Petroflow Energy (PEF) 6-K Petroflow Energy LTD. Announces Q3 2008 Financial Results

Exhibit 99.2

HIGHLIGHTS

	Expressed in Canadian Dollars unless otherwise noted(Unaudited)
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008		2007
			Restated					Restated
Oil and natural gas sales, net of transportation	$	16,617,918	$	5,691,668		$	42,029,915	$	15,463,587
Production per day
Oil and natural gas liquids (Bbl/d)		504		276			414		259
Natural gas (Mcf/d)		13,396		7,151			12,166		6,091
Equivalence at 6:1 (BOE/d)		2,737		1,468			2,442		1,274
Sales Price
Oil and natural gas liquids ($/Bbl)	$	119.38	$	79.85		$	114.65	$	71.78
Natural gas ($/Mcf)	$	8.99	$	5.66		$	8.77	$	6.35
Equivalence at 6:1 ($/BOE)	$	66.00	$	42.66		$	63.12	$	44.94
EBITDA1	$	16,268,829	$	1,355,018		$	12,586,939	$	4,058,943
Funds from operations2	$	6,023,077	$	336,352		$	11,918,914	$	1,692,198
-per share, Basic2 -	$	0.19	$	0.01		$	0.41	$	0.07
Diluted2 -	$	0.18	$	0.01		$	0.39	$	0.06
Net income (loss) before other items	$	1,293,113	$	(1,449,107	)	$	2,035,696	$	(3,102,345	)
Net income (loss)	$	12,031,390	$	(1,296,145	)	$	988,012	$	(3,091,315	)
-per share, Basic2 -	$	0.41	$	(0.05	)	$	0.03	$	(0.12	)
Diluted2 -	$	0.39	$	(0.05	)	$	0.03	$	(0.12	)
Capital expenditures	$	22,338,329	$	13,291,290		$	57,629,136	$	40,595,311
Capital dispositions		—		—		$	28,249,927		—
Basic weighted average shares outstanding		29,430,383		28,172,134			29,342,529		25,997,500
Working capital (deficiency)3
-As at September 30, 2008								$	(12,777,666	)
-As at December 31, 2007								$	(16,936,728	)
						As at November 19, 2008
Common Shares									29,571,094
Warrants outstanding									1,692,000
Options outstanding									2,898,600

(1)	EBITDA is a non-GAAP measure and represents net income (loss) before interest expense, income taxes, Depreciation, depletion and accretion as defined on page 2 of this Management’s Discussion and Analysis (“MD&A”).
(2)	Funds from operations is also a non-GAAP measure as defined on page 2 of this MD&A.
(3)	Excludes derivative contracts.

The following discussion and analysis of the operating and financial results of Petroflow Energy Ltd. (“Petroflow’ or the “Company’) is for the three and nine months ended September 30, 2008 and is provided by management as of November 19, 2008. It should be read in conjunction with Petroflow’s unaudited consolidated financial statements and related notes for the three and nine months ended September 30, 2008 and 2007. All dollar amounts are presented in Canadian dollars and are prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP’). Additional information including the Company’s Annual Information Form may be found on the SEDAR web site atwww.sedar.com.

FORWARD-LOOKING INFORMATION

This discussion and analysis contains forward-looking information relating to future events. In some cases, forward-looking information can be identified by such words as “anticipate”, “continue”, “estimate”, “except”, “forecast”, “may”, “will”, “project”, “should”, “believe” or similar expressions. In addition, statements relating to “reserves” or “resources” are forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities estimated and can be profitably produced in the future.

These statements represent management’s best projections, but undue reliance should not be placed upon them as they are derived from numerous assumptions. These assumptions are subject to known and unknown risks and uncertainties, including the business risks discussed in both the Management’s Discussion and Analysis and in the Company’s Annual Information Form, which may cause actual performance and financial results to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause results to differ materially from those predicted. The reader should be aware that historical results are not necessarily indicative of future performance.

NON-GAAP MEASURES

This document contains the terms “funds from operations”, which is a non-GAAP term. The funds from operations measurement is expressed before changes in non-cash working capital and is used by the Company to analyze operations, performance, leverage and liquidity. This term should not be considered as an alternative to, or more meaningful than, cash provided by operating activities or net income (loss) as determined in accordance with GAAP as an indicator of the Company’s performance. The reconciliation between net loss and funds from operations can be found in the Statements of Cash Flows included in the audited consolidated financial statements noted above. The Company considers funds from operations to be a key measure that demonstrates ability to generate funds for future growth through capital investment. Funds from operations as presented does not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities.

Earnings before interest, tax, depreciation and amortization (“EBITDA”) is a non-GAAP measure of performance that describes earnings before interest, taxes, depletion, depreciation and accretion. The Company discloses this measure, which is based on its financial statements, because it considers this measure gives a greater understanding of the Company’s operating results and financial position.

BARREL OF OIL EQUIVALENCY

Natural gas reserves and volumes contained herein are converted to barrels of oil equivalent (“boe”) amounts using a conversion rate of nine thousand cubic feet (“mcf”) of natural gas to one barrel (“bbl”) of oil (“6:1”). The terms “barrels of oil equivalent” may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf to one bbl is based on an energy equivalency conversion method primarily applicable to the burner tip and does not represent a value equivalency at the wellhead.

OVERALL PERFORMANCE

The Company’s production volumes for the three months ended September 30, 2008, averaged 2,737 boepd, 13% higher than the second quarter of 2008 and 86% higher than the three months ended September 30, 2007. The Company’s production volumes for the nine months ended September 30, 2008, averaged 2,442 boepd, 92% higher than the nine months ended September 30, 2007. The Company tied in 5 wells during the third quarter of 2008. Continued production increases, combined with stronger natural gas and crude oil prices resulted in funds from operations for the three months ended September 30, 2008 of $6.0 million, $3.5 million higher than the second quarter of 2008 and $5.7 million higher than the three months ended September 30, 2007. Funds from operations for the nine months ended September 30, 2008 would have been substantially higher except for certain onetime expenses, not expected to be incurred on an ongoing basis. These onetime expenses consisted of employment bonuses of $1.0 million and professional and other fees related to the Company’s successful application to list on the American Stock Exchange of $0.7 million. The Company tied in 21 wells during the nine months ended September 30, 2008. Higher production with stronger natural gas and crude oil prices increased funds from operations for the nine months ended September 30, 2008, to $11.9 million, $10.2 million higher than the nine months ended September 30, 2007.

Capital expenditures were $57.6 million for the nine months ended September 30, 2008, and $22.2 million for the three months ended September 30, 2008. During the nine months ended September 30, 2008, the Company completed 21 wells and two salt water disposal wells with a success rate of 100%. As of September 30, 2008, another 7 wells were in various stages of drilling or completion.

On May 22, 2008, the Company disposed its San Juan Basin coal bed methane property (“New Mexico sale”) for gross cash proceeds of $US 29 million.

Debt, net of working capital (excluding derivative contracts), was $86.2 million at September 30, 2008; $8.9 million higher than at June 30, 2008, as a result capital expenditures during the quarter being in excess of funds from operations.

Oklahoma

The Hunton resource play in the State of Oklahoma is the Company’s primary asset and opportunity for future growth. Petroflow’s focus during 2008 was on drilling opportunities located on the area of mutual interest lands acquired by Petroflow under the terms of the farm-in agreement with Enterra Energy Trust (“Enterra”). The terms of this agreement (the “Farmout”) allow for the Company to have a rolling option to drill wells on the basis of paying, as a percentage of Enterra’s working interest, 100% of the capital costs in the property to earn a 70% working interest. These percentages are proportional to Enterra’s working interest on a property by property basis, and generally result in the Company paying about 80% of costs to earn a 56% net working interest. The option to drill is subject to meeting minimum drilling commitments as specified in a mutually agreed upon plan of development. The Company is the operator during the drilling process, with Enterra taking over operatorship once each well is put on production.

The Company has also commenced its Extension Program in the Hunton resource play beyond the Farmout area of mutual interest with Enterra. Petroflow continues to establish four new project areas and has begun drilling activity in one of these areas. During the three months ended September 30, 2008, the Company drilled a salt water disposal well and its first development well, which is currently undergoing production testing. Petroflow holds a non promoted 90% working interest in this area and is proceeding with its land activities in the other project areas where it anticipates holding a 65% to 70% non promoted working interest. The Extension Program leases will not be subject to the terms and conditions currently under the Farmout; rather they will be subject to industry standard joint interest terms.

New Mexico

On May 22, 2008, the Company completed the sale of its non-core asset in New Mexico for cash proceeds of $US 29 million and no longer maintains any working interest in the area. The Company’s interest was in the Juniper project, located in this basin and was purchased in August of 2005.

Texas

The Company purchased an operated oil producing property in the Permian Basin in Midland, Texas, in December of 2005. There was no drilling on this property during the nine months ended September 30, 2008. The Permian Basin in Midland is considered to be a steady cash flow property and has a positive impact on the Company’s overall operations.

Canada (Alberta)

No capital expenditures were incurred in Canada during the nine months ended September 30, 2008.

RESULTS OF OPERATIONS

Subsequent to publishing its financial statements for the years ended December 31, 2006 and 2007, Petroflow Energy Ltd. (the “Company”) discovered an error in accounting principles used in the preparation of its consolidated financial statements for the years ended December 31, 2006 and 2007 and the related interim periods. The error related to the method used by the Company in translating the foreign currency transactions of its US subsidiary and is more fully described in note 14. As a result, the Company has restated its 2007 annual consolidated financial statements and the September 30, 2007 unaudited interim comparative consolidated financial.

The restatement of the financial statements has no impact on cash balances previously reported. However, certain amounts in the statements of cash flows have been restated to reflect adjustments which include expenditures on property and equipment, amortization expense, changes in non-cash working capital, and unrealized foreign exchange gains and losses.

Production

	Three months ended				Nine months ended
	September 30,				September 30,
	2008		2007		2008		2007
Total Average Volumes
Oil & NGL (bbls)		46,391		25,405		113,436		70,694
Natural Gas (mcf)		1,232,394		657,906		3,333,440		1,662,835
Total (boe)		251,790		135,056		669,009		347,833
Daily Sales Volumes — Average
Oil & NGL (bbls/day)		504		276		414		259
Natural Gas (mcf/day)		13,396		7,151		12,166		6,091
Total (boe/day)		2,737		1,468		2,442		1,274

Volumes

Sales volumes for the three months ended September 30, 2008, increased over the three months ended September 30, 2007 by 86%, and sales volumes for the nine months ended September 30, 2008 increased over the nine months ended September 2007 by 92%, primarily due to the drilling program in Oklahoma. This activity has resulted in continual volume increases as new wells are drilled and completed.

