supporting Noteholders and PricewaterhouseCoopers Inc., in its capacity as the CCAA Court-appointed monitor of Lone Pine regarding the Proposed Plan and will continue to do so until the Proposed Plan is filed with the CCAA Court. The Proposed Plan is subject to revision prior to submission to the CCAA Court based upon those continuing discussions, and thereafter in response to those continuing discussions as well as creditor claims and objections and the requirements of the CCAA Court or the CCAA. There can be no assurance that the Company will be able to secure approval of the Proposed Plan by the CCAA Court, or that the Proposed Plan will be accepted by the Company’s creditors.

Financing During Pendency of the Creditor Protection Proceedings

During the pendency of the Creditor Protection Proceedings, the Company is funding operations pursuant to an order of the CCAA Court permitting the Company’s use of cash balances, working capital and available borrowings under a $10 million DIP Credit Facility (as defined and discussed below). As of November 4, 2013, the Company had not borrowed any amounts under the DIP Credit Facility.

Since approval of the DIP Credit Facility, the Company has focused on executing its strategic and operating initiatives and ensuring the smooth transition and maintenance of its business in creditor protection. However, there can be no assurance that cash on hand, cash generated through operations and other available funds will be sufficient to meet the Company’s restructuring or ongoing cash needs or that the Company will remain in compliance with all the necessary terms and conditions of the DIP Credit Agreement (as defined below) or that the lending commitments under the DIP Credit Agreement will not be terminated by the lenders.

Going Concern

The Company’s financial liquidity condition and the resulting commencement of the Creditor Protection Proceedings cast substantial doubt about the Company’s ability to continue as a going concern. Due to ongoing liquidity issues, the Company has failed to meet certain financial obligations and liabilities, including a significant interest payment on the Senior Notes. The Company is dependent on the outcome of the Creditor Protection Proceedings and requires additional financing in order to finance its business activities on an ongoing basis both during and following the Creditor Protection Proceedings.

The accompanying condensed consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the 12-month period following the date of these consolidated financial statements. The Company’s ability to continue as a going concern is contingent upon its ability to comply with the financial and other covenants contained in the DIP Credit Agreement, the CCAA Court’s approval of a plan of compromise and arrangement and the Company’s ability to successfully implement such plan and obtain exit financing, among other things. As a result of the Creditor Protection Proceedings, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating under the Creditor Protection Proceedings, the Company may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the terms of the Support Agreements and the approval of the CCAA Court or as otherwise permitted in the ordinary course of business (and subject to restrictions contained in the DIP Credit Agreement and the Support Agreements), for amounts other than those reflected in the accompanying condensed consolidated financial statements. Further, the plan of compromise and arrangement could materially change the amounts and classifications of assets and liabilities reported in the historical consolidated financial statements. The accompanying condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amounts, or the amount and classification of certain liabilities that may result should the Company be unable to continue as a going concern or as a consequence of the Creditor Protection Proceedings.

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Financial Reporting in Reorganization

As outlined in Basis of Presentation (above), liabilities that are subject to compromise primarily represent unsecured pre-CCAA filing obligations of the Company that may be subject to impairment and settlement at lesser amounts through the Creditor Protection Proceedings. Under the terms of the CCAA Initial Order, dated September 25, 2013, and orders of the U.S. Bankruptcy Court, any actions to enforce or otherwise effect payment of these liabilities was stayed during the Creditor Protection Proceedings. As at September 30, 2013, these liabilities were classified separately as liabilities subject to compromise on the Company’s consolidated balance sheet at their unadjusted carrying values. The CCAA claim process is currently in early stages of progress. The extent of compromise, if any, is not determinable and is subject to future events, including completion of the CCAA claim process and the Creditor Protection Proceedings. Post-CCAA filing liabilities as at September 30, 2013 that are subject to the Creditor Protection Proceedings have not been segregated by the Company on the consolidated balance sheet due to the amounts not being material for the six-day period ended September 30, 2013.

As at September 30, 2013, current liabilities subject to compromise consisted of the following:

Accounts payable and accrued liabilities	$	15,101
Senior Notes	194,831
Pre-filing accrued interest on Senior Notes	12,656

Total current liabilities subject to compromise	$	222,588

During the Creditor Protection Proceedings, the Company has continued, and expects to continue, with its day-to-day operations, and employee obligations and any trade payables incurred after September 25, 2013 are expected to be paid or satisfied in the ordinary course.

The Company has reclassified all indebtedness outstanding under the Existing Credit Facility (as defined below) as a current liability in this Quarterly Report. As a result of the Creditor Protection Proceedings and in accordance with counterparty agreements, all financial instruments and related agreements were terminated with early settlements effective on or about September 26, 2013. The resulting realized loss in the amount of $2.5 million has been recognized in the third quarter and is classified as long-term debt - current portion as at September 30, 2013 pursuant to the provisions of the Existing Credit Facility.

Exchange Listing

Trading in the Company’s common stock on the Toronto Stock Exchange (“TSX”) was halted on September 25, 2013, and the Company’s common stock was subsequently delisted on October 31, 2013. Trading in the Company’s common stock on the New York Stock Exchange (“NYSE”) was suspended on September 16, 2013, and the Company’s common stock was subsequently removed from listing and registration on the NYSE on October 22, 2013. As a result of the Company’s financial position and the Creditor Protection Proceedings, the Company believes that its outstanding equity securities will likely have no value and will be canceled under any plan of compromise and arrangement including the Proposed Plan. As a result, the Company urges that caution be exercised with respect to existing and future investments in any of its currently outstanding securities.

See also Part I, “Item 2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part II, “Item 1A — Risk Factors”.

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(5) PROPERTY AND EQUIPMENT

Full Cost Method of Accounting

The Company uses the full cost method of accounting for oil and natural gas activities. The Company capitalizes all costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, dry holes and overhead directly related to exploration and development activities), and the fair value of estimated future costs of site restoration, dismantlement and abandonment activities.

Under the full cost method, the Company performs a ceiling test calculation each quarter using prices that are based on the average of the first-day-of-the-month prices during the 12-month period prior to the reporting date. The full cost ceiling test is a limitation on capitalized costs prescribed by SEC Regulation S-X Rule 4-10. If the net capitalized costs for a cost center exceed the sum of SEC-prescribed calculated components, a ceiling test write-down is recognized to the extent of the excess capitalized costs.

No write-down was required for the three and nine months ended September 30, 2013. However, during 2012, as a result of a decline in the 12-month average trailing natural gas price, the Company’s internal estimate of its proved undeveloped natural gas volumes decreased significantly at June 30 and September 30, 2012 compared to December 31, 2011. This decrease in natural gas volumes reduced the Company’s internal estimate of the present value of future net revenue from proved reserves and resulted in the Company recognizing ceiling test write-downs of $142.9 million and $271.7 million before tax for the three and nine months ended September 30, 2012, respectively.

(6) LONG-TERM DEBT

The commencement of the Creditor Protection Proceedings constituted an event of default with respect to the following debt instruments:

· Indenture governing the Senior Notes, dated February 14, 2012, among LPR Canada, as issuer, the other loan parties thereto, as guarantors, and U.S. National Bank Association, as trustee, under which approximately US$207.4 million principal and accrued interest was outstanding on the Senior Notes as of September 25, 2013; and

In addition, all outstanding derivative instruments were terminated at the counterparties’ option upon the commencement of the Creditor Protection Proceedings. The net loss on the termination of these contracts has been applied to the outstanding Existing Credit Facility balance effective as of the date of termination.

As a result of the event of default, all obligations under these instruments, by the terms thereof, became due and payable. Any efforts to enforce such payment obligations are stayed as a result of the commencement of the Creditor Protection Proceedings and the creditors’ rights of enforcement in respect thereof are subject to the applicable provisions of the CCAA and the United States Bankruptcy Code. Accordingly, all other Existing Credit Facility covenants as at September 30, 2013 are no longer enforceable.

All indebtedness outstanding under the Existing Credit Facility is classified as a current liability in this Quarterly Report. The Senior Notes are included in liabilities subject to compromise as at September 30, 2013. See also Note 2 — Creditor Protection Proceedings, Liquidity and Going Concern.

As at the dates indicated, the components of the Company’s long-term debt and current portions were as follows.

	At September 30, 2013									At December 31, 2012
	(In thousands)
	Principal			Unamortized Discount			Total			Principal		Unamortized Discount		Total
Existing Credit Facility — secured	$	182,477		$	—		$	182,477		$	148,000	$	—	$	148,000
Senior Notes — subject to compromise	200,558			5,727			194,831			198,985		6,675		192,310
	383,035			5,727			377,308			346,985		6,675		340,310
Current portion of long-term debt	(182,477		)	—			(182,477		)	—		—		—

Current portion of long-term debt— liabilities subject to compromise (Note 2)	(200,558		)	(5,727		)	(194,831		)	—		—		—
Long-term debt	$	—		$	—		$	—		$	346,985	$	6,675	$	340,310

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Existing Credit Facility - Secured

Lone Pine maintains a $500 million credit facility (the “Existing Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. The Existing Credit Facility was to mature on March 18, 2016 and its availability was governed by a borrowing base. Acceleration of the maturity of the indebtedness under the Existing Credit Facility occurs automatically in the case of a bankruptcy or insolvency event. Effective September 25, 2013 and upon commencement of the Creditor Protection Proceedings, maturity of the Existing Credit Facility was accelerated, which led to a cross default under the Indenture and an acceleration of the maturity of the Senior Notes, and the Company has no further ability to borrow thereunder. See also Note 2 — Creditor Protection Proceedings, Liquidity and Going Concern.

The borrowing base under the Existing Credit Facility was $185 million at September 30, 2013 (December 31, 2012 - $275 million). At September 30, 2013, the Company had $183 million outstanding (including financial derivative termination settlements) (December 31, 2012 - $148 million), at a weighted average interest rate of 4.7%.

Senior Notes — Subject to Compromise

DIP Credit Facility — Subject to Creditor Protection Proceedings

In connection with the Creditor Protection Proceedings and in order to provide liquidity during the Creditor Protection Proceedings, on October 24, 2013, the Company and LPR Canada entered into a credit agreement (the “DIP Credit Agreement”) with respect to a $10 million debtor-in-possession credit facility (the “DIP Credit Facility”). Certain of the lenders under the Existing Credit Facility are lenders under the DIP Credit Facility, and the agent under the Existing Credit Facility serves as administrative agent under the DIP Credit Facility. Pursuant to the terms of the DIP Credit Agreement, (i) the lenders agreed to lend LPR Canada up to $10 million, which loans will bear interest at the Canadian Prime Rate (as defined in the DIP Credit Agreement), plus 5.00%, (ii) the Company and each Restricted Subsidiary (as defined in the DIP Credit Agreement) agreed to guarantee LPR Canada’s obligations thereunder, and (iii) the Obligations (as defined in the DIP Credit Agreement) are and shall be at all times secured by the liens in all collateral created by the DIP Charge (as defined in the DIP Credit Agreement) and all such liens shall be first priority liens subject only to the Administration Charge (as defined in the DIP Credit Agreement). LPR Canada is obligated to pay the agent an upfront fee of 2% and the lenders a commitment fee of 0.75% of unutilized commitments. Proceeds of loans under the DIP Credit Facility may be used to provide for working capital, capital expenditures and other expenditures during the course of the Creditor Protection Proceedings, in accordance with the terms of the DIP Credit Agreement. The DIP Credit Facility matures on March 25, 2014.

