Exhibit 99.1

Compton Petroleum Corporation                                                                

Consolidated Balance Sheets

(Unaudited) (000’s)

As a	September 30,  2011		December 31, 2010 (note 20)			January 1,  2010 (note 20)
Assets
Current assets:
Cash	$	1,103	$	-		$	-
Trade and other accounts receivable		22,354		29,515			37,389
Risk management, note 15a		4,950		8,041			198
Other current assets, note 17		4,981		4,812			14,287
		33,388		42,368			51,874
Non-current assets:
Development and production, note 3		590,573		751,382			1,609,874
Exploration and evaluation, note 4		41,698		68,550			72,378
Risk management, note 15a		32		-			-
Other long term assets, note 17		2,631		2,620			2,494
Total assets	$	668,322	$	864,920		$	1,736,620
Liabilities
Current liabilities:
Trade and other accounts payable	$	37,114	$	57,755		$	67,909
Credit facility, note 5a		-		145,584			107,183
Risk management, note 15a		-		116			94
Senior term notes, note 6		-		44,757			-
MPP term financing, note 7		5,835		11,098			4,601
		42,949		259,310			179,787
Non-current liabilities:
Credit facility, note 5a		103,130		-			-
Senior term notes, note 6		-		192,455			461,741
Risk management, note 15a		-		-			1,331
MPP term financing, note 7		27,150		34,522			46,807
Provisions, note 9		163,211		184,424			138,998
Deferred income taxes		-		7,011			186,210
Total liabilities		336,440		677,722			1,014,874
Shareholders’ equity
Share capital, note 10b		283,128		416,433			416,425
Share purchase warrants, note 10c		32,255		13,800			13,800
Other reserves		-		40,112			37,043
Retained earnings (deficit)		-		(289,682	)		250,279
Non-controlling interest, note 7		16,499		6,535			4,199
Total equity		331,882		187,198			721,746
Total liabilities and shareholders’ equity	$	668,322	$	864,920		$	1,736,620

Commitments and contingent liabilities, note 18

Subsequent events, note 19

see accompanying notes to the consolidated interim financial statements

On behalf of the Board

A. Loader, M.A.	J. Stephens Allan, C.A.
Director	Director

Compton Petroleum Corporation

Consolidated Interim Statements of Operations and Comprehensive Earnings (Loss)

(Unaudited) (000’s)

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Revenue, net of royalties, note 16	$	38,971		$	36,728		$	109,304		$	146,400
Expenses
Operating		12,213			12,173			36,103			42,707
Transportation		1,650			2,424			4,477			5,816
Administrative		2,179			5,391			11,082			16,630
Royalty obligations, note 16		2,345			2,749			8,849			12,599
Depletion and depreciation		15,284			18,028			44,330			63,373
Exploration and evaluation, note 4		11,358			525			20,975			651
Share based compensation, note 12f		231			975			40			3,039
Foreign exchange and other (gain) loss, note 14		(50,183	)		(10,828	)		(72,430	)		(3,911	)
Risk management (gain) loss, note 15c		(6,498	)		(9,246	)		(7,305	)		(23,191	)
Impairment expense (reversal), note 3		(148	)		44,907			(435	)		117,664
Finance costs
Accretion of decommissioning liabilities		1,131			1,114			3,718			3,400
Interest and financing costs, note 13		6,829			11,436			25,695			39,561
Earnings (loss) before taxes		42,580			(42,920	)		34,205			(131,938	)
Income taxes
Current		-			-			-			-
Deferred		14,273			(9,865	)		10,115			(34,334	)
		14,273			(9,865	)		10,115			(34,334	)
Net earnings (loss)	$	28,307		$	(33,055	)	$	24,090		$	(97,604	)
Net earnings (loss) attributable to:
Non-controlling interest, note 7	$	6,691		$	346		$	9,964		$	1,443
Majority shareholders		21,616			(33,401	)		14,126			(99,047	)
Net earnings (loss) and comprehensive earnings (loss)	$	28,307		$	(33,055	)	$	24,090		$	(97,604	)
Net earnings (loss) per share, note 11
Basic	$	3.26		$	(25.08	)	$	6.34		$	(74.05	)
Diluted	$	2.43		$	(25.08	)	$	3.03		$	(74.05	)

see accompanying notes to the consolidated interim financial statements

September 30, 2011

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Compton Petroleum Corporation

Consolidated Interim Statements of Changes in Equity

(Unaudited) (000’s)

	Capital stock			Share purchase warrants		Other reserves			Retained earnings/ Deficit			Non- controlling interest		Total
Balance at January 1, 2010	$	416,425		$	13,800	$	37,043		$	250,279		$	4,199	$	721,746
Net earnings (loss)		-			-		-			(99,047	)		1,443		(97,604	)
Share based payments		-			-		2,266			-			-		2,266
Options exercised		8			-		-			-			-		8
Balance at September 30, 2010, note 20	$	416,433		$	13,800	$	39,309		$	151,232		$	5,642	$	626,416
Balance at January 1, 2011	$	416,433		$	13,800	$	40,112		$	(289,682	)	$	6,535	$	187,198
Net earnings (loss)		-			-		-			14,126			9,964		24,090
Share issuance, net		197,450			18,455		-			-			-		215,905
Share based payments		-			-		(1,259	)		-			-		(1,259	)
IFRS fair value adjustment, net of tax, note 6		-			-		-			(94,052	)		-		(94,052	)
Reduction of stated capital and other reclassification		(330,755	)		-		(38,853	)		369,608			-		-
Balance at September 30, 2011	$	283,128		$	32,255	$	-		$	-		$	16,499	$	331,882

see accompanying notes to consolidated interim financial statements

September 30, 2011

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Compton Petroleum Corporation

Consolidated Interim Statements of Cash Flow

(Unaudited) (000’s)

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Operating activities
Net earnings (loss)	$	28,307		$	(33,055	)	$	24,090		$	(97,604	)
Amortization and other		(104	)		425			547			6,287
Depletion and depreciation		15,284			18,028			44,330			63,373
Unrealized foreign exchange and other (gains) losses		5,841			(13,860	)		(1,528	)		(7,560	)
Deferred income taxes		14,273			(9,865	)		10,115			(34,334	)
Share based compensation		(554	)		753			(1,259	)		2,266
Accretion of decommissioning liabilities		1,131			1,114			3,718			3,400
Decommissioning expenditures		(774	)		(5,680	)		(1,127	)		(12,708	)
Unrealized risk management (gain) loss		(3,344	)		(5,594	)		2,943			(15,319	)
Impairment		(148	)		44,907			(435	)		117,664
Exploration and evaluation		11,358			525			20,975			651
Non-cash gain on debt extinguishment, note 6		(56,623	)		-			(56,623	)		-
(Gain) loss on asset disposition		-			3,148			(16,329	)		5,688
		14,647			846			29,417			31,804
Change in non-cash working capital		(8,993	)		5,133			(13,407	)		(10,075	)
		5,654			5,979			16,010			21,729
Financing activities
Repayment of credit facility		(26,401	)		-			(43,124	)		(107,183	)
MPP term financing repayment		(7,381	)		(1,314	)		(12,634	)		(3,925	)
Proceeds from equity financing, net of issuance costs, note 6		36,962			-			36,962			5
		3,180			(1,314	)		(18,796	)		(111,103	)
Investing activities
Development and production additions		(5,343	)		(3,148	)		(18,390	)		(14,248	)
Exploration and evaluation additions		(2,388	)		(2,266	)		(3,859	)		(4,443	)
Property acquisitions		-			94			-			(56	)
Development and production dispositions		-			35,983			9,489			153,540
Exploration and evaluation dispositions		-			-			16,649			-
Royalty dispositions		-			-			-			23,469
		(7,731	)		30,663			3,889			158,262
Change in cash		1,103			35,328			1,103			68,888
Cash, beginning of period		-			33,560			-			-
Cash, end of period	$	1,103		$	68,888		$	1,103		$	68,888

see accompanying notes to the consolidated interim financial statements

September 30, 2011

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Compton Petroleum Corporation

Notes to the Interim Consolidated Financial Statements

(Unaudited)

Compton Petroleum Corporation (the “Corporation” or “Compton”), incorporated under the laws of Alberta and domiciled in Canada, is in the business of the exploration for and production of petroleum and natural gas reserves in the Western Canada Sedimentary Basin.  The registered office of the Corporation is as follows:

Suite 500, Bankers Court

850 2nd Street, SW

Calgary, Alberta, Canada

T2P 0R8

1.          BASIS OF PRESENTATION

(a)         Statement of compliance

The consolidated interim financial statements are unaudited and have been prepared in accordance with IAS 34 “Interim Financial Reporting” (“IAS 34”), using accounting policies consistent with the International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board (“IASB”) and Interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).

These interim consolidated financial statements present the results of operations and financial position as at and for the three and nine month periods ended September 30, 2011 and 2010 and will form part of the Corporation’s first IFRS consolidated annual financial statements for the year ending December 31, 2011.  As a result, they have been prepared in accordance with IFRS 1, “First-time Adoption of International Financial Reporting Standards”, with retrospective application of accounting standards as required.  These consolidated interim financial statements do  not include all of the necessary annual disclosures in accordance with IFRS.  Previously, the Corporation prepared its consolidated annual and consolidated interim financial statements in accordance with Canadian Generally Accepted Accounting Principles (“Previous GAAP”).