Commodity Prices

	Three months ended				Nine months ended
	September 30,				September 30,
	2008		2007		2008		2007
Average Prices
Oil & natural gas liquids ($/bbl)	$	119.38	$	79.85	$	114.65	$	71.78
Natural gas ($/mcf)		8.99		5.66		8.77		6.35
$/boe	$	66.00	$	42.66	$	63.12	$	44.94
Average Benchmark Prices
Average exchange rate: US$ to Cdn$	$	0.96	$	1.04	$	0.98	$	1.11
WTI (US$/bbl)		118.21		75.39		113.30		66.19
Edmonton Light ($/bbl)		122.61		80.70		115.86		77.06
NYMEX (US$/mmbtu)		10.24		6.06		9.73		6.86
AECO natural gas ($/GJ)		9.49		5.61		8.69		6.65

Natural Gas and Natural Gas Liquids

Natural gas and natural gas liquid sales prices for the three months ended September 30, 2008, compared to the same period in 2007, increased by 59% from $5.66 to $8.99, and for the nine months ended September 30, 2008 compared to the same period in 2007, increased by 38% from $6.35 to $8.77, consistent with increases in benchmark NYMEX prices. The percentage increase is less than that of NYMEX, as a higher percentage of the Company’s gas came from Oklahoma in the three and nine months ended September 30, 2008, and the natural gas produced in Oklahoma is subject to a significant basis differential, historically in the range of 10% to 15% of NYMEX. Beginning at the end of the third quarter, the basis differential in Oklahoma has exceeded historical norms by approximately $US 2.00 per mmbtu. The basis differential is expected to gradually return to historical norms by early summer 2009.

In the nine months ended September 30, 2008, Petroflow renegotiated two gas contracts in Oklahoma, resulting in improved net revenue to Petroflow. The Company is currently receiving production revenues from Oklahoma under the new pricing terms of these contracts, representing approximately 75% of its gas production from Oklahoma. The new contracts which allow the Company to be paid for natural gas liquids, on a phased in basis, are expected to result in higher prices than under the old contracts.

Crude Oil

For the three months ended September 30, 2008 compared to the same period in 2007, average prices increased 50% from $79.85 to $119.38, and for the nine months ended September 30, 2008 compared to the same period in 2008, average prices increased 60% from $71.78 to $114.65, consistent with the market price increase. A majority of the Company’s oil production in 2008 was received from Oklahoma which receives prices closer to WTI as opposed to production in Texas and Alberta, the areas which produced the majority of Petroflow’s oil in the nine months of September 30, 2007.

Crude Oil and Gas Sales

	Three months ended							Nine months ended
	September 30,							September 30,
	2008		2007		% Change			2008		2007		% Change
Crude Oil	$	5,538,025	$	2,028,559		173	%	$	13,005,919	$	5,003,214		156	%
Natural gas and natural gas liquids		11,079,893		3,724,497		198	%	$	29,224,420		10,628,986		177	%
Total oil and natural gas revenues	$	16,617,918	$	5,753,055		189	%	$	42,230,339	$	15,632,200		170	%

Gross revenues from oil, natural gas and natural gas liquids totaled $16.6 million for the three months ended September 30, 2008, compared to $5.8 million for the three months ended September 30, 2007, an increase of 189%. This increase is mostly attributable to an 86% increase in production related to the Company’s drilling activity in Oklahoma. During the third quarter, the Company put an additional 5 wells on production in Oklahoma. The increase in sales was also affected by the increase in sales revenue per mcf of natural gas of 59% in 2008 and sales revenue per bbl of oil of 49%, both as compared to the same period in 2007.

Gross revenues from oil, natural gas and natural gas liquids totaled $42.2 million for the nine months ended September 30, 2008, and $15.6 million for the nine months ended September 30, 2007, an increase of 170%. This increase is attributable to a 92% increase in production due to the Company’s drilling activity in Oklahoma. During the nine months ended September 30, 2008, the Company put 21 wells on production in Oklahoma. The increase in sales was also affected by the increase in sales revenue per mcf of natural gas of 38% in 2008 and sales revenue per bbl of oil of 60%, both as compared to the same period in 2007.

Derivative Instruments

	Three months ended								Nine months ended
	September 30,								September 30,
	2008			2007		% Change			2008			2007		% Change
Unrealized gain	$	11,295,283		$	239,649		4,613	%	$	520,070		$	108,135		381	%
Realized loss		(543,082	)		—		(100	%)		(1,564,477	)		—		100	%
Per boe	$	42.70		$	1.77		(2,307	%)	$	(1.56	)	$	0.31		(602	%)

All derivatives contracts are recorded on the balance sheet at fair value. The Company has not designated any of its derivative contracts as effective accounting hedges, even though the Company considers all commodity contracts to be effective economic hedges. Therefore, changes in the fair value of the derivative contracts are recognized in net income for the period.

Fair value is calculated at a point in time based on an approximation of the amounts that would be received or paid to settle these instruments, with reference to forward prices. Accordingly, the magnitude of the unrealized gain or loss will continue to fluctuate with changes in commodity prices.

The fair value of the derivatives at September 30, 2008, was an asset of $0.18 million comprised of a $0.09 million liability on oil contracts and a $0.27 million asset on gas contracts.

The three months ended September 30, 2008, includes an $11.3 million unrealized gain on derivatives compared to an income of $0.24 million for the three months ended September 30, 2007. The unrealized gain on derivatives for the three months ended September 30, 2008, resulted from the change in the fair value of the derivative contracts during the quarter from a liability of $11.6 million at June 30, 2008 to an asset of $0.18 million at September 30, 2008. The $11.3 million gain was comprised of $2.3 million unrealized income on crude oil contracts, and a $9.0 million unrealized gain on natural gas contracts. The unrealized gain in the third quarter is primarily attributable to weaker forward oil and natural gas prices compared to June 30, 2008.

The nine months ended September 30, 2008, includes a $0.95 million unrealized gain on derivatives compared to an income of $0.1 million for the nine months ended September 30, 2007. The unrealized gain on derivatives for the nine months ended September 30, 2008, resulted from the change in the fair value of the derivative contracts during the nine months of 2008 from a liability of $0.3 million at December 31, 2007, to an asset of $0.18 million at September 30, 2008. The $0.52 million gain was comprised of $0.05 million unrealized loss on crude oil contracts, and a $0.57 million unrealized gain on natural gas contracts. The unrealized gain in the nine months ended September 30, 2008 is primarily attributable to weaker natural gas forward prices compared to December 31, 2007, and an increase in derivative instruments held.

The following tables outline the details of all the Company’s derivative contracts:

Crude Oil

	Volume per		Call Price		Put Price
Period	day (boe)		US$		US$
January 1, 2008 – June 30, 2009		75	$	72.80	$	65.00
January 1, 2008 – December 31, 2008		75	$	107.50	$	75.00
January 1, 2009 – December 31, 2009		75	$	100.50	$	75.00
January 1, 2009 – December 31, 2009		100	$	89.70	$	70.00
January 1, 2010 – December 31, 2010		100	$	78.70	$	65.00

Natural Gas

	Volume per		Call Price		Put Price
Period	day (mmbtu)		US$		US$
April 1, 2008 – September 30, 2008		350	$	9.50	$	6.00
April 1, 2008 – September 30, 2008		350	None		$	6.00
April 1, 2008 – October 31, 2008		1,750	$	9.70	$	6.50
April 1, 2008 – October 31, 2008		2,000	$	10.20	$	7.00
April 1, 2008 – October 31, 2008		3,000	$	10.70	$	8.00
November 1, 2008 – March 31, 2009		1,750	$	11.40	$	7.50
November 1, 2008 – March 31, 2009		2,000	$	11.20	$	8.00
November 1, 2008 – March 31, 2009		3,000	$	13.55	$	8.00
January 1, 2009 – December 31, 2009		1,000	None		$	7.00
April 1, 2009 – September 30, 2009		2,000	$	10.08	$	7.00
April 1, 2009 – October 31, 2009		3,000	$	9.03	$	8.00
October 1, 2009 – December 31, 2009		2,000	$	10.80	$	7.50
November 1, 2009 – November 30, 2010		1,500	None		$	6.50
January 1, 2010 – December 31, 2010		2,000	$	10.05	$	6.50
January 1, 2010 – December 31, 2010		500	None		$	6.50
January 1, 2010 – December 31, 2010		1,000	$	9.45	$	6.50

Royalties

	Three months ended									Nine months ended
	September 30,									September 30,
	2008			2007			% Change			2008			2007			% Change
Royalties	$	3,508,174		$	1,214,881			189	%	$	9,055,499		$	3,452,678			162	%
% of Sales		21.11	%		21.12	%		—			21.44	%		22.09	%		(3	%)
Per boe	$	13.93		$	9.00			55	%	$	13.54		$	9.93			36	%

Royalties, which include severance taxes, were $3.5 million for three months ended September 30, 2008, compared to $1.2 million for the three months ended September 30, 2007. Royalties, which include severance taxes, were $9.1 million for nine months ended September 30, 2008, compared to $3.5 million for the nine months ended September 30, 2007. The royalty rate is consistent for the three months ended September 30, 2008 and 2007. The royalty rate has decreased 3% for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 due to a prior period severance tax rebate. In Oklahoma, the Company receives a rebate of severance taxes on all of its production. The severance rebate amounts to approximately 6% of sales in Oklahoma. All horizontal wells drilled in Oklahoma and put on production prior to July 1, 2009 are eligible for the rebate for a period of four years from commencement of production from the applicable well subject to reaching economic payout of the capital costs of the Company’s overall Oklahoma horizontal well drilling program.

In response to industry concerns regarding the Alberta New Royalty Framework (the “Framework”), on April 10, 2008 the Government of Alberta announced two new royalty programs designed to encourage the continued development of deep oil and gas reserves. The new royalty programs are not expected to have an impact on the Company as only 4% of the Company’s sales are earned in Alberta.

