CALGARY, ALBERTA - (Marketwire - March 31, 2008) -
THIS NEWS RELEASE IS NOT FOR DISSEMINATION IN THE UNITED STATES OR TO ANY UNITED STATES NEWS SERVICES.
Fortress Energy Inc., (TSX:FEI) ("Fortress" or the "Company") announces that it has filed its Audited Consolidated Financial Statements and Management's Discussion and Analysis for the years ended December 31, 2007 and 2006, and its Annual Information Form which includes Fortress' reserves data and other oil and gas information for the year ended December 31, 2007, with the Canadian securities regulatory authorities on the System for Electronic Document Analysis and Retrieval ("SEDAR"). An electronic copy of these documents may be obtained on Fortress' SEDAR profile at www.sedar.com or on the Fortress website at www.fortressenergy.ca.
Fortress completed a very active year of pursuing its ACQUIRE AND EXPLOIT strategy in the Ladyfern area of Northeast B.C.
The acquisition of Marauder Resources West Coast Inc. in November 2006 represented a considerable change for the Company, providing Fortress with a new focus area at Ladyfern. The acquisition provided 14,000 net acres of undeveloped land, which the Company subsequently increased in 2007 to 87,011 net acres through the combination of an acquisition, participation in Crown sales, and acreage earned through completing commitments under farm-in arrangements. This also had the effect of increasing its average working interest in the general area from 55 percent to 78 percent. The large land inventory has provided the Company with an array of new drilling prospects to add to its already significant development drilling inventory.
Milestones reached in 2007 included:
- Completed drilling of 11 development wells, three exploration wells, and performed seven re-completions, all in areas operated by Fortress. The drilling resulted in two new pool discoveries in the Square Creek area which provided follow-up development and appraisal drilling opportunities for 2008;
- Completed a $12.5 million asset acquisition in the Ladyfern, Mearon and Velma areas. The acquisition included approximately 250 boe per day of natural gas production with additional productive capacity which was increased to 460 boe per day, estimated reserves of 1.0 million boe proved and 1.5 million proved plus probable, and more than 50,000 net acres of undeveloped land that increased its average working interest from 55 percent to 78 percent;
- Completed the installation of a refrigeration plant at Ladyfern, which also allows for the tie-in of wells at Velma, provides greater reliability of processing capabilities, increases natural gas liquids recoveries and generates additional processing revenues for the Company;
- Completed a reorganization of SignalEnergy Inc. on February 20, 2007, with the redemption of 23 million Signal shares at $1.30 per share, and the exchange of the remaining Signal shares on the basis of one share of Fortress for every five shares of Signal. This allowed for a $30 million distribution to the shareholders of Fortress; and
- Increased the Company's borrowing facility from $7 million to $25 million with ATB Financial.
Capital expenditures in 2007 were $38.5 million which included completion and tie-in costs associated with wells drilled in 2006 and the asset acquisition in the Ladyfern, Mearon and Velma areas. The total capital program operated by the Company, including expenditures of its partners, was approximately $56 million. The capital program resulted in:
- Proved plus probable reserves increased 51% to 6,456 mboe and a 25% increase in reserves per share;
- Proved plus probable finding, development and acquisition costs of $15.02 per boe (excluding an estimate of future capital);
- Replacement of production by 6.1 times;
- Proved and probable reserve life index (RLI) of 13.7 years based on Fortress' current production rates;
- Undeveloped land holdings of 87,011 net acres at December 31, 2007, an increase of 293%; and
- Production increased by 79% and production per share increased by 48%.
The winter 2007-2008 capital program will be a very active period for Fortress with most of the Company's activity focused on delineating the Square Creek discovery and constructing a 41 kilometre pipeline and gathering system to service the area. The Company will also continue pursuing other acquisition opportunities and business combinations to further consolidate its operations in the Ladyfern area. We are encouraged by the improving trend of natural gas prices caused by larger than expected inventory draws during the winter months and continued access to oilfield services at prices more competitive than in previous years.
FINANCIAL AND OPERATING SUMMARY
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2007 2006
($000's) $/boe ($000's) $/boe
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Petroleum and natural gas sales 13,895 38.43 9,090 44.92
Realized gain on commodity contracts 393 1.09 - -
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14,288 39.52 9,090 44.92
Royalties (2,688) (7.43) (1,398) (6.93)
Operating costs (4,030) (11.15) (2,161) (10.71)
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Operating netback (1) 7,570 20.94 5,531 27.28
General and administrative expenses (3,786) (10.47) (4,350) (21.57)
Net interest income (expense) (856) (2.37) 1,433 7.25
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Funds from operations (1) 2,928 8.10 2,614 12.96
Unrealized gain on commodity
contracts 92 0.25 - -
Depletion, depreciation and accretion (11,192) (30.95) (4,955) (24.57)
Stock-based compensation (2,513) (6.95) (822) (4.08)
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Loss before other items: (10,685) (29.55) (3,163) (15.69)
Gain on sale of oil and gas property,
plant and equipment - - 15,835 78.51
Goodwill impairment - - (4,548) (22.55)
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Income (loss) before income taxes (10,685) (29.55) 8,124 40.27
Future income tax recovery (expense) 2,715 7.51 (36) (0.18)
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Net income (loss) (7,970) (22.04) 8,088 40.09
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(1) Non-GAAP measures. See discussion in the following MD&A.
MANAGEMENT'S DISCUSSION AND ANALYSIS
March 31, 2008
Management's discussion and analysis ("MD&A") should be read in conjunction with the consolidated financial statements of Fortress Energy Inc. ("Fortress" or the "Company", formerly known as SignalEnergy Inc.) for the years ended December 31, 2007 and 2006. The consolidated financial statements have been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). All tabular amounts in the following discussion are in thousands of Canadian dollars unless otherwise noted. Additional information is available on the Company's web site at www.fortressenergy.ca or under the Company's profile at www.sedar.com.
Non-GAAP Measurements
The terms "funds from operations" and "operating netback" used in the MD&A are not recognized measures under GAAP. Management believes that in addition to net income, funds from operations and operating 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. Investors are cautioned, however, that these measures should not be construed as alternatives to net income determined in accordance with GAAP, as an indication of the Company's performance.
Reconciliation of "Funds from Operations" to Cash Flow from Operating Activities per GAAP
The Company's method of calculating funds from operations may differ from that of other companies, and, accordingly it may not be comparable to measures used by other companies. The Company calculates funds from operations by taking cash flow from operating activities as determined under GAAP before changes in non-cash operating working capital and abandonment expenditures. The consolidated statements of cash flows included in the consolidated financial statements present the reconciliation between net income (loss) and funds from operations. A summary of this reconciliation is as follows:
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($000's) 2007 2006
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Cash flow from operating activities 3,570 741
Change in non-cash operating working capital (722) 1,873
Abandonment expenditures 80 -
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Funds from operations 2,928 2,614
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BOE Presentation
Natural gas reserves and volumes recorded in thousand cubic feet are converted to barrels of oil equivalent ("boe") on the basis of six thousand cubic feet ("mcf") of gas to one barrel ("bbl") of oil. The term "barrels of oil equivalent" may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf to 1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.
Forward Looking Statements
Statements in this MD&A may contain forward looking information including expectations of future production, components of cash flow and earnings, expected future events and/or financial results that are forward looking in nature and subject to substantial risks and uncertainties. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The Company cautions the readers that actual performance will be affected by a number of factors, as many may respond to changes in economic and political circumstances throughout the world. Events or circumstances may cause actual results to differ materially from those predicted, a result of numerous known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company. These risks include, but are not limited to: the risks associated with the oil and gas industry, commodity prices and exchange rate changes; industry related risks could include, but are not limited to, operational risks in exploration, development and production, delays or changes in plans; risks associated with the uncertainty of reserve estimates, health and safety risks and the uncertainty of estimates and projections of production, costs and expenses. These external factors beyond the Company's control may affect the marketability of oil and natural gas produced, industry conditions including changes in laws and regulations, changes in income tax regulations, increased competition, fluctuations in commodity prices, interest rates, and variations in the Canadian/United States dollar exchange rate. The reader is cautioned not to place undue reliance on this forward looking information.
Statements throughout this MD&A that are not historical facts may be considered "forward looking statements." These forward looking statements sometimes include words to the effect that management believes or expects a stated condition or result. All estimates and statements that describe the Company's objectives, goals or future plans are forward looking statements. 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 any number of risks including, but not limited to:
a. Risks associated with the oil and gas industry and regulatory bodies (e.g. operational risks in exploration, development and production, or changes in royalty rates);
b. Delays or changes in plans with respect to exploration or development projects or capital expenditures;
c. Uncertainty of estimates and projections relating to recoverable reserves, costs and expenses;
d. Health, safety and environmental risks; and
e. Commodity price and exchange rate fluctuations.
DESCRIPTION OF THE BUSINESS
Fortress Energy Inc. was formed through the reorganization (the "Reorganization") of SignalEnergy Inc. ("Signal"), including an arrangement (the "Arrangement") under the Companies Act (Quebec), which was approved at a Special Meeting of Shareholders on February 15, 2007 and was effective February 20, 2007. Further details are provided in notes 2 and 10 to the audited consolidated financial statements.
Fortress' primary focus is the exploration and development of natural gas reserves in Western Canada. The Company has approximately 87,011 net acres of undeveloped land in the Ladyfern, Velma and Buick Creek areas in NE British Columbia and the Chigwell, Bashaw, Square Creek, Halverson, Mearon and Dahl areas of Alberta.
The Company's strategy is to 'acquire and exploit' properties that are early in their development cycle that offer exploration, appraisal and development drilling opportunities, while maintaining low finding and development costs. Fortress operates most of its production enabling it to have complete control over cost management of its capital programs.
CORPORATE HIGHLIGHTS
During the year ended December 31, 2007, Fortress accomplished the following:
- Drilled 11 gross development wells, 3 gross exploration wells and completed 7 recompletion operations at Ladyfern South, Mearon North and Square Creek. This program added 200 boe/d of new production and two new pool discoveries.
- Increased proven reserves to 4,108 mboe and proven plus probable reserves to 6,456 mboe.
- Increased average production to 1,256 boe/d for the fourth quarter of 2007 from 522 boe/d for the fourth quarter of 2006.
- Completed the reorganization of SignalEnergy Inc. on February 15, 2007.
- Announced the addition of Mr. Robert D'Adamo, VP Land, and Mr. Darren Jackson, COO, to the management team.
- Completed a strategic asset acquisition in the Ladyfern, Mearon and Velma areas in July for $12.5 million, adding proven reserves of 1,040 mboe and proven plus probable reserves of 1,546 mboe. The acquisition included 54,232 net acres of undeveloped land, consolidating the Company's land position in its core Ladyfern, Mearon and Velma areas.
- Secured a new $25 million bank borrowing facility.
- Announced an agreement with AltaGas to construct a 41 km pipeline for the Square Creek development area to the AltaGas processing facility at Clear Prairie. Construction commenced in December and the final commissioning of the pipeline will be completed in early April 2008.
- Raised $5 million ($4.4 million net) through a public offering of common shares on a flow-through basis in December.
DETAILED FINANCIAL ANALYSIS
Production
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Three months ended Year ended
December 31, December 31,
2007 2006 2007 2006
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Sales volume:
Natural gas (mcf/d) 7,455 3,012 5,845 2,744
Oil and NGL's (bbl/d) 13 20 16 95
Total(boe/d) 1,256 522 990 553
Sales price:
Natural gas ($/mcf) 6.19 7.19 6.32 6.95
Oil and NGLs ($/bbl) 86.95 56.47 68.15 59.94
Total ($/boe) 38.07 44.13 38.43 44.92
Benchmark prices:
AECO average price ($/mcf) 6.00 6.89 6.60 6.54
Edmonton par ($/boe) 80.75 65.24 75.49 73.72
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Sales volumes for the year ended December 31, 2007 increased to 990 boe/d compared to 553 boe/d for 2006 as result of the Company's acquisition of Marauder Resources West Coast Inc. ("Marauder") on November 15, 2006 which added sales gas volumes of 450 boe/d. The Company's 2007 drilling program, which included 14 gross (8 net) wells in the Ladyfern South, Mearon North and Square Creek areas, and 7 recompletion operations, added additional volumes of 200 boe/d in the second quarter of 2007. In July 2007, the Company acquired a partner's working interest in Ladyfern North, Mearon North and Velma increasing the Company's working interest to 100% in these areas. This strategic acquisition added additional volumes in the third quarter of 225 boe/d which the Company had increased in the fourth quarter to 425 boe/d with the start up of two wells at Velma in late August. In the first quarter of 2006, the Company sold its oil and natural gas assets in the Redwater, Carrot Creek, Ferrier and Kaybob areas which recorded sales volumes of 674 boe/d in that quarter. The Company retained its Buick Creek, Chigwell and Bashaw properties which were producing at a rate of approximately 330 boe/d at the time of the sale.
