Petroflow Energy 6K . Announces Q2 2008 Financial Results | PEF 27 Aug 08

Exhibit 99.3

HIGHLIGHTS
Expressed in Canadian Dollars unless otherwise noted
(Unaudited)


	Three Months Ended June 30,							Six Months Ended June 30,
	2008			2007				2008			2007
				Restated							Restated
*Oil and natural gas sales,*
*net of transportation*	$	15,310,628		$	5,964,024			$	25,411,997			9,771,919

*Production per day*
Oil and natural gas liquids (Bbl/d)		412			304				373			250
Natural gas (Mcf/d)		12,086			6,225				11,592			5,552
Equivalence at 6:1 (BOE/d)		2,426			1,341				2,305			1,176

*Sales Price*
Natural gas ($/Mcf)		9.70			7.14				8.61			6.80
Oil and natural gas liquids ($/Bbl)		121.48			69.36				109.32			67.25
Equivalence at 6:1 ($/BOE)		68.95			48.87				60.97			46.43

EBITDA¹		(4,294,379	)		2,369,599				(2,665,940	)		2,703,925

*Funds from operations*²		2,578,764			1,493,509				5,895,907			1,355,846
-per share, basic and diluted²		0.09			0.06				0.20			0.05

*Net income (loss) before other items*		(143,275	)		(141,856	)			742,853			(1,653,238	)

*Net loss*		(8,884,498	)		2,524				(11,043,378	)		(1,795,170	)
-per share, basic and diluted		(0.30	)		0.00				(0.38	)		(0.07	)

*Capital expenditures*		20,039,615			14,888,541				35,290,808			27,304,021
*Capital dispositions*	$	(28,249,927	)	$	—			$	(28,249,927	)	$	—

*Basic weighted average shares outstanding*		29,341,315			24,925,056				29,291,630			24,892,162

*Working capital (deficiency)*³
*-As at June 30, 2008*											$	(15,150,743	)
*-As at December 31, 2007*											$	(16,936,728	)

							As at August 21, 2008
*Common Shares*												29,423,894
*Warrants outstanding*												1,692,000
*Options outstanding*												2,891,800


*(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.

MANAGEMENT DISCUSSION AND ANALYSIS

The following discussion and analysis of the operating and financial results of Petroflow Energy Ltd. (“Petroflow” or the “Company”) is for the three and six months ended June 30, 2008 and is provided by management as of August 21, 2008. It should be read in conjunction with Petroflow’s unaudited consolidated financial statements and related notes for the three and six months ended June 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 at www.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 six 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 June 30, 2008, averaged 2,426 boepd, 12% higher than the first quarter of 2008 and 81% higher than the three months ended June 30, 2007. The Company’s production volumes for the six months ended June 30, 2008, averaged 2,305 boepd, 96% higher than the six months ended June 30, 2007. The Company tied in 8 wells during the second 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 June 30, 2008 of $2.6 million, $0.7 million lower than the first quarter of 2008 and $1.1 million higher than the three months ended June 30, 2007. Funds from operations for the three and six months ended June 30, 2008 would have been substantially higher except for certain one time expenses, not expected to be incurred on an ongoing basis. These one time expenses consisted of a provision for doubtful receivables of $1.4 million, 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 16 wells during the first half of 2008. Higher production with stronger natural gas and crude oil prices increased funds from operations for the six months ended June 30, 2008, to $5.9 million, $4.5 million higher than the first half of 2007.

Capital expenditures were $35.3 million for the six months ended June 30, 2008, and $20.0 million for the three months ended June 30, 2008. During the first half of 2008, the Company completed 16 wells and one salt water disposal well with a success rate of 100%. As of June 30, 2008, another 5 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 $77.3 million at June 30, 2008; $13.4 million lower than at March 31, 2008, primarily as a result of proceeds from the New Mexico sale during the quarter.

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 the first half of 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.

During the second quarter of 2008 the Company reported the initiation of its Extension Program in the Hunton resource play beyond the Farmout area of mutual interest with Enterra. Petroflow is establishing four new project areas and has initiated drilling activity in one of these areas. 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 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 standards joint interest terms.

New Mexico

In the second quarter of 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 six months ended June 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 six months ended June 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. As a result, the Company has restated its 2007 annual consolidated financial statements. Additionally, the June 30, 2007, unaudited interim comparative consolidated financial statements have also been restated to correct the foreign translation of the Company’s wholly-owned U.S. subsidiary as indicated in note 14.

