Fortress Energy Inc.
TSX : FEI

Fortress Energy Inc.

November 14, 2007 20:51 ET

Fortress Energy Releases Results for the Third Quarter of 2007

CALGARY, ALBERTA--(Marketwire - Nov. 14, 2007) -

THIS NEWS RELEASE IS NOT FOR DISSEMINATION IN THE UNITED STATES OR TO ANY UNITED STATES NEWS SERVICES. 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.

Fortress Energy Inc. (TSX:FEI) ("Fortress" or the "Company") is pleased to announce its financial and operating results for the third quarter of 2007.

Third Quarter Highlights

- Announced and completed a $12.9 million asset acquisition consisting of 280 boe/d of natural gas production in the Ladyfern and Velma areas in British Columbia and the Mearon area in Alberta.

- Sales averaged 1,025 boe/d, an increase of 17% from the second quarter of 2007 and 210% from the third quarter of 2006.

- Completed the installation and testing of a refrigeration plant at Ladyfern.

- Tied-in two wells in the Velma area in late August adding 400 boe/d of additional production.

- Increased borrowing facility to $26.5 million from $7 million.

Update of Operations

The Company continued to execute on its "Acquire and Exploit" strategy in the third quarter completing a $12.9 million asset acquisition in the Ladyfern, Mearon and Velma areas on July 18, 2007. The acquisition was financed by an increase in the Company's operating line. These assets included approximately 280 boe/d of natural gas production with additional behind pipe production, estimated proven reserves of 1 million boe and proven plus probable reserves of 1.5 million boe, plus 55,418 net acres of undeveloped land. With the tie-in to production facilities of two wells at Velma in late August, the Company increased the average production from these assets to approximately 480 boe/d. Production from the Velma area commenced in late August at a rate of 280 boe/d and was subsequently optimized in September and is now producing 400 boe/d of natural gas. The high productivity achieved from the tie in of these wells has resulted in the reduction of approximately 160 boe/d being produced from the Ladyfern North area.

New Royalty Framework

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 coalbed 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.

Outlook

The overall industry conditions for natural gas producers have been challenging. The brisk pace of natural gas directed drilling in the United States combined with moderate weather have created record storage levels of natural gas which has depressed natural gas prices. In addition the Alberta government proposed to increase oil and gas royalty rates which will negatively impact the entire oil and gas industry return on investment.

Despite these challenges, the Company has increased its average production to 1,025 boe/d in the third quarter of 2007 from 331 boe/d in the third quarter of 2006, and is currently producing approximately 1,300 boe/d. It has increased its proven plus probable reserves to 7.0 million boe from 4.3 million boe at December 31, 2006 achieving finding and development costs of less than $12.00/boe. The Company will continue to evaluate and analyze its capital projects and acquisition opportunities, seeking strategic assets at attractive valuation levels. Its significant discovery at Square Creek provides a sizeable development opportunity the Company intends to pursue in the winter 2008 drilling season.

J. Cameron Bailey, President and Chief Executive Officer

On Behalf of the Board of Directors


MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") should be read in conjunction with the unaudited interim consolidated financial statements of Fortress Energy Inc. ("Fortress" or the "Company", formerly known as SignalEnergy Inc.) for the three and nine months ended September 30, 2007 and the audited consolidated financial statements of Fortress Energy Inc. for the year ended December 31, 2006. The interim 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.

This MD&A provides management's analysis of Fortress' historical financial and operating performance based on information currently available. Actual results will vary from estimates and variances may be significant. Historical results are not indicative of future performance.

Non-GAAP Measurements

Management uses the term "funds from operations" to analyze operating performance and leverage, determined as cash flow from operating activities adjusted for changes in non-cash working capital balances. While widely used in the oil and gas industry, funds from operations does not have any standardized meaning prescribed by GAAP and therefore it may not be comparable to the calculation of similar measures for other entities. The Company considers funds from operations to be a key measure since it demonstrates the Company's ability to generate the cash necessary to fund future growth and repay debt. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period, nor should it be viewed as an alternative to cash flow from operating activities, net income (loss), or other measures of financial performance calculated in accordance with GAAP.

Management also uses certain key performance indicators ("KPI's") and industry benchmarks such as "operating netbacks" and funds from operations/boe to analyze financial and operating performance. These KPI's and benchmarks as presented do not have any standard meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities.

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 report 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.



SELECTED QUARTERLY INFORMATION

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2007
Q3 Q2 Q1
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Sales volume:
Natural gas (mcf/d) 6,111 5,082 4,699
Oil and NGL's (bbl/d) 7 29 22
Barrels of oil equivalent (boe/d) 1,025 876 805
Sales price:
Natural gas ($/mcf) 5.53 7.07 7.47
Oil and NGLs ($/bbl) 71.42 52.14 60.56
Barrels of oil equivalent ($/boe) 33.44 42.75 45.48
Benchmark prices:
AECO average price ($/mcf) 5.12 7.11 7.37
Edmonton Par ($/bbl) 80.70 72.65 67.86
Financial ($000's unless otherwise
noted):
Petroleum and natural gas sales 3,154 3,407 3,296
Net income (loss) (1,603) (617) (308)
Net income (loss) per share
- basic ($) (0.12) (0.05) (0.02)
Net income (loss) per share
- diluted ($) (0.12) (0.05) (0.02)
Funds from operations 505 1,147 1,558
Operating costs ($/boe) 10.31 8.23 8.82
Weighted average shares outstanding
- basic ('000) 13,266 13,258 13,262
Weighted average shares outstanding
- diluted ('000) 13,266 13,258 13,262
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2006 2005
Q4 Q3 Q2 Q1 Q4
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Sales volume:
Natural gas (mcf/d) 3,010 1,777 1,833 4,366 6,253
Oil and NGL's (bbl/d) 20 35 69 263 430
Barrels of oil equivalent (boe/d) 522 331 375 991 1,472
Sales price:
Natural gas ($/mcf) 7.19 5.31 6.04 7.86 11.48
Oil and NGLs ($/bbl) 57.19 65.43 57.08 59.62 65.95
Barrels of oil equivalent ($/boe) 44.13 35.46 40.08 50.45 68.31
Benchmark prices:
AECO average price ($/mcf) 6.89 5.68 6.02 7.58 11.43
Edmonton Par ($/bbl) 65.24 80.26 80.43 68.90 72.18
Financial ($000's unless otherwise
noted):
Petroleum and natural gas sales 2,149 1,079 1,362 4,500 9,250
Net income (loss) (5,635) (13) 270 13,440 952
Net income (loss) per share
- basic ($) (0.07) (0.00) 0.00 0.19 0.02
Net income (loss) per share
- diluted ($) (0.07) (0.00) 0.00 0.19 0.02
Funds from operations 1,089 821 17 687 4,223
Operating costs ($/boe) 5.73 8.51 13.13 13.07 12.81
Weighted average shares 81,439 73,266 72,595 70,598 69,195
outstanding - basic ('000)
Weighted average shares 81,439 73,266 73,316 71,239 69,525
outstanding - diluted ('000)
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Q3 - 2007

