| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Financials | | | | | | | | | | | | | | | | | | |
| Oil sales | | | 2,207,782 | | | | 4,711,123 | | | | (53 | %) | | | 4,155,670 | | | | 7,467,894 | | | | (44 | %) |
| Natural gas and NGL sales | | | 6,714,341 | | | | 10,681,188 | | | | (37 | %) | | | 14,338,968 | | | | 18,144,527 | | | | (21 | %) |
| Total oil, natural gas and NGL revenue | | | 8,922,123 | | | | 15,392,311 | | | | (42 | %) | | | 18,494,638 | | | | 25,612,421 | | | | (28 | %) |
Funds from operations (1) | | | 4,551,366 | | | | 2,578,764 | | | | 76 | % | | | 5,844,388 | | | | 5,895,907 | | | | (1 | %) |
| Per share basic and diluted ($) | | | 0.16 | | | | 0.09 | | | | 76 | % | | | 0.20 | | | | 0.20 | | | | (2 | %) |
| Net loss | | | (8,572,558 | ) | | | (8,884,498 | ) | | | (2 | %) | | | (8,590,380 | ) | | | (11,043,378 | ) | | | (21 | %) |
| Per share basic and diluted ($) | | | (0.29 | ) | | | (0.30 | ) | | | 11 | % | | | (0.29 | ) | | | (0.38 | ) | | | (23 | %) |
Capital expenditures(2) | | | - | | | | 20,023,615 | | | | (100 | %) | | | 14,680,987 | | | | 35,455,885 | | | | (59 | %) |
Net debt (end of period) (3) | | | 142,430,358 | | | | 78,729,439 | | | | 81 | % | | | 142,430,358 | | | | 78,729,439 | | | | 81 | % |
| Operating Highlights | | | | | | | | | | | | | | | | | | | | | | | | |
| Production: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil (bbls per day) | | | 388 | | | | 409 | | | | (5 | %) | | | 403 | | | | 369 | | | | 9 | % |
| Natural gas and NGL (mcf per day) | | | 23,173 | | | | 12,099 | | | | 92 | % | | | 20,728 | | | | 11,541 | | | | 80 | % |
| Total (boe per day) (6:1) | | | 4,250 | | | | 2,426 | | | | 75 | % | | | 3,858 | | | | 2,292 | | | | 68 | % |
| Average realized price: | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil ($ per bbl) | | | 62.60 | | | | 126.48 | | | | (51 | %) | | | 56.95 | | | | 111.25 | | | | (49 | %) |
| Natural gas and NGL ($ per mcf) | | | 3.18 | | | | 9.70 | | | | (67 | %) | | | 3.82 | | | | 8.64 | | | | (56 | %) |
| Realized gain (loss) on commodity contracts ($ per bbl) | | | 20.04 | | | | (4.27 | ) | | | 569 | % | | | 13.17 | | | | (2.45 | ) | | | 638 | % |
| Combined average ($ per boe) | | | 43.11 | | | | 65.45 | | | | (34 | %) | | | 39.66 | | | | 58.94 | | | | (33 | %) |
| Netback ($ per boe) | | | | | | | | | | | | | | | | | | | | | | | | |
| Oil, natural gas and NGL sales | | | 23.07 | | | | 69.73 | | | | (67 | %) | | | 26.49 | | | | 61.39 | | | | (57 | %) |
| Realized gain (loss) on commodity contracts | | | 20.04 | | | | (4.27 | ) | | | 569 | % | | | 13.17 | | | | (2.45 | ) | | | 638 | % |
| Royalties and severance taxes | | | 5.33 | | | | 14.90 | | | | (64 | %) | | | 5.86 | | | | 13.30 | | | | (56 | %) |
| Operating expenses | | | 12.53 | | | | 11.73 | | | | 7 | % | | | 12.06 | | | | 10.29 | | | | 17 | % |
| Transportation expenses | | | - | | | | 0.37 | | | | (100 | %) | | | - | | | | 0.48 | | | | (100 | %) |
| Operating netback | | | 25.25 | | | | 38.46 | | | | (34 | )% | | | 21.74 | | | | 34.87 | | | | (38 | %) |
| G&A expense | | | 5.85 | | | | 13.94 | | | | (58 | %) | | | 6.32 | | | | 10.25 | | | | (38 | %) |
| Interest expense | | | 7.66 | | | | 6.48 | | | | 18 | % | | | 7.07 | | | | 7.20 | | | | (2 | %) |
| Corporate netback | | | 11.74 | | | | 18.04 | | | | (35 | %) | | | 8.35 | | | | 17.42 | | | | (52 | %) |
| Common shares | | | | | | | | | | | | | | | | | | | | | | | | |
| Common shares outstanding, end of period | | | 29,509,894 | | | | 29,423,894 | | | | 0 | % | | | 29,509,894 | | | | 29,423,894 | | | | 0 | % |
| Weighted average basic shares outstanding | | | 29,529,762 | | | | 29,341,315 | | | | 1 | % | | | 29,574,152 | | | | 29,291,630 | | | | 1 | % |
| (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 current 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 4,250 boe per day, a 75% increase over the second quarter of 2008 average sales production of 2,426 boe per day, and a 22% increase over the first quarter of 2009 average sales production of 3,462 boe per day.