(b)         Basis of measurement

The consolidated interim financial statements have been prepared on the historical cost basis except for the revaluation of certain non-current assets and financial instruments. Historical cost is generally based on the fair value of the consideration given in exchange for assets recorded on the date of the transaction.  The consolidated interim financial statements have been prepared on a going concern basis.

These interim financial statements have been prepared following the same accounting policies as presented and disclosed in the Q1 2011 interim financial statements (see Note 2).  These policies have been retrospectively and consistently applied except where specific exemptions permitted alternative treatment upon transition to IFRS in accordance with IFRS 1 as disclosed in Note 20 - “Transition to IFRS”.

The consolidated interim financial statements were authorized on November 4, 2011 by the Board of Directors.

(c)         Functional and presentation currency

The functional currency of Compton, and all its consolidated subsidiaries, is Canadian dollars, and all amounts are presented in thousands (000’s) of Canadian dollars herein unless otherwise stated.

September 30, 2011

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2.          SIGNIFICANT ACCOUNTING POLICIES

(a)         Basis of consolidation

The consolidated interim financial statements include the accounts of the Corporation and its wholly owned subsidiaries.  The consolidated interim financial statements also include the accounts of Mazeppa Processing Partnership (the “Partnership” or “MPP”) in accordance with Standing Interpretations Committee Standards 12 (“SIC-12”), Special Purpose Entities, as outlined in Note 7 - “MPP Term Financing and Non-Controlling Interest”.

Interests in jointly controlled assets are included in these financial statements using the proportionate consolidation method and included in the accounts is the Corporation’s proportionate share of revenues, expenses, assets and liabilities.

All inter‐company transactions, balances, income and expenses are eliminated in full on consolidation.

 (b)        Critical accounting judgments and key sources ofmeasurement uncertainty

The timely preparation of consolidated interim financial statements requires that Management make estimates and assumptions and use judgment regarding the measurement of assets, liabilities, revenues, and expenses.  Such estimates relate primarily to transactions and events that have not settled as of the date of the interim financial statements.  Accordingly, actual results may materially differ from estimated amounts as future confirming events occur.

Amounts recorded for depletion and depreciation, and amounts used in impairment test calculations are based upon estimates of petroleum and natural gas reserves and future costs to develop those reserves.  By their nature, these estimates of reserves, costs, and related future cash flows are subject to uncertainty, and the impact on the consolidated financial statements of future periods could be material.

Development and production assets are grouped into cash generating units (“CGUs”) identified as having largely independent cash flows and are geographically integrated.  The determination of these CGUs was based on Management’s interpretation and judgment.

The calculation of decommissioning liabilities includes estimates of the ultimate settlement amounts, inflation factors, risk free rates, and timing of settlement.  The impact of future revisions to these assumptions on the consolidated financial statements of future periods could be material.

The amount of share based compensation expense is subject to uncertainty as it reflects the Corporation’s best estimate of whether or not performance will be achieved and obligations incurred.

The amount ascribed to share purchase warrants upon issue is subject to uncertainty as it reflects the Corporation’s best estimate of fair value at the time of issue.

The estimated inventory allowance recognized to present inventory balances at the lower of cost and net realizable value.

The estimated fair value of risk management contracts is subject to measurement uncertainty as future commodity prices and exchange rates are used in the valuation.

The values of pension assets and obligations and the amount of pension costs charged to earnings depend on certain actuarial and economic assumptions which by their nature are subject to measurement uncertainty.

Tax interpretations, regulations and legislation in which the Corporation and its subsidiaries operate are subject to change.  As such, income taxes are subject to measurement uncertainty.

September 30, 2011

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 (c)         Recent accounting pronouncements

All accounting standards effective for periods on or after January 1, 2011 have been adopted as part of the transition to IFRS.  The following new IFRS pronouncements have been issued or are outstanding in the third quarter, are effective on January 1, 2013, and may have an impact on the Corporation in the future.

• IFRS 9, "Financial Instruments", which is the result of the first phase of the IASB’s project to replace IAS 39, "Financial Instruments: Recognition and Measurement". The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value.

• IFRS 10, "Consolidated Financial Statements", which is the result of the IASB’s project to replace Standing Interpretations Committee 12, "Consolidation - Special Purpose Entities" and the consolidation requirements of IAS 27, "Consolidated and Separate Financial Statements". The new standard eliminates the current risk and rewards approach and establishes control as the single basis for determining the consolidation of an entity.

• IFRS 11, "Joint Arrangements", which is the result of the IASB’s project to replace IAS 31, “Interests in Joint Ventures”. The new standard redefines joint operations and joint ventures and requires joint operations to be proportionately consolidated and joint ventures to be equity accounted. Under IAS 31, joint ventures could be proportionately consolidated.

• IFRS 12, "Disclosure of Interests in Other Entities", which outlines the required disclosures for interests in subsidiaries and joint arrangements. The new disclosures require information that will assist financial statement users to evaluate the nature, risks and financial effects associated with an entity’s interests in subsidiaries and joint arrangements.

• IFRS 13, "Fair Value Measurement", which provides a common definition of fair value, establishes a framework for measuring fair value under IFRS and enhances the disclosures required for fair value measurements. The standard applies where fair value measurements are required and does not require new fair value measurements.

• IAS 19, "Post Employment Benefits", which amends the recognition and measurement of defined benefit pension expense and expands disclosures for all employee benefit plans.

 The Corporation is currently assessing the impact of the new standards, but does not anticipate that the adoption of the standards will have a significant impact on the Corporation’s consolidated financial statements.

September 30, 2011

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3.          DEVELOPMENT AND PRODUCTION

	Development			MPP			Corporate
	costs (1)			Facility			Assets			Total
Cost or deemed cost:
Balance at January 1, 2010	$	1,545,269		$	53,703		$	12,538		$	1,611,510
Additions		42,430			-			1,449			43,879
Transfer from E&E (Note 4)		47			-			-			47
Disposals		(186,490	)		-			-			(186,490	)
Decommissioning adjustment and other		60,972			-			-			60,972
Balance at December 31, 2010	$	1,462,228		$	53,703		$	13,987		$	1,529,918
Additions		18,781			-			168			18,949
Transfer from E&E (Note 4)		3,564			-			-			3,564
Disposals		(15,346	)		-			-			(15,346	)
Decommissioning adjustment and other		(19,639	)		-			-			(19,639	)
Balance at September 30, 2011	$	1,449,588		$	53,703		$	14,155		$	1,517,446
Accumulated depletion, depreciation and impairment losses:
Balance at January 1, 2010	$	(1,636	)	$	-		$	-		$	(1,636	)
Depletion and depreciation		(83,767	)		(2,224	)		(3,043	)		(89,034	)
Impairment loss		(695,395	)		-			-			(695,395	)
Disposals		7,529			-			-			7,529
Other		-			-			-			-
Balance at December 31, 2010	$	(773,269	)	$	(2,224	)	$	(3,043	)	$	(778,536	)
Depletion and depreciation		(40,300	)		(1,668	)		(2,362	)		(44,330	)
Impairment loss, net of reversal		(106,697	)		-			-			(106,697	)
Disposals		2,643			-			-			2,643
Other		47			-			-			47
Balance at September 30, 2011	$	(917,576	)	$	(3,892	)	$	(5,405	)	$	(926,873	)
Net book value:
As at January 1, 2010	$	1,543,633		$	53,703		$	12,538		$	1,609,874
As at December 31, 2010		688,959			51,479			10,944			751,382
As at September 30, 2011	$	532,012		$	49,811		$	8,750		$	590,573

(1) Included in equipment and facilities are finance leases with a cost of $1.6 million (January 1, 2010 - $11.5 million; December 31, 2010 - $8.5 million) and accumulated depletion of $0.3 million (January 1, 2010 - $1.6 million; December 31, 2010 - $1.6 million)

During the nine months ended September 30, 2011, $1.4 million (2010 - $3.3 million) was capitalized directly attributable to compensation, insurance, and other costs.  These costs were a reduction of administrative expenses for the period.

Minor property dispositions at Niton and Centron during the first quarter of 2011 resulted in total proceeds of $26.2 million, and a net gain on sale of $16.4 million.  Net gains include components of both development and production ($1.5 million), and exploration and evaluation ($14.9 million). (See Note 4 - “Exploration and Evaluation”).   There were no significant dispositions in the second and third quarters of 2011.

During 2010, the disposition of properties at Niton and Gilby resulted in gross proceeds of $153.0 million, and a net loss on sale of $5.7 million. Net losses include components of both development and production ($5.2 million), and exploration and evaluation ($0.5 million). (See Note 4 - “Exploration and Evaluation”).

Gains and losses on disposition are presented in foreign exchange and other gains (losses).

September 30, 2011

- 8 -

An impairment test is performed on capitalized property and equipment costs, at the CGU level, when indicators of impairment exist. On transition to IFRS on January 1, 2010, the value of Compton’s development costs were written down by $263.9 million (see Note 20 - “Transition to IFRS”).  Throughout 2010, a further write down of $695.4 million was recorded based on the estimated recoverable amount of Compton’s assets.  The recoverable amount represents the assets value in use, under a 10% discounted cash flow.  These write downs reflect the low natural gas price environment during that time.  At September 30, 2010, $117.2 million impairment was recognized, using a value in use approach at 10% discounted cash flow.