In addition to customary affirmative covenant obligations, the DIP Credit Agreement provides for certain information delivery requirements to each lender and the agent, including (i) quarterly and annual financial statements, (ii) weekly delivery of actual receipts and disbursements with a variance analysis against the cash flow model most recently filed with the CCAA Court and (iii) monthly financial results. LPR Canada is also obligated to obtain, on or before November 13, 2013, a fully executed commitment letter from a replacement lender (or lenders) providing for credit facilities, which together with the proceeds of the Share Offering contemplated in the Proposed Plan, would be sufficient to repay in full all obligations outstanding under the Existing Credit Facility.

The DIP Credit Agreement also contains a financial covenant, which requires that for any particular week in which any amounts are outstanding under the DIP Credit Agreement, at the end of such week there will be no negative variance in LPR Canada’s actual net change in cash flow from that set out in the cash flow model most recently filed with the CCAA Court in excess of: (i) for such week, the greater of $500,000 or 15% and (ii) in the aggregate from the date of the CCAA Initial Order through such week, the greater of $1,000,000 and 15%; provided, however, that any newly filed cash flow model shall not, absent approval of lenders holding at least 66 2/3%

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of the loan commitments, contain a Material Adverse Change (as defined in the DIP Credit Agreement) in aggregate revenues or expenses from the cash flow model most recently filed with the CCAA Court.

The DIP Credit Agreement also contains customary negative covenants restricting certain of the Company and LPR Canada’s activities, including restrictions on their ability to incur indebtedness, incur liens, consummate certain fundamental changes, make investments, dispose of assets, enter into sale and lease transactions, enter into hedging agreements, make restricted payments and enter into transactions with affiliates. Furthermore, the DIP Credit Agreement contains customary events of default, which include a plan of compromise and arrangement not being sanctioned by the CCAA Court prior to December 31, 2013 and certain other insolvency proceeding-related events of default. LPR Canada’s ability to access the commitments under the DIP Credit Facility may be impaired in the event that it or the Company does not comply with the covenant requirements or if it defaults on its obligations under the DIP Credit Agreement.

(7) DERIVATIVE INSTRUMENTS

Commodity Derivatives

Lone Pine has historically entered into derivative instruments to manage its exposure to commodity price risk caused by fluctuations in commodity prices, which have served to protect and provide certainty on a portion of the Company’s cash flows. Lone Pine’s commodity derivative instruments have generally served as effective economic hedges of commodity price exposure. Lone Pine elected not to designate its derivatives as hedging instruments for accounting purposes and recognized all changes in fair value of its derivative instruments as unrealized gains or losses on derivative instruments in the Condensed Consolidated Statements of Operations.

Effective September 25, 2013 in conjunction with the Creditor Protection Proceedings (see Note 2), all derivative instrument agreements were terminated, and final realized settlements have been recognized in this Quarterly Report.

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 September 30,						Nine Months Ended September 30,
	2013			2012			2013		2012
	(In thousands)
Realized (gains) losses on derivative instruments	$	4,487		$	(8,134	)	$	3,225	$	(22,031	)
Unrealized (gains) losses on derivative instruments	(254		)	15,412			4,409		11,041
Losses (gains) on derivative instruments	$	4,233		$	7,278		$	7,634	$	(10,990	)

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(8) 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. The carrying amounts and fair values of Lone Pine’s financial instruments are summarized below.

	Fair Value	At September 30, 2013				At December 31, 2012
	Hierarchy Level	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
Assets:
Cash	—	$	8,308	$	8,308	$	28	$	28
Accounts receivable	—	11,591		11,591		16,502		16,502
Derivative instruments	2	—		—		5,703		5,703
Liabilities:
Bank overdraft	—	—		—		4,872		4,872
Accounts payable and accrued liabilities	—	—		—		32,468		32,468
Accrued interest	—	—		—		7,742		7,742
Derivative instruments	2	—		—		1,294		1,294
Current portion of long-term debt (Existing Credit Facility)	2	182,477		182,477		—		—

Current liabilities subject to compromise:
Accounts payable and accrued liabilities	—	15,101		15,101		—		—
Accrued interest	—	12,656		12,656		—		—
Current portion of long-term debt (Senior Notes)	1	194,831		120,903		—		—
Total current liabilities subject to compromise		222,588		148,660		—		—

Long-term debt:
Existing Credit Facility	2	—		—		148,000		148,000
Senior Notes	1	—		—		192,310		186,046
Total long-term debt		—		—		340,310		334,046
Capital lease obligation	2	3,856		3,856		5,738		5,738

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(9) LOSS PER SHARE

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Net loss	$	(14,987	)	$	(124,301	)	$	(59,033	)	$	(238,844	)
Net earnings attributable to participating securities	—			—			—			—
Net loss attributable to common stock for basic and diluted earnings per share	$	(14,987	)	$	(124,301	)	$	(59,033	)	$	(238,844	)
Weighted average number of shares of common stock outstanding during the period for basic earnings per share	86,584			85,016			86,089			85,008
Dilutive effects of potential shares of common stock	—			—			—			—
Weighted average number of shares of common stock outstanding during the period, including the effects of dilutive potential shares of common stock, for diluted earnings per share	86,584			85,016			86,089			85,008
Basic loss per share of common stock	$	(0.17	)	$	(1.46	)	$	(0.69	)	$	(2.81	)
Diluted loss per share of common stock	$	(0.17	)	$	(1.46	)	$	(0.69	)	$	(2.81	)

At September 30, 2013, approximately 1.2 million (September 30, 2012 — 1.8 million) potential shares of common stock were excluded from the diluted loss per share of common stock calculation as the effect was anti-dilutive.

(10) STOCK-BASED COMPENSATION

The following table reconciles the change in number of units outstanding for each of the Company’s long-term incentive plans for the nine months ended September 30, 2013.

	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	636,166		4,790,081		2,671,171		—		271,740		8,369,158
Vested	(910,380	)	(1,631,977	)	(1,254,330	)	—		(67,935	)	(3,864,622	)
Forfeited	(96,669	)	(420,786	)	—		(67,224	)	—		(584,679	)
Cancelled	—		—		—		(255,188	)	—		(255,188	)
Outstanding as of September 30, 2013	608,647		3,137,869		1,416,841		322,294		271,740		5,757,391
Outstanding as of September 30, 2012	1,014,132		460,208		—		646,856		67,935		2,189,131

At September 30, 2013, the Company had 322,294 stock options outstanding, of which 112,538 had vested with the majority being exercisable no later than the first quarter of 2017.

Subsequent to September 30, 2013, the Company’s common stock was delisted on both the NYSE and TSX. Accordingly, stock based compensation programs are subject to future amendments or cancellation, and are currently being evaluated. An estimated related non-cash expense of approximately $3.0 million for unrecognized stock-based compensation amounts at September 30, 2013 is expected to be recorded in a future period.

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(11) EMPLOYEE TERMINATION BENEFITS

In the first half of 2013, Lone Pine implemented a cost-reduction measure to reduce its ongoing general and administrative expenses. As a result, in the nine months ended September 30, 2013, Lone Pine recorded charges totaling approximately $3.2 million in general and administrative expenses in the Condensed Consolidated Statements of Operations for wages and benefits related to employee terminations, including cash payments of approximately $2.7 million.

(12) INCOME TAXES

The Company’s combined Canadian federal and provincial statutory income tax rate was 25% for each of the three- and nine-month periods ended September 30, 2013 and 2012. The effective income tax rate for each of the three- and nine-month periods ended September 30, 2013 was 0% (2012 — 24% and 24%, respectively).

(13) REORGANIZATION COSTS

The Company has segregated certain costs that are directly related to the Creditor Protection Proceedings in this Quarterly Report in accordance with ASC 852. For the three and nine months ended September 30, 2013, the total reorganization costs were $2.1 million and was comprised of $1.8 million of professional fees and $0.3 million for the Retention Program (as defined below). As at September 30, 2013 approximately $1.1 million of reorganization costs is included in accrued liabilities.

On September 11, 2013, the compensation committee of the board of directors of the Company implemented an employee retention program (the “Retention Program”) for key employees of LPR Canada, including the Company’s named executive officers. The Retention Program was put in place following staff reductions completed in the first half of 2013, and is intended to incentivize key employees and executive officers to remain employed with LPR Canada until at least January 31, 2014. Pursuant to the Retention Program, eligible participants will receive a cash retention award on the earlier of (1) January 31, 2014 and (2) the date on which the Company terminates the participant’s employment without cause (as determined in accordance with the Company’s policies and applicable law). In the event that a retention award is paid prior to January 31, 2014 as a result of a termination without cause, the amount payable will be prorated to the date of termination. On September 25, 2013, the Retention Program was approved in the CCAA Initial Order.

(14) 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 6 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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CONDENSED CONSOLIDATING BALANCE SHEET

(In thousands of Canadian dollars)

	At September 30, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries		Subsidiary Issuer			Eliminations			Consolidated

ASSETS
Current assets:
Cash	$	30		$	—	$	8,278		$	—		$	8,308
Accounts receivable	1,099			492		11,214			(1,214		)	11,591
Prepaid expenses and other current assets	423			—		6,488			—			6,911
Total current assets	1,552			492		25,980			(1,214		)	26,810
Property and equipment, at cost:
Oil and natural gas properties, full cost method of accounting:
Proved, net of accumulated depletion	—			—		344,579			—			344,579
Unproved	—			—		146,872			—			146,872
Net oil and natural gas properties	—			—		491,451			—			491,451
Other property and equipment, net of accumulated depreciation and amortization	—			—		62,523			—			62,523
Net property and equipment	—			—		553,974			—			553,974
Investment in affiliate	55,356			58,063		—			(113,419		)	—
Other assets	—					2,223			—			2,223
	$	56,908		$	58,555	$	582,177		$	(114,633	)	$	583,007
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	—		$	—	$	—		$	—		$	—
Current portion of long-term debt — secured	—			—		182,477			—			182,477
Capital lease obligation - secured	—			—		1,309			—			1,309
Other current liabilities	33			—		950			—			983
Total current liabilities not subject to compromise	33			—		184,736			—			184,769
Current liabilities subject to compromise (note 2)	184			—		223,618			(1,214		)	222,588
Long-term debt	—			—		—			—			—
Asset retirement obligations	—			—		13,982			—			13,982
Capital lease obligation - secured	—			—		2,547			—			2,547
Other liabilities	23			—		1,199			—			1,222
Total long-term liabilities not subject to compromise	23			—		17,728			—			17,751
Stockholders’ equity:
Common stock	852			39,135		832,750			(871,885		)	852
Capital surplus	367,003			19,027		143,138			457,282			986,450
Retained earnings (accumulated deficit)	(311,592		)	393		(819,512		)	301,184			(829,527		)
Accumulated other comprehensive income (loss)	405			—		(281		)	—			124
Total stockholders’ equity	56,668			58,555		156,095			(113,419		)	157,899
	$	56,908		$	58,555	$	582,177		$	(114,633	)	$	583,007

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CONDENSED CONSOLIDATING BALANCE SHEET

(In thousands of Canadian dollars)

	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 - secured	—			—		1,217			—			1,217
Other current liabilities	164			—		2,400			—			2,564
Total current liabilities not subject to compromise	449			—		51,725			(3,311		)	48,863
Current liabilities subject to compromise	—			—		—			—			—