Sales volumes in the fourth quarter of 2007 increased to 1,256 boe/d from 522 boe/d in the fourth quarter of 2006. Late in the third quarter of 2007, the Company added a refrigeration plant to its Ladyfern property improving its natural gas liquids recovery and lowering the dew point of the gas entering a third party processing facility, improving the time on production for these wells. In late August 2007, the Company brought two wells at Velma on stream and after optimizing in September these wells were producing at a combined rate of 426 boe/d. The Velma wells are tied into the Ladyfern gathering system and the start-up of these wells increased the line pressures and reduced production volumes from the Company's Ladyfern wells by approximately120 boe/d. As part of the first quarter 2008 capital program, the Company is adding compression at Ladyfern to restore lost production. The Company's acquisition of Marauder in November 2006 added incremental sales volumes for the fourth quarter of 2006 of 230 boe/d.
Natural gas accounted for substantially all of the Company's sales in 2007. The change in sales mix from 2006 is a result of the sale of the Company's oil producing assets in the first quarter of 2006 and the Marauder acquisition in the fourth quarter of 2006. The average price realized in 2007 for natural gas (net of transportation costs and before realized gains on commodity contracts) was $6.32/mcf compared to the AECO average price of $6.60/mcf. For the fourth quarter of 2007, the Company realized a natural gas price of $6.19/mcf (net of transportation costs and before realized gains on commodity contracts) compared to the average AECO price of $6.00/mcf.
Revenue
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Three months ended Year ended
December 31, December 31,
2007 2006 2007 2006
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Petroleum and natural gas
sales ($000's) 4,396 2,149 13,895 9,090
$/boe 38.07 44.13 38.43 44.92
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Petroleum and natural gas sales for the year ended December 31, 2007 were $13,895,000 compared to $9,090,000 for the year prior. This increase is due to an increase in sales volumes from 553 boe/d in 2006 to 990 boe/d in 2007 which is attributable to the acquisition of Marauder, the 2007 drilling program and the asset acquisition in July. This increase was affected by a reduction in natural gas prices realized by the Company in 2007 of 14.4% from 2006 prices.
For the three months ended December 31, 2007, the Company recorded sales of $4,396,000 compared to $2,149,000 for the same period in 2006. This increase is attributed to the items previously noted.
A reconciliation of petroleum and natural gas sales between 2007 and 2006 is
a follows:
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($000's)
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Petroleum and natural gas sales - year ended December 31, 2006 9,090
Effect of increased production year-over-year 7,144
Effect of decreased product prices year-over-year (2,339)
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Petroleum and natural gas sales - year ended December 31, 2007 13,895
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Realized and Unrealized Gains on Commodity Contracts
The Company uses commodity contracts to manage its exposure to fluctuations in the price of natural gas. In 2007, the Company recorded realized gains on commodity contracts of $393,000 or $1.09/boe (2006 - $nil) and an unrealized gain of $92,000 or $0.25/boe. In the fourth quarter of 2007, the Company recorded realized gains on commodity contracts of $35,000, or $$0.30/boe, and unrealized gains of $19,000, or $0.16/boe.
The following commodity contracts were in place at December 31, 2007 and
March 31, 2008:
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Type Period Volume (GJ/d) Fixed Price ($/GJ)
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Swap January 1, 2008 to October 31, 2008 2,000 6.51
Swap January 1, 2008 to October 31, 2008 3,000 6.505
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Royalties
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Three months ended Year ended
December 31, December 31,
2007 2006 2007 2006
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Royalties (net of Alberta
Royalty Tax Credit) ($000's) 1,317 24 2,688 1,398
$/boe 11.41 0.49 7.43 6.93
Percentage of petroleum and natural
gas sales 30.0 1.1 19.3 15.4
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Royalties were $2,688,000 for the year ended December 31, 2007 compared to $1,398,000 for the prior year. The increase reflects increased sales volumes in 2007. As a percentage of petroleum and natural gas sales (net of transportation costs and before realized gains on commodity contracts), royalties increased to 19.3% in 2007 compared to 15.4% from the prior year. This increase is attributed to increased production volumes in the fourth quarter from the start-up of the Company's Velma property which records a royalty rate of approximately 20%. Contributing to this increase was a $294,000 charge resulting from a reassessment by Alberta Taxation of Alberta Royalty Tax Credits ("ARTC") claimed for prior taxation years and a charge for royalties of $235,000 related to prior periods, which were based on best estimates at that time. These additional charges are approximately 3.8% of petroleum and natural gas sales for 2007. The Company's wells at Ladyfern North qualify for the Ultra-Marginal Royalty Program which assesses a reduced royalty rate for low producing wells in the province of British Columbia, resulting in an effective royalty rate of approximately 8% for these wells.
For the fourth quarter of 2007, royalties increased to $1,317,000 from $24,000 for the fourth quarter of 2006. This increase is attributed to increased sales in the fourth quarter of 2007. As a percentage of petroleum and natural gas sales royalties were 30.0% in the fourth quarter of 2007 compared to 1.1% for the fourth quarter of 2006. The increase in the fourth quarter of 2007 compared to the royalty rate realized for all of 2007 is due to increased production from the Velma property and additional charges, previously noted. The fourth quarter of 2006 reflects a reduction in royalties of $426,000 to reflect unrecognized Alberta Royalty Tax Credits ("ARTC").
On October 25, 2007, the Alberta Government released "The New Royalty Framework" which summarizes the Governments decision on Alberta's new royalty structure pertaining to oil and gas resources, including oil sands, conventional oil and gas, and coal bed methane. This is in response to recommendations recently put forth by the Alberta Royalty Review Panel. This new royalty structure will take effect on January 1, 2009. Based on our review of the new royalty structure, our current production will be affected only in a modest way at current prices. In some cases, royalty rates will actually decline from current rates depending upon rates of production in 2009 and future years. On this basis, and assuming current prices, we believe that a majority of our inventory will continue to provide economic returns. The actual effect on the Company will be determined based on the actual legislation enacted, production rates, commodity prices, foreign exchange rates, production mix and service costs as they exist on January 1, 2009. For 2007, approximately 34% of the Company's production was from Alberta with the remaining 66% from British Columbia. In addition, approximately 36% of the proven plus probable reserves at December 31, 2007 are in Alberta, with the remaining 64% from British Columbia.
Operating Expenses
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Three months ended Year ended
December 31, December 31,
2007 2006 2007 2006
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Operating ($000's) 1,762 279 4,030 2,161
$/boe 15.26 5.73 11.15 10.71
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Operating expenses increased in 2007 to $4,030,000 from $2,161,000 in 2006 due to an increase in sales volumes, as previously noted. In 2007, operating expenses were $11.15/boe compared to $10.71/boe in 2006. Operating expenses for 2007 include natural gas processing, road usage and maintenance, and contract operating expenses related to 2006 totaling $341,000, or $0.94/boe. Excluding these 2006 costs, operating expenses for 2007 amounted to $10.21/boe.
For the fourth quarter of 2007, operating expenses were $1,762,000, or $15.26/boe, compared to $279,000 for the fourth quarter of 2006, or $5.73/boe. Operating expenses increased in the fourth quarter of 2007 due to increased production volumes from the start-up of the Velma wells late in the third quarter and an under estimation in prior quarters attributed to a lack of experience with the Marauder assets. In addition, the Company recorded incremental consulting services of $77,000 (or $0.67/boe) and methanol costs of $72,000 ($0.62/boe). Additional operating expenses are typically recorded in the fourth quarter due to the "winter access" nature of the Company's properties as certain operations can only be conducted during these winter months.
General and Administrative Expenses
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Three months ended Year ended
December 31, December 31,
2007 2006 2007 2006
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Gross ($000's) 1,608 1,405 5,399 4,760
Partner recoveries ($000's) (115) - (304) -
Capitalized ($000's) (362) (240) (1,309) (410)
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Net ($000's) 1,203 1,165 3,786 4,350
$/boe 10.42 24.19 10.47 21.57
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General and administrative expenses decreased to $3,786,000 in 2007 from $4,350,000 in 2006. In the first quarter of 2006, the Company sold a substantial portion of its oil and gas assets and became the target of a takeover transaction. As a result of the asset sale, the Company substantially curtailed its operations in the first quarter of 2006. In 2006, the Company underwent a downsizing incurring severance and retention costs of approximately $959,000 and incremental legal costs of $360,000. After the closing of the Marauder transaction, the Company rehired technical staff to execute on its capital program for first quarter of 2007. Gross general and administrative expenses increased in 2007 to $5,399,000 from $4,760,000 in 2006. This increase reflects an allowance for doubtful accounts receivable balances of $525,000. General and administrative expenses for the three months ended December 31, 2007 were $1,203,000 compared to $1,165,000 for the three months ended December 31, 2006.
As a result of the rehiring of staff and significant ramp up in exploration and development activities, general and administrative expenses capitalized in 2007 increased to $1,309,000 from $410,000 in 2006. The Company's policy is to capitalize salaries, consulting fees and software costs that are directly attributable to exploration and development activities.
Stock-based Compensation Expense
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Three months ended Year ended
December 31, December 31,
2007 2006 2007 2006
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Stock-based compensation
expense ($000's) 2,084 - 2,513 822
$/boe 18.05 - 6.95 4.08
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Stock-based compensation expense for the year ended December 31, 2007 increased to $2,513,000 from $822,000 for 2006. On October 4, 2007, the Company cancelled 1,193,000 stock options that were outstanding resulting in a charge to the consolidated statement of operations of $2,063,000 of previously unrecognized compensation cost related to these options. As a result of the sale of oil and gas assets and a takeover bid in the first quarter of 2006, the Company vested all outstanding stock options on March 1, 2006. As a result, the recognition of stock-based compensation expense in 2006 was accelerated.
Interest Income and Expense
Interest income of $219,000 for the year ended December 31, 2007 represents interest earned on the invested cash from the sale of oil and gas assets in the first quarter of 2006 to the time of the Reorganization and $30 million redemption of common shares in February 2007. At December 31, 2006, the Company held $35,048,000 of commercial paper investments with a yield of 4.3%. Interest income for 2006 also relates to invested cash from the sale of oil and gas properties in the first quarter.
Interest expense increased to $1,075,000 in 2007 from $498,000 in the prior year due to increased borrowings to finance operations and the asset acquisition that was completed in July. With the sale of oil and gas assets in the first quarter of 2006, the Company repaid its revolving credit facility that was outstanding at that time. Interest expense for 2007 also reflects interest and penalties of $105,000 related to the audits of ARTC and a 2003 flow-through share issuance of a subsidiary company.
Interest expense in the fourth quarter of 2007 was $434,000 representing interest on the Company's bank line and interest and penalties resulting from the ARTC audit, compared to $133,000 in the fourth quarter of 2006 which relates entirely to interest on unspent flow-through obligations.
Depletion, Depreciation and Accretion Expense
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Three months ended Year ended
December 31, December 31,
2007 2006 2007 2006
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Depletion and depreciation expense
($000's) 4,536 1,418 11,039 4,865
Accretion of asset retirement
obligations ($000's) 71 15 153 90
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Total ($000's) 4,607 1,433 11,192 4,955
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Depletion and depreciation expense
($/boe) 39,90 29.52 30.53 24.12
Accretion of asset retirement
obligations ($/boe) 0.61 0.31 0.42 0.45
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Total ($/boe) 40.51 29.83 30.95 24.57
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Depletion and depreciation expense was $11,039,000 for the year ended December 31, 2007 compared to $4,865,000 for the prior year. This increase is attributed to a 79% increase in sales volumes over 2006 levels, and an additional depletion and depreciation charge of $1,404,000 resulting from a ceiling test impairment at December 31, 2007. Depletion and depreciation expense for 2007 increased to $30.53/boe from $24.12/boe in 2006. The impact of the ceiling test impairment charge is $3.88/boe for the year ended December 31, 2007 and results from minor downward technical revisions to reserves and a decrease in forecast natural gas prices for 2008 and 2009. The impact of the ceiling test impairment on the fourth quarter depletion and depreciation expense is $12.16/boe.