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 June 30,

Six months ended June 30,

2008

2007

2008

2007

Total Average Volumes

Oil & NGL (bbls)

37,454

27,641

67,521

45,289

Natural Gas (mcf)

1,099,791

566,500

2,098,201

1,004,929

Total (boe)

220,752

122,058

417,222

212,777

Daily Sales Volumes — Average

Oil & NGL (bbls/day)

412

304

373

250

Natural Gas (mcf/day)

12,086

6,225

11,592

5,552

Total (boe/day)

2,426

1,341

2,305

1,176

Volumes

Sales volumes for the three months ended June 30, 2008, increased over the three months ended June 30, 2007, by 81%, and sales volumes for the six months ended June 30, 2008, increased over the six months ended June 2007, by 96%, 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 June 30,				Six months ended June 30,
	2008		2007		2008		2007

Average Prices

Oil & natural gas liquids ($/bbl)	$	121.48	$	69.36	$	109.32	$	67.25
Natural gas ($/mcf)		9.70		7.14		8.61		6.80

$/boe	$	68.95	$	48.87	$	60.97	$	46.43

Average Benchmark Prices

Average exchange rate: US$ to Cdn$	$	0.99	$	1.10	$	0.99	$	1.14
WTI (US$/bbl)		123.95		65.03		110.91		61.65
Edmonton Light ($/bbl)		126.74		72.62		112.48		70.19
NYMEX (US$/mmbtu)		10.93		7.56		9.48		7.26
AECO natural gas ($/GJ)		9.37		7.07		8.29		7.24

Natural Gas

Natural gas sales prices for the three months ended June 30, 2008, compared to the same period in 2007 increased by 36% from $7.14 to $9.70, and for the six months ended June 30, 2008 compared to the same period in 2007, increased by 27% from $6.80 to $8.61, 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 six months ended June 30, 2008, and the natural gas produced in Oklahoma is subject to a significant index differential.

In the first half of 2008, Petroflow renegotiated two of its three 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 two 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.

Oil and Natural Gas Liquids

For the three months ended June 30, 2008 compared to the same period in 2007, average prices increased 75% from $69.36 to $121.48, and for the six months ended June 30, 2008 compared to the same period in 2008, average prices increased 63% from $67.25 to $109.32, 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 first half of 2007.

Oil and Gas Sales


	Three months ended June 30,							Six months ended June 30,
	2008		2007		% Change			2008		2007		% Change

Oil and natural gas liquids	$	4,722,330	$	1,917,270		146	%	$	7,554,061	$	3,045,616		148	%
Natural gas		10,669,981		4,047,279		164	%		18,058,360		6,833,529		164	%

Total oil and natural gas revenues	$	15,392,311	$	5,964,549		158	%	$	25,612,421	$	9,879,145		159	%

Gross revenues from oil, natural gas and natural gas liquids totaled $15.4 million for the three months ended June 30, 2008, compared to $6.0 million for the three months ended June 30, 2007, an increase of 158%. This increase is mostly attributable to an 81% increase in production related to the Company’s drilling activity in Oklahoma. During the second quarter, the Company put an additional 8 wells on production in Oklahoma. The increase in sales was also affected by the increase in sales revenue per mcf of natural gas of 36% in 2008 and sales revenue per bbl of oil and natural gas liquids of 75%, both as compared to the same period in 2007.

Gross revenues from oil, natural gas and natural gas liquids totaled $25.6 million for the six months ended June 30, 2008, and $9.9 million for the six months ended June 30, 2007, an increase of 159%. This increase is attributable to a 96% increase in production due to the Company’s drilling activity in Oklahoma. During the first half of 2008, the Company put 16 wells on production in Oklahoma. The increase in sales was also affected by the increase in sales revenue per mcf of natural gas of 27% in 2008 and sales revenue per bbl of oil and natural gas liquids of 63%, both as compared to the same period in 2007.

Derivative Instruments


	Three months ended June 30,									Six months ended June 30,
	2008			2007			% Change			2008			2007			% Change

Unrealized gain (loss)	$	(7,794,106	)	$	149,851			(5,301	%)	$	(10,775,213	)	$	(131,514	)		8,093	%

Realized loss		(943,407	)		—			100	%		(1,021,395	)		—			100	%
Per boe	$	(39.58	)	$	(0.80	)		(4,848	%)	$	(28.27	)	$	(0.62	)		100	%

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 June 30, 2008, was a liability of $11.6 million, comprised of a $3.1 million liability on oil contracts and an $8.5 million liability on gas contracts.