Funds from operations increased by 76% in the second quarter of 2009 to $4.6 million from $2.6 million in the second quarter of 2008. This resulted in a per share (basic and diluted) increase of 76% to $0.16 in the second quarter of 2009 from $0.09 in the same period of 2008.
The Company recorded an $8.6 million net loss in the second quarter of 2009 ($0.29 per share - basic and diluted) compared to a net loss of $8.9 million ($0.30 per share - basic and diluted) in the same period of 2008. Production increases in the second quarter of 2009 were more than offset by the decrease in commodity prices and increase in operating expenses.
A 67% reduction in revenue per boe was a large contributor to the 34% 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 $25.25 per boe in the second quarter of 2009. The Company’s corporate netback (defined as operating netback per boe less G&A and interest expense per boe) was $11.74 per boe for the quarter.
Operating costs increased 7% to $12.53 per boe in the second quarter of 2009 as compared to $11.73 in the second quarter of 2008 and $11.48 per boe in the first quarter of 2009. The Company performed extensive workovers on six wells during the second quarter. The workovers were designed to enhance long term production and ultimately decrease operating costs, the cost of which was $ 0.55 per boe.
During the second quarter of 2009 and shortly thereafter, significant changes in the management of the Company occurred with the resignations of the Chairman of the Board of Directors, Mr. Richard Clark; followed by the CEO of the Company, Mr. John Melton. Mr. David Elgie, a professional engineer with considerable public company experience has replaced Mr. Clark. The remainder of the Company’s management team, headed by Mr. Sandy Andrew as President has remained in place.
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 second 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 six months ended June 30, 2009 and is provided by management as of August 14, 2009. It should be read in conjunction with Petroflow’s unaudited consolidated financial statements and related notes for the three and six months ended June 30, 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) sources of funding for future capital requirements, (vi) amounts received or paid to settle financial instruments currently entered into upon maturity, and (vii) 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 result 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 thereof 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 a value 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:
| | | | | | | | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | 2009 | | | 2008 | |
| Funds from operations | | $ | 4,551,366 | | | $ | 2,578,764 | | | $ | 5,844,388 | | | $ | 5,895,907 | |
| Changes in non-cash working capital | | | 147,660 | | | | (5,991,862 | ) | | | 2,794,251 | | | | (8,400,734 | ) |
| Cash flow from (used in) operating activities (per GAAP) | | $ | 4,699,026 | | | $ | (3,413,098 | ) | | $ | 8,638,639 | | | $ | (2,504,827 | ) |
RESULTS OF OPERATIONS
Production volumes
| | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | |
| Daily Sales Volumes | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude oil (bbls/day) | | | 388 | | | | 419 | | | | 494 | | | | 504 | | | | 412 | | | | 332 | | | | 255 | | | | 276 | |
| Natural gas & natural gas liquids (mcf/day) | | | 23,173 | | | | 18,255 | | | | 16,240 | | | | 13,396 | | | | 12,086 | | | | 10,960 | | | | 8,679 | | | | 7,151 | |
| Total (boe/day) | | | 4,250 | | | | 3,462 | | | | 3,201 | | | | 2,737 | | | | 2,426 | | | | 2,159 | | | | 1,702 | | | | 1,468 | |
Petroflow’s average sales production rate grew to 4,250 boe per day, a 75% increase over the second quarter of 2008 average sales production of 2,426 boe per day, and a 22% increase over the first quarter of 2009 average sales production of 3,462 boe per day. This growth occurred even though the Company had no drilling activity in the second 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 June 2009. Petroflow’s average for the first half of 2009 was 3,858 boe per day, a 68% increase over the first half of 2008 average sales production of 2,292 boe per day. The growth in the first half 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 June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Revenue | | | | | | | | | | | | | | | | | | |
| Crude Oil | | $ | 2,207,782 | | | $ | 4,711,123 | | | | (53 | %) | | $ | 4,155,670 | | | $ | 7,467,894 | | | | (44 | %) |
| Natural gas & natural gas liquids | | | 6,714,341 | | | | 10,681,188 | | | | (37 | %) | | | 14,338,968 | | | | 18,144,857 | | | | (21 | %) |
| Total oil & natural gas revenues | | $ | 8,922,123 | | | $ | 15,392,311 | | | | (42 | %) | | $ | 18,494,638 | | | $ | 25,612,421 | | | | (28 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Prices | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude Oil ($/bbl) | | | 62.60 | | | | 126.48 | | | | (51 | %) | | | 56.95 | | | | 111.25 | | | | (49 | %) |
| Natural gas & natural gas liquids ($/mcf) | | | 3.18 | | | | 9.70 | | | | (67 | %) | | | 3.82 | | | | 8.64 | | | | (56 | %) |
| Total oil, natural gas and NGL | | | | | | | | | | | | | | | | | | | | | | | | |
Revenue (per boe) | | | 23.07 | | | | 69.73 | | | | (67 | %) | | | 26.49 | | | | 61.39 | | | | (57 | %) |
| Unrealized gain (loss) (per boe) | | | (26.72 | ) | | | (35.31 | ) | | | (24 | %) | | | (10.09 | ) | | | (25.83 | ) | | | (35 | %) |
| Realized gain (loss) (per boe) | | | 20.04 | | | | (4.27 | ) | | | 569 | % | | | 13.17 | | | | (2.45 | ) | | | 638 | % |
| Total oil, natural gas and NGL | | | | | | | | | | | | | | | | | | | | | | | | |
Revenue after commodity contracts (per boe) | | | 16.39 | | | | 30.15 | | | | (46 | %) | | | 29.57 | | | �� | 33.11 | | | | (11 | %) |
Oil, natural gas and natural gas liquids and commodity contracts, other revenues
A 75% increase in production combined with a 67% decrease in average revenue per boe for the second quarter of 2009 resulted in revenues of $8.9 million decreasing from $15.4 million in the second quarter of 2008.
