Fortress Energy Inc.
TSX : FEI

Fortress Energy Inc.

August 14, 2009 16:06 ET

Fortress Energy Inc. Announces Second Quarter 2009 Financial and Operating Results

CALGARY, ALBERTA--(Marketwire - Aug. 14, 2009) -

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

Fortress Energy Inc. ("Fortress" or the "Company") (TSX:FEI) announces the results for the second quarter ended June 30, 2009.

North American Natural Gas Market Overview

With less that 680 rigs operating in the United States and 82 operating in Canada focused on natural gas drilling, the North American natural gas supply may decline quickly absorbing much of the surplus of gas that is currently appearing in buoyant inventories. Mr. Bailey, President and CEO of Fortress, has completed an analysis of North American Natural Gas Markets which can be reviewed at:

http://fortressenergy.ca/files/US%20Natural%20Gas%20Markets%20August%2012.ppt
along with

"Has Anyone Done the Math?"

http://www.fortressenergy.ca/files/Has%20Anyone%20Done%20the%20Math%20v4.pdf.

His conclusion is there is an insufficient number of natural gas focused rigs operating, which will cause critical supply shortages and natural gas prices to increase.

Recent Initiatives

In light of the current down turn and our view of current market fundamentals, we have undertaken a number of initiatives to assist in improving future profitability:

- Entered into a series of forward sale contracts that result in 4.6 Mmcf/d, being 60% of our current production, receiving an average price of $7.92/mcf until December 31, 2009 and $8.36/mcf until March 31, 2010.

- Voluntarily shutting-in approximately 1.8 Mmcf/d of production which can be brought back on stream when higher natural gas prices prevail.

- Reduction of fixed operating costs by consolidating remote operations at Square Creek and re-routing gas at Velma allowing for annual savings of $800,000, being $0.28/mcf. Further operating cost reductions are being pursued. The operating cost reduction will not be experienced in operating results until the third quarter of 2009.

- Entered into a Letter of Intent which allows Fortress to acquire the 50% working interest in Square Creek it currently does not own, for cash consideration of $7,000,000. Completion of the acquisition would provide Fortress an additional 2.7 Mmcf/d of production and the potential to increase production from the area. Since Fortress is the operator of the property, no additional staff or overhead would be required to manage these additional assets.

Highlights of the second quarter include:

- During the quarter Fortress received an average price of $6.22/mcf ($37.35 per boe) from 7.7 Mmcf/d (1,279 boe/d) of production compared to an average spot price of $3.45/mcf during the quarter.

- Operating net back was $1,800,000 or $2.58/mcf ($15.46/boe).

- Achieved funds from operations of $557,000 or $0.02 per share.

- Production from Square Creek averaged gross 5.4 mmcf/d (2.7 mmcf/d net) with approximately 3.6 Mmcf/d (1.8 Mmcf/d net) voluntarily shut-in.


- The low natural gas price environment has resulted in a ceiling test impairment charge of $14,276,000 having the effect of reducing the book value of the Company's assets by such amount.

Fortress's board of directors has accepted the resignation of Richard A. Grafton as a director of the Company. In tendering his resignation Mr. Grafton cited personal reasons, and expressed concern that he may not be able to dedicate the time that may be required as a director of Fortress. The Company accepted Mr. Grafton's resignation with regret, thanked him for his attention to the affairs of the Company since his initial appointment in January 2008 and wished him well in all of his future endeavors.

FINANCIAL AND OPERATING SUMMARY



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Three months ended June 30,
2009 2008
($000s) $/boe ($000s) $/boe
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Petroleum and natural gas sales 4,346 37.35 7,231 54.31
Royalties (442) (3.80) (1,293) (9.71)
Operating costs (1,855) (15.95) (2,051) (15.40)
Transportation (249) (2.14) (237) (1.78)
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Operating netback (1) 1,800 15.46 3,650 27.42
General and administrative expenses (639) (5.48) (566) (4.25)
Professional fees (337) (2.90) (149) (1.11)
Bad debts (37) (0.32) 53 0.40
Interest expense (212) (1.82) (361) (2.71)
Current income tax expense (18) (0.15) - -
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Funds from operations (1) 557 4.79 2,627 19.74
Unrealized gain (loss) on commodity
contracts (922) (7.92) 151 1.13
Depletion, depreciation and accretion (3,695) (31.75) (3,712) (27.88)
Ceiling test impairment (14,276) (122.69) - -
Stock-based compensation expense (48) (0.41) (54) (0.41)
Write-down of pipeline asset held for
sale - - - -
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Loss before future income taxes (18,384) (157.98) (988) (7.42)
Future income tax recovery 3,779 32.48 244 1.83
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Net loss (14,605) (125.50) (744) (5.59)
Sales volume (boe/d) 1,279 1,463
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Six months ended June 30,
2009 2008
($000s) $/boe ($000s) $/boe
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Petroleum and natural gas sales 9,552 41.07 12,868 51.83
Royalties (920) (3.96) (2,263) (9.12)
Operating costs (3,670) (15.78) (3,426) (13.80)
Transportation (495) (2.13) (449) (1.80)
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Operating netback (1) 4,467 19.20 6,730 27.11
General and administrative expenses (1,361) (5.85) (1,054) (4.25)
Professional fees (488) (2.10) (337) (1.36)
Bad debts (179) (0.77) 53 0.21
Interest expense (453) (1.95) (741) (2.98)
Current income tax expense (36) (0.15) - -
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Funds from operations (1) 1,950 8.38 4,651 18.74
Unrealized gain (loss) on commodity
contracts 1,496 6.43 (2,990) (12.04)
Depletion, depreciation and accretion (7,508) (32.28) (6,822) (27.48)
Ceiling test impairment (14,276) (61.37) - -
Stock-based compensation expense (127) (0.55) (72) (0.29)
Write-down of pipeline asset held for
sale - - (552) (2.22)
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Loss before future income taxes (18,465) (79.39) (5,785) (23.29)
Future income tax recovery 3,867 16.63 1,586 6.38
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Net loss (14,598) (62.76) (4,199) (16.91)
Sales volume (boe/d) 1,285 1,364
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(1) Non-GAAP measures. See discussion in the following Management Discussion
& Analysis.