Long-term debt	—			—		340,310			—			340,310
Asset retirement obligations	—			—		12,839			—			12,839
Capital lease obligation - secured	—			—		4,521			—			4,521
Other liabilities	107			—		1,201			—			1,308
Total long-term liabilities not subject to compromise	107			—		358,871			—			358,978
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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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(In thousands of Canadian dollars)

	Three Months Ended September 30, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Revenues:
Oil and natural gas	$	—		$	—		$	26,366		$	—		$	26,366
Interest and other	—			—			6			—			6
Total revenues	—			—			26,372			—			26,372
Costs, expenses and other:
Lease operating expenses	—			—			7,732			—			7,732
Production and property taxes	—			—			703			—			703
Transportation and processing	—			—			3,035			—			3,035
General and administrative	839			5			1,642			—			2,486
Depreciation, depletion and amortization	—			—			17,228			—			17,228
Interest expense	—			—			7,674			—			7,674
Accretion of asset retirement obligations	—			—			337			—			337
Foreign currency exchange losses (gains)	20			10			(4,413		)	—			(4,383		)
Loss (gains) on derivative instruments	—			—			4,233			—			4,233
Equity loss in affiliates	14,128			—			—			(14,128		)	—
Reorganization costs	—			—			2,082						2,082
Other, net	—			—			232			—			232
Total costs, expenses and other	14,987			15			40,485			(14,128		)	41,359
Earnings (loss) before income taxes	(14,987		)	(15		)	(14,113		)	14,128			(14,987		)
Income tax expense	—			—			—			—			—
Net earnings (loss)	$	(14,987	)	$	(15	)	$	(14,113	)	$	14,128		$	(14,987	)

CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands of Canadian dollars)

	Three Months Ended September 30, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations		Consolidated

Net earnings (loss)	$	(14,987	)	$	(15	)	$	(14,113	)	$	14,128	$	(14,987	)
Other comprehensive income:
Amortization of accumulated actuarial loss, net of tax	—			—			5			—		5
Total other comprehensive income	—			—			5			—		5
Comprehensive (loss) income	$	(14,987	)	$	(15	)	$	(14,108	)	$	14,128	$	(14,982	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(In thousands of Canadian dollars)

	Three Months Ended September 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Revenues:
Oil and natural gas	$	—		$	—		$	38,188		$	—		$	38,188
Interest and other	—			—			8			—			8
Total revenues	—			—			38,196			—			38,196
Costs, expenses and other:
Lease operating expenses	—			—			11,961			—			11,961
Production and property taxes	—			—			831			—			831
Transportation and processing	—			—			3,510			—			3,510
General and administrative	1,089			2			2,959			—			4,050
Depreciation, depletion and amortization	—			—			30,236			—			30,236
Ceiling test write-down of oil and natural gas properties	—			—			142,879			—			142,879
Interest expense	—			—			8,181			—			8,181
Accretion of asset retirement obligations	—			—			350			—			350
Foreign currency exchange losses (gains)	29			17			(7,042		)	—			(6,996		)
Gains on derivative instruments	—			—			7,278			—			7,278
Equity loss in affiliates	123,180			—			—			(123,180		)	—
Other, net	3			—			135			—			138
Total costs, expenses and other	124,301			19			201,278			(123,180		)	202,418
Earnings (loss) before income taxes	(124,301		)	(19		)	(163,082		)	123,180			(164,222		)
Income tax recovery	—			—			(39,921		)	—			(39,921		)
Net earnings (loss)	$	(124,301	)	$	(19	)	$	(123,161	)	$	123,180		$	(124,301	)

CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands of Canadian dollars)

	Three Months Ended September 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations		Consolidated

Net earnings (loss)	$	(124,301	)	$	(19	)	$	(123,161	)	$	123,180	$	(124,301	)
Other comprehensive income:
Amortization of accumulated actuarial loss, net of tax	—			—			4			—		4
Total other comprehensive income	—			—			4			—		4
Comprehensive (loss) income	$	(124,301	)	$	(19	)	$	(123,157	)	$	123,180	$	(124,297	)

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CONDENSED CONSOLIDATING SCHEDULE OF OPERATIONS

(In thousands of Canadian dollars)

	Nine Months Ended September 30, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Revenues:
Oil and natural gas	$	—		$	—		$	86,254		$	—		$	86,254
Interest and other	—			—			11			—			11
Total revenues	—			—			86,265			—			86,265
Costs, expenses and other:
Lease operating expenses	—			—			24,651			—			24,651
Production and property taxes	—			—			1,842			—			1,842
Transportation and processing	—			—			9,716			—			9,716
General and administrative	3,595			10			11,101			—			14,706
Depreciation, depletion and amortization	—			—			54,473			—			54,473
Interest expense	—			—			22,716			—			22,716
Accretion of asset retirement obligations	—			—			861			—			861
Foreign currency exchange losses (gains)	(88		)	(16		)	6,717			—			6,613
Losses on derivative instruments	—			—			7,634			—			7,634
Equity loss in affiliates	55,526			—			—			(55,526		)	—
Reorganization costs	—			—			2,082			—			2,082
Other, net	—			—			78			—			78
Total costs, expenses and other	59,033			(6		)	141,871			(55,526		)	145,372
Earnings (loss) before income taxes	(59,033		)	6			(55,606		)	55,526			(59,107		)
Income tax recovery	—			—			(74		)	—			(74		)
Net earnings (loss)	$	(59,033	)	$	6		$	(55,532	)	$	55,526		$	(59,033	)

CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands of Canadian dollars)

	Nine Months Ended September 30, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries		Subsidiary Issuer			Eliminations		Consolidated

Net earnings (loss)	$	(59,033	)	$	6	$	(55,532	)	$	55,526	$	(59,033	)
Other comprehensive income (loss):
Amortization of accumulated actuarial loss, net of tax	—			—		(59		)	—		(59		)
Total other comprehensive income	—			—		(59		)	—		(59		)
Comprehensive (loss) income	$	(59,033	)	$	6	$	(55,591	)	$	55,526	$	(59,092	)

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CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

(In thousands of Canadian dollars)

	Nine Months Ended September 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Revenues:
Oil and natural gas	$	—		$	—		$	124,937		$	—		$	124,937
Interest and other	—			—			18			—			18
Total revenues	—			—			124,955			—			124,955
Costs, expenses and other:
Lease operating expenses	—			—			40,570			—			40,570
Production and property taxes	—			—			2,516			—			2,516
Transportation and processing	—			—			11,974			—			11,974
General and administrative	2,854			5			11,137			—			13,996
Depreciation, depletion and amortization	—			—			88,548			—			88,548
Ceiling test write-down of oil and natural gas properties	—			—			271,749			—			271,749
Interest expense	—			—			22,174			—			22,174
Accretion of asset retirement obligations	—			—			1,027			—			1,027
Foreign currency exchange losses (gains)	66			16			(3,105		)	—			(3,023		)
Gains on derivative instruments	—			—			(10,990		)	—			(10,990		)
Equity loss in affiliates	235,871			—			—			(235,871		)	—
Other, net	53			—			137			—			190
Total costs, expenses and other	238,844			21			435,737			(235,871		)	438,731
Earnings (loss) before income taxes	(238,844		)	(21		)	(310,782		)	235,871			(313,776		)
Income tax recovery	—			—			(74,932		)	—			(74,932		)
Net earnings (loss)	$	(238,844	)	$	(21	)	$	(235,850	)	$	235,871		$	(238,844	)

CONDENSED CONSOLIDATING STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(In thousands of Canadian dollars)

	Nine Months Ended September 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations		Consolidated

Net earnings (loss)	$	(238,844	)	$	(21	)	$	(235,850	)	$	235,871	$	(238,844	)
Other comprehensive income:
Amortization of accumulated actuarial loss, net of tax	—			—			14			—		14
Total other comprehensive income	—			—			14			—		14
Comprehensive (loss) income	$	(238,844	)	$	(21	)	$	(235,836	)	$	235,871	$	(238,830	)

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(In thousands of Canadian dollars)

	Three Months Ended September 30, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Operating activities:
Net earnings (loss)	$	(14,987	)	$	(15	)	$	(14,113	)	$	14,128		$	(14,987	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			—			17,228			—			17,228
Amortization of deferred costs	—			—			660			—			660
Accretion of asset retirement obligations	—			—			337			—			337
Unrealized foreign currency exchange gains	—			—			(4,545		)	—			(4,545		)
Unrealized gains on derivative instruments	—			—			(254		)	—			(254		)
Stock-based compensation	141			—			90			—			231
Equity loss in affiliates	14,128			—			—			(14,128		)	—
Other, net	—			—			864			—			864
Changes in operating assets and liabilities:
Accounts receivable	13			—			119			—			132
Prepaid expenses and other current assets	200			—			(13		)	—			187
Accounts payable and accrued liabilities	(282		)	—			(1,262		)	—			(1,544		)
Accrued interest and other current liabilities	—			—			4,813			—			4,813
Net cash provided by (used in) operating activities	(787		)	(15		)	3,924			—			3,122
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			(2,877		)	—			(2,877		)
Other fixed assets	—			—			(65		)	—			(65		)
Proceeds from divestiture of assets, net	—			—			28			—			28
Net cash used in investing activities	—			—			(2,914		)	—			(2,914		)
Financing activities:
Repayment of long-term debt	—			—			—			—			—
Debt issuance costs	—			—			(189		)	—			(189		)
Proceeds from bank borrowings	—			—			208,477			—			208,477
Repayments of bank borrowings	—			—			(204,000		)	—			(204,000		)
Change in intercompany balances	803			15			(818		)	—			—
Change in bank overdrafts	—			—			—			—			—
Issuance of common stock	2			—			—			—			2
Capital lease payments	—			—			(1,281		)	—			(1,281		)
Other, net	—			—			27			—			27
Net cash provided by (used in) financing activities	805			15			2,216			—			3,036
Net increase in cash	18			—			3,226			—			3,244
Cash at beginning of period	12			—			5,052			—			5,064
Cash at end of period	$	30		$	—		$	8,278		$	—		$	8,308

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(In thousands of Canadian dollars)

	Three Months Ended September 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Operating activities:
Net earnings (loss)	$	(124,301	)	$	(19	)	$	(123,161	)	$	123,180		$	(124,301	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			—			30,236			—			30,236
Ceiling test write-down of oil and natural gas properties	—			—			142,879			—			142,879
Amortization of deferred costs	—			—			648			—			648
Accretion of asset retirement obligations	—			—			350			—			350
Deferred income tax recovery	—			—			(39,921		)	—			(39,921		)
Unrealized foreign currency exchange losses	—			—			(6,963		)	—			(6,963		)
Unrealized gains on derivative instruments	—			—			15,412			—			15,412
Stock-based compensation	238			—			903			—			1,141
Equity loss in affiliates	123,180			—			—			(123,180		)	—
Other, net	(1		)	—			328			—			327
Changes in operating assets and liabilities:
Accounts receivable	(10		)	—			1,597			—			1,587
Prepaid expenses and other current assets	211			—			(634		)	—			(423		)
Accounts payable and accrued liabilities	(17		)	—			4,245			—			4,228
Accrued interest and other current liabilities	218			—			(5,525		)	—			(5,307		)
Net cash provided by (used in) operating activities	(482		)	(19		)	20,394			—			19,893
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			(30,196		)	—			(30,196		)
Other fixed assets	—			—			(425		)	—			(425		)
Proceeds from divestiture of assets, net	—			—			8,238			—			8,238
Net cash used in investing activities	—			—			(22,383		)	—			(22,383		)
Financing activities:
Proceeds from bank borrowings	—			—			924,000			—			924,000
Repayments of bank borrowings	—			—			(916,000		)	—			(916,000		)
Change in intercompany balances	560			19			(579		)	—			—
Change in bank overdrafts	(81		)	—			(5,766		)	—			(5,847		)
Capital lease payments	—			—			(369		)	—			(369		)
Other, net	—			—			1			—			1
Net cash provided by (used in) financing activities	479			19			1,287			—			1,785
Net increase (decrease) in cash	(3		)	—			(702		)	—			(705		)
Cash at beginning of period	35			—			845			—			880
Cash at end of period	$	32		$	—		$	143		$	—		$	175