A 68% increase in production combined with a 57% decrease in average revenue per boe over the first half of 2009 resulted in revenues of $18.5 million decreasing from $25.6 million for the first half of 2008.
The Company had certain oil and natural gas commodity contracts in place as of June 30, 2009 and has entered into additional contracts since the quarter end. The Company had an unrealized loss of $10.3 million and a realized gain of $7.7 million on its commodity contracts for the second quarter of 2009, and an unrealized loss of $7.0 million and a realized gain of $9.2 million for the first half of 2009. The realized gain includes $5.6 million related to the monetization of hedging positions which had not yet matured prior to the end of the second quarter of 2009. The realized gain was reduced by $0.6 million for the second quarter and $2.4 million for the first half of 2009 due to the purchase of additional puts in the period. These particular puts 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.
Prices
In the second quarter of 2009 the Company realized average revenue per boe of $23.07, a decrease of 67% from the $69.73 per boe in the second quarter of 2008. In the first half of 2009 the Company realized average revenue per boe of $26.49, a decrease of 57% from the $61.39 per boe in 2008.
Petroflow realized an average natural gas and natural gas liquids price of $3.18 per mcf in the second quarter of 2009, a 67% decrease from $9.70 per mcf averaged in the second quarter of 2008. This compares to an average NYMEX reference price of US $3.60 per MMBtu in the second quarter of 2009 which is a 67% decrease from the second quarter of 2008 price of $10.93 per MMBtu. The percentage decrease in natural gas prices received by Petroflow is consistent with the decrease in the NYMEX reference price. Natural gas produced in Oklahoma is usually subject to a basis differential, historically in the range of 10% to 15% of NYMEX.
Petroflow realized an average natural gas and natural gas liquids price of $3.82 per mcf in the first half of 2009, a 56% decrease from $8.64 per mcf averaged in the first half of 2008. This compares to an average NYMEX reference price of US $4.25 per MMBtu in the first half of 2009 and a 55% decrease from the 2008 price of $9.48 per MMBtu. The percentage decrease is consistent with the movement in benchmark prices.
The Company realized an average price of $62.60 per bbl of oil in the second quarter of 2009, a decrease of 51% from $126.48 per bbl realized in the second quarter of 2008. This compares to an average WTI price of US$59.51 per bbl in the second quarter of 2009 a 52% decrease from US $123.95 per bbl in the second quarter of 2008. The decrease in second quarter oil prices was consistent with the movement in benchmark prices.
The Company realized an average price of $56.95 per bbl of oil in the first half of 2009, a decrease of 49% from $111.25 per bbl realized in the first half of 2008. This compares to an average WTI price of US$51.19 per bbl in the second quarter of 2009 a 54% decrease from US$110.91 per bbl in the first half of 2008. The decrease in first half oil prices was consistent with the movement in benchmark prices.
Royalties
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30. | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Royalties | | $ | 2,060,828 | | | $ | 3,289,124 | | | | (37 | %) | | $ | 4,088,338 | | | $ | 5,547,325 | | | | (26 | %) |
| % of Sales | | | 23 | % | | | 21 | % | | | | | | | 22 | % | | | 22 | % | | | | |
| Per boe | | $ | 5.33 | | | $ | 14.90 | | | | (64 | %) | | $ | 5.86 | | | $ | 13.30 | | | | (56 | %) |
Royalties, which include severance taxes (net of rebates), were $2.0 million or 23% of revenue for the second quarter of 2009, compared to $3.3 million or 21% of revenue in the second quarter of 2008. The increase in average royalty rate was primarily the result of the Company turning on several wells that do not qualify for the severance tax rebate.