Operating and Transportation Expenses

	��
		Three months ended							Nine months ended
		September 30,							September 30,
		2008		2007		% Change			2008		2007		% Change
Operating expenses		$	2,896,705	$	1,731,356		67	%	$	7,191,978	$	3,926,845		83	%
Per boe		$	11.50	$	12.82		(10	%)	$	10.75	$	11.29		(5	%)
Transportation costs		$	—	$	61,387		(100	%)	$	200,424	$	168,613		19	%
Per boe		$	—	$	0.45		(100	%)	$	0.30	$	0.48		(38	%)

Operating expenses increased by 67% for the three months ended September 30, 2008 as compared to the same period in 2007 and increased 83% for the nine months ended September 30, 2008 compared to the same period in 2007. On a per boe basis, operating expenses decreased 10% for the three month and 6% for the nine month periods ended September 30, 2008. For the three months ended September 30, 2008, operating expenses decreased to $11.50/boe from $12.82/boe in 2007. For the nine months ended September 30, 2008, the operating costs decreased to $10.75/boe from $11.29/boe in 2007. The decrease for the three and nine month periods are the results of higher percentage of the Company’s wells being on stream for an extended period, which decreases its operating costs per unit of production compared to the 2007 periods as the Company tends to incur higher operating costs in the start up phase of a well’s life.

Transportation costs represent the cost of delivering the Company’s petroleum products from the wellhead to various sales markets, and are incurred in direct proportion to the production capabilities of the Company’s wells in the New Mexico property. On a per boe basis, for the three months ended September 30, 2008, this expense decreased to $0.00/boe compared to $0.45/boe for the three months ended September 30, 2007. This decrease is the result of the sale of the New Mexico property on May 22, 2008.

For the nine months ended September 30, 2008, this expense decreased by 38% to $0.30/boe compared to $0.48/boe for the nine months ended September 30, 2007. This decrease is the result the sale of the New Mexico property on May 22, 2008.

Depletion, Depreciation and Accretion (DD&A)

	Three months ended							Nine months ended
	September 30,							September 30,
	2008		2007		% Change			2008		2007		% Change
			Restated							Restated
Depletion and depreciation	$	2,695,325	$	1,418,873		95	%	$	7,027,436	$	4,058,571		75	%
Accretion on asset retirement obligation		12,156		48,777		(75	%)		37,332		95,026		(61	%)
	$	2,707,481	$	1,467,650		84	%	$	7,064,768	$	4,153,597		70	%
Per boe	$	10.75	$	10.87		(1	%)	$	10.56	$	11.94		(12	%)
Write-down of property and equipment	$	—	$	—				$	1,015,950	$	—		100	%
Per boe	$	0.00	$	0.00				$	1.52	$	0.00		100	%

The total DD&A rate decreased to $10.75/boe for the three months ended September 30, 2008, compared to $10.87/boe for the same period in 2007. For the nine months ended September 30, 2008, the total DD&A rate decreased to $1 0.56/boe from $11 .94/boe for the same period in 2007. This decrease is the result of the New Mexico asset sale and the result of reserve levels increasing significantly in the Oklahoma area relative to production volumes during 2008.

Accretion expense decreased for the three and nine months ended September 30, 2008, due to the New Mexico asset sale and an increase in estimated reserve life compared to the three and nine months ended September 30, 2007. The estimated reserve life has increased for the three months ended September 30, 2008, as future production decline rates are anticipated to be lower than in 2007. As well the Company anticipates commodity prices in future years to be higher than what was anticipated in 2006, thereby prolonging the estimated economic life of the wells.

For the nine month period ended September 30, 2008, the Company performed a ceiling test in accordance with the Canadian Institute of Chartered Accountant’s full cost accounting guidelines which did not result in a writedown (June 30, 2008 — $1,015,950 write down of property and equipment on the Company’s Canadian properties).

General and Administrative Expenses

	Three months ended							Nine months ended
	September 30,							September 30,
	2008		2007		% Change			2008		2007		% Change
General and administrative	$	2,835,255	$	1,166,332		143	%	$	7,112,850	$	3,360,608		112	%
Per boe	$	11.26	$	8.64		30	%	$	10.63	$	9.66		10	%

Total general and administrative expenses for the three months ended September 30, 2008 were $2.8 million compared to $1.2 million in 2007. General and administrative expense per boe increased by 30% from $8.64 for the three months ended September 30, 2007, to $11.26 for the same period in 2008. The increases for the three months ended September 30, 2008, are mainly the result of $0.7 million non-cash issuance of common shares to directors for compensation and one-time expenses for non-recurring fees related to its listing on the American Stock Exchange, including compliance requirements, legal fees, consulting services and other related charges.

Total general and administrative expenses for the nine months ended September 30, 2008 were $7.1 million compared to $3.4 million in 2007. General and administrative expense per boe increased by 10% from $9.66 for the nine months ended September 30, 2007 to $10.63 for the same period in 2008. The increases for the nine months ended September 30, 2008, are the result of are the result of $0.7 million non-cash issuance of common shares to directors for compensation, $1.0 million associated with employee bonuses incurred in June 2008 and $0.7 million in one-time expenses for non-recurring fees related to the 40-F registration statement of the Company and its listing on the American Stock Exchange, including compliance requirements, audit fees, legal fees, consulting services and other related charges.

Stock Based Compensation

	Three months ended							Nine months ended
	September 30,							September 30,
	2008		2007		% Change			2008		2007		% Change
Stock based compensation	$	1,871,419	$	404,496		363	%	$	2,662,254	$	738,051		261	%
Per boe	$	7.43	$	3.00		148	%	$	3.93	$	2.12		88	%

The Company’s stock-based compensation expense increased 363% for the three months ended September 30, 2008, from $0.4 million to $1.9 million. This increase is the result of the Company amending its stock option plan on July 10, 2008 relating to the vesting provisions of all of its Option Agreements previously issued to employees, officers and directors. The options are exercised pursuant to the following vesting schedule, 1/3 on the date of grant, 1/3 on the 1st anniversary of the date of the grant and 1/3 on the 2nd anniversary of the date of the grant. In addition to this amendment, the effect of this amended stock option plan was $1.8 million towards the expense for the three months ended September 30, 2008. The Company issued 342,000 stock options at prices from $4.15 to $7.08 and 112,860 vested at the time of grant, contributing $0.7 million towards the expense and 43,500 options were exercised for the three months ended September 30, 2008.

(1) Excludes derivative contracts

For the nine month period ended September 30, 2008, stock-based compensation expense was $2.7 million compared to $0.7 million for the nine months ended September 30, 2007. The increase is the result of the Company amending its stock option plan on July 10, 2008 relating to the vesting provisions of all of its Option Agreements previously issued to employees, officers and directors. The options are exercisable pursuant to the following vesting schedule, 1/3 on the date of the grant, 1/3 on the 1st anniversary of the date of the grant and 1/3 on the 2nd anniversary of the date of the grant. The effect of this amended stock option plan was $1.8 million towards the expense for the nine months ended September 30, 2008. In addition to this amendment, the Company issued 672,000 stock options at prices from $1.80 to $7.08 and 217,760 vested at the time of grant, contributing to $1.4 million towards the expense and 225,050 options were exercised and 20,850 options were cancelled for the nine months ended September 30, 2008.

Interest Expense

	Three months ended									Nine months ended
	September 30,									September 30,
	2008			2007			% Change			2008			2007			% Change
Interest expense and financing Expense	$	1,529,958		$	1,183,513			29	%	$	4,534,159		$	2,996,661			51	%
Average interest rate		7.55	%		10.20	%					7.97	%		9.86	%
Per boe	$	6.08		$	8.76			(31	%)	$	6.78		$	8.62			(21	%)

Interest expense increased by 29% to $1.5 million for the three months ended September 30, 2008. Interest expense increased by 51% to $4.5 million for the nine months ended September 30, 2008. These increases are a result of higher debt levels for the three and nine months ended September 30, 2008, when compared to the same periods in 2007. Interest expense decreased by 31% on a per boe basis for the three months ended September 30, 2008 and by 21% for the nine months ended September 30, 2008, as compared to the prior periods, due to the significant growth in period-over-period production volumes. Overall interest rates for the three months and nine months ended September 30, 2008 have declined from corresponding rates in the prior periods due to the decline in LIBOR over that time frame.

At September 30, 2008, the Company had $73.4 million of bank debt outstanding compared to $41.4 million at September 30, 2007. The Company’s debt consists of senior debt facilities provided by a syndicate of U.S. banking institutions and capital leases provided by the Company’s working interest partner in Oklahoma amounting to $18.5 million as of September 30, 2008. The interest rates charged by the bank are LIBOR plus 2% to LIBOR plus 2.5% on the first U.S. $102 million of funds advanced and LIBOR plus 4% on the next U.S. $8 million. The annual interest rate charged in the capital leases is 12%.

Provision for Doubtful Accounts

On July 22, 2008, SemGroup L.P. one of the Company’s petroleum and natural gas marketers announced that it and certain of its North American subsidiaries had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code as well as an application for creditor protection under the Companies’ Creditors Arrangement Act in Canada. Petroflow has a maximum potential exposure of $4.4 million up to the date of the SemGroup petition in respect of uncollected revenues. The account receivable arose from a majority of the oil production volumes and 20% of the natural gas volumes sold to SemCrude, L.P. and SemGas, L.P. subsidiaries of SemGroup, L.P .,(“SemGroup”) for the marketing of a portion of Petroflow’s production. Petroflow’s management has retained legal counsel and continues to have discussions with SemGroup and its Monitor to best manage and resolve this matter. At this time, the Company’s best estimate of the uncollectible amount of the receivable is $1.4 million, which amount has been recorded in these financial statements. The Company continues to sell natural gas to SemGas, however during August 2008 the Company began to sell its oil to another petroleum and natural gas marketer.

Income Taxes

For the three months ended September 30, 2008, the Company did not recognize any future income taxes or recoveries. The Company is currently not taxable and does not expect to be taxable in the near future, based on current capital spending and price forecasts.

