Fortress Energy Inc.
TSX : FEI

Fortress Energy Inc.

August 14, 2008 17:00 ET

Fortress Energy Inc. Releases Its Second Quarter 2008 Results and Provides an Update of Operations

CALGARY, ALBERTA--(Marketwire - Aug. 14, 2008) -

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

Fortress Energy Inc. (the "Company" or "Fortress") (TSX:FEI) releases its Second Quarter 2008 Results and provides an update of operations.

Corporate Highlights:

- The Company completed a $16.5 million equity financing.

- Increased average production in the second quarter to 1,463 boe/d, a 67% increase from the comparable quarter in 2007 and a 16% increase from the first quarter of 2008.

- Achieved funds from operations in the second quarter of $2.6 million. Funds from operations grew by 129% from the second quarter of 2007 and 30% from the first quarter of 2008.

- The Company announced the appointment of Brent D. Defosse and Joel Dryer to the Board of Directors in July. Mr. Defosse comes to Fortress Energy as a Professional Engineer with over 28 years experience in the oil and gas industry and is a former Chief Operating Officer of an oil and gas energy trust. Mr. Dryer brings to Fortress over 30 years experience in the finance, technology, and manufacturing industries.

Square Creek Development

During the first half of the year, Fortress was successful in the exploitation of it properties in the general Ladyfern area converting its resources into proven producing reserves. The construction of the pipeline to service the Square Creek area has enabled us to begin producing reserves in the Square Creek area and opened up a new exploration area where Fortress owns 41,800 net acres along the corridor. The pipeline was constructed with 10 mmcf/d of capacity and current production from the Square Creek area is limited by the compression at the Clear Prairie facility owned by a third party. Fortress and the third party are examining alternatives to increase capacity allowing Fortress to increase flow rates from the Square Creek area.

To date, Fortress has incurred approximately $14.5 million in the Square Creek area and has established net proven and probable reserves of 8.6 bcf and now producing approximately net 2.8mmcf/d with more production capacity from two additional Bluesky wells that are tied-in but not producing. Fortress is securing services for its 2008/09 Winter Capital Program which includes up to seven additional wells to evaluate the pool limits of the Bluesky and Notikewin formations.

Production Rates and Operating Costs

During the quarter, Fortress averaged 1,463 boe/d which was lower than expected production of 1,750 boe/d. Approximately 145 boe/d was shut-in for 17 days with an additional 5 days of reduced service at Buick Creek due to a scheduled plant turnaround at the Spectra owned McMahon gas processing facility in June. In addition, the Clear Prairie Gas Plant shut down for unscheduled maintenance resulting in approximately 400 boe/d from the Square Creek Area being shut in for six days.

During the second quarter, Fortress added additional field compression to service the Ladyfern North and Velma areas. There was little improvement in production rates from the compressor during the quarter due to a number of mechanical problems encountered on the start-up. These mechanical issues are on-going and we are working with the manufacturer to resolve.

There were a number of one-time costs related to the start-up of the Ladyfern field compression and Square Creek facility, combined with plant shut downs that resulted in operating cost increasing to an average of $15.40 per boe. We expect that with higher average production and the elimination of start-up costs that future operating costs will be lower in future quarters.

Fortress's cash flow for the first half of 2008 amounted to $4.6 million compared to $2.9 million of cash flow for the entire 2007 year. This cash flow was achieved from average production of 1,364 boe/d and is expected to increase in the future periods as production has increased to approximately 1,600 boe/d.



FINANCIAL AND OPERATING SUMMARY

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Three months ended Six months ended

June 30, 2008 June 30, 2007 June 30, 2008 June 30, 2007

($000's) $/boe ($000's) $/boe ($000's) $/boe ($000's) $/boe
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Petroleum and
natural gas
sales 8,066 60.58 3,310 41.53 13,604 54.80 6,606 43.41
Realized gain
(loss) on
commodity
contracts (1,072) (8.05) 97 1.22 (1,185) (4.77) 97 0.64
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6,994 52.53 3,407 42.75 12,419 50.03 6,703 44.05
Royalties (1,293) (9.71) (484) (6.07) (2,263) (9.12) (991) (6.51)
Operating
costs (2,051)(15.40) (656) (8.23) (3,426)(13.80) (1,295) (8.51)
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Operating
netback (1) 3,650 27.42 2,267 28.45 6,730 27.11 4,417 29.03
General and
administrative
expenses (715) (5.37) (945)(11.86) (1,391) (5.60) (1,735)(11.40)
Net interest
income
(expense) (308) (2.31) (175) (2.20) (688) (2.77) 23 0.15
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Funds from
operations (1) 2,627 19.74 1,147 14.39 4,651 18.74 2,705 17.78
Unrealized
gain (loss) on
commodity
contracts 151 1.13 108 1.36 (2,990)(12.04) 108 0.71
Depletion,
depreciation
and accretion (3,712)(27.88) (2,209)(27.72) (6,822)(27.48) (4,049)(26.60)
Stock-based
compensation
expense (54) (0.41) (169) (2.12) (72) (0.29) (279) (1.83)
Loss on sale
of pipeline
asset - - - - (552) (2.22) - -
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Loss before
income tax
recovery (988) (7.42) (1,123)(14.09) (5,785)(23.29) (1,515) (9.94)
Future income
tax recovery 244 1.83 506 6.35 1,586 6.38 590 3.88
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Net loss (744) (5.59) (617) (7.74) (4,199)(16.91) (925) (6.06)
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(1) Non-GAAP measures. See discussion in the following MD&A.


MANAGEMENT'S DISCUSSION AND ANALYSIS

August 14, 2008

Management's discussion and analysis ("MD&A") should be read in conjunction with the unaudited interim financial statements of Fortress Energy Inc. ("Fortress" or the "Company") as at and for the three and six months ended June 30, 2008 and the audited consolidated financial statements of Fortress Energy Inc. for the year ended December 31, 2007. The interim 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

The terms "funds from operations" and "operating netback" used in this 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.

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 statements of cash flows included in the 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) Three months ended Six months ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
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Cash provided by operating activities 6,883 1,669 8,578 3,784
Change in non-cash operating working
capital (4,256) (522) (4,008) (1,079)
Abandonment expenditures - - 81 -
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Funds from operations 2,627 1,147 4,651 2,705
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Funds from operations per share is calculated using the weighted average basic and diluted shares used to calculate earnings per share.

Operating netback is calculated as the average unit sales price less royalties, realized gain (loss) on commodity contracts, and operating expenses. Operating netback represents the cash margin for every barrel of oil equivalent and is a common benchmark used in the oil and gas industry. There is no GAAP measure that is reasonably comparable to operating netback.

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' primary focus is the exploration and development of natural gas reserves in Western Canada. The Company has approximately 93,600 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

The results for the three months ended June 30, 2008 are as follows:

- The Company completed a $16.5 million ($15 million net of issuance costs) equity financing consisting of 11,033,400 units ("Units"), each Unit consisting of one common share and one-half of one common share purchase warrant. A total of 9,350,100 Units were issued prior to June 30, 2008 for gross proceeds of $14,025,150 with the remaining 1,683,300 Units being issued in July. The proceeds will be used to fund the Company's 2009 capital program and working capital requirements.

- Increased average production in the second quarter to 1,463 boe/d, a 67% increase from the comparable quarter in 2007 and a 16% increase from the first quarter of 2008.

- Achieved funds from operations in the second quarter of $2.6 million or $19.74/boe. Funds from operations grew by 129% from the second quarter of 2007 and 30% from the first quarter of 2008.