Estimated future development costs for proved undeveloped properties included in the calculation of depletion expense at December 31, 2007 increased to $16,435,000 from $15,595,000 at the end of 2006. Undeveloped land costs at December 31, 2007 increased to $7,371,000 from $3,158,000 at December 31, 2006 and were excluded from assets subject to depletion.
Accretion expense for the year ended December 31, 2007 was $153,000 compared to $90,000 for the prior year. This increase is due to additional wells added in the first quarter of 2007 and an increase in working interests resulting from the asset acquisition in July of 2007. Accretion expense for the fourth quarter of 2007 of $71,000 increased from the fourth quarter of 2006 due to additional wells added, as previously noted. In addition, the Company recorded additional accretion expense of $30,000 in the fourth quarter of 2007 as a result of a loss on settlement of retirement obligations.
Income Tax
The Company recorded a recovery of future income taxes for the year ended December 31, 2007 of $2,715,000 compared to future income tax expense of $36,000 in 2006. Future income tax reflects the difference between the underlying tax value and carrying value of the Company's assets and liabilities. The change in future income taxes reflects the sale of oil and gas assets in the first quarter of 2006 and the application of available tax pools to minimize the tax liability to the Company. Based on current commodity prices and planned capital expenditures, the Company does not expect to be cash taxable in 2008.
The income tax effect of a $5 million flow-through share offering completed in December 2007 will be recorded in the first quarter of 2008 with the filing of the renouncement documents to the taxation authorities. The effective date of the renouncement was December 31, 2007 with all expenditures to be incurred by December 31, 2008. As of March 31, 2008, the Company has incurred approximately $1,000,000 of eligible expenditures.
The estimated tax pools of the Company at December 31, 2007 are as follows:
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($000's)
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Canadian Oil and Gas Property Expenses 14,790
Canadian Development Expenses 26,931
Canadian Exploration Expenses 15,307
Undepreciated Capital Cost 28,788
Share issuance costs 922
Investment Tax Credits 2,367
Non-capital losses 210
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89,315
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Net Income (Loss)
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Three months ended Year ended
($000's except per share December 31, December 31,
and per boe amounts) 2007 2006 2007 2006
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Net income (loss) (5,442) (5,609) (7,970) 8,088
Net income (loss) per share
- basic and diluted (0.40) (0.08) (0.59) 0.11
Net income (loss) per boe (47.13) (116.80) (22.04) 40.09
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The Company recorded a net loss of $7,970,000 for the year ended December 31, 2007 compared to net income of $8,088,000 for the prior year. This translates into a basic and diluted net loss per share of $0.59 for 2007 and basic and diluted net income per share for 2006 of $0.11. The 2007 net loss is attributable to a reduction in the operating netback realized, a significant increase in depletion and depreciation expenses as a result of a ceiling test impairment, and an increase in stock-based compensation expense. Net income for 2006 was the result of a gain on sale of oil and gas assets recorded of $15,835,000.
For the fourth quarter of 2007, the Company recorded a net loss of $5,442,000 compared to $5,609,000 for the fourth quarter of 2006. In the fourth quarter of 2006 the Company recorded a reduction of $4,120,000 to the previously recorded gain on sale of oil and gas assets resulting from additional capital expenditures required to complete commitments to the purchaser of those assets. In the fourth quarter of 2007, the Company recorded additional depletion and depreciation expenses of $1,404,000 as a result of a ceiling test impairment, as previously noted.
Funds from Operations
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Three months ended Year ended
($000's except share December 31, December 31,
and per boe amounts) 2007 2006 2007 2006
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Funds from (used in) operations (282) 1,089 2,928 2,614
Funds from operations ($/boe) (2.44) 22.68 8.10 12.96
Funds from operations per share
- basic and diluted (0.02) 0.02 0.22 0.04
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Funds from operations for the year ended December 31, 2007 were $2,928,000 compared to $2,614,000 for 2006. This increase is attributed to an increase in production in 2007 of 79% over the prior year, reduced by a lower operating netback realized which decreased from $27.28 for 2006 to $20.94 as a result of lower natural gas prices realized and an increase in operating costs. The Company also recorded additional general and administrative expenses related to doubtful accounts receivable balances in the fourth quarter of 2007.
Funds used in operations for the fourth quarter of 2007 were $282,000 - a decrease of $1,371,000 from the fourth quarter of 2006. This decrease is due to a substantially lower operating netback in the fourth quarter of 2007, reflecting reduced natural gas prices and increases in royalties and operating expenses, and additional general and administrative expenses, as noted.
Capital Expenditures
----------------------------------------------------------------------------
Three months ended Year ended
December 31, December 31,
($000's) 2007 2006 2007 2006
----------------------------------------------------------------------------
Land and seismic 38 (33) 232 94
Drilling and completions 1,495 (704) 11,696 1,343
Equipment and facilities 1,766 (367) 10,873 2,293
Property acquisitions 20 255 12,963 720
Corporate acquisition - 23,208 - 23,208
Capitalized overhead costs 362 240 1,309 410
Other 211 56 1,377 126
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3,892 22,655 38,450 28,194
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----------------------------------------------------------------------------
Total capital expenditures for 2007 were $38,450,000 compared to $28,194,000 in 2006. The Company's initial capital program was $15,000,000 which was allocated to the first quarter drilling program focusing exclusively on the Company's lands in the Ladyfern, Mearon, Square Creek, and Drake areas. The Company drilled a total of 14 gross (8 net) wells of which 11 gross (6.5 net) were considered to be development wells and 3 gross (1.5 net) were exploratory wells. In addition, the Company completed 7 recompletion operations of existing wells. A total of 8 gross (4.5 net) wells were tied into production facilities in the first quarter of which 1 gross (0.5 net) wells were from Marauder's 2006 drilling program. The wells that were tied to production facilities in the first quarter of 2007 added incremental production of 200 boe/d. The 2007 drilling program also set up an additional 20 development and 6-8 exploratory drilling opportunities for 2008. In the first nine months of 2006, the Company was not actively engaged in exploration or development opportunities due to the sale of oil and gas assets in the first quarter.
The capital program was expanded in the third quarter of 2007 to include the acquisition of a partner's working interests in the Ladyfern, Mearon and Velma areas for cash of $12,535,000. The acquisition included approximately 280 boe/d of natural gas production with additional production behind pipe, estimated reserves of 1,040 mboe on a proven basis and 1,546 mboe on a proven plus probable basis, and 54,232 net acres of undeveloped land. The Company also completed the installation of its refrigeration plant at Ladyfern to improve the recovery of natural gas liquids and to lower the dew point of the gas entering the third-party processing facility. The plant came on line in late August and is expected to provide greater reliability of processing capabilities and generate additional processing revenues for the Company. The Company also completed the surface facilities and the tie-in of two wells at Velma which came on production in late August.
The Company's approved capital expenditures for 2008 is $8,100,000 which is expected to be incurred primarily in the first quarter and is focused on the Company's Square Creek development area in Alberta.
Share Capital
----------------------------------------------------------------------------
Three months ended Year ended
December 31, December 31,
2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted average common shares
outstanding - basic and
diluted 13,417,746 74,494,047 13,417,746 74,494,047
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----------------------------------------------------------------------------
Options to purchase 397,000 common shares at December 31, 2007 (December 31,
2006 - 110,000) were not included in the calculation of weighted average -
diluted common shares outstanding because they were anti-dilutive.
----------------------------------------------------------------------------
Outstanding securities
----------------------------------------------------------------------------
Common shares 15,970,059
Stock options 397,000
----------------------------------------------------------------------------
Total outstanding securities at December 31, 2007 16,367,059
Common shares issued in the first quarter of 2008 16,829
----------------------------------------------------------------------------
Total outstanding securities at March 31, 2008 16,383,888
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The estimated fair value of stock options of $0.50 per share (December 31, 2006 - $0.71) is amortized to expense over the three-year vesting period on a straight-line basis. In 2007, the Company recorded compensation expense of $2,513,000 (2006 - $822,000).
On December 21, 2007, the Company closed a public offering of 2,703,000 flow-through common shares at $1.85 per share for total gross proceeds of $5,000,550 ($4,395,000 net of share issuance costs). The full expenditure commitment was renounced to subscribers effective December 31, 2007 with all expenditures to be incurred by December 31, 2008. As of March 31, 2008, the Company has incurred eligible expenditures of approximately $1,000,000.
Liquidity and Capital Resources
The Company has a working capital deficiency of $24,029,000 at December 31, 2007. The Company has a $25 million revolving, demand credit facility with its bank (the "Bank"), bearing interest at the Bank's prime lending rate plus 0.25% (effective interest rate for 2007 of 6.5%) and collateralized by an interest over all present and after acquired property of the Company. The authorized limit is subject to annual review and re-determination of the Company's borrowing base by the Bank.
The credit facility has a covenant that requires the Company to maintain its working capital ratio at 1:1 or greater while the credit facility is outstanding. The working capital ratio is defined as current assets plus the unutilized portion of the credit facility divided by current liabilities less the balance drawn against the credit facility. The Company is in compliance with this covenant at December 31, 2007 but will not be at March 31, 2008. Due to the winter access nature of the Company's properties much of its capital program is conducted in the first quarter of the year causing a working capital deficiency. The Company has kept the Bank appraised of its working capital covenant.
----------------------------------------------------------------------------
As at December 31,
($000's) 2007
----------------------------------------------------------------------------
Revolving operating loan available 25,000
Working capital deficiency (24,029)
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Capital resources available 971
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----------------------------------------------------------------------------
The Company's initial capital budget for 2008 is $8,100,000. The 2008 capital program will be funded through a combination of cash flow from operations and the available credit facility. The Company is contemplating an additional equity financing in the second quarter of 2008 and has taken initial steps in this regard.
Cash provided by operating activities was $3,570,000 for 2007 compared to $741,000 for 2006. This increase is due to an increase in funds from operations in 2007 of $234,000 resulting from an increase in sales volumes, and an increase in non-cash working capital balances of $2,595,000. For the fourth quarter of 2007, funds used in operations were $282,000 compared to funds from operations of$1,089,000 - due to a decrease in the operating netback realized and additional general and administrative expenses attributed to bad debts expense incurred in the fourth quarter of 2007.
Cash used in financing activities for 2007 was $3,638,000 compared to $19,776,000. In the first quarter of 2007, the Company redeemed 23,076,923 common shares as part of the Reorganization of Signal for $30,400,000. The Company was advanced additional funds on its bank credit facilities to fund a $12,535,000 asset acquisition in July, 2007. In December of 2007, the Company completed a flow-through share offering for gross proceeds of $5,001,000 (net $4,395,000). In the first quarter of 2006 the Company used the proceeds from the sale of oil and gas assets to repay the Company's operating line of credit which had $28,600,000 drawn at that time. In addition, the Company received proceeds of $3,199,000 for the exercise of employee stock options in 2006.
Cash used in investing activities for 2007 was $36,644,000 compared to cash provided by investing activities of $55,730,000 for 2006. Cash used in investing activities for 2007 reflects capital expenditures for the Company's drilling program, new facilities and the strategic asset acquisition in July. In 2006, cash provided by investing activities reflects net cash proceeds of $91,223,000 on the sale of oil and gas assets in the first quarter of 2006 and relatively minor capital expenditures of $4,986,000 due to the downsizing of its operations in 2006.
Related Party Transactions
In 2007, the Company was charged $522,000 in legal fees by a law firm where a director of the Company is a partner, of which $212,000 is included in accounts payable and accrued liabilities at December 31, 2007.