The three months ended June 30, 2008, includes a $7.8 million unrealized loss on derivatives compared to a gain of $0.1 million for the three months ended June 30, 2007. The unrealized loss on derivatives for the three months ended June 30, 2008, resulted from the change in the fair value of the derivative contracts during the quarter from a liability of $3.7 million at March 31, 2008 to a liability of $11.6 million at June 30, 2008. The $7.8 million loss was comprised of $2.0 million unrealized loss on crude oil contracts, and a $5.7 million unrealized loss on natural gas contracts. The unrealized loss in the second quarter is primarily attributable to strong forward natural gas prices compared to March 31, 2008.

The six months ended June 30, 2008, includes a $10.8 million unrealized loss on derivatives compared to a loss of $0.1 million for the six months ended June 30, 2007. The unrealized loss on derivatives for the six months ended June 30, 2008, resulted from the change in the fair value of the derivative contracts during the six months of 2008 from a liability of $0.3 million at December 31, 2007, to a liability of $10.5 million at June 30, 2008. The $10.8 million loss was comprised of $2.4 million unrealized loss on crude oil contracts, and an $8.4 million unrealized loss on natural gas contracts. The unrealized loss in the first half of 2008 is primarily attributable to strong natural gas forward prices compared to December 31, 2007, and an increase in derivative instruments held.

As of August 20, 2008, the Company’s risk management liabilities had been reduced to $1.9 million as a result of commodity price declines. If prices remain consistent to September 30, 2008, the Company would recognize an unrealized gain on derivates of approximately $9.0 million in the third quarter, which will more than offset the unrealized loss in the second quarter.

The realized portion of the loss, $943,407 for the three months ended June 30, 2008 and $1,021,395 for the six months ended June 30, 2008 is the difference between actual prices in 2008 and the ceiling price to which the Company was entitled for in the applicable period.

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


*Crude Oil*
	*Volume per*		*Call*
*Period*	*day (boe)*		*Price*		*Put Price*

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


*Natural Gas*
	*Volume per*
	*day*		*Call*
*Period*	*(mmbtu)*		*Price*		*Put Price*

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

Royalties


	Three months ended June 30,									Six months ended June 30,
	2008			2007			% Change			2008			2007			% Change

Royalties	$	3,289,124		$	1,226,393			168	%	$	5,547,325		$	2,237,797			148	%
% of Sales		21.37	%		20.56	%		4	%		21.66	%		22.65	%		(4	%)

Per boe	$	14.90		$	10.05			48	%	$	13.30		$	10.52			26	%

Royalties, which include severance taxes, were $3.3 million for three months ended June 30, 2008, compared to $1.2 million for the three months ended June 30, 2007. Royalties, which include severance taxes, were $5.5 million for six months ended June 30, 2008, compared to $2.2 million for the six months ended June 30, 2007. The royalty rate is consistent for the three months ended June 30, 2008 and for the six months ended June 30, 2008 compared to the three and six months ended June 30, 2007. 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 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 Expenses


	Three months ended June 30,							Six months ended June 30,
	2008		2007		% Change			2008		2007		% Change

Operating expenses	$	2,588,720	$	1,322,867		96	%	$	4,295,273	$	2,195,489		96	%
Per boe	$	11.73	$	10.84		8	%	$	10.29	$	10.32		0	%

Operating expenses increased by 96% for the three and six months ended June 30, 2008 as compared to the same periods in 2007. On a per boe basis, operating expenses increased 8% to $11.73/boe from $10.84/boe for the three months ended June 30, 2008 compared to three months ended June 30, 2007. For the six months ended June 30, 2008, the operating costs remained consistent from $10.32/boe to $10.29/boe in 2007. The increase for the three months ended June 30, 2008 is the result of industry cost pressures, higher fuel and power costs together with workover costs in Texas in the second quarter of 2008.

Transportation Costs


	Three months ended June 30,							Six months ended June 30,
	2008		2007		% Change			2008		2007		% Change

Transportation costs	$	81,683	$	525		15,459	%	$	200,424	$	107,226		87	%
Per boe	$	0.37	$	0.00		100	%	$	0.48	$	0.50		(4	%)

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. On a per boe basis, for the three months ended June 30, 2008, this expense increased to $0.37/boe compared to $0.00/boe for the three months ended June 30, 2007. This increase is the result of a prior period-related adjustment in 2007 to transportation costs that was made that caused the significant decline on a per boe basis for the three months ended June 30, 2007.