Following the Recapitalization plan (the “Recapitalization”) completed in September 2011, the Corporation’s assets were reduced to their underlying event-driven fair market values, under an optional IFRS 1 election.  The election resulted in a write down to Development and Production assets of $107.1 million, leaving a deemed cost carrying value of $590.6 million.  See Note 6 - “Senior Term Notes” for additional details on the Recapitalization.

At September 30, 2011, no indicators of impairment were identified that would imply a further decline in development and production asset carrying values below the determined deemed cost.

4.          EXPLORATION AND EVALUATION

Balance at January 1, 2010	$	72,378
Additions		6,925
Disposals		(8,620	)
Impairment / land expiries		(2,086	)
Transfers to D&P (Note 3)		(47	)
Balance at December 31, 2010	$	68,550
Additions		3,859
Disposals		(2,126	)
Impairments / land expiries		(25,021	)
Transfers to D&P (Note 3)		(3,564	)
Balance at September 30, 2011	$	41,698

An impairment test is performed on the costs capitalized to exploration and evaluation when indicators of impairment exist.  On transition to IFRS on January 1, 2010, the value of Compton’s exploration and evaluation assets were tested for impairment and no write down was required.  Throughout 2010, a total of $2.1 million of undeveloped land expired and was charged to exploration and evaluation expense. Land expiries and impairment on exploratory well costs charged to exploration and evaluation expense during the nine months ended September 30, 2011 totaled $21.0 million (2010 - $0.7 million).

Following the Recapitalization completed in September 2011, the Corporation’s assets were written down to their underlying event driven fair market values, under an optional IFRS 1 election.  The election resulted in the write down of Exploration and Evaluation assets of $4.0 million, to a $41.7 million deemed cost carrying value.  See Note 6 - “Senior Term Notes” for additional details on the Recapitalization.

At September 30, 2011, no indicators of impairment were identified that would imply a further decline in exploration and evaluation asset carrying values below the determined deemed cost.

September 30, 2011

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5.          DEBT

(a)         Credit facility

	September 30, 2011			December 31, 2010			January 1, 2010
Authorized credit facility	$	160,000		$	170,000		$	220,000
Prime rate loans	$	104,000		$	-		$	37,000
Bankers’ acceptance term loans		-			144,700			70,000
Bank indebtedness, prime rate		-			2,576			1,462
Discount to maturity		(870	)		(1,692	)		(1,279	)
Advances under the credit facility	$	103,130		$	145,584		$	107,183

On September 27, 2011, Compton reached an agreement with a new syndicate of lenders for a credit facility of $160.0 million, including a working capital facility of $15.0 million and a syndicated facility of $145.0 million.  The facility term ends September 26, 2012, with a maturity one year thereafter if not renewed.  The facility is subject to re-determination of the borrowing base semi-annually at September 30 and May 31.  The borrowing base is determined based on, among other things, the Corporation’s current reserve report, results of operations, the lenders view of the current and forecasted commodity prices and the current economic environment.

In addition to the drawn portion of the facility, $0.9 million (December 31, 2010 - $4.3 million) of letters of credit were outstanding in favour of service providers to Compton at September 30, 2011.

Advances under the syndicated facility bear interest at margins determined on the ratio of total consolidated debt to consolidated cash flow which are currently as follows:

   Prime rate and US Base rate plus 1.75%; and

   Bankers’ Acceptances rate and LIBOR rate plus 2.75%.

The effective interest rate on the credit facility at September 30, 2011, was 6.17% (2010 - 5.44%).

The credit facility is secured by a first fixed and floating charge debenture in the amount of $500 million covering all the Corporation’s assets and undertakings.

(b)         Finance leases

Finance leases relate to operating equipment with lease terms ranging from 3 to 5 years. Finance leases have been recognized as assets based on the lower of the respective fair values and present value of future lease payments and any related buyout costs.  The Corporation’s obligations under finance leases are secured by the lessors’ title to the underlying property.  The fair value of the finance lease liabilities approximates the carrying amount.

	Minimum lease payments
	September 30, 2011			December 31, 2010
Not later than one year	$	1,119		$	1,033
Later than one year and not later than five years		447			1,680
Later than five years		-			-
Less future finance charges		(329	)	$	(469	)
Present value of minimum lease payments	$	1,237		$	2,244
Current finance lease obligations	$	832		$	864
Long-term finance lease obligations		405			1,380
Present value of minimum lease payments(1)	$	1,237		$	2,244

(1) Finance leases are included in development and production assets, and trade and other accounts payable

September 30, 2011

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6.         SENIOR TERM NOTE

	September 30,		December 31,		January 1,
	2011		2010		2010
US$193.5 million, 10% due Sept. 15, 2017	$	-	$	192,455	$	-
US$45.0 million, 10% due Sept. 15, 2011		-		44,757		-
US$450.0 million, 7.625% due Dec. 1, 2013		-		-		470,970
Unamortized transaction costs		-		-		(9,229	)
Carrying value	$	-	$	237,212	$	461,741
Current	$	-	$	44,757	$	-
Non-current		-		192,455		461,741
Senior term notes	$	-	$	237,212	$	461,741

During the period, the senior term notes were fully extinguished as part of the approved Recapitalization plan and related elections.  The recognition of key transactional items, in chronological order, are itemized as follows:

• August 10, 2011 - Common shares are consolidated on a 200:1 basis (see Note 10 - “Share Capital” and Note 11 - “Per Share Amounts”);

• August 23, 2011 - Senior term notes are extinguished for common shares, rights, and cashless warrants. These instruments were valued based on individually available market prices.  A net gain of $56.0 million was recognized in current period earnings on extinguishment (see Note 14 - “Foreign Exchange and Other (Gains) Losses”).  Of the $56.0 million gain on debt extinguishment, $56.6 million was considered non-cash and has been excluded from operating cash flow;

• September 27, 2011 - The $37.0 million (gross proceed of $50.0 million, net of issuance costs of $13.0 million) rights offering closes, completing the Recapitalization plan (see Note 10(b) - “Share Capital”);

• September 27, 2011 - The Corporation elected, under IFRS transitional provisions, to take an optional event driven revaluation of the book value of its assets and liabilities based on the negotiated value underlying the transactions, as provided in the approved Management proxy circular dated July 24, 2011.  This resulted in a combined $111.1 million ($94.1 million, net of tax) write-down of its development and production, and exploration and evaluation assets.  The net adjustment was charged directly to retained earnings having no impact on current period earnings or cashflows.  See Note 3 - “Development and Production” and Note 4 - “Exploration and Evaluation”;

• September 30, 2011 - Further to the shareholder resolution approved July 25, 2011, the Corporation reduced its stated capital by eliminating the balances in other reserves, and deficit.  The total stated capital reduction was $330.8 million, and did not affect current period earnings (see Note 10(b) - “Share Capital”).

In October 2010, the Corporation had issued US $193.5 million of senior term notes due September 15, 2017, and US $45.0 million of mandatory convertible notes due September 15, 2011.

7.          MPP TERM FINANCING AND NON-CONTROLLING INTEREST

MPP is a limited partnership organized under the laws of the Province of Alberta and owns certain midstream facilities, including gas plants and pipelines in southern Alberta, through which Compton processes a significant portion of its production from the area.  Compton’s interaction with MPP is governed by agreements (the “MPP Agreements”) which provide for:

(a) Compton’s management of the midstream facility;

(b) the payment by Compton to MPP of a base processing fee and the reimbursement of MPP’s net out-of-pocket costs;

September 30, 2011

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(c) the dedication of Compton’s production and reserves from the defined area through the facilities; and

(d) an option granted to Compton to purchase the MPP partnership at a predetermined amount on April 30, 2014.

Compton is considered to be the primary beneficiary of MPP’s operations, although it does not have an ownership interest in the midstream facilities.  Pursuant to the IASB’s Standing Interpretation’s Committee (“SIC”) 12, Consolidation - Special Purpose Entities, the assets, liabilities, and operations of the Partnership are consolidated in these financial statements.  The equity in MPP is attributable to its third party owners and is recorded as a non-controlling interest in these consolidated financial statements, comprised of the following:

	September 30, 2011		December 31, 2010		January 1, 2010
Non-controlling interest, beginning of period	$	6,535	$	4,199	$	59,762
Earnings attributable to non-controlling interest		9,964		2,336		3,259
Distributions to limited partner		-		-		(3,822	)
MPP term financing		-		-		(55,000	)
Non-controlling interest, end of period(1)	$	16,499	$	6,535	$	4,199

(1) Non-controlling interest includes all purchase option prepayments made prior to April 30, 2014.

On April 30, 2009, Compton completed the renegotiation of the MPP Agreements for a further term of five years.  All agreements expire on April 30, 2014 with the exception of the agreement that dedicates Compton’s production and reserves from the defined area to the facilities which continues through April 30, 2024.  At the time of the renegotiation, $55.0 million of the non-controlling interest was transferred to the MPP term financing caption in these consolidated financial statements, with a corresponding reduction in the non-controlling interest.  The MPP term financing is comprised of:

	September 30, 2011			December 31, 2010			January 1,  2010
Present value of the base processing fee	$	15,685		$	19,552		$	24,287
Purchase option		17,700			26,588			27,800
Unamortized transaction costs		(400	)		(520	)		(679	)
MPP term financing	$	32,985		$	45,620		$	51,408

The base processing fee component of the MPP term financing is accounted for as an amortizing obligation paid in full over its term to April 30, 2014, through a monthly principal and interest payment totaling $0.8 million per month. The effective rate of interest is 11.68% per annum.