All related party transactions are in the normal course of business and have been measured at the agreed to exchange amounts, which are the amounts of consideration established and agreed to by the related parties and which are similar to those negotiated with third parties.
Subsequent Events
Subsequent to December 31, 2007, the Company issued a letter of credit for $1,000,000 with an expiry of February 1, 2009 related to a gas transportation and processing agreement (refer to note 13 to the consolidated financial statements).
On January 1, 2008, the Company amalgamated with its subsidiary companies.
Commitments and Contingencies
Royalties
The Company will pay to various university research centers royalties amounting to two - five percent on sales of licensed products related to a research contract and acquired technology rights and 15% of sublicense revenues from products related to the acquired technology rights. At December 31, 2007 and 2006, there were no royalties payables under these agreements. These agreements relate to a predecessor company which was a cancer drug discovery enterprise.
Office space and equipment
The Company is committed to minimum annual lease payments under operating
leases for office premises and office equipment to March, 2013, as follows:
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($000's)
----------------------------------------------------------------------------
2008 431
2009 430
2010 435
2011 439
Thereafter 549
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2,284
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Transportation and Processing
On November 27, 2007, the Company entered into an agreement with an affiliate of AltaGas Income Trust ("AltaGas") for the transportation and processing of natural gas from the Company's Square Creek, Alberta area. The agreement requires the Company to construct a 41 km pipeline from a central point in the Square Creek development area to the AltaGas processing facility at Clear Prairie to enable the delivery and sale of natural gas. Upon commissioning of the pipeline, which is expected in early April 2008, AltaGas has agreed to purchase the pipeline from the Company. In exchange, the Company has committed to pay the greater of a fee calculated as monthly volumes at an established rate per mcf, or an established minimum monthly processing fee based on estimated gas throughput of 2 mmcf per day until the costs of the pipeline have been recovered, at which time the Company will pay a reduced monthly processing fee until the earlier of April 1, 2015 or the delivery of a total of 15 bcf.
Committed payments are as follows:
----------------------------------------------------------------------------
($000's)
----------------------------------------------------------------------------
2008 949
2009 1,260
2010 1,052
2011 767
2012 767
Thereafter 1,605
----------------------------------------------------------------------------
6,400
----------------------------------------------------------------------------
The Company's joint interest partner in the Square Creek area has agreed to be responsible for all terms and conditions of the agreement related to their 50% working interest in this area. Committed payments, as noted above, represents only the Company's 50% working interest. Included in accounts receivable at December 31, 2007 is $745,000 due from AltaGas that relates to preliminary construction costs incurred by the Company.
Drilling Commitments
As at December 31, 2007, the Company had committed to drill a well in the Square Creek area pursuant to a farm-in agreement, at an estimated cost of $650,000. In January, 2008, the Company drilled this well and satisfied the terms of the agreement.
Guarantees
The Company maintains liability insurance for its directors and officers and indemnifies its directors and officers against any and all claims or losses reasonably incurred in the performance of their service to the Company to the extent permitted by law.
Claims and Litigation
The Company is involved in various claims and litigation arising in the normal course of business. The outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company's favor. If the outcome is unfavorable, it could have a materially adverse impact on the Company's financial position or results of operations.
SELECTED QUARTERLY INFORMATION
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----------------------------------------------------------------------------
2007 2006
Q4 Q3(1) Q2(1) Q1 Q4 Q3 Q2 Q1
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Production:
Natural gas
(mcf/d) 7,455 6,111 5,082 4,699 3,010 1,777 1,833 4,366
Oil and NGL's
(bbl/d) 13 7 29 22 20 35 69 263
Barrels of
oil
equivalent
(boe/d) 1,256 1,025 876 805 522 331 375 991
Average
realized
price:
Natural gas
($/mcf) 6.19 5.07 6.86 7.47 7.19 5.31 6.04 7.86
Oil and NGLs
($/bbl) 86.95 71.42 52.14 60.56 57.19 65.43 57.08 59.62
Barrels of
oil
equivalent
($/boe) 38.07 30.68 41.52 45.48 44.13 35.46 40.08 50.45
Benchmark
prices:
AECO average
price ($/mcf) 6.00 5.12 7.11 7.37 6.89 5.68 6.02 7.58
Edmonton Par
($/bbl) 80.75 80.70 72.65 67.86 65.24 80.26 80.43 68.90
Financial
($000's
unless
otherwise
noted):
Petroleum and
natural gas
sales 4,396 2,893 3,310 3,296 2,149 1,079 1,362 4,500
Net income
(loss) (5,442) (1,603) (617) (308) (5,635) (13) 270 13,440
Net income
(loss) per
share - basic
($) (0.39) (0.12) (0.05) (0.02) (0.07) (0.00) 0.00 0.19
Net income
(loss) per
share -
diluted ($) (0.39) (0.12) (0.05) (0.02) (0.07) (0.00) 0.00 0.19
Funds from
(used in)
operations (282) 505 1,147 1,558 1,089 821 17 687
Operating
costs($/boe) 15.26 10.31 8.23 8.82 5.73 8.51 13.13 13.07
Weighted
average
shares
outstanding-
basic('000) 13,561 13,266 13,258 13,262 81,439 73,266 72,595 70,598
Weighted
average
shares
outstanding-
diluted
('000) 13,561 13,266 13,258 13,262 81,439 73,266 73,316 71,239
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(1) Restated to eliminate the effect of realized gains on commodity
contracts.
Disclosure Controls and Procedures
Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to the Company's management as appropriate to allow timely decisions regarding required disclosure. The Company's Chief Executive Officer and Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by the annual filings, that the Company's disclosure controls and procedures as of the end of such period are effective to provide reasonable assurance that material information related to the Company, including its consolidated subsidiaries, is made known to them by others within those entities. It should be noted that while the Company's Chief Executive Officer and Chief Financial Officer believe that the Company's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Internal Controls over Financial Reporting
The Company has conducted a review of the design of its internal controls over financial reporting, with the conclusion that as at December 31, 2007, the Company's system of internal controls over financial reporting is sufficiently designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the Company's GAAP. In its assessment, the Company identified certain material weaknesses in the design of its internal controls over financial reporting:
a) due to the small number of staff, it is not feasible to achieve the complete segregation of incompatible duties; and
b) due to the small number of staff, the Company relies upon third parties as participants in the Company's internal controls over financial reporting and accounting for income taxes.
The Company believes these weaknesses are mitigated by: the active involvement of senior management and the board of directors in all the affairs of the Company; open lines of communication within the Company; the present levels of activities and transactions within the Company being readily transparent; the thorough review of the Company's financial statements by management, the board of directors and by the Company's auditors. In addition, the Company has increased the size of its finance team in 2007. However, these mitigating factors will not necessarily prevent the likelihood that a material misstatement will not occur as a result of the aforesaid weaknesses in the Company's internal controls over financial reporting. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met.
Changes in Accounting Policies and Practices
Effective January 1, 2007, the Company adopted six new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA"): Handbook Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income" and Section 3251 "Equity".
The adoption of these standards did not impact January 1, 2007 opening balances.
(i) Financial instruments - recognition and measurement
Section 3855 establishes standards for recognizing and measuring financial assets, financial liabilities, and non-financial derivatives. It requires that financial assets and financial liabilities, including derivatives, be recognized on the balance sheet when the Company becomes a party to the contractual provisions of the financial instrument or non-financial derivative contract. Under this standard, all financial instruments are required to be measured at fair value upon initial recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for sale, held-to-maturity, loans or receivables, or other financial liabilities. Financial assets and financial liabilities held for-trading are measured at fair value with changes in those fair values recognized in net earnings. Financial assets held-to-maturity, loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method of amortization. Investments in equity instruments classified as available-for-sale that do not have a quoted market price in an active market are measured at cost.
Cash and cash equivalents and risk management assets are designated as "held-for-trading". Accounts receivable are designated as "loans or receivables". The revolving operating loan and accounts payable and accrued liabilities are designated as "other liabilities".
Derivative instruments are recorded on the balance sheet at fair value, including those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. Changes in the fair values of derivative instruments are recognized in net earnings, with the exception of derivatives designated as effective cash flow hedges and hedges of the foreign currency exposure of a net investment in a self-sustaining foreign operation, which are recognized in other comprehensive income. In addition, Section 3855 requires that an entity must select an accounting policy of either expensing debt issue costs as incurred or applying them against the carrying value of the related asset or liability. The Company's policy is to expense debt issue costs as incurred.
(ii) Hedges
Section 3865 provides alternative treatments to Section 3855 for entities which choose to designate qualifying transactions as hedges for accounting purposes. It replaces and expands on Accounting Guideline 13 "Hedging Relationships", and the hedging guidance in Section 1650 "Foreign Currency Translation" by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. The Company has elected not to apply hedge accounting to its financial instruments.
(iii) Accounting changes
Section 1506 provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impracticable to determine. As well, voluntary changes in an accounting policy are to be made only when required by a primary source of GAAP or the change results in more relevant and reliable information.
(iv) Comprehensive income (loss) and accumulated other comprehensive income (loss)
Section 1530 introduces comprehensive income, which consists of net earnings and other comprehensive income ("OCI"). OCI represents changes in shareholder's equity during a period arising from transactions and changes in prices, markets, interest rates, and exchange rates. OCI includes unrealized gains and losses on financial assets classified as available-for-sale, unrealized translation gains and losses arising from self-sustaining foreign operations net of hedging activities and changes in the fair value of the effective portion of cash flow hedging instruments.
New Canadian Accounting Pronouncements
(i) On December 1, 2006, the CICA issued three new accounting standards: Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments - Disclosures, and Handbook Section 3863, Financial Instruments - Presentation. These new standards are effective January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital; (ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments - Disclosure and Presentation, revising and enhancing its disclosure requirements, and carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. We are currently assessing the impact of these new standards on our financial statements.
(ii) The Canadian Accounting Standards Board (AcSB) has confirmed that the use of International Financial Reporting Standards ("IFRS") will be required in 2011 for publicly accountable profit-oriented enterprises. IFRS will replace Canada's current GAAP for those enterprises. These include listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. The official changeover date is for interim and annual financial statements relating to fiscal years beginning on or after Jan. 1, 2011. Companies will be required to provide comparative IFRS information for the previous fiscal year. Fortress is currently evaluating the impact of adopting IFRS.
BUSINESS RISKS and UNCERTAINTIES
Fortress' production and exploration activities are concentrated in the Western Canadian Sedimentary Basin, where activity is highly competitive and includes a variety of different sized companies ranging from smaller junior producers to the much larger integrated petroleum companies. Fortress is subject to the various types of business risks and uncertainties including:
- finding and developing oil and natural gas reserves at economic costs;
- production of oil and natural gas in commercial quantities; and
- marketability of oil and natural gas produced.
In order to reduce exploration risk, the Company strives to employ highly qualified and motivated professional employees with a demonstrated ability to generate quality proprietary geological and geophysical prospects. To help maximize drilling success, Fortress combines exploration in areas that afford multi-zone prospect potential, targeting a range of low to moderate risk prospects with some exposure to select high-risk with high-reward opportunities. The Company explores in areas where the Company has drilling experience.
The Company mitigates its risk related to producing hydrocarbons through the utilization of the most appropriate technology and information systems. In addition, the Company seeks to maintain operational control of its prospects.
Oil and gas exploration and production can involve environmental risks such as pollution of the environment and destruction of natural habitat, as well as safety risks such as personal injury. In order to mitigate such risks, Fortress conducts its operations at high standards and follows safety procedures intended to reduce the potential for personal injury to employees, contractors and the public at large. The Company maintains current insurance coverage for general and comprehensive liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect changing corporate requirements, as well as industry standards and government regulations. Fortress may periodically use financial or physical delivery hedges to reduce its exposure against the potential adverse impact of commodity price volatility, as governed by formal policies approved by senior management subject to controls established by the Board of Directors.
CRITICAL ACCOUNTING ESTIMATES
The reader is advised that the critical accounting estimates, policies, and practices as described in this MD&A and report continue to be critical in determining Fortress' financial results.