- The Company announced the appointment of Brent D. Defosse and Joel Dryer to the Board of Directors in July. Mr. Defosse comes to Fortress Energy as a Professional Engineer with over 28 years experience in the oil and gas industry and is a former Chief Operating Officer of an oil and gas energy trust. Mr. Dryer brings to Fortress over 30 years experience in the finance, technology, and manufacturing industries.



DETAILED FINANCIAL ANALYSIS

Production

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Three months ended Six months ended
June 30, June 30,
2008 2007 2008 2007
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Sales volume:
Natural gas (mcf/d) 8,690 5,082 8,040 4,890
Oil and NGL's (bbl/d) 15 29 24 2
Total(boe/d) 1,463 876 1,364 841
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Sales volumes for the three months ended June 30, 2008 were 1,463 boe/d compared to 876 boe/d for the three months ended June 30, 2007 - an increase of 587 boe/d or 67%. This increase is due to the acquisition of a partners working interest in the Ladyfern, Mearon and Velma areas in July 2007 increasing the Company's working interest to 100% in these areas, the start up of two wells at Velma in late August 2007, and the start up of 5 wells (2.5 net) at Square Creek in late March of 2008. The anticipated sales volume on the start up of the Square Creek wells was approximately 540 boe/d but the actual sales volume was 399 boe/d. Capacity constraints at the Clear Prairie facility that processes gas from the Square Creek area resulted in the Company producing the Square Creek area at much lower rates. Two wells remain shut-in and others are flowing at reduced rates while the Company works with the third party plant operator to resolve the capacity issues. In addition, the Clear Prairie facility was shut down for 6 days in the second quarter. 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 at Ladyfern by approximately 120 boe/d. As part of the first quarter 2008 capital program, the Company added compression at Ladyfern to restore lost production. The Company experienced mechanical issues on the start up of this compressor resulting in substantial down time and no significant production gains from this area in the second quarter. These compressor issues are on-going and the Company is working with the manufacturer to resolve these issues. In addition, sales from the Buick Creek area were negatively affected by a scheduled plant turnaround at the Spectra owned McMahon gas processing facility in June. The turnaround resulted in the facility being completely shut down for a 17 day period and a 5 day period with reduced service. Sales volumes for the month of May for the Buick Creek area were 134 boe/d.

Sales volumes for the six months ended June 30, 2008 were 1,364 boe/d compared to 841 boe/d for the six months ended June 30, 2007. This increase is due to the asset acquisition in July 2007 and the start up of wells in the Velma and Square Creek areas. The acquired working interest accounted for sales volumes of 433 boe/d in the six months ended June 30, 2008.



Revenue

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Three months ended Six months ended
June 30, June 30,
2008 2007 2008 2007
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Petroleum and natural gas sales
($000's) 8,066 3,310 13,604 6,606
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Average realized prices:
Natural gas ($/mcf) 10.02 6.86 9.03 7.17
Realized gain (loss) on commodity
contracts ($/mcf) (1.34) 0.21 (0.80) 0.11
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Realized natural gas price ($/mcf) 8.68 7.07 8.23 7.28
Oil and NGLs ($/bbl) 108.04 52.14 88.34 46.55
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Total ($/boe) 52.53 42.75 50.03 44.05
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Benchmark prices:
AECO average price ($/mcf) 9.82 7.11 8.90 7.32
Edmonton par ($/boe) 126.37 72.65 112.34 70.16
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Petroleum and natural gas sales for the three months ended June 30, 2008 were $8,066,000 compared to $3,310,000 for three months ended June 30, 2007. This increase is attributable to a 67% increase in sales volumes and a 23% increase in the price of natural gas realized by the Company. Petroleum and natural gas sales for the six months ended June 30, 2008 were $13,604,000 compared to $6,606,000 for the six months ended June 30, 2007.

The average natural gas price realized by the Company for the second quarter of 2008 was $10.02/mcf (net of transportation costs and before realized losses on commodity contracts) compared to the AECO average price of $9.82/mcf. This compares to the average natural gas price realized in the second quarter of 2007 of $6.86/mcf (net of transportation costs and before realized gains on commodity contracts) and an AECO average price of $7.11/mcf. For the six months ended June 30, 2008, the Company realized an average price for natural gas of $9.03/mcf (net of transportation costs and before realized losses on commodity contracts) compared to an average AECO price of $8.90/mcf. For the six months ended June 30, 2007, the Company realized an average natural gas price of $7.17/mcf (net of transportation costs and before realized gains on commodity contracts) compared to an AECO average price of $7.32/mcf.

The Company's current production is approximately 99% natural gas and revenues are reliant on North American natural gas prices. Natural gas prices increased in the second quarter based on bullish sentiment including lower than expected LNG (liquefied natural gas) imports to the United States, lower Canadian production, and an extended outage at the Independence Hub in the Gulf of Mexico resulting in a decline in storage levels. The natural gas price has also been supported by record high oil prices. Weather will be a key determining factor in demand patterns for electric power generation to meeting the air conditioning requirements.

The Company uses commodity contracts to manage its exposure to fluctuations in the price of natural gas. In the second quarter of 2008, the Company realized a loss on commodity contracts of $1,072,000, or $1.34/mcf, and an unrealized gain on commodity contracts of $151,000, or $0.19/mcf. For the six months ended June 30, 2008, the Company realized a loss on commodity contracts of $1,185,000, or $0.85/mcf, and an unrealized loss on commodity contracts of $2,990,000, or $2.01/mcf. Approximately 50% of the Company's current production is under contract. Contracts in place as of June 30, 2008 are as follows:



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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 Six months ended
June 30, June 30,
2008 2007 2008 2007
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Royalties ($000's) 1,293 484 2,263 991
$/boe 9.71 6.07 9.12 6.51
Percentage of petroleum and natural gas
sales 16.0 14.6 16.6 15.0
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Royalties were $1,293,000 for the three months ended June 30, 2008 compared to $484,000 for the three months ended June 30, 2007. This increase reflects increased volumes and natural gas prices, as noted previously. As a percentage of petroleum and natural gas sales (net of transportation costs and before realized losses on commodity contracts), royalties increased to 16.0% in the second quarter of 2008 compared to 14.6% in the second quarter of 2007. This increase is attributed to increased production volumes from the start-up of the Company's Velma and Square Creek properties in August 2007 and March 2008, respectively. These two properties record average royalty rates of approximately 20%. The Company's wells at Ladyfern 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 six months ended June 30, 2008, the Company recorded royalties of $2,263,000 compared to $991,000 in the second quarter of 2007. As a percentage of petroleum and natural gas sales, royalties for the first six months of 2008 were 16.6% compared to 15.0% for the comparable period in 2007. Fortress expects royalties as a percentage of petroleum and natural gas sales to increase to approximately 19% - 20% for the balance of 2008.



Operating Expenses

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Three months ended Six months ended
June 30, June 30,
2008 2007 2008 2007
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Operating expenses ($000's) 2,051 656 3,426 1,295
$/boe 15.40 8.23 13.80 8.51
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Operating expenses increased in the three months ended June 30, 2008 to $2,051,000 from $656,000 in the second quarter of 2007. On a per boe basis, operating expenses of $15.40/boe were 87% higher than the second quarter of 2007. This increase is due to higher operating costs being experienced across all fields with the most significant increase from the start up of the Square Creek area in late March 2008. Square Creek recorded operating expenses of approximately $18.58/boe in the second quarter due to higher than anticipated third party plant operating expenses and plant capacity constraints that resulted in lower production levels. In addition, the Buick Creek wells were shut-in for a plant turnaround in June which increased operating expenses on a per boe basis as a portion of operating expenses are fixed costs.

