Exhibit 99.2
Third Quarter Report for the period ended September 30, 2009
TSX: PEF
FINANCIAL AND OPERATING SUMMARY
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| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | |
| Financials | | | | | | | | | | | | | | | | | | |
| Oil Sales ($) | | | 1,638,145 | | | | 5,538,025 | | | | (70 | %) | | | 5,793,817 | | | | 13,005,919 | | | | (55 | %) |
| Natural gas and NGL sales ($) | | | 7,389,492 | | | | 11,079,893 | | | | (33 | %) | | | 21,728,459 | | | | 29,224,420 | | | | (26 | %) |
| Total oil, natural gas and NGL Sales ($) | | | 9,027,637 | | | | 16,617,918 | | | | (46 | %) | | | 27,522,276 | | | | 42,230,339 | | | | (35 | %) |
Funds (used in) from operations ($)(1) | | | (1,367,678 | ) | | | 6,023,007 | | | | (123 | %) | | | 4,476,710 | | | | 11,918,914 | | | | (62 | %) |
Per share basic ($) | | | (0.05 | ) | | | 0.20 | | | | (123 | %) | | | 0.15 | | | | 0.41 | | | | (63 | %) |
Per share diluted ($) | | | (0.05 | ) | | | 0.19 | | | | (124 | %) | | | 0.15 | | | | 0.39 | | | | (63 | %) |
| Net income (loss) ($) | | | (8,705,716 | ) | | | 12,031,390 | | | | (172 | %) | | | (17,296,096 | ) | | | 988,012 | | | | (1,851 | %) |
Per share basic ($) | | | (0.30 | ) | | | 0.41 | | | | (172 | %) | | | (0.59 | ) | | | 0.03 | | | | (2,067 | %) |
Per share diluted ($) | | | (0.30 | ) | | | 0.39 | | | | (177 | %) | | | (0.59 | ) | | | 0.03 | | | | (2,067 | %) |
Capital expenditures ($)(2) | | | 248,779 | | | | 22,338,329 | | | | (99 | %) | | | 14,392,092 | | | | 57,629,136 | | | | (75 | %) |
Net debt (as at September 30)(3) | | | 136,395,182 | | | | 78,729,439 | | | | 73 | % | | | 136,395,182 | | | | 78,729,439 | | | | 73 | % |
| Operating Highlights | | | | | | | | | | | | | | | | | | | | | | | | |
| Production: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil (bbls per day) | | | 302 | | | | 504 | | | | (40 | %) | | | 369 | | | | 415 | | | | (11 | %) |
Natural gas and | | | | | | | | | | | | | | | | | | | | | | | | |
NGL (mcfe per day) | | | 23,328 | | | | 13,396 | | | | 74 | % | | | 21,604 | | | | 12,212 | | | | 77 | % |
Total (boe per day) (6:1) | | | 4,190 | | | | 2,737 | | | | 53 | % | | | 3,970 | | | | 2,451 | | | | 62 | % |
| Average realized price: | | | | | | | | | | | | | | | | | | | | | | | | |
Oil ($ per bbl) | | | 58.92 | | | | 119.39 | | | | (51 | %) | | | 57.49 | | | | 114.74 | | | | (50 | %) |
Natural gas and NGL ($ per mcfe) | | | 3.44 | | | | 8.99 | | | | (62 | %) | | | 3.68 | | | | 8.77 | | | | (58 | %) |
Realized gain (loss) on commodity contracts ($ per boe) | | | 1.20 | | | | (2.16 | ) | | | 156 | % | | | 8.91 | | | | (2.34 | ) | | | 481 | % |
Combined average ($ per boe) | | | 24.62 | | | | 63.84 | | | | (61 | %) | | | 34.31 | | | | 60.79 | | | | (44 | %) |
| Netback ($ per boe) | | | | | | | | | | | | | | | | | | | | | | | | |
Oil, natural gas and NGL sales | | | 23.42 | | | | 66.00 | | | | (65 | %) | | | 25.40 | | | | 63.12 | | | | (60 | %) |
Realized gain (loss) on commodity contracts | | | 1.20 | | | | (2.16 | ) | | | 156 | % | | | 8.91 | | | | (2.34 | ) | | | (481 | %) |
Royalties | | | 4.65 | | | | 13.93 | | | | (67 | %) | | | 5.43 | | | | 13.54 | | | | (60 | %) |
Operating expenses | | | 9.35 | | | | 11.50 | | | | (19 | %) | | | 11.10 | | | | 10.75 | | | | 3 | % |
Transportation expenses | | | - | | | | - | | | | 0 | % | | | - | | | | 0.30 | | | | (100 | %) |
| Operating netback | | | 10.62 | | | | 38.40 | | | | (72 | %) | | | 17.79 | | | | 36.20 | | | | (51 | %) |
| G&A expense | | | 7.62 | | | | 11.26 | | | | (32 | %) | | | 6.78 | | | | 10.63 | | | | (36 | %) |
| Provision for doubtful receivables | | | 0.52 | | | | 0.06 | | | | 747 | % | | | 0.18 | | | | 2.13 | | | | (91 | %) |
| Interest expense | | | 6.03 | | | | 6.08 | | | | (1 | %) | | | 6.70 | | | | 6.78 | | | | (1 | %) |
| Corporate netback | | | (3.55 | ) | | | 21.01 | | | | (117 | %) | | | 4.12 | | | | 16.66 | | | | (75 | %) |
| Common shares | | | | | | | | | | | | | | | | | | | | | | | | |
| Common shares outstanding, end of period | | | 29,549,894 | | | | 29,567,394 | | | | (0.1 | %) | | | 29,549,894 | | | | 29,567,394 | | | | (0.1 | %) |
| Weighted average basic shares outstanding | | | 29,510,329 | | | | 29,430,383 | | | | 0.27 | % | | | 29,530,597 | | | | 29,342,529 | | | | 0.64 | % |
| (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. |
| (2) | Includes non-cash capital expenditures through leases. |
| (3) | Net debt is total of bank loan, obligation under capital lease less working capital (excluding derivative contract). |
OVERVIEW AND HIGHLIGHTS
In these challenging times in the oil and gas industry, maximizing the value of assets and using them as a foundation for future growth remains a key element in Petroflow’s business model.