Sales volumes for the third quarter of 2007 were 1,025 boe/d compared to 876 boe/d in the second quarter of 2007. This increase is the result of the strategic asset acquisition in the Company's core areas of Ladyfern, Mearon and Velma which closed on July 18, 2007. The acquired assets added incremental sales volumes for the third quarter of approximately 225 boe/d. These incremental sales volumes were partially offset by facility constraints at Chigwell and Buick Creek. Significant capital projects completed during the quarter include the installation of the refrigeration plant at Ladyfern and the completion of a sweetening facility and the tie-in of two wells at Velma. The Company recorded a net loss of $1,603,000 in the third quarter.

Q2 - 2007

Sales volumes in the second quarter of 2007 were 876 boe/d compared to 805 boe/d in the previous quarter reflecting the first full quarter of sales volumes from wells drilled and tied to production facilities in March 2007. Major capital projects in the quarter were the installation of a refrigeration plant located at Ladyfern to improve the recovery of natural gas liquids and pipeline costs to tie wells in the Velma area to production facilities. The net loss for the second quarter of $617,000 reflects a decrease in funds from operations to $1,147,000 from $1,558,000 in the prior quarter resulting from a reduction in natural gas prices realized and higher interest and general and administrative expenses incurred.

Q1 - 2007

Sales volumes increased to 805 boe/d in the first quarter - an increase of 283 boe/d from the prior quarter - reflecting the first full quarter of results from the acquisition of Marauder Resources West Coast Inc. ("Marauder") on November 15, 2006. The Company drilled 14 gross (8 net) wells, tied 8 wells to production facilities (of which 1 well was from the 2006 program), and conducted 7 recompletions of existing well bores, resulting in incremental sales volumes of 200 boe/d in the first quarter of 2007. The Company recorded a net loss of $308,000 in the quarter compared to a net loss of $5,635,000 in the prior quarter. The net loss for the fourth quarter of 2006 is the result of a write off of goodwill of $4.5 million and adjustments to the gain on sale of oil and gas properties to reflect additional capital commitments incurred. Funds from operations for the quarter were $1,558,000 compared to $1,089,000 in the prior quarter, reflecting production gains noted and improved operating netbacks.

Q4 - 2006

Sales volumes increased in the quarter to 522 boe/d from 331 boe/d for the prior quarter as a result of the acquisition of Marauder which added additional sales volumes of 450 boe/d from the effective date. Funds from operations increased to $1,089,000 in the fourth quarter from $821,000 in the prior quarter, due to the Marauder acquisition and improved natural gas prices realized by the Company which increased by 35.4% to $7.19/mcf. The Company recorded a net loss of $5,635,000 in the quarter, as noted previously in this MD&A.

Q3 - 2006

Sales decreased from the prior quarter due to declining commodity prices and sales volumes to $1,079,000 from $1,362,000 in the prior quarter. The Company completed workover operations on two wells in the Buick Creek and Bashaw areas in the third quarter of 2006 but was unable to restore production for these wells. Funds from operations improved to $821,000 in the quarter from $17,000 in the previous quarter, reflecting lower royalties, operating and general and administrative costs. The Company recorded a net loss of $13,000 in the quarter primarily as a result of higher depletion and depreciation charges that reflect reserve adjustments for the two wells noted.

Q2 - 2006

Sales volumes declined in the second quarter as a result of the sale of the Company's Redwater, Ferrier, and Carrot Creek properties in the first quarter. A reduction in natural gas prices realized in the quarter of 20.5% contributed to reduced sales revenues. Funds from operations for the second quarter were $17,000 reflecting lower sales volumes and commodity prices and an increase in operating costs due to an under estimation relating to Redwater in the prior quarter. Incremental legal and advisory costs related to a failed takeover bid for the shares of the Company were recorded in the second quarter. Net income for the quarter was $270,000 - a significant reduction from the prior quarter which reflects the gain on the sale of oil and gas assets.

Q1 - 2006

In the first quarter of 2006 the Company sold its interest in certain oil and gas assets, as noted previously in this MD&A, for $91.2 million. The Company used the proceeds to repay its operating loan which had $28,550,000 drawn at the time of repayment. These oil and gas assets contributed sales volumes of 674 boe/d in the first quarter. Funds from operations declined substantially from the previous quarter due to a 26.1% decline in commodity prices realized by the Company, and an increase in operating costs due to the addition of several wells in the Redwater area that had been tied into production facilities in the first quarter. Net income for the quarter of $13,440,000 reflects a gain on the sale of oil and gas assets of $20,087,000.

Q4 - 2005

Sales volumes increased to 1,472 boe/d as a result of the addition of Goose River Resources Ltd. ("Goose River") in August and the Company's capital program which included the drilling of 31 gross (19 net) wells in the last nine months of 2005 with a 97% success rate. Funds from operations were $4,223,000 for the quarter compared to $3,141,000 in the prior quarter reflecting a 24.5% increase in natural gas prices realized. Net income for the fourth quarter was $952,000 reflecting substantially improved commodity prices and sales volumes.