In these consolidated financial statements, the MPP net out-of-pocket costs are included in operating expense, the interest component of the base processing fee is included in interest and financing charges expense and the principal component of the base processing fee is recorded as a reduction in the MPP term financing liability.

The purchase option represents the pre-determined price at which Compton may, at its discretion, purchase the MPP partnership on April 30, 2014.  If Compton does not exercise this purchase option it may renew the MPP Agreements with terms and conditions to be negotiated at that time, or enter into an arrangement with the owners of the MPP facilities to process natural gas for the Corporation at a fee to be determined at that time.

The MPP Agreements prescribe minimum throughput volumes and dedicated reserves which, if not exceeded, may require a buy-down of the purchase option.  The minimum throughput volume of 56.0 mmcf/d is an average of the throughput volume of the preceding two consecutive calendar quarters.  The prepayment amount is $400,000 per 1.0 mmcf/d of shortfall.  Each prepayment of the purchase option will cause the minimum throughput volume to be adjusted downward to the average throughput volume of the preceding two consecutive calendar quarters.  In the event that the estimated dedicated reserves, as projected at April 30, 2014, are less than 200 BCF or have a discounted reserve value of less than $250 million using a 10% discount rate, the prepayment amount is the greater of $108,000 per $1 million of reserve value shortfall and $135,000 per 1.0 BCF of the reserves shortfall.

September 30, 2011

- 12 -

As of September 30, 2011, the threshold throughput volume was reduced to 55.2 mmcf/d.  The cumulative prepayment of the purchase option since the renewal of the MPP Agreements in April 2009 is $10.1 million, including $8.9 million in 2011. The prepayments have reduced the amount of the MPP term financing liability.  Subsequent to quarter end, a payment of $0.3 million was made for the period ending September 30, 2011.

8.         CAPITAL STRUCTURE

The Corporation’s capital structure is comprised of working capital, long-term debt, and shareholders’ equity.  The Corporation’s objectives when managing its capital structure are to:

(a) ensure the Corporation can meet its financial obligations;

(b) retain an appropriate level of leverage relative to the risk of Compton’s underlying assets; and

(c) finance internally generated growth and potential acquisitions.

Compton manages its capital structure based on changes in economic conditions and the Corporation’s planned capital requirements.  Compton has the ability to adjust its capital structure by making modifications to its capital expenditure program, divesting of assets and by altering debt levels or issuing equity.

The Corporation monitors its capital structure and financing requirements using non-GAAP measures consisting of total net debt to capitalization and total net debt to “Adjusted EBITDA”.  Adjusted EBITDA is defined as net earnings before interest and finance charges, income taxes, depletion and depreciation, accretion of decommissioning liabilities, unrealized foreign exchange and other gains (losses), unrealized risk management gains (losses) and other non-recurring expenses.

Compton targets a total net debt to capitalization ratio of between 40% and 50% calculated as follows:

	September 30, 2011			December 31, 2010			January 1,  2010
Working capital (surplus) deficiency(1)	$	8,676		$	23,428		$	16,233
Credit facility(2)		103,130			145,584			107,183
MPP term financing(3)		32,985			45,620			51,408
Senior term notes(4)		-			237,212			461,741
Total net debt		144,791			451,844			636,565
Total shareholders’ equity		331,882			187,198			721,746
Total capitalization	$	476,673		$	639,042		$	1,358,311
Total net debt to capitalization ratio		30.4	%		70.7	%		46.9	%

(1) Adjusted working capital excludes risk management, current MPP term financing and the credit facility

(2) Includes unamortized transaction costs of $870 (December 31, 2010 - $1,692; January 1, 2010 - $1,279)

(3) Includes unamortized financing fees of $400 (December 31, 2010 - $520; January 1, 2010 - $679)

(4) Includes unamortized original issue discount and related transaction costs of $nil (December 31, 2010 - $nil; January 1, 2010 - $9,229)

Following the Recapitalization, the Corporation met the targeted net debt to capitalization ratio as well as the net debt to adjusted EBITDA target at September 30, 2011.  Previously, both metrics had fallen outside of Management’s target ranges.

In the first quarter of 2011, property sales for gross proceeds of $26.2 million were used to repay a portion of the credit facility with the balance applied to working capital.  In the third quarter of 2011, the extinguishment of the senior term notes and gross share issuance proceeds of $50.0 million significantly reduced total net debt.

September 30, 2011

- 13 -

In 2010, the final 1.25% component of an overriding royalty interest (totaling 5%) was sold for gross proceeds of $23.8 million, which along with sale proceeds of $153.0 million from property dispositions were applied to reduce the credit facility.  In addition, the completion of the Arrangement in respect of the Notes further reduced Compton’s net debt position; see Note 6 - “Senior Term Notes”.

Shareholder equity was reduced as part of the transition to IFRS and the resulting adjustments recorded during 2010 negatively impacted net loss and deficit.  These adjustments are disclosed in more detail in Note 20 - “Transition to IFRS”.

Compton targets a total net debt to Adjusted EBITDA of 2.5 to 3.0 times.  At September 30, 2011, total net debt to Adjusted EBITDA was 1.7x (December 31, 2010 - 4.1x) calculated on a trailing 12 month basis as follows:

	September 30, 2011			December 31,  2010
Total net debt	$	144,791		$	451,844
12 months ended	September 30, 2011			December 31,  2010
Net loss	$	(426,787	)	$	(539,961	)
Add (deduct)
Interest and finance charges		36,422			50,288
Income taxes		(134,823	)		(179,272	)
Depletion and depreciation		70,372			89,415
Accretion of decommissioning liabilities		4,822			4,504
Unrealized foreign exchange (gains) losses		1,190			(4,842	)
Unrealized risk management (gains) losses		9,111			(9,151	)
Loss (Gain) on sale of assets		(15,553	)		5,252
Gain on debt extinguishment		(65,002	)		(9,040	)
Other expenses		5,039			5,039
Exploration and evaluation		22,410			2,086
Impairment		577,296			695,395
Adjusted EBITDA	$	84,497		$	109,713
Total net debt to adjusted EBITDA		1.7	x		4.1	x

Low natural gas prices over the past two years have affected the Corporation’s Adjusted EBITDA.  Compton’s total net debt to Adjusted EBITDA at September 30, 2011, was below the internal targeted ratio of 2.5 to 3.0 times.  The Corporation has taken significant steps to reduce its overall debt to achieve its internal targets, including the Recapitalization completed in the quarter.

Compton is subject to certain covenants relating to its credit facility.  At September 30, 2011, the Corporation was in compliance with the covenants of the credit facility.

9.         PROVISIONS

(a)        Decommissioning liabilities

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the liabilities associated with the decommissioning of oil and natural gas assets:

September 30, 2011

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	September 30, 2011			December 31,  2010
Decommissioning liabilities, beginning of period	$	184,424		$	125,105
Liabilities incurred		154			4,754
Liabilities settled and disposed		(4,833	)		(10,911	)
Accretion expense		3,718			4,504
Revision of estimate		(20,252	)		60,972
Decommissioning liabilities, end of period	$	163,211		$	184,424

The total undiscounted amount of estimated cash flows required to settle the liabilities, net of salvage, at September 30, 2011 was $156.3 million (December 31, 2010 - $234.3 million, January 1, 2010 - $139.0 million).   Salvage values included in determining the undiscounted cash flows were $103.5 million at September 30, 2011 (December 31, 2010 - $108.5 million, January 1, 2010 - $135.5 million).  The decommissioning liability has been determined without inclusion of the salvage values, and discounted using a risk free rate ranging from 1.4% to 2.8% (December 31, 2010 - 2.4% to 3.5%, January 1, 2010 - 2.8% to 4.1%) depending on the reserve life.    Due to the Corporation’s long reserve life, the majority of these liabilities are not expected to be settled until well into the future.  Settlements are expected to be funded from general Corporation resources at the time of decommissioning and removal.

(b) Lease surrender obligations

Included in provisions at the time of transition to IFRS was $13.9 million related to the surrender of unused office space.  The lease was determined by Management to be an onerous contract, and the provision included in these financial statements reflects the present value of estimated net cash flows to the end of the original lease term.  The provision for unused office space was settled in third quarter of 2010.

 10 SHARE CAPITAL

 (a) Authorized

The Corporation is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares, issuable in series.

(b) Issued, outstanding and fully paid

	Number of Shares			Amount
Common shares outstanding,
January 1, 2010		263,660		$	416,425
Shares issued under stock option plan		6			8
Common shares outstanding,
December 31, 2010		263,666		$	416,433
Share consolidation(1)		(262,347	)		-
Shares issued under Recapitalization plan, net(2)		25,040			197,450
Stated capital reduction(3)		-			(330,755	)
Common shares outstanding,
September 30, 2011		26,359		$	283,128

1) Effective August 10, 2011, the Corporation completed a 200:1 consolidation of its common shares.  The share consolidation was affected prior to the issuance of common shares and cashless warrants under the Recapitalization plan.

2) The Recapitalization plan included the issuance of common shares on the conversion of the senior term notes, and a $50.0 million rights offering; net of share issuance costs of $13.0 million

3) On July 25, 2011, the shareholders of the Corporation approved a stated capital reduction to transfer balances within Shareholders’ Equity.  The adjustments, eliminating other reserves of $38.9 million and deficit of $369.6 million, have been affected as of September 30, 2011 following the Recapitalization.