Petroflow’s average sales production rate grew to 4,190 boe per day, a 53% increase over the third quarter of 2008 average sales production of 2,737 boe per day.
Mainly as a consequence of low commodity prices, funds from operations decreased by 123% in the third quarter of 2009 to ($1.4 million) from $6.0 million in the third quarter of 2008. This resulted in a decrease of 123% to ($0.05) per share basic and 124% to ($0.05) per share diluted in the third quarter of 2009 from $0.20 and $0.19 respectively in the same period of 2008.
The Company recorded an $8.7 million net loss in the third quarter of 2009 (($0.30) per share - basic and diluted) compared to a net income of $12.0 million ($0.41 per share basic and $0.39 per share diluted) in the same period of 2008. Production increases in the third quarter of 2009 were more than offset by the decrease in commodity prices and an unrealized loss in commodity contracts.
A 61% reduction in revenue per boe was a large contributor to the 72% 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 per boe) which averaged $10.62 per boe in the third quarter of 2009. The Company’s corporate netback (defined as operating netback per boe less G&A and interest expense per boe) was a loss of $3.55 per boe for the quarter.
Operating costs decreased 19% to $9.35 per boe in the third quarter of 2009 as compared to $11.50 in the third quarter of 2008 and $12.53 per boe in the second quarter of 2009. The decrease is due to production levels increasing at a greater rate than costs.
Effective September 30, 2009 the Company entered into an amended credit facility agreement (the “Amended Facility”). This facility is made up two tranches, “A” and “C”. The “A” tranche has a maturity date of January 1, 2012 with a borrowing base of US$100 million. There is an interest rate floor on tranche A of 5.5%. The “C” tranche matures on September 30, 2010, has a borrowing base of US$10 million, and an interest rate floor of 7.5%.
The Amended Facility also requires that the Company raise an additional US$18 million on or before December 17, 2009 to reduce the aggregate outstanding indebtedness.
As at September 30, 2009 the Company was not in compliance with its debt covenants. As a result the bank loan has been reclassified to a current liability.
The Company entered into a swap contract with respect to 6800 MMBTU per day of gas production for the period from October 1, 2009 to September 30, 2012. The swap contract covers over 25% of the Company’s current working interest production levels and provides Petroflow with stabilized prices for those volumes. Combined with existing derivative contracts, the Company has downside price protection on over 40% of its current working interest production for the next two years.
The Company’s ability to continue as a going concern will be dependent on various factors, including the continuing support of its bank and other creditors, securing ongoing debt and equity financing, the generation of profitable operating results and or the sale of a portion of its property and equipment assets. While the Company is focusing its efforts on these matters, there is significant uncertainty that these initiatives will be successful, which would make the use of accounting principles applicable to a going concern inappropriate.
The on-going global economic and financial crisis has resulted in reduced liquidity in financial markets, restricted access to financing, demand destruction for commodities, and lower pricing. These factors impacted the Company in the third quarter of 2009 and are expected to impact the performance of the Company 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.
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 and nine months ended September 30, 2009 and is provided by management as of November 10, 2009. 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, 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”, “expect”, “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.
This Management Discussion & Analysis (“MD&A”) contains statements concerning anticipated: (i) production weighting for 2009, (ii) exploration and development activities, (iii) capital expenditures for 2009, (iv) sources of funding for future capital requirements, (v) amounts received or paid to settle financial instruments currently entered into upon maturity, and (vi) changes to accounting policies.
The forward-looking statements are based on certain key expectations and assumptions made by Petroflow, including expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expense, cash flow and capital expenditures and the application of regulatory regimes.
Although Petroflow believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risk in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections related to production, costs and expenses, and health, safety and environmental risk), commodity price and exchange rate fluctuations and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Certain of the risks are set out in more detail in this MD&A and in the Company’s AIF which has been filed on SEDAR and can be accessed at www.sedar.com.
The forward-looking statements contained in this MD&A are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
All amounts are expressed in Canadian dollars unless otherwise noted. Oil, natural gas and natural gas liquids reserves and volumes are converted to a common unit of measure, referred to as a barrel of oil equivalent (boe), on the basis of 6,000 cubic feet of natural gas being equal to 1 barrel of oil. This conversion ratio is based on an energy equivalency at the wellhead. It should be noted that the use of boe might be misleading, particularly if used in isolation. The term boe per day (boe/d) has been used throughout this MD&A.
The terms “funds from operations”, “funds from operations per share”, “net debt” and “netback” used in this discussion are not recognized measures under Canadian generally accepted accounting principles (GAAP). Management believes that in addition to net earnings, funds from operations, net debt and netback are useful supplemental measures as they provide an indication of the results generated by the Company’s principal business activities before the consideration of how those activities are financed or how the results are taxed. Investors are cautioned, however that these measures should not be construed as alternatives to net earnings determined in accordance with GAAP, as an indication of the Company’s performance.
The Company’s method of calculating funds from operations may differ from that of other companies, and, accordingly, may not be comparable to measures used by other companies. The Company determines funds from operations as cash flow from operating activities before changes in non-cash working capital as follows:
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| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Funds (used in) from operations | | $ | (1,367,678 | ) | | $ | 6,023,007 | | | | (123 | %) | | $ | 4,476,710 | | | $ | 11,918,914 | | | | (62 | %) |
| Changes in non-cash working capital items | | | 1,977,866 | | | | 1,350,318 | | | | 46 | % | | | 4,772,117 | | | | (7,050,416 | ) | | | 168 | % |
| Cash (used in) provided by operating activities | | $ | 610,188 | | | $ | 7,373,325 | | | | (92 | %) | | $ | 9,248,827 | | | $ | 4,868,498 | | | | 90 | % |
RESULTS OF OPERATIONS
Production volumes
| | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Daily Sales Volumes | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil (bbls/day) | | | 302 | | | | 388 | | | | 419 | | | | 494 | | | | 504 | | | | 412 | | | | 332 | | | | 255 | |
| Natural gas & natural gas liquids (mcf/day) | | | 23,328 | | | | 23,173 | | | | 18,255 | | | | 16,240 | | | | 13,396 | | | | 12,086 | | | | 10,960 | | | | 8,679 | |
| Total (boe/day) | | | 4,190 | | | | 4,250 | | | | 3,462 | | | | 3,201 | | | | 2,737 | | | | 2,426 | | | | 2,159 | | | | 1,702 | |
Petroflow’s average sales production rate was 4,190 boe per day, a 53% increase over the third quarter of 2008 average sales production of 2,737 boe per day. This growth occurred even though the Company has had no drilling activity since the first quarter of 2009. The increase is partially due to a changeover in the Company’s natural gas sales contracts, wherein it is now being paid for processed natural gas liquids. However, in addition, the average production per well has increased approximately 11% from December 2008 to September 2009. Petroflow’s average for the first nine months of 2009 was 3,970 boe per day, a 62% increase over the first nine months of 2008 average sales production of 2,451 boe per day. The growth in the first nine months of 2009 compared to the same period in 2008 continues to be primarily the result of the successful drilling program in Oklahoma.