REORGANIZATION

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 remaining 66,539,059 common shares of Signal were exchanged for 13,307,815 common shares of Fortress, which was a shell company that was formed for the purposes of completing the Reorganization.

The economic substance of the Reorganization is a transaction whereby the resulting entity is governed under the laws of the Province of Alberta, and not Quebec. Signal was dissolved into Fortress on April 19, 2007.

The balance sheet and share capital 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.



RESULTS OF OPERATIONS

Sales

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Three months ended Nine months ended
September 30, September 30,
2007 2006 2007 2006
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Petroleum and natural gas sales
($000's) 3,154 1,079 9,857 6,941
Sales volume:
Natural gas (mcf/d) 6,111 1,777 5,302 2,649
Oil and NGL's (bbl/d) 7 35 17 121
Barrels of oil equivalent (boe/d) 1,025 331 901 563
Sales price:
Natural gas ($/mcf) 5.53 5.31 6.60 6.86
Oil and NGLs ($/bbl) 71.42 65.43 65.29 60.96
Barrels of oil equivalent ($/boe) 33.44 35.46 40.05 45.16
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Petroleum and natural gas sales for the third quarter of 2007 were $3,154,000 compared to $1,079,000 for the third quarter of 2006. This increase is the result of higher sales volumes due to the acquisition of Marauder in the fourth quarter of 2006, additional wells drilled and tied into production facilities in the first quarter of 2007, and the strategic asset acquisition in the Ladyfern, Mearon and Velma areas in the third quarter of 2007. Average sales volumes were 1,025 boe/d in the third quarter of 2007 compared to 331 boe/d in the third quarter of 2006. The Company recorded petroleum and natural gas sales of $9,857,000 in the first nine months of 2007 on sales volumes of 901 boe/d compared to petroleum and natural gas sales of $6,941,000 and sales volumes of 563 boe/d for the first nine months of 2006.

Natural gas accounted for 99% of sales volumes for the first nine months of 2007 compared to 79% for the first nine months of 2006. This change resulted from the sale of substantially all of the Company's oil producing assets in the first quarter of 2006. The natural gas price realized by the Company in the three months ended September 30, 2007 increased to $5.53/mcf from $5.31/mcf a year earlier. The average AECO prices for the third quarters of 2007 and 2006 were $5.12/mcf and $5.68/mcf, respectively. The average natural gas price realized by the Company in the third quarter of 2007 includes a realized gain on a natural gas collar of $261,000 or $0.46/mcf. The average natural gas price realized for the nine months ended September 30, 2007 was $6.60/mcf compared to $6.86/mcf for the nine months ended September 30, 2006. The effect of the natural gas collar on the natural gas price realized for the nine months ended September 30, 2007 is $0.24/mcf.



Royalties

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Three months ended Nine months ended
September 30, September 30,
2007 2006 2007 2006
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Royalties (net of Alberta Royalty Tax
Credit) ($000's) 380 142 1,371 1,374
$/boe 4.03 4.67 5.57 8.94
Percentage of petroleum and natural
gas sales 12.0 13.2 13.9 19.8
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Royalties were $380,000 for the three months ended September 30, 2007 compared to $142,000 for the three months ended September 30, 2006. This increase reflects an increase in sales volumes in the third quarter of 2007. As a percentage of petroleum and natural gas sales the royalty rate decreased to 12.0% in the third quarter of 2007 from 13.2% in the third quarter of 2006. This decrease is due to the change in mix of the properties and the effect of realized gains recorded on a natural gas collar in the third quarter of 2007. For the nine months ended September 30, 2007, royalties decreased to $1,371,000 from $1,374,000 for the nine months ended September 30, 2006. As a percentage of petroleum and natural sales, royalties decreased to 13.9% for the nine months ended September 30, 2007 from 19.8% for the nine months ended September 30, 2006 due to the sale of oil and gas properties in the first quarter of 2006 which carried substantial freehold and gross override royalty components, and a reduction in the royalty rate attributed to the Ultra-Marginal Royalty Program which assesses a reduced royalty rate for low producing wells in the province of British Columbia. The Company's Ladyfern wells qualify for this program. There were also two significant accounting adjustments recorded in the second quarter of 2007. The first pertains to a $206,000 charge resulting from the audit and reassessment of Alberta Royalty Tax Credits ("ARTC") claimed for prior taxation years. The second adjustment relates to a reduction in royalties for the 2006 fiscal year in the amount of $309,000 resulting from the Ultra-Marginal Royalty Program. Both adjustments relate to subsidiary companies for periods that were prior to ownership by Fortress.

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 coalbed 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.



Operating Expenses

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Three months ended Nine months ended
September 30, September 30,
2007 2006 2007 2006
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Operating expenses ($000's) 973 264 2,268 1,882
$/boe 10.31 8.51 9.21 12.26
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The Company's operating expenses increased to $973,000 in the third quarter of 2007 from $264,000 in the third quarter of 2006. Operating expenses increased in the third quarter of 2007 to $10.31/boe compared to $8.51/boe in the third quarter of 2006 due to operating inefficiencies that have resulted from delays in bringing incremental production on stream in the third quarter of 2007. Operating expenses for the nine months ended September 30, 2007 were $2,268,000 compared to $1,828,000 for the same nine month period in 2006. This increase is due to higher sales volumes in the nine months ended September 30, 2007. On a per boe basis, operating expenses decreased to $9.21/boe for the nine months ended September 30, 2007 from $12.26/boe for the nine months ended September 30, 2006. This decrease is due to the sale of oil and gas properties in the first quarter of 2006 which carried substantially higher operating costs related to compressor and pump jack rentals, trucking, salt water disposal, and oil treating fees at third party facilities.