September 30, 2011

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(c) Cashless warrants

A total of 3,690,982 cashless warrants, expiring August 24, 2014, were issued to existing shareholders.  Two cashless warrants were issued for each common share held post consolidation.  Cashless warrants were valued at $5.00 per unit, based on market exchange pricing at the time of issue.  The cashless warrants will be settled with common shares subject to the share price triggers and dates noted below:

Prior to August 23, 2012	$11.92
August 24, 2012 to August 23, 2013	$12.52
August 24, 2013 to August 23, 2014	$13.14

 (d) Shareholder rights plan

The Corporation has a shareholder rights plan (the “Plan”) to ensure all shareholders are treated fairly in the event of a take-over offer or other acquisition of control of the Corporation.

Pursuant to the Plan, the Board of Directors authorized and declared the distribution of one Right in respect of each common share outstanding.  In the event that an acquisition of 20% or more of the Corporation’s shares is completed and the acquisition is not a permitted bid, as defined by the Plan, each Right will permit the holder, other than holders not in compliance with the Plan, to acquire a common share at a 50% discount to the market price at that time.

The Recapitalization completed during the quarter did not trigger the shareholder rights plan.

11. PER SHARE AMOUNTS

The following table summarizes the common shares used in calculating net loss per common share:

	three months ended, September 30,				nine months ended September 30,
	2011		2010		2011		2010
Weighted average common shares		8,684		1,318		3,801		1,318
outstanding - basic(1)
Effect of mandatory convertible notes		3,241		-		4,753		-
Effect of stock options and warrants		-		-		-		-
Weighted average common shares		11,925		1,318		8,554		1,318
outstanding - diluted(1) (2)

(1) Effective August 10, 2011, the Corporation completed a 200:1 consolidation of its common shares.  Prior period weighted average shares were restated for comparative purposes.

(2) $0.7 million and $1.8 million related to interest expense on the mandatory convertible notes for the three and nine months ended September 30, 2011, respectively, have been added to net earnings for the determination of dilutive earnings per share.

In calculating diluted loss per common share for the nine months ended September 30, 2011, the Corporation excluded 1,913 options (2010 - 76,799) and 690,000 share purchase warrants (2010 - 690,000) as the exercise price was greater than the average price of its common shares in these periods.

12. SHARE BASED COMPENSATION PLANS

(a) Stock option plan and employee long term incentive

In conjunction with the Recapitalization, substantially all of the employees, officers and directors voluntarily surrendered their stock options in June 2011. The Corporation may issue new stock options at some point in the future as determined by the compensation committee of the Board of Directors.  A total of 1,913 options remain outstanding at September 30, 2011 with an average exercise price of $690.23.  The outstanding stock options have been restated to reflect the share consolidation.

September 30, 2011

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In 2011, the Corporation implemented a fixed value long term incentive award for employees to replace of the historical stock option plan.  The fixed awards were to vest over three years, and were payable in cash or common shares at the discretion of the Corporation.  The 2011 awards were settled for cash following the change in control triggered by the Recapitalization.

(b) Share purchase plan

The Corporation offers a share purchase plan to all of its employees.  This program enables employees to receive corporate contributions, in the form of Compton Petroleum Corporation common shares, at a matched percentage to individual contributions (subject to a maximum).  The corporate contributions vest to the employee immediately and are made with each payroll deposit.

(c) Restricted share unit plan

In 2008, the Corporation implemented a Restricted Share Unit Plan (“RSU” or “the RSU Plan”) for employees, officers and directors.  At September 30, 2011, all RSUs issued under the RSU Plan were fully settled, and the program discontinued.

The Corporation has proposed a new RSU plan that was still pending Board of Director ratification at September 30, 2011.

(d) Deferred share unit plan

In 2011, the Corporation implemented a Deferred Share Unit Plan (“DSU” or “the DSU Plan”) for directors.  The purpose of the DSU Plan is to attract and retain qualified, high caliber and talented individuals to serve as members of the Board and to promote a greater alignment of interests between independent members of the Board and the shareholders of the Corporation. DSU awards vest immediately, and are expensed in the current period.  Awards are payable upon cessation of each directors role in cash or in common shares at the discretion of Management.  A maximum of 9,375 common shares have been authorized by the Board of Directors for settlement of DSU awards outstanding.

At September 30, 2011, a total of 1,186 DSUs were outstanding, issued at a price of $59.00 per unit.  During the quarter, 2,458 DSUs were settled for cash at a price of $12.60 per unit.  The DSUs have been restated to reflect the share consolidation.

(e) Retention share plan

In 2011, the Corporation implemented a Retention Share Plan (“Retention Shares” or “the Retention Plan”) for executives.  The Retention Plan was put in place following the revision of compensation arrangements with the executive.  The Retention Plan provided for fixed awards to executives totaling $1.5 million, payable equally over a three year term.   Awards were payable to a maximum of 50% in common shares, and minimum 50% in cash at the discretion of the Corporation. The Retention Plan was settled entirely for cash following the change in control triggered by the Recapitalization.

September 30, 2011

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(f) Share based compensation expense

The following table presents amounts charged to share based compensation expense:

	three months ended September 30,					nine months ended September 30,
	2011			2010		2011			2010
Stock option plan(1) (2)	$	(22	)	$	753	$	(1,443	)	$	2,266
Employee long term incentive(1)		66			-		397			-
Deferred share unit plan		-			-		215			-
Retention share plan(1)		59			-		325			-
Share purchase plan		128			222		546			773
	$	231		$	975	$	40		$	3,039

(1) The Corporation is currently reviewing share based compensation plans following the close of the Recapitalization.

(2) Included in stock based compensation expense for the three and nine months ended September 30, 2011, there were non-cash components of $(554) and $(1,259), respectively (three months 2010 - $753, nine months 2010 - $2,266).

13. INTEREST AND FINANCE CHARGES

During the period, the following financing charges were expensed through net earnings:

	three months ended September 30,				nine months ended September 30,
	2011		2010		2011		2010
Interest on senior term notes	$	3,397	$	9,379	$	14,910	$	28,023
Interest on credit facility		2,202		14		6,413		2,692
Interest on capital lease obligations		23		39		70		1,187
Other interest and finance charges		1,207		2,004		4,302		7,659
	$	6,829	$	11,436	$	25,695	$	39,561

During the nine months ended September 30, 2011, no borrowing costs were capitalized (2010 - $nil) in respect of capital projects currently in process.

Other finance charges include bank service charges and fees as well as other miscellaneous interest revenue and expenses.

September 30, 2011

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14. FOREIGN EXCHANGE AND OTHER (GAINS) LOSSES

During the period, the following foreign exchange and other (gains) losses were charged through net earnings:

	three months ended September 30,						nine months ended September 30,
	2011			2010			2011			2010
Foreign exchange loss/(gain) on translation of US$ debt	$	5,841		$	(13,860	)	$	(1,528	)	$	(7,560	)
Gain on extinguishment of US$ debt(1)		(55,962	)		-			(55,962	)		-
(Gain)/loss on disposition of assets		(83	)		3,148			(15,117	)		5,688
Other		21			(116	)		177			(2,039	)
Foreign exchange and other (gains) losses	$	(50,183	)	$	(10,828	)	$	(72,430	)	$	(3,911	)

(1) On August 23, 2011 the USD senior term notes were converted to equity and fully extinguished (see Note 6 - “Senior Term Notes”).

15. RISK MANAGEMENT

At September 30, 2011, the Corporation’s financial assets and liabilities consist of cash, trade and other accounts receivable, trade and other accounts payable, credit facility, risk management assets and liabilities relating to the use of derivative financial instruments and MPP term financing.

The following summarizes a) fair value of financial assets and liabilities, b) risk management assets and liabilities, c) risk management gains and losses and d) risk associated with financial assets and liabilities.

(a) Fair value of financial assets and liabilities

The carrying amount and fair value of financial assets and liabilities were as follows:

	September 30,  2011				December 31, 2010				January 1,  2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets
Fair value through profit or loss
Risk management(1)	$	4,982	$	4,982	$	8,041	$	8,041	$	198	$	198
Loans and receivables
Accounts receivable		22,354		22,354		29,515		29,515		37,389		37,389
Cash		1,103		1,103		-		-		-		-
Financial liabilities
Fair value through profit or loss
Risk management(1)	$	-	$	-	$	116	$	116	$	1,425	$	1,425
Financial liabilities measured at amortized cost
Accounts payable		37,114		37,114		57,755		57,755		67,609		67,609
Credit facility		103,130		104,000		145,584		147,276		107,183		108,462
MPP term financing(1)		32,985		33,385		45,620		46,140		51,408		52,087
Senior term notes		-		-		237,212		202,810		461,741		362,647

     (1)       Includes current and long term

Financial instruments of the Corporation carried on the consolidated interim balance sheets are carried at amortized cost with the exception of financial derivative instruments, which are carried at fair value. The Corporation classifies the fair value of these transactions according to the following hierarchy.

• Level 1 - quoted prices in active markets for identical financial instruments.

September 30, 2011

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• Level 2 - quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant and significant value drivers are observable in active markets.

• Level 3 - valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable.

The Corporation’s financial derivative instruments have been assessed on the fair value hierarchy described above and classified Level 2.