For the six months ended June 30, 2008 operating expenses were $3,426,000 compared to $1,295,000 for the six months ended June 30, 2007. One a per boe basis, operating expenses were $13.80/boe for the six months ended June 30, 2008 compared to $8.51/boe for the six months ended June 30, 2007. In the first quarter of 2008, the Company incurred additional gas processing charges related to the Chigwell property resulting from adjustments to 2007 and prior periods at a third party gas processing plant. The largest factors affecting operating expenses are gas processing fees; contract operating fees, chemicals and equipment rentals which account for approximately 75% of the Company's operating expenses.



General and Administrative Expenses

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Three months ended Six months ended
June 30, June 30,
2008 2007 2008 2007
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Gross ($000's) 1,017 1,240 2,124 2,438
Partner recoveries ($000's) (95) - (333) -
Capitalized ($000's) (207) (295) (400) (703)
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Net ($000's) 715 945 1,391 1,735
$/boe 5.37 11.86 5.60 11.40
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Net general and administrative expenses decreased to $715,000 in the second quarter of 2008 from $945,000 in the second quarter of 2007. Gross general and administrative expenses for the second quarter of 2008 reflect an 18% decrease from the second quarter of 2007 which is mainly attributable to a reduction in consulting fees charged to the Company.

Net general and administrative expenses decreased to $1,391,000 for the six months ended June 30, 2008 from $1,735,000 for the six months ended June 30, 2007. General and administrative expenses for the six months ended June 30, 2008 were $5.60/boe compared to $11.40/boe for the six months ended June 30, 2007. The decrease on a per boe basis is mainly due to an increase in production volumes in 2008 as compared to 2007.

Partner recoveries reflect the portion of the Company's general and administrative expenses recoverable from partners related to the Company's capital program.

The Company's policy is to capitalize salaries, stock-based compensation, 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 Six months ended
June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Stock-based compensation expense
($000's):
Stock options 14 169 32 279
Restricted stock units 120 - 120 -
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134 169 152 279
Stock-based compensation
capitalized to property, plant
and equipment (80) - (80) -
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Net stock-based compensation expense 54 169 72 279
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$/boe 0.41 2.12 0.29 1.83
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The net stock-based compensation expense for the three months ended June 30, 2008 was $54,000 reflecting a decrease from the three months ended June 30, 2007 of $115,000. The gross stock-based compensation for the three months ended June 30, 2008 was $134,000 of which $14,000 was attributable to stock options and $120,000 to restricted stock units. This compares to $169,000 for the three months ended June 30, 2007 which was attributable to stock options granted in January 2007 that were later cancelled in November 2007. In June 2008, the Company approved a restricted stock unit plan that is settled in cash on maturity. As at June 30, 2008, there were 500,000 restricted stock units outstanding that mature on December 31, 2010. For the three and six months ended June 30, 2008, the Company capitalized stock-based compensation of $80,000 directly related to exploration and development activities (three and six months ended June 30, 2007 - $nil).

The net stock-based compensation expense for the six months ended June 30, 2008 was $72,000, a decrease of $207,000 from the six month period ended June 30, 2007. No options were granted in the six months ended June 30, 2008.

Interest Income and Expense

The Company recorded interest expense of $308,000 for the three months ended June 30, 2008 compared to $175,000 for the three months ended June 30, 2007. The Company recorded interest expense of $688,000 for the six months ended June 30, 2008 compared to net interest income in the six months ended June 30, 2007 of $23,000. Interest expense in the first six months of 2008 reflects interest on the Company's revolving credit facility and interest on unspent flow-through obligations. Net interest income for the six months ended June 30, 2007 reflects interest earned on commercial paper investments prior to the reorganization of SignalEnergy Inc. ("Signal"), whereby Signal redeemed approximately 23 million common shares at $1.30 per share for a total cost of $30,000,000.



Depletion, Depreciation and Accretion Expense

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Three months ended Six months ended
June 30, June 30,
2008 2007 2008 2007
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Depletion and depreciation expense
($000's) 3,668 2,183 6,747 3,999
Accretion of asset retirement
obligations ($000's) 44 26 75 50
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Total ($000's) 3,712 2,209 6,822 4,049
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Depletion and depreciation expense
($/boe) 27.55 27.39 27.18 26.27
Accretion of asset retirement
obligations ($/boe) 0.33 0.33 0.30 0.33
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Total ($/boe) 27.88 27.72 27.48 26.60
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Depletion and depreciation are calculated based on capital expenditures, production rates, and reserves. Depletion and depreciation expense was $3,668,000 for three months ended June 30, 2008 compared to $2,183,000 for the three months ended June 30, 2007. This increase is attributable to increased production volumes in the second quarter of 2008, which have increased 67% from the second quarter of 2007. The depletion and depreciation expense rate for the second quarter of 2008 was $27.55/boe compared to $27.39/boe for the second quarter of 2007. For the six months ended June 30, 2008, the Company recorded depletion and depreciation expense of $6,747,000 compared to $3,999,000 for the six months ended June 30, 2007.

Estimated future development costs for proved undeveloped properties included in the calculation of depletion expense at June 30, 2008 decreased to $15,842,000 from $21,300,000 at June 30, 2007. Undeveloped land costs at June 30, 2008 increased to $7,362,000 from $4,300,000 at June 30, 2007 and were excluded from assets subject to depletion.

Accretion expense for the three months ended June 30, 2008 was $44,000 compared to $26,000 for the three months ended June 30, 2007. For the six months ended June 30, 2008 the Company recorded accretion expense of $75,000 compared to $50,000 for the six months ended June 30, 2007. The Company completed the construction of a refrigeration plant and sweetening facilities in the second and third quarters of 2007 and acquired a partners working interest in the Ladyfern North, Mearon North and Velma areas in July 2007, significantly increasing the Company's asset retirement obligation. In addition, the Company added 6 wells (3.5 net) in the first quarter of 2008 and production and gathering facilities at Square Creek.

Income Tax

The Company recorded a recovery of future income taxes for the three months ended June 30, 2008 of $244,000 compared to $506,000 for the three months ended June 30, 2007. For the six months ended June 30, 2008, the Company recorded a recovery of future income taxes of $1,586,000 compared to $590,000 for the first six months of 2007. 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 capital costs incurred since the second quarter of 2007. 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 was 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 June 30, 2008, the Company has incurred approximately $1 million of eligible expenditures.

The estimated tax pools of the Company at June 30, 2008 are as follows:



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($000's)
----------------------------------------------------------------------------
Canadian Oil and Gas Property Expenses 15,210
Canadian Development Expenses 33,278
Canadian Exploration Expenses 11,330
Undepreciated Capital Cost 30,654
Share Issuance Costs 1,981
Investment Tax Credits 2,367
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94,820
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Net Loss

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Three months ended Six months ended
June 30, June 30,
($000's except per share
and per boe amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Net loss 744 617 4,199 925
Net loss per share
- basic and diluted 0.04 0.05 0.26 0.07
Net loss per boe 5.59 7.74 16.91 6.08
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The Company recorded a net loss of $744,000 for the three months ended June 30, 2008 compared to $617,000 for the three months ended June 30, 2007. This translates into a basic and diluted net loss per share of $0.04 for the three months ended June 30, 2008 and $0.05 for the three months ended June 30, 2007. The net loss for the six months ended June 30, 2008 was $4,199,000 compared to $925,000 for the six months ended June 30, 2007. For the six months ended June 30, 2008 the Company recorded a loss on commodity contracts of $2,990,000 and a loss on the sale of a pipeline asset of $552,000.



