Petroflow Energy (PEF) 6-K Current report (foreign)

Exhibit 99.2

First Quarter Report for the period ended March 31, 2009

TSX:PEF            NYSE Amex:  PED

FINANCIAL AND OPERATING SUMMARY

	Quarter ended March 31,
	2009			2008			% Change
Financials
Oil sales		1,947,888			2,756,771			(29	%)
Natural gas  and NGL sales		7,624,587			7,463,339			2	%
Total oil, natural gas and NGL revenue		9,572,475			10,220,110			(6	%)
Funds from operations (1)		1,293,023			3,317,143			(61	%)
Per share basic and diluted ($)		0.04			0.11			(62	%)
Net earnings (loss)		(17,822	)		(2,158,880	)		(99	%)
Per share basic and diluted ($)		(0.00	)		(0.07	)		(65	%)
Capital expenditures		15,155,954			15,251,193			(1	%)
Net debt (end of period)		151,289,336			90,710,662			67	%
Operating Highlights
Production:
Oil  (bbls per day)		419			332			26	%
Natural gas and NGL (mcf per day)		18,255			10,960			67	%
Total (boe per day) (6:1)		3,462			2,159			60	%
Average realized price:
Oil ($ per bbl)		51.66			92.25			(44	%)
Natural gas and NGL ($ per mcf)		4.64			7.47			(38	%)
Realized gain (loss) on commodity contracts		4.65			(0.40	)		(1,272	%)
Combined average ($ per boe)		35.38			51.62			(31	%)
Netback ($ per boe)
Oil, natural gas and NGL sales		30.73			52.02			(31	%)
Royalties		6.51			11.49			(43	%)
Operating expenses		11.48			8.69			32	%
Transportation expenses		-			0.60			(100	%)
Operating netback		17.39			30.84			(44	%)
G&A expense		6.89			6.11			13	%
Interest expense		6,34			8.01			(21	%)
Corporate netback		4.16			16.72			(75	%)
Common shares
Common shares outstanding, end of period		29,532,594			29,242,344			1	%
Weighted average basic shares outstanding		29,865,715			29,242,344			2	%

(1) Management uses funds from operations (before changes in non-cash working capital) to analyze operating performance and leverage.  Funds from operations as presented does not have any standardized meaning prescribed by Canadian GAAP and, therefore, may not be comparable with the calculation of similar measures for other entities.

1

OVERVIEW AND HIGHLIGHTS

Maintaining financial and operational flexibility remains a key element in Petroflow’s business model. In the first quarter of 2009, the Company invested $15.2 million, which is consistent with the $15.3 million spent in the first quarter of 2008.

The Company continues to concentrate its capital expenditures in Oklahoma.  The Company drilled one salt water disposal well and one natural gas well in the first quarter of 2009 and put the natural gas well and 6 wells drilled in the fourth quarter of 2008 on stream.

In the first quarter of 2009, Petroflow’s average sales production rate grew to 3,462 boe per day, a 60% increase over the first quarter of 2008 average sales production of 2,159 per day, and an 8% increase over the fourth quarter of 2008 average sales production of 3,201 boe per day.

Funds from operations per share (basic and diluted) decreased by 62% to $0.04 in the first quarter of 2009 from $0.11 in the same period of 2008.  Funds from operations declined by 61% in the first quarter of 2009 to $1.3 million from $3.3 million in the first quarter of 2008.

The Company recorded an $18,000 net loss in the first quarter of 2009 ($0.00 per share - basic and diluted) compared to a net loss of $2.2 million ($0.07 per share - basic and diluted) in the same period of 2008.  The decrease in commodity prices in the first quarter of 2009 more than offset increases in production.

A 31% reduction in revenue per boe was a large contributor to the 44% reduction in Petroflow’s operating netback (defined as revenue net of realized gains/losses in commodity contracts per boe less royalties, operating and transportation expenses on a per boe basis which averaged $17.39 per boe in the first quarter of 2009.  The Company’s corporate netback (defined as operating netback per boe less G&A and interest expense per boe) was $4.16 per boe for the quarter.

Operating costs per boe decreased 12% to $11.48 in the first quarter of 2009 as compared to $12.99 per boe in the fourth quarter of 2008.