The carrying amount of cash, trade and other accounts receivable, and trade and other accounts payable approximate fair value due to the short term nature of these instruments and variable rates of interest.  The credit facility and MPP term financing fair values approximate their carrying value, without the effect of amounts being amortized for accounting purposes.  The senior term notes traded in the US and the estimated fair value was determined using quoted market prices.  Risk management assets and liabilities are recorded at their estimated fair value based on the mark to market method of accounting, using quoted market prices, third-party indicators and forecasts.  Management also considers credit risk exposure on all assets and liabilities, and adjusts fair values where appropriate.

The following table reconciles the changes in the fair value of financial instruments outstanding. Changes in fair value are the result of comparing external counterparty information, which is compared to observable market data.

Risk management	September 30, 2011			December 31,  2010
Balance, beginning of period	$	7,925		$	(1,227	)
Unrealized gain (loss) on financial instruments:
Commodity collars and swaps		(3,301	)		9,146
Electricity swaps		305			59
Foreign exchange forwards		53			(53	)
Fair value, end of period	$	4,982		$	7,925
Total fair value consists of the following:
Fair value - current portion, net	$	4,950		$	7,925
Fair value - long-term portion, net		32			-
Total fair value, end of period	$	4,982		$	7,925

(b) Risk management assets and liabilities

(i) Net risk management positions

Risk management assets and liabilities relate to unrealized gains and losses associated with commodity price risk management and foreign currency risk management and are classified on the balance sheet as follows:

	September 30, 2011		December 31, 2010			January 1, 2010
Risk management asset
Current asset	$	4,950	$	8,041		$	198
Non-current asset		32		-			-
Risk management liability
Current liability		-		(116	)		(94	)
Non-current liability		-		-			(1,331	)
Net risk management asset (liability)	$	4,982	$	7,925		$	(1,227	)

September 30, 2011

- 20 -

(ii) Net fair value of commodity positions

On September 30, 2011, the Corporation had the following commodity contracts in place, expressed in Canadian dollars unless otherwise noted:

Commodity	Term	Volume	Average Price		Mark-to- Market Gain (Loss)
Commodity
Natural Gas
Collar	Jul./09 - Oct./11	10,000 GJ/d	$4.50 - $7.00/GJ	$	313
US$ Swap	Apr./11 - Oct./11	15,000 MMBtu/d	$4.64 / MMBtu		426
US$ Basis	Apr./11 - Oct./11	15,000 MMBtu/d	($0.64) / MMBtu		(181)
Swap	Jul./11 - Dec./11	10,000 GJ/d	$5.00 / GJ		1,390
US$ Swap	Jul./11 - Dec./12	10,000 MMBtu/d	$4.65 / MMBtu		4,516
Oil
US$ Option	Jan./12 - Dec./12	1,000 Bbl/d	$100.00 / Bbl		(1,689)
US$ Option	Jul./11 - Dec./11	1,000 Bbl/d	$101.60 / Bbl		(35)
Electricity
Swap	Jan./10 - Dec./11	84 MWh/d	$50.74 / MWh		242
Total unrealized commodity gain (loss)				$	4,982

(c) Risk management gains and losses

Risk management gains and losses recognized in net earnings during the period relating to commodity prices and foreign currency transactions are summarized below:

Nine months ended September 30	Commodity Contracts			Foreign Currency			2011 Total			2010 Total
Unrealized change in fair value	$	2,996		$	(53	)	$	2,943		$	(15,319	)
Realized cash settlements		(10,248	)		-			(10,248	)		(7,872	)
Total (gain) loss	$	(7,252	)	$	(53	)	$	(7,305	)	$	(23,191	)

Three months ended September 30	Commodity Contracts			Foreign Currency			2011 Total			2010 Total
Unrealized change in fair value	$	(2,985	)	$	(359	)	$	(3,344	)	$	(5,594	)
Realized cash settlements		(3,154	)		-			(3,154	)		(3,652	)
Total (gain) loss	$	(6,139	)	$	(359	)	$	(6,498	)	$	(9,246	)

The gains and losses realized during the year on the electricity contract are included in operating expenses.

September 30, 2011

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 (d) Risk associated with financial assets and liabilities

The Corporation is exposed to financial risks arising from its financial assets and liabilities which fluctuate in value due to movements in market prices and is comprised of the following:

    (i)     Market risk

Market risk is the risk that the fair value or future cash flows from financial assets or liabilities will fluctuate due to movements in market prices and is comprised of the following:

—       Commodity price risk

The Corporation is exposed to commodity price movements as part of its normal oil and gas operations.  Under guidelines established and approved by the Board of Directors, Compton enters into economic hedge transactions relating to crude oil, natural gas and electricity prices to mitigate volatility in commodity prices and the resulting impact on cash flows.  The contracts entered into are forward transactions providing the Corporation with a range of prices on the commodities sold.  Prices are marked to industry benchmarks specifically to AECO and Henry Hub monthly prices for gas contracts, WTI Nymex for crude oil contracts and AESO for electricity contracts.  Prices are valued in Canadian and United States dollars unless otherwise disclosed.  The Corporation does not use derivative contracts for speculative purposes.

With respect to AECO settled commodity contracts in place at September 30, 2011, an increase of $0.25/mcf in the price of natural gas, holding all other variables constant, would have reduced the fair value of the derivative financial instrument and decreased after tax earnings by approximately $1.0 million (2010 - $1.7 million).  A similar decline in commodity prices would have had the opposite impact.

An increase of US$0.25/MMBtu in the price of NYMEX gas settled contracts, holding all other variables constant, would have reduced the fair value of the derivative financial instrument and decreased after tax earnings by approximately $0.2 million (2010 - N/A).  A similar decline in commodity prices would have had the opposite impact.

An increase of US$0.25/bbl in the price of crude oil, holding all other variables constant, would have reduced the fair value of the derivative financial instrument and decreased after tax earnings by approximately $0.1 million (2010 - N/A).  A similar decline in commodity prices would have had the opposite impact.

—       Foreign exchange rate risk

The Corporation is exposed to fluctuations in the exchange rate between the Canadian dollar and the US dollar.  Crude oil and to a certain extent natural gas prices are based upon reference prices denominated in US dollars, while the majority of the Corporation’s expenses are denominated in Canadian dollars.

—       Interest rate risk

The Corporation is exposed to interest rate risk principally associated with borrowings.  Floating rates, associated with bank debt, expose the Corporation to short-term movements in interest rates.

The Corporation’s cash flows are impacted by changes in interest rates on the floating rate bank debt.  At September 30, 2011, a 100bps change in interest rates would have impacted after tax earnings by $1.0 million (2010 - $0.3 million) assuming the change in interest rates occurred at the beginning of the year.

(ii)    Credit risk

The Corporation is exposed to credit risk, which is the risk that a counterparty will fail to perform an obligation or settle a liability, resulting in a financial loss to the Corporation.

September 30, 2011

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A significant portion of Compton’s trade and other accounts receivable and other current asset balances are with entities in the oil and gas industry and subject to normal industry credit risks.  The allowance for doubtful accounts is less than 5% of total balances and relates to receivables acquired through corporate acquisitions and unresolved differences with partners.  Substantially all of the receivable balances at September 30, 2011 were current.

In-the-money derivative financial instrument contracts are with investment grade Canadian and US financial institutions that are also members of the Corporation’s banking syndicate.  At September 30, 2011, three financial institutions held all of the outstanding financial instrument contracts.

The Corporation regularly assesses the financial strength of its marketing customers and limits the total exposure to individual counterparties based on management determined criteria.  As well, a number of contracts contain provisions that allow Compton to demand the posting of collateral in the event of a downgrade to a non-investment grade credit rating.

The maximum credit risk exposure associated with the Corporation’s financial assets is the carrying amount.

(iii)   Liquidity risk

Compton is exposed to liquidity risk, which is the risk that the Corporation will be unable to generate or obtain sufficient cash to meet its commitments as they come due.  Mitigation of this risk is achieved through the active management of cash and debt requirements over the next 12 months.  In managing liquidity risk, in addition to cash flow generated from operating activities, the Corporation has funds available under its credit facility.  The credit facility provides for accommodations by way of prime loan, bankers’ acceptance, US base rate loan or LIBOR loan.  Canadian and US direct advances bear interest at the bank’s prime lending rate plus applicable margins.  Amounts drawn through bankers’ acceptance or LIBOR loans bear interest at the market rate for these products plus a stamping fee based on the Corporation’s debt to trailing cash flow ratio.  On September 27, 2011, the Corporation entered into a new syndicated credit facility to September 26, 2012 under conditions outlined in Note 5a - “Debt”.  Compton believes it has the ability to adjust its capital structure by making modifications to its capital expenditure program, divesting of assets and by issuing new debt or equity to maintain liquidity.  See also Note 18 - “Commitments and Contingent Liabilities”.