Royalties, in the first half of 2009 were $4.1 million or 22% of revenue, compared to $5.5 million or 22% of revenue in the first half 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
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Operating expenses | | $ | 4,845,287 | | | $ | 2,588,720 | | | | 87 | % | | $ | 8,422,332 | | | $ | 4,295,273 | | | | 96 | % |
| Per boe | | $ | 12.53 | | | $ | 11.73 | | | | 7 | % | | $ | 12.06 | | | $ | 10.29 | | | | 17 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Transportation costs | | $ | - | | | $ | 81,683 | | | | (100 | %) | | $ | - | | | $ | 200,424 | | | | (100 | %) |
| Per boe | | $ | - | | | $ | 0.37 | | | | (100 | %) | | $ | - | | | $ | 0.48 | | | | (100 | %) |
Operating expenses per boe increased by 7% to $12.53 per boe in the second quarter of 2009 from $11.73 in the second quarter of 2008. Total operating expenses in the second quarter of 2009 were $4.9 million, up 87% from $2.6 million in the second quarter of 2008. The increase in operating expenses in the second quarter of 2009 is due to the increase in production and additional costs associated with workovers designed to improve production efficiency and ultimately reduce operating expenses in the future.
Operating expenses per boe increased by 17% to $12.06 per boe in the first half of 2009 from $10.29 in the first half of 2008. Total operating expenses in the first half of 2009 were $8.4 million, up 96% from $4.3 million in the first half of 2008. The increase in overall operating expenses in the first half of 2009 as compared to 2008 is due to the increase in production as well as the costs mentioned previously.
Transportation expenses for the second quarter of 2009 were $0.00 per boe compared to $0.37 per boe for the second quarter in 2008. This was primarily due to the sale of the New Mexico property on May 22, 2008.
Transportation expenses for the first half of 2009 were $0.00 per boe compared to $0.48 per boe for the first half 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 June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| General and administrative | | $ | 2,263,948 | | | $ | 3,077,667 | | | | (26 | %) | | $ | 4,410,389 | | | $ | 4,277,595 | | | | 3 | % |
| Per boe | | $ | 5.85 | | | $ | 13.94 | | | | (58 | %) | | $ | 6.32 | | | $ | 10.25 | | | | (38 | %) |
G&A expenses for the second quarter of 2009 decreased by 58% on a per boe basis to $5.85 from $13.94 per boe in the second quarter of 2008. Total G&A expenses decreased in the second quarter of 2009 compared to the second quarter of 2008. Additional costs in 2009 related to increased staffing levels, along with expenses associated with the Company’s listing on the Toronto Stock Exchange were more than offset by expenses incurred in the second quarter of 2008 but not in 2009. These expenses included $1.0 million associated with employee bonuses incurred in June 2008 and one-time expenses related to the listing on the American Stock Exchange. G&A expenses, on a per boe basis, declined in the second quarter of 2009 versus 2008 primarily due to the increase in production in 2009, along with factors mentioned above.
G&A expenses for the first half of 2009 decreased by 38% on a per boe basis to $6.32 from $10.25 per boe in the first half of 2008. The decrease on a per boe basis resulted primarily from increase in production in 2009 as compared to 2008.
Interest Expense
| | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change |
| Interest expense and financing expense | | $ | 2,963,045 | | | $ | 1,430,183 | | | | 107 | % | | $ | 4,937,206 | | | $ | 3,004,201 | | | | 64 | % |
| Average interest rate | | | 8.08 | % | | | 8.70 | % | | | (7 | %) | | | 7.30 | % | | | 9.00 | % | | | (19 | %) |
| Per boe | | $ | 7.66 | | | $ | 6.48 | | | | 18 | % | | $ | 7.07 | | | $ | 7.20 | | | | (2 | %) |
Interest expense in the second quarter of 2009 was $3.0 million or $7.66 per boe as compared to $1.4 million or $6.48 per boe in the second quarter of 2008. Petroflow’s average interest rate for the second quarter of 2009 was approximately 8.08%. 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 half of 2009 was $4.9 million or $7.07 per boe as compared to $3.0 million or $7.20 per boe in the first half of 2008. Petroflow’s average interest rate for the first half of 2009 was approximately 7.30%. The increase in interest expense primarily resulted from an increase in debt levels. The increase in expense for the first half of 2009 was offset by a reduction in interest rates in the first quarter of 2009 compared to the same period in 2008.
The Company’s debt consists of senior debt facilities provided by a syndicate of U.S. banking institutions and capital leases provided by the Company’s working interest partner in Oklahoma. The interest rates charged by the banks were LIBOR plus 2% to LIBOR plus 4% for the first quarter of 2009 and 5.5% for the second quarter of 2009. The annual interest rate charged on the capital leases is 12%.