Funds from Operations

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Three months ended Six months ended
June 30, June 30,
($000's except per share
and per boe amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Funds from operations 2,627 1,147 4,651 2,705
Funds from operations ($/boe) 19.74 14.39 18.74 17.78
Funds from operations per
share - basic and diluted 0.16 0.09 0.28 0.20
----------------------------------------------------------------------------
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Funds from operations for second quarter of 2008 were $2,627,000 compared to $1,147,000 for the second quarter of 2007. This increase is attributed to a 67% increase in production volumes and a 23% increase in the realized price of natural gas. The operating netback realized by the Company for the three months ended June 30, 2008 decreased from $28.45/boe in the second quarter of 2007 to $27.42/boe due to an increase in operating expenses.

Fund from operations for the six months ended June 30, 2008 increased to $4,651,000 from $2,705,000 for the six months ended June 30, 2007. The increase is due to increased production and prices realized. The Company's operating netback for the six months ended June 30, 2008 decreased by $1.92/boe compared to the six months ended June 30, 2007 mainly due to an increase in operating expenses.



Capital Expenditures

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,

($000s) 2008 2007 2008 2007
----------------------------------------------------------------------------
Land and seismic 150 402 583 434
Drilling and completions 284 405 5,041 9,573
Equipment and facilities 2,501 2,129 16,076 4,294
Capitalized overhead costs 287 295 480 703
Abandonment expenditures - - 81 -
Other 27 1,089 33 1,166
Dispositions (8,150) - (8,150) -
----------------------------------------------------------------------------
(4,901) 4,320 14,144 16,170
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The total capital expenditures for the three months ended June 30, 2008 were $3,249,000, excluding dispositions, compared to additions of $4,320,000 for the three months ended June 30, 2007. The total capital expenditures for the six months ended June 30, 2008 were $14,144,000 compared to $16,170,000 for the six months ended June 30, 2007. The capital program for the first six months of 2008 was focused on the follow-up to the discovery of the Bluesky and Notikewin gas pools from the 2007 winter drilling program and compression and optimization at Ladyfern. Fortress drilled two additional wells in the Bluesky formation and three wells in the Notikewin to better delineate the two structures. The Company constructed a 10 mmcf/d gathering and production facility to service eight wells it has in the area. From the drilling activity completed to date, two additional Bluesky locations and five additional Notikewin locations have been identified and are currently planned to be pursued in the 2009 winter drilling program.

The Company completed the construction of a 41 km pipeline to deliver gas to the Clear Prairie gas plant to service the Square Creek area, the corridor along which it owns 41,800 net acres of land opening up a significant exploration area for the Company. The pipeline was completed and commissioned in March for a total cost of $8,702,000 and was sold to a mid-stream service provider in April for proceeds of $8,150,000 resulting in a loss on the sale of $552,000.

At the Clear Prairie facility, Fortress has arrangements for 5.0 mmcf/d (2.5 mmcf/d net) of firm processing capacity and has processing service available on a best efforts basis for larger volumes. Fortress' ability to produce natural gas at an optimum rate from the Square Creek area is restricted by processing capacity at the Clear Prairie facility owned by a third party. Fortress is working with the third party to increase production capacity.



Share Capital

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,

2008 2007 2008 2007
----------------------------------------------------------------------------
Weighted average common
shares outstanding
- basic and diluted 16,808,660 13,257,860 16,394,538 13,260,828
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Stock-based compensation arrangements and warrants outstanding at June 30, 2008 and 2007 were not included in the calculation of weighted average - diluted common shares outstanding because they were anti-dilutive.



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

Outstanding securities
----------------------------------------------------------------------------

Common shares 25,336,988
Warrants 4,675,050
Stock options 397,000
----------------------------------------------------------------------------
Total outstanding securities at June 30, 2008 30,409,038
Common shares and warrants issued July 4, 2008 2,524,950
Options granted July 8, 2008 1,684,633
----------------------------------------------------------------------------
Total outstanding securities at August 14, 2008 34,618,621
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 June 30, 2008, the Company has incurred eligible expenditures of approximately $1,000,000.

The Company closed a public offering of 11,033,400 units ("Units") on June 20, 2008, June 27, 2008 and July 4, 2008, for gross proceeds of $16,550,100 ($15,002,000 net of issuance costs). Each Unit consists of one common share of the Company and one-half of one common share purchase warrant. The warrants are exercisable on or before June 20, 2011 subject to the right of Company to accelerate the expiry time on not less than 30 days notice to the warrant holders, if the aggregate sales price of the common shares during a period of 20 consecutive days divided by the aggregate number of common shares sold is at least $3.00. Each whole warrant entitles the holder thereof to purchase one common share an at exercise price of $2.00. The proceeds of the financing will be used to fund the Company's 2009 capital program and working capital requirements.

A total of 9,350,100 Units were issued before June 30, 2008 for gross proceeds of $14,025,150. The remaining 1,683,300 Units were issued on July 4, 2008 and will be reflected in the Company's financial statements for the three and nine months ended September 30, 2008. The impact of the July 4, 2008 closing on the financial statements for the three and nine months ended September 30, 2008 results in a decrease in the revolving operating loan of $2,289,000 and an increase in share capital of $2,289,000 (net of issuance costs of $236,000).

Liquidity and Capital Resources

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 the three and six months ended June 30, 2008 of 5.00% and 5.25% respectively, and for the three and six months ended June 30, 2007 - 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 Company has a $1,000,000 letter of credit which reduces its borrowing capacity on the revolving operating loan.

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 the working capital covenant at June 30, 2008.

Cash provided by operating activities was $6,883,000 for the second quarter of 2008 compared to $1,669,000 for the second quarter of 2007. This increase is due to an increase in non-cash working capital balances and funds from operations in the three months ended June 30, 2008 when compared to the three months ended June 30, 2007. Cash provided by operating activities for the six months ended June 30, 2008 was $8,578,000 compared to $3,784,000 for the six months ended June 30, 2007. This increase is due to increased funds from operations and changes in non-cash working capital.

Cash provided by financing activities for the three months ended June 30, 2008 was $8,864,000 compared to $3,061,000 for the three months ended June 30, 2007. In the second quarter of 2008, the Company closed a public offering of 9,350,100 Units for gross proceeds of $14,025,150 ($12,713,000 net of issuance costs). The proceeds of the financing will be used to fund the Company's 2009 capital program and to provide additional working capital. Cash provided by financing activities for the six months ended June 30, 2008 were $8,605,000 compared to cash used in financing activities for the six months ended June 30, 2007 of $23,846,000. In the first quarter of 2007, the Company redeemed 23,076,923 common shares as part of its reorganization of Signal for $30,471,000. The Company also purchased 50,000 common shares in the first quarter of 2007 for $186,000.

Cash used in investing activities for the second quarter of 2008 was $15,747,000 compared to $6,087,000 for the second quarter of 2007. The Company's capital expenditures were $3,249,000 in the second quarter of 2008 compared to $4,320,000 in the second quarter of 2007. Cash used in investing activities for the six months ended June 30, 2008 was $17,189,000 compared to $16,634,000 for the six months ended June 30, 2007. In the second quarter of 2008, the Company recorded the sale of a 41 km pipeline connecting the Square Creek area to processing facilities for $8,150,000.

Related Party Transactions

In the three and six months ended June 30, 2008, the Company was charged $246,000 and $576,000 respectively 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 June 30, 2008.

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

(a) On July 8, 2008, the Company granted stock options to acquire 1,684,633 common shares of the Company at an exercise price of $1.35 per share, expiring July 8, 2013.

(b) On July 21, 2008, the Company entered into a commodity price contract to sell 1,250 GJ/d of natural gas at $9.58/GJ for the period of November 1, 2008 to March 31, 2009.

(c) On August 8, 2008, the Company entered into a commodity price contract to sell 3,750 GJ/d of natural gas at $8.25/GJ for the period of November 1, 2008 to March 31, 2009.

(d) On July 4, 2008, the Company completed the closing of 1,683,300 Units for gross proceeds of $2,524,950 ($2,289,000 net of issuance costs).