| Revenue and realized prices |
| | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil | | $ | 1,638,145 | | | $ | 5,538,025 | | | | (70 | %) | | $ | 5,793,817 | | | $ | 13,005,919 | | | | (55 | %) |
| Natural gas and NGLs | | | 7,389,492 | | | | 11,079,893 | | | | (33 | %) | | | 21,728,459 | | | | 29,224,420 | | | | (26 | %) |
| Total oil, natural gas and NGL revenues | | $ | 9,027,637 | | | $ | 16,617,918 | | | | (46 | %) | | $ | 27,522,276 | | | $ | 42,230,339 | | | | (35 | %) |
| Crude oil ($/bbl) | | $ | 58.92 | | | $ | 119.39 | | | | (51 | %) | | $ | 57.49 | | | $ | 114.74 | | | | (50 | %) |
| Natural gas & NGL ($/mcf) | | | 3.44 | | | | 8.99 | | | | (62 | %) | | | 3.68 | | | | 8.77 | | | | (58 | %) |
| Total oil, natural gas and NGL revenue (per boe) | | | 23.42 | | | | 66.00 | | | | (65 | %) | | | 25.40 | | | | 63.12 | | | | (60 | %) |
| Realized gain (loss) on commodity contracts | | | 1.20 | | | | (2.16 | ) | | | 156 | % | | | 8.91 | | | | (2.34 | ) | | | 481 | % |
| Realized revenue ( per boe) | | | 24.62 | | | | 63.84 | | | | (61 | %) | | | 34.31 | | | | 60.78 | | | | (44 | %) |
| Unrealized gain (loss) on commodity contracts | | | (9.18 | ) | | | 44.86 | | | | (120 | %) | | | (9.76 | ) | | | 0.78 | | | | (1,356 | %) |
| Total oil, natural gas and NGL revenue after commodity contracts (per boe) | | $ | 15.44 | | | $ | 108.70 | | | | (86 | %) | | $ | 24.55 | | | $ | 61.55 | | | | (60 | %) |
Oil, natural gas and natural gas liquids and commodity contracts, other revenues
A 53% increase in production combined with a 65% decrease in average revenue per boe for the third quarter of 2009 resulted in revenues of $9.0 million, decreasing from $16.6 million in the third quarter of 2008.
A 62% increase in production combined with a 60% decrease in average revenue per boe over the nine months ended 2009 resulted in revenues of $27.5 million, decreasing from $42.2 million for the nine months ended 2008.
The Company had certain oil and natural gas commodity contracts in place as of September 30, 2009. The Company had an unrealized loss of $3.5 million and a realized gain of $0.5 million on its commodity contracts for the third quarter of 2009, and an unrealized loss of $10.6 million and a realized gain of $9.7 million for the nine months ended 2009. The realized gain was reduced by $2.4 million for the first nine months of 2009 due to the cost of additional puts in the first half of 2009. The strategy of purchasing puts will allow the Company to benefit from price increases in the future. Please refer to the “Financial Instruments” section of this MD&A for further details on these commodity contracts.
Prices
In the third quarter of 2009 the Company realized average revenue per boe of $24.62, a decrease of 61% from the $63.84 per boe in the third quarter of 2008. In the first nine months of 2009 the Company realized average revenue per boe of $34.31, a decrease of 44% from the $60.78 per boe in the same period in 2008.
Petroflow realized a combined natural gas and natural gas liquids price of $3.44 per mcf in the third quarter of 2009, a 62% decrease from $8.99 per mcf averaged in the third quarter of 2008. This compares to an average NYMEX reference price of US $3.39 per MMBtu in the third quarter of 2009 which is a 67% decrease from the third quarter of 2008 price of $10.24 per MMBtu. The percentage decrease in natural gas prices received by Petroflow is consistent with the decrease in the NYMEX reference price.
Petroflow realized a combined natural gas and natural gas liquids price of $3.68 per mcf in the first nine months of 2009, a 58% decrease from $8.77 per mcf averaged in the first nine months of 2008. This compares to an average NYMEX reference price of US $3.96 per MMBtu in the first nine months of 2009 and a 59% decrease from the 2008 price of $9.73 per MMBtu. The percentage decrease is consistent with the movement in benchmark prices.
The Company realized an average price of $58.92 per bbl of oil in the third quarter of 2009, a decrease of 51% from $119.39 per bbl realized in the third quarter of 2008. This compares to an average WTI price of US$66.95 per bbl in the third quarter of 2009 a 43% decrease from US $118.21 per bbl in the third quarter of 2008. The decrease in third quarter oil prices was consistent with the movement in benchmark prices.
The Company realized an average price of $57.49 per bbl of oil in the first nine months of 2009, a decrease of 50% from $114.74 per bbl realized in the first nine months of 2008. This compares to an average WTI price of US$56.86 per bbl in the third quarter of 2009 a 50% decrease from US$113.30 per bbl in the first half of 2008. The decrease in first nine months oil prices was consistent with the movement in benchmark prices.