MANAGEMENT'S DISCUSSION AND ANALYSIS

August 14, 2009

This 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, 2009 and the audited consolidated financial statements of Fortress Energy Inc. for the year ended December 31, 2008. 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 the MD&A are not recognized measures under GAAP. Management believes that in addition to net income, funds from operations and operating netback are useful supplemental measures as they provide an indication of the results generated by the Company's principal business activities before the consideration of how those activities are financed. Investors are cautioned, however, that these measures should not be construed as alternatives to net income determined in accordance with GAAP.

The Company's method of calculating funds from operations may differ from that of other companies, and, accordingly it may not be comparable to measures used by other companies. The Company calculates funds from operations by taking cash flow from operating activities as determined under GAAP before changes in non-cash operating working capital and abandonment expenditures. The consolidated statements of cash flows included in the consolidated financial statements present the reconciliation between net income (loss) and funds from operations. A summary of this reconciliation is as follows:



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($000s) Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
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Cash provided by operating activities 1,879 6,883 2,476 8,578
Change in non-cash operating working
capital (1,324) (4,256) (698) (4,008)
Abandonment expenditures 2 - 172 81
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Funds from operations 557 2,627 1,950 4,651
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Operating netback is calculated on a per boe basis taking the sale price and
deducting royalties, operating expenses and transportation expenses, as
follows:

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Three months ended June 30,
2009 2008
($000s) ($/boe) ($000s) ($/boe)
----------------------------------------------------------------------------
Petroleum and natural gas
sales 4,346 37.35 7,231 54.31
Royalties (442) (3.80) (1,293) (9.71)
Operating expenses (1,855) (15.95) (2,051) (15.40)
Transportation expenses (249) (2.14) (237) (1.78)
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Operating netback 1,800 15.46 3,650 27.42
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Six months ended June 30,
2009 2008
($000s) ($/boe) ($000s) ($/boe)
----------------------------------------------------------------------------
Petroleum and natural gas
sales 9,552 41.07 12,868 51.83
Royalties (920) (3.96) (2,263) (9.12)
Operating expenses (3,670) (15.78) (3,426) (13.80)
Transportation expenses (495) (2.13) (449) (1.80)
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Operating netback 4,467 19.20 6,730 27.11
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BOE Presentation

Natural gas reserves and volumes recorded in thousand cubic feet are converted to barrels of oil equivalent ("boe") on the basis of six thousand cubic feet ("mcf") of gas to one barrel ("bbl") of oil. The term "barrels of oil equivalent" may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf to 1 bbl is based on an energy equivalent conversion method primarily applicable at the burner tip and is not intended to represent a value equivalent at the wellhead.

Forward-Looking Statements

Certain 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. Without limiting the generality of the foregoing, the Company has made materially forward-looking statements:

(i) Under "Capital Expenditures" regarding the Pine Creek exploration well and anticipated timing of production; and

(ii) Under "Liquidity and Capital Resources" regarding working capital requirements.

The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The Company cautions the reader that actual performance will be affected by a number of factors, including 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 (applicable to the forward-looking statements (i) through (iii) above), delays or changes in plans (applicable to the forward-looking statements identified in (i) through (iii) above); 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:

(i) 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);

(ii) Delays or changes in plans with respect to exploration or development projects or capital expenditures;

(iii) Uncertainty of estimates and projections relating to recoverable reserves, costs and expenses;

(iv) Health, safety and environmental risks;

(v) Commodity price and exchange rate fluctuations; and

(vi) Liquidity risk and working capital requirements (refer to "Liquidity and Capital Resources" on page 10 of this MD&A).

Forward-looking statements contained herein are made as of the date hereof subject to the requirements of applicable securities legislation and except as otherwise required by law, the Company assumes no obligation to update any forward-looking statements, whether as a result of new information, future events and results, or otherwise. There can be no assurance that forward-looking statements will prove to be accurate, as actual results and future events could differ materially from those anticipated in such statements. Accordingly, the reader is cautioned not to place undue reliance on forward-looking statements.

DESCRIPTION OF THE BUSINESS

Fortress' primary focus is the exploration and development of natural gas reserves in Western Canada. The Company has approximately 80,500 net acres of undeveloped land in the Ladyfern, Velma and Buick Creek areas in northeast British Columbia and the Chigwell, Bashaw, Square Creek, Halverson, and Mearon areas of Alberta.

The Company's strategy is to acquire and exploit properties that are early in their development cycle and that offer exploration, appraisal and development drilling opportunities, while maintaining low finding and development costs. Fortress is the operator of most of its production, providing control over cost management of its operating and capital programs.

DETAILED FINANCIAL ANALYSIS

Production



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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
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Sales volume:
Natural gas (mcf/d) 7,603 8,690 7,634 8,040
Oil and NGL (bbls/d) 12 15 13 24
Total (boe/d) 1,279 1,463 1,285 1,364
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Sales volumes for the three months ended June 30, 2009 were 1,279 boe/d compared to 1,463 boe/d for the three months ended June 30, 2008. Total sales volumes have decreased by 13 percent in the three months ended June 30, 2009 compared to the three months ended June 30, 2008. This decrease results from the Company electing to cut back production by 300 boe/d by shutting in several Square Creek wells due to low natural gas prices. This shut-in production can be restored at the Company's choice.

Sales volumes for the six months ended June 30, 2009 were 1,285 boe/d compared to 1,364 boe/d for the six months ended June 30, 2008, a decrease of 6 percent. This decrease is consistent with the three months ended June 30, 2009, as previously noted.