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(In thousands of Canadian dollars)

	Nine Months Ended September 30, 2013
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Operating activities:
Net earnings (loss)	$	(59,033	)	$	6		$	(55,532	)	$	55,526		$	(59,033	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			—			54,473			—			54,473
Amortization of deferred costs	—			—			1,921			—			1,921
Accretion of asset retirement obligations	—			—			861			—			861
Deferred income tax recovery	—			—			(74		)	—			(74		)
Unrealized foreign currency exchange losses	—			—			6,515			—			6,515
Unrealized losses on derivative instruments	—			—			4,409			—			4,409
Stock-based compensation	456			—			2,553			—			3,009
Equity loss in affiliates	55,526			—			—			(55,526		)	—
Other, net	—			—			(2,928		)	—			(2,928		)
Changes in operating assets and liabilities:
Accounts receivable	(2		)	—			4,915			—			4,913
Prepaid expenses and other current assets	(275		)	—			431			—			156
Accounts payable and accrued liabilities	(57		)	—			(9,781		)	—			(9,838		)
Accrued interest and other current liabilities	—			—			5,046			—			5,046
Net cash provided by (used in) operating activities	(3,385		)	6			12,809			—			9,430
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			(39,965		)	—			(39,965		)
Other fixed assets	—			—			(148		)	—			(148		)
Proceeds from divestiture of assets, net	—			—			16,208			—			16,208
Net cash used in investing activities	—			—			(23,905		)	—			(23,905		)
Financing activities:
Repayment of long-term debt	—			—			(4,589		)	—			(4,589		)
Debt issuance costs	—			—			(275		)	—			(275		)
Proceeds from bank borrowings	—			—			1,228,477			—			1,228,477
Repayments of bank borrowings	—			—			(1,194,000		)	—			(1,194,000		)
Change in intercompany balances	3,442			(6		)	(3,436		)	—			—
Change in bank overdrafts	(44		)	—			(4,828		)	—			(4,872		)
Issuance of common stock	17			—			—			—			17
Capital lease payments	—			—			(1,882		)	—			(1,882		)
Other, net	—			—			(121		)	—			(121		)
Net cash provided by (used in) financing activities	3,415			(6		)	19,346			—			22,755
Net increase in cash	30			—			8,250			—			8,280
Cash at beginning of period	—			—			28			—			28
Cash at end of period	$	30		$	—		$	8,278		$	—		$	8,308

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CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

(In thousands of Canadian dollars)

	Nine Months Ended September 30, 2012
	Parent Guarantor			Combined Guarantor Subsidiaries			Subsidiary Issuer			Eliminations			Consolidated

Operating activities:
Net earnings (loss)	$	(238,844	)	$	(21	)	$	(235,850	)	$	235,871		$	(238,844	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	—			—			88,548			—			88,548
Ceiling test write-down of oil and natural gas properties	—			—			271,749			—			271,749
Amortization of deferred costs	—			—			1,750			—			1,750
Accretion of asset retirement obligations	—			—			1,027						1,027
Deferred income tax recovery	—			—			(74,932		)	—			(74,932		)
Unrealized foreign currency exchange losses	—			—			(3,031		)	—			(3,031		)
Unrealized gains on derivative instruments	—			—			11,041			—			11,041
Stock-based compensation	618			—			2,243			—			2,861
Equity loss in affiliates	235,871			—			—			(235,871		)	—
Other, net	—			—			(390		)	—			(390		)
Changes in operating assets and liabilities:
Accounts receivable	(40		)	—			11,978			—			11,938
Prepaid expenses and other current assets	(109		)	—			874			—			765
Accounts payable and accrued liabilities	(404		)	—			(17,120		)	—			(17,524		)
Accrued interest and other current liabilities	218			—			2,625			—			2,843
Net cash provided by (used in) operating activities	(2,690		)	(21		)	60,512			—			57,801
Investing activities:
Capital expenditures for property and equipment:
Exploration, development and acquisition costs	—			—			(160,451		)	—			(160,451		)
Other fixed assets	—			—			(2,074		)	—			(2,074		)
Proceeds from divestiture of assets, net	—			—			8,518			—			8,518
Net cash used in investing activities	—			—			(154,007		)	—			(154,007		)
Financing activities:
Net proceeds from issuance of long-term debt	—			—			192,052			—			192,052
Debt issuance costs	—			—			(1,295		)	—			(1,295		)
Proceeds from bank borrowings	—			—			2,390,000			—			2,390,000
Repayments of bank borrowings	—			—			(2,484,000		)	—			(2,484,000		)
Change in intercompany balances	2,449			21			(2,470		)	—			—
Change in bank overdrafts	—			—			454			—			454
Capital lease payments	—			—			(1,107		)	—			(1,107		)
Other, net	—			—			1			—			1
Net cash provided by financing activities	2,449			21			93,635			—			96,105
Net increase (decrease) in cash	(241		)	—			140			—			(101		)
Cash at beginning of period	273			—			3			—			276
Cash at end of period	$	32		$	—		$	143		$	—		$	175

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”) contained in our Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report”), as well as the condensed consolidated financial statements and related notes included in Part I, “Item 1. Financial Statements” in this Form 10-Q for the three and nine months ended September 30, 2013 (“Quarterly Report”). All expectations, forecasts, assumptions and beliefs about our future financial results, condition, operations, strategic plans and performance are forward-looking statements, as described in more detail under “Cautionary Note Regarding Forward-Looking Statements” in this MD&A. Our actual results may differ materially because of a number of risks and uncertainties. See Part I, “Item 1A. Risk Factors” in our 2012 Annual Report and Part II, “Item 1A. Risk Factors” in this Quarterly Report for additional information regarding known material risks.

In this Quarterly Report, unless otherwise indicated or the context otherwise requires, references to “we”, “us”, “our”, or “Lone Pine” refer to Lone Pine Resources Inc., a Delaware corporation, and its consolidated subsidiaries, including Lone Pine Resources Canada Ltd. Unless the context otherwise requires, references in this Quarterly Report to the “Company” refer to Lone Pine Resources Inc. and references in this Quarterly Report to “LPR Canada” refer to Lone Pine Resources Canada Ltd., an Alberta corporation and a wholly owned subsidiary of the Company.

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

Overview

We are an independent oil and gas exploration, development and production company with operations in Canada. Our reserves, producing properties and exploration prospects are located in the provinces of Alberta, British Columbia and Quebec, and in the Northwest Territories. We are incorporated under the laws of the State of Delaware.

Recent Developments

Creditor Protection Proceedings

On September 25, 2013, we commenced proceedings under the Companies’ Creditors Arrangement Act (“CCAA”) in the Court of Queen’s Bench of Alberta (the “CCAA Court”) and ancillary proceedings under Chapter 15 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “U.S. Bankruptcy Court”). The Company, LPR Canada and all other subsidiaries of the Company are parties to the CCAA and Chapter 15 proceedings (collectively, the “Creditor Protection Proceedings”).

The Creditor Protection Proceedings were filed to implement a plan of restructuring in accordance with Support Agreements (the “Support Agreements”), dated September 24, 2013, among the Company, LPR Canada and the Company’s other subsidiaries and certain holders of LPR Canada’s outstanding 10.375% Senior Notes due 2017 (the “Senior Notes”), who in the aggregate hold approximately 75% of the Senior Notes (the “Supporting Noteholders”). Pursuant to the Support Agreements, we have agreed to pursue a restructuring through a plan of compromise and arrangement under the CCAA, which will be subject to creditor and court approval, and ancillary proceedings under Chapter 15 of the United States Bankruptcy Code for recognition of the CCAA proceedings. Each of the Supporting Noteholders has agreed under the terms of its Support Agreement to support the restructuring plan and vote their claims under the Senior Notes in favor of its approval at any meeting of creditors to be held for that purpose.

While definitive terms will be set forth in the CCAA plan of compromise and arrangement, the restructuring contemplated under the Support Agreements provides for the cancellation of all outstanding shares of the Company’s common stock, the conversion of all Senior Notes into new common shares, and a new equity investment of US$100 million by holders of the Senior Notes (the “Noteholders”) through an offering to eligible affected creditors (including the Noteholders) of convertible preferred shares (the “Share Offering”). The proposed restructuring is the result of agreements reached with Supporting Noteholders representing a significant majority of the outstanding Senior Notes, and consideration by the board of directors of the Company, with advice from its financial and legal advisors, of all available alternatives. Based on such consideration and advice, the board of directors of the Company has determined that the proposed restructuring is in the best interests of the Company.

The restructuring contemplates that the Share Offering will be made available to all eligible affected creditors (including the Noteholders) on a pro rata basis pursuant to available exemptions from the prospectus requirements of Canadian securities legislation

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and the registration requirements of the U.S. Securities Act of 1933, as amended (the “Securities Act”), and certain of the Supporting Noteholders (the “Backstopping Noteholders”) have provided a backstop commitment to subscribe for any portion of the proposed Share Offering that is not taken up by other Noteholders in accordance with Backstop Agreements (the “Backstop Agreements”), dated September 24, 2013, among the Company, LPR Canada and the Company’s other subsidiaries and such Backstopping Noteholders. The preferred shares to be issued under the Share Offering will be convertible, in the aggregate, into such number of common shares as is equal to 75% of the common shares outstanding on an “as converted” basis on completion of the restructuring. The preferred shares will carry preferential dividend and liquidation rights, and certain corporate transactions and other matters will, following completion of the restructuring, be subject to preferred shareholder approval in certain circumstances. Details concerning the timing and mechanics of participating in the Share Offering, including as an additional backstop party, will be made available as part of the meeting materials to be sent to all creditors.

It is a condition to the restructuring that we obtain a new secured credit facility, and we are engaged in active lender discussions for this purpose. Proceeds from the Share Offering and borrowings under the new credit facility will be used, in part, to repay all indebtedness under our existing secured credit facility, which as of November 4, 2013 was approximately Cdn$183 million.

During the Creditor Protection Proceedings, we expect to continue with our day-to-day operations, and employee obligations and any trade payables incurred are expected to be paid or satisfied in the ordinary course. On October 24, 2013, the Company and LPR Canada entered into a credit agreement (the “DIP Credit Agreement”) with respect to a $10 million debtor-in-possession credit facility (the “DIP Credit Facility”) with the lenders party thereto and JPMorgan Chase Bank, N.A., Toronto Branch, as administrative agent. See Note 6 to the accompanying condensed consolidated financial statements and “Liquidity and Capital Resources” below for additional information regarding the DIP Credit Facility. The DIP Credit Facility, together with cash balances of Cdn$12 million as at November 4, 2013 and anticipated cash flow from operations, are expected to provide sufficient liquidity to us through the restructuring period.