For the six months ended June 30, 2008, this expense decreased by 4% to $0.48/boe compared to $0.50/boe for the six months ended June 30, 2007. This overall decrease is the result of higher gas volumes not subject to this charge.

Depletion, Depreciation and Accretion (DD&A)


	Three months ended June 30,							Six months ended June 30,
					%							%
	2008		2007		Change			2008		2007		Change
	Restated							Restated
Depletion and depreciation	$	2,143,986	$	1,518,479		41	%	$	4,332,111	$	2,639,698		64	%
Accretion on asset retirement obligation		9,839		23,366		(58	%)		25,176		46,249		(46	%)


	$	2,153,825	$	1,541,845		40	%	$	4,357,287	$	2,685,947		62	%

Per boe	$	9.96	$	12.63		(23	%)	$	10.44	$	12.62		(17	%)

Write-down of property and equipment	$	1,015,950	$	—		100	%	$	1,015,950	$	—		100	%

Per boe	$	4.60	$	0.00		100	%	$	2.44	$	0.00		100	%

The total DD&A rate decreased to $9.96/boe for the three months ended June 30, 2008, compared to $12.63/boe for the same period in 2007. For the six months ended June 30, 2008, the total DD&A rate decreased to $10.44/boe from $12.62/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 six months ended June 30, 2008, due to of the New Mexico asset sale and an increase in estimated reserve life compared the three and six months ended June 30, 2007. The estimated reserve life has increased for the three months ended June 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.

The Company recorded a write-down of $1.0 million on the Company’s Canadian properties or $4.60/boe for the three months ended June 30, 2008 and $2.44/boe for the six months ended June 30, 2008 compared to no write-down recorded for the same periods in 2007. The carrying value of the Company’s petroleum and natural gas properties is limited to the amount calculated under the ceiling test on a country by country basis as at the balance sheet date. At June 30, 2008, the calculation indicated the carrying amount of the Company’s Canadian petroleum and natural gas properties was in excess of the amount calculated under the ceiling test, accordingly, a write-down in the amount of $1.0 million was recorded. The ceiling test calculation was based on forecast benchmark reference prices adjusted for the Company’s quality and price differentials. There was no impairment of the Company’s U.S. properties.

General and Administrative Expenses


	Three months ended June 30,							Six months ended June 30,
					%+							%
	2008		2007		Change			2008		2007		Change

General and administrative	$	3,077,667	$	1,100,807		180	%	$	4,277,595	$	2,194,276		95	%

Per boe	$	13.94	$	9.02		55	%	$	10.25	$	10.31		1	%

Total general and administrative expenses for the three months ended June 30, 2008 were $3.1 million compared to $1.1 million in 2007. General and administrative expense per boe increased by 55% from $9.02 for the three months ended June 30, 2007, to $13.94 for the same period in 2008. Total general and administrative expenses for the six months ended June 30, 2008 were $4.3 million compared to $2.2 million in 2007. General and administrative expense per boe increased by 1% from $10.31 for the six months ended June 30, 2007 to $10.25 for the same period in 2008.

The increases for the three and six months ended June 30, 2008, are the result of $1.0 million associated with employee bonuses incurred in June 2008 and one-time expenses of $0.7 million 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, legal fees, consulting services and other related charges.

Stock Based Compensation


	Three months ended June 30,							Six months ended June 30,
					%+							%
	2008		2007		Change			2008		2007		Change

Stock based compensation	$	499,381	$	98,991		179	%	$	790,835	$	333,555		137	%

Per boe	$	2.26	$	0.81		65	%	$	1.90	$	1.57		21	%

The Company’s stock-based compensation expense increased 179% for the three months ended June 30, 2008, from 98,991 to $0.5 million. This increase is the result of 280,000 options granted at prices from $3.87 to $7.50 , 81,500 of these vested at the time of grant, contributing to $0.3 million towards the expense, and 181,550 options exercised for the three months ended June 30, 2008.

For the six month period ended June 30, 2008, stock-based compensation expense was $0.8 million compared to $0.3 million for the six months ended June 30, 2007. This increase is the result of 330,000 options granted at prices from $1.80 to $7.50 and 96,500 of these vested at the time of grant, contributing to $401,548 towards the expense and 181,500 options exercised for the six months ended June 30, 2008.