Royalties
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| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Royalties | | $ | 1,793,662 | | | $ | 3,508,174 | | | | (49 | %) | | $ | 5,882,000 | | | $ | 9,055,499 | | | | (35 | %) |
| % of Sales | | | 20 | % | | | 21 | % | | | | | | | 21 | % | | | 21 | % | | | | |
| Per boe | | $ | 4.65 | | | $ | 13.93 | | | | (67 | %) | | $ | 5.43 | | | $ | 13.54 | | | | (60 | %) |
Royalties, which include severance taxes (net of rebates), were $1.8 million or 20% of revenue for the third quarter of 2009, compared to $3.5 million or 21% of revenue in the third quarter of 2008.
Royalties, in the first nine months of 2009 were $5.9 million or 21% of revenue, compared to $9.1 million or 21% of revenue in the first nine months of 2008.
The severance tax rebate amounts to approximately 6% of sales in Oklahoma. All horizontal wells drilled in Oklahoma and put on production prior to July 1, 2010 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
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| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating expenses | | $ | 3,603,123 | | | $ | 2,896,705 | | | | 24 | % | | $ | 12,025,456 | | | $ | 7,191,978 | | | | 67 | % |
| Per boe | | $ | 9.35 | | | $ | 11.50 | | | | (19 | %) | | $ | 11.10 | | | $ | 10.75 | | | | 3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Transportation costs | | $ | - | | | $ | - | | | | 0 | % | | $ | - | | | $ | 200,424 | | | | (100 | %) |
| Per boe | | $ | - | | | $ | - | | | | 0 | % | | $ | - | | | $ | 0.30 | | | | (100 | %) |
Operating expenses per boe decreased by 19% to $9.35 per boe in the third quarter of 2009 as compared to $12.53 per boe in the second quarter and $11.50 in the third quarter of 2008. The decrease is due to production levels increasing at a greater rate than costs. Total operating expenses in the third quarter of 2009 were $3.6 million, up 24% from $2.9 million in the third quarter of 2008. The increase in operating expenses in the third quarter of 2009 is due to a 53% increase in production.
Operating expenses per boe increased by 3% to $11.10 per boe in the first nine months of 2009 from $10.75 in the first nine months of 2008. Total operating expenses in the first nine months of 2009 were $12.0 million, up 67% from $7.2 million in the first nine months of 2008. The increase in overall operating expenses in the first nine months of 2009 as compared to 2008 is due to the increase in production, as well as operating expenses incurred in the first half of the year. Those expenses were associated with workovers designed to improve production efficiency and ultimately reduce operating expenses in the future.
Transportation expenses for the first nine months of 2009 were $0.00 per boe compared to $0.30 per boe for the first nine months in 2008. This was primarily due to the sale of the New Mexico property on May 22, 2008.
General and Administrative Expenses (G&A)
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| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| General and administrative | | $ | 2,936,008 | | | $ | 2,835,255 | | | | 4 | % | | $ | 7,346,397 | | | $ | 7,112,850 | | | | 3 | % |
| Per boe | | $ | 7.62 | | | $ | 11.26 | | | | (32 | %) | | $ | 6.78 | | | $ | 10.63 | | | | (36 | %) |
G&A expenses for the third quarter of 2009 decreased by 32% on a per boe basis to $7.62 from $11.26 per boe in the third quarter of 2008. Total G&A expenses in the third quarter of 2009 were $2.9 million, up 4% from $2.8 million in the third quarter of 2008. The increases for the three months ended September 30, 2009, is mainly the result of $0.7 million of severance paid to the Company’s former CEO and $0.3 million for compensation accrued to the directors for services rendered.
G&A expenses for the first nine months of 2009 decreased by 36% on a per boe basis to $6.78 from $10.63 per boe in the first nine months of 2008. The decrease on a per boe basis resulted primarily from increase in production in 2009 as compared to 2008.
Interest Expense
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| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest expense and financing expense | | $ | 2,324,326 | | | $ | 1,529,958 | | | | 52 | % | | $ | 7,261,532 | | | $ | 4,534,159 | | | | 60 | % |
| Average interest rate | | | 6.47 | % | | | 7.55 | % | | | (14 | %) | | | 6.73 | % | | | 7.97 | % | | | (16 | %) |
| Per boe | | $ | 6.03 | | | $ | 6.08 | | | | (1 | %) | | $ | 6.70 | | | $ | 6.78 | | | | (1 | %) |
Interest expense in the third quarter of 2009 was $2.3 million or $6.03 per boe as compared to $1.5 million or $6.08 per boe in the third quarter of 2008. Petroflow’s average interest rate for the third quarter of 2009 was 6.47%. The increase in interest expense resulted from an increase in debt levels offset by a decrease in the average interest rate compared to the same period in 2008.
Interest expense in the first nine months of 2009 was $7.3 million or $6.70 per boe as compared to $4.5 million or $6.78 per boe in the first nine months of 2008. Petroflow’s average interest rate for the first nine months of 2009 was 6.73%. The increase in interest expense primarily resulted from an increase in debt levels. The increase in expense for the first nine months of 2009 was offset by a reduction in interest rates in the first nine months of 2009 compared to 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 were LIBOR plus 2% to LIBOR plus 4% for the first quarter of 2009 and 5.5% for the third quarter of 2009. The annual interest rate charged on the capital leases is 12%.
Provision for Doubtful Receivables
| | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | |
| Provision for doubtful receivables | | $ | 200,256 | | | $ | 15,442 | | | | 1,197 | % | | $ | 200,256 | | | $ | 1,425,970 | | | | (86 | %) |
| Per boe | | $ | 0.52 | | | $ | 0.06 | | | | 747 | % | | $ | 0.18 | | | $ | 2.13 | | | | (91 | %) |
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 had 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 it’s Monitor to best manage and resolve this matter. At this time, the Company’s best estimate of the uncollectible amount of the receivable is $2,384,371 (US$2,195,351) which amount has been recorded in these financial statements.