Netbacks
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| ($/boe) | | | | | | | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 23.07 | | | $ | 69.73 | | | | (67 | %) | | $ | 26.49 | | | $ | 61.39 | | | | (57 | %) |
| Realized gain (loss) on derivative instruments | | | 20.04 | | | | (4.27 | ) | | | 569 | % | | | 13.17 | | | | (2.45 | ) | | | 638 | % |
| Royalties | | | 5.33 | | | | 14.90 | | | | (64 | %) | | | 5.86 | | | | 13.30 | | | | (56 | %) |
| Operating costs | | | 12.53 | | | | 11.73 | | | | 7 | % | | | 12.06 | | | | 10.29 | | | | 17 | % |
| Transportation costs | | | - | | | | 0.37 | | | | (100 | %) | | | - | | | | 0.48 | | | | (100 | %) |
| Operating netbacks | | $ | 25.25 | | | | 38.46 | | | | (34 | %) | | $ | 21.74 | | | $ | 34.87 | | | | (38 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| G&A | | | 5.85 | | | | 13.94 | | | | (58 | %) | | | 6.32 | | | | 10.25 | | | | (38 | %) |
| Interest | | | 7.66 | | | | 6.48 | | | | 18 | % | | | 7.07 | | | | 7.20 | | | | (2 | %) |
| Corporate netback | | $ | 11.74 | | | $ | 18.04 | | | | (35 | %) | | $ | 8.35 | | | $ | 17.42 | | | | (52 | %) |
Funds from operations
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Funds from operations | | $ | 4,551,366 | | | $ | 2,578,764 | | | | 76 | % | | $ | 5,844,388 | | | $ | 5,895,907 | | | | (1 | %) |
| Per share - basic and diluted | | | 0.16 | | | | 0.09 | | | | 76 | % | | | 0.20 | | | | 0.20 | | | | (2 | %) |
| Per boe | | $ | 11.77 | | | $ | 11.68 | | | | 1 | % | | $ | 8.37 | | | $ | 14.13 | | | | (41 | %) |
Funds from operations increased by 76% in the second quarter of 2009 to $4.6 million from $2.6 million in the second quarter of 2008. On a per share basis (basic and diluted) funds from operations increased by 76% to $0.16 from $0.09 in the corresponding period of 2008. The increase in funds from operations primarily results from the realized gain on the monetization of derivative instruments, which helped offset the impact of declining commodity prices.
Funds from operations decreased by 1% in the first half of 2009 to $5.8 million from $5.9 million in the first half of 2008. On a per share basis (basic and diluted) funds from operations remained consistent in the first half of 2009 and 2008 at $0.20. Funds from operations decreased by 41% on a per boe basis to $8.37 in the first half of 2009 from $14.13 in the first half 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 transportation expense per boe.
Stock Based Compensation
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Stock based compensation | | $ | 275,322 | | | $ | 499,381 | | | | (45 | %) | | $ | 632,791 | | | $ | 790,835 | | | | (20 | %) |
| Per boe | | $ | 0.71 | | | $ | 2.26 | | | | (69 | %) | | $ | 0.91 | | | $ | 1.90 | | | | (52 | %) |
The Company recognized stock-based compensation expense of $0.2 million on its stock options in the second quarter of 2009 and $0.6 million on its stock options for the six months ended June 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 half of 2009, Petroflow granted 60,000 options at a weighted average of $1.34 while cancelling 177,467 stock options at a weighted average exercise price of $3.76. The following assumptions were used to calculate stock-based compensation for the six months period ended June 30, 2009; zero dividend yield; expected volatility of 116%; risk free rate of 1.20%; and expected life of 2 - 5 years.
Depletion, Depreciation and Accretion (DD&A)
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Depletion and depreciation | | $ | 3,707,047 | | | $ | 2,143,986 | | | | 73 | % | | $ | 7,115,955 | | | $ | 4,332,111 | | | | 64 | % |
| Accretion on asset retirement obligation | | | 27,910 | | | | 9,839 | | | | 184 | % | | | 57,056 | | | | 25,176 | | | | 127 | % |
| | | $ | 3,734,957 | | | $ | 2,153,825 | | | | 73 | % | | $ | 7,173,012 | | | $ | 4,357,287 | | | | 65 | % |
| Per boe | | $ | 9.66 | | | $ | 9.76 | | | | (1 | %) | | $ | 10.27 | | | $ | 10,44 | | | | (2 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Write-down of property and equipment | | $ | - | | | $ | 1,015,950 | | | | (100 | %) | | $ | - | | | $ | 1,015,950 | | | | (100 | %) |
| Per boe | | $ | - | | | $ | 4.60 | | | | (100 | %) | | $ | - | | | $ | 2.44 | | | | (100 | %) |
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 $44.7 million have been included in the depletion calculation.
The Company recorded $3.7 million or $9.66 per boe in DD&A expense in the second quarter of 2009, a decrease of 1% as compared to $9.76 per boe in DD&A expense in the second quarter of 2008. This DD&A calculation is based on production volumes of 386,726 boes in the quarter. The increase in total DD&A for the three month period ended June 30, 2009 reflects an increase in production, as compared to the same period in 2008.