We expect to complete the restructuring before January 31, 2014. However, the outcome and timing of the Creditor Protection Proceedings, and the implementation of a successful restructuring plan including obtaining a new and adequate secured credit facility to finance our business activities on an ongoing basis is not assured or determinable at this time. As part of the Creditor Protection Proceedings and as discussed further below, we anticipate the development and implementation of a plan of compromise and arrangement to restructure our capital structure and business operations. Confirmation of a plan of compromise and arrangement could materially alter the classifications and amounts reported in our consolidated financial statements, which do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that might be necessary as a consequence of confirmation of such plan, or the effect of any operational changes that may be implemented.

Event of Default, Stay and Operation and Implication of the Creditor Protection Proceedings

The commencement of the Creditor Protection Proceedings constituted an event of default with respect to the following debt instruments:

As a result of such event of default, all obligations under such instruments, by the terms thereof, became due and payable. However, under the CCAA and the United States Bankruptcy Code, the initiation of the Creditor Protection Proceedings automatically stays most actions against a debtor, including most actions to collect indebtedness incurred prior to the initial CCAA filing date or to exercise control over property of a debtor. Accordingly, although commencement of the Creditor Protection Proceedings triggered defaults under these instruments, any efforts to enforce such payment obligations are stayed and the creditors’ rights of enforcement in respect thereof are subject to the applicable provisions of the CCAA and the United States Bankruptcy Code. Absent an order of the CCAA Court, substantially all pre-filing liabilities are subject to compromise under a plan of compromise and arrangement. As a result of the Creditor Protection Proceedings, the realization of assets and the satisfaction of liabilities are subject to uncertainty. For example, we may, subject to the terms of the Support Agreements and approval of the CCAA Court, sell or otherwise dispose of assets and liquidate or compromise liabilities for amounts other than those reflected in the consolidated financial statements. Further, a confirmed plan of compromise and arrangement may materially change the amounts and classifications in our historical consolidated financial statements.

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In connection with the CCAA Initial Order, we received approval from the CCAA Court to pay or otherwise honor certain pre-filing obligations generally designed to stabilize our operations including payments to certain critical suppliers and joint venture partners. We are paying, and intend to continue paying, claims arising after the petition date in the ordinary course of business. We have retained, pursuant to the CCAA Initial Order, legal and financial professionals to advise us on the Creditor Protection Proceedings and certain other professionals to provide services and advice to us in the ordinary course of business. From time to time, we may seek CCAA Court approval to retain additional professionals.

We have incurred and expect to continue to incur significant costs associated with the restructuring and the Creditor Protection Proceedings. The amount of these expenses is expected to significantly affect our financial position and results of operations, but we cannot accurately predict the effect the Creditor Protection Proceedings will have on our business at this time.

Plan of Compromise and Arrangement

For us to successfully emerge from the Creditor Protection Proceedings, we must obtain the CCAA Court’s approval of a plan of compromise and arrangement, which will enable us to transition from the Creditor Protection Proceedings into ordinary course operations out of creditor protection. In connection with the plan of compromise and arrangement, we must also obtain a new credit facility, or “exit financing.” Our ability to obtain such approval and financing will depend on, among other things, the timing and outcome of various ongoing matters in the Creditor Protection Proceedings. A plan of compromise and arrangement determines the rights and treatment of claims of various creditors and security holders, and is subject to the ultimate outcome of negotiations and CCAA Court decisions ongoing through the date on which the plan of compromise and arrangement is sanctioned.

Although we have not yet filed a plan of compromise or arrangement or a related disclosure statement with the CCAA Court, we intend to propose a plan in accordance with the terms of the Support Agreements (the “Proposed Plan”). The Proposed Plan provides for the cancellation of all outstanding shares of the Company’s common stock, the conversion of all Senior Notes into new common shares and the Share Offering. We anticipate filing the Proposed Plan on or before November 29, 2013, unless otherwise extended by agreement of the Supporting Noteholders. Following submission of the Proposed Plan, we expect to take all actions necessary to obtain approval for it from Lone Pine’s affected creditors and the CCAA Court on or before December 31, 2013. Generally, the Proposed Plan will provide, among other things, mechanisms for (i) settlement of claims against us; (ii) treatment of our existing equity and debt holders; (iii) provision for exit financing; and (iv) certain corporate governance and administrative matters pertaining to the reorganized company.

We continue to have ongoing discussions with the Supporting Noteholders and PricewaterhouseCoopers Inc., in its capacity as the CCAA Court-appointed monitor of Lone Pine (the “Monitor”) regarding the Proposed Plan and will continue to do so until the Proposed Plan is filed with the CCAA Court. The Proposed Plan is subject to revision prior to submission to the CCAA Court based upon those continuing discussions, and thereafter in response to those continuing discussions, as well as creditor claims and objections and the requirements of the CCAA Court or the CCAA. There can be no assurance that we will be able to secure approval of the Proposed Plan by the CCAA Court, or that the Proposed Plan will be accepted by our creditors.

Financing During Pendency of the Creditor Protection Proceedings

During the pendency of the Creditor Protection Proceedings, we are funding operations pursuant to an order of the CCAA Court permitting our use of cash balances, working capital and available borrowings under the DIP Credit Facility. As of November 4, 2013, we have not borrowed any amounts under the DIP Credit Facility.

Since approval of the DIP Credit Facility, we have focused on executing our strategic and operating initiatives and ensuring the smooth transition and maintenance of our business in creditor protection. However, there can be no assurance that cash on hand, cash generated through operations and other available funds will be sufficient to meet our restructuring or ongoing cash needs or that we will remain in compliance with all the necessary terms and conditions of the DIP Credit Agreement or that the lending commitments under the DIP Credit Agreement will not be terminated by the lenders.

Going Concern

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Results of Operations

The table below presents selected financial results for the periods indicated.

	Three Months Ended September 30,						Nine Months Ended September30,
	2013			2012			2013			2012
	(In thousands, except volumes and per unit data)
Oil and natural gas revenues	$	26,366		$	38,188		$	86,254		$	124,937
Net sales volumes (MMcfe)(1)	3,937			7,577			12,631			23,979
Realized sales price (per thousand cubic feet equivalent (“Mcfe”))	$	6.70		$	5.04		$	6.83		$	5.21
Net loss	$	(14,987	)	$	(124,301	)	$	(59,033	)	$	(238,844	)
Adjusted EBITDA(2)	$	5,981		$	26,981		$	32,032		$	80,601

(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 loss to Adjusted EBITDA. Net loss is the most directly comparable measure calculated and presented in accordance with GAAP.

We recorded a net loss of $15.0 million for the three months ended September 30, 2013 compared to a net loss of $124.3 million for the three months ended September 30, 2012. We recorded a net loss of $59.0 million for the nine months ended September 30, 2013 compared to a net loss of $238.8 million for the nine months ended September 30, 2012. The decrease in the net loss for each period of 2013 was primarily related to ceiling test write-downs of oil and natural gas properties recognized in 2012. Due to an improvement in natural gas prices over the 12-month trailing period there was no ceiling test write-down in the 2013 periods compared to $142.9 million and $271.7 million recognized for the respective three and nine months ended September 30, 2012.

In the three and nine months ended September 30, 2013 our revenues less production expenses decreased by $7.0 million and $19.8 million, respectively, from the three and nine months ended September 30, 2012. The decreases were primarily related to natural production volume declines and the impact of the divestiture of non-core properties that had generated revenues less production expenses in 2012. Other factors that impacted our financial results to date in 2013 included reorganization costs incurred in the third quarter, higher realized losses on derivative instruments, foreign currency exchange losses as a result of a decreasing Canadian dollar, partly offset by lower depreciation, depletion and amortization expense (“DD&A”) due to lower net sales volumes and a lower recovery of deferred income tax expense.

Adjusted EBITDA decreased $21.0 million and $48.6 million for the three and nine months ended September 30, 2013, respectively, compared to the same periods in 2012, primarily due to the decline in our operating income, 2013 reorganization costs and realized losses on derivatives.

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

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Sales Volumes and Revenues

The table below presents our sales volumes by product for the periods indicated.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Working interest sales volumes(1):
Oil (Mbbls)	213		366		748		1,168
NGLs (Mbbls)	7		26		21		76
Natural gas (MMcf)	3,157		5,371		9,855		17,297
Total equivalent (MMcfe)	4,478		7,723		14,470		24,836
Total equivalent daily sales volumes (MMcfe/d)	48.7		83.9		53.0		90.6
Total equivalent daily sales volumes (boe/d)	8,117		13,991		8,833		15,107
Average liquids weighting	29	%	30	%	32	%	30	%

Net sales volumes(2):
Oil (Mbbls)	187		334		665		1,060
NGLs (Mbbls)	7		18		18		53
Natural gas (MMcf)	2,773		5,465		8,533		17,301
Total equivalent (MMcfe)	3,937		7,577		12,631		23,979
Total equivalent daily sales volumes (MMcfe/d)	42.8		82.4		46.3		87.5
Total equivalent daily sales volumes (boe/d)	7,132		13,726		7,711		14,586
Average liquids weighting	30	%	28	%	32	%	28	%

(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 the volumes attributable to royalties.

Net sales volumes for each of the three and nine months ended September 30, 2013 decreased by approximately 40 MMcfe/d compared to the three and nine months ended September 30, 2012. This reduction was due to a decline in natural gas net sales volumes, which was largely due to the divestiture of non-core properties in the fourth quarter of 2012 and the first quarter of 2013 together with a decline in oil net sales volumes following a period of reduced capital expenditures. Natural gas volumes were also lower due to the natural decline in our production as a result of a decision to suspend investment in natural gas drilling activities.

Our average net liquids weighting increased from 30% for the nine months ended September 30, 2012 to 32% for the nine months ended September 30, 2013. Total crude oil volumes decreased in each period of 2013 period due to a lower level of capital expenditures in 2013 as compared to 2012, and natural declines on our existing properties.

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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 September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Revenues (in thousands):
Oil	$	18,687		$	26,561		$	59,836		$	87,568
Natural gas	7,356			10,666			25,645			34,293
NGLs	323			961			773			3,076
Total oil and natural gas revenues	$	26,366		$	38,188		$	86,254		$	124,937

Average prices per unit:
NYMEX WTI (US$ per bbl)	105.81			92.20			98.19			96.16
NYMEX WTI ($ per bbl)	109.89			91.76			100.50			96.38
Edmonton Par ($ per bbl)	104.89			83.30			95.64			86.88
Average oil sales price ($ per bbl)	99.93			79.52			89.98			82.61
Differential — NYMEX WTI to average oil sales price ($ per bbl)	9.96			12.24			10.52			13.77
Differential — Edmonton Par to average oil sales price ($ per bbl)	4.96			3.78			5.66			4.27

NYMEX Henry Hub (US$ per MMBtu)	3.58			2.81			3.67			2.59
NYMEX Henry Hub ($ per MMBtu)	3.72			2.80			3.76			2.60
AECO ($ per MMBtu)	2.82			2.19			3.16			2.18
Average natural gas sales price ($ per MMBtu)	2.65			1.95			3.01			1.98
Differential — NYMEX Henry Hub to average natural gas sales price ($ per MMBtu)	1.07			0.85			0.75			0.62
Differential — AECO to average natural gas sales price ($ per MMBtu)	0.17			0.24			0.15			0.20

Average NGL sales price ($ per bbl)	46.14			53.39			42.94			58.04
Percentage of NYMEX WTI	42		%	58		%	43		%	60		%

Total equivalent realized sales price ($ per Mcfe)	6.70			5.04			6.83			5.21
Total equivalent realized sales price ($ per barrel of oil equivalent (“boe”))	40.18			30.24			40.97			31.26

Revenues decreased from $38.2 million for the three months ended September 30, 2012 to $26.4 million for the three months ended September 30, 2013, and from $124.9 million for the nine months ended September 30, 2012 to $86.3 million for the nine months ended September 30, 2013. These decreases are related to lower net sales volumes, offset partly by improved oil and natural gas pricing in 2013.