The reader is further cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes. Changes in these judgments and estimates could have a material impact on the financial results and financial condition. The following discussion outlines accounting policies and practices that are critical to determining the Company's financial results:
Accounting for Petroleum and Natural Gas Operations
The Company follows the full cost method of accounting whereby all costs relating to the acquisition of, exploration for and development of oil and gas reserves are capitalized in a single Canadian cost center. Such costs include lease acquisition, lease rentals on undeveloped properties, geological and geophysical costs, drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities.
The application of the full cost method of accounting requires management's judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper income tax treatment of the costs incurred.
Full cost accounting depends on the estimated proven reserves that are believed to be recoverable from the Company's oil and gas properties. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. Our reserve estimates are based on current production forecasts, prices and economic conditions. Fortress' reserves were evaluated by the independent engineering firm Sproule Associates Ltd.
Reserve estimates are critical to many of our accounting estimates, including:
- Calculating our unit-of-production depletion and future site restoration rates. Proven reserve estimates are used to determine rates that are applied to each unit-of-production in calculating depletion expense.
- Assessing when necessary, oil and gas assets for possible impairment. Estimated future undiscounted cash flows are determined using proven reserves. The criteria used to assess impairment, including the impact of changes in reserve estimates, are discussed below.
As circumstances change and additional data becomes available, reserve estimates also change, possibly materially impacting net income. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.
Although we make every reasonable effort to ensure that our reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to our reserve estimates can arise from changes in oil and gas prices, and reservoir performance. Such revisions can be either positive or negative.
It would take a very significant decrease in our proven reserves to limit our ability to borrow money under our credit facility.
Impairment of Petroleum and Natural Gas Properties
The Company reviews its full cost pool for impairment annually. An impairment provision is recorded whenever events or circumstances indicate that the carrying value of the Company's properties may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and probable petroleum and natural gas reserves, as estimated by the Company on the balance sheet date. Reserve estimates, as well as estimates for petroleum and natural gas prices and production costs may change, and there can be no assurance that impairment provisions will not be required in the future.
Management's assessment of, among other things, the results of exploration activities, commodity price outlooks, and planned future development and sales, impacts the amount and timing of impairment provisions.
Asset Retirement Obligations
The asset retirement obligations provision recorded in the consolidated financial statements is based on an estimate for total costs for future site restoration and abandonment of the Company's petroleum and natural gas properties. This estimate is based on management's analysis of production structure, reservoir characteristics and depth, market demand for equipment, currently available procedures, and discussions with construction and engineering consultants. Estimating these future costs requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including changing technology, political and regulatory environments.
Income Taxes
The Company records future tax assets and liabilities to account for the expected future tax consequences of events that have been recorded in its consolidated financial statements and its tax returns. These amounts are estimates; the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash flows and capital expenditures in current and future periods. The Company periodically assesses its ability to realize on its future tax assets. If Fortress concluded that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset will be reduced by a valuation allowance.
Claims and Litigation
The Company is involved in various claims and litigation arising in the normal course of business. The outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company's favor. If the outcome is unfavorable, it could have a materially adverse impact on the Company's financial position or results of operations.
With the above risks and uncertainties, the reader is cautioned that future events and results may vary significantly from that which Fortress currently foresees.
MANAGEMENT'S RESPONSIBILITY FOR THE FINANCIAL STATEMENTS
The accompanying consolidated financial statements and all information in this report are the responsibility of management. The consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. Financial statements are not precise since they include certain amounts based upon estimates and judgments. When alternative accounting methods exist, management has chosen those it deems to be the most appropriate to ensure fair and consistent presentation. The financial information presented elsewhere in this report is consistent with that in the financial statements.
Management maintains financial and operating systems that include appropriate and effective internal controls. Such systems are designed to provide reasonable assurance that the financial information is reliable and relevant, and the Company's assets are appropriately accounted for and adequately safeguarded.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and is ultimately responsible for reviewing and approving the financial statements. The Board of Directors carries out this responsibility principally through its Audit Committee.
The Audit Committee, with all of its members being outside directors, is appointed by the Board of Directors and reviews the financial statements and Management's Discussion and Analysis; assesses the adequacy of the internal controls of the Company; considers the report of the external auditors; examines the fees and expenses for audit services; and recommends to the Board of Directors the independent auditors for appointment by the shareholders. The Audit Committee reports its findings to the Board of Directors for consideration when approving the annual financial statements for issuance to the shareholders.
These consolidated financial statements have been audited by Ernst & Young LLP, the external auditors, in accordance with Canadian generally accepted auditing standards, on behalf of the shareholders. Ernst & Young LLP have full and free access to, and meet periodically with, the Audit Committee.
"signed" "signed"
J. Cameron Bailey Jamie Jeffs, C.A.
President & CEO Chief Financial Officer
AUDITORS' REPORT
To the Shareholders of Fortress Energy Inc.
We have audited the consolidated balance sheets of Fortress Energy Inc. as at December 31, 2007 and 2006 and the consolidated statements of operations, comprehensive income (loss) and deficit and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2007 and 2006 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.
Calgary, Canada "signed"
Ernst & Young LLP
March 28, 2008 Chartered Accountants
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FORTRESS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
As at December 31
(in thousands)
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------
ASSETS (note 7)
Current Assets
Cash and cash equivalents (note 3) $ 44 $ 36,756
Accounts receivable and accrued revenue 7,964 7,951
Prepaid expenses and deposits 565 368
Commodity contracts (note 12) 92 -
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8,665 45,075
Property, plant and equipment (note 5) 99,265 70,579
----------------------------------------------------------------------------
$ 107,930 $ 115,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities (note 15) $ 10,101 $ 7,080
Income taxes payable - 283
Revolving operating loan (note 7) 22,593 -
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32,694 7,363
Future income taxes (note 8) 2,180 5,052
Asset retirement obligations (note 9) 3,050 1,678
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37,924 14,093
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Commitments and contingencies (notes 13 and 16)
Shareholders' Equity
Share capital (note 10) 121,274 157,508
Contributed surplus (note 10) 14,428 1,779
Deficit (65,696) (57,726)
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70,006 101,561
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$ 107,930 $ 115,654
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See accompanying notes to consolidated financial statements.
On behalf of the Board of Directors:
"signed" "signed"
J. Cameron Bailey Will Franklin
Director Director
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FORTRESS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS) AND
DEFICIT
For the years ended December 31
(in thousands, except per share amounts)
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------
REVENUES
Petroleum and natural gas sales $ 13,895 $ 9,090
Royalties (net of Alberta Royalty Tax Credit) (2,688) (1,398)
Interest income 219 1,931
Realized gain on commodity contracts (note 12) 393 -
Unrealized gain on commodity contracts (note 12) 92 -
----------------------------------------------------------------------------
11,911 9,623
----------------------------------------------------------------------------
EXPENSES
Operating 4,030 2,161
General and administrative (note 15) 3,786 4,350
Stock-based compensation (note 11) 2,513 822
Interest 1,075 498
Depletion, depreciation and accretion (note 5) 11,192 4,955
----------------------------------------------------------------------------
22,596 12,786
----------------------------------------------------------------------------
Loss before the following (10,685) (3,163)
----------------------------------------------------------------------------
OTHER ITEMS
Gain on sale of oil and gas property, plant and
equipment (note 5) - 15,835
Goodwill impairment (note 6) - (4,548)
----------------------------------------------------------------------------
- 11,287
----------------------------------------------------------------------------
Income (loss) before income taxes (10,685) 8,124
----------------------------------------------------------------------------
Income tax expense (recovery) (note (8)
Current - -
Future (2,715) 36
----------------------------------------------------------------------------
(2,715) 36
----------------------------------------------------------------------------
Net income (loss) and comprehensive income (loss)
for the year (7,970) 8,088
Deficit, beginning of year (57,726) (65,814)
----------------------------------------------------------------------------
Deficit, end of year $ (65,696) $ (57,726)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per share (note 10)
Basic ($0.59) $0.11
Diluted ($0.59) $0.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
----------------------------------------------------------------------------
FORTRESS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31
(in thousands)
----------------------------------------------------------------------------
2007 2006
----------------------------------------------------------------------------
CASH PROVIDED BY (USED IN):
OPERATING ACTIVITIES
Net income (loss) for the year $ (7,970) $ 8,088
Items not affecting cash flows:
Unrealized gain on commodity contracts (92) -
Stock-based compensation 2,513 822
Depletion, depreciation and accretion 11,192 4,955
Gain on sale of oil and gas property, plant and
equipment - (15,835)
Goodwill impairment - 4,548
Future income tax expense (recovery) (2,715) 36
Abandonment expenditures (80) -
----------------------------------------------------------------------------
2,848 2,614
Change in non-cash operating working capital
(note 14) 722 (1,873)
----------------------------------------------------------------------------
Cash provided by operating activities 3,570 741
----------------------------------------------------------------------------
FINANCING ACTIVITIES
Change in revolving operating loan 22,593 (22,975)
Redemption of common shares (note 10) (30,440) -
Purchase of common shares (note 10) (186) -
Issuance of common shares on exercise of stock
options - 3,199
Issuance of flow-through common shares 5,001 -
Share issuance costs (606) -
----------------------------------------------------------------------------
Cash used in financing activities (3,638) (19,776)
----------------------------------------------------------------------------
INVESTING ACTIVITIES
Property, plant and equipment additions (25,915) (4,986)
Sale of property, plant and equipment, net of
transaction costs - 91,223
(note 5)
Acquisition of businesses (note 4) (12,535) (23,208)
Change in non-cash investing working capital
(note 14) 1,806 (7,299)
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Cash provided by (used in) investing activities (36,644) 55,730
----------------------------------------------------------------------------
Net change in cash (36,712) 36,695
Cash and cash equivalents - beginning of year 36,756 61
----------------------------------------------------------------------------
Cash and cash equivalents - end of year $ 44 $ 36,756
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplemental cash flow information (note 14)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.
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FORTRESS ENERGY INC.
Notes to Consolidated Financial Statements
December 31, 2007 and 2006
(Tabular figures are in thousands of Canadian dollars unless otherwise
indicated)
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1. NATURE OF OPERATIONS
Fortress Energy Inc. ("Fortress" or the "Company" formerly SignalEnergy Inc.) is a Calgary-based junior oil and gas exploration and development company. All activity is conducted in Western Canada and comprises a single operating segment.
Effective February 20, 2007, SignalEnergy Inc. ("Signal") completed a reorganization whereby all of its assets were transferred to Fortress and a significant number of Signal shares were redeemed for cash (refer to notes 2 and 10).
2. SIGNIFICANT ACCOUNTING POLICIES
The consolidated financial statements of the Company have been prepared by management in accordance with Canadian generally accepted accounting principles. The timely preparation of financial statements requires that management make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from estimates.
On February 20, 2007, Signal and Fortress reorganized, as follows (refer to note 10 for a continuity of Fortress' and Signal's share capital):
(i) Signal redeemed 23,076,923 common shares for cash at a price of $1.30 per share;
(ii) Fortress issued 13,307,815 common shares from treasury to Signal's shareholders in exchange for all of Signal's outstanding shares;
(iii) Out-of-pocket transaction costs of $440,000 were incurred.
This reorganization was accounted for as a continuity of interests. The balance sheet and share capital as presented are of Fortress as a legal entity. The assets, liabilities, and dollar amounts attributed to share capital are those of Signal. The financial position, results of operations and cash flow for all periods prior to the Reorganization are those of Signal.
In the opinion of management, these consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.
(a) Consolidation
The consolidated financial statements of the Company include the accounts of the Company and its wholly-owned subsidiaries. All inter-company transactions and balances have been eliminated.
(b) Joint operations
Substantially all of the Company's exploration, development and production activities are conducted jointly with others and, accordingly, these consolidated financial statements reflect only the Company's proportionate interest in such activities.
(c) Cash and cash equivalents
Cash and cash equivalents include short-term investments with an original maturity of three months or less from the date of purchase. Cash and cash equivalents are stated at cost, which approximates market value.
(d) Property, plant and equipment
The Company follows the full cost method of accounting whereby all costs relating to the acquisition of, exploration for and development of oil and gas reserves are capitalized and accumulated in a single Canadian cost center. Such costs include lease acquisition, lease rentals on undeveloped properties, geological and geophysical, drilling of both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities.
Proceeds from the disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such disposition would alter the depletion and depreciation rate by 20% or more.