Revenue



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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
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Petroleum and natural gas sales ($000s) 4,346 7,231 9,552 12,868
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Average realized prices:
Natural gas ($/mcf) 3.71 10.32 4.53 9.33
Realized gain (loss) on commodity
contracts ($/mcf) 2.51 (1.34) 2.31 (0.80)
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Realized natural gas price ($/mcf) 6.22 8.98 6.84 8.53
Oil and NGL ($/bbl) 45.11 108.04 41.95 88.34
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Combined average realized price
($/boe) 37.35 54.31 41.07 51.83
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Benchmark prices:
AECO average natural gas price ($/mcf) 3.45 9.82 4.18 8.90
Edmonton par crude oil ($/bbl) 66.70 126.37 58.95 112.34
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Petroleum and natural gas sales which include realized gains and losses on commodity contracts, for the three months ended June 30, 2009 were $4,346,000 compared to $7,231,000 for the three months ended June 30, 2008, a decrease of 40 percent. This decrease is attributable to a 31 percent decrease in the combined average realized commodity price in the second quarter of 2009 from the second quarter of 2008 and a 13 percent decrease in sales volumes.

For the six months ended June 30, 2009, petroleum and natural gas sales were $9,552,000 compared to $12,868,000 for the six months ended June 30, 2008 - a decrease of 26 percent. This decrease is attributable to a 21 percent decrease in the combined average realized commodity price and a 6 percent decrease in sales volumes in the first half of 2009 when compared to the same period in 2008.

The average natural gas price realized by the Company for the second quarter of 2009 was $3.71/mcf compared to the AECO average price of $3.45/mcf. This compares to the average natural gas price realized in the second quarter of 2008 of $10.32/mcf and an AECO average price of $9.82/mcf. The average natural gas price realized by the Company for the six months ended June 30, 2009 was $4.53/mcf compared to the AECO average price of $4.18/mcf. This compares to the average natural gas price realized in six months ended June 30, 2008 of $9.33/mcf and an AECO average price of $8.90/mcf. The Company receives a slight premium to the AECO price of approximately 4 percent to 5 percent due to the higher heating value of its natural gas.

The Company uses commodity contracts to manage its exposure to fluctuations in the price of natural gas. For the three months ended June 30, 2009, the Company realized a gain on commodity contracts of $1,733,000, or $2.51/mcf, compared to a realized loss on commodity contracts of $1,072,000, or $1.34/mcf, in the three months ended June 30, 2008, which is included in petroleum and natural gas sales. The Company recorded an unrealized loss on commodity contracts in the three months ended June 30, 2009 of $922,000 compared to an unrealized gain on commodity contracts for the three months ended June 30, 2008 of $151,000.

For the six months ended June 30, 2009, the Company realized a gain on commodity contracts of $3,192,000, or $2.31/mcf, compared to a realized loss on commodity contracts of $1,185,000 or $0.80/mcf for the six months ended June 30, 2008. In addition, the unrealized gain on commodity contracts in the six months ended June 30, 2009 was $1,496,000 compared to an unrealized loss on commodity contracts of $2,990,000. The Company has sold forward approximately 60 percent of its natural gas production through to the end of the first quarter of 2010 giving the Company a degree of certainty over its cash flow. The estimated mark-to-market value of the Company's commodity contracts at June 30, 2009 was $3,983,000.

At June 30, 2009 the Company had the following commodity contracts in place:



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Period Volume (GJ/d) ($/GJ)
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Swap April 1, 2009 to December 31, 2009 5,100 7.20
Swap January 1, 2010 to March 31, 2010 2,600 8.38
Swap January 1, 2010 to March 31, 2010 2,500 6.80
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Royalties

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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
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Royalties ($000s) 442 1,293 920 2,263
$/boe 3.80 9.71 3.96 9.12
Percentage of petroleum and natural gas
sales (1) 16.9% 15.6% 14.5% 16.1%
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(1) Before realized gains and losses on commodity contracts.


Royalties decreased to $442,000 for the second quarter of 2009 from $1,293,000 for the second quarter of 2008. This decrease is due to a reduction in the natural gas price which fell from $10.32/mcf in the second quarter of 2008 to $3.71/mcf in the second quarter of 2009 - a decrease of 64 percent. Royalties are not attributed to realized gains and losses on commodity contracts. The effective royalty rate for the second quarter of 2009 was 16.9 percent compared to 15.6 percent for the second quarter of 2008. This increase reflects a charge in the second quarter of 2009 of $60,000 related to an audit and reassessment of Alberta Royalty Tax Credits of a predecessor company.

For the six months ended June 30, 2009, royalties were $920,000 compared to $2,263,000 for the six months ended June 30, 2008. This decrease is attributed to a 51 percent decrease in the natural gas price realized.

Operating Expenses



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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Operating costs ($000s) 1,855 2,051 3,670 3,426
$/boe 15.95 15.40 15.78 13.80
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For the three months ended June 30, 2009, operating expenses were $1,855,000 or $15.95/boe compared to $2,051,000 or $15.40/boe for the three months ended June 30, 2008. Operating expenses decreased in the second quarter of 2009 due to a decrease in production volumes. Operating expenses increased on a per boe basis due to an increase in Square Creek production volumes in the second quarter of 2009 which records higher operating costs relative to the Company's other properties. The Company's Square Creek property is a remote winter-access property which contributes to its relatively high operating costs.

For the six months ended June 30, 2009, operating expenses were $3,670,000 compared to $3,426,000 for the six months ended June 30, 2008. Operating costs for the six months ended June 30, 2009 were higher than the six months ended June 30, 2008 because they included six months of Square Creek operations compared to only three months in the first six months of 2008.

The Company has taken several steps to reduce operating costs at Square Creek, including the purchase of a rented compressor, camp, rig mats and other rented equipment. In addition, the Company tendered the field operations contract for Square Creek and re-routed its Velma production to another third party processing plant which is expected to result in approximately $800,000 of annualized savings to the Company.

Transportation Expenses



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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Transportation costs ($000s) 249 237 495 449
$/boe 2.14 1.78 2.13 1.80
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Transportation costs for the three months ended June 30, 2009 were $249,000 compared to $237,000 for the second quarter of 2008. Transportation costs include the transportation and fuel costs associated with the usage of natural gas pipelines. Transportation costs for the six months ended June 30, 2009 were $495,000 compared to $449,000 for the six months ended June 30, 2008. The rate that the Company was charged for interruptible transportation services increased in October 2008. The Company also secured an additional firm transportation services contract at Owl Lake where all of its gas from the general Ladyfern area is sold.