Net Income (Loss) and Funds from Operations

	Three months ended									Nine months ended
	September 30,									September 30,
	2008			2007			% Change			2008			2007			% Change
				Restated									Restated
Net income (loss)	$	12,031,390		$	(1,296,145	)		1,028	%	$	988,012		$	(3,091,315	)		132	%
Per boe	$	47.78		$	(9.60	)		598	%	$	1.48		$	(8.89	)		117	%
Funds from operations	$	6,023,077		$	336,352			1,691	%	$	11,918,914		$	1,692,198			604	%
Changes in non-cash working capital items		(1,207,606	)		2,038,955			(159	%)		(9,608,340	)		6,435,480			(249	%)
Cash provided by operating activities	$	4,815,401		$	2,375,307			103	%	$	2,310,574		$	8,127,678			(72	%)

The Company earned net income for the three months ended September 30, 2008, of $12.0 million compared to a net loss of $1.3 million in 2007, primarily because of an unrealized gain on derivative instruments of $11.7 million.

The Company earned a net income for the nine months ended September 30, 2008 of $1.0 million compared to net loss of $3.0 million in 2007, because of increased oil and gas production revenues of $42.2 million and unrealized gain on derivative instruments of $0.5 million this was however offset by a write-down on Canadian properties of $1.0 million and a $1.4 million provision for doubtful accounts receivable recorded for the nine months ended September 30, 2008.

The Company’s funds from operations for the three months ended September 30, 2008 increased to $6.0 million from $0.3 million in 2007. The improvement was due to the increased oil and gas production revenues over the period.

The Company’s funds from operations for the nine months ended September 30, 2008, increased to $11.9 million from $1.7 million in 2007. The increase is primarily due to increased revenues driven by higher prices and production. The increase in revenues more than offset the increases in operating and general and administrative expenses which are relatively consistent in 2008, with the exception of the one- time expenses incurred as described previously.

SUMMARY OF QUARTERLY RESULTS

Quarterly Financial Information (Restated)(in thousands except for per share amounts)

	2008									2007												2006
	Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Oil and gas sales	$	16,618		$	15,392		$	10,220		$	6,361		$	5,753		$	5,965		$	3,915		$	2,641
Funds from operations		6,023			2,579			3,317			(1,092	)		336			1,491			(138	)		(1,669	)
Per share — Basic and diluted		0.19			0.09			0.12			(0.04	)		0.01			0.06			—			(0.07	)
Diluted		0.18			0.09			0.12			(0.04	)		0.01			0.06			—			(0.07	)
Net income (loss)		12,031			(8,884	)		(2,159	)		(3,792	)		(1,296	)		74			(1,797	)		(2,880	)
Per share — Basic		0.41			(0.30	)		(0.07	)		(0.14	)		(0.05	)		0.00			(0.07	)		(0.12	)
Diluted		0.39			(0.30	)		(0.07	)		(0.14	)		(0.05	)		0.00			(0.07	)		(0.12	)
Total assets		137,143			111,147			120,764			103,029			88,923			82,686			74,873			66,110
Working capital deficiency(1)		(12,778	)		(15,151	)		(20,223	)		(17,147	)		(53,021	)		(53,947	)		(46,299	)		(33,251	)

(1) Excludes derivative contracts

LIQUIDITY AND CAPITAL RESOURCES

	September 30,		December 31,		%
	2008		2007		Change
Working capital deficiency (excluding derivative contracts)	$	12,777,666	$	16,936,728		(25	%)
Shareholders’ equity	$	24,855,236	$	19,083,256		30	%

The Company’s growth strategy since March 2006 has been focused on drilling in its Hunton Resource Play in Oklahoma. The development drilling was financed primarily with bank debt during 2008, compared to equity and bank debt in 2007. In addition, the Company has used trade accounts payable under normal credit terms from its suppliers and cash flow from operations to continue funding its ongoing capital program. In this regard, at September 30, 2008, the Company had a working capital deficiency (excluding derivative contracts) of $12.8 million.

Management expects to fund its 2008 operating and capital budget of approximately $69 million with a combination of funds generated from operations, possible issuances of equity capital, and utilizing additional bank financing.

On September 30, 2008 the Company had a U.S. $200 million revolving credit facility in place with a U.S. based bank. This facility is dependent upon continued yearly reserve additions, with current availability of $US 110 million made up of two tranches, “A” and “B”. The “A” tranche has a maturity date of January 1, 2012 with a borrowing base of $US 102 million. The “B” tranche matures on January 1, 2010, and has a borrowing base of $US 8 million.

As at September 30, 2008, the Company had $73.4 million ($US 70.7 million) drawn on its credit facility and a net working capital deficit of $12.8 million (excluding the derivative contracts) for a total net debt of $86.2 million. As at September 30, 2008, the Company was in compliance with its debt covenants.

Shareholders’ equity increased by 30% in the nine months ended September 30, 2008 to $24.9 million, due primarily to the net income incurred in the period.

As of November 19, 2008, the Company has 29,571,094 Common Shares, 1,692,000 warrants and 2,898,600 options outstanding.

CAPITAL EXPENDITURES

	Three months ended								Nine months ended
	September 30,								September 30,
	2008		2007			% Change			2008			2007		% Change
			Restated									Restated
Capital Expenditures
Land and rentals	$	460,634	$	1,835,439			(75	%)	$	1,048,333		$	2,035,699		(50	%)
Seismic		—		(2,312	)		(100	%)		—			10,409		(100	%)
Drilling and completions		10,967,331		10,843,302			1	%		31,363,002			28,818,785		9	%
Equipment and facilities		9,117,187		847,495			976	%		14,971,191			7,971,330		88	%
Other assets		45,365		12,251			270	%		178,636			36,055		395	%
		20,590,517		13,536,175			52	%		47,561,162			38,872,278		22	%
Assets under capital lease		1,747,813		(244,885	)		(814	%)		10,067,975			1,723,033		484	%
		22,338,329		13,291,290			68	%		57,629,136			40,595,311		42	%
Property dispositions		—		—			—			(28,249,927	)		—		(100	%)
Total	$	22,338,329	$	13,291,290			68	%	$	29,379,209		$	40,595,311		(28	%)

For the three months ended September 30, 2008, the Company spent a significant portion of its developmental drilling budget in Oklahoma where 7 wells were drilled, and 5 wells were put on production. In the three months ended September 30, 2007, the Company drilled 8 wells in Oklahoma and brought 6 wells (3 Oklahoma: 3 New Mexico) on production.

Capital expenditures had increased 42% for the nine months ended September 30, 2008, compared to the same period in 2007. During the nine months ended September 30, 2008, the Company drilled 25 wells in Oklahoma including two salt water disposal wells and brought 21 wells on production compared to 21 wells that were drilled (20 Oklahoma; 1 New Mexico) and 25 wells brought on production (18 — Oklahoma; 7 — New Mexico). The increase in 2008 relates to the pace of drilling in Oklahoma, where the Company was continuously drilling with three rigs as compared to two rigs in the first half of 2007.

Capital expenditures include assets under capital lease resulting from a contract that the Company entered into during 2006 as part of its farm-in agreement. The leased assets consist of three salt water disposal wells drilled in Oklahoma as well as infrastructure for all of the wells. The lease bears interest at 12%. This capital lease resulted in the capitalization of $1.7 million of additional expenditures for the three months ended and $10.0 million of additional expenditures for the nine months ended September 30, 2008.

The Company completed the sale of its non-core asset in New Mexico for net proceeds of $28,249,927 onMay 22, 2008.

COMMITMENTS

In August 2006, the Company signed two drilling contracts, effective at the end of July 2006, whereby two rigs were available to the Company for its drilling program in Oklahoma. One rig has been contracted out at a cost of U.S. $17,000 per day for two years; this rig will subsequently be contracted out on a month to month basis. The second rig is contracted out at a cost of U.S. $17,000 per day for three years.

In April 2007, the Company signed a third drilling rig contract with the same service provider for a newer rig in September of 2007 at a rate of U.S. $22,000 per day for three years. The Company has the option under this third contract, with 45 days written notice, to switch one of the older rigs available under the August 2006 contracts for this newer rig should the Company not need a third rig.

OFF-BALANCE SHEET ARRANGEMENTS

No off-balance sheet arrangements were entered into during the three month period ended September 30, 2008.

RELATED PARTY TRANSACTIONS

As at September 30, 2008, $19,100 (December 31, 2007 — $nil) was due to Macon Oil & Gas Corp. (“MOG”), a wholly owned subsidiary of Macon Resources Ltd., operator of one of the Company’s producing properties. Macon Resources Ltd., is a related party by virtue of its significant shareholdings in the Company. Additionally, $195,000 is owed by the Company to MOG (December 31, 2007 — $220,000) in respect of a bank loan in which MOG is the borrower of record with the bank. MOG is charging the Company interest equal to its rate of interest (prime plus one) and the loan is secured by the property.

For the nine months ended September 30, 2008, legal fees totaling $433,326 (year ended December 31, 2007 — $333,838) were charged to the Company by the Company’s legal counsel where a director of the Company is a partner in the law firm.

For the nine months ended September 30, 2008, $49,884 (December 31, 2007 — $38,525) was charged to the Company by a director of the Company for services rendered.

As at September 30, 2008, $892,171 (December 31, 2007, $384,725) was due to the Company by a joint interest partner in which a director of the Company has an interest.

All transactions with related parties were recorded at exchange amounts and were incurred in the normal course of business.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

On November 23, 2007, the ASC and the securities commissions in the other jurisdictions in which Petroflow is registered, exempted Venture Issuers from certifying disclosure controls and procedures as well as Internal Controls over Financial Reporting as of December 31, 2007, and thereafter. Since Petroflow is a Venture Issuer it is now required to file “basic certificates”, which it has done for the quarter ended September 30, 2008.

CRITICAL ACCOUNTING ESTIMATES

The significant accounting policies used by Petroflow are disclosed in the notes to Petroflow’s December 31, 2007 consolidated financial statements. Certain accounting policies require that management make appropriate decisions when formulating estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The Manager reviews the estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes in estimated amounts that differ materially from current estimates. Petroflow might realize different results from the application of new accounting standards published, from time to time, by various regulatory bodies. An assessment of Petroflow’s significant accounting estimates is discussed in the MD&A filed with Petroflow’s audited consolidated financial statements for the year ended December 31, 2007.

NEW ACCOUNTING STANDARDS

Effective January 1, 2008, the Company implemented the provisions of CICA Handbook Section 1535 “Capital Disclosures”, Section 3862 “Financial Instruments — Disclosures”, and Section 3863 “Financial Instruments — Presentation”.