The Company’s bank line is currently $124 million (US $99.3 million).  Subsequent to March 31, 2009, the Company entered into an amended credit facility agreement (the “Amended Facility”).  The Amended Facility is US $200 million revolving credit facility with a US based banking syndicate. This facility is dependent upon continued yearly reserve additions, with current availability of US $110 million which is all included in Tranche “A”.  There is an interest rate floor on the Amended Facility of 5.5%.

The global economic and financial crisis has continued to reduce liquidity in financial markets, restrict access to financing and cause significant demand destruction for commodities and lower pricing.  These have continued to affect the economy in the first quarter of 2009 and continue to impact the performance of the economy going forward.  The Company will continue to be flexible in its capital spending in order to respond to changes in commodity prices, costs and capital markets.

2

MANAGEMENT’S 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 months ended March 31, 2009 and is provided by management as of May 25, 2009.  It should be read in conjunction with Petroflow’s unaudited consolidated financial statements and related notes for the three months ended March 31, 2009 and 2008.  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.

NON-GAAP MEASURES

This document contains the term “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 its ability to generate funds for future growth through capital investment.  Funds from operations as presented does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities.

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 term “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.  The reader should be aware that historical results are not necessarily indicative of future performance.

3

RESULTS OF OPERATIONS

Production volumes

	2009		2008					2007
		Q1		Q4	Q3	Q2	Q1		Q4	Q3	Q2
Daily Sales Volumes
Crude oil (bbls/day)		419		494	504	412	332		255	276	304
Natural gas & natural gas
liquids (mcf/day)		18,255		16,240	13,396	12,086	10,960		8,679	7,151	6,225
Total (boe/day)		3,462		3,201	2,737	2,426	2,159		1,702	1,468	1,341

Petroflow’s average sales production rate grew to 3,462 boe per day, a 60% increase over the first quarter of 2008 average sales production of 2,159 per day, and an 8% increase over the fourth quarter of 2008 average sales production of 3,201 boe per day.   This growth occurred even though the Company reduced its drilling program in the first quarter of 2009.  The growth in the first quarter of 2009 compared to the same period in 2008 was primarily the result of the successful drilling program in Oklahoma.

Revenue and realized prices

	Three months ended March 31,
	2009		2008			% Change
Crude oil	$	1,947,888	$	2,831,731			(31	%)
Natural gas and natural gas liquids		7,624,587		7,388,379			3	%
Total oil and natural gas revenues	$	9,572,475	$	10,220,110			(6	%)
Crude oil ($/bbl)	$	51.66	$	92.25			(44	%)
Natural gas & NGL ($/mcf)		4.64		7.47			(38	%)
Total oil, natural gas and NGL revenue (per boe)		30.73		52.02			(41	%)
Unrealized gain (loss)		10.56		(15.17	)		(170	%)
Realized gain (loss)		4.65		(0.40	)		(1,272	%)
Total oil, natural gas and NGL revenue after commodity contracts (per boe)	$	45.94	$	36.45			26	%

Oil, natural gas and natural gas liquids and commodity contracts other revenues

A 60% increase in production combined with a 41% decrease in average revenue per boe resulted in revenues of $9.6 million decreasing from $10.2 million in the first quarter of 2008.

The Company had in place certain oil and natural gas commodity contracts as of March 31, 2009 and had entered into additional contracts since the quarter end.  The Company recognized an unrealized gain of $3.3 million and had a realized gain of $1.5 million on its commodity contracts for the period ended March 31, 2009. The realized gain on hedges was reduced by $1.8 million due to the purchase cost of additional puts in the period.  These particular hedges will allow the Company to profit from price increases in the future.  Please refer to the “Financial Instruments” section of this MD&A for further details on these commodity contracts.

4

Prices

In the first quarter of 2009 the Company realized average revenue per boe of $35.38, a decrease of 31% from the $51.62 in the first quarter of 2008.

Petroflow realized an average natural gas and natural gas liquids price of $4.64 per mcf in the first quarter of 2009, a 38% decrease from $7.47 per mcf averaged in the first quarter of 2008.  This compares to an average NYMEX reference price of US $4.57 per MMBtu in the first quarter of 2009 and a 49% decrease from the first quarter of 2008 price of $8.93 per MMBtu.  The percentage decrease is less than that of NYMEX, which is priced in US dollars.  The difference in differentials was caused by an influx of gas from the Rocky Mountains into the sales market, traditionally serviced by Oklahoma production, in the late fall of 2008.  Natural gas produced in Oklahoma is usually subject to a basis differential, historically in the range of 10% to 15% of NYMEX.