Commitments and Contingencies

Office space and equipment

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



----------------------------------------------------------------------------
Equipment Office
Rental Lease Total
$ $ $
----------------------------------------------------------------------------
Balance of 2008 286 211 497
2009 148 423 571
2010 - 435 435
2011 - 439 439
2012 - 439 439
Thereafter - 110 110
----------------------------------------------------------------------------
434 2,057 2,491
----------------------------------------------------------------------------


Transportation and Processing

The Company has an agreement for the transportation and processing of natural gas from the Company's Square Creek, Alberta area. The Company is 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 earlier of April 1, 2015 or the delivery of a total of 15 bcf.



Committed payments are as follows:

----------------------------------------------------------------------------
$
----------------------------------------------------------------------------
Balance of 2008 683
2009 1,260
2010 1,052
2011 767
2012 767
Thereafter 1,605
----------------------------------------------------------------------------
6,134
----------------------------------------------------------------------------


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 represent only the Company's 50% working interest.

Letter of Credit

On February 1, 2008, the Company issued a letter of credit of $1,000,000 with an expiry of February 1, 2009, related to a gas transportation and processing agreement.

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 outcomes are unfavorable, they could have a materially adverse impact on the Company's financial position or results of operations.



SELECTED QUARTERLY INFORMATION

----------------------------------------------------------------------------
2008 2007 2006
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
----------------------------------------------------------------------------
Production:
Natural gas
(mcf/d) 8,690 7,391 7,455 6,111 5,082 4,699 3,010 1,777
Oil and
NGL's
(bbl/d) 15 33 13 7 29 22 20 35
Barrels of
oil
equivalent
(boe/d) 1,463 1,265 1,256 1,025 876 805 522 331
Average
realized
price (1):
Natural gas
($/mcf) 10.02 7.87 6.19 5.07 6.86 7.47 7.19 5.31
Oil and NGLs
($/bbl) 108.04 79.61 86.95 71.42 52.14 60.56 57.19 65.43
Barrels of
oil
equivalent
($/boe) 52.53 48.10 38.07 30.68 41.52 45.48 44.13 35.46
Benchmark
prices:
AECO average
price
($/mcf) 9.82 7.90 6.00 5.12 7.11 7.37 6.89 5.68
Edmonton Par
($/bbl) 126.37 98.45 80.75 80.70 72.65 67.86 65.24 80.26
Financial
($000's
unless
otherwise
noted):
Petroleum
and
natural
gas sales 8,066 5,538 4,396 2,893 3,310 3,296 2,149 1,079
Net income
(loss) (744) (3,455) (5,442) (1,603) (617) (308) (5,635) (13)
Net income
(loss) per
share -
basic ($) (0.04) (0.22) (0.39) (0.12) (0.05) (0.02) (0.07) (0.00)
Net income
(loss) per
share -
diluted ($) (0.04) (0.22) (0.39) (0.12) (0.05) (0.02) (0.07) (0.00)
Funds from
(used in)
operations 2,627 2,025 (282) 505 1,147 1,558 1,089 821
Operating
costs
($/boe) 15.40 11.94 15.26 10.31 8.23 8.82 5.73 8.51
Weighted
average
shares
outstanding
basic
('000) 16,809 15,980 13,561 13,266 13,258 13,262 81,439 73,266
Weighted
average
shares
outstanding
diluted
('000) 16,809 15,980 13,561 13,266 13,258 13,262 81,439 73,266
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Realized prices are net of transportation costs and before realized
gains or losses 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 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, 2007 MD&A remain unchanged as at June 30, 2008.

Changes in Accounting Policies and Practices

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, and Handbook Section 1400 - General Standards of Financial Statement 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. The adoption of Section 1400, which includes requirements to assess and disclose the Company's ability to continue as a going concern, did not have an impact on the financial statements.

New Canadian Accounting Pronouncements

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 January 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.

CICA 3064, Goodwill and Intangible Assets, will replace CICA 3062, Goodwill and Other Intangible Assets, and results in withdrawal of CICA 3450, Research and Development Costs, and amendments to Accounting Guideline (AcG) 11, Enterprises in the Development Stage and CICA 1000, Financial Statement Concepts. The standard intends to reduce the differences with IFRS in the accounting for intangible assets and results in closer alignment with U.S. GAAP. Under current Canadian standards, more items are recognized as assets than under IFRS or U.S. GAAP. The objectives of CICA 3064 are to reinforce the principle-based approach to the recognition of assets only in accordance with the definition of an asset and the criteria for asset recognition; and clarify the application of the concept of matching revenues and expenses such that the current practice of recognizing as assets items that do not meet the definition and recognition criteria is eliminated. The standard will also provide guidance for the recognition of internally developed intangible assets (including research and development activities), ensuring consistent treatment of all intangible assets, whether separately acquired or internally developed. Fiscal years beginning on or after October 1, 2008, with early adoption encouraged. The Company is currently evaluating the impact of this standard.

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.

Additional risk factors can be found under "Risk Factors Relating to the Oil and Gas Business" in the Company's 2007 Annual Information Form or under "Business Risks and Uncertainties" in the Company's 2007 Annual Report both of which can be found on the Company's website www.fortressenegy.ca or under the Company's profile on www.sedar.com. The risks should not be construed as exhaustive. There are numerous factors, both known and unknown, that could cause actual results or events to differ materially from forecast results.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
FORTRESS ENERGY INC.
BALANCE SHEETS
As at
(in thousands)
----------------------------------------------------------------------------
June 30, December 31,
2008 2007
----------------------------------------------------------------------------

ASSETS (note 6)
Current Assets
Cash and cash equivalents $ 38 $ 44
Accounts receivable and accrued revenue
(note 9) 11,483 7,964
Prepaid expenses and deposits 386 565
Commodity contracts (note 11) - 92
---------------------------------------------------------------------------
11,907 8,665
Property, plant and equipment (note 5) 106,289 99,265
----------------------------------------------------------------------------
$ 118,196 $ 107,930
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Revolving operating loan (note 6) $ 18,485 $ 22,593
Accounts payable and accrued liabilities
(note 14) 14,338 10,101
Commodity contracts (note 11) 2,899 -
---------------------------------------------------------------------------
35,722 32,694

Future income taxes 1,534 2,180
Asset retirement obligations (note 8) 3,303 3,050
----------------------------------------------------------------------------
40,559 37,924
----------------------------------------------------------------------------

Commitments and contingencies (notes 11 and 12)

Shareholders' Equity
Share capital (note 9) 131,518 121,274
Warrants (note 9) 1,554 -
Contributed surplus (note 9) 14,460 14,428
Deficit (69,895) (65,696)
---------------------------------------------------------------------------
77,637 70,006
----------------------------------------------------------------------------
$ 118,196 $ 107,930
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Subsequent events (note 15)

See accompanying notes to financial statements.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
FORTRESS ENERGY INC.
STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME (LOSS) AND DEFICIT
For the three and six months ended June 30
(in thousands, except per share amounts)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

REVENUES
Petroleum and natural gas sales $ 8,066 $ 3,310 $ 13,604 $ 6,606
Royalties (1,293) (484) (2,263) (991)
Interest income - - - 216
Realized gain (loss) on commodity
contracts (note 11) (1,072) 97 (1,185) 97
Unrealized gain (loss) on
commodity contracts (note 11) 151 108 (2,990) 108
---------------------------------------------------------------------------
5,852 3,031 7,166 6,036
---------------------------------------------------------------------------
EXPENSES
Operating 2,051 656 3,426 1,295
General and administrative (notes
5 and 14) 715 945 1,391 1,735
Stock-based compensation (note 10) 54 169 72 279
Interest 308 175 688 193
Depletion, depreciation and
accretion (note 5) 3,712 2,209 6,822 4,049
---------------------------------------------------------------------------
6,840 4,154 12,399 7,551
---------------------------------------------------------------------------
Loss from operations (988) (1,123) (5,233) (1,515)
Loss on sale of pipeline asset
(note 4) - - (552) -
----------------------------------------------------------------------------
Loss before future income tax
recovery (988) (1,123) (5,785) (1,515)
Future income tax recovery (note 7) (244) (506) (1,586) (590)
----------------------------------------------------------------------------
Net loss and comprehensive loss for
the period (744) (617) (4,199) (925)

Deficit, beginning of period (69,151) (58,034) (65,696) (57,726)
----------------------------------------------------------------------------
Deficit, end of period $(69,895) $(58,651) $(69,895) $(58,651)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net loss per share (note 9)
Basic $(0.04) $(0.05) $(0.26) $(0.07)
Diluted $(0.04) $(0.05) $(0.26) $(0.07)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to financial statements.