Section 1535 establishes standards for disclosing information about an entity’s capital and how it is managed. This Section specifies disclosure about objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the entity has complied with any capital requirements, and if it has not complied, the consequences of such non-compliance. Sections 3862 and 3863 establish standards for the presentation and disclosure of information that enable users to evaluate the significance of financial instruments to the entity’s financial position, and the nature and extent of risks arising from financial instruments and how the entity manages those risks.

The implementation of these new standards did not impact the Company’s financial results, however did result in additional disclosures.

FUTURE ACCOUNTING CHANGES

International Financial Reporting Standards (“IFRS”)

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with the International Financial Reporting Standards (IFRS) by 2011 and The Company will be required to report according to IFRS standards for the year ended December 31, 2011. The Company is currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosure.

Future Accounting Changes

In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts Clarifying the criteria for the recognition of assets, intangible assets and internal developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for fiscal years beginning on or after October 1, 2008 and early adoption is permitted. The Company is currently evaluating the impact these sections will have on its results of operations and financial position.

PETROFLOW ENERGY LTD.

INTERIM
CONSOLIDATED FINANCIAL STATEMENTS
UNAUDITED

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2008

Petroflow Energy Ltd.
Consolidated Balance Sheet
Expressed in Canadian Dollars
(Unaudited)

	September 30,			December 31,
	2008			2007
Assets
Current assets
Cash and cash equivalents	$	1,319,218		$	801,804
Accounts receivable		12,011,910			4,931,126
Risk management asset (note 9)		272,475			—
Prepaids and other		888,239			289,727
		14,491,842			6,022,657
Investment in limited partnership		519,100			498,450
Property and equipment (note 3)		122,131,684			96,508,175
	$	137,142,626		$	103,029,282
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	19,612,899		$	19,460,854
Risk management liabilities (note 9)		—			210,123
Current portion of obligation under capital lease (note 6)		7,384,134			3,498,531
		26,997,033			23,169,508
Bank loan (note 5)		73,424,206			52,957,826
Obligation under capital lease (note 6)		11,116,752			6,835,012
Risk management liabilities (note 9)		90,410			122,192
Asset retirement obligations (note 4)		658,989			861,488
		112,287,390			83,946,026
Shareholders’ equity
Share capital (note 7)		38,408,304			36,900,052
Warrants (note 7)		103,935			103,935
Contributed surplus (note 7)		5,717,279			3,369,281
Accumulated other comprehensive loss		(2,003,107	)		(2,930,825	)
Deficit		(17,371,175	)		(18,359,187	)
		24,855,236			19,083,256
	$	137,142,626		$	103,029,282

Commitments (note 8)

Subsequent events (note 11)

Approved by the Board of Directors:

Signed“Richard Clark”                      Director          Signed“Donald Rowden”                     Director

Petroflow Energy Ltd.
Consolidated Statement of Operations and Deficit
Expressed in Canadian Dollars
(Unaudited)

	Three months ended						Nine months ended
	September 30,						September 30,
	2008			2007			2008			2007
				Restated						Restated
				(note 14)						(note 14)
Revenue
Oil and natural gas sales	$	16,617,918		$	5,753,055		$	42,230,339		$	15,632,200
Royalties and severance taxes		(3,508,174	)		(1,214,881	)		(9,055,499	)		(3,452,678	)
		13,109,744			4,538,174			33,174,840			12,179,522
Interest and other		39,629			27,453			69,209			62,508
		13,149,373			4,565,627			33,244,049			12,242,030
Expenses
Operating		2,896,705			1,731,356			7,191,978			3,926,845
Transportation		—			61,387			200,424			168,613
Depletion and depreciation		2,695,325			1,418,873			7,027,436			4,058,571
Write-down of property and equipment (note 3)		—			—			1,015,950			—
Accretion		12,156			48,777			37,332			95,026
General and administrative		2,835,255			1,166,332			7,112,850			3,360,608
Stock-based compensation (note 7)		1,871,419			404,496			2,662,254			738,051
Interest and financing costs		1,529,958			1,183,513			4,534,159			2,996,661
Provision for doubtful receivables (note 9)		15,442			—			1,425,970			—
		11,856,260			6,014,734			31,208,353			15,344,375
Net income (loss) before other items		1,293,113			(1,449,107	)		2,035,696			(3,102,345	)
Realized loss on derivative instruments		(543,082	)		—			(1,564,477	)		—
Unrealized gain on derivatives instruments		11,295,283			239,649			520,070			108,135
Foreign exchange loss		(13,924	)		(86,687	)		(3,277	)		(97,105	)
Net income (loss)		12,031,390			(1,296,145	)		988,012			(3,091,315	)
Deficit, beginning of the period		(29,402,565	)		(13,367,032	)		(18,359,187	)		(10,999,503	)
Change in accounting policy		—			—			—			(572,359	)
Deficit, end of the period	$	(17,371,175	)	$	(14,663,177	)	$	(17,371,175	)	$	(14,663,177	)
Net income (loss) for the period per common share
Basic	$	0.41		$	(0.05	)	$	0.03		$	(0.12	)
Diluted	$	0.39		$	(0.05	)	$	0.03		$	(0.12	)
Weighted average common shares outstanding
Basic		29,430,383			28,172,134			29,342,529			25,997,500
Diluted		30,912,375			28,663,627			30,585,721			26,493,629

See accompanying notes to consolidated financial statements.

Petroflow Energy Ltd.
Consolidated Statements of Comprehensive Gain (Loss)
Expressed in Canadian Dollars
(Unaudited)

	Three months ended					Nine months ended
	September 30,					September 30,
	2008		2007			2008		2007
			Restated					Restated
			(note 14)					(note 14)
Net income (loss)	$	12,031,390	$	(1,296,145	)	$	988,012	$	(3,091,315	)
Other comprehensive loss
Foreign currency translation gain (loss)		598,275		(4,505,533	)		927,718		(2,450,460	)
Comprehensive gain (loss)	$	12,629,665	$	(5,801,678	)	$	1,915,730	$	(5,541,775	)

Consolidated Statement of Accumulated Other Comprehensive Gain
(Loss) Expressed in Canadian Dollars
(Unaudited)

	Nine months ended September 30,
	2008			2007
				Restated
				(note 14)
Accumulated other comprehensive gain (loss), beginning of period	$	(2,930,825	)	$	278,418
Foreign currency translation gain (loss)		927,718			(2,450,460	)
Accumulated other comprehensive loss, end of period	$	(2,003,107	)	$	(2,172,042	)

Petroflow Energy Ltd.
Consolidated Statements of Cash Flows
Expressed in Canadian Dollars
(Unaudited)

	Three months ended						Nine months ended
	September 30,						September 30,
	2008			2007			2008			2007
				Restated						Restated
				(note 14)						(note 14)
Cash provided by (used in):
Operating activities
Net income (loss)	$	12,031,390		$	(1,296,145	)	$	988,012		$	(3,091,315	)
Non-cash items:
Depletion and Depreciation		2,695,325			1,418,873			7,027,436			4,058,571
Accretion		12,156			48,777			37,332			95,026
Write-down of property and equipment		—			—			1,015,950			—
Unrealized gain on derivative instruments		(11,295,283	)		(239,649	)		(520,070	)		(108,135	)
Non-cash common share compensation		708,000			—			708,000			—
Stock-based compensation		1,871,419			404,496			2,662,254			738,051
		6,023,007			336,352			11,918,914			1,692,198
Changes in non-cash working capital items		(1,207,606	)		2,038,955			(9,608,340	)		6,435,481
		4,815,401			2,375,307			2,310,574			8,127,679
Financing activities
Increase in bank loan		19,031,443			4,436,064			17,620,915			37,830,378
Issuance of common shares (net of share issue costs)		—			7,861,235			—			7,940,915
Subscription funds		—			(860,000	)		—			—
Exercise of options		61,140			—			485,996			—
Repayment of notes payable		—			(510,580	)		—			(17,899,840	)
Capital lease payments		(1,178,482	)		(40,361	)		(2,534,856	)		(291,364	)
Net change in non-cash financing items		—			(136,561	)		—			(459,177	)
		17,914,101			10,749,797			15,572,055			27,120,912
Investing activities
Expenditures on property, plant and equipment		(20,425,439	)		(12,339,104	)		(47,561,162	)		(38,872,278	)
Disposals on property, plant and equipment		—			—			28,249,927			—
Net change in non-cash investing items		(2,894,243	)		880,700			1,599,551		��	2,577,518
		(23,319,682	)		(11,458,404	)		(17,711,684	)		(36,294,760	)
Change in cash and cash equivalents		(590,180	)		1,666,701			170,945			(1,046,169	)
Effect of Foreign currency rate changes on cash and cash equivalents		333,653			39,651			346,469			277,926
Cash and cash equivalents, beginning of period		1,575,745			690,661			801,804			3,165,256
Cash and cash equivalents, end of period	$	1,319,218		$	2,397,013		$	1,319,218		$	2,397,013
Cash interest paid	$	1,009,162		$	446,651		$	3,506,005		$	1,977,285
Cash interest received	$	14,168		$	27,453		$	38,499		$	62,508
Non-cash capital expenditure through leases	$	1,747,813		$	(244,885	)	$	10,067,975		$	1,723,033

See accompanying notes to consolidated financial statements.

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

1. SIGNIFICANT ACCOUNTING POLICIES

The unaudited interim consolidated financial statements of Petroflow Energy Ltd. (the “Company” or “Petroflow”) have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”), following the same accounting policies and methods of computation as the consolidated financial statements of the Company for the year ended December 31, 2007 except as discussed in Note 2 below. These unaudited interim consolidated financial statements do not include all disclosures required in the annual consolidated financial statements and should be read in conjunction with the Company’s restated annual consolidated financial statements and notes thereto for the year ended December 31, 2007.

2. CHANGES IN ACCOUNTING POLICIES

Capital Disclosures

Effective January 1, 2008, the Company adopted the following standards previously issued by the Canadian Accounting Standards Board (“AcSB”). In accordance with the transitional provision of these standards, these changes were adopted prospectively with no restatement of prior periods. No impact to the earnings or cash flows of the Company was identified upon adoption.