The Company realized an average price of $51.66 per bbl of oil in the first quarter of 2009, a decrease of 44% from $92.25 per bbl realized in the first quarter of 2008.  This compares to an average WTI price of US$43.05 per bbl in the first quarter of 2009 a 56% decrease from US $97.87 per bbl in the first quarter of 2008.  The decrease in first quarter oil prices was consistent with the movement in benchmark prices.

 Royalties

		Three months ended March 31,
		2009			2008		% Change
Royalties	$	2,027,510		$	2,258,201		(10	%)
% of Sales		21	%		22	%
Per boe	$	6.51		$	11.49		(43	%)

Royalties, which include severance taxes, in the first quarter of 2009 was $2.0 million or 21% of revenue, compared to $2.3 million or 22% of revenue in the first quarter of 2008.  The decrease in average royalty rate was primarily the result of the Company receiving a rebate of severance taxes on all of its production from horizontal wells in Oklahoma.  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.

Operating and Transportation Expenses

Three months ended March 31,
2009	2008	% Change

Operating expenses	$	3,577,046	$	1,706,553	110	%
Per boe	$	11.48	$	8.69	32	%
Transportation costs	$	-	$	18,741	(100	%)
Per boe	$	-	$	0.60	(100	%)

Operating expenses per boe increased by 32% to $11.48 per boe in the first quarter of 2009 from $8.69 in the first quarter of 2008.  Total operating expenses in the first quarter of 2009 were $3.6 million, up 110% from $1.7 million in the first quarter of 2008.  The increase in operating expense in the first quarter of 2009 is due to overall higher costs including well servicing expenses, minor workovers, equipment and supplies as compared to the first quarter of 2008.

5

Transportation expenses for the first quarter of 2009 were $0.00 per boe compared to $0.60 per boe for the first quarter in 2008.   This was primarily due to the sale of the New Mexico property on May 22, 2008.

General and Administrative Expenses (G&A)

	Three months ended March 31,
	2009		2008		% of Change
General and administrative	$	2,146,441	$	1,199,928		79	%
Per boe	$	6.89	$	6.11		13	%

G&A expenses for the first quarter of 20009 increased by 13% on a per boe basis to $6.89 from $6.11 per boe in the first quarter of 2008.  The increase on a per boe basis resulted primarily from an increase in staffing levels, investor relations, higher insurance expenses and legal fees which were partially offset by an increase in production in 2009 as compared to 2008.

Interest Expense

	Three months ended March 31,
	2009			2008			% of Change
Interest expense and financing expense	$	1,974,160		$	1,574,018			25	%
Average interest rate		5.72	%		9.12	%		(37	%)
Per boe	$	6.34		$	8.01			(21	%)

Interest expense in the first quarter of 2009 was $2.0 million or $6.34 per boe as compared to $1.6 million or $8.01 per boe in the first quarter of 2008.  Petroflow’s average interest rate for the first quarter of 2009 was approximately 5.72%.  The decrease in interest expense resulted from an increase in debt levels which was more than offset by a decrease in interest rates from the same period in 2008.

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.  The interest rates charged by the banks are LIBOR plus 2% to LIBOR plus 4% for the first quarter of 2009.  The annual interest rate charged on the capital leases is 12%.

Netbacks

	Three months ended March 31,
	2009			2008			% of Change
($/boe)
Oil and natural gas sales	$	30.73		$	52.02			(41	%)
Realized gain (loss)		4.65			(0.40	)		(12.72	)
Royalties		(6.51	)		(11.49	)		(43	%)
Operating costs		(11.48	)		(8.69	)		32	%
Transportation costs		-			(0.60	)		(100	%)
Operating netbacks	$	17.39		$	30.84			(44	%)
G&A	$	(6.89	)	$	(6.11	)		13	%
Interest		(6.34	)		(8.01	)		(21	%)
Corporate netback	$	4.16		$	16.72			(75	%)

6

Petroflow’s operating netback per boe (defined as revenue including realized gain on commodity contracts per boe less royalties, operating and transportation expenses on a per boe basis) was $17.39 in the first quarter of 2009, a 44% decrease from $30.84 in the first quarter of 2008.  The decrease in operating netback was primarily due to a 41% decrease in revenue per boe and a 32% increase in operating expenses per boe, offset by a 43% decrease in royalties per boe and a 100% decrease in transportation expenses per boe in the first quarter of 2009, as compared to the corresponding period in 2008.  The increase in per unit operating expenses in the first quarter of 2009 was primarily the result of an extensive work over program implemented in the Oklahoma properties which we expect to have a positive impact on production for an extended period of time.