----------------------------------------------------------------------------
----------------------------------------------------------------------------
FORTRESS ENERGY INC.
STATEMENTS OF CASH FLOWS

For the three and six months ended June 30
(in thousands)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

OPERATING ACTIVITIES
Net loss for the period $ (744) $ ( 617) $ (4,199) $ (925)
Items not affecting cash flows:
Unrealized loss (gain) on
commodity contracts (151) (108) 2,990 (108)
Stock-based compensation 54 169 72 279
Depletion, depreciation and
accretion 3,712 2,209 6,822 4,049
Loss on sale of pipeline asset - - 552 -
Future income tax recovery (244) (506) (1,586) (590)
Abandonment expenditures - - (81) -
----------------------------------------------------------------------------
2,627 1,147 4,570 2,705
Change in non-cash operating
working capital (note 13) 4,256 522 4,008 1,079
----------------------------------------------------------------------------
Cash provided by operating
activities 6,883 1,669 8,578 3,784
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Change in revolving operating loan (3,849) 3,030 (4,108) 6,780
Redemption of common shares (note 9) - 31 - (30,440)
Purchase of common shares (note 9) - - - (186)
Issue of common shares and warrants
(note 9) 14,025 - 14,025 -
Share issuance costs (1,312) - (1,312) -
----------------------------------------------------------------------------
Cash provided by (used in)
financing activities 8,864 3,061 8,605 (23,846)
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Property, plant and equipment
additions (3,249) (4,320) (22,213) (16,170)
Proceeds on sale of pipeline asset
(note 4) 8,150 - 8,150 -
Change in non-cash investing
working capital (note 13) (20,648) (1,767) (3,126) (464)
----------------------------------------------------------------------------
Cash used in investing activities (15,747) (6,087) (17,189) (16,634)
----------------------------------------------------------------------------

Net change in cash - (1,357) (6) (36,696)
Cash and cash equivalents -
beginning of period 38 1,417 44 36,756
----------------------------------------------------------------------------
Cash and cash equivalents - end of
period $ 38 $ 60 $ 38 $ 60
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Supplemental cash flow information
(note 13)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to financial statements.


FORTRESS ENERGY INC.
Notes to Financial Statements
June 30, 2008
(Tabular figures are in thousands of Canadian dollars unless otherwise
indicated)


1. NATURE OF OPERATIONS

Fortress Energy Inc. ("Fortress" or the "Company") 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.

2. SIGNIFICANT ACCOUNTING POLICIES

(a) Basis of presentation

Except as noted below, the unaudited interim 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 for the year ended December 31, 2007. Certain information or disclosures normally required to be included in notes to annual audited financial statements have been condensed or omitted. The unaudited interim financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2007.

The timely preparation of financial statements requires that management make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from estimates.

In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

On January 1, 2008, the Company amalgamated with its subsidiary companies.

(b) Restricted stock unit plan

The Company has a restricted stock unit plan which is described in note 9(f). Restricted stock units vest over a three year period and are settled in cash. A liability and expense are recorded at each reporting date, determined by multiplying the number of vested units by the volume weighted average closing price of the Company's common shares for the 20 day period immediately prior to the reporting date.

(c) Comparative figures

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

3. CHANGES IN ACCOUNTING POLICIES

(a) 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, and Handbook Section 1400 - General Standards of Financial Statement 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, as disclosed in note 11 to the financial statements. The adoption of Section 1400, which includes requirements to assess and disclose the Company's ability to continue as a going concern, did not have an impact on the financial statements.

(b) 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 January 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.

CICA 3064, Goodwill and Intangible Assets, will replace CICA 3062, Goodwill and Other Intangible Assets, and results in withdrawal of CICA 3450, Research and Development Costs, and amendments to Accounting Guideline (AcG) 11, Enterprises in the Development Stage and CICA 1000, Financial Statement Concepts. The standard intends to reduce the differences with IFRS in the accounting for intangible assets and results in closer alignment with U.S. GAAP. Under current Canadian standards, more items are recognized as assets than under IFRS or U.S. GAAP. The objectives of CICA 3064 are to reinforce the principle-based approach to the recognition of assets only in accordance with the definition of an asset and the criteria for asset recognition; and clarify the application of the concept of matching revenues and expenses such that the current practice of recognizing as assets items that do not meet the definition and recognition criteria is eliminated. The standard will also provide guidance for the recognition of internally developed intangible assets (including research and development activities), ensuring consistent treatment of all intangible assets, whether separately acquired or internally developed. Fiscal years beginning on or after October 1, 2008, with early adoption encouraged. The Company is currently evaluating the impact of this standard.

4. SALE OF PIPELINE ASSET

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 required 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, AltaGas agreed to purchase the pipeline from the Company. In exchange, the Company committed to pay a fee to AltaGas for the use of the pipeline as disclosed in note 11. The construction and commissioning of the pipeline was completed in March, 2008 and on April 16, 2008, the Company completed the sale of the pipeline for proceeds of $8,150,000. The total cost incurred to construct the pipeline was $8,702,000 resulting in a loss on the pipeline asset of $552,000.



5. PROPERTY, PLANT AND EQUIPMENT

----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
June 30, 2008 $ $ $
----------------------------------------------------------------------------
Oil and gas properties 130,485 24,407 106,078
Other 351 140 211
----------------------------------------------------------------------------
130,836 24,547 106,289
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


For the three and six months ended June 30, 2008, the Company capitalized general and administrative expenses of $207,000 and $400,000, respectively (three and six months ended June 30, 2007 - $295,000 and $703,000) directly attributable to exploration and development activities. In addition, the Company capitalized stock-based compensation expense related to exploration and development activities of $80,000 in the three and six months ended June 30, 2008.

Estimated future development costs of $15,842,000 (June 30, 2007 - $21,300,000) were included in the calculation of depletion expense for the six months ended June 30, 2008. As at June 30, 2008, undeveloped land costs of $7,362,000 (June 30, 2007 - $4,300,000) were excluded from assets subject to depletion.

6. REVOLVING OPERATING LOAN

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 the three and six months ended June 30, 2008 of 5.00% and 5.25%, respectively, and for the three and six months ended June 30, 2007 - 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 Company has a $1,000,000 letter of credit which reduces its borrowing capacity on the revolving operating loan (June 30, 2007 - $nil).

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 as at June 30, 2008.