General and Administrative Expenses

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Three months ended Nine months ended
September 30, September 30,
($000's) 2007 2006 2007 2006
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General and administrative expense,
gross 1,167 494 3,605 3,355
General and administrative costs
capitalized (319) (60) (1,022) (170)
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General and administrative expenses,
net 848 434 2,583 3,185
$/boe 8.99 14.26 10.50 20.72
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General and administrative expenses increased to $848,000 in the third quarter of 2007 compared to $434,000 in the third quarter of 2006. In the first quarter of 2006, the Company substantially curtailed its exploration and development activities due to the sale of oil and gas properties which included most of its prospect inventory and was not actively pursuing exploration and development activities until the closing of the Marauder acquisition in November 2006. General and administrative expenses for the nine months ended September 30, 2007 were $2,583,000 compared to $3,185,000. This decrease is attributed increased capitalized costs with the ramp up in the Company's exploration and development activities in 2007.

The Company capitalized general and administrative expenses of $319,000 in the third quarter of 2007 compared to $60,000 in the third quarter of 2006. This increase is the result of increased exploration and development activities in 2007 with the acquisition of Marauder in November 2006 and its inventory of drill-ready locations. The Company capitalized general and administrative expenses of $1,022,000 in the nine months ended September 30, 2007 compared to $170,000 in the nine months ended September 30, 2006.



Stock-based Compensation Expense

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Three months ended Nine months ended
September 30, September 30,
2007 2006 2007 2006
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Stock-based compensation expense
($000's) 150 - 429 822
$/boe 1.59 - 1.74 5.35
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Stock-based compensation expense for the three months ended September 30, 2007 was $150,000 compare to $nil for the three months ended September 30, 2006. Stock-based compensation expense reflects the value attributed to stock options granted to employees, officers, directors and consultants to the Company. Stock-based compensation expense for the first nine months of 2007 was $429,000 compared to $822,000 for the first nine months of 2006. As a result of the sale of oil and gas properties in the first quarter of 2006, all unvested stock options outstanding were vested on March 1, 2006 resulting in an increase in stock-based compensation expense for the nine months ended September 30, 2006 reflecting this early vesting and accelerating the recognition of stock-based compensation expense.



Interest Expense

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Three months ended Nine months ended
September 30, September 30,
2007 2006 2007 2006
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Interest expense ($000's) 448 61 641 365
$/boe 4.75 2.00 2.60 2.37
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Interest expense for the third quarter of 2007 was $448,000 compared to $61,000 for the third quarter of 2006. For the third quarter of 2007, interest expense represents interest on the Company's operating loan. Interest expense recorded in the third quarter of 2006 pertains to interest on unspent flow-through obligations. The Company's operating loan was completely repaid in the first quarter of 2006 with the proceeds from the sale of oil and gas properties.

Interest expense for the nine months ended September 30, 2007 was $641,000 compared to $365,000 for the nine months ended September 30, 2006. This increase results from the strategic asset acquisition in the third quarter of 2007 which was financed by the Company's operating loan facility. Interest expense for 2007 also reflects interest and penalties of $69,000 related to the audit and reassessment of ARTC and interest of $36,000 related to the audit of a 2003 flow-through share issuance by a subsidiary company.



Depletion and Depreciation Expense

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Three months ended Nine months ended
September 30, September 30,
2007 2006 2007 2006
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Depletion and depreciation expense
($000's) 2,504 818 6,503 3,447
$/boe 26.54 26.88 26.42 22.43
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Depletion and depreciation expense was $2,504,000 for the third quarter of 2007 compared to $818,000 for the third quarter of 2006 resulting from an increase in sales volumes in the third quarter. Depletion and depreciation expense for the nine months ended September 30, 2007 was $6,503,000 compared to $3,447,000 for the nine months ended September 30, 2006 - an increase of $3,056,000 reflecting the sale of oil and gas properties in the first quarter of 2006. Estimated future development costs for proved undeveloped properties of $28.6 million (September 30, 2006 - $nil) were included in the calculation of depletion and depreciation expense for the nine months ended September 30, 2007. Undeveloped land costs of $4.3 million (September 30, 2006 - $1.2 million) were excluded from assets subject to depletion for the nine months ended September 30, 2007.

The Company performed a ceiling test at September 30, 2007 to assess the recoverability of its petroleum and natural gas interests. As at September 30, 2007 there was no impairment write down required.



Accretion of Asset Retirement Obligations

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Three months ended Nine months ended
September 30, September 30,
2007 2006 2007 2006
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Accretion of asset retirement obligations
($000's) 32 16 82 75
$/boe 0.33 0.53 0.33 0.49
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Accretion expense was $32,000 for the third quarter of 2007 compared to $16,000 for the third quarter of 2006. This increase is the result of an increase in the asset retirement obligation in 2007 due to the addition of the Marauder properties in November 2006, additional drilling conducted in the first quarter of 2007, and the asset acquisition in the third quarter of 2007. The sale of oil and gas properties in the first quarter of 2006 resulted in the assumption of asset retirement obligations of $3,387,000 by the purchaser. Accretion expense was $82,000 for the nine months ended September 30, 2007 compared to $75,000 for the nine months ended September 30, 2006. The accretion rate decreased to $0.33/boe as a result of increased sales volumes in 2007. This rate is also affected by the change in property mix as the Marauder properties require minimal surface reclamation resulting in a lower retirement obligation per well.

Income Tax

The Company recorded a future income tax recovery of $613,000 for the third quarter of 2007 compared to $nil for the third quarter of 2006. Future income tax reflects the difference between the underlying tax value and carrying value of the Company's assets and liabilities. The Company recorded a future income tax recovery of $1,203,000 for the first nine months of 2007 compared to a future income tax expense of $3,439,000 for the nine months ended September 30, 2006. This change 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.



Operating Netback

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Three months ended Nine months ended
September 30, September 30,
($/per boe) 2007 2006 2007 2006
----------------------------------------------------------------------------
Petroleum and natural gas sales 33.44 35.46 40.05 45.16
Less: Royalties (net of ARTC) (4.03) (4.67) (5.57) (8.94)
Operating expenses (10.31) (8.51) (9.21) (12.26)
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Operating netback 19.10 22.28 25.27 23.96
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Funds from operations 5.35 26.96 13.04 9.92
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The Company's operating netback for the third quarter of 2007 was $19.10/boe compared to $22.28/boe for the third quarter of 2006. This decrease is the result of lower natural gas prices realized and higher operating expenses in the third quarter of 2007. The operating netback for the nine months ended September 30, 2007 was $25.27/boe compared to $23.96/boe for the nine months ended September 30, 2006. This increase is the result of lower royalties and operating expenses realized in the third quarter of 2007.