On January 1, 2008, the Company prospectively adopted CICA Section 1535 Capital Disclosures issued by the “AcSB. This Section establishes standards for disclosing information about an entity’s objectives, policies and processes for managing its capital structure. In addition, disclosures include whether companies have complied with externally composed capital requirements. The disclosures have been included in Note 9.

Financial Instruments Disclosures and Presentation

On January 1, 2008, the Company prospectively adopted the following new standards issued by the AcSB: Financial Instruments — Disclosure (Section 3862) and Financial Instruments — Presentation (Section 3863). These accounting standards replaced Financial Instruments — Disclosure and Presentation (Section 3861). The disclosures required by Section 3862 provide additional information on the risks associated with our financial instruments and how we manage those risks. The additional disclosures required by these standards are provided in Note 9.

New Accounting Pronouncements

In February 2008, the AcSB issued Section 3064, Goodwill and Intangible Assets and amended Section 1000, Financial Statement Concepts clarifying the criteria for the recognition of assets, intangible assets and internal developed intangible assets. Items that no longer meet the definition of an asset are no longer recognized with assets. The standard is effective for fiscal years beginning on or after October 1, 2008 and early adoption is permitted. The Company is currently evaluating the impact these sections may have on its results of operations and financial position.

In January 2006, the AcSB adopted a strategic plan for the direction of accounting standards in Canada. Accounting standards for public companies in Canada will converge with the International Financial Reporting Standards (IFRS) by 2011 and the Company will be required to report according to IFRS for the year ending December 31, 2011. The Company is currently assessing the impact of the convergence of Canadian GAAP with IFRS on our results of operations, financial position and disclosure.

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

3. PROPERTY AND EQUIPMENT

			Accumulated
			depletion &
	Cost		depreciation			Net book value
September 30, 2008
Petroleum and natural gas interests and the equipment thereon	$	141,610,689	$	(19,782,269	)	$	121,828,420
Office Equipment		443,699		(140,435	)		303,264
	$	142,054,388	$	(19,922,704	)	$	122,131,684
December 31, 2007
Petroleum and natural gas interests and the equipment thereon	$	107,151,998	$	(10,818,198	)	$	96,333,800
Office Equipment		247,121		(72,746	)		174,375
	$	107,399,119	$	(10,890,944	)	$	96,508,175

At September 30, 2008, oil and gas properties included $5,583,037 (December 31, 2007 — $416,346) relating to unproved properties, the cost of which has been excluded from the depletion calculation. At September 30, 2008 future development costs of $74,241,048 (December 31, 2007 - $102,386,633) on proved undeveloped land are included in the depletion calculation.

The Company did not capitalize any general and administrative costs during the period.

Included in property and equipment at September 30, 2008 are assets under capital lease totaling $22,231,437 (December 31, 2007 — $11,428,527) that are being depleted along with the Company’s other oil and gas assets.

For the nine month period ended September 30, 2008, the Company performed a ceiling test in accordance with the Canadian Institute of Chartered Accountant’s full cost accounting guidelines which did not result in a write-down (June 30, 2008 — $1,015,950 write down of property and equipment on the Company’s Canadian properties; year ended December 31, 2007 — nil).

On May 22, 2008, the Company sold its San Juan Basin coal bed methane property for net cash proceeds of $28,249,927.

4. ASSET RETIREMENT OBLIGATIONS

The Company’s asset retirement obligations result from net ownership interests in petroleum and natural gas assets including well sites and processing facilities, all of which have estimated costs to abandon and reclaim that will be incurred in the future. As at September 30, 2008, the Company estimated that undiscounted cash flows of $3,409,963 (December 31, 2007 — $4,046,077) are required to settle its asset retirement obligations which are expected to be incurred between 2008 and 2048. An inflation rate of 2% and a credit-adjusted risk-free rate of 8% were used to calculate the fair value of the asset retirement obligations as at September 30, 2008. Subsequent adjustments to the initial asset and liability are recorded to reflect revisions to estimated future cash flow requirements.

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

The Company’s asset retirement obligation changed as follows:

	September 30,			December 31,
	2008			2007
Balance beginning of period	$	861,488		$	1,199,142
Increase in liabilities		44,193			51,853
Adjustment for revision of estimated life		—			(465,444	)
Disposal of asset and other		(209,197	)		—
Asset retirement costs incurred		(74,827	)		—
Accretion expense		37,332			75,937
Balance at September 30, 2008	$	658,989		$	861,488

5. BANK LOAN

On September 30, 2008 the Company had a U.S. $200,000,000 revolving credit facility with a U.S. based bank. This facility is dependent upon continued yearly reserve additions, with current availability of U.S. $110,000,000 made up two tranches, “A” and “B”. The “A” tranche has a maturity date of January 1, 2012 with a borrowing base of $US 102 million. Interest rates on the “A” tranche are either a range from LIBOR plus 2% to LIBOR plus 2.5% depending on the percentage of funds actually borrowed or the base rate. The base rate is a fluctuating rate equal to the higher of (a) the Federal Funds Rate plus .5% and (b) the rate of interest in effect for such day as publicly announced from time to time by the Administrative Agent as its “prime rate”. The “B” tranche matures on January 1, 2010, has a borrowing base of $US 8 million, and bears interest at LIBOR plus 4% or the base rate plus 1.5%. As at September 30, 2008 a total of $73,424,206 (U.S. $70,722,603) was drawn on this facility (December 31, 2007 — $52,957,826 (U.S. $53,422,603)). For the nine months ended September 30, 2008 $2,641,073 (U.S. $2,631,164) was incurred as interest expense and for the three months ended September 30, 2008 $753,956 (U.S. $724,700) was incurred as interest expense on the revolving credit facility.

6. OBLIGATION UNDER CAPITAL LEASE

A summary of the Company’s obligation under capital lease is as follows:

2008	$	3,023,623
2009		8,754,782
2010		7,393,604
2011		2,551,343
Total minimum lease payment		21,723,352
Less amount representing annual interest at 12.0%		(3,222,466	)
		18,500,886
Less current portion		(7,384,134	)
	$	11,116,752

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

7. SHARE CAPITAL

a) Authorized

An unlimited number of Common shares, with one vote per share and an unlimited number of Preferred shares, issuable in series (no Preferred Shares have been issued to date).

b) Outstanding and Issued:

	Number of
	Shares		Amount
Balance at December 31, 2007		29,242,344	$	36,900,052
Exercise of stock options		225,050		485,996
Shares issued to Directors		100,000		708,000
Reclassification from contributed surplus on exercise of stock options		—		314,256
Balance at September 30, 2008		29,567,394	$	38,408,304

On July 10, 2008 the Company issued 100,000 common shares to the directors of the Company as compensation at a price of $7.08 per share.

c) Warrants:

	Number of
	Warrants		Amount
Balance at December 31, 2007, and September 30, 2008		1,692,000	$	103,935

d) Stock-based compensation plan

The Company maintains a stock option plan, which is governed by the Compensation Committee. All directors, officers and certain employees and consultants are eligible to participate in the plan. Under the plan, the Company may grant options for up to 10% of the issued and outstanding common shares. The aggregate number of options that may be granted to any one individual (excluding consultants) must not exceed five percent of the total issued and outstanding common shares and must not exceed two percent of the total issued and outstanding common shares for those granted to consultants. Options were granted at exercise prices equal to the estimated fair value of the shares at the date of grant and, with the exception of 250,000 options granted to consultants, vest 30% on the date of grant, with an additional 20% vesting on each of the first and second anniversary of the date of grant and an additional 15% vesting on each of the third and fourth anniversary of the date of grant. On July 10, 2008 the Company amended its stock option plan relating to the vesting provisions of all of its Option Agreements previously issued to employees, officers and directors. The options are exercisable pursuant to the following vesting schedule, 1/3 on the date of grant, 1/3 on the 1st anniversary of the grant and 1/3 on the 2nd anniversary of the date of grant. Options expire on or before five years from the date of grant. The effect of this amended stock option plan was $1.8 million towards the expense for the three and nine months ended September 30, 2008. The 250,000 options granted to consultants expire on or before two years from the date of grant and vest 25% every three months from the date of grant.

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

A summary of the status of the Company’s stock option plan at September 30, 2008 is presented below:

	2008					2007
				Weighted					Weighted
	Number of			average		Number of			average
	Options			exercise price		Options			exercise price
Outstanding, beginning of period		2,476,200		$	2.01		2,080,300		$	1.93
Granted		672,000			5.61		638,500			2.39
Exercised		(225,050	)		2.16		(94,600	)		0.80
Cancelled/Forfeited		(20,850	)		3.21		(148,000	)		3.39
Outstanding, end of period		2,902,300		$	2.82		2,476,200		$	2.01

Fair Value of Options:

Compensation costs attributable to share options granted are measured at fair value at the grant date and expensed over the expected exercise time-frame with a corresponding increase to contributed surplus. Upon exercise of the stock options, consideration paid by the option holder together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. The fair value of each option granted is estimated on the date of grant using the Black-Scholes options pricing model with the following weighted average assumptions for the nine month period ended September 30:

	2008			2007
Dividend yield		0	%		0	%
Expected volatility		119	%		102	%
Risk free rate of return		3.28	%		3.87	%
Expected option life	2 – 5 years			2 – 5 years

Contributed Surplus:

	2008			2007
Balance, beginning of year	$	3,369,281		$	1,668,319
Stock-based compensation expense		2,662,254			1,261,763
Expired Warrants		—			521,500
Exercise of stock options		(314,256	)		(82,301	)
Balance, end of period	$	5,717,279		$	3,369,281

8. COMMITMENTS

On August 2, 2006, the Company signed two contracts whereby, effective at the end of July 2006, two drilling rigs were made available to the Company for its drilling program in Oklahoma. One rig has been contracted to the Company at a cost of U.S. $17,000 per day for two years, and the other at U.S. $17,000 per day for three years. Both rigs have been fully utilized by the Company’s capital program, and no stand-by fees have been incurred.

In April 2007 the Company signed a third drilling rig contract with the same service provider for a newer rig to be available in September of 2007 at a rate of U.S. $22,000 per day for three years. The Company has the option under this third contract to, with 45 days written notice, switch one of the older rigs available under the August 2006 contracts for this newer rig should the Company not need a third rig.