7. INCOME TAXES

The provision for income tax recovery recorded in the statement of
operations differs from the amount that would be obtained by applying the
statutory income tax rate to the loss before tax as follows:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Six months
ended June 30, ended June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Loss before tax $ (988) $ (1,123) $(5,785) $(1,515)
----------------------------------------------------------------------------
Expected tax recovery at 30.25%
(June 30, 2007 - 32.12%) (299) (361) (1,750) (487)
Add (deduct) income tax effect of:
Stock-based compensation 17 54 22 90
Non-deductible expenses and
other permanent differences (12) 94 (7) 100
Rate adjustments 50 (293) 149 (293)
----------------------------------------------------------------------------
Income tax recovery (244) (506) (1,586) (590)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. 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 June 30, 2008 to be $3.3 million (December 31, 2007 - $3.1 million) based on a total future liability of $5.3 million (December 31, 2007 - $4.8 million) which will be primarily incurred between 2010 and 2029. An inflation rate of 2.0% (December 31, 2007 - 2.0%) and a credit-adjusted risk-free rate of 7.5% (December 31, 2007 - 7.5%) were used to calculate the fair value of the asset retirement obligations.



----------------------------------------------------------------------------
Asset Retirement Obligations $
----------------------------------------------------------------------------
Balance, December 31, 2007 3,050
Liabilities incurred 259
Accretion expense 75
Abandonment expenditures (81)
----------------------------------------------------------------------------
Balance, June 30, 2008 3,303
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. SHARE CAPITAL

(a) Authorized:

Unlimited number of voting common shares.

Unlimited number of preferred shares.

(b) Common shares issued and outstanding:

----------------------------------------------------------------------------
Number of
Common Shares $
----------------------------------------------------------------------------
Balance, December 31, 2007 15,970,059 121,274
Issued in exchange for employment services (i) 16,829 25
Tax effect of flow-through share
renouncement (ii) - (1,275)
Public offering (iii) 9,350,100 12,471
Share issuance costs (iii) - (1,312)
Tax effect of share issuance costs - 335
----------------------------------------------------------------------------
Balance, June 30, 2008 25,336,988 131,518
----------------------------------------------------------------------------


(i) 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.

(ii) 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 of $1,275,000 was recorded in the first quarter of 2008 when the renouncement documents were filed. As of June 30, 2008, the Company had incurred eligible expenditures of $1,000,000.

(iii) The Company closed a public offering of 11,033,400 units ("Units") on June 20, 2008, June 27, 2008 and July 4, 2008, for gross proceeds of $16,550,100 ($15,002,000 net of issuance costs). Each Unit consists of one common share of the Company and one-half of one common share purchase warrant. The warrants are exercisable on or before June 20, 2011 subject to the right of Company to accelerate the expiry time on not less than 30 days notice to the warrant holders, if the aggregate sales price of the common shares during a period of 20 consecutive days divided by the aggregate number of common shares sold is at least $3.00. Each whole warrant entitles the holder thereof to purchase one common share an at exercise price of $2.00.

These financial statements reflect the issuance of 9,350,100 Units that
were issued before June 30, 2008. The remaining 1,683,300 Units were issued on July 4, 2008 and will be reflected in the Company's financial statements for the three and nine months ended September 30, 2008. The impact of the July 4, 2008 closing on the financial statements for the three and nine months ended September 30, 2008 results in a decrease in the revolving operating loan of $2,289,000 and an increase in share capital of $2,289,000 (net of issuance costs of $236,000). Included in accounts receivable at June 30, 2008 is $749,700 related to 499,800 Units that were issued on June 27, 2008 for which the Company did not receive payment until July 4, 2008.

The fair value of the warrants is $1,554,000 as determined using the Black-Scholes option pricing model with a risk-free interest rate of 3.05%, an expected weighted average life of 1.5 years, an expected volatility of 70% and an expected dividend yield of nil. Accordingly, the fair value assigned to the common shares was $12,471,000.



(c) Warrants issued and outstanding:

----------------------------------------------------------------------------
Number
of Warrants $
----------------------------------------------------------------------------
Balance, December 31, 2007 - -
Public offering (note 9 (b)(iii)) 4,675,050 1,554
----------------------------------------------------------------------------
Balance, June 30, 2008 4,675,050 1,554
----------------------------------------------------------------------------

(d) Contributed surplus:

----------------------------------------------------------------------------
Balance, December 31, 2007 14,428
Stock-based compensation expense (note 10) 32
----------------------------------------------------------------------------
Balance, June 30, 2008 14,460
----------------------------------------------------------------------------


(e) 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.

There were no stock options granted in the three and six months ended June 30, 2008.



The Company has the following stock options outstanding:

----------------------------------------------------------------------------
Outstanding at June 30, 2008 Exercisable at June 30, 2008
Weighted Weighted
Weighted average Average
Exercise average Exercise Exercise
Price years to Price Number Price
$ Number expiry $ exercisable $
----------------------------------------------------------------------------
1.18 375,000 4.5 1.18 - -
19.50 - 50.00 22,000 0.9 20.75 22,000 20.75
----------------------------------------------------------------------------
Outstanding,
June 30, 2008 397,000 4.3 2.26 22,000 20.75
----------------------------------------------------------------------------


(f) Restricted stock unit plan:

In June 2008, the Company approved a restricted stock unit plan. The Board of Directors, in its sole discretion may determine the period in which units credited under this plan shall vest which period shall not exceed three years. Holders are credited with additional units as dividends are declared on the common shares. The value of vested units is determined by the weighted average of the board lot trading prices of the Company's common shares traded on the TSX for the last 20 trading days immediately prior to the day such units mature. Such amount is paid in cash within 30 days.

As at June 30, 2008, there were 500,000 restricted stock units outstanding which mature on December 31, 2010 and vest over a three year period. The Company recorded a liability at June 30, 2008 based on the intrinsic value which was determined by multiplying the number of vested units by the volume weighted average closing price of the Company's common shares for the 20 day period immediately prior to June 30, 2008. For the three and six months ended June 30, 2008, the Company recorded compensation expense related to the restricted stock unit plan of $120,000 of which $72,000 was capitalized to property, plant and equipment and $48,000 was included in stock-based compensation expense.

(g) Per share amounts:

The weighted average number of common shares outstanding for the three and six months ended June 30, 2008 and 2007 are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Six months
ended June 30, ended June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Weighted average
- basic and diluted 16,808,660 13,257,860 16,394,538 13,260,828
----------------------------------------------------------------------------


Stock-based compensation arrangements and warrants outstanding at June 30, 2008 and 2007 were not included in the calculation of weighted average - diluted common shares outstanding because they were anti-dilutive.

10. 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:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Risk-free interest rate (%) - 3.75 - 3.75
Expected life (years) - 5.0 - 5.0
Expected volatility (%) - 50.0 - 50.0
Expected dividend yield (%) - - - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 (June 30, 2007 - $2.09) is amortized to expense over the vesting period on a straight-line basis. For the three months and six months ended June 30, 2008, the Company recorded compensation expense of $14,000 and $32,000, respectively, related to stock options (three and six months ended June 30, 2007 - $169,000 and $279,000, respectively).

11. FINANCIAL INSTRUMENTS

Overview

The Company has exposure to the following risks from its financial instruments:

- Credit risk;

- Liquidity risk; and

- Market risk.

The Company's Board of Directors has overall responsibility for the establishment and oversight of the Company's risk management framework and establishes and monitors risk management policies to: identify and analyze the risks faced by the Company; to set appropriate limits and controls; and to monitor risks and adherence to market conditions and the Company's activities.