Income Taxes
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Future income tax recovery | | $ | 1,219,016 | | | $ | - | | | | 100 | % | | $ | 413,517 | | | $ | - | | | | 100 | % |
| Per boe | | $ | 3.15 | | | $ | - | | | | 100 | % | | $ | 0.59 | | | $ | - | | | | 100 | % |
A net future tax recovery of approximately $1.2 million has been recognized in the financial statements for the second quarter of 2009, a recovery of $0.4 million from the year ended 2008. All of the recovery is related to the Company’s wholly owned subsidiary North American Petroleum Corporation USA (“NAPCUS”). During the second quarter of 2009, the Company did not recognize a current income tax expense and applied an income tax asset to offset an income tax liability at June 30, 2009. A valuation allowance was applied to fully offset the income tax assets at June 30, 2008.
Net Loss
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | % Change | | | 2009 | | | 2008 | | | % Change | |
| Net loss | | $ | (8,572,558 | ) | | $ | (8,884,498 | ) | | | 4 | % | | $ | (8,590,380 | ) | | $ | (11,043,378 | ) | | | 22 | % |
| Per share - basic and diluted | | $ | (0.29 | ) | | $ | (0.30 | ) | | | 3 | % | | $ | (0.29 | ) | | | (0.38 | ) | | | 23 | % |
The Company recorded an $8.6 million net loss in the second quarter of 2009 ($0.29 per share - basic and diluted) compared to a net loss of $8.9 million ($0.30 per share - basic and diluted) in the same period of 2008. The decrease in commodity prices in the second quarter of 2009 more than offset increases in production in the second quarter 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.
The Company recorded an $8.6 million net loss for the first half of 2009 ($0.29 per share - basic and diluted) compared to a net loss of $11.0 million ($0.38 per share - basic and diluted) in the same period of 2008. The decrease in commodity prices in the first half of 2009 more than offset increases in production in the first half 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 a large contributor to the net loss.
SUMMARY OF QUARTERLY RESULTS
| | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | | | | Q2 | | | | Q1 | | | | Q4 | | | | Q3 | |
| Oil and gas sales | | $ | 8,922 | | | $ | 9,572 | | | $ | 12,485 | | | $ | 16,618 | | | $ | 15,392 | | | $ | 10,220 | | | $ | 6,361 | | | $ | 5,753 | |
| Funds from operations | | | 4,551 | | | | 1,293 | | | | 730 | | | | 6,023 | | | | 2,579 | | | | 3,317 | | | | (1,092 | ) | | | 510 | |
| Per share - Basic | | | 0.16 | | | | 0.04 | | | | 0.02 | | | | 0.19 | | | | 0.09 | | | | 0.12 | | | | (0.04 | ) | | | 0.02 | |
| Per share - Diluted | | | 0.16 | | | | 0.04 | | | | 0.02 | | | | 0.18 | | | | 0.09 | | | | 0.12 | | | | (0.04 | ) | | | 0.02 | |
| Net income (loss) | | | (8,573 | ) | | | (18 | ) | | | 3,302 | | | | 12,031 | | | | (8,884 | ) | | | (2,159 | ) | | | (3,792 | ) | | | (1,271 | ) |
| Per share - Basic | | | (0.29 | ) | | | (0.00 | ) | | | 0.11 | | | | 0.41 | | | | (0.30 | ) | | | (0.07 | ) | | | (0.14 | ) | | | (0.05 | ) |
| Per share - Diluted | | | (0.29 | ) | | | (0.00 | ) | | | 0.11 | | | | 0.39 | | | | (0.30 | ) | | | (0.07 | ) | | | (0.14 | ) | | | (0.05 | ) |
| Total assets | | | 180,530 | | | | 207,318 | | | | 195,110 | | | | 137,143 | | | | 111,147 | | | | 120,764 | | | | 103,029 | | | | 88,923 | |
| Working capital (deficiency) | | | (10,328 | ) | | | (21,284 | ) | | | (26,222 | ) | | | (12,778 | ) | | | (15,151 | ) | | | (20,223 | ) | | | (17,147 | ) | | | (53,021 | ) |
| (1) | Working capital excludes derivative contracts |
CAPITAL EXPENDITURES
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | %Change | | | 2009 | | | 2008 | | | % Change | |
| Land and rentals | | $ | - | | | $ | 416,715 | | | | (68 | %) | | $ | 507,596 | | | $ | 587,699 | | | | (13 | %) |
| Drilling and completions | | | - | | | | 11,184,026 | | | | (137 | %) | | | 4,190,076 | | | | 20,560,749 | | | | (79 | %) |
| Equipment and facilities | | | - | | | | 2,025,519 | | | | (48 | %) | | | 3,826,816 | | | | 5,854,004 | | | | (27 | %) |
| Other assets | | | - | | | | 68,208 | | | | (94 | %) | | | 24,497 | | | | 133,271 | | | | (82 | %) |
| | | | - | | | | 13,694,468 | | | | (122 | %) | | | 8,548,985 | | | | 27,135,723 | | | | (67 | %) |
| Property disposals | | | - | | | | (28,249,927 | ) | | | (100 | %) | | | - | | | | (28,249,927 | ) | | | 100 | % |
| | | | - | | | | (14,555,459 | ) | | | 79 | % | | | 8,548,985 | | | | (1,114,204 | ) | | | 805 | % |
| Assets under capital lease | | | - | | | | 6,345,147 | | | | (53 | %) | | | 6,132,002 | | | | 8,320,162 | | | | (26 | %) |
| Total | | $ | - | | | $ | (8,210,312 | ) | | | 100 | % | | $ | 14,680,987 | | | $ | 7,205,958 | | | | 115 | % |
Maintaining financial and operational flexibility remains a key element in Petroflow’s business model. Petroflow’s capital program in the second quarter of 2009 was minimized to align with the depressed economic and commodity price environment compared to the second quarter of 2008 in which the Company invested $20.0 million which was offset by its non-core asset in New Mexico for $28.2 million.