Other capital assets include furniture and fixtures and are recorded at cost.
(e) Depletion and depreciation
All costs of acquisition, exploration and development of oil and gas reserves, associated with plant and equipment costs (net of salvage value), and estimated costs of future development of proven undeveloped reserves are depleted using the unit-of-production method based on estimated gross proven reserves as determined by the Company's independent reserve engineers.
Costs of unproved properties and seismic costs on undeveloped land are initially excluded from oil and gas properties for the purpose of calculating depletion. When proven reserves are assigned or the property or seismic costs are considered impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.
The relative volume of oil and natural gas reserves and production are converted to equivalent barrels of oil based on the relative energy content of one barrel of oil being equal to six thousand cubic feet of natural gas.
Capital assets not related to oil and gas properties are depreciated over their estimated useful lives using the straight-line method at annual rates of 20% to 100%.
(f) Impairment of property, plant and equipment
A ceiling test is performed to recognize and measure impairment, if any, of the carrying amount of oil and gas properties and equipment by comparing the carrying amount of property and equipment to the sum of undiscounted cash flows expected to result from the future production of proven reserves and the cost of unproved properties less any impairment. Cash flows are based on a forecast of prices and costs, adjusted for transportation and quality, as provided by the Company's independent reserve engineers. Should this result in an excess of carrying value, the Company would then measure the amount of impairment by comparing the carrying amounts of property and equipment to the sum of the estimated net present value of future cash flows from proven plus probable reserves and the cost of unproved properties less any impairment. A risk-free interest rate is used to arrive at the net present value of the future cash flows. Any excess is recorded as additional depletion in the period the impairment is identified.
The carrying value of undeveloped properties (land and seismic data) is reviewed periodically and written down to net realizable value if impairment is determined.
(g) Asset retirement obligations
Asset retirement obligations include the costs of abandonment of oil and gas wells, dismantling and removing tangible equipment, and returning land to its original condition.
The fair value of estimated asset retirement obligations is recognized in the consolidated financial statements in the period in which they are identified and when a reasonable estimate of the fair value can be made. The fair value is determined through a review of engineering studies, industry guidelines, and management's estimate on a site-by-site basis. The asset retirement cost, equal to the estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset.
The liability is subsequently adjusted for the passage of time, which is recognized as accretion expense in the consolidated statement of operations. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. The increase in the carrying value of the asset is amortized using the unit of production method based on estimated gross proven reserves, as determined by independent engineers. Actual costs incurred upon settlement of the asset retirement obligations are charged against the asset retirement obligation to the extent of the liability recorded. Any difference between the actual costs incurred upon settlement of the asset retirement obligation and the recorded liability is charged to property, plant and equipment in the period in which the settlement occurs unless the settlement represents abandonment of the last well in the cost centre, in which case the difference is charged to the consolidated statement of operations.
(h) Goodwill
Goodwill, at the time of acquisition, represents the excess of purchase price of a business over the fair value of net identifiable assets acquired in the business combination. The Company assesses the carrying amount of goodwill for impairment on an annual basis, or more frequently when changes in circumstances indicate that impairment may exist. The amount of impairment loss, if any, is charged to the consolidated statement of operations in the period the impairment is identified.
(i) Flow-through shares
A portion of the Company's exploration and development activities is financed through proceeds received from the issuance of flow-through shares. Under the terms of the flow-through share issues, the tax attributes of the related expenditures are renounced to the share subscribers. To recognize the foregone tax benefits to the Company, the carrying value of the shares issued is reduced by the tax effect of the tax benefits renounced to the subscribers. The tax effect of the renouncement is recorded when the required documents are filed with the tax authorities and the corresponding exploration and development expenditures are incurred or there is reasonable certainty they will be incurred within the permitted time frame.
(j) Stock-based compensation
The Company has a stock based compensation plan, which is described in note 11. The Company accounts for stock-based compensation using the fair value method whereby compensation expense is recognized over the vesting period based on the fair value of stock options at the date of grant. The fair value of stock options granted is determined using the Black-Scholes option-pricing model and is recorded as compensation expense and contributed surplus. Contributed surplus is reduced as stock options are exercised and credited to share capital.
(k) Revenue recognition
Petroleum and natural gas sales are recognized as revenue when the commodities are delivered to purchasers. The costs associated with the delivery, including operating and transportation, are recognized in the same period in which the related revenue is earned and recorded.
(l) Future income taxes
The Company follows the liability method of accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future income tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change is substantively enacted. Income tax expense for the period is the tax payable for the period and any change during the period in future income tax assets and liabilities. A valuation allowance is recorded to the extent that the realization of future tax assets is not more likely than not.
(m) Measurement uncertainty
The operations of the Company are complex, and regulations and legislation affecting the Company are continually changing. Although the ultimate impact of these matters on the net income or loss cannot be determined at this time, it could be material for any one quarter or year. Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and revenues and expenses during the reporting year. Actual results can differ from those estimates.
Recorded amounts for depletion and depreciation of petroleum and natural gas properties and equipment are based on estimates. The ceiling test and impairment calculations are based on estimates of oil and natural gas reserves, future costs required to develop those reserves and the fair value of unproved properties. By their nature, these estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the effect on the consolidated financial statements of future years could be significant.
The capital expenditures classification made with respect to the renouncement of flow-through shares is based on estimates from geological and geophysical information obtained and the classification of the expenditures may be challenged by the taxation authorities and in this regard the assessments may be different from that of management. By their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes of estimates in future years could be significant.
The consolidated financial statements include accruals based on the terms of existing joint venture agreements. Due to varying interpretations of the definition of terms in these agreements the accruals made by management in this regard may be significantly different from those determined by the Company's joint venture partners. The effect on the consolidated financial statements resulting from such adjustments, if any, will be reflected prospectively.
Option pricing models require the input of highly subjective assumptions including the expected stock price volatility. By their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes of estimates in future years could be significant.
(n) Per share amounts
The treasury stock method is used in the determination of diluted earnings per share. Under this method, the diluted weighted average number of shares is calculated assuming the proceeds that arise from the exercise of outstanding in-the-money options are used to purchase common shares of the Company at their average market price for the applicable period.
(o) Investment tax credits
Investment tax credits are applied against expenses or the related capital assets when it is reasonably certain that they will be realized. Ultimate realization will depend on the review and approval by the tax authorities concerned.
(p) Comparative figures
Certain comparative figures have been reclassified to conform to the presentation adopted in the current year.
(q) Changes in accounting policies
Effective January 1, 2007, the Company adopted five new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA"): Handbook Section 3855 "Financial Instruments - Recognition and Measurement", Section 3861 "Financial Instruments - Disclosure and Presentation", Section 3865 "Hedges", Section 1506 "Accounting Changes", Section 1530 "Comprehensive Income" and Section 3251 "Equity".
The adoption of these standards did not impact January 1, 2007 opening balances.
(i) Financial instruments - recognition and measurement
Section 3855 establishes standards for recognizing and measuring financial assets, financial liabilities, and non-financial derivatives. It requires that financial assets and financial liabilities, including derivatives, be recognized on the balance sheet when the Company becomes a party to the contractual provisions of the financial instrument or non-financial derivative contract. Under this standard, all financial instruments are required to be measured at fair value upon initial recognition except for certain related party transactions. Measurement in subsequent periods depends on whether the financial instrument has been classified as held-for-trading, available-for sale, held-to-maturity, loans or receivables, or other financial liabilities. Financial assets and financial liabilities held for-trading are measured at fair value with changes in those fair values recognized in net earnings. Financial assets held-to-maturity, loans and receivables, and other financial liabilities are measured at amortized cost using the effective interest method of amortization. Investments in equity instruments classified as available-for-sale that do not have a quoted market price in an active market are measured at cost.
Cash and cash equivalents and risk management assets are designated as "held-for-trading". Accounts receivable are designated as "loans or receivables". The revolving operating loan and accounts payable and accrued liabilities are designated as "other liabilities".
Derivative instruments are recorded on the balance sheet at fair value, including those derivatives that are embedded in financial or non-financial contracts that are not closely related to the host contracts. Changes in the fair values of derivative instruments are recognized in net earnings, with the exception of derivatives designated as effective cash flow hedges and hedges of the foreign currency exposure of a net investment in a self-sustaining foreign operation, which are recognized in other comprehensive income. In addition, Section 3855 requires that an entity must select an accounting policy of either expensing debt issue costs as incurred or applying them against the carrying value of the related asset or liability. The Company's policy is to expense debt issue costs as incurred.
(ii) Hedges
Section 3865 provides alternative treatments to Section 3855 for entities which choose to designate qualifying transactions as hedges for accounting purposes. It replaces and expands on Accounting Guideline 13 "Hedging Relationships", and the hedging guidance in Section 1650 "Foreign Currency Translation" by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. The Company has elected not to apply hedge accounting to its financial instruments.
(iii) Accounting changes
Section 1506 provides expanded disclosures for changes in accounting policies, accounting estimates and corrections of errors. Under the new standard, accounting changes should be applied retrospectively unless otherwise permitted or where impracticable to determine. As well, voluntary changes in an accounting policy are to be made only when required by a primary source of GAAP or the change results in more relevant and reliable information.
(iv) Comprehensive income (loss) and accumulated other comprehensive income (loss)
Section 1530 introduces comprehensive income, which consists of net earnings and other comprehensive income ("OCI"). OCI represents changes in shareholder's equity during a period arising from transactions and changes in prices, markets, interest rates, and exchange rates. OCI includes unrealized gains and losses on financial assets classified as available-for-sale, unrealized translation gains and losses arising from self-sustaining foreign operations net of hedging activities and changes in the fair value of the effective portion of cash flow hedging instruments.
(r) Future accounting changes
(i) On December 1, 2006, the CICA issued three new accounting standards: Handbook Section 1535, Capital Disclosures, Handbook Section 3862, Financial Instruments - Disclosures, and Handbook Section 3863, Financial Instruments - Presentation. These new standards are effective January 1, 2008. Section 1535 specifies the disclosure of (i) an entity's objectives, policies and processes for managing capital; (ii) quantitative data about what the entity regards as capital; (iii) whether the entity has complied with any capital requirements; and (iv) if it has not complied, the consequences of such non-compliance. The new Sections 3862 and 3863 replace Handbook Section 3861, Financial Instruments - Disclosure and Presentation, revising and enhancing its disclosure requirements, and carrying forward unchanged its presentation requirements. These new sections place increased emphasis on disclosures about the nature and extent of risks arising from financial instruments and how the entity manages those risks. We are currently assessing the impact of these new standards on our financial statements.
(ii) The Canadian Accounting Standards Board (AcSB) has confirmed that the use of International Financial Reporting Standards ("IFRS") will be required in 2011 for publicly accountable profit-oriented enterprises. IFRS will replace Canada's current GAAP for those enterprises. These include listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders. The official changeover date is for interim and annual financial statements relating to fiscal years beginning on or after Jan. 1, 2011. Companies will be required to provide comparative IFRS information for the previous fiscal year. Fortress is currently evaluating the impact of adopting IFRS.
3. CASH AND CASH EQUIVALENTS
Cash and cash equivalents consist of cash on hand and a short-term
investment as follows:
---------------------------------------------------------------------------
2007 2006
$ $
---------------------------------------------------------------------------
Cash on hand 44 1,708
Short-term investment - 35,048
---------------------------------------------------------------------------
44 36,756
---------------------------------------------------------------------------
---------------------------------------------------------------------------
4. BUSINESS ACQUISITIONS
(a) Effective November 15, 2006, the Company acquired all of the issued and outstanding common shares of Marauder Resources West Coast Inc. ("Marauder") for consideration of $33,990,716, consisting of $15,000,000 of cash, 16,349,534 common shares of the Company valued at $17,330,506, and transaction and severance costs of $1,660,210. The common shares issued were valued at $1.06 per share based on the Company's trading price for the five-day period prior to and the five-day period immediately following the announcement of this transaction.