Crude oil revenues decreased by 30% in the third quarter of 2013 compared to the third quarter of 2012 primarily due to the decrease in crude oil net sales volumes as a result of the lower rate of capital investment employed by the Company over the preceding quarters, partially offset by increases in our realized crude oil price. Crude oil revenues decreased by 32% in the nine months ending September 30, 2013 compared to the nine ended September 30, 2013 for similar reasons.

Our natural gas revenues decreased by 31% in the third quarter of 2013 compared to the third quarter of 2012 primarily due to a decrease in natural gas net sales volumes, partly offset by a 36% increase in our realized natural gas price from $1.95 per MMBtu in the third quarter of 2012 to $2.65 per MMBtu in the third quarter of 2013. Natural gas revenues decreased 32% in the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012 primarily due to the similar level of decrease in natural gas net sales volumes, partly offset by improved realized pricing.

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Our natural gas pricing and related revenue in both the 2012 and 2013 periods was negatively impacted by our delivery commitment of approximately 21,000 MMBtu/d of natural gas under a long-term sales contract. The impact of this contract was more pronounced in 2013 because the volumes committed under the contract represent a larger proportion of our overall natural gas volumes. For the three and nine months ended September 30, 2013, we estimate that this delivery commitment reduced our natural gas revenue by approximately $1.3 million ($0.46 per MMBtu) and $5.4 million ($0.63 per MMBtu), respectively. This contract expires in October 2014.

Production Expense

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

	Three Months Ended September 30,				Nine Months Ended September30,
	2013		2012		2013		2012
	(In thousands, except per Mcfe data)
Production expense:
Lease operating expenses	$	7,732	$	11,961	$	24,651	$	40,570
Production and property taxes	703		831		1,842		2,516
Transportation and processing costs	3,035		3,510		9,716		11,974
	$	11,470	$	16,302	$	36,209	$	55,060
Production expense per Mcfe:
Lease operating expenses	$	1.96	$	1.58	$	1.95	$	1.69
Production and property taxes	0.18		0.11		0.15		0.10
Transportation and processing costs	0.77		0.46		0.77		0.50
	$	2.91	$	2.15	$	2.87	$	2.29

Lease Operating Expenses

Lease operating expenses for the three months ended September 30, 2013 were $7.7 million compared to $12.0 million for the three months ended September 30, 2012, and $24.7 million for the nine months ended September 30, 2013 compared to $40.6 million for the nine months ended September 30, 2012. The decrease in lease operating expenses was mainly due to lower production volumes in 2013, decreased workovers, and lower trucking costs as a result of tie-ins completed earlier in the year.

The cost of workover activity decreased from $1.4 million and $8.8 million in the three and nine months ended September 30 2012, respectively, to $0.5 million and $3.5 million in the three and nine months ended September 30, 2013, respectively. The reduction in workover costs was primarily related to an overall reduction in activity partly related to divestitures and at Evi as a result of optimized completion techniques.

Although total lease operating expenses decreased, there was an overall increase in the cost per Mcfe in 2013 periods, which was partly due to the decrease in production volumes and fixed cost elements and a higher net liquids weighting where our crude oil properties have higher per unit operating costs than natural gas properties.

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 decreases for the three and nine months ended September 30, 2013 compared to the same periods in 2012 were 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 field-level gathering and transportation costs as well as processing costs for crude oil. Transportation and processing costs for the three and nine months ended September 30, 2013 decreased to $3.0 million and $9.7 million, respectively, compared to $3.5 million and $12.0 million for the three and nine months ended September 30, 2012, respectively.

The decreases were primarily related to the overall 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 in 2013 due to lower volume impacts and due to the transportation costs for the divested properties being lower than the average per Mcfe cost in the comparative nine month period in 2012.

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General and Administrative Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands, except per Mcfe data)
General and administrative costs	$	3,182		$	4,422		15,619			$	15,537
Stock-based compensation costs	284			1,321			3,525			3,708
Total costs incurred	3,466			5,743			19,144			19,245
General and administrative costs capitalized (including stock-based compensation)	(980		)	(1,693		)	(4,438		)	(5,249		)
General and administrative expense	$	2,486		$	4,050		$	14,706		$	13,996
General and administrative expense per Mcfe	$	0.63		$	0.53		$	1.16		$	0.58

General and Administrative Costs

General and administrative costs primarily consist of the salaries and related benefit costs for our employees, fees for contractors, professional fees and office lease costs. Costs directly associated with the Creditor Protection Proceedings that commenced in September 2013 are outlined separately below and are excluded from general and administrative expense.

In the third quarter of 2013, general and administrative costs decreased by $1.2 million from the third quarter of 2012 primarily due to a lower number of employees, salary and benefit costs following a reduction in staffing over the first six months of 2013.

In the nine months ended September 30, 2013, general and administrative expense of $15.6 million was comparable to $15.5 million in 2012. The 2013 period includes severance payments related to the termination of the former chief executive officer and chief financial officer in the first quarter of 2013 and the costs related to employee terminations benefits that were recognized in the second quarter of 2013.

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 common stock of the Company, the fair value of which was determined and fixed at their grant date.

The decrease in stock-based compensation costs from the third quarter of 2012 to the third quarter of 2013 was primarily related to stock-settled units that were issued in January 2012 and their cost being recognized in the first year of vesting and also due to a lower level of stock-settled units outstanding compared to 2012.

The decrease in stock-based compensation costs from the nine months ended September 30, 2012 to the nine months ended September 30, 2013 was related to a decrease in costs as discussed above, partially offset by the acceleration of $1.6 million of costs for officer and employee terminations, and the cost of new awards granted in 2013.

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 23% to 29% during the periods presented. Capitalized costs have decreased in 2013 compared to 2012 periods due to less exploration and development and supporting activity.

Reorganization costs

We have segregated certain costs that are directly related to the Creditor Protection Proceedings in accordance with ASC 852. For the three and nine months ended September 30, 2013, the total reorganization costs of $2.1 million were comprised of $1.8 million of professional fees and $0.3 million for the Retention Program (as defined below). There were no comparative reorganization costs in 2012.

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As of September 30, 2013, reorganization costs included in accounts payable and accrued liabilities totaled approximately $1.1 million and are subject to the Creditor Protection Proceedings. The total future reorganization costs related to the Creditor Protection Proceedings are not determinable and are subject to those proceedings and dependent on future events.

Depreciation, Depletion and Amortization

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In thousands, except per Mcfe data)
Depreciation, depletion and amortization	$	17,228	$	30,236	$	54,473	$	88,548
Depreciation, depletion and amortization per Mcfe	$	4.28	$	3.99	$	4.31	$	3.69

For the three and nine months ended September 30, 2013, DD&A was $17.2 million and $54.5 million, respectively, compared to $30.2 million and $88.5 million for the three and nine months ended September 30, 2012, respectively.

The decreases in DD&A were due to lower net sales volumes, partially offset by higher per-unit depletion rates. The increases in the per-unit rates were primarily due to the addition of proved crude oil reserves to our depletable base since 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 a continued decline in the 12-month average trailing natural gas price.

Full Cost Method of Accounting

During the three and nine months ended September 30, 2013, due partly to improved natural gas prices, we did not recognize a ceiling test write-down. During the three and nine months ended September 30, 2012, we recognized a ceiling test write-downs of $142.9 million before tax ($107.3 million after tax) and $271.7 million before tax ($204.1 million after tax), respectively, primarily due to the 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 September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In thousands)
Interest costs—Senior Notes(1)	$	5,312	$	5,529	$	16,509	$	13,950
Interest costs—Existing Credit Facility(1)	2,321		2,578		6,023		7,976
Interest costs—other	41		74		184		248
Interest expense	$	7,674	$	8,181	$	22,716	$	22,174

(1) Including amortization of debt issue costs.

The increase in interest costs on the Senior Notes for the nine months ended September 30, 2013 compared to the same period in 2012 was primarily due to the Senior Notes only being outstanding for seven and one-half months in 2012 compared to nine months in 2013. The decrease in interest costs on our Existing Credit Facility (as herein defined) was due to a reduced level of borrowings in 2013 compared to the same period in 2012. Other interest has decreased mainly due to a reduction in other financing interest and capital lease expense.

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In accordance with the Creditor Protection Proceedings, the accrued interest on Senior Notes was stayed effective September 25, 2013, resulting in a $0.4 million decrease in interest expense for the three months ended September 30, 2013.

Derivative Instruments

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Unrealized losses (gains) on derivative instruments
Oil	$	(786	)	$	7,907		$	4,389		$	(4,180	)
Natural gas	532			7,505			20			15,221
Unrealized losses (gains) on derivative instruments	$	(254	)	$	15,412		$	4,409		$	11,041

Realized losses (gains) on derivative instruments
Oil	$	5,244		$	(2,697	)	$	3,715		$	(4,654	)
Natural gas	(757		)	(5,437		)	(490		)	(17,377		)
Realized losses (gains) on derivative instruments	$	4,487		$	(8,134	)	$	3,225		$	(22,031	)
Losses (gains) on derivative instruments	4,233			7,278			7,634			(10,990		)

We have historically entered into oil and natural gas derivative instruments to manage our exposure to commodity price risk caused by fluctuations in commodity prices, which protected and provided certainty on a portion of our cash flows. Effective September 25, 2013 and as a result of the Creditor Protection Proceedings and the provisions of the Company’s derivative instrument agreements, all agreements were terminated with the respective counterparties. As of September 30, 2013, there were no outstanding derivative instrument contracts.

The portion of realized losses on derivative instruments that were subject to early termination provisions related to the Creditor Protection Proceedings, in the amount of approximately $2.5 million, were comprised of a $0.7 million realized gain on natural gas contracts and a $3.2 million realized loss on crude oil contracts.

The realized losses in 2013 as compared to realized gains in 2012 relate mainly to crude oil contracts and an increase in NYMEX WTI crude oil prices in 2013. As well, we had less natural gas volumes hedged at in-the-money swap prices compared to 2012.

Foreign Currency Exchange

In the three and nine months ended September 30, 2013, we recorded a foreign currency exchange gain of $4.4 million and a foreign currency exchange loss of $6.6 million loss, respectively. In the three and nine months ended September 30 2012, we recorded foreign currency exchange gains of $7.0 million and $3.0 million, respectively.

The gains and losses are primarily unrealized and relate to the translation of the Senior Notes from U.S. to Canadian dollars in the respective periods.