General and Administrative Expenses



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Three months ended June 30, Six months ended June 30,
2009 2008 2009 2008
($000s) ($/boe) ($000s) ($/boe) ($000s) ($/boe) ($000s) ($/boe)
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General and
administrative
expenses,
net of
recoveries 639 5.48 566 4.25 1,361 5.85 1,054 4.25
Professional
fees 337 2.90 149 1.11 488 2.10 337 1.36
Bad debts 37 0.32 (53) (0.40) 179 0.77 (53) (0.21)
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Total 1,013 8.70 662 4.96 2,028 8.72 1,338 5.40
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General and administrative expenses, net of recoveries, increased to $639,000 in the three months ended June 30, 2009 from $566,000 in the second quarter of 2008. This increase is due to a reduction in overhead recoveries from partners as a result of the amount of capital spending in the second quarter of 2009 compared to the same period in 2008. The Company also hired an additional consultant in July 2008. General and administrative expenses, net of recoveries, for the six months ended June 30, 2009 were $1,361,000 compared to $1,054,000 for the six months ended June 30, 2008. This increase is due to lower overhead recoveries from partners and additional consulting fees.

Professional fees include fees for lawyers, auditors, income tax professionals, independent reserves evaluators, and other advisors. Professional fees increased in the second quarter of 2009 compared to the second quarter of 2008 due to additional tax compliance matters arising in the quarter. Professional fees for the six months ended June 30, 2009 were $488,000 compared to $337,000 for the six months ended June 30, 2008 due to additional tax compliance matters arising in the first half of 2009.

Bad debts for the three months ended June 30, 2009 were $37,000 compared to a recovery of $53,000 in the second quarter of 2008. Bad debts reflect the accounts of former joint venture partners that are considered uncollectible; many of these accounts are related to companies that were acquired by the Company.

Stock-based Compensation Expense



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Three months ended Six months ended
June 30, June 30,
($000s except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Stock-based compensation expense:
Stock options 35 6 96 24
Restricted stock units 13 48 31 48
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Total 48 54 127 72
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$/boe 0.41 0.41 0.55 0.29
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Stock-based compensation expense for the second quarter of 2009 was $48,000 compared to $54,000 for the second quarter of 2008. Stock-based compensation expense for the six months ended June 30, 2009 was $127,000 compared to $72,000 for the six months ended June 30, 2008. In the third quarter of 2008, the Company granted 1,684,633 stock options to employees, officers and directors of the Company with an exercise price of $1.35 per share, expiring July 8, 2013. Also in the third quarter of 2008, the Company introduced a restricted stock unit plan.

Interest Expense



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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Interest expense ($000s) 212 361 453 741
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$/boe 1.82 2.71 1.95 2.98
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The Company recorded interest expense of $212,000 for the second quarter of 2009 compared to $361,000 for the second quarter of 2008. Interest expense for the second quarter of 2009 reflects interest on the Company's bank indebtedness and accrued interest and penalties on an income tax reassessment. Interest expense for the second quarter of 2008 reflects interest on bank indebtedness and accrued interest on flow-through commitments. Interest expense for the six months ended June 30, 2009 was $453,000 compared to $741,000 for the six months ended June 30, 2008. This decrease is due to a decrease in the prime lending rate which averaged 2.54% for the six months ended June 30, 2009 compared to 5.17% for the six months ended June 30, 2008. In addition, interest expense for the six months ended June 30, 2008 included interest on flow-through commitments of $120,000.

Depletion, Depreciation and Accretion Expense



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Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Depletion and depreciation expense
($000s) 3,638 3,668 7,393 6,747
Accretion of asset retirement
obligations ($000s) 57 44 115 75
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Depletion, depreciation and accretion
expense ($000s) 3,695 3,712 7,508 6,822
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Ceiling test impairment ($000s) 14,276 - 14,276 -
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Depletion and depreciation expense
($/boe) 31.26 27.55 31.98 27.18
Accretion of asset retirement
obligations ($/boe) 0.49 0.33 0.50 0.30
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Depletion, depreciation and accretion
expense ($/boe) 31.75 27.88 32.28 27.48
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Ceiling test impairment ($/boe) 122.69 - 61.37 -
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Depletion and depreciation expense is calculated based on capital expenditures, production rates, and proved reserves. Depletion and depreciation expense was $3,638,000 for the three months ended June 30, 2009 compared to $3,668,000 for the three months ended June 30, 2008. On a per boe basis, depletion and depreciation expense increased to $31.26/boe for the three months ended June 30, 2009 from $27.55/boe for the three months ended June 30, 2008. In the first quarter of 2009, the Company drilled 3 wells for which no new reserves were assigned resulting in an increase in the depletion and depreciation rate.

Depletion and depreciation expense for the six months ended June 30, 2009 was $7,393,000 compared to $6,747,000 for the six months ended June 30, 2008. On a per boe basis, depletion and depreciation expense increased to $31.98/boe for the six months ended June 30, 2009 from $27.18/boe for the six months ended June 30, 2008. This increase is consistent with that of the three months ended June 30, 2009.

In the three and six months ended June 30, 2009, the Company recorded a ceiling test impairment charge of $14,276,000 due to a significant decrease in natural gas prices. The impact of the ceiling test impairment charge was $122.69/boe and $61.37/boe for three and six months ended June 30, 2009, respectively.

Estimated future development costs for proved undeveloped properties included in the calculation of depletion expense at June 30, 2009 decreased to $11,235,000 from $15,842,000 at June 30, 2008 due to the Company's development activities at Square Creek. In addition, pressure testing conducted in March 2009 on wells at Square Creek indicated that the Company does not need to drill any additional wells to drain the Bluesky pool resulting in a reduction of future development costs. Undeveloped land costs at June 30, 2009 increased to $7,477,000 from $7,362,000 at June 30, 2008 and were excluded from assets subject to depletion. Undeveloped land costs increased in the second quarter of 2009 due to additional Crown land purchases.

Accretion expense for the second quarter of 2009 was $57,000 compared to $44,000 for the second quarter of 2008. This increase is due to capital expenditures in the Pine Creek and Square Creek areas in the first quarter of 2009. For the six months ended June 30, 2009, accretion costs amounted to $115,000 compared to $75,000 for the six months ended June 30, 2008. This increase is due to capital expenditures in the first quarter of 2009, as noted.