The acquisition has been accounted for using the purchase method and the results of operations are included in the consolidated statement of operations from the effective date of November 15, 2006. The purchase price was allocated to the assets and liabilities, as follows:
---------------------------------------------------------------------------
$
---------------------------------------------------------------------------
Property, plant and equipment 46,794
Non-cash working capital deficiency (1,651)
Future income tax liability (3,994)
Asset retirement obligations (610)
Bank indebtedness (6,548)
---------------------------------------------------------------------------
33,991
---------------------------------------------------------------------------
Consideration:
Cash 15,000
16,349,534 common shares 17,331
Transaction costs 1,660
---------------------------------------------------------------------------
33,991
---------------------------------------------------------------------------
(b) Effective July 18, 2007 the Company acquired its partner's working interests in the Ladyfern, Mearon and Velma areas for $12,535,000, including transaction costs of $48,000 and the assumption of asset retirement obligations of $370,000. The acquisition included 54,232 net acres of undeveloped land.
The acquisition has been accounted for using the purchase method and the results of operations are included in the consolidated statement of operations from the effective date of July 18, 2007. The purchase price was allocated to the assets and liabilities, as follows:
---------------------------------------------------------------------------
$
---------------------------------------------------------------------------
Property, plant and equipment 12,905
Asset retirement obligations (370)
---------------------------------------------------------------------------
12,535
---------------------------------------------------------------------------
Consideration:
Cash 12,487
Transaction costs 48
---------------------------------------------------------------------------
12,535
---------------------------------------------------------------------------
5. PROPERTY, PLANT AND EQUIPMENT
---------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
December 31, 2007 $ $ $
---------------------------------------------------------------------------
Oil and gas properties 116,746 17,694 99,052
Other 319 106 213
---------------------------------------------------------------------------
117,065 17,800 99,265
---------------------------------------------------------------------------
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
December 31, 2006 $ $ $
---------------------------------------------------------------------------
Oil and gas properties 77,194 6,708 70,486
Other 146 53 93
---------------------------------------------------------------------------
77,340 6,761 70,579
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Effective February 27, 2006, the Company sold certain oil and gas properties, tangible equipment and undeveloped land for cash proceeds of $96,446,000. The transaction involved the sale of the Company's Ferrier, Carrot Creek, Kaybob, Redwater and certain other minor properties (the "Sold Properties"). The transaction costs were $1,163,000. The Company also incurred additional costs of $4,060,000 to complete its capital commitments to the purchaser. The carrying amount of the Sold Properties at the time of sale was $82,835,000 and the related asset retirement obligation was $3,387,000. The Company recorded a gain on sale of oil and gas properties and equipment of $15,835,000 in 2006.
In 2007, the Company capitalized general and administrative expenses of $1,309,000 (2006 - $410,000) directly attributable to exploration and development activities. The Company has not capitalized any stock-based compensation expense related to exploration and development activities
Estimated future development costs of $16,435,000 (December 31, 2006 - $15, 595,000) were included in the calculation of depletion expense for the year ended December 31, 2007. As at December 31, 2007, undeveloped land costs of $7,371,000 (December 31, 2006 - $3,158,000) were excluded from assets subject to depletion.
The Company performed a ceiling test calculation at December 31, 2007 which resulted in the carrying amount of the Company's oil and gas properties exceeding the estimated undiscounted future cash flows associated with the Company's proved reserves. As a result, the Company performed the second step of the ceiling test by comparing the discounted cash flows from proven plus probable reserves to the carrying amount of oil and gas properties. As a result of performing this second step, a ceiling test write down of $1,404,000 has been recorded as additional depletion and depreciation expense in the consolidated statements of operations. The oil and natural gas prices used in the ceiling test calculation are based on the January 1, 2008 commodity price forecast of our independent reserve evaluators and are as follows:
---------------------------------------------------------------------------
Edmonton Light Crude Oil AECO Gas
Year (Cdn$/bbl) (Cdn$/MMbtu)
---------------------------------------------------------------------------
2008 88.17 6.51
2009 84.54 7.22
2010 83.16 7.69
2011 81.26 7.70
2012 80.73 7.61
2013 81.25 7.78
2014 82.88 7.96
2015 84.55 8.14
2016 86.25 8.32
2017 87.98 8.51
---------------------------------------------------------------------------
Prices increase at a rate of 2% per year after 2017. The benchmark prices were adjusted for quality and transportation.
6. GOODWILL IMPAIRMENT
The Company assesses the carrying amount of goodwill for impairment on an annual basis, or more frequently when changes in circumstances indicate that impairment may exist. As part of this assessment, the Company considers the latest available information including the Company's market capitalization as indicated by the Company's share price. As a result of this assessment, the Company recorded a goodwill impairment of $4,548,000 which was reflected as a non-cash charge to the consolidated statement of operations in 2006.
7. BANK FACILITIES
The Company has a $25,000,000 revolving, demand credit facility with its bank (the "Bank"), bearing interest at the Bank's prime lending rate plus 0.25% (effective interest rate for 2007 of 6.5%) and collateralized by an interest over all present and after acquired property of the Company. The authorized limit is subject to annual review and re-determination of the Company's borrowing base by the Bank.
The credit facility has a covenant that requires the Company to maintain its working capital ratio at 1:1 or greater while the credit facility is outstanding. The working capital ratio is defined as current assets plus the unutilized portion of the credit facility divided by current liabilities less the balance drawn against the credit facility. The Company is in compliance with this covenant at December 31, 2007 but anticipates that it will not be in compliance at the end of the first quarter of 2008. Due to the winter access nature of the Company's properties much of its capital program is conducted in the first quarter of the year causing a working capital deficiency. The Company has kept the Bank appraised of its working capital covenant.
8. INCOME TAXES
The provision for income tax expense (recovery) recorded in the consolidated statement of operations differs from the amount that would be obtained by applying the statutory income tax rate to the income (loss) before tax as follows:
---------------------------------------------------------------------------
2007 2006
$ $
---------------------------------------------------------------------------
Income (loss) before tax (10,685) 8,124
---------------------------------------------------------------------------
Expected tax expense (recovery)
at 32.12% (2006 - 34.50%) (3,432) 2,803
Add (deduct) income tax effect of:
Non-deductible crown charges - 167
Resource allowance - (66)
Stock-based compensation 807 284
Non-taxable ARTC 94 (145)
Non-taxable portion of capital gain - (1,800)
Flow-through share renouncement - (1,022)
Non-deductible expenses and other permanent
differences (20) 20
Rate adjustments (164) (205)
---------------------------------------------------------------------------
Income tax expense (recovery) (2,715) 36
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Future tax assets and liabilities are comprised of:
---------------------------------------------------------------------------
2007 2006
$ $
---------------------------------------------------------------------------
Net book value of property and equipment in excess
of tax pools 3,513 6,929
Non-capital losses carried forward (210) (854)
Asset retirement obligations (793) (513)
Attributed Canadian royalty income (90) (88)
Share issue costs (240) (422)
---------------------------------------------------------------------------
Net future income tax liability 2,180 5,052
---------------------------------------------------------------------------
The Company has non-capital losses for income tax purposes of approximately $686,000 (2006 - $3.3 million) which are available for application against future taxable income and which expire in 2014.
The Company has approximately $2.4 million (2005 - $2.8 million) of unclaimed investment tax credits available to reduce the future years' income tax payable. The benefit has not been recorded for financial statement purposes. These credits will expire in the following years:
---------------------------------------------------------------------------
$
---------------------------------------------------------------------------
2008 267
2009 74
2010 279
2011 1,013
2012 734
---------------------------------------------------------------------------
2,367
---------------------------------------------------------------------------
At December 31, 2007, the Company has approximately $85.9 million of
available resource pools and undepreciated capital cost pools, as follows:
---------------------------------------------------------------------------
$
---------------------------------------------------------------------------
Canadian Oil and Gas Property Expenses 14,790
Canadian Development Expenses 26,931
Canadian Exploration Expenses 15,307
Undepreciated Capital Cost 28,788
---------------------------------------------------------------------------
85,816
---------------------------------------------------------------------------
9. ASSET RETIREMENT OBLIGATIONS
The Company's asset retirement obligations result from net ownership interests in oil and gas assets including well sites, gathering systems and processing facilities. The Company estimates the net present value of its total asset retirement obligations at December 31, 2007 to be $3.1 million (December 31, 2006 - $1.7 million) based on a total future liability of $4.8 million (December 31, 2006 - $3.1 million) which will be primarily incurred between 2008 and 2029. An inflation rate of 2.0% (2006 - 2.0%) and a credit-adjusted risk-free rate of 7.5% (2006 - 6.5%) were used to calculate the fair value of the asset retirement obligations.
---------------------------------------------------------------------------
Asset Retirement Obligations $
---------------------------------------------------------------------------
Balance, December 31, 2005 4,428
Adjustments to assumptions (92)
Liabilities incurred and acquired 639
Liabilities disposed (note 5) (3,387)
Accretion expense 90
---------------------------------------------------------------------------
Balance, December 31, 2006 1,678
Adjustments to assumptions 635
Liabilities incurred and acquired 664
Accretion expense 153
Abandonment expenditures (80)
---------------------------------------------------------------------------
Balance, December 31, 2007 3,050
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Adjustments to assumptions in 2007 of $635,000 reflect an increase in the
estimated abandonment and reclamation costs for the Ladyfern, Mearon and
Velma properties.
10. SHARE CAPITAL
(a) Authorized:
Unlimited number of voting common shares.
Unlimited number of preferred shares.
(b) Common shares issued and outstanding:
(i) SignalEnergy Inc.
---------------------------------------------------------------------------
Number of
Common Shares $
---------------------------------------------------------------------------
Balance, December 31, 2005 70,520,948 136,097
Issued on business acquisition (note 4) 16,349,534 17,331
Tax effect on flow-through share
renouncement (ii) - (1,022)
Issued on exercise of stock options 2,745,500 4,382
---------------------------------------------------------------------------
Balance, December 31, 2006 89,615,982 157,508
Redemption of common shares (iv) (23,076,923) (40,374)
Exchanged for common shares of Fortress (iv) (66,539,059) (117,134)
---------------------------------------------------------------------------
Balance, December 31, 2007 - -
---------------------------------------------------------------------------
(ii) On December 1, 2005, the Company closed a private placement of 2,000,000 flow-through common shares at $1.52 per share for total gross proceeds of $3,040,000 ($2,935,000 net of share issuance costs). The full expenditure commitment was renounced to subscribers effective December 31, 2005. The tax effect related to this flow-through offering of $1,022,000 was recorded at March 31, 2006 using a tax rate of 33.62%.
(iii) Fortress Energy Inc.
---------------------------------------------------------------------------
Number of
Common Shares $
---------------------------------------------------------------------------
Balance, December 31, 2006 - -
Issued in exchange for shares of Signal (iv) 13,307,815 117,134
Normal course issuer bid (v) (50,000) (438)
Issued in exchange for employment services (vi) 9,244 25
Issued on flow-through offering (vii) 2,703,000 5,001
Share issuance costs (vii) - (606)
Tax effect of share issuance costs - 158
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Balance, December 31, 2007 15,970,059 121,274
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(iv) A Reorganization (the "Reorganization") of SignalEnergy Inc. ("Signal"), including an arrangement (the "Arrangement") under the Companies Act (Quebec), was approved by the shareholders at a Special General Meeting of Shareholders held on February 15, 2007 and was effective on February 20, 2007.
Under the Arrangement, shareholders of Signal could elect to receive cash, common shares of Fortress, or a combination of both, subject to total cash available of $30 million. Shareholders representing 63,400,000 common shares of Signal elected to receive cash which resulted in a cash distribution to shareholders of $30,000,000 to redeem 23,076,923 common shares of Signal at $1.30 per share. The historical value of these shares of $40,374,000 was removed from share capital and the excess over the redemption price and reorganization costs of $9,934,000 was recorded as an increase in contributed surplus. The remaining 66,539,059 common shares of Signal were exchanged for common shares of Fortress on a basis of one common share of Fortress for every five common shares of Signal, resulting in the issuance of 13,307,815 common shares of Fortress.
Fortress was a shell company that was formed on January 15, 2007 for the purposes of completing the Reorganization of Signal.
(v) On December 13, 2006, the Company initiated a normal course issuer bid process whereby a maximum of 896,160 common shares (as adjusted for the Reorganization) could be repurchased beginning December 15, 2006 and terminating December 14, 2007. The Company purchased 50,000 common shares at an average price of $3.71 per share or $186,000. The historical value of these shares of $438,000 was removed from share capital and the excess over the purchase price of $252,000 was recorded as an increase in contributed surplus.