Netbacks
| | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | |
| ($/boe) | | | | | | | | | | | | | | | | | | |
| Oil, natural gas and NGL sales | | $ | 23.42 | | | $ | 66.00 | | | | (65 | %) | | $ | 25.40 | | | $ | 63.12 | | | | (60 | %) |
| Realized gain (loss) on derivative contracts | | | 1.20 | | | | (2.16 | ) | | | 156 | % | | | 8.91 | | | | (2.34 | ) | | | 481 | % |
| Royalties | | | 4.65 | | | | 13.93 | | | | (67 | %) | | | 5.43 | | | | 13.54 | | | | (60 | %) |
| Operating costs | | | 9.35 | | | | 11.50 | | | | (19 | %) | | | 11.10 | | | | 10.75 | | | | 3 | % |
| Transportation costs | | | - | | | | - | | | | 0 | % | | | - | | | | 0.30 | | | | (100 | %) |
| Operating netbacks | | $ | 10.62 | | | $ | 38.40 | | | | (72 | %) | | $ | 17.79 | | | $ | 36.20 | | | | (51 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| G&A | | $ | 7.62 | | | $ | 11.26 | | | | (32 | %) | | $ | 6.78 | | | $ | 10.63 | | | | (36 | %) |
| Provision for doubtful receivables | | | 0.52 | | | | 0.06 | | | | 747 | % | | | 0.18 | | | | 2.13 | | | | (91 | %) |
| Interest | | | 6.03 | | | | 6.08 | | | | (1 | %) | | | 6.70 | | | | 6.78 | | | | (1 | %) |
| Corporate netback | | $ | (3.55 | ) | | $ | 21.01 | | | | (117 | %) | | $ | 4.12 | | | $ | 16.66 | | | | (75 | %) |
Funds from operations
| | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Funds (used in) from operations | | $ | (1,367,678 | ) | | $ | 6,023,007 | | | | (123 | %) | | $ | 4,476,710 | | | $ | 11,918,914 | | | | (62 | %) |
| Per share - basic | | | (0.05 | ) | | | 0.20 | | | | (123 | %) | | | 0.15 | | | | 0.41 | | | | (63 | %) |
| Per share - diluted | | | (0.05 | ) | | | 0.19 | | | | (126 | %) | | | 0.15 | | | | 0.39 | | | | (61 | %) |
| Per boe | | $ | (3.55 | ) | | $ | 23.92 | | | | (115 | %) | | $ | 4.12 | | | $ | 17.82 | | | | | (77%) |
Funds from operations decreased by 123% in the third quarter of 2009 to ($1.4 million) from $6.0 million in the third quarter of 2008. On a per share basis (basic and diluted) funds from operations decreased to ($0.05) compared to the corresponding period of 2008 of $0.20 and $0.19 respectively. Funds from operations decreased by 115% on a per boe basis to ($3.55) in the third quarter of 2009 from $23.92 in the third quarter of 2008, primarily as a result of a decrease in revenue per boe, offset by the increase in realized gain of derivative instruments and decrease in royalties and operating expense per boe.
Funds from operations decreased by 62% in the first nine months of 2009 to $4.5 million from $11.9 million in the first nine months of 2008. On a per share basis (basic and diluted) funds from operations decreased to $0.15 from $0.41 and $0.39, respectively in the corresponding period of 2008. Funds from operations decreased by 77% on a per boe basis to $4.12 in the first nine months of 2009 from $17.82 in the first nine months of 2008, primarily as a result of a decrease in revenue per boe, offset by the increase in realized gain on the monetization of derivative instruments and decrease in royalties and operating expense per boe.
Stock Based Compensation
| | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Stock-based compensation | | $ | 244,542 | | | $ | 1,871,419 | | | | (87 | %) | | $ | 877,333 | | | $ | 2,662,254 | | | | (67 | %) |
| Per boe | | $ | 0.63 | | | $ | 7.43 | | | | (91 | %) | | $ | 0.81 | | | $ | 3.93 | | | | (79 | %) |
The Company’s stock-based compensation expense decreased 87% in the third quarter of 2009 and 67% for the nine months ended September 30, 2009. This decrease compared to 2008 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 Company recognized stock-based compensation expense of $0.2 million on its stock options in the third quarter of 2009 and $0.9 million on its stock options for the nine months ended September 30, 2009, calculated using the Black-Scholes option pricing model. Stock-based compensation expense is recognized on a straight-line basis over the vesting period. During the first nine months of 2009, Petroflow granted 60,000 options at a weighted average of $1.34 while cancelling 451,300 stock options at a weighted average exercise price of $3.52 and 40,000 options were exercised at $0.80 per share. The following assumptions were used to calculate stock-based compensation for the nine months period ended September 30, 2009; zero dividend yield; expected volatility of 109%; risk free rate of 1.26%; and expected life of 2 - 5 years.
Depletion, Depreciation and Accretion (DD&A)
| | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | |
| Depletion and depreciation | | $ | 3,357,926 | | | $ | 2,695,325 | | | | 25 | % | | $ | 10,473,881 | | | $ | 7,027,436 | | | | 49 | % |
| Accretion on asset retirement obligation | | | 38,000 | | | | 12,156 | | | | 213 | % | | | 95,056 | | | | 37,332 | | | | 155 | % |
| | | $ | 3,395,926 | | | $ | 2,707,481 | | | | 25 | % | | $ | 10,568,937 | | | $ | 7,064,768 | | | | 50 | % |
| Per boe | | $ | 8.81 | | | $ | 10.75 | | | | (18 | %) | | $ | 9.75 | | | $ | 10.56 | | | | (8 | %) |
| Write-down of property and equipment | | $ | 145,463 | | | $ | - | | | | 100 | % | | $ | 145,463 | | | $ | 1,015,950 | | | | (86 | %) |
| Per boe | | $ | 0.38 | | | $ | - | | | | 100 | % | | $ | 0.13 | | | $ | 1.52 | | | | (91 | %) |
Depletion and depreciation are calculated based upon capital expenditures, production rates and reserves. Excluded from the Company’s depletion and depreciation calculation are costs associated with unproven properties of $1.7 million. Future development costs for proved reserves of $42.3 million have been included in the depletion calculation.
The Company recorded $3.4 million or $8.81 per boe in DD&A expense in the third quarter of 2009, a decrease of 18% as compared to $10.75 per boe in DD&A expense in the third quarter of 2008. The decline in the DD&A rate is primarily due to a 20% increase in reserves with no overall increase in depletable costs. This DD&A calculation is based on production volumes of 385,504 boes in the quarter. The increase in total DD&A for the three month period ended September 30, 2009 reflects an increase in production, as compared to the same period in 2008.