Income Tax Expense (Recovery)

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands )
Current income tax	$	—		$	—		$	—		$	—
Deferred income tax expense (recovery)	—			(39,921		)	(74		)	(74,932		)
Total income tax expense (recovery)	$	—		$	(39,921	)	$	(74	)	$	(74,932	)
Effective income tax rate	0		%	24		%	0		%	24		%

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

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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 changes in Canada.

During the year ended December 31, 2012, our deferred income tax liability transitioned into a deferred income tax asset position primarily as a result of the ceiling test write-downs that reduced the net book value of our proved properties. Since it was determined that it was more likely not to be able to realize the benefit of the asset, we recorded a valuation allowance against the full value of the asset. During the three and nine months ended September 30, 2013, our effective income tax rates were 0% because we recorded valuation allowances against the increases in the deferred income tax asset since we determined that it was more likely the Company will not be able to realize the benefit of the asset.

Liquidity and Capital Resources

Our condensed consolidated financial statements were prepared on a going concern basis at September 30, 2013, which contemplates continuity of operations, realization of assets and the satisfaction of liabilities in the normal course of business for the twelve-month period following the date of the consolidated financial statements. The disclosure outlined below, in Notes 1 and 2 in our accompanying condensed consolidated financial statements and in “Recent Developments” above address important factors affecting our financial condition, liquidity and capital resources.

Sources of Liquidity

Our exploration, development and acquisition activities require us to make significant operating and capital expenditures, and we have historically used the following as our primary sources of liquidity.

· Cash provided by operating activities;

· Non-core asset divestitures;

· Existing Credit Facility; and

· Equity and debt capital markets.

Changes in the market prices for oil, natural gas and NGLs directly impact our level of cash provided by operating activities. During the three months ended September 30, 2013, natural gas comprised approximately 78% of our net sales volumes. As a result, our operations and cash flows have historically been more sensitive to fluctuations in the market price for natural gas than in the market price for oil. We have historically entered into derivative instruments to manage our exposure to commodity price risk caused by fluctuations in commodity prices, which protected and provided certainty on a portion of our cash provided by operating activities. Effective September 25, 2013, commodity swaps to hedge 3,000 bbls/d of crude oil and commodity collars to hedge 30,000 MMBtu/d of natural gas (total of 5.0 Bcfe) for the balance of 2013 and commodity swaps to hedge 250 bbls/d of crude oil and 5,000 MMBtu/d of natural gas (total of 2.4 Bcfe) for 2014 were terminated. As a result of these terminations, there are no outstanding derivative instrument agreements as of November 4, 2013.

In 2012, we announced that we were actively considering methods of debt reduction, including the divestiture of non-core assets. In 2012, we completed the sale of certain non-core natural gas weighted properties for cash proceeds after closing adjustments of $97.7 million, and in the first half of 2013 we completed additional sales for cash proceeds after closing adjustments of approximately $16.2 million.

As of September 30, 2013, our Existing Credit Facility had a borrowing base of $185 million. As of November 5, 2013, we had $183 million in borrowings outstanding under our Existing Credit Facility at a weighted average interest rate of 4.7%. Due to the Creditor Protection Proceedings, we are currently in default under the Existing Credit Facility. On October 24, 2013, we entered into the DIP Credit Agreement, which provides us access to the DIP Credit Facility during the pendency of the Creditor Protection Proceedings, subject to the terms and conditions of the DIP Credit Agreement.

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

Cash Flows

The table below summarizes our net cash provided by operating activities, net cash used in investing activities and net cash provided by financing activities during the periods indicated.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Net cash provided by operating activities	$	3,122		$	19,893		$	9,430		$	57,801
Net cash used in investing activities	(2,914		)	(22,383		)	(23,905		)	(154,007		)
Net cash provided by financing activities	3,036			1,785			22,755			96,105

Net Cash Provided by Operating Activities

Net cash provided by operating activities is primarily affected by sales volumes, commodity prices and cash-based expenses. The decreases in net cash provided by operating activities in the three and nine months ended September 30, 2013 from the same periods in 2012 were primarily due to a decrease in revenues less production expenses as discussed above. In addition, approximately $0.8 million of reorganization costs relating to the Creditor Protection Proceedings were paid in the 2013 period.

Working Capital Deficit

We had a working capital deficit of $380.5 million at September 30, 2013, including current liabilities subject to compromise, compared to a $23.0 million deficit at December 31, 2012. The increase was primarily due to a reclassification of certain long-term liabilities to short-term related to the Existing Credit Facility and Senior Notes, upon the commencement of the Creditor Protection Proceedings.

Net Cash Used In Investing Activities

Net cash used in investing activities primarily comprises capital expenditures for 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.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Exploration, development and acquisition costs	$	(2,877	)	$	(30,196	)	$	(39,965	)	$	(160,451	)
Other fixed assets	(65		)	(425		)	(148		)	(2,074		)
Proceeds from divestiture of assets, net	28			8,238			16,208			8,518
Net cash used in investing activities	$	(2,914	)	$	(22,383	)	$	(23,905	)	$	(154,007	)

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.

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The decreases in net cash used in investing activities in the three and nine months ended September 30, 2013 compared to the three and nine months ended September 30, 2012 were primarily due to lower capital expenditures and proceeds received from the divestiture of non-core assets in the first half of 2013.

Capital Expenditures

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(In thousands)
Exploration and development	$	1,705	$	34,878	$	30,796	$	131,927
Property acquisitions	—		156		—		10,737
General and administrative costs capitalized	980		1,693		4,438		5,249
Total capital expenditures	$	2,685	$	36,727	$	35,234	$	147,913

Primary factors impacting the low level of our 2013 capital expenditures and third quarter activity include financial condition and liquidity issues and therefore a reduced capital expenditure plan.

In the first nine months of 2013, our capital program focused on light oil development in the Evi area of Alberta where we drilled 6.8 net wells, completed 7.3 net wells and tied-in 7.3 net wells. Due to the lack of available liquidity under the Existing Credit Facility, we did not drill, complete or tie-in any wells during the third quarter of 2013.

Acquisitions and Divestitures

In the first quarter of 2013, we completed the sale of non-core assets in the Herronton area of Alberta for cash proceeds of approximately $13.7 million. In the second quarter of 2013, we completed the sale of certain non-core properties, primarily undeveloped land, resulting in additional proceeds of approximately $2.5 million. In the third quarter of 2013, there were no major acquisitions or divestitures.

Net Cash Provided by Financing Activities

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Repayment of long-term debt	$	—		$	—		$	(4,589	)	$	—
Net proceeds from issuance of long-term debt	—			—			—			192,052
Debt issuance costs	(189		)	—			(275		)	(1,295		)
Proceeds from bank borrowings	208,477			924,000			1,228,477			2,390,000
Repayments of bank borrowings	(204,000		)	(916,000		)	(1,194,000		)	(2,484,000		)
Change in bank overdrafts	—			(5,847		)	(4,872		)	454
Issuance of common stock	2			—			17			—
Capital lease payments	(1,281		)	(369		)	(1,882		)	(1,107		)
Other, net	27			1			(121		)	1
Net cash provided by financing activities	$	3,036		$	1,785		$	22,755		$	96,105

In the first three quarters of 2013, net cash provided by financing activities was primarily related to borrowings under our Existing Credit Facility. In 2012, we issued Senior Notes and used the net proceeds to reduce borrowings outstanding under our Existing Credit Facility.

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Existing Credit Facility — Secured

As a result of the commencement of the Creditor Protection Proceedings on September 25, 2013, we are currently in default under our $500 million credit facility (the “Existing Credit Facility”) with a syndicate of banks led by JPMorgan Chase Bank, N.A., Toronto Branch. At September 30, 2013, borrowings under our Existing Credit Facility increased to $183 million from $148 million at December 31, 2012. As of November 4, 2013, we had $183 million outstanding under our Existing Credit Facility at a weighted average interest rate of 4.7% and $2 million of outstanding letters of credit. See “Recent Developments” in this MD&A.

Senior Notes — Subject to Compromise

On February 14, 2012, LPR Canada issued US$200 million aggregate principal amount of 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. Interest is payable on the Senior Notes semi-annually, in arrears, on each February 15 and August 15. The Company did not pay the August 15, 2013 scheduled interest payment and following the expiration of an automatic 30-day cure period, which resulted in an event of default under the Indenture. See “Recent Developments” in this MD&A.

At September 30, 2013 and December 31, 2012, we had outstanding US$195 million and US$200 million, respectively, aggregate principal amount of Senior Notes. In the nine months ended September 30, 2013, we used a portion of the proceeds from recently completed non-core asset sales to repurchase US$5.0 million of Senior Notes for $4.6 million (US$4.5 million), resulting in the recognition of a gain on debt extinguishment of approximately $0.4 million included in other, net on the Condensed Consolidated Statements of Operations.

DIP Credit Facility — Subject to CCAA Preferred Charge

In connection with the Creditor Protection Proceedings, on October 24, 2013, the Company and LPR Canada entered into the DIP Credit Agreement with respect to the DIP Credit Facility. Certain of the lenders under the Existing Credit Facility are lenders under the DIP Credit Facility, and the agent under the Existing Credit Facility serves as administrative agent under the DIP Credit Facility. Pursuant to the terms of the DIP Credit Agreement, (i) the lenders agreed to lend LPR Canada up to $10 million, which loans will bear interest at the Canadian Prime Rate (as defined in the DIP Credit Agreement), plus 5.00%, (ii) the Company and each Restricted Subsidiary (as defined in the DIP Credit Agreement) agreed to guarantee LPR Canada’s obligations thereunder, and (iii) the Obligations (as defined in the DIP Credit Agreement) are and shall be at all times secured by the liens in all collateral created by the DIP Charge (as defined in the DIP Credit Agreement) and all such liens shall be first priority liens subject only to the Administration Charge (as defined in the DIP Credit Agreement). LPR Canada is obligated to pay the agent an upfront fee of 2% and the lenders a commitment fee of 0.75% of unutilized commitments. Proceeds of loans under the DIP Credit Facility may be used to provide for working capital, capital expenditures and other expenditures during the course of the Creditor Protection Proceedings, in accordance with the terms of the DIP Credit Agreement. The DIP Credit Facility matures on March 25, 2014.

In addition to customary affirmative covenant obligations, the DIP Credit Agreement provides for certain information delivery requirements to each lender and the agent, including (i) quarterly and annual financial statements, (ii) weekly delivery of actual receipts and disbursements with a variance analysis against the cash flow model most recently filed with the CCAA Court and (iii) monthly financial results. LPR Canada is also obligated to obtain, on or before November 13, 2013, a fully executed commitment letter from a replacement lender (or lenders) providing for credit facilities, which together with the proceeds of the Share Offering contemplated in the Creditor Protection Proceedings, would be sufficient to repay in full all obligations outstanding under the Existing Credit Facility.

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Adoption of New Accounting Standards

In connection with the commencement of the Creditor Protection Proceedings, we adopted Accounting Standards Codification (“ASC”) No. 852 -— Reorganization (“ASC 852”) during the third quarter of 2013. ASC 852 requires, among other things, the segregation of reorganization costs directly related to the Creditor Protection Proceedings and related proceedings, other related disclosures such as the use of financial statement headers (Under Creditor Protection Proceedings as of September 25, 2013 — See Notes 1, 2, 6 and 13) and the classification of balance sheet obligations, based on available information, as either subject to compromise, secured or if determinable, as under-secured.