In the first six months of 2009, the Company invested $14.7 million compared to $35.3 million invested in the first six 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 six months of 2009 in Oklahoma. Petroflow invested $4.2 million on drilling and completion, $3.8 million on facilities and equipment, $0.5 million on land, lease and other assets and $6.1 million on assets under capital leases. The Company drilled one salt water disposal well and one natural gas well in the first half of 2009. The natural gas well and 6 additional wells drilled in the fourth quarter of 2008 were put on stream during the first half 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
At June 30, 2009, the Company had drawn $122.5 million (US $106.0 million) on its credit facility and had a working capital deficiency (excluding derivative contracts) of $10.3 million. No portion of the bank debt is due within the next twelve months. The Company was in compliance with all of its financial covenants as at June 30, 2009.
At June 30, 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 with a maturity date of January 1, 2012. There is an interest rate floor on the Amended Facility of 5.5%.
As at June 30, 2009, the Company owed its joint venture partner $21.1 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 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 and six month periods ended June 30, 2009.
SHARE CAPITAL AND OPTION ACTIVITY
| | | | | | | |
| | | As at August 13, | | | As at June 30, | |
| | | 2009 | | | 2009 | | | 2008 | |
| Common Shares | | | 29,509,894 | | | | 29,509,894 | | | | 29,423,894 | |
| Warrants | | | 1,692,000 | | | | 1,692,000 | | | | 1,692,000 | |
| Stock Options | | | 2,781,133 | | | | 2,781,133 | | | | 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 June 30, 2009, the Company had 29,509,894 common shares and 2,781,133 options outstanding. During the first six months of 2009, the Company granted 60,000 stock options at a weighted average exercise price of $1.34 while 177,467 options were cancelled at a weighted average price of $3.76.
As of August 13, 2009, the Company has 29,509,894 Common Shares; 1,692,000 warrants and 2,781,133 options outstanding.
CONTRACTUAL OBLIGATIONS, COMMITMENTS AND CONTINGENCIES
The Company is committed to the following payments under its operating leases for office space:
| | | | | |
| 2009 | | $ | 154,891 | |
| 2010 | | | 230,956 | |
| 2011 | | | 80,231 | |
| 2012 | | | 81,086 | |
| 2013 | | | 34,040 | |
| | | $ | 581,204 | |
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 $2.5 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 12 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 June 30, 2009.
RELATED PARTY TRANSACTIONS
As at June 30, 2009, $0.006 million (December 31, 2008 - ($0.01 million)) 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. Additionally, $0.2 million is owed by the Company to MOG (December 31, 2008 - $0.2 million) 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.
As at June 30, 2009, $0.1 million was due to Patron Energy LLC., a joint interest partner, whose President and principal partner is a director of the Company.
As at June 30, 2009 $0.1 million (December 31, 2008, $0.5 million) was due to the Company by a joint interest partner in which a director of the Company has an interest.
As at June 30, 2009, $0.1 million was due to a joint interest partner who is a director of the Company.