Funds from operations for the third quarter of 2007 were $5.35/boe compared to $ 26.96/boe for the third quarter of 2006. This decrease is attributed to a higher operating netback realized in the third quarter of 2006 and interest income earned on invested cash. Funds from operations for the nine months ended September 30, 2007 were $13.04/boe compared to $9.92/boe the nine months ended September 30, 2006. This increase is attributed to a higher operating netback and lower net general and administrative expenses.



Net Income/(Loss)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
($000's except per share amounts) 2007 2006 2007 2006
----------------------------------------------------------------------------
Net income/(loss) (1,603) (13) (2,528) 13,697
Net income/(loss) per share - basic (0.12) (0.00) (0.19) 0.19
Net income/(loss) per share - diluted (0.12) (0.00) (0.19) 0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company recorded a net loss of $1,603,000 for the third quarter of 2007 compared to a net loss of $13,000 for the third quarter of 2006. This translates to a basic and diluted loss per share of $0.12 for the third quarter of 2007 compared to $nil for 2006. The Company's net loss for the nine months ended September 30, 2007 was $2,528,000 compared to net income of $13,697,000 for the nine months ended September 30, 2006. Net income for the first nine months of 2006 is attributed to the gain on sale of oil and gas assets of $19,955,000. The basic and diluted loss per share for the nine months ended September 30, 2007 was $0.19 compared to basic and diluted income per share of $0.19 for the nine months ended September 30, 2006.



Capital Expenditures

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
($000's) 2007 2006 2007 2006
----------------------------------------------------------------------------
Land and lease retention 19 17 84 121
Geological and geophysical 98 (50) 110 6
Drilling and completions 553 1,138 10,126 2,047
Facilities and equipment 4,813 495 9,107 2,660
Property acquisitions 12,586 - 12,943 465
Capitalized overhead costs 319 60 1,022 170
Other - (90) 1,166 70
----------------------------------------------------------------------------
18,388 1,570 34,558 5,539
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In the third quarter of 2007, the Company acquired a partner's working interests in the Ladyfern, Mearon and Velma areas for cash of $12.9 million, subject to final adjustments. The acquisition included approximately 280 boe/d of natural gas production with additional production behind pipe, estimated reserves of 1.0 million boe on a proven basis and 1.5 million boe on a proven plus probable basis, and over 55,418 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 production 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.

In the first quarter of 2007, the Company's drilling program focused 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. In addition, the Company completed 7 recompletion operations 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.

Liquidity and Capital Resources

Cash used in operating activities was $879,000 for the third quarter of 2007 compared to cash provided by operating activities of $2,209,000 for the third quarter of 2006. This decrease in cash provided by operating activities is due to a decrease in funds from operations in the third quarter of 2007 of $316,000 and an decrease in non-cash working capital balances. For the nine months ended September 30, 2007, cash provided by operating activities was $2,905,000 compared to cash provided by operating activities of $545,000 for the nine months ended September 30, 2006. This increase is due to an increase in funds from operations for the nine months ended September 30, 2007 to $3,210,000 from $1,525,000 for the nine months ended September 30, 2006, resulting from higher sales volumes recorded.

Cash provided by financing activities for the third quarter of 2007 was $17,630,000 compared to $nil for the third quarter of 2006. This increase represents additional funds advanced on the Company's operating loan which was used to fund the asset acquisition in the Ladyfern, Mearon, and Velma areas which closed on July 18, 2007. For the nine months ended September 30, 2007, cash used in financing activities was $6,216,000 compared to $19,787,000 for the nine months ended September 30, 2006. In the first quarter of 2007 the Company redeemed 23 million common shares as part of the reorganization of Signal for $30.4 million. 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 $28.6 million drawn. In addition, the Company received proceeds of $3.2 million for the exercise of employee stock options. Under the terms of its revolving credit facility the Company is required to maintain a debt-to-cash flow ratio of no greater than 2.5:1. As at September 30, 2007, the Company is in breach of this covenant. The Bank has issued a waiver regarding this breach. The Company is currently seeking alternative sources of financing to reduce its drawings on this facility, including, but not limited to, equity issuances and the sale of non-strategic assets.

Cash used in investing activities for the third quarter of 2007 was $16,758,000 compared to cash used in investing activities of $2,501,000 in the third quarter of 2006. Capital expenditures in the third quarter of 2007 relate to asset acquisition in the Ladyfern, Mearon and Velma areas for $12,900,000, the installation of the refrigeration plant at Ladyfern, and construction of surface facilities and the tie-in of two wells at Velma. Cash used in investing activities for the nine months ended September 30, 2007 was $33,392,000 compared to cash provided by investing activities of $80,163,000 for the nine months ended September 30, 2006. Cash used in investing activities for the nine months ended September 30, 2007 reflects capital expenditures for the Company's drilling program, new facilities and the strategic asset acquisition. By comparison, in 2006 the Company incurred capital expenditures of only $5,539,000 due to the downsizing of its operations following the sale of oil and gas properties in the first quarter.

Securities Outstanding

Securities outstanding as of the date of this MD&A consist of 13,267,059, issued and outstanding common shares and nil stock options. On October 4, 2007, the Board of Directors cancelled all stock options outstanding under the current stock option plan.

Off-balance Sheet Arrangements

The Company has no off-balance sheet arrangements.

Related Party Transactions

The Company has no related party transactions.

Subsequent Events

On October 4, 2007, the Company cancelled all stock options outstanding under the current stock option plan. The effect of this cancellation will result in a reversal of previously recognized stock-based compensation expense related to stock options of $398,000 in the fourth quarter of 2007.