Income Tax



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Three months ended Six months ended
June 30, June 30,
($000s except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Current income tax expense 18 - 36 -
Future income tax recovery (3,779) (244) (3,867) (1,586)
----------------------------------------------------------------------------
Total (3,761) (244) (3,831) (1,586)
----------------------------------------------------------------------------
$/boe (32.33) (1.83) (16.48) (6.38)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company recorded an income tax recovery for the second quarter of 2009 of $3,761,000 which compares to $244,000 for the second quarter of 2008. In the second quarter of 2009, the Company recorded a ceiling test impairment charge of $14,276,000 which resulted in a reversal of the future income taxes in the quarter.

In each of the first two quarters of 2009, the Company recorded current income tax expense of $18,000 consisting of arrears interest. All tax returns have been filed but not all have yet been assessed by CRA. Future income tax recoveries reflect the differences between the underlying tax values and carrying values of the Company's assets and liabilities.

The estimated tax pools of the Company at June 30, 2009 are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
($000s)
----------------------------------------------------------------------------
Canadian Oil and Gas Property Expenses 14,277
Canadian Development Expenses 27,976
Canadian Exploration Expenses 14,810
Undepreciated Capital Cost 27,710
----------------------------------------------------------------------------
84,773
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net Loss

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Net loss ($000s) (14,605) (744) (14,598) (4,199)
Net loss per share - basic and
diluted ($) (0.54) (0.04) (0.54) (0.26)
Net loss ($/boe) (125.50) (5.59) (62.76) (16.91)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company recorded a net loss of $14,605,000 for the second quarter of 2009 compared to a net loss of $744,000 for the second quarter of 2008. This translates into basic and diluted net loss per share of $0.54 for the second quarter of 2009 compared to $0.04 for the second quarter of 2008. The net loss for the second quarter of 2009 is mainly due to a ceiling test impairment charge in the quarter of $14,276,000. The net loss for the six months ended June 30, 2009 was $14,598,000 compared to $4,199,000 for the six months ended June 30, 2008. The net loss for the six months ended June 30, 2009 is attributed to the ceiling test impairment charge in the second quarter. The net loss for the six months ended June 30, 2008 is due to an unrealized loss on commodity contracts of $2,990,000 and the loss on the sale of a pipeline asset of $552,000

Funds from Operations



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Funds from operations ($000s) (1) 557 2,627 1,950 4,651
Funds from operations ($/boe) 4.79 19.74 8.38 18.74
Funds from operations per share - basic
and diluted ($) 0.02 0.16 0.07 0.28
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Non-GAAP measure as defined on page 2.


Funds from operations for the second quarter of 2009 were $557,000 compared to $2,627,000 for the second quarter of 2008. This decrease is attributable to lower operating netbacks resulting from significantly lower natural gas prices. Funds from operations for the six months ended June 30, 2009 were $1,950,000 compared to $4,651,000 for the six months ended June 30, 2008. This decrease is also due to lower natural gas prices realized in the period.

Capital Expenditures



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
($000s) 2009 2008 2009 2008
----------------------------------------------------------------------------
Land and seismic 145 150 264 583
Drilling and completions 188 284 4,231 5,041
Equipment and facilities 616 2,501 2,001 16,076
Capitalized overhead costs 278 287 486 480
Abandonments 2 - 172 81
Other 11 27 21 33
Dispositions - (8,150) - (8,150)
----------------------------------------------------------------------------
1,240 (4,901) 7,175 14,144
----------------------------------------------------------------------------
----------------------------------------------------------------------------


During the first quarter of 2009, the Company finished operations relating to the completion of an exploratory well in the Pine Creek area and undertook the drilling of three wells in the Square Creek area, the Company's core producing property. At Pine Creek, the Company is continuing to analyze the results from the extensive pressure testing undertaken during completion operations. This information will allow the Company to decide on the most appropriate next steps in developing this high-impact prospect, whether it be a horizontal leg to the existing vertical well or the drilling of another vertical well in a portion of the section which would be aimed at encountering the highest-quality valley fill reservoir.

The Company also participated in the drilling of two development wells at Square Creek and drilled one 100 percent working interest exploratory well. One of the development wells was successfully equipped and tied-in during the first quarter of 2009. The other is being evaluated for a potential completion uphole in the shallower Notikewin Formation during the next operating season. The performance of this well is being closely monitored and the Company may increase rates in order to take advantage of the new well incentive program announced by the Alberta government in March 2009.

Outstanding Securities



----------------------------------------------------------------------------
Outstanding securities
----------------------------------------------------------------------------
Common shares 26,921,788
Warrants 5,516,700
Stock options 1,423,546
----------------------------------------------------------------------------
Total outstanding securities at June 30, 2009 and August 14,
2009 33,862,034
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The dilutive effect of the Company's issuable securities at June 30, 2009, which consists of 1,423,546 options (June 30, 2008 - 397,000) and 5,516,700 warrants (June 30, 2008 - 5,516,700) to issue common shares, was nil shares. These options and warrants are available for dilution in future periods.

Liquidity and Capital Resources

The Company's consolidated financial statements have been prepared on a going concern basis, which assumes the realization of assets and discharge of liabilities in the normal course of business for the foreseeable future. The Company has experienced consecutive losses, has an accumulated deficit of $87,595,000 and a working capital deficiency of $23,870,000 as at June 30, 2009. Included in this deficiency are short term borrowings of $23,378,000 under the revolving operating loan. The revolving operating loan limit is $24,000,000, bears interest at the Bank's prime lending rate plus 1% and is collateralized by an interest over all present and after acquired property and fixed charges on specific assets. The authorized limit is subject to annual review and re-determination of the Company's borrowing base by the Bank.

There is significant uncertainty regarding the Company's ability to continue as a going concern, which is dependent upon achieving on-going cash flow from operating activities and receiving additional support from its lenders and investors. In the event that natural gas prices remain at current levels or reduce, the future operations of the Company is dependent on its ability to successfully raise capital and receive the continued financial support of its lender. The outcome of these matters cannot be predicted at this time.