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 June 30, 2009 and 2008:
| | | | | | | |
| | | Three months ended June 30, | | | Six months ended June 30, | |
| | | 2009 | | | 2008 | | | %Change | | | 2009 | | | 2008 | | | % Change | |
| Unrealized gain (loss) | | | | | | | | | | | | | | | | | | |
| Natural gas | | $ | (8,882,866 | ) | | $ | (5,020,775 | ) | | | (77 | %) | | $ | (5,221,416 | ) | | $ | (7,726,243 | ) | | | 32 | % |
| Oil | | | (1,449,785 | ) | | | (2,773,331 | ) | | | 48 | % | | | (1,821,067 | ) | | | (3,048,970 | ) | | | 40 | % |
| | | $ | (10,332,651 | ) | | $ | (7,794,106 | ) | | | (33 | %) | | $ | (7,042,483 | ) | | $ | (10,775,213 | ) | | | 35 | % |
| Realized gain (loss) | | | | | | | | | | | | | | | | | | | | | | | | |
| Natural gas | | $ | 8,164,206 | | | $ | (356,660 | ) | | | 2,389 | % | | $ | 10,659,061 | | | $ | (249,741 | ) | | | 4,368 | % |
| Oil | | | 213,973 | | | | (586,747 | ) | | | 136 | % | | | 967,913 | | | | (771,653 | ) | | | 225 | % |
| | | | 8,378,179 | | | | (943,407 | ) | | | 988 | % | | | 11,626,974 | | | | (1,021,394 | ) | | | 1,238 | % |
| Cost of contracts and other | | | (628,905 | ) | | | - | | | | (100 | %) | | | (2,428,205 | ) | | | - | | | | (100 | %) |
| | | $ | 7,749,272 | | | $ | (943,407 | ) | | | 921 | % | | $ | 9,198,769 | | | $ | (1,021,394 | ) | | | 1,001 | % |
The following table outlines the details of the Company’s natural gas derivative contracts:
| | | | | | | | | | | | | |
| | | Volume | | | | | | | | | | |
| | | per day | | | Swap | | | Call | | | | |
| Natural Gas | | (mmbtu) | | | Price | | | Price | | | Put Price | |
| | | | | | (US$) | | | (US$) | | | (US$) | |
| June 1, 2009 - October 31, 2009 | | | 2,000 | | | | 3.53 | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | |
| September 1, 2009 - September 30, 2010 | | | 500 | | | | - | | | | - | | | | 5.25 | |
| September 1, 2009 - September 30, 2010 | | | 1,000 | | | | - | | | | - | | | | 5.25 | * |
| | | | | | | | | | | | | | | | | |
| November 1, 2009 - December 31, 2009 | | | 2,500 | | | | 5.40 | | | | - | | | | - | |
| November 1, 2009 - December 31, 2009 | | | 2,500 | | | | 5.52 | | | | - | | | | - | |
| November 1, 2009 - December 31, 2009 | | | 1,000 | | | | - | | | | - | | | | 4.25 | * |
| November 1, 2009 - December 31, 2009 | | | 1,000 | | | | - | | | | 6.30 | | | | 4.25 | |
| | | | | | | | | | | | | | | | | |
| January 1, 2010 - March 31, 2010 | | | 2,500 | | | | 5.52 | | | | - | | | | - | |
| January 1, 2010 - October 31, 2010 | | | 500 | | | | - | | | | 6.75 | | | | 5.25 | |
| January 1, 2010 - October 31, 2010 | | | 500 | | | | - | | | | - | | | | 5.25 | * |
| January 1, 2010 - December 31, 2010 | | | 500 | | | | - | | | | - | | | | 6.50 | |
| January 1, 2010 - December 31, 2010 | | | 2,500 | | | | - | | | | - | | | | 5.25 | * |
| January 1, 2010 - December 31, 2010 | | | 2,500 | | | | - | | | | 8.00 | | | | 5.25 | |
| | | | | | | | | | | | | | | | | |
| 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 | | | 1,500 | | | | - | | | | - | | | | 6.00 | * |
| November 1, 2010 - March 31, 2011 | | | 1,500 | | | | - | | | | - | | | | 6.00 | |
| | | | | | | | | | | | | | | | | |
| January 1, 2011 - March 31, 2011 | | | 2,500 | | | | - | | | | - | | | | 6.25 | * |
| January 1, 2011 - March 31, 2011 | | | 1,500 | | | | - | | | | - | | | | 6.25 | * |
| January 1, 2011 - March 31, 2011 | | | 1,000 | | | | - | | | | 8.25 | | | | 6.25 | |
| | | | | | | | | | | | | | | | | |
| April 1, 2011 - June 30, 2011 | | | 2,000 | | | | - | | | | 6.95 | | | | 6.00 | |
| April 1, 2011 - June 30, 2011 | | | 2,000 | | | | - | | | | - | | | | 6.00 | * |
| | | Volume | | | | | | | |
| | | per day | | | | | | | |
| Crude Oil | | (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 | |
| | | | | | | | | | | | | |
| 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 | | | | | | | | | | | | |
| | | | | | | | | | | | | |
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 upon 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.
INTERNAL CONTROL OVER FINANCIAL REPORTING
The Company’s President and Chief Financial Officer have designed, or caused to be designed under their supervision, 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.
This is the first period in which the Company has reported on the design of internal controls over financial reporting; consequently there is no report on changes in internal controls over financial reporting from the previous period.
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.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that all relevant information is gathered and reported to senior management, including the President and Chief Financial Officer (“CFO”), on a timely basis so that appropriate decisions can be made regarding public disclosure.
Management has evaluated the effectiveness of the design and operation of its disclosure controls and procedures, under the supervision of its President and CFO. Based on this evaluation, Management concluded that the disclosure controls and procedures, as defined in National Instrument 52-109, were effective as of June 30, 2009.
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.