Commitments and Contingencies

The Company is committed to minimum annual lease payments under operating leases for office premises and office equipment to March, 2013, as follows:



----------------------------------------------------------------------------
($000's)
----------------------------------------------------------------------------
Balance of 2007 121
2008 431
2009 430
2010 435
2011 439
2012 439
Thereafter 110
----------------------------------------------------------------------------
2,405
----------------------------------------------------------------------------


The Company is involved in various claims arising in the normal course of business. In the opinion of management, all such claims are not expected to materially affect the Company's financial position.

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 discussion and conclusion with respect to the Company's internal controls over financial reporting included in the December 31, 2006 MD&A remain unchanged as at September 30, 2007.

NEW CANADIAN ACCOUNTING PRONOUNCEMENTS

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".

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.

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.

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 does not currently have any hedges in place and therefore the adoption of Section 3865 "Hedges" did not have any impact on the Company's financial statements.

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.

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.

Future accounting changes

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.

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.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
FORTRESS ENERGY INC.
CONSOLIDATED BALANCE SHEETS
As at
(in thousands)
(unaudited)
----------------------------------------------------------------------------
September December
30, 2007 31, 2006
----------------------------------------------------------------------------

ASSETS (note 2)
Current
Cash and cash equivalents $ 53 $ 36,756
Accounts receivable 10,056 7,951
Prepaid expenses 489 368
Risk management asset (note 11) 73 -
----------------------------------------------------------------------------
10,671 45,075
Property, plant and equipment (notes 4 and 5) 99,209 70,579
----------------------------------------------------------------------------
$ 109,880 $ 115,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current
Accounts payable and accrued liabilities $ 10,450 $ 7,080
Income taxes payable - 283
Revolving operating loan (note 5) 24,410 -
----------------------------------------------------------------------------
34,860 7,363

Asset retirement obligations (note 6) 2,343 1,678
Future income tax 3,849 5,052
----------------------------------------------------------------------------
41,052 14,093
----------------------------------------------------------------------------

Contingencies (note 12)

Shareholders' Equity
Share capital (notes 8 and 13) 116,721 157,508
Contributed surplus (note 8) 12,361 1,779
Deficit (60,254) (57,726)
----------------------------------------------------------------------------
68,828 101,561

----------------------------------------------------------------------------
$ 109,880 $ 115,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Subsequent event (note 13)

See accompanying notes to consolidated financial statements.



FORTRESS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS) AND
DEFICIT
For the three and nine months ended September 30
(in thousands, except per share amounts)
(unaudited)
----------------------------------------------------------------------------
Three months ended Nine months ended
2007 2006 2007 2006
----------------------------------------------------------------------------

REVENUE
Petroleum and natural gas
(note 11) $ 3,154 $ 1,079 $ 9,857 $ 6,941
Royalties (net of Alberta Royalty
Tax Credit) (380) (142) (1,371) (1,374)
Interest income - 643 216 1,390
Unrealized gain (loss) on
financial instruments (note 11) (35) - 73 -
----------------------------------------------------------------------------
2,739 1,580 8,775 6,957
----------------------------------------------------------------------------
EXPENSES
Operating 973 264 2,268 1,882
General and administrative 848 434 2,583 3,185
Stock-based compensation (note 9) 150 - 429 822
Interest 448 61 641 365
Depletion and depreciation 2,504 818 6,503 3,447
Accretion of asset retirement
obligations (note 6) 32 16 82 75
----------------------------------------------------------------------------
4,955 1,593 12,506 9,776
----------------------------------------------------------------------------
Loss before the following (2,216) (13) (3,731) (2,819)
OTHER
Gain on sale of oil and gas
property, plant and equipment - - - 19,955
----------------------------------------------------------------------------
Income (loss) before income taxes (2,216) (13) (3,731) 17,136

Income tax expense (recovery) (note 7)
Future (613) - (1,203) 3,439
----------------------------------------------------------------------------

Net income (loss) and comprehensive
income (loss) for the period (1,603) (13) (2,528) 13,697

Deficit, beginning of period (58,651) (52,104) (57,726) (65,814)
----------------------------------------------------------------------------
Deficit, end of period $(60,254) $(52,117) $(60,254) $(52,117)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income (loss) and comprehensive
income (loss) per share (note 8)
Basic (0.12) 0.01 (0.19) 0.19
Diluted (0.12) 0.01 (0.19) 0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
FORTRESS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the three and nine months ended September 30
(in thousands, except per share amounts)
(unaudited)
----------------------------------------------------------------------------
Three months ended Nine months ended
2007 2006 2007 2006
----------------------------------------------------------------------------

CASH PROVIDED BY (USED IN)

OPERATING ACTIVITIES
Net income (loss) for the period $ (1,603) $ (13) $ (2,528) $ 13,697
Items not affecting cash flows:
Unrealized loss (gain) on
financial instruments 35 - (73) -
Stock-based compensation 150 - 429 822
Depletion and depreciation 2,504 818 6,503 3,447
Accretion of asset retirement
obligations 32 16 82 75
Gain on sale of oil and gas
property, plant and equipment - - - (19,955)
Future income tax expense
(recovery) (613) - (1,203) 3,439
----------------------------------------------------------------------------
Funds from operations 505 821 3,210 1,525
Change in non-cash working capital
(note 10) (1,384) 1,388 (305) (980)
----------------------------------------------------------------------------
(879) 2,209 2,905 545

FINANCING ACTIVITIES
Change in revolving operating loan 17,630 - 24,410 (22,975)
Issuance of common shares on
exercise of stock options - - - 3,188
Redemption of common shares (note 8) - - (30,440) -
Purchase of common shares (note 8) - - (186) -
----------------------------------------------------------------------------
17,630 - (6,216) (19,787)
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Property, plant and equipment
additions (18,388) (1,570) (34,558) (5,539)
Sale of property and equipment, net
of transaction costs - - - 95,345
Change in non-cash working capital
(note 10) 1,630 (931) 1,166 (9,643)
----------------------------------------------------------------------------
(16,758) (2,501) (33,392) 80,163
----------------------------------------------------------------------------

Net change in cash (7) (292) (36,703) 60,921
Cash and cash equivalents
- beginning of period 60 61,274 36,756 61
----------------------------------------------------------------------------
Cash and cash equivalents
- end of period $ 53 $ 60,982 $ 53 $ 60,982
----------------------------------------------------------------------------

Supplemental cash flow information (note 10)

----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


----------------------------------------------------------------------------
FORTRESS ENERGY INC.
Notes to Consolidated Financial Statements
September 30, 2007
(Tabular figures are in thousands of Canadian dollars unless otherwise
indicated)
(unaudited)
----------------------------------------------------------------------------


1. NATURE OF OPERATIONS

Fortress Energy Inc. ("Fortress" or the "Company", formerly SignalEnergy Inc.) is a Calgary-based company involved in the exploration, development and production of petroleum and natural gas. 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. This transaction is further described in notes 2 and 8.

2. SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of presentation

Except as noted below, the unaudited interim consolidated financial statements of the Company have been prepared by management in accordance with Canadian generally accepted accounting principles using the same accounting policies as set out in note 2 to the audited consolidated financial statements of the Company for the year ended December 31, 2006. Certain information or disclosures normally required to be included in notes to annual audited financial statements have been condensed or omitted. The unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2006.

On February 20, 2007, Signal and Fortress reorganized, as follows (refer to note 8 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.

The economic substance of the Reorganization is a transaction whereby the resulting entity is governed under the laws of the Province of Alberta, and not Quebec. Signal was dissolved into Fortress on April 19, 2007.

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.

(b) Comparative figures

Certain comparative figures have been reclassified to conform to the presentation adopted in the current period.

3. 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.

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.

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.

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.

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.

Future accounting changes

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.



4. PROPERTY, PLANT AND EQUIPMENT

----------------------------------------------------------------------------

September 30, 2007 December 31, 2006
$ $
----------------------------------------------------------------------------
Petroleum and natural gas properties 112,224 77,194
Other 249 146
----------------------------------------------------------------------------
112,473 77,340
Accumulated depletion and depreciation (13,264) (6,761)
----------------------------------------------------------------------------
Net book value 99,209 70,579
----------------------------------------------------------------------------


For the nine months ended September 30, 2007, the Company capitalized general and administrative expenses related to exploration and development activities of $1,022,000 (September 30, 2006 - $170,000).

Estimated future development costs for proved undeveloped reserves of $28.6 million (September 30, 2006 - $nil) were included in the calculation of depletion expense for the nine months ended September 30, 2007. As at September 30, 2007, undeveloped land costs of $4.3 million (September 30, 2006 - $1.2 million) were excluded from assets subject to depletion.

Effective July 18, 2007, the Company acquired a partner's working interests in the Ladyfern, Mearon and Velma areas for cash of $12.9 million, subject to final adjustments. The Company also assumed related asset retirement obligations of $289,000.

5. BANK FACILITIES

The Company has a revolving credit facility with its bank (the "Bank") of $26.5 million, with a current borrowing capacity of $25 million, bearing interest at the Bank's prime lending rate plus 0.25% (effective interest rate for the nine months ended September 30, 2007 of 6.5%) and secured by an interest over all present and after acquired property and a floating charge on all lands of a subsidiary company. Under the terms of the revolving credit facility the Company is required to maintain a debt-to-cash flow ratio of no greater than 2.5:1. As at September 30, 2007, the Company is in breach of this covenant. The Bank has issued a waiver regarding this breach.

6. 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 September 30, 2007 to be $2.3 million based on a total future liability of $4.0 million which will be primarily incurred between 2007 and 2029. An inflation rate of 2.0% (2006 - 3.0%) and a credit-adjusted risk-free rate of 6.5% (2006 - 6.0%) were used to calculate the fair value of the asset retirement obligations.



----------------------------------------------------------------------------
Asset Retirement Obligations $
----------------------------------------------------------------------------
Balance, December 31, 2006 1,678
Liabilities incurred 294
Liabilities incurred on acquisition (note 4) 289
Accretion expense 82
----------------------------------------------------------------------------
Balance, September 30, 2007 2,343
----------------------------------------------------------------------------
----------------------------------------------------------------------------


7. 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 income taxes as follows:



----------------------------------------------------------------------------
Three months Nine months
ended September 30, ended September 30,
2007 2006 2007 2006
----------------------------------------------------------------------------

$ $ $ $
----------------------------------------------------------------------------
Income (loss) before income taxes (2,216) (13) (3,731) 17,136
----------------------------------------------------------------------------
Expected tax expense (recovery)
at 32.12% (2006 - 34.50%) (711) (4) (1,198) 5,912
Add (deduct) income tax effect of:
Non-deductible crown charges - 14 - 124
Resource allowance - (13) - (52)
Stock-based compensation 47 - 137 284
Flow-through share
renouncement - - - (1,022)
Non-deductible expenses and
other permanent differences (8) 1 92 19
Rate adjustments 59 2 (234) (1,826)
----------------------------------------------------------------------------
Income tax expense (recovery) (613) - (1,203) 3,439
----------------------------------------------------------------------------


8. SHARE CAPITAL

(a) Authorized:

Unlimited number of voting common shares without par value.

Unlimited number of non-voting, non-retractable, non-redeemable preferred
shares without par value to be issued in series as determined by the
Company.

(b) Common shares issued and outstanding:

(i) SignalEnergy Inc.

----------------------------------------------------------------------------
Number of
Common Shares $
----------------------------------------------------------------------------
Balance, December 31, 2006 89,615,982 157,508
Redemption of common shares (iii) (23,076,923) (40,374)
Exchanged for common shares of Fortress (iii) (66,539,059) (117,134)
----------------------------------------------------------------------------
Balance, September 30, 2007 - -
----------------------------------------------------------------------------

(ii) Fortress Energy Inc.