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

9. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

The Company’s financial assets and liabilities are comprised of cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, investment in Limited Partnership, risk management liabilities and bank loan. Risk management liabilities arise from the use of derivatives. Discussions of risk associated with financial liabilities, fair values of financial liabilities and summarized information related to risk management positions are detailed below:

Risks associated with financial liabilities

The Company is exposed to financial risks from its financial liabilities. The financial risks include market risk relating to commodity prices, interest rates, foreign exchange rates, credit and liquidity risks.

Market Risk

Market risk is the risk that the fair value or future cash flows of a derivative will fluctuate because of changes in market prices. Market risk comprises foreign exchange risk, interest rate risk and commodity price risk discussed below.

Commodity Price Risk

The Company is exposed to commodity price risk on crude oil and natural gas revenues. As a means to mitigate the exposure to commodity price volatility, the Company has entered into various derivative agreements. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company’s policy is not to use derivative financial instruments for speculative purposes.

Crude Oil — The Company has partially mitigated its exposure to the WTI NYMEX price with option contracts.

Natural gas — The Company has partially mitigated the natural gas commodity price risk by entering into fixed price swaps and option contracts. As disclosed below:

Crude Oil

	Volume		Call
	per day		Price		Put Price
Period	(boe)		$ US		US$
January 1, 2008 – March 31, 2009		75	$	72.80	$	65.00
January 1, 2008 – December 31, 2008		75	$	107.50	$	75.00
January 1, 2009 – December 31, 2009		75	$	100.50	$	75.00

Natural Gas

	Volume		Call
	per day		Price		Put Price
Period	(mmbtu)		US$		US$
April 1, 2008 – September 30, 2008		350	$	9.50	$	6.00
April 1, 2008 – September 30, 2008		350	None		$	6.00
April 1, 2008 – October 31, 2008		1,750	$	9.70	$	6.50
April 1, 2008 – October 31, 2008		2,000	$	10.20	$	7.00
April 1, 2008 – October 31, 2008		3,000	$	10.70	$	8.00
November 1, 2008 – March 31, 2009		1,750	$	11.40	$	7.50
November 1, 2008 – March 31, 2009		2,000	$	11.20	$	8.00
November 1, 2008 – March 31, 2009		3,000	$	13.55	$	8.00
April 1, 2009 – September 30, 2009		2,000	$	10.08	$	7.00
April 1, 2009 – October 31, 2009		3,000	$	9.03	$	8.00
October 1, 2009 – December 31, 2009		2,000	$	10.80	$	7.50

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

The estimated fair value of all of the above contracts at September 30, 2008 is a current asset of $272,475 (December 31, 2007 — ($210,123 current liability)) and a long term liability of $90,410 (December 31, 2007 — $122,192).

Interest Rate Risk

The Company is exposed to interest rate risk on bank indebtedness to the extent of changes in the LIBOR rate. At September 30, 2008, a one percent increase or decrease in the interest rate on debt amounts to $551,000 impact to net income for the nine months ended September 30, 2008. The Company had no interest rate swap or financial contracts in place as at or during the three months ended September 30, 2008.

Foreign Exchange Risk

The Company’s significant operations are in the U.S. and the functional currency of its U.S. subsidiary’s operations is the U.S. Dollar (self sustaining operation). As a result, the revenues and expenses are translated to Canadian dollars using average exchange rates for the period. Assets and liabilities are translated at the period-end exchange rate. Gains or losses resulting from the translation are included in accumulated other comprehensive income (loss) in shareholders’ equity.

The Company’s foreign exchange gain (loss) is primarily comprised of unrealized foreign exchange gains and losses on the translation of its net assets in the U.S. subsidiary. A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in $16,000 in foreign exchange (gain) loss at September 30, 2008 which would be recognized in other comprehensive income.

Fair value of Financial Assets and Liabilities

The Company’s financial instruments recognized in the balance sheet consist of cash and cash equivalents, accounts receivable, investment in limited partnership, accounts payable and accrued liabilities and the bank loan. The carrying values of these financial instruments other than investment in limited partnership and bank loan approximate their fair market value due to their demand nature or relatively short periods to maturity. The fair value of the unquoted investment in limited partnership cannot be practically determined. The carrying value of the bank loan approximates its fair value as the interest is charged at current market rates. Risk management (liabilities) assets are marked to market at the end of each balance sheet date.

Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company’s receivables from joint venture partners and petroleum and natural gas marketers. As at September 30, 2008, Petroflow’s receivables consisted of $4,423,848 from joint venture partners, and $7,225,961 from petroleum and natural gas marketers.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. Petroflow’s policy to mitigate credit risk associated with these balances is to establish marketing relationships with large purchasers. The Company historically has not experienced any collection issues with its petroleum and natural gas marketers except as discussed below. Joint venture receivables and other receivables are typically collected within one to three months of the joint venture bill being issued to the partner. Petroflow attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to expenditure. However, the receivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances is dependent on industry factors, such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition, further risk exists with joint venture partners as disagreements occasionally arise that increases the potential for non-collection. Petroflow does typically obtain collateral through cash calls from its joint venture partners; however, does not obtain collateral from petroleum and natural gas marketers. The Company does have the ability to withhold production from joint venture partners in the event of non-payment.

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

Cash and cash equivalents consist of cash bank balances and short-term deposits maturing in less than 90 days. Petroflow manages the credit exposure related to short-term investments by selecting counterparties based on credit ratings and monitors all investments to ensure a stable return, avoiding complex investment vehicles with higher risk. Petroflow has no investments in asset-backed commercial paper.

The carrying amount of accounts receivable and cash and cash equivalents represents the maximum credit exposure. On July 22, 2008, SemGroup L.P. one of the Company’s petroleum and natural gas marketers announced that it and certain of its North American subsidiaries had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code as well as an application for creditor protection under the Companies’ Creditors Arrangement Act in Canada. Petroflow has a maximum potential exposure of $US2.8 million as of September 30, 2008 and an additional $US1 .6 million or a total of $4.4 million up to the date of the SemGroup petition in respect of uncollected revenues. The account receivable arises from a majority of the oil production volumes and 20% of the natural gas volumes sold to SemCrude, L.P. and SemGas, L.P. subsidiaries of SemGroup, L.P., (“SemGroup”) for the marketing of a portion of Petroflow’s production. Petroflow’s management has retained legal counsel and continues to have discussions with SemGroup and its Monitor to best manage and resolve this matter. At this time, the Company’s best estimate of the uncollectible amount of the receivable is $1,425,970, (U.S. $1,400,000) which amount has been recorded in these financial statements.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Petroflow’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking harm to the Company’s reputation. Petroflow prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary.

Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. To facilitate the capital expenditure program, Petroflow has a revolving reserves based credit facility, as outlined in note 5 that is reviewed by the lender.

Capital Management

	September 30,		December 31,
	2008		2007
Bank debt	$	73,424,206	$	52,957,826
Working capital deficiency (1)		12,777,666		16,936,728
Net debt		86,201,872		69,894,554
Shareholders’ equity		24,855,236		19,083,256
Total capitalization	$	111,057,108	$	88,977,810

(1) Working capital excludes derivative contracts

The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company considers its capital structure to include shareholders’ equity, bank debt and working capital. In order to maintain or adjust the capital structure, the Company may, from time to time, issue shares and adjust its capital spending to manage current and projected debt levels.

As the Company is in a development stage its primary focus is on increasing the proved and probable reserve value attributable to its property plant and equipment and maintaining the ratio of its overall indebtedness to proved plus probable reserves (discounted at 10%) at less than 1:3. As of June 30, 2008, the latest date for which the Company had independent reserve information, that ratio was 1:8.05. The Company also monitors capital based on the ratio of net debt to annualized funds from operations before deducting interest expense. This ratio is calculated as net debt, defined as outstanding bank debt plus or minus working capital (excluding derivative contracts), divided by funds from operations before interest and changes in non-cash working capital for the most recent calendar quarter, annualized (multiplied by four) and future expected cash flows on an annual basis. Funds from operations is calculated based on cash provided by operating activities before changes in non-cash working capital and expenditures on asset retirement obligations. The Company’s strategy is to maintain a ratio of net debt to annualized funds from operations within debt covenants established under its banking facility. As at September 30, 2008, the Company’s ratio of net debt to annualized cash flow before interest was 3.56 to 1, which is within debt covenants established under its banking facility.

This ratio may increase at certain times as a result of acquisitions and/or large capital projects. In order to facilitate the management of these ratios, the Company prepares annual capital expenditure budgets, which are updated as necessary depending on varying factors, including current and forecast prices, successful capital deployment and general industry conditions. The annual budgets are approved by the Board of Directors.

The Company has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future. There were no changes in the Company’s approach to capital management during the three months ended September 30, 2008.

10. RELATED PARTIES

As at September 30, 2008, $19,100 (December 31, 2007 — $3,032) was due to Macon Oil & Gas Corp. (“MOG”), a wholly owned subsidiary of Macon Resources Ltd., operator of one of the Company’s producing properties. Macon Resources Ltd., is a related party by virtue of its significant shareholdings in the Company. Additionally, $195,000 is owed by the Company to MOG (December 31, 2007 — $220,000) in respect of a bank loan in which MOG is the borrower of record with the bank. MOG is charging the Company interest equal to its rate of interest (prime plus one), and the loan is secured by the property.

For the nine months ended September 30, 2008, legal fees totaling $433,326 (year ended December 31, 2007 — $333,838) were charged to the Company by the Company’s legal counsel where a director of the Company is a partner in the law firm.

For the nine months ended September 30, 2008, $49,884 (December 31, 2007 — $38,525) was charged to the Company by a director of the Company for services rendered.

As at September 30, 2008, $892,171 (December 31, 2007, $384,725) was due to the Company by a joint interest partner in which a director of the Company has an interest.

All transactions with related parties were recorded at exchange amounts and were incurred in the normal course of business.

11. SUBSQUENT EVENTS

Subsequent to September 30, 2008, the Company entered into additional financial derivative contracts for natural gas and crude oil. The following table outlines the details of these contracts.

Crude Oil

	Volume		Call
	per day		Price		Put Price
Period	(boe)		US$		US$
January 1, 2009 – December 31, 2009		100	$	89.70	$	70.00
January 1, 2010 – December 31, 2010		100	$	78.70	$	65.00

Natural Gas

	Volume		Call
	per day		Price		Put Price
Period	(mmbtu)		US$		US$
January 1, 2009 – December 31, 2009		1,000			$	7.00
November 1, 2009 – November 30, 2010		1,500			$	6.50
January 1, 2010 – December 31, 2010		2,000	$	10.05	$	6.50
January 1, 2010 – December 31, 2010		500			$	6.50
January 1, 2010 – December 31, 2010		1,000	$	9.45	$	6.50

Petroflow Energy Ltd.

Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

12. SEGMENTED INFORMATION

The Company conducts its business in two geographic segments: Western Canada and Mid-Western United States. A summary of segmented information for the three and nine month periods ended September 30, 2008 and 2007 is presented below.

Nine months ended September 30, 2008	Canada			USA			Consolidated
Oil and gas sales	$	716,731		$	41,513,608		$	42,230,339
Total revenue		574,144			32,669,905			33,244,049
Operating expenses		322,999			6,868,979			7,191,978
Depletion and depreciation		675,138			6,352,298			7,027,436
General and administrative expenses		3,150,499			3,962,351			7,112,850
Interest expense		—			4,534,159			4,534,159
Income (loss) before other items		(7,576,458	)		9,612,154			2,035,696
Capital expenditures		41,254			57,587,883			57,629,137
Capital proceeds on disposal		—			(28,249,927	)		(28,249,927	)
Property and equipment		3,373,601			118,758,083			122,131,684
Total assets		7,593,834			129,548,792			137,142,626

Nine months ended September 30, 2007
(Restated Note 14)	Canada		USA			Consolidated
Oil and gas sales	$	933,533	$	14,698,667		$	15,632,200
Total revenue		671,006		11,571,024			12,242,030
Operating expenses		118,541		3,808,304			3,926,845
Depletion and depreciation		407,937		3,650,634			4,058,571
General and administrative expenses		1,940,961		1,419,647			3,360,608
Interest expense		177,907		2,818,754			2,996,661
Loss before other items		2,132,016		(5,234,361	)		(3,102,345	)
Total Capital expenditures		113,954		40,481,357			40,595,311
Property and equipment		5,132,975		74,848,447			79,981,422
Total assets		6,877,649		82,045,673			88,923,322

Three months ended September 30, 2008	Canada			USA		Consolidated
Oil and gas sales	$	215,397		$	16,402,521	$	16,617,918
Total revenue		169,335			12,980,039		13,149,374
Operating expenses		143,254			2,753,451		2,896,705
Depletion and depreciation		224,058			2,451,267		2,695,325
General and administrative expenses		1,510,905			1,324,350		2,835,255
Interest expense		—			1,529,958		1,529,958
Net income (loss) before other items		(3,899,685	)		5,192,798		1,293,113
Capital expenditures		5,932			22,167,320		22,173,252

Three months ended September 30, 2007
(Restated Note 14)	Canada		USA			Consolidated
Oil and gas sales	$	272,175	$	5,480,880		$	5,753,055
Total revenue		199,293		4,366,334			4,565,627
Operating expenses		36,954		1,694,402			1,731,356
Depletion and depreciation		173,028		1,245,845			1,418,873
General and administrative expenses		382,069		784,263			1,166,332
Interest expense		170,004		1,013,509			1,183,513
Loss before other items		3,224,397		(4,673,504	)		(1,449,107	)
Total Capital expenditures		463,902		11,630,317			12,094,219

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

13. COMPARATIVE FIGURES

Certain of the comparative figures have been reclassified to conform with the presentation adopted in the current period.

14.  RESTATEMENT OF SEPTEMBER 30, 2007 COMPARATIVE UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS

The September 30, 2007 unaudited interim comparative consolidated financial statements have been restated to correct the foreign translation of the Company’s wholly-owned U.S. subsidiary. The Company had, in error, previously determined the functional currency of the U.S. subsidiary operations to be the Canadian dollar. However, based on a detailed review of the facts and circumstances, management has concluded that the functional currency of the U.S. subsidiary is the U.S. dollar and restated the 2007 annual financial statements to reflect this determination. As a result, the comparative September 30, 2007 financial information has been adjusted to reflect the translation of the U.S. subsidiary operation as self-sustaining. Assets and liabilities are translated at the spot rate in effect at the balance sheet date, and the consolidated statements of operations and cash flows are translated at the average exchange rate in effect during the period. The resulting unrealized cumulative translation adjustment, net of applicable income taxes, is recorded as a component of accumulated other comprehensive income (loss) in shareholders’ equity.

The correction has had no net impact on cash balances previously reported, however certain amounts previously reported in the consolidated statement of cash flows have been restated to reflect the following adjustments, including expenditures on property and equipment, amortization expense, changes in non-cash working capital, and unrealized foreign exchange gains and losses. Certain balances on the cash flow statement have been restated to reflect translation at an average exchange rate where they were previously reported as a period end exchange rate.

Impact of Restatement on the nine months ended September 30, 2007 Consolidated Financial Statements

The Company has restated its opening and closing balance sheet for September 30, 2007, as well as the consolidated statement of operations and comprehensive loss and deficit and cash flows for the nine month period ended September 30, 2007 as follows:

• Adjust property and equipment by $9,707,624 with a corresponding adjustment to other comprehensive income account, as a result of the re-measurement from historical to current foreign exchange rates at September 30, 2007.

• Adjustment to decrease amortization expense and increase property and equipment by $83,622 to correct the calculation of amortization expense.

• Adjustment to remove previously recognized foreign exchange loss of $7,232,929 from the statement of operations to a component of accumulated other comprehensive income (loss).

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

The effect of the restatement as at September 30, 2007 on the consolidated statements of operations and cash flows for the nine months then ended is as follows:

	As previously
Nine months ended September 30, 2007	reported			Restatement			As restated
Expenses
Foreign exchange gain (loss)	$	7,232,929		$	(7,330,034	)	$	(97,105	)
Amortization		4,142,193			(83,622	)		4,058,571
Net loss for the period		4,155,097			(7,246,412	)		(3,091,315	)
Accumulated comprehensive loss for the period		—			(5,619,527	)		(5,619,527	)
Deficit — End of period		(7,756,865	)		(6,906,312	)		(14,663,177	)
Net loss per share		0.16			(0.27	)		(0.12	)
Consolidated Statement of Cash Flows
Operations		7,130,258			997,421			8,127,679
Financing		24,899,054			2,221,858			27,120,912
Investing		(32,797,555	)		(3,497,205	)		(36,294,760	)
Effect of foreign exchange rates on cash		—			277,926			277,926
Change in cash and cash equivalents		(768,243	)		(277,926	)		(1,046,169	)
Cash — End of period		2,397,013			—			2,397,013

Impact of Restatement on three months ended September 30, 2007 Consolidated Financial Statements

The Company has restated its opening and closing balance sheet for September 30, 2007, as well as the consolidated statement of operations and comprehensive loss and deficit and cash flows for the three month period ended September 30, 2007 as follows:

• Adjust property and equipment by $4,110,434 with a corresponding adjustment to other comprehensive income account, as a result of the re-measurement from historical to current foreign exchange rates at September 30, 2007.

• Adjustment to decrease amortization expense and increase property and equipment by $68,778 to correct the calculation of amortization expense.

• Adjustment to remove previously recognized foreign exchange loss of $3,034,068 from the statement of operations to a component of accumulated other comprehensive income (loss).

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

The effect of the restatement as at September 30, 2007 on the consolidated statements of operations and cash flows for the three months then ended is as follows:

	As previously
Three months ended September 30, 2007	reported			Restatement			As restated
Expenses
Foreign exchange gain (loss)	$	3,034,068		$	(3,120,755	)	$	(86,687	)
Amortization		1,487,651			(68,778	)		1,418,873
Net loss for the period		1,755,832			(3,051,977	)		(1,296,145	)
Accumulated comprehensive loss for the period		—			(6,275,937	)		(6,275,937	)
Deficit — End of period		(7,756,865	)		(6,906,312	)		(14,663,177	)
Net loss per share		0.06			(0.11	)		(0.05	)
Consolidated Statement of Cash Flows
Operations		1,595,343			779,964			2,375,307
Financing		9,691,764			1,058,034			10,749,797
Investing		(9,580,755	)		(1,877,649	)		(11,458,404	)
Effect of foreign exchange rates on cash		—			39,651			39,651
Change in cash and cash equivalents		1,706,352			(39,651	)		1,666,701
Cash — End of period		2,397,013			—			2,397,013

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

CORPORATE INFORMATION

Directors	Officers
Richard Clark	Richard Clark
Chairman	Chairman
Partner, Gowling Lafleur Henderson LLP
Joseph Blandford	Joseph Blandford
Vice Chairman	Vice Chairman
Chairman, Engineering Foundation Advisory Board
Donald J. Rowden	John Melton
Chief Executive Officer, MacSema Inc.	President & Chief Executive Officer
Richard Azar, II	Sandy Andrew
Director	Executive Vice President & Chief Operating Officer
David Elgie	Duncan Moodie
Director	Chief Financial Officer
John Melton	Kevin Davis
President & Chief Executive Officer	Senior Vice President, Corporate Development
Patricia Leeson	Louis Schott
Corporate Secretary	Associate Corporate Secretary
Sally Fletchinger	Corporate Office
Corporate Controller	Petroflow Energy Ltd.
	970, 717 — 7th Avenue SW
Stock Exchange Listing	Calgary, Alberta T2P 0Z3
TSX Venture Exchange	Telephone: (403) 539-4320
Symbol: PEF	Facsimile: (403) 705-0488
American Stock Exchange	Contact: Duncan Moodie
Symbol: PED	Email: dmoodie@petroflowenergy.com
Registrar and Transfer Agent	Auditors
Valiant Trust Company	PricewaterhouseCoopers LLP
Calgary, Alberta	Calgary, Alberta
Legal Counsel	Bankers
Gowling Lafleur Henderson LLP	Guaranty Bank
Hogan and Hartson LLP	Texas Capital Bank
	National Bank of Canada

Petroflow Energy Ltd.
Notes to the Unaudited Interim Consolidated Financial Statements
Expressed in Canadian Dollars
For the three and nine months ended September 30, 2008
(Unaudited)

Caution to the Reader

Certain information regarding the Company contained herein may constitute forward-looking statements under applicable securities laws. Such statements are subject to known or unknown risks and uncertainties that may cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The risks, uncertainties and other factors that could influence actual results are described in Petroflow’s annual reports to the shareholders and other documents filed with regulatory authorities.