Credit Risk

Credit risk is primarily related to the Company's receivables from joint venture partners and petroleum and natural gas marketers and the risk of financial loss if a customer, partner or counterparty to a financial instrument fails to meet its contractual obligations. A substantial portion of the Company's accounts receivable are with customers in the energy industry and are subject to normal industry credit risk. The Company generally grants unsecured credit but routinely assesses the financial strength of its customers.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company sells the majority of its production to two petroleum and natural gas marketers therefore is subject to concentration risk which is mitigated by management's policies and practices related to credit risk, as discussed above. The Company historically has not experienced any collection issues with its petroleum and natural gas marketers. Joint venture receivables are typically collected within one to three months of the joint venture bill being issued to the partner. However, the receivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs, the risk of unsuccessful drilling and occasional disagreements between parties. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to expenditure. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however in certain circumstances, it may cash call a partner in advance of the work. As well, the Company does have the ability to withhold production from joint venture partners in the event of non-payment.

The Company establishes an allowance for doubtful accounts as determined by management based on their assessment of collection therefore the carrying amount of accounts receivable generally represents the maximum credit exposure. There were no receivables written off during the three and six months ended June 30, 2008.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The Company's approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due without incurring unacceptable losses or risking harm to the Company's reputation.

The Company prepares capital expenditures budgets which are regularly monitored and updated as considered necessary. As well, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has a revolving credit facility (note 6) that is reviewed annually by the lender.

Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company's net earnings or the value of financial instruments. The objective of market risk management is to mitigate exposures within acceptable limits, while maximizing returns.

The Company utilizes commodity price contracts to manage market risks relevant to commodity prices. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

Foreign Currency Exchange Risk

Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although all of the Company's petroleum and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for petroleum and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollar. The Company had no forward exchange rate contracts in place as at or during the three and six months ended June 30, 2008.

Commodity Price Risk

Commodity price risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by world economic events that dictate the levels of supply and demand. The Company has attempted to mitigate commodity price risk through the use of financial derivative sales contracts. The Company's contracts in place as of June 30, 2008 are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Type Period Volume (GJ/d) Fixed Price
($/GJ)
----------------------------------------------------------------------------
Swap January 1, 2008 2,000 6.51
to October 31, 2008

Swap January 1, 2008 3,000 6.505
to October 31, 2008
----------------------------------------------------------------------------


For the three and six months ended June 30, 2008, the Company realized a loss related to these commodity contracts of $1,072,000 and $1,185,000 respectively (three and six months ended June 30, 2007 - a gain of $97,000) and recorded an unrealized gain for the three months ended June 30, 2008 of $151,000 and an unrealized loss for the six months ended June 30, 2008 of $2,990,000 (three and six months ended June 30, 2007 - a gain of $108,000). A $1.00 change in the AECO price would increase or decrease this loss for the three months ended June 30, 2008 by $455,000.

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 June 30, 2008. For the three months ended June 30, 2008, a difference in interest rate of 1.0% would change net earnings by an estimated $48,000.

Capital Management

The Company's policy is to maintain a strong capital base for the objectives of maintaining financial flexibility, creditor and market confidence and to sustain the future development of the business.

The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company considers its capital structure to include shareholders' equity and working capital. In order to maintain or adjust the capital structure, the Company may from time to time issue shares and adjust its capital spending to manage current and projected debt levels. To assess capital and operating efficiency and financial strength, the Company continually monitors its net debt and working capital which is a non-GAAP measure and calculated as follows:



----------------------------------------------------------------------------
June 30, 2008 December 31, 2007
----------------------------------------------------------------------------
Current assets $ 11,907 $ 8,665
Current liabilities (35,722) (32,694)
----------------------------------------------------------------------------
Net debt and working capital deficiency $ (23,815) $ (24,029)
----------------------------------------------------------------------------


The net debt and working capital deficiency is a result of normal operating conditions in periods when the Company incurs significant capital expenditures relative to revenue. Net debt is defined as current assets less current liabilities.

The Company's share capital is not subject to external restrictions; however the credit facility is based on petroleum and natural gas reserves. The Company has not paid or declared any dividends since the date of incorporation, nor are any contemplated in the foreseeable future.

Fair Value of Financial Instruments

The Company's financial instruments as at June 30, 2008 include accounts receivable, commodity contracts, accounts payable and the revolving operating loan. The fair value of accounts receivable and accounts payable approximate their carrying amounts due to their short terms to maturity. The fair value of commodity contracts is determined by calculating the difference between the contracted price and published forward price curves as at the balance sheet date, using the remaining contracted natural gas volumes. The Company's revolving operating loan bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.



The carrying and fair values of the Company's financial instruments are as
follows:

----------------------------------------------------------------------------
Classification Carrying Value Fair Value
$ $
----------------------------------------------------------------------------
Held-for trading (cash and commodity contracts) (2,861) (2,861)
Loans and receivables (accounts receivable) 11,483 11,483
Held-to-maturity - -
Other liabilities (accounts payable and revolving
operating loan) (32,823) (32,823)
----------------------------------------------------------------------------
Total (24,201) (24,201)
----------------------------------------------------------------------------


12. COMMITMENTS AND CONTINGENCIES

Office space and equipment

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

----------------------------------------------------------------------------
Equipment Office
Rental Lease Total
$ $ $
----------------------------------------------------------------------------
Balance of 2008 286 211 497
2009 148 423 571
2010 - 435 435
2011 - 439 439
2012 - 439 439
Thereafter - 110 110
----------------------------------------------------------------------------
434 2,057 2,491
----------------------------------------------------------------------------


Transportation and Processing

The Company has an agreement for the transportation and processing of natural gas from the Company's Square Creek, Alberta area. The Company is 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 earlier of April 1, 2015 or the delivery of a total of 15 bcf.



Committed payments are as follows:

----------------------------------------------------------------------------
$
----------------------------------------------------------------------------
Balance of 2008 683
2009 1,260
2010 1,052
2011 767
2012 767
Thereafter 1,605
----------------------------------------------------------------------------
6,134
----------------------------------------------------------------------------


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 represent only the Company's 50% working interest.

Letter of Credit

On February 1, 2008, the Company issued a letter of credit of $1,000,000 with an expiry of February 1, 2009, related to a gas transportation and processing agreement.



13. CHANGE IN NON-CASH WORKING CAPITAL

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

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
$ $ $ $

Accounts receivable and accrued
revenue (1,087) (1,370) (3,519) (3,633)
Prepaid expenses and deposits 481 30 179 (15)
Accounts payable and accrued
liabilities (15,746) 95 4,237 4,546
Income taxes payable - - - (283)
----------------------------------------------------------------------------
(16,352) (1,245) 897 615
Accounts payable settled
through issuance of shares - - 25 -
Stock-based compensation
included in accounts payable (40) - (40) -
----------------------------------------------------------------------------
(16,392) (1,245) 882 615
Attributable to investing
activities (20,648) (1,767) (3,126) (464)
----------------------------------------------------------------------------
Attributable to operating
activities 4,256 522 4,008 1,079
----------------------------------------------------------------------------

Interest paid 248 72 588 90
----------------------------------------------------------------------------
----------------------------------------------------------------------------


14. RELATED PARTY TRANSACTIONS

In the three and six months ended June 30, 2008, the Company was charged $246,000 and $576,000 respectively, 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 June 30, 2008.

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.

15. SUBSEQUENT EVENTS

(a) On July 8, 2008, the Company granted stock options to acquire 1,684,633 common shares of the Company at an exercise price of $1.35 per share, expiring July 8, 2013.

(b) On July 21, 2008, the Company entered into a commodity price contract to sell 1,250 GJ/d of natural gas at $9.58/GJ for the period of November 1, 2008 to March 31, 2009.

(c) On August 8, 2008, the Company entered into a commodity price contract to sell 3,750 GJ/d of natural gas at $8.25/GJ for the period of November 1, 2008 to March 31, 2009.

(d) On July 4, 2008, the Company completed the closing of 1,683,300 Units for gross proceeds of $2,524,950 ($2,289,000 net of issuance costs), as referred to in note 9 (b)(iii).

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.

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