The Company’s corporate netback per boe (defined as operating netback per boe less G&A expense per boe), was $4.16 in the first quarter of 2009, a 75% decrease as compared to $16.72 in the first quarter of 2008.  The decrease in corporate netback was impacted by a reduction of interest expense per boe and an increase of G&A expense per boe.

Funds from operations and cash flow from operations

	Three months ended March 31,
	2009		2008		% of Change
Funds from operations	$	1,293,023	$	3,317,143		(61	%)
Per share - basic and diluted	$	0.04	$	0.11		(62	%)
Per boe	$	4.15	$	16.88		(75	%)

Funds from operations decreased by 61% in the first quarter of 2009 to $1.3 million from $3.3 million in the first quarter of 2008.  On a per share basis (basic and diluted) funds from operations decreased by 62% to $0.04 from $0.11 in the corresponding period of 2008.  Funds from operations decreased by 75% on a per boe basis to $4.15 in the first quarter of 2009 from $16.88 in the first quarter of 2008, primarily as a result of a decrease in revenue per boe, and an increase in operating costs per boe, which is offset partially by a decrease in royalties and transportation expense per boe.

Cash flow from operations differs from funds from operations due to the inclusion of changes in non-cash working capital.  Cash flow used in operations for the first quarter of 2009 was $10.9 million as compared to $890,000 in the first quarter of 2008.  Included in cash flow used in operations is an increase in non-cash working capital of $12.2 million for the first quarter of 2009 and an increase of $2.4 million for the corresponding period of 2008.

Stock Based Compensation

	Three months ended March 31,
	2009		2008		% of Change
Stock-based compensation	$	357,459	$	291,454		23	%
Per boe	$	1.15	$	1.48		(23	%)

The Company recognized stock-based compensation expense of $357,000 on its stock options in the first quarter of 2009, calculated using the Black-Scholes option pricing model.�� Compensation expense is recognized on a straight-line basis over the vesting period.  During the first quarter of 2009, Petroflow granted 60,000 stock options at a weighted average exercise price of $1.34 while 76,400 stock options were cancelled at a weighted average price of $2.75.  The following assumptions were used to calculate stock-based compensation for the three months period ended March 31, 2009; zero dividend yield; expected volatility of 134%; risk free rate of 1.07%; and expected life of 2 - 5 years.

7

Depletion, Depreciation and Accretion (DD&A)

	Three months ended March 31,
	2009		2008		% of Change
Depletion and depreciation	$	3,408,908	$	2,188,125		56	%
Accretion on asset retirement obligation		29,147		15,337		90	%
	$	3,438,055	$	2,203,462		57	%
Per boe	$	11.04	$	11.22		(2	%)

Depletion and depreciation are calculated based upon capital expenditures, production rates and reserves.  The Company uses the asset retirement obligation method to record the present value of estimated cleanup and restoration costs for all of its facilities, including well sites and pipelines.  The liability amount is increased each reporting period due to the passage of time, and the amount of accretion is charged to earnings in the period.  Excluded from the Company’s depletion and depreciation calculation are costs associated with unproven properties of $1.4 million.  Future development costs for proved reserves of $61.9 million have been included in the depletion calculation.

The Company recorded $3.4 million or $11.04 per boe in DD&A expense in the first quarter of 2009, a decrease of 2% as compared to $11.22 per boe in DD&A expense in the first quarter of 2008.  This DD&A calculation is based on production volumes of 311,536 boes in the quarter.  The decrease in per boe DD&A for the three month period ended March 31, 2009 reflects a decrease in future development capital, as compared to the same period in 2008.

Income Taxes

	Three months ended March 31,
	2009		2008		% of Change
Future income tax expense	$	805,499	$	–		100	%
Per boe	$	2.59	$	–		100	%

A net future tax liability of approximately $1.2 million has been recognized in the financial statements for the first quarter of 2009, an increase of $806,000 from the year ended 2008.  All of which related to the Company’s wholly owned subsidiary North American Petroleum Corporation USA (“NAPCUS”).   During the first quarter of 2009, the Company did not recognize a current income tax expense.  A valuation allowance was applied to fully offset the income tax assets at March 31, 2008.