Interest Expense


	Three months ended June 30,							Six months ended June 30,
	2008		2007		% Change			2008			2007			% Change
	Restated							Restated
Interest expense and financing expense	$	1,430,183	$	825,230		73	%	$	3,004,201		$	1,813,148			66	%
Average interest rate						8.7	%		6.0	%		9.0	%		6.8	%

Per boe	$	6.48	$	6.76		(4	%)	$	7.20		$	8.52			(16	%)

Interest expense increased by 73% to $1.4 million for the three months ended June 30, 2008. Interest expense increased by 66% to $3.0 million for the six months ended June 30, 2008. These increases are a result of higher debt levels for the three and six months ended June 30, 2008, when compared to the same periods in 2007. Interest expense decreased by 4% on a per boe basis for the three months ended June 30, 2008 and by 16% for the six months ended June 30, 2008, as compared to the prior periods, due to the significant growth in period-over-period production volumes as well as the reduction in bank debt due to the New Mexico asset sale.

At June 30, 2008, the Company had $52.6 million of bank debt outstanding compared to $39.2 million at June 30, 2007. Most of the Company’s debt consists of senior debt facilities provided by a syndicate of U.S. banking institutions. The interest rates charged by the bank are LIBOR plus 2% to LIBOR plus 2.5% on the first U.S. $70 million of funds advanced and LIBOR plus 4% on the next U.S. $6 million.

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 $US2.8 million as of June 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 $1.4 million, which amount has been recorded in these financial statements.

Income Taxes

For the three months ended June 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 Loss and Funds from Operations


	Three months ended June 30,								Six months ended June 30,
	2008			2007		% Change			2008			2007			% Change
	Restated								Restated

Net loss	$	(8,884,498	)	$	2,524		(352,101	)%	$	(11,043,378	)	$	(1,795,170	)		(515	%)

Per boe	$	(40.25	)	$	0.02		(194,727	)%	$	(26.47	)	$	(8.44	)		(214	%)

Funds from operations	$	2,578,764		$	1,493,509		73	%	$	5,895,907		$	1,355,846			335	%
Changes in non-cash working capital items		(5,991,862	)		3,615,611		304	%		(8,400,734	)		4,396,525			(291	%)

Cash provided by operating activities	$	(3,413,098	)	$	5,109,120		(167	%)	$	(2,504,827	)	$	5,752,371			(144	%)

The Company incurred a net loss for the three months ended June 30, 2008, of $8.9 million compared to net income of $2,000 in 2007, primarily because of an unrealized loss on derivative instruments of $7.8 million, a write-down on Canadian properties of $1.0 million, and a $1.4 million provision for bad debt expense as a result of one of the Company’s petroleum and natural gas marketer’s announcing that it and certain of its North American subsidiaries had filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy.

The Company incurred a net loss in for the six months ended June 30, 2008 of $9.7 million compared to net loss of $1.8 million in 2007, primarily because of an unrealized loss on derivative instruments of $10.8 million and a write-down on Canadian properties of $1.0 million and a $1.4 million provision for doubtful accounts receivable recorded for the six months ended June 30, 2008.

The Company’s funds from operations for the three months ended June 30, 2008 increased by $4.5 million from $1.4 million in 2007. The improvement was due to the increased oil and gas production revenues over the period. 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 above.

The Company’s funds from operations for the six months ended June 30, 2008, increased by $45 million from $1.3 million in 2007 to $5.9 million in 2008. The increase is primarily due to increased revenues driven by higher prices and production.

SUMMARY OF QUARTERLY RESULTS

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


	2008						2007												2006
	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3

Oil and gas sales	$	15,392		$	10,220		$	6,361		$	5,753		$	5,965		$	3,915		$	2,641		$	2,112
Funds from operations		2,579			3,317			(1,092	)		510			1,491			(138	)		(1,669	)		(484	)
Per share — Basic and diluted		0.09			0.12			(0.04	)		0.02			0.06			—			(0.07	)		0.02
Net income (loss)		(8,884	)		(2,159	)		(3,792	)		(1,271	)		74			(1,797	)		(2,880	)		(1,158	)
Per share — Basic and diluted		(0.30	)		(0.07	)		(0.14	)		(0.05	)		0.00			(0.07	)		(0.12	)		(0.04	)
Total assets		111,147			120,764			103,029			88,923			82,686			74,873			66,110			41,705
Working capital deficiency⁽¹⁾		(15,151	)		(20,223	)		(17,147	)		(53,021	)		(53,947	)		(46,299	)		(33,251	)		(12,856	)