Scheduled reviews of the revolving operating loan focus on the borrowing base supporting lending limits and are influenced by the lenders willingness to lend in general, commodity price forecasts used to determine the lending base, lenders interest in particular business sectors, such as energy and the relative strength of the borrower. Given these constraints, there is no assurance that the Company will be able to sustain its current borrowing base and may be required to reduce its outstanding loan. Should there be a requirement of the Company to reduce its outstanding loan, there are a number of options available including, but not limited to:

(i) Issuance of additional equity;

(ii) Negotiation of incremental borrowings with subordinated lenders; and

(iii) Divestiture of assets.

Any adjustment to the revolving operating loan will be completed in connection with the annual bank review, which is currently ongoing.

The Company is required to maintain its working capital ratio at 1:1 or greater while the facilities are 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, 2009. The Company's ability to maintain compliance with these financial covenants is dependent on certain factors, certain of which are outside the Company's control. Such factors include future industry and capital market conditions and commodity pricing. Based on current market conditions and commodity prices, the Company may have difficulty maintaining compliance with this financial covenant in the next 12 month period and the Bank can demand repayment of the operating loan facility.

The Company's capital resources available at June 30, 2009 are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30,
($000s) 2009
----------------------------------------------------------------------------
Operating loan available 24,000
Working capital deficiency (23,870)
----------------------------------------------------------------------------
Capital resources available 130
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Due to the winter-access nature of the Company's properties, most of its 2009 capital program was conducted in the first quarter. For the six months ended June 30, 2009, the Company has incurred capital expenditures of $7,175,000 and had a working capital deficiency of $23,870,000. Future capital requirements will be funded through cash flows from operations. There is no assurance that Fortress will be able to sustain its current borrowing base and may be required to reduce its outstanding operating loan facility. Fortress has options available to deal with a borrowing base reduction including the sale of non-core properties, dedication of cash flows, and liquidation of its commodity contracts.

Cash provided by operating activities for the second of 2009 was $1,879,000 compared to $6,883,000 for the second quarter of 2008. This decrease is due to lower operating netbacks realized due to significantly lower natural gas prices and a decrease in non-cash working capital balances. Cash provided by operating activities for the six months ended June 30, 2009 was $2,476,000 compared to $8,578,000 for the six months ended June 30, 2008. Consistent with the second quarter, this decrease is due to lower natural gas prices realized and a decrease in non-cash working capital balances.

Cash provided by financing activities for second quarter of 2009 was $483,000 compared to $8,864,000 for the second quarter of 2008. Cash provided by financing activities in the second quarter of 2009 represents an increase in amounts drawn on the operating loan from the prior quarter while cash provided by financing activities for the second quarter of 2008 represents the proceeds from a public offering of 9,350,100 Units for gross proceeds of $14,025,150 ($12,713,000 net of issuance costs) and repayments on the operating loan totaling $3,849,000. Cash provided by financing activities for the six months ended June 30, 2009 was $2,845,000 compared to $8,605,000 for the six months ended June 30, 2008. Cash provided by financing activities for the six months ended June 30, 2009 reflects an increase in amounts drawn on the operating loan while cash provided by financing activities for the six months ended June 30, 2008 reflects proceeds from a public offering, previously noted, and repayments on the operating loan totaling $4,108,000.

Cash used in investing activities for the second quarter of 2009 was $2,362,000 compared to $15,747,000 for the second quarter of 2008. The Company's capital expenditures in the second quarter of 2009 were $1,238,000 compared to $3,249,000 in the second quarter of 2008. Cash used in investing activities for the six months ended June 30, 2009 was $5,431,000 compared to $17,189,000 for the six months ended June 30, 2008. For the six months ended June 30, 2009 the Company incurred capital expenditures of $7,003,000 and $22,213,000 for the six months ended June 30, 2008. In addition, in April 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, 2009, the Company was charged $36,000 and $84,000 (three and six months ended June 30, 2008 - $246,000 and $576,000), in legal fees by a law firm of which a director of the Company is a partner.

In the three and six months ended June 30, 2009, the Company was charged and recorded $30,000 and $65,000 (three and six months ended June 30, 2008 - $nil) by a director for consulting services of which $10,000 is included in accrued liabilities.

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.

Commitments and Contingencies

Royalties

The Company has agreed to pay to various university research centres royalties amounting to 2 percent to 5 percent on sales of licensed products related to a research contract and acquired technology rights and 15 percent of sublicense revenues from products related to the acquired technology rights. At June 30, 2009 there were no royalties payable under these agreements. These agreements relate to a predecessor company which was a cancer drug discovery enterprise.

Office space and equipment

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



----------------------------------------------------------------------------
Equipment Office
Rental Lease Total
($000s) $ $ $
----------------------------------------------------------------------------
2009 6 229 235
2010 11 470 481
2011 9 475 484
2012 - 474 474
2013 - 119 119
----------------------------------------------------------------------------
26 1,767 1,793
----------------------------------------------------------------------------


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/d until the earlier of April 1, 2015 or the delivery of a total of 15 bcf.

Committed payments are as follows:



----------------------------------------------------------------------------
($000s)
----------------------------------------------------------------------------
Balance of 2009 612
2010 1,088
2011 767
2012 767
2013 767
Thereafter 895
----------------------------------------------------------------------------
4,896
----------------------------------------------------------------------------


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 its 50 percent working interest in this area. Committed payments represent only the Company's 50 percent working interest. From start up in March 2008 to June 30, 2009, the Square Creek property has produced 2,615 mmcf (1,307.5 mmcf net) of natural gas.

Letter of Credit

On February 1, 2009, the Company issued a letter of credit of $900,000 with an expiry of February 1, 2010, related to a gas transportation and processing agreement.

Guarantees

The Company maintains liability insurance for its directors and officers and indemnifies its directors and officers against any and all claims or losses reasonably incurred in the performance of their service to the Company to the extent permitted by law.

Income Tax Refund

In September 2008, the Company re-filed its income tax returns for the 1997 to 1999 tax years to claim additional scientific research and experimental development credits related to the bio-technology business of its predecessor company. These additional claims could result in a refund to the Company the amount of which cannot be determined at this time.