16. ROYALTIES

Revenue recognized in net earnings is reduced by crown and freehold royalties.  The Corporation’s total royalty expense for the nine months ended September 30, 2011 was $27.3 million (2010 - $38.3 million).

	three months ended September 30,					nine months ended September 30,
	2011			2010		2011		2010
Crown	$	2,597		$	4,861	$	12,808	$	19,046
Freehold		1,825			1,884		5,675		6,705
Offset to revenue		4,422			6,745		18,483		25,751
Overriding royalty		1,947			1,957		5,728		7,445
Other royalties		508			790		1,517		2,833
Freehold mineral taxes		(110	)		2		1,604		2,321
Royalty obligations expense		2,345			2,749		8,849		12,599
Total royalties	$	6,767		$	9,494	$	27,332	$	38,350

September 30, 2011

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17. OTHER ASSETS

	September 30, 2011		December 31, 2010			January 1,  2010
Prepaid expenses	$	2,518	$	1,602		$	538
Marketable securities		-		-			3,830
Deposits		2,463		3,210			9,919
Other current assets	$	4,981	$	4,812		$	14,287
Inventory(1)	$	2,076	$	2,175		$	2,175
Pension asset		470		470			344
Other		85		(25	)		(25	)
Other long term assets	$	2,631	$	2,620		$	2,494

(1)      Presented net of allowance of $1.5 million (December 31, 2010 - $1.5 million, January 1, 2010 - $1.5 million), to adjust to realizable value

18. COMMITMENTS AND CONTINGENT LIABILITIES

(a) Commitments

The Corporation has committed to certain payments over the next five years, as follows:

	2011		2012		2013		2014		2015		Thereafter
Credit facility	$	-	$	-	$	104,000	$	-	$	-	$	-
MPP term financing(1)		2,702		9,592		9,592		20,594		-		-
Accounts payable		37,114		-		-		-		-		-
Finance leases		90		1,030		224		224		-		-
Office facilities		473		1,938		2,001		2,001		2,046		5,449
	$	40,379	$	12,560	$	115,817	$	22,819	$	2,046	$	5,449

(1)         Represents monthly fixed base fee payments; the 2011 amount includes purchase option repayments of $0.3 million

Payments to MPP relate to payments made pursuant to a processing agreement between the Corporation and MPP which, together with associated management and option agreements, expire on April 30, 2014

Commitments on finance leases relate to arrangements on certain production facilities (see Note 5b - “Finance Leases”), and include monthly rental payments as well as the buyout option at the end of the lease term.  It is the Corporation’s intention to purchase these assets as they come due.

The Corporation has an overriding royalty (“ORR”) obligation of 5.0% to a third party.  The ORR represents a commitment of the Corporation’s future gross production revenue, less certain transportation costs and marketing fees, on the existing land base as at September 26, 2009.

(b) Legal proceedings

The Corporation is involved in various legal claims associated with normal operations.  In Management’s opinion, it has accrued adequate amounts based on its assessment of probability for these claims, and although unresolved at the current time, are not significant and are not expected to have a material impact on the financial position or results of operations of the Corporation.

19. SUBSEQUENT EVENTS

Subsequent to the quarter end, the Corporation announced the signing of a farmout and joint venture agreement related its 79,000 net acres of undeveloped land holdings in northern Montana.  The farmout joint venture grants the joint venture partner the ability to earn a 50% interest in this area by incurring capital expenditures on the exploration and development of the property. Compton will retain a 50% working interest in the area without incurring any capital expenditure commitments. At their cost, the joint venture partner has committed to the completion of a survey program at a minimum cost of $2.0 million on or before July 31, 2012 and the drilling of a test well on or before December 31, 2012.

September 30, 2011

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On October 5, 2011, 690,000 warrants, adjusted for the share consolidation, issued in October 2009 expired without being exercised.

20. TRANSITION TO IFRS

The Corporation’s consolidated interim financial statements for the nine months ended September 30, 2011 are presented under IFRS and prepared in accordance with IAS 34 and IFRS 1, and as such include the application of IFRS 1 “First-Time Adoption of International Financial Reporting Standards” (“IFRS 1”).

IFRS 1 requires all first-time adopters to retrospectively apply all effective IFRS standards as of the transition date of January 1, 2010.  However, it also provides certain optional exemptions and certain mandatory exceptions for first time IFRS adopters.

The Corporation has taken the following key optional exemptions upon transition to IFRS:

Deemed cost election for petroleum and natural gas assets

Under IFRS 1, the Corporation was allowed and elected to deem the value of its petroleum and natural gas assets, at the date of transition, based on the historical cost under Previous GAAP.

Decommissioning liabilities included in the cost of development and production

Under Previous GAAP, decommissioning liabilities were discounted at a credit adjusted risk free rate.  Under IFRS the estimated cash flow to abandon and remediate the wells and fields has been risk adjusted; therefore the provision recognized on the balance sheet has been discounted at a risk free rate.

Business combinations

Compton has entered into business combinations before the date of transition of January 1, 2010. Compton has not elected to adopt IFRS 3 “Business Combinations” retrospectively.  As a result, the classification of acquisitions under Previous GAAP will remain the same with no change in the recognition of assets and liabilities, excluding goodwill.

Reconciliations of Previous GAAP to IFRS

IFRS 1 requires an entity to reconcile balance sheets, equity, net earnings, comprehensive income and cash flows for prior periods. The following reconciliations present the adjustments made to the Corporation’s previously reported financial results in compliance with IFRS 1.  Reconciliations include the consolidated balance sheet as at September 30, 2010, and consolidated statements of operation and comprehensive loss for the three and nine months ended September 30, 2010 and equity for the nine months ended September 30, 2010.  Full transitional disclosures under IFRS 1 were provided in the Corporation’s first interim financial statements for the three months ended March 31, 2011.

The Corporation’s first time adoption of IFRS did not have a significant impact on the total operating, investing or financing cash flows.

September 30, 2011

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Balance Sheet As at September 30, 2010
	Notes	Previous GAAP		Effect of transition to IFRS			IFRS
CURRENT ASSETS
Cash		$	68,888	$	-		$	68,888
Trade and other accounts receivable			24,346		-			24,346
Risk management			14,054		-			14,054
Other assets			7,255		-			7,255
Deferred income tax	[a]		55		(55	)		-
			114,598		(55	)		114,543
Development and production	[b, c, d, h, j]		1,701,226		(411,734	)		1,289,492
Exploration and evaluation	[c]		-		67,551			67,551
Risk management			283		-			283
Other assets	[d]		743		1,815			2,558
TOTAL ASSETS		$	1,816,850	$	(342,423	)	$	1,474,427
CURRENT LIABILITIES
Trade and other accounts payable	[h]	$	51,923	$	4,337		$	56,260
Risk management			207		-			207
Credit facility			-		-			-
Senior term notes			-		-			-
MPP term financing			5,657		-			5,657
Deferred income taxes	[a]		3,724		(3,724	)		-
			61,511		613			62,124
Risk management			37		-			37
Senior term notes			455,728		-			455,728
MPP term financing			41,826		-			41,826
Provisions	[e]		38,968		97,367			136,335
Deferred income taxes	[a]		258,955		(106,994	)		151,961
TOTAL LIABILITIES			857,025		(9,014	)		848,011
NON-CONTROLLING INTEREST	[f]		5,297		(5,297	)		-
EQUITY
Capital stock	[k]		386,714		29,719			416,433
Share purchase warrants			13,800		-			13,800
Other reserves	[i]		38,029		1,280			39,309
Non-controlling interest	[f]		-		5,642			5,642
Retained earnings	[a, b, d, h, i]		515,985		(364,753	)		151,232
TOTAL EQUITY			954,528		(328,112	)		626,416
TOTAL LIABILITIES and EQUITY		$	1,816,850	$	(342,423	)	$	1,474,427

September 30, 2011

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Reconciliation of Equity

	Notes	As at September 30, 2010
TOTAL EQUITY UNDER PREVIOUS GAAP		$	954,528
Recognition of impairment write-downs, depletion, and disposition  adjustments	[b, c, j]	$	(366,520	)
Revaluation of decommissioning liabilities	[e]		(73,904	)
Recognition of inventory	[d]		(3,508	)
Elimination of unamortized pension assets	[d]		(360	)
Recognition of leases	[h]		218
Recognition of provisions	[e]		-
		$	(444,074	)
Tax effect of above	[a]		110,665
TOTAL ADJUSTMENT TO EQUITY		$	(333,409	)
Reclassification of non-controlling interest	[f]		5,297
TOTAL EQUITY UNDER IFRS		$	626,416

September 30, 2011

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Effect of IFRS Adoption for the Consolidated Statement of Operations and Comprehensive Loss

		For the Three Months Ended September 30, 2010
	Notes	Previous GAAP			Effect of transition to IFRS			IFRS
REVENUE
Oil and natural gas revenues		$	43,473		$	-		$	43,473
Royalties	[g]		(5,612	)		(1,133	)		(6,745	)
TOTAL NET REVENUE			37,861			(1,133	)		36,728
EXPENSES
Operating	[g]		15,452			(3,279	)		12,173
Transportation			2,424			-			2,424
Administrative			5,391			-			5,391
Shared based payments	[i]		922			53			975
Foreign exchange and other gains	[b,h]		(13,976	)		3,148			(10,828	)
Risk management			(9,246	)		-			(9,246	)
Other royalty obligations	[g]		-			2,749			2,749
Depletion, depreciation and amortization	[b, j]		28,545			(10,517	)		18,028
Exploration and evaluation	[c]		-			525			525
Impairment write-downs	[b]		-			44,907			44,907
Other expenses	[e]		-			-			-
TOTAL EXPENSES			29,512			37,586			67,098
FINANCE COSTS
Interest and finance charges	[h]		11,397			39			11,436
Accretion of decommissioning liabilities	[e]		1,068			46			1,114
TOTAL FINANCE COSTS			12,465			85			12,550
LOSS BEFORE TAXES AND NON-CONTROLLING INTEREST			(4,116	)		(38,804	)		(42,920	)
INCOME TAXES
Current			-			-			-
Deferred	[a]		(125	)		(9,740	)		(9,865	)
TOTAL INCOME TAXES			(125	)		(9,740	)		(9,865	)
LOSS BEFORE NON-CONTROLLING INTEREST			(3,991	)		(29,064	)		(33,055	)
NON-CONTROLLING INTEREST	[f]		354			(8	)		346
NET LOSS AND COMPREHENSIVE LOSS		$	(4,345	)	$	(29,056	)	$	(33,401	)
NET LOSS PER SHARE
Basic		$	(3.30	)	$	(22.04	)	$	(25.34	)
Diluted		$	(3.30	)	$	(22.04	)	$	(25.34	)