(1) Excludes derivative contracts

LIQUIDITY AND CAPITAL RESOURCES


			December 31,		%
	June 30, 2008		2007		Change

Working capital deficiency (excluding derivative contracts)	$	15,150,743	$	16,936,728		(19	%)

Shareholders’ equity	$	9,585,012	$	19,083,256		(43	%)

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 June 30, 2008, the Company had a working capital deficiency (excluding derivative contracts) of $15.2 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 June 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 U.S. $76 million made up two tranches, “A” and “B”. The “A” tranche has a maturity date of January 1, 2012 with a borrowing base of $US 70 million. The “B” tranche matures on January 1, 2010, has a borrowing base of U.S. $ 6 million.

As at June 30, 2008, the Company had $52.6 million (U.S. $52 million) drawn on its credit facility and a net working capital deficit of $15.2 million (excluding the derivative contracts) for a total net debt of $79.4 million. As June 30, 2008, the Company was in compliance with its debt covenants.

Shareholders’ equity decreased by 50% in the six months ended June 30, 2008 to $9.6 million, due primarily to the net loss incurred in the period.

Subsequent to June 30, 2008, the Company amended its stock option plan relating to the vesting provisions of its Option Agreements previously issued to employees, officers and directors. The options may now be exercised 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.

As of August 21, 2008, the Company has 29,527,894 Common Shares, 1,692,000 warrants and 2,891,800 options outstanding.

CAPITAL EXPENDITURES


	Three months ended June 30,									Six months ended June 30,
							%								%
	2008			2007			Change			2008			2007		Change
Capital Expenditures	Restated									Restated

Land and rentals	$	416,715		$	(167,118	)		(349	%)	$	587,699		$	200,260		193	%
Seismic		—			2,450			(100	%)		—			12,721		(100	%)
Drilling and completions		11,184,026			9,829,146			18	%		20,395,672			17,975,483		13	%
Equipment and facilities		2,025,519			3,251,718			(38	%)		5,854,004			7,123,835		(18	%)
Assets under capital lease		6,345,147			1,952,720			225	%		8,320,162			1,967,918		323	%
Other assets		68,208			19,625			248	%		133,271			23,804		460	%

		20,039,615			14,888,541			38	%		35,290,808			27,304,021		29	%
Property dispositions		(28,249,927	)		—			(100	%)		(28,249,927	)		—		(100	%)

Total	$	(8,210,312	)	$	14,888,541			(156	%)	$	7,040,881		$	27,304,021		(74	%)

For the three months ended June 30, 2008, the Company spent a significant portion of its developmental drilling budget in Oklahoma where 9 wells were drilled, including one salt water disposal well, and 8 wells were put on production. In the three months ended June 30, 2007, the Company drilled 5 wells in Oklahoma and brought 10 wells on production (5 - Oklahoma and 5 — New Mexico).

Capital expenditures had increased 29%for the six months ended June 30, 2008, compared to the same period in 2007. During the first half of 2008, the Company drilled 17 wells in Oklahoma including one salt water disposal well and brought 16 wells on production compared to 11 wells that were drilled (10 Oklahoma;1 New Mexico) and 19 wells brought on production (9 — Oklahoma; 10 — 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 an obligation 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 $6.3 million of additional expenditures for the three months ended June 30, 2008, compared to $5.8 million in 2007. The lease resulted in the capitalization of $8.3 million of additional expenditures for the six months ended June 30, 2008, compared to $5.8 million in 2007.

The Company completed the sale of its non-core asset in New Mexico for net proceeds of $28,249,927 on May 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 June 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 June 30, 2008.

RELATED PARTY TRANSACTIONS

As at June 30, 2008, $1,624 (December 31, 2007 — $nil) was due to Macon Resources (“Macon”) and $2,970 (December 31, 2007 — $3,032) was due to Macon Oil & Gas Corp. (“MOG”), a wholly owned subsidiary of Macon, operator of one of the Company’s producing properties. 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 six months ended June 30, 2008, legal fees totaling $280,820 (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 six months ended June 30, 2008, $34,026 (December 31, 2007 — $38,525) was charged to the Company by a director of the Company for services rendered.

As at June 30, 2008, $353,590 (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 June 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 (PEF) Inactive 6-KPetroflow Energy LTD. Announces Q2 2008 Financial Results