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. The increase in accretion expense was mainly the result of change in estimated reserve life. This is offset by the increase in the estimated reclamation costs for certain wells.
The Company incurred a $0.1 million write-down of property and equipment in the third quarter of 2009. The write-down of property and equipment was the result of both downward reserve adjustments and prices in Canada only.
Net Loss
| | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | | $ | (8,705,716 | ) | | $ | 12,031,390 | | | | (172 | %) | | $ | (17,296,096 | ) | | $ | 988,012 | | | | (1,851 | %) |
| Per share - basic | | | (0.30 | ) | | | 0.41 | | | | (172 | %) | | | (0.59 | ) | | | 0.03 | | | | (2,067 | %) |
| Per share - diluted | | | (0.30 | ) | | | 0.39 | | | | (177 | %) | | | (0.59 | ) | | | 0.03 | | | | (2,067 | %) |
| Per boe | | $ | (22.58 | ) | | $ | 47.78 | | | | (147 | %) | | $ | (15.96 | ) | | $ | 1.48 | | | | (1,181 | %) |
The Company recorded an $8.7 million net loss in the third quarter of 2009 (($0.30) per share - basic and diluted) compared to a net income of $12.0 million ($0.41 per share - basic and $0.39 per share - diluted) in the same period of 2008. The decrease in commodity prices in the third quarter of 2009 more than offset increases in production in the third quarter of 2009 as compared to the same period of 2008. The decrease in revenue, increases in operating costs, DD&A and unrealized loss on derivative instruments offset by the increase in realized gain on derivative instruments and decrease in royalty expense were large contributors to the net loss.
The Company recorded a $17.3 million net loss for the first nine months of 2009 (($0.59) per share - basic and diluted) compared to net income of $1.0 million ($0.03 per share - basic and diluted) in the same period of 2008. The decrease in commodity prices in the first nine months of 2009 more than offset increases in production in the first nine months of 2009 as compared to the same period of 2008. The decrease in revenue, increases in operating costs, unrealized loss on derivative instruments and DD&A offset by the increase in realized gain on the monetization of derivative instruments and decrease in royalty expense were large contributors to the net loss.
SUMMARY OF QUARTERLY RESULTS
| | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil and gas sales | | $ | 9,028 | | | $ | 8,922 | | | $ | 9,572 | | | $ | 12,485 | | | $ | 16,618 | | | $ | 15,392 | | | $ | 10,220 | | | $ | 6,361 | |
| Funds (used in) from operations | | | (1,368 | ) | | | 4,551 | | | | 1,293 | | | | 730 | | | | 6,023 | | | | 2,579 | | | | 3,317 | | | | (1,092 | ) |
Per share - Basic | | | (0.05 | ) | | | 0.15 | | | | 0.04 | | | | 0.02 | | | | 0.19 | | | | 0.09 | | | | 0.12 | | | | (0.04 | ) |
Per share - Diluted | | | (0.05 | ) | | | 0.15 | | | | 0.04 | | | | 0.02 | | | | 0.18 | | | | 0.09 | | | | 0.12 | | | | (0.04 | ) |
| Net income (loss) | | | (8,706 | ) | | | (8,573 | ) | | | (18 | ) | | | 3,302 | | | | 12,031 | | | | (8,884 | ) | | | (2,159 | ) | | | (3,792 | ) |
Per share - Basic | | | (0.30 | ) | | | (0.29 | ) | | | (0.00 | ) | | | 0.11 | | | | 0.41 | | | | (0.30 | ) | | | (0.07 | ) | | | (0.14 | ) |
Per share - Diluted | | | (0.30 | ) | | | (0.29 | ) | | | (0.00 | ) | | | 0.10 | | | | 0.39 | | | | (0.30 | ) | | | (0.07 | ) | | | (0.14 | ) |
| Total assets | | | 172,479 | | | | 180,530 | | | | 207,318 | | | | 195,110 | | | | 137,143 | | | | 111,147 | | | | 120,764 | | | | 103,029 | |
Working capital (deficiency)(1) | | | (128,739 | ) | | | (10,328 | ) | | | (21,284 | ) | | | (26,222 | ) | | | (12,778 | ) | | | (15,151 | ) | | | (20,223 | ) | | | (17,147 | ) |
(1) Working capital excludes derivative contracts
CAPITAL EXPENDITURES
| | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Land and rentals | | $ | - | | | $ | 460,634 | | | | (100 | %) | | $ | 559,710 | | | $ | 1,048,333 | | | | (47 | %) |
| Drilling and completions | | | - | | | | 10,967,330 | | | | (99 | %) | | | 4,261,112 | | | | 31,363,001 | | | | (86 | %) |
| Equipment and facilities | | | - | | | | 9,117,187 | | | | (100 | %) | | | 3,707,486 | | | | 14,971,191 | | | | (75 | %) |
| Abandonment | | | 130,929 | | | | - | | | | 100 | % | | | 130,929 | | | | - | | | | 100 | % |
| Other assets | | | - | | | | 45,365 | | | | (100 | %) | | | 20,677 | | | | 178,636 | | | | (88 | %) |
| | | | 130,929 | | | | 20,590,516 | | | | (99 | %) | | | 8,679,914 | | | | 47,561,161 | | | | (82 | %) |
| Property disposals | | | - | | | | - | | | | 0 | % | | | - | | | | (28,249,927 | ) | | | 100 | % |
| | | | 130,929 | | | | 20,590,516 | | | | (99 | %) | | | 8,679,914 | | | | 19,311,234 | | | | 55 | % |
| Assets under capital lease | | | 117,850 | | | | 1,747,813 | | | | (93 | %) | | | 5,712,178 | | | | 10,067,975 | | | | (43 | %) |
| Total | | $ | 248,779 | | | $ | 22,338,329 | | | | (99 | %) | | $ | 14,392,092 | | | $ | 29,379,209 | | | | (51 | %) |
Maintaining financial and operational flexibility remains a key element in Petroflow’s business model. Petroflow’s capital program in the third quarter of 2009 was minimized to $0.1 million to align with the depressed economic and commodity price environment as compared to the third quarter of 2008 in which the Company invested $21.0 million.