----------------------------------------------------------------------------
Number of
Common Shares $
----------------------------------------------------------------------------
Balance, December 31, 2006 - -
Issued in exchange for shares of Signal (iii) 13,307,815 117,134
Normal course issuer bid (iv) (50,000) (438)
Issued in exchange for employment services (v) 9,244 25
----------------------------------------------------------------------------
Balance, September 30, 2007 13,267,059 116,721
----------------------------------------------------------------------------


(iii) 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 for the purposes of completing the Reorganization of Signal.

(iv) 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. As at September 30, 2007, the Company had 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.

(v) 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 is 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 September 30, 2007. The Company recorded stock-based compensation expense of $19,000 and $31,000 in the three and nine months ended September 30, 2007, respectively, related to this agreement.



(c) Contributed surplus:

----------------------------------------------------------------------------
$
----------------------------------------------------------------------------
Balance, December 31, 2006 1,779
Share redemption (note 8 (b)(iii)) 9,934
Normal course issuer bid (note 8 (b)(iv)) 252
Stock-based compensation expense (note 9) 396
----------------------------------------------------------------------------
Balance, September 30, 2007 12,361
----------------------------------------------------------------------------


(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 typically vest over a four-year period and expire five years from the date of grant.



The following table summarizes stock option transactions:

----------------------------------------------------------------------------
Weighted average
Number exercise price $
----------------------------------------------------------------------------
Outstanding, beginning of period 22,000 20.75
Granted 1,193,000 4.51
Cancelled (80,000) 4.75
----------------------------------------------------------------------------
Outstanding, September 30, 2007 1,135,000 4.76
----------------------------------------------------------------------------
Exercisable, September 30, 2007 22,000 20.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company has the following stock options outstanding at September 30,
2007:

----------------------------------------------------------------------------
Outstanding Exercisable
---------------------------------------------- --------------------------
Range of Weighted Weighted Weighted
exercise average average average
prices years to exercise Number exercise
$ Number expiry price $ exercisable price $
----------------------------------------------------------------------------
3.00 - 4.00 215,000 4.6 3.17 - -
4.00 - 5.00 898,000 4.3 4.75 - -
19.50 - 50.00 22,000 1.6 20.75 22,000 20.75
----------------------------------------------------------------------------
Outstanding,
September
30, 2007 1,135,000 4.3 4.76 22,000 20.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(e) Per share amounts:

The weighted average number of common shares outstanding for the three and
nine months ended September 30, 2007 and 2006 are as follows:

----------------------------------------------------------------------------
Three months Nine months
ended September 30, ended September 30,
----------------------------------------------------------------------------
2007 2006 2007 2006
----------------------------------------------------------------------------
Weighted average - basic 13,266,288 73,266,448 13,263,711 72,152,877
Weighted average - diluted 13,266,288 73,266,448 13,263,711 72,152,877
----------------------------------------------------------------------------


The weighted average number of common shares outstanding reflects the effects of the Reorganization on February 20, 2007. Options to purchase 1,135,000 common shares for the three and nine months ended September 30, 2007 (September 30, 2006 - 110,000) were not included in the calculation of weighted average - diluted common shares outstanding because they were anti-dilutive.

9. 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:



----------------------------------------------------------------------------
September 30, 2007 September 30, 2006
----------------------------------------------------------------------------
Risk-free interest rate (%) 3.75 3.51
Expected life (years) 5.0 3.3
Expected volatility (%) 50.0 60.0
Expected dividend yield (%) - -
----------------------------------------------------------------------------


The estimated weighted average fair value of stock options of $2.09 per share (September 30, 2006 - $3.55) is amortized to expense over the vesting period on a straight-line basis. For the three months and nine months ended September 30, 2007, the Company recorded compensation expense of $150,000 and $429,000, respectively (three and nine months ended September 30, 2006 - $nil and $822,000, respectively). The total stock-based compensation expense for the three and nine months ended September 30, 2007 includes amounts related to an employment agreement as described in note 8 (b)(v).

10. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital balances are comprised of the following:



----------------------------------------------------------------------------
Three months Nine months
ended September 30, ended September 30,
2007 2006 2007 2006
----------------------------------------------------------------------------

$ $ $ $
----------------------------------------------------------------------------
Accounts receivable 1,528 192 (2,105) 4,481
Prepaid expenses (106) (112) (121) (57)
Accounts payable and accrued
liabilities (1,176) 377 3,370 (15,047)
Income taxes payable - - (283) -
----------------------------------------------------------------------------
246 457 861 (10,623)
----------------------------------------------------------------------------
Attributable to operating activities (1,384) 1,388 (305) (980)
Attributable to investing activities 1,630 (931) 1,166 (9,643)
----------------------------------------------------------------------------

Interest paid 448 61 641 365
----------------------------------------------------------------------------


11. FINANCIAL INSTRUMENTS

The Company entered into a derivative contract to manage its exposure to
fluctuations in the price of natural gas, as follows:

----------------------------------------------------------------------------
Type Period Volume Price Price Index
Floor Ceiling
----------------------------------------------------------------------------
Natural gas April 1, 2007 to 2,500 GJ/d $6.00/GJ $8.30/GJ AECO-CGPR
collar October 31, 2007
----------------------------------------------------------------------------


This derivative contract has not been designated as a hedge and, accordingly, has been recorded on the balance sheet as an asset based on its fair value. The fair value of this derivative contract marked-to-market at September 30, 2007 results in an unrealized loss of $35,000 for the three months ended September 30, 2007 and an unrealized gain of $73,000 for the nine months ended September 30, 2007.

Realized gains and losses are recorded in petroleum and natural gas revenue in the period in which they occur. The Company realized a gain of $261,000 and $358,000 in the three and nine month periods ended September 30, 2007, respectively, representing actual cash settlements paid on this derivative contract.

12. CONTINGENCIES

The Company is involved in various claims arising in the normal course of business. In the opinion of management, all such claims are not expected to materially affect the Company's financial position.

13. SUBSEQUENT EVENT

On October 4, 2007, the Company cancelled all stock options outstanding under the current stock option plan. The effect of this cancellation will result in a reversal of previously recognized stock-based compensation expense related to stock options of $398,000 in the fourth quarter of 2007.

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