Net Loss

	Three months ended March 31,
	2009			2008			% of Change
Net loss	$	(17,822	)	$	(2,158,880	)		99	%
Per share - basic and diluted	$	(0.00	)	$	(0.07	)		100	%
Per boe	$	(0.06	)	$	(11.11	)		74	%

The Company recorded an $18,000 net loss in the first quarter of 2009 ($0.00 per share - basic and diluted) compared to a net loss of $2.2 million ($0.07 per share - basic and diluted) in the same period of 2008.  The decrease in commodity prices in the first quarter of 2009 more than offset increases in production in the first quarter of 2009 as compared to the same period of 2008.  The decrease in revenue, increases in operating costs and DD&A offset by the decrease in royalty expense were a large contributor to the net loss.

8

SUMMARY OF QUARTERLY RESULTS

	2009			2008				2007
	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Oil and gas sales	$ 9,572	$12,485	$16,618	$15,392	$10,220	$ 6,361	$5,753	$5,965
Funds from operations	1,293	730	6,023	2,579	3,317	(1,092)	510	1,491
Per share - Basic	0.04	0.02	0.19	0.09	0.12	(0.04)	0.02	0.06
Per share - Diluted	0.04	0.02	0.18	0.09	0.12	(0.04)	0.02	0.06
Net income (loss)	(18)	3,302	12,031	(8,884)	(2,159)	(3,792)	(1,271)	74
Per share - Basic	(0.00)	0.11	0.41	(0.30)	(0.07)	(0.14)	(0.05)	0.00
Per share - Diluted	(0.00)	0.10	0.39	(0.30)	(0.07)	(0.00)	(0.05)	0.00
Total assets	207,318	195,110	137,143	111,147	120,764	103,029	88,923	82,686
Working capital
(deficiency)	(21,284)	(26,222)	(12,778)	(15,151)	(20,223)	(17,147)	(53,021)	(53,947)

(1) Working capital excludes derivative contracts

CAPITAL EXPENDITURES

	Three months ended March 31,
	2009	2008	% of Change
Land and rentals	$      380,497	$    170,984	(123%)
Drilling and completions	8,368,862	9,211,646	(9%)
Equipment and facilities	3,250,954	3,828,485	(15%)
Other assets	20,350	65,063	(69%)
	12,020,663	13,276,178	(9%)
Assets under capital lease	3,135,291	1,975,015	59%
Total	$ 15,155,954	$15,251,193	(1%)

Maintaining financial and operational flexibility remains a key element in Petroflow’s business model.  Petroflow’s capital program in the first quarter of 2009 was reduced to align with the depressed economic and commodity price environment.  In the first quarter of 2009, the Company invested $15.2 million, which is consistent with the $15.3 million spent in the first quarter of 2008.

Petroflow had focused its first quarter capital expenditures in Oklahoma.  Petroflow invested $8.2 million on drilling and completion, $3.3 million on facilities and equipment, $401,000 on land, lease and other assets and $3.1 million on assets under capital leases.  The Company drilled one salt water disposal well and one natural gas well in the first quarter of 2009 and put the natural gas well and 6 wells drilled in the fourth quarter of 2008 on stream.

The capital expenditures relating to assets under capital leases relate to a contract the Company entered during 2006 as part of its farm-in agreement.  The leased assets consist of four salt water disposal wells drilled in Oklahoma as well as infrastructure for all the wells.  The lease bears interest at 12% and resulted in the capitalization of $3.2 million of additional expenditures for the first quarter of 2009.

9

LIQUIDITY AND CAPITAL RESOURCES

At March 31, 2009, the Company had drawn $124.1 million ($US 99.3 million) on its credit facility and had a working capital deficiency (excluding derivative contracts) of $21.3 million.  No portion of the bank debt is due within the next twelve months.  The Company’s ratio of net debt to annualized funds from operations, before deducting interest expense, which is based on NAPCUS’s financial statements, was 5.47 times.  This is within debt covenants established under NAPCUS’s banking facility which must not exceed 5.50.  The Company was in compliance with all of its financial covenants as at March 31, 2009.

At March 31, 2009, the Company had a US $200 million revolving credit facility in place with a US based banking syndicate. 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 had a maturity date of January 1, 2012 with a borrowing base of $US 102 million.  The “B” tranche matures on January 1, 2010, and had a borrowing base of $US 8 million.