Income Tax Reassessment

Based on the results of an audit concluded in March 2009 by the Canada Revenue Agency (CRA) on the 2004 flow-through expenditures of a business acquired by the Company in 2006, the Company was reassessed by CRA for interest of $277,000 on expenditures not qualifying for renunciation under the flow-through share program in the amount of $1,916,000. The Company filed a Notice of Objection with CRA on July 31, 2009 after consultation with its tax advisors and legal counsel and is appealing this reassessment. The Company has indemnified the subscribers of this flow-through share offering from income taxes related to the offering. The amount of the potential indemnification cannot be determined at this time.

Letter of Intent to Acquire Natural Gas Property

On June 29, 2009 the Company entered into a Letter of Intent to acquire a 50 percent working interest in a producing natural gas property in the Square Creek area of Alberta for cash consideration of $7,000,000 subject to the execution of a formal purchase and sale agreement and financing. The acquisition provides Fortress with an additional 2.7 mmcf/d of production and the potential to increase production from the area. In addition, the Company has changed the area operator to optimize the operation and substantially reduce the operating costs.

SELECTED QUARTERLY INFORMATION



----------------------------------------------------------------------------
----------------------------------------------------------------------------
2009 2008 2007
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
----------------------------------------------------------------------------
Production:
Natural gas
(mcf/d) 7,603 7,665 8,118 8,733 8,690 7,391 7,455 6,111
Oil and NGLs
(bbls/d) 12 14 14 23 15 33 13 7
Total (boe/d) 1,279 1,292 1,367 1,478 1,463 1,265 1,256 1,025
Average
realized
price:
Natural gas
($/mcf) 6.22 7.47 6.69 7.99 8.98 8.03 6.19 5.07
Oil and NGLs
($/bbl) 45.11 37.72 60.42 82.29 108.04 79.61 86.95 71.42
Combined
average
($/boe) 37.35 44.79 47.50 48.44 54.31 48.96 38.07 30.68
Benchmark
prices:
AECO average
natural gas
price ($/mcf) 3.45 4.92 6.69 7.76 9.82 7.90 6.00 5.12
Edmonton Par
crude oil
($/bbl) 66.70 51.13 64.18 123.08 126.37 98.45 80.75 80.70
Financial
($000s unless
otherwise
noted):
Petroleum and
natural gas
sales (1) 4,346 5,206 5,962 5,811 7,231 5,637 4,599 3,313
Net income
(loss) (14,605) 7 (624) 1,070 (744) (3,455) (5,442) (1,603)
Net income
(loss) per
share -
basic($) (0.54) 0.00 (0.02) 0.04 (0.04) (0.22) (0.39) (0.12)
Net income
(loss) per
share -
diluted ($) (0.54) 0.00 (0.02) 0.04 (0.04) (0.22) (0.39) (0.12)
Funds from
(used in)
operations 557 1,393 1,113 1,193 2,627 2,025 (282) 505
Operating
costs ($/boe) 15.95 15.62 14.50 15.72 15.40 11.94 15.26 10.31
Weighted
average
shares 26,922 26,922 26,965 26,965 16,809 15,980 13,561 13,266
outstanding -
basic ('000s)
Weighted
average
shares
outstanding -
diluted
('000s) 26,922 26,922 26,965 27,004 16,809 15,980 13,561 13,266
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Restated to include realized gains or losses on commodity contracts and
for the effects of transportation costs which previously were netted
from petroleum and natural gas sales.


Disclosure Controls and Procedures

The Company has established disclosure controls and procedures to ensure timely and accurate preparation of financial and other reports. Disclosure controls and procedures are designed to provide reasonable assurance that material information required to be disclosed is recorded, processed, summarized and reported within the periods specified by securities regulations and that information required to be disclosed is accumulated and communicated to the appropriate members of management and properly reflected in the Company's filings. The Chief Executive Officer and the Chief Financial Officer oversee this evaluation process and have concluded that the design and operation of these disclosure controls and procedures are adequate and effective in ensuring that the information required to be disclosed by the Company in reports filed with the Canadian Securities Administrators is accurate and complete and filed within the time periods required. The Chief Executive Officer and Chief Financial Officer have individually signed certifications to this effect.

Internal Controls over Financial Reporting

Management has designed internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The Company's Management, under the direction and supervision of the Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the design and effectiveness of the internal controls over financial reporting as at June 30, 2009. Based on their assessment Management determined that the internal controls over financial reporting were effective as at June 30, 2009.

There is no change in the Company's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. Management, including the Chief Executive Officer and the Chief Financial Officer, do not expect that the Company's disclosure controls or the Company's internal controls over financial reporting will prevent or detect all error or fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system's objectives will be met. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.

Given the Company's limited staff level, certain duties within the accounting and finance department cannot be properly segregated. However, none of the segregation of duty deficiencies resulted in a misstatement to the financial statements as the Company relies on certain compensating controls, including substantive periodic review of the financial statements and other information by the Chief Executive Officer and Audit Committee. This weakness is considered to be a common area of deficiency for many smaller listed companies in Canada.

Changes in Accounting Policies and Practices

The Canadian Institute of Chartered Accountants (CICA) Handbook Section 3064, Goodwill and Intangible Assets, replaced Section 3062, Goodwill and Other Intangible Assets, and resulted in the withdrawal of Section 3450, Research and Development Costs, and amendments to Accounting Guideline (AcG) 11, Enterprises in the Development Stage and Section 1000, Financial Statement Concepts. The standard reduces the differences with IFRS in the accounting for intangible assets and results in closer alignment with U.S. GAAP. The objectives of Section 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 also provides 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. The adoption of this standard by Fortress on January 1, 2009 did not have an impact on the Company's financial statements.

On January 20, 2009 the CICA Emerging Issues Committee (EIC) issued EIC-173 Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. Under EIC-173, an entity's own credit risk and the credit risk of the counterparty with which it conducts transactions should be taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. Fortress adopted the requirements of EIC-173 effective January 1, 2009. The adoption of this standard did not have an impact on the Company's 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.