September 30, 2011

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Effect of IFRS Adoption for the Consolidated Statement of Operations and Comprehensive Loss
		For the 9 Months Ended September 30, 2010
	Notes	Previous GAAP			Effect of transition to IFRS			IFRS
REVENUE
Oil and natural gas revenues		$	172,151		$	-		$	172,151
Royalties	[g]		(28,342	)		2,591			(25,751	)
TOTAL NET REVENUE			143,809			2,591			146,400
EXPENSES
Operating	[g]		51,936			(9,229	)		42,707
Transportation			5,816			-			5,816
Administrative			16,630			-			16,630
Shared based payments	[i]		2,698			341			3,039
Foreign exchange and other gains	[b, h]		(9,599	)		5,688			(3,911	)
Risk management			(23,191	)		-			(23,191	)
Other royalty obligations	[g]		-			12,599			12,599
Depletion, depreciation and amortization	[b, j]		96,910			(33,537	)		63,373
Exploration and evaluation	[c]		-			651			651
Impairment write-downs	[b]		-			117,664			117,664
Other expenses	[e]		14,834			(14,834	)		-
TOTAL EXPENSES			156,034			79,343			235,377
FINANCE COSTS
Interest and finance charges	[h]		38,374			1,187			39,561
Accretion of decommissioning liabilities	[e]		3,178			222			3,400
TOTAL FINANCE COSTS			41,552			1,409			42,961
LOSS BEFORE TAXES AND NON-CONTROLLING INTEREST			(53,777	)		(78,161	)		(131,938	)
INCOME TAXES
Current			-			-			-
Deferred	[a]		(15,233	)		(19,101	)		(34,334	)
TOTAL INCOME TAXES			(15,233	)		(19,101	)		(34,334	)
LOSS BEFORE NON-CONTROLLING INTEREST			(38,544	)		(59,060	)		(97,604	)
NON-CONTROLLING INTEREST	[f]		1,098			345			1,443
NET LOSS AND COMPREHENSIVE LOSS		$	(39,642	)	$	(59,405	)	$	(99,047	)
NET LOSS PER SHARE
Basic		$	(30.08	)	$	(45.07	)	$	(75.15	)
Diluted		$	(30.08	)	$	(45.07	)	$	(75.15	)

September 30, 2011

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Notes to reconciliation

(a)  Deferred taxes

Under Previous GAAP, the Corporation has recognized deferred tax assets and liabilities, primarily associated with its exploration and evaluation, development and production, and risk management activities.  Under IFRS, current deferred tax balances have been re-classed for presentation entirely as long term assets/liabilities.

In addition, each of the balances adjusted through equity on transition to IFRS have been tax effected based on the Corporation’s estimated reversal rate of approximately 25%.  As at September 30, 2010, the cumulative impact on the deferred tax liability was a decrease of $110.7 million. See the reconciliation of equity for adjustments that required a tax effect.

(b)  Development and production

Under Previous GAAP, the Corporation followed full cost accounting for its petroleum and natural gas assets.  This methodology enabled the capitalization of amounts exceeding those acceptable for IFRS.  Under IFRS 1 on transition, the Corporation elected to allocate its full cost pool to its identified CGUs and then performed an impairment test.

Under the transitional election, an impairment test of the Corporation’s assets was required at a CGU level subsequent to the allocation.  The Corporation recognized an impairment write-down of $263.9 million on its petroleum and natural gas assets at January 1, 2010.  Write-downs were based on the recoverable amount of assets, representing value in use, under a 10% discounted cash flow.  The write-downs were primarily recognized in two Southern Alberta CGUs with long reserve lives where the discount rates have the most impact on the value in use assessment.

For the three months ended September 30, 2010, an impairment write-down of $44.9 million was recognized across certain CGUs.  An impairment write-down of $117.7 million was recognized for the nine months ended September 30, 2010. The impairments reflect the historically low natural gas pricing environment and outlook.

The restated IFRS balances also reflect gains and losses on the derecognition of assets disposed of during 2010 at Niton and Gilby.  The combined net losses of $5.7 million have been included in the foreign exchange and other gains and losses presentation in net loss.  Under Previous GAAP, proceeds on sales were deducted from the full cost pool without gain or loss recognition unless the disposition changed the depletion rate by more than 20%.

(c)  Exploration and evaluation

IFRS 6 “Exploration and Evaluation of Mineral Resources” requires the separate recognition of exploration assets that have not yet established a determinable future value in the form of technically feasible and commercially viable reserves.  The $72.4 million of exploration and evaluation costs recognized under IFRS on transition at January 1, 2010 represent the Corporation’s interest in undeveloped lands and mineral rights, and exploratory wells under evaluation.

For the three months ended September 30, 2010, the expiry of undeveloped mineral rights resulted in the derecognition of $0.5 million of exploration and evaluation assets, and have been presented as exploration expense in net loss.

For the nine months ended September 30, 2010, land expiries charged to exploration and evaluation expense totaled $0.7 million.

(d)  Other assets

Under a transitional election contained in IFRS 1, the Corporation eliminated unamortized actuarial gains of $0.2 million associated with the Mazeppa Processing Partnership defined benefit pension plan.  In addition, vested past service costs of the pension plan totaling $0.6 million were also adjusted through equity on transition.  The net result of both entries was a reduction in other assets of $0.4 million. There were no additional adjustments at September 30, 2010.

Also on transition, the Corporation adopted an accounting policy to recognize identifiable inventory items that are currently being marketed for sale or redeployment.  Identifiable inventory of $2.2 million was initially recognized on transition at January 1, 2010 and is included for presentation purposes in other assets at the lower of cost and recoverable amounts.   The recognition of inventory reduced development and production by $5.7 million, and a valuation allowance of $3.5 million was reflected in equity.

September 30, 2011

- 30 -

(e)  Provisions

The estimated provision for decommissioning liabilities associated with the Corporation’s petroleum and natural gas assets has been adjusted on transition to IFRS.  The adjustment reflects the application of a risk free rate for the discounting of the liability (based on the underlying assets), where under Previous GAAP this was measured using a credit risk adjusted rate.  The adjustment to the discounted decommissioning liability recognized at September 30, 2010 was $97.4 million.

In addition, a provision of $13.9 million was recognized at January 1, 2010 for lease surrender costs payable, and a reduction of other corporate assets of $0.9 million in related leasehold improvements.  The provision reflects the lower estimated cost of surrender for a portion of the corporate office space under lease, compared to the cost of fulfilling the contract.  The undeveloped and unutilized space was determined by Management to be an onerous contract.  The entire adjustment of $14.8 million was reflected in equity on transition.  The provision was settled during the second quarter of 2010.

 (f)  Non-controlling interest

The presentation of non-controlling interest has been changed on transition from Previous GAAP to IFRS.  Under IFRS, non-controlling interest is considered a component of equity and presentation reclassification was made.  Minor adjustments in 2010 relating to the recognition and depletion of MPP facility assets, pension and decommissioning liabilities were also made.

For the nine months ended September 30, 2010, the impact of transitional IFRS adjustments was $0.3 million.  No significant impact for the three months ended September 30, 2010.

 (g)  Royalties

The presentation of royalties under IFRS has changed from previous disclosures under Previous GAAP.   Previously, royalties were aggregated in a single line and shown as a reduction of total revenue in net loss.  Under IFRS, crown and freehold royalties have been netted from revenues, all other royalties have been presented as “Other royalty obligations” in the expenses.  In addition, gas cost allowances have been presented as a recovery of related processing fees included in operating expense.

(h)  Leases

On transition to IFRS at January 1, 2010, the classification of certain leases were changed to be recognized as finance leases under IFRS.  These leases have been included in trade and other accounts payable for financial statement purposes as they are not individually material.  As a result of the reclassification, at September 30, 2010, development and production was increased by $7.6 million (net), capital lease obligations increased $4.3 million, and the impact of interest and depreciation expense of $1.2 million and $0.5 million respectively, was recorded through net loss.

September 30, 2011

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(i)  Share based payments

Under Previous GAAP, share based payments were recognized as an expense on a straight-line basis through the date of full vesting.  Under IFRS, the expense is required to be recognized over the individual vesting periods for graded vesting awards.

For the three months ended September 30, 2010, there was no significant increase in share based compensation expense from the revised valuation methodology.  For the nine months ended September 30, 2010, the increase was $0.3 million.

(j)  Depletion

Upon transition to IFRS, the Corporation adopted a policy of depleting its petroleum and natural gas assets on a unit of production basis over proved plus probable reserves, by depletable component.  The depletion policy under Previous GAAP was a unit of production over proved reserves in a single pool.

For the three months ended September 30, 2010, a decrease in depletion of $10.5 million resulted from the reduction of the Corporation’s petroleum and natural gas asset base and the revised depletion methodology.  For the nine months ended September 30, 2010, depletion expense was reduced by $33.5 million.

September 30, 2011

- 32 -