In the first nine months of 2009, the Company invested $14.4 million compared to $57.6 million invested in the first nine months of 2008 which was offset by the divestiture of its non-core asset in New Mexico for $28.2 million.
Petroflow focused its capital program for the first nine months of 2009 in Oklahoma. Petroflow invested $4.3 million on drilling and completion, $3.7 million on facilities and equipment, $0.1 million on abandonment expenses, $0.5 million on land, lease and other assets and $6.0 million on assets under capital leases. The Company drilled one salt water disposal well and one natural gas well in the first nine months of 2009. The natural gas well and 6 additional wells drilled in the fourth quarter of 2008 were put on stream during the first three months of 2009.
The capital expenditures relating to assets under capital lease 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%.
LIQUIDITY AND CAPITAL RESOURCES
The Company’s source of funding includes the issuance of equity securities for cash, primarily through private placements and debt financing. The Company has issued common shares pursuant to private placement financings and exercise of warrants and options.
At September 30, 2009, the Company had cash of $2.1 million and a working capital deficit of $128.7 million excluding derivative contracts. The working capital deficit includes a current liability of $140.0 million which consists of accounts payable and accrued liabilities, current portion of obligations under capital lease, and the bank loan. At September 30, 2009 the Company is not in compliance with all of its covenants on its bank loan, as a result the loan term portion has been reclassified to current. This default is one of the factors which raise substantial doubt about the Company’s ability to continue as a going concern as discussed in Note 1 - Nature of Operations and Ability to Continue as a Going Concern in the financial statements.
At September 30, 2009, the Company had drawn $119.4 million (US$110.0 million) on its credit facility and had a working capital deficiency (excluding derivative contracts) of $128.7 million. The Company was not in compliance with its financial covenants as at September 30, 2009.
Effective September 30, 2009 the Company entered into an amended credit facility agreement (the “Amended Facility”). The Company has a US$200,000,000 revolving credit facility with a banking syndicate. This facility is dependent upon continued yearly reserve additions, and is made up of two tranches, “A” and “C”. The “A” tranche has a maturity date of January 1, 2012 with a borrowing base of US$100 million. There is an interest rate floor on tranche A of 5.5%. The “C” tranche matures on September 30, 2010, has a borrowing base of US$10 million, and an interest rate floor of 7.5%. As at September 30, 2009 the Company was not in compliance with its debt covenants. As a result the bank loan has been reclassified to a current liability.
The Amended Facility also requires that the Company raise an additional US$18 million on or before December 17, 2009 to reduce the aggregate outstanding indebtedness.
As at September 30, 2009, the Company owed its joint venture partner $18 million in respect of an obligation under capital lease. The Company’s farm-in agreement provides that the joint venture partner will provide financing on a capital lease basis for all infrastructure costs. The relevant financing is payable over three years at 12% interest once the related infrastructure is put into use.
The current economic slowdown, reduced availability of credit, and challenging equity markets have resulted in Petroflow suspending its drilling efforts 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 and nine month periods ended September 30, 2009.
SHARE CAPITAL AND OPTION ACTIVITY
| | | | | | | |
| | | As at November 10, | | | As at September 30, | |
| | | 2009 | | | 2009 | | | 2008 | |
| | | | | | | | | | |
| Common Shares | | | 29,549,894 | | | | 29,549,894 | | | | 29,423,894 | |
| Warrants | | | 1,692,000 | | | | 1,692,000 | | | | 1,692,000 | |
| Stock Options | | | 2,087,800 | | | | 2,467,300 | | | | 2,603,800 | |
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 September 30, 2009, the Company had 29,549,894 common shares and 2,467,300 options outstanding. During the first nine months of 2009, the Company granted 60,000 stock options at a weighted average exercise price of $1.34 while 451,300 options were cancelled at a weighted average price of $3.52 and 40,000 options were exercised at $0.80 per share.
As of November 10, 2009, the Company has 29,549,894 Common Shares; 1,692,000 warrants and 2,087,800 options outstanding.
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES
The Company is committed to the following payments under its operating leases for office space:
| | | | | |
| 2009 | | $ | 67,142 | |
| 2010 | | | 247,780 | |
| 2011 | | | 95,688 | |
| 2012 | | | 90,769 | |
| 2013 | | | 38,105 | |
| | | $ | 539,484 | |
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 December 31, 2008, 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.
The Company is party to employment agreements with six (6) members of senior management that require certain severance payments be made upon the occurrence of certain “change of control” events. In light of the recent retirement of the Company's CEO and the recent resignations of certain members of the Company's Board of Directors, the "change of control" provisions are being assessed to determine whether these events may have constituted a change of control. If such change of control provisions have been triggered, which is not admitted by the Company, then the provisions would enable the employees to elect, within 12 months of the date of the change of control, to terminate their agreements and receive aggregate severance payments of up to Cdn $2.4 million. A definitive determination regarding this issue has not been made by the Company at this time. In addition, the Company is unable to assess the likelihood of resignations by the applicable employees in the next 9 months. No employees have, at this point, advised that they have an intent to resign.
OFF-BALANCE SHEET ARRANGEMENTS
Petroflow was not involved in any off-balance sheet transactions during the quarter ended September 30, 2009.
RELATED PARTY TRANSACTIONS
As at September 30, 2009, $(2,065) (December 31, 2008 - ($14,169)) was due from (to) Macon Oil & Gas Corp. (“MOG”), a wholly owned subsidiary of Macon, as operator of one of the Company’s producing properties.
As at September 30, 2009, $10,261 was due to Patron Energy LLC., a joint interest partner, whose President and Vice President and principal partners are directors of the Company.
As at September 30, 2009 $73,023 (December 31, 2008, $470,223) was due to a joint interest partner in which a director of the Company has an interest.
As at September 30, 2009, $324,250 was due to the Company from a joint interest partner who is a director of the Company.
As at September 30, 2009 $322,302 was due to the directors 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.