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 our amounts in accumulated other comprehensive income were not significant and, therefore, the amendments did not affect our financial statements.

Future Accounting Pronouncements

In the second quarter of 2013, the FASB issued Accounting Standards Update 2013-07, Liquidation Basis of Accounting (“ASU 2013-07”), which requires entities to prepare their financial statements using the liquidation basis of accounting when the likelihood is remote that the entity will return from liquidation. This pronouncement is effective for entities that determine liquidation is imminent during annual reporting periods beginning after December 15, 2013, and interim reporting periods therein, and are to be applied prospectively. The Company does not expect ASU 2013-07 to impact its accounting and disclosure requirements as the Company continues to present its financial statements, subject to the Creditor Protection Proceedings, on a going concern basis. The Company is monitoring possible future impacts and application.

In the first quarter of 2013, 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 is 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 is 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

Certain statements and information in this Quarterly Report may constitute “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 regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-

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looking statements. 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 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;

· estimates of our average global market capitalization;

· our future financial condition and results of operations;

· our future revenues, cash flows and expenses;

· our plans to dispose of non-core assets;

· our plans to restructure and refinance our Senior Notes and the indebtedness outstanding under our existing secured credit facility and otherwise complete a comprehensive restructuring;

· our plans to complete a new replacement senior secured credit facility;

· our plans and expectations with respect to the operation of our business and ability to satisfy our obligations and payables during the restructuring;

· our plans and expectations with respect to the Creditor Protection Proceedings generally, including the anticipated timing thereof;

· our access to capital and expectations with respect to liquidity, capital resources and our ability to continue as a going concern;

· 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 our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. 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 and the acceleration of such indebtedness;

· our ability to complete a strategic restructuring and refinancing transaction or alternative transaction, including associated risks such as (i) our ability to negotiate and execute definitive documentation with respect to the restructuring (including our ability to complete a new replacement senior secured credit facility) and obtain court approval thereof, (ii) our ability to prosecute, develop and consummate one or more plans of compromise and arrangement with respect to the proceedings, (iii) the effects of the proceedings on us and the interests of various creditors, equity holders and other constituents, (iv) bankruptcy court rulings and the outcomes of the proceedings in general, (v) the length of time we will operate under the proceedings; (vi) risks associated with third party motions in the proceedings, which may interfere with our ability to develop or consummate one or more plans of compromise and arrangement, (vii) the potential adverse effects of the proceedings on our liquidity or results of operations, (viii) our ability to execute our business and restructuring plan, (ix) increased legal and other costs related to the proceedings, (x) our ability to maintain contracts that are critical to our operation and to obtain and maintain normal terms and relationships with our suppliers, other service providers, customers, employees, stockholders and other third parties, and (xi) our ability to retain key executives, managers and employees;

· our ability to generate sufficient cash flow from operations or obtain adequate financing to fund our capital expenditures and meet working capital needs and our ability to continue as a going concern during the restructuring;

· our ability to replace and sustain production;

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

· increases in costs of drilling, completion and 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 ceiling test write-downs;

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

· a deterioration in the demand for our products;

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

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

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

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

· the uncertainty related to the pending litigation against us.

Should one or more of the risks or uncertainties described above or elsewhere in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see our filings with the U.S. Securities and Exchange Commission, including our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K.

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

Reconciliation of Non-GAAP Measure

In addition to reporting net earnings as defined under U.S. generally accepted accounting principles (“GAAP”), we also present Adjusted EBITDA, a non-GAAP measure calculated as net loss before interest expense, income tax expense (recovery), DD&A, impairment of goodwill, impairment of assets, ceiling test write-downs of oil and natural gas properties, accretion of asset retirement obligations, unrealized losses (gains) on derivative instruments and foreign currency exchange (gains) losses. Adjusted EBITDA also excludes the stock-settled portion of stock-based compensation expense, as this amount will be settled in shares of our common stock rather than cash payments. By eliminating these items, we believe the result is a useful measure across time in evaluating our performance. Our management also uses Adjusted EBITDA to manage our business, including in preparing our annual operating budget and financial projections. We believe that Adjusted EBITDA is also useful to investors because similar measures are frequently used by securities analysts, rating agencies, investors and other interested parties in their evaluation of companies in similar industries. As indicated, Adjusted EBITDA does not include interest expense on borrowed money, DD&A on capital assets or the payment of income taxes, which are all necessary elements of our operations. Adjusted EBITDA does not account for these and other expenses and therefore its utility as a measure of our performance has material limitations. As a result of these limitations, our management does not view Adjusted EBITDA in isolation and uses other measurements, such as net loss and revenues, to measure performance.

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

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(In thousands)
Net loss	$	(14,987	)	$	(124,301	)	$	(59,033	)	$	(238,844	)
Add back (deduct):
Interest expense	7,674			8,181			22,716			22,174
Income tax expense (recovery)	—			(39,921		)	(74		)	(74,932		)
Depreciation, depletion and amortization	17,228			30,236			54,473			88,548
Ceiling test write-down of oil and natural gas properties	—			142,879			—			271,749
Accretion of asset retirement obligations	337			350			861			1,027
Unrealized (gains) losses on derivative instruments	(254		)	15,412			4,409			11,041
Foreign currency exchange (gains) losses	(4,383		)	(6,996		)	6,613			(3,023		)
Stock-based compensation (stock-settled portion)	366			1,141			2,067			2,861
Adjusted EBITDA	$	5,981		$	26,981		$	32,032		$	80,601

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2012 Annual Report on Form 10-K for the year ended December 31, 2012. 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 have historically entered 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 entered into contracts with counterparties who are participants in our Existing Credit Facility. These arrangements, which were based on prices available in the financial markets at the time we entered into the contracts, settled in cash and did not require physical deliveries of hydrocarbons.

As of September 30, 2013, all agreements were terminated and final settlements were recorded, as a result of counterparty terms to exercise early termination upon commencement of the Creditor Protection Proceedings. Accordingly, the estimated fair value of all our commodity derivative instruments at September 30, 2013 was $0.

As of September 30, 2013, approximately $2.5 million was included in the current portion of long-term debt related to the early termination of all derivative instruments.

Long-Term Sales Contract

As of September 30, 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 September 30, 2013, we had $183 million in outstanding borrowings on our Existing Credit Facility, with a weighted average interest rate of 4.7%. 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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Operating under the Creditor Protection Proceedings may restrict our ability to pursue our strategic and operational initiatives.

Under the Creditor Protection Proceedings, transactions outside the ordinary course of business are subject to the prior approval of the CCAA Court, which may limit our ability to respond in a timely manner to certain events or take advantage of certain opportunities. Additionally, the terms of the DIP Credit Agreement limit our ability to undertake certain business initiatives. These limitations include, among other things, restrictions on our ability to:

· incur indebtedness;

· incur liens;

· consummate certain fundamental changes, including any consolidation, merger or amalgamation;

· make investments;

· dispose of assets;

· enter into sale and leaseback transactions;

· enter into hedging agreements;

· make restricted payments; and

· enter into transactions with affiliates.

The pursuit of the Creditor Protection Proceedings has consumed and will continue to consume a substantial portion of the time and attention of our corporate management and will impact how our business is conducted, which may have an adverse effect on our business and results of operations.

The requirements of the Creditor Protection Proceedings have consumed and will continue to consume a substantial portion of our corporate management’s time and attention and leave them with less time to devote to the operation of our business. This diversion of attention may materially adversely affect the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Creditor Protection Proceedings are protracted.

We may experience increased levels of employee attrition.

During the pendency of the Creditor Protection Proceedings, we may experience increased levels of employee attrition, and our employees are facing considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale, at the corporate and field levels, could have a materially adverse effect on our ability to meet customer, trade partner and strategic partner expectations, thereby adversely affecting our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incent key employees to remain with us through the pendency of the Creditor Protection Proceedings is limited during the Creditor Protection Proceedings by restrictions on implementation of retention programs. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

As a result of the Creditor Protection Proceedings, our historical financial information may not be indicative of our future financial performance.

Our capital structure will likely be significantly altered under any plan of compromise and arrangement ultimately confirmed by the CCAA Court. Should the fresh-start reporting rules apply to us upon the effective date of a plan of compromise and arrangement, our assets and liabilities would be adjusted to fair values and our accumulated deficit would be restated to zero. Accordingly, if fresh-start reporting rules apply, our financial condition and results of operations following our emergence from the Creditor Protection Proceedings would not be comparable to the financial condition and results of operation reflected in our historical financial statements. In connection with the Creditor Protection Proceedings and the development of a plan of compromise and

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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		Certificate of Amendment to Amended and Restated Certification of Incorporation of Lone Pine Resources Inc., incorporated herein by reference to Exhibit 3.1 to Form 8-K for Lone Pine Resources Inc. filed May 16, 2013 (File No. 001-35191).

3.3		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).

10.1		Fifth Amendment dated July 26, 2013 to Credit Agreement dated March 18, 2011, among Lone Pine Resources Inc., as parent, Lone Pine Resources Canada Ltd., as borrower, each of the lenders party thereto and JPMorgan Chase Bank, N.A., Toronto Branch as Administrative Agent, incorporated herein by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed July 29, 2013 (File No. 001-35191).

10.2		Forbearance Agreement dated as of September 11, 2013 by and between Lone Pine Resources Canada Ltd., as borrower, Lone Pine Resources Inc., as parent guarantor, JPMorgan Chase Bank, N.A., Toronto Branch, on its own behalf and on behalf of the Majority Lenders, each of the Hedging Lenders party thereto, and each of the other Loan Parties party thereto, incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed September 12, 2013 (File No. 001-35191).

10.3		Form of Support Agreement, dated September 24, 2013, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., Lone Pine Resources Inc.’s other subsidiaries and the Supporting Noteholders, incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed September 25, 2013 (File No. 001-35191).

10.4		Form of Backstop Agreement, dated September 24, 2013, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., Lone Pine Resources Inc.’s other subsidiaries and the Backstopping Noteholders, incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed September 25, 2013 (File No. 001-35191).

10.5		Credit Agreement, dated as of October 24, 2013, among Lone Pine Resources Inc., Lone Pine Resources Canada Ltd., the lenders party thereto and JPMorgan Chase Bank, N.A., Toronto Branch, as Administrative Agent, incorporated by reference to Exhibit 10.1 to Form 8-K for Lone Pine Resources Inc. filed October 30, 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 Chief Executive Officer and Chief 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 Extension Calculation Linkbase Document.

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition.

Monetary Amounts and Exchange Rate Data	iii
Part I - FINANCIAL INFORMATION
Item 1 - Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	1
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012	2
Condensed Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012	2
Condensed Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2013 and 2012	3
Condensed Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2013	4
Notes to Condensed Consolidated Financial Statements	5
Item 2 - Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 3 - Quantitative and Qualitative Disclosures About Market Risk	46
Item 4 - Controls and Procedures	47
Part II - OTHER INFORMATION
Item 1 - Legal Proceedings	48
Item 1A - Risk Factors	49
Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3 - Defaults Upon Senior Securities	51
Item 4 - Mine Safety Disclosures	51
Item 5 - Other Information	51
Item 6 - Exhibits	51
Signatures	52
Exhibit Index	53

	LONE PINE RESOURCES INC.
	(Registrant)

November 8, 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 Chief Financial Officer
		(on behalf of the Registrant)