Subsequent to March 31, 2009, the Company entered into an amended credit facility agreement (the “Amended Facility”).  The Amended Facility is US $200 million revolving credit facility with a US based banking syndicate. This facility is dependent upon continued yearly reserve additions, with current availability of US $110 million which is all included in Tranche “A”.  Tranche “B” which formerly had a limit of US $8 million has been retired.  There is an interest rate floor on the Amended Facility of 5.5%.

The current economic slowdown, reduced availability of credit, and challenging equity markets have resulted in Petroflow suspending its drilling efforts for a short time and setting its objectives for 2009 to operating within forecasted funds from operations.See “Nature of Operations and Ability to Continue as a Going Concern”, in the notes to the financial statements for the three month period ended March 31, 2009.

SHARE CAPITAL AND OPTION ACTIVITY

	As at May 27,		As at March 31,
	2009		2009		2008
Common Shares		29,514,494		29,532,594		29,242,344
Warrants		1,692,000		1,692,000		1,692,000
Stock Options		2,882,200		2,882,200		2,526,200

Petroflow has received regulatory approval under Canadian securities laws to purchase Common Shares under a Normal Course Issuer Bid.  The Company is entitled to purchase, for cancellation, up to 1,829 common shares per day on or before March 31, 2009 and 1000 common shares per day thereafter which commenced on February 6, 2009 and terminates on February 5, 2010.

At March 31, 2009, the Company had 29,532,594 common shares and 2,882,200 options outstanding.  During the first quarter of 2009, the Company granted 60,000 stock options at a weighted average exercise price of $1.34 while 76,500 options were cancelled at a weighted average price of $2.75.

As of May 25, 2009, the Company has 29,514,494 Common Shares; 1,692,000 warrants and 2,882,200 options outstanding.

10

CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES

The Company is committed to the following payments under its operating leases for office space:

2009	$	232,338
2010		230,956
2011		80,231
2012		81,086
2013		34,040
	$	658,651

In April 2007, the Company signed a drilling rig contract with a service provider at a rate of U.S. $22,000 per day for three years.  Subsequent to year end this drilling rig was returned to the service provider.  The Company has not currently received formal termination of the contract from the service provider; however, it is Management’s belief through discussions with the service provider that the contract has been terminated with no further commitment.

OFF-BALANCE SHEET ARRANGEMENTS

Petroflow was not involved in any off-balance sheet transactions during the quarter ended March 31, 2009.

RELATED PARTY TRANSACTIONS

As at March 31, 2009, $1,145 (December 31, 2008 - $14,169) was due to Macon Oil & Gas Corp. (“MOG”), a wholly owned subsidiary of Macon, as operator of one of the Company’s producing properties. Additionally, $195,000 is owed by the Company to MOG (December 31, 2008 - $195,000) 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 three months ended March 31, 2009, legal fees totalling $83,154 (March 31, 2008 - $150,477) were charged to the Company by the Company’s legal counsel where a director of the Company is a partner in the law firm.

As at March 31, 2009 $40,760 (December 31, 2008, $470,223) was due to the Company by a joint interest partner in which a director of the Company has an interest.

For the three months ended March 31, 2009, $51,217 (March 31, 2008 - $38,525) was charged to the Company by a director of the Company for services rendered.

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

FINANCIAL INSTRUMENTS

Derivative contracts are recorded at fair value based on an estimate of the amounts that would have been received or paid to settle these instruments prior to maturity given future market prices and other relevant factors.  The actual amounts received or paid to settle these instruments at maturity could differ significantly from those estimated.

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The following table indicated the realized and unrealized losses on commodity contracts for the quarter ended March 31, 2009 and 2008:

	Three months ended March 31,
	2009			2008			% Change
Unrealized gain (loss)
Natural gas	$	3,661,449		$	(2,705,483	)		235	%
Oil		(371,281	)		(275,639	)		(35	%)
		3,290,168			(2,981,107	)		210	%
Realized gain (loss)
Natural gas	$	2,494,855			106,919			1,767	%
Oil		7,539,940			(172,470	)		426	%
		3,248,795			(77,988	)		3,434	%
Cost of contracts and other		(1,799,299	)		-			(100	%)
	$	1,449,496		$	(77,988	)		1,959	%

The following table outlines the details of the Company’s natural gas derivative contracts:

Natural Gas	Volume per day (mmbtu)	Swap Price	Call Price	Put Price
		(US$)	(US$)	(US$)
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 - March 31, 2009	1,000		-	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 - December 31, 2009	1,500		-	6.50
November 1, 2009 - December 31, 2009	2,500	5.52	-	-
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

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Subsequent to the first quarter of 2009, the Company entered into natural gas contracts with the following terms:
Natural Gas	Volume per day (mmbtu)	Swap Price	Call Price	Put Price
		(US$)	(US$)	(US$)
April 1, 2009 - September 30, 2009	1,000		-	7.00
June 1, 2009 - October 31, 2009	2,000	3.53	-	-
September 1, 2009 - September 30, 2010	1,500		-	5.25
October 1, 2009 - December 31, 2009	1,000		-	7.00
January 1, 2010 - March 31, 2010	2,500	5.52	-	-
January 1, 2010 - November 30, 2010	1,500		None	6.50
April 1, 2010 -October 31, 2010	2,500		6.25	5.00
November 1, 2010 - March 31, 2011	750		-	6.25
November 1, 2010 - March 31, 2011	750		8.60	6.25
November 1, 2010 - March 31, 2011	3,000		-	6.00
January 1, 2011 - March 31, 2011	2,500		-	6.25

The following table outlines the details of the Company’s oil derivative contracts:
Crude Oil	Volume per day (bbls)	Call Price	Put Price
		(US$)	(US$)
January 1, 2008 - March 31, 2009	75	72.80	65.00
January 1, 2009 - December 31, 2009	75	100.50	75.00
January 1, 2009 - December 31, 2009	100	89.70	70.00

Subsequent to the first quarter of 2009, the Company entered into oil contracts with the following terms:

Crude Oil	Volume per day (bbls)	Call Price	Put Price
		(US$)	(US$)
May 1, 2009 - August 31, 2009	150	70.50	40.00
September 1, 2009 - March 31, 2011	100	-	47.50
January 1, 2010 - December 31, 2010	100	78.70	65.00

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NEW ACCOUNTING POLICIES

On February 13, 2008, the Accounting Standards Board (“AcSB”) of the Canadian Institute of Chartered Accountants confirmed that Canadian publicly accountable enterprises are required to adopt International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”), effective January 1, 2011. In June 2008, the Canadian Securities Administrators (“CSA”) proposed that Canadian public companies which are also Securities and Exchange Commission (“SEC”) registrants, such as Petroflow, could retain the option, currently available to them, to prepare their financial statements under US GAAP instead of IFRS. In November 2008, the SEC published for comment a proposed roadmap that could result in US issuers being required to adopt IFRS, on a phased in approach based on market capitalization, starting in 2014.

We are assessing IFRS accounting policies, including those that provide policy options, in comparison with accounting policies under US GAAP. We are developing an approach to be taken to embed the change in GAAP in our accounting processes and systems. In addition, Petroflow is developing the accounting system change requirements that will be implemented on adoption of either IFRS or US GAAP.

We are closely monitoring regulatory developments made by the CSA and the SEC and developments in accounting made by the AcSB, FASB and the IASB that may affect the timing, nature or disclosure of our adoption of IFRS or US GAAP. Assessment of these developments together with our assessment of the impact on our financial statements of changes in accounting policies will determine whether Petroflow adopts IFRS or US GAAP as the basis of its future public financial reporting.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The Chief Executive Officer ("CEO") and the Chief Financial Officer ("CFO") are filing Form 52-109F2 - Certification of Interim Filings Following a Initial Public Offering, Reverse Takeover or Becoming a Non-Venture Issuer  ("Certificate") for the Company's first interim period since becoming a non-venture issuer.  This is an alternative form of Certificate to the usual certificate required for non-venture issuers and does not include representations relating to the establishment and maintenance of disclosure controls and procedures and internal control over financial reporting as defined in NI 52-109.  However, the CEO and CFO are responsible for ensuring that processes are in place to provide them with sufficient knowledge to support the representations they are making in the Certificate.

RISK MANAGEMENT

Additional risk factors can be found under “Risk Factors” in the Company’s 2008 Annual Information Form and 2008 Annual Report which can be found on www.sedar.com.  The risks discussed should not be construed as exhaustive.  There are numerous factors, both known and unknown, that could cause actual results or events to differ materially from forecast results.

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