The following table indicates the realized and unrealized losses on commodity contracts for the quarter ended September 30, 2009 and 2008:
| | | | | | | | | | | | | | | | | | | |
| | | Three months ended September 30, | | | Nine months ended September 30, | |
| | | | | | | | | % of | | | | | | | | | % of | |
| | | 2009 | | | 2008 | | | Change | | | 2009 | | | 2008 | | | Change | |
| | | | | | | | | | | | | | | | | | | |
| Unrealized gain (loss) | | | | | | | | | | | | | | | | | | |
| Natural gas | | $ | 5,221,417 | | | $ | 8,304,407 | | | | (37 | %) | | | - | | | $ | 578,165 | | | | (100 | %) |
| Oil | | | 1,821,067 | | | | 2,990,876 | | | | (39 | %) | | | - | | | | (58,095 | ) | | | 100 | % |
| | | $ | 7,042,483 | | | $ | 11,295,283 | | | | (38 | %) | | $ | - | | | $ | 520,070 | | | | (100 | %) |
| Realized gain (loss) | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas | | $ | 346,480 | | | $ | (501,920 | ) | | | 169 | % | | $ | 11,005,541 | | | $ | (751,662 | ) | | | 1,564 | % |
| Oil | | | 44,048 | | | | (41,162 | ) | | | 207 | % | | | 1,011,962 | | | | (812,815 | ) | | | 225 | % |
| | | $ | 390,529 | | | | (543,082 | ) | | | 172 | % | | | 12,017,503 | | | | (1,564,477 | ) | | | 868 | % |
| Cost of contracts | | | 72,376 | | | | - | | | | | | | | (2,355,829 | ) | | | - | | | | | |
| | | $ | 462,905 | | | $ | (543,082 | ) | | | 185 | % | | $ | 9,661,674 | | | | (1,564,477 | ) | | | 718 | % |
The following table outlines the details of the Company’s natural gas derivative contracts excluding any swap contracts noted below:
| Natural Gas | | Volume per day | | | Put Price | |
| | | (mmbtu) | | | USD | |
| | | | | | | | | |
| September 1, 2009 - September 30, 2010 | | | 1000 | | | | 5.25 | * |
| November 1, 2009 - December 31, 2009 | | | 1000 | | | | 4.25 | * |
| January 1, 2010 - October 31, 2010 | | | 500 | | | | 5.25 | * |
| January 1, 2010 - December 31, 2010 | | | 2500 | | | | 5.25 | * |
| November 1, 2010 - March 31, 2011 | | | 1500 | | | | 6.00 | * |
| January 1, 2011 - March 31, 2011 | | | 4000 | | | | 6.25 | * |
| April 1, 2011 - June 30, 2011 | | | 2000 | | | | 6.00 | * |
| Crude Oil | | Volume per day | | | Call Price | | | Put Price | |
| | | (bbls) | | | USD | | | USD | |
| | | | | | | | | | | | | |
| January 1, 2009 - December 31, 2009 | | | 75 | | | | 100.50 | | | | 75.00 | |
| January 1, 2009 - December 31, 2009 | | | 100 | | | | 89.70 | | | | 70.00 | |
| May 1, 2009 - August 31, 2009 | | | 150 | | | | 70.50 | | | | 40.00 | |
| September 1, 2009 - March 31, 2011 | | | 50 | | | | - | | | | 47.50 | |
| September 1, 2009 - March 31, 2011 | | | 50 | | | | - | | | | 47.50 | * |
| January 1, 2010 - December 31, 2010 | | | 100 | | | | 78.70 | | | | 65.00 | |
| January 1, 2011 - June 30, 2011 | | | 100 | | | | 100.75 | | | | 56.50 | |
| April 1, 2011 - June 30, 2011 | | | 100 | | | | 100.75 | | | | 56.50 | |
*Contingent Put Premiums
The Company has also entered into a swap contract with respect to 6800 MMBTU per day of gas production. The contract consists of 6800 MMBTU per day at a fixed price of US$7.25 per MMBTU for a period from October 1, 2009 to December 31, 2010, followed by a fixed price of US$5.33 per MMBTU for the period January 1, 2011 to September 30, 2012.
The swap contract covers over 25% of the Company’s current working interest production levels and provides Petroflow with stabilized prices. Combined with existing derivative contracts, the Company has downside price protection on over 40% of its current working interest production for the next two years.
CHANGES IN ACCOUNTING POLICIES
Credit Risk and Fair Value of Financial Assets and Liabilities
In January 2009, the CICA issued EIC-173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. The EIC provides guidance on how to take into account credit risk of an entity and counterparty when determining the fair value of financial assets and financial liabilities, including derivative instruments. This standard is effective for the Company’s fiscal periods ending on or after January 20, 2009 with retrospective application. The application of this EIC did not have a material effect on the Company’s financial statements.
Future Accounting Standards
Financial Instruments - Disclosures
In May 2009, the CICA amended Section 3862, “Financial Instruments - Disclosures,” to include additional disclosure requirements about fair value measurement for financial instruments and liquidity risk disclosures. These amendments require a three level hierarchy that reflects the significance of the inputs used in making the fair value measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant outputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement. These amendments are effective on December 31, 2009. The Company is assessing the impact these new rules will have on its Financial Statements.
International Financial Reporting Standards
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 September 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.
The Company is currently assessing IFRS accounting policies, including those that provide policy options, in comparison with accounting policies under US GAAP and is developing an approach to embed the change in GAAP in Petroflow’s accounting processes and systems.
Management is 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 the Company’s adoption of IFRS or US GAAP. Assessment of these developments together with Management’s assessment of the financial statement impact of changes in accounting policies will determine whether Petroflow adopts IFRS or US GAAP as the basis of its future public financial reporting.
INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s President and Chief Financial Officer have designed, or caused to be designed under their supervision, disclosure controls and procedures and internal controls over financial reporting to provide reasonable assurance regarding the reliability of the Company’s financial reporting and preparation of financial statements for external purposes in accordance with Canadian GAAP. There were no changes in the Company’s internal controls or new weaknesses noted in controls during Q3 2009 that have materially affected, or are reasonably likely to affect, the Company’s internal controls over financial reporting.
It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.
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.