(vi) As part of an agreement with a new employee, the Company agreed to grant shares with a total market value of $50,000 to the employee, to be paid on June 30, August 31, October 31, and December 31, 2007. The actual number of shares issuable on each of these dates was based on the volume weighted-average trading price of the Company's shares for the 30-day period prior to issuance. A total of 9,244 common shares have been issued to the employee as of December 31, 2007 related to the June and August payment dates and an additional 16,829 common shares were issued in February of 2008 related to the October and December payment dates. The Company recorded stock-based compensation expense of $50,000 in 2007 related to this agreement.
(vii) On December 21, 2007, the Company closed a public offering of 2,703,000 flow-through common shares at $1.85 per share for total gross proceeds of $5,000,550 ($4,395,000 net of share issuance costs). The full expenditure commitment was renounced to subscribers effective December 31, 2007 with all expenditures to be incurred by December 31, 2008. The tax effect of the renunciation will be recorded in the first quarter of 2008 when the renouncement documents were filed.
(c) Contributed surplus:
---------------------------------------------------------------------------
Balance, December 31, 2005 2,140
Stock-based compensation expense 822
Reclassification to share capital for stock options exercised (1,183)
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Balance, December 31, 2006 1,779
Share redemption (note 10 (b)(iv)) 9,934
Normal course issuer bid (note 10 (b)(v)) 252
Stock-based compensation expense (note 11) 2,463
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Balance, December 31, 2007 14,428
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(d) Stock option plan:
The Company grants stock options to employees, officers, directors and consultants of the Company pursuant to an incentive plan (the "Plan"). Under the Plan, the exercise price of options granted cannot be less than the closing market price for the Company's common shares on the date of grant. Options vest over a three-year period and expire five years from the date of grant.
The following table summarizes stock option transactions:
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2007 2006
---------------------------------------------
Weighted Weighted
average average
exercise exercise
Number price Number price
$ $
---------------------------------------------------------------------------
Outstanding, beginning of year 110,000 4.15 4,385,500 2.01
Granted 1,568,000 3.68 - -
Cancelled (1,281,000) 4.47 (1,530,000) 1.49
Exercised - - (2,745,500) 1.17
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Outstanding, end of year 397,000 2.26 110,000 4.15
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Exercisable, end of year 22,000 20.75 110,000 4.15
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The Company has the following stock options outstanding:
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Exercisable at
Outstanding at December 31, 2007 December 31, 2007
Weighted Weighted Weighted
average Average Average
Exercise years to Exercise Number Exercise
Price Number expiry Price exercisable Price
$ $ $
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1.18 375,000 5.0 1.18 - -
19.50 - 50.00 22,000 1.4 20.75 22,000 20.75
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Outstanding,
December 31, 2007 397,000 2.26 2.26 22,000 20.75
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---------------------------------------------------------------------------
---------------------------------------------------------------------------
Exercisable at
Outstanding at December 31, 2006 December 31, 2006
Weighted Weighted Weighted
average Average Average
Exercise years to Exercise Number Exercise
Price Number expiry Price exercisable Price
$ $ $
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3.00 - 4.00 102,000 2.5 3.91 102,000 3.91
4.00 - 5.00 4,000 4.5 4.40 4,000 4.40
10.00 4,000 3.1 10.00 4,000 10.00
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Outstanding,
December 31, 2006 110,000 2.6 4.15 110,000 4.15
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Stock options outstanding at the time of the Reorganization were exchanged
for stock options of Fortress on a basis of one stock option of Fortress
for every five stock options of Signal.
(e) Per share amounts:
The weighted average number of common shares outstanding for the years
ended December 31, 2007 and 2006 are as follows:
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2007 2006
---------------------------------------------------------------------------
Weighted average - basic and diluted 13,417,746 74,494,047
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The weighted average number of common shares outstanding reflects the effects of the Reorganization on February 20, 2007. Options to purchase 397,000 common shares at December 31, 2007 (December 31, 2006 - 110,000) were not included in the calculation of weighted average - diluted common shares outstanding because they were anti-dilutive.
11. STOCK-BASED COMPENSATION
The Company records compensation costs on the granting of stock options using the fair value method. Compensation expense is calculated using the Black-Scholes option pricing model with the following weighted average assumptions:
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2007 2006
---------------------------------------------------------------------------
Risk-free interest rate (%) 3.4 3.51
Expected life (years) 4.0 5.0
Expected volatility (%) 50.0 60.0
Expected dividend yield (%) - -
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The Company has not incorporated an estimated forfeiture rate for stock options that will not vest but accounts for the actual forfeitures as they occur.
The estimated fair value of stock options of $0.50 per share (December 31, 2006 - $0.71) is amortized to expense over the vesting period on a straight-line basis. In 2007, the Company recorded compensation expense of $2,513,000 related to stock options (2006 - $822,000). On October 4, 2007, the Company cancelled 1,193,000 stock options that were outstanding resulting in a charge to the consolidated statement of operations of $2,063,000 of previously unrecognized compensation cost related to these options. Stock-based compensation expense for the year ended December 31, 2007 of $2,153,000 includes $50,000 related to an employment agreement (note 10(b)(vi)).
12. FINANCIAL INSTRUMENTS
Fair value of financial instruments
The Company has financial instruments consisting of cash and cash equivalents, accounts receivable, accounts payable, and revolving operating loan. The carrying value of these instruments approximate fair value due to their short-term maturity.
Credit risk
A substantial portion of the Company's accounts receivable are with customers and joint venture partners in the petroleum and natural gas industry and are subject to normal industry credit risk. The Company will generally extend unsecured credit to these companies, and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions and may accordingly impact the Company's overall credit risk. Management believes the risk will be mitigated by the size, reputation and diversified nature of the companies to which they extend credit.
Interest rate risk
The Company is exposed to interest rate risk to the extent that changes in market interest rates impact its borrowings under the revolving credit facility. The Company has no interest rate swaps or hedges at December 31, 2007.
Foreign currency risk
The Company is exposed to foreign currency fluctuations as crude oil and natural gas prices received are referenced to U.S. dollar dominated prices.
Commodity price risk management
The Company enters into derivative financial instruments to manage its exposure to fluctuations in the price of natural gas. The Company has not designated these derivatives as a hedge for accounting purposes, and, accordingly has recorded the unrealized gains and losses on these contracts on the balance sheet as assets or liabilities with changes in fair value recorded in net income (loss) for the period. Realized gains or losses from financial instruments related to commodity price are recognized in net income as the related sales occur.
For the year ended December 31, 2007, the Company recorded a realized gain on commodity contracts of $393,000 (2006 - $nil). The Company recorded an unrealized gain of $92,000 for the year ended December 31, 2007 on the following commodity contracts which are outstanding at December 31, 2007:
---------------------------------------------------------------------------
Unrealized
Gain on
Commodity
Fixed Contracts at
Volume Price December 31,
Type Period (GJ/d) ($/GJ) 2007 ($)
---------------------------------------------------------------------------
Swap January 1, 2008 to October 31, 2008 2,000 6.51 37
Swap January 1, 2008 to October 31, 2008 3,000 6.505 55
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92
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13. COMMITMENTS AND CONTINGENCIES
Royalties
The Company has agreed to pay to various university research centers royalties amounting to two - five percent on sales of licensed products related to a research contract and acquired technology rights and 15% of sublicense revenues from products related to the acquired technology rights. At December 31, 2007 and 2006, there were no royalties payable under these agreements. These agreements relate to a predecessor company which was a cancer drug discovery enterprise.
Office space and equipment
The Company is committed to minimum annual lease payments under operating
leases for office premises and office equipment to March, 2013, as follows:
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$
---------------------------------------------------------------------------
2008 431
2009 430
2010 435
2011 439
Thereafter 549
---------------------------------------------------------------------------
2,284
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Transportation and Processing
On November 27, 2007, the Company entered into an agreement with an affiliate of AltaGas Income Trust ("AltaGas") for the transportation and processing of natural gas from the Company's Square Creek, Alberta area. The agreement requires the Company to construct a 41 km pipeline from a central point in the Square Creek development area to the AltaGas processing facility at Clear Prairie to enable the delivery and sale of natural gas. Upon commissioning of the pipeline, which is expected in early April 2008, AltaGas has agreed to purchase the pipeline from the Company. In exchange, the Company has committed to pay the greater of a fee calculated as monthly volumes at an established rate per mcf, or an established minimum monthly processing fee based on estimated gas throughput of 2 mmcf per day until the costs of the pipeline have been recovered, at which time the Company will pay a reduced monthly processing fee until the earlier of April 1, 2015 or the delivery of a total of 15 bcf.
Committed payments are as follows:
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$
---------------------------------------------------------------------------
2008 949
2009 1,260
2010 1,052
2011 767
2012 767
Thereafter 1,605
---------------------------------------------------------------------------
6,400
---------------------------------------------------------------------------
The Company's joint interest partner in the Square Creek area has agreed to be responsible for all terms and conditions of the agreement related to their 50% working interest in this area. Committed payments, as noted above, represent only the Company's 50% working interest. Included in accounts receivable at December 31, 2007 is $745,000 due from AltaGas that relates to preliminary construction costs incurred by the Company.
Drilling Commitments
As at December 31, 2007, the Company had committed to drill a well in Alberta pursuant to a farm-in agreement, at an estimated cost of $650,000. In January, 2008, the Company drilled this well and satisfied the terms of the agreement.
Guarantees
The Company maintains liability insurance for its directors and officers and indemnifies its directors and officers against any and all claims or losses reasonably incurred in the performance of their service to the Company to the extent permitted by law.
Claims and Litigation
The Company is involved in various claims and litigation arising in the normal course of business. The outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company's favor. If the outcome is unfavorable, it could have a materially adverse impact on the Company's financial position or results of operations.
14. CHANGE IN NON-CASH WORKING CAPITAL
Changes in non-cash working capital balances are comprised of the
following:
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2007 2006
$ $
---------------------------------------------------------------------------
Accounts receivable and accrued revenue (13) 3,318
Prepaid expenses and deposits (197) (110)
Accounts payable and accrued liabilities 3,021 (10,729)
Income taxes payable (283) -
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2,528 (7,521)
Less: working capital deficiency acquired
on acquisitions - (1,651)
---------------------------------------------------------------------------
2,528 (9,172)
Attributable to investing activities 1,806 (7,299)
---------------------------------------------------------------------------
Attributable to operating activities 722 (1,873)
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Interest paid 1,075 498
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15. RELATED PARTY TRANSACTIONS
In 2007, the Company was charged $522,000 in legal fees by a law firm where a director of the Company is a partner, of which $212,000 is included in accounts payable and accrued liabilities at December 31, 2007.
All related party transactions are in the normal course of business and have been measured at the agreed to exchange amounts, which are the amounts of consideration established and agreed to by the related parties and which are similar to those negotiated with third parties.
16. SUBSEQUENT EVENTS
(a) Subsequent to December 31, 2007, the Company issued a letter of credit for $1,000,000 with an expiry of February 1, 2009, related to a gas transportation and processing agreement (refer to note 13).
(b) On January 1, 2008, the Company amalgamated with its subsidiary companies.
BOE Presentation
Natural gas reserves and volumes recorded in thousand cubic feet are converted to barrels of oil equivalent ("boe") on the basis of six thousand cubic feet ("mcf") of gas to one barrel ("bbl") of oil. The term "barrels of oil equivalent" may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf to 1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead.
Caution to Reader
This news release contain contains forward-looking information. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable by Fortress at the time of preparation, may prove to be incorrect. The actual results achieved in future periods will vary from the information provided herein and the variations may be material. Consequently, there is no representation by Fortress that actual results achieved during future periods will be the same in whole or in part as the information contained herein.
The common shares of Fortress have not and will not be registered under the United States Securities Act of 1933, as amended (the "U.S. Securities Act") or any state securities laws and may not be offered or sold in the United States or to any U.S. person except in certain transactions exempt from the registration requirements of the U.S. Securities Act and applicable state securities laws.
Website: www.fortressenergy.ca
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