In June 2009, the AcSB amended Section 3862, Financial Instruments - Disclosures, to converge with Improving Disclosures about Financial Instruments (Amendments to IFRS 7). The amendments expand the disclosures required in respect of recognized fair value measurements and clarify existing principles for disclosures about the liquidity risk associated with financial instruments. This standard will be effective for the annual period ending December 31, 2009.

CRITICAL ACCOUNTING ESTIMATES

The reader is advised that the critical accounting estimates, policies, and practices as described in this MD&A and report continue to be critical in determining Fortress' financial results.

The reader is further cautioned that the preparation of financial statements in accordance with GAAP requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes. Changes in these judgments and estimates could have a material impact on the financial results and financial condition. The following discussion outlines accounting policies and practices that are critical to determining the Company's financial results:

Accounting for Petroleum and Natural Gas Operations

The Company follows the full cost method of accounting whereby all costs relating to the acquisition of, exploration for and development of oil and gas reserves are capitalized in a single Canadian cost centre. Such costs include lease acquisition, lease rentals on undeveloped properties, geological and geophysical costs, drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities.

The application of the full cost method of accounting requires management's judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper income tax treatment of the costs incurred.

Full cost accounting depends on the estimated proved reserves that are believed to be recoverable from the Company's oil and gas properties. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The Company's reserve estimates are based on current production forecasts, prices and economic conditions. Fortress' reserves were evaluated by the independent engineering firm Sproule Associates Ltd.

Reserve estimates are critical to many of Fortress' accounting estimates, including:

- Calculating our unit-of-production depletion and future site restoration rates. Proved reserve estimates are used to determine rates that are applied to each unit-of-production in calculating depletion expense; and

- Assessing when necessary, oil and gas assets for possible impairment. Estimated future undiscounted cash flows are determined using proved reserves. The criteria used to assess impairment, including the impact of changes in reserve estimates, are discussed below.

As circumstances change and additional data becomes available, reserve estimates also change, possibly materially impacting net income. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although Fortress makes every reasonable effort to ensure that its reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Positive or negative revisions to the Company's reserve estimates can arise from changes in oil and gas prices, and reservoir performance.

Impairment of Petroleum and Natural Gas Properties

The Company reviews its full cost pool for impairment annually. An impairment provision is recorded whenever events or circumstances indicate that the carrying value of the Company's properties may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved plus probable petroleum and natural gas reserves, as estimated by the Company on the balance sheet date. Reserve estimates, as well as estimates for petroleum and natural gas prices and production costs, may change and there can be no assurance that impairment provisions will not be required in the future.

Management's assessment of, among other things, the results of exploration activities, commodity price outlooks, planned future development and sales impacts the amount and timing of impairment provisions.

Asset Retirement Obligations

The provision for asset retirement obligations recorded in the consolidated financial statements is based on an estimate of total costs for future site restoration and abandonment of the Company's petroleum and natural gas properties. This estimate is based on management's analysis of production structure, reservoir characteristics and depth, market demand for equipment, currently available procedures, and discussions with construction and engineering consultants. Estimating these future costs requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including changing technology, political and regulatory environments.

Income Taxes

The Company records future tax assets and liabilities to account for the expected future tax consequences of events that have been recorded in its consolidated financial statements and its tax returns. These amounts are estimates; the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash flows and capital expenditures in current and future periods. The Company periodically assesses its ability to realize its future tax assets. If Fortress concluded that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance.

Claims and Litigation

The Company is involved in various claims and litigation arising in the normal course of business. The outcome of these matters is uncertain and there can be no assurance that such matters will be resolved in the Company's favour. If the outcomes of these claims are unfavourable, there could be a materially adverse impact on the Company's financial position or results of operations.

With the above risks and uncertainties, the reader is cautioned that future events and results may vary significantly from those which Fortress currently foresees.

BUSINESS RISKS and UNCERTAINTIES

General

Fortress' production and exploration activities are concentrated in the Western Canada 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 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 high-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 selected high-risk with high-reward opportunities.

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.

Global Financial Crisis

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to commodity prices. These conditions worsened in 2008 and are continuing in 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially early in 2009. Notwithstanding certain positive economic signs observed so far in the third quarter of 2009, these factors have negatively impacted company valuations and are expected to impact the performance of the global economy going forward.

Oil and natural gas prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and demand of these commodities due to the current state of economies around the world, OPEC actions and ongoing global credit and liquidity concerns.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. As the Company's revenues may decline as a result of decreased commodity pricing, it may be required to reduce capital expenditures. In addition, uncertain levels of near term industry activity coupled with the current global credit crisis expose the Company to access to capital risk. There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on its business, financial condition, results of operations and prospects.

Third-party Credit Risk

The Company may be exposed to third-party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on Fortress' business, financial condition, results of operations and prospects.

Additional risk factors can be found under "Risk Factors Relating to the Oil and Gas Business" in the Company's 2008 Annual Information Form which can be found on the Company's website 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.
CONSOLIDATED BALANCE SHEETS
(See Nature of Operations and Going Concern Uncertainty - note 1)
As at
(in thousands)
(unaudited)
----------------------------------------------------------------------------
June 30, December 31,
2009 2008
----------------------------------------------------------------------------

ASSETS (note 5)
Current Assets
Cash and cash equivalents $ 70 $ 180
Accounts receivable 6,400 6,997
Prepaid expenses and deposits 781 854
Commodity contracts (note 9) 3,983 2,319
----------------------------------------------------------------------------
11,234 10,350
Commodity contracts (note 9) - 168
Property, plant and equipment (note 4) 90,150 104,904
----------------------------------------------------------------------------
$ 101,384 $ 115,422
----------------------------------------------------------------------------
----------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Revolving operating loan (note 5) $ 23,378 $ 20,533
Accounts payable and accrued liabilities
(note 12) 11,554 9,990
Income taxes 172 136
Future income taxes - 684
----------------------------------------------------------------------------
35,104 31,343

Future income taxes - 3,439
Asset retirement obligations (note 7) 3,531 3,395
----------------------------------------------------------------------------
38,635 38,177
----------------------------------------------------------------------------

Commitments and contingencies (note 10)

Shareholders' Equity
Share capital (note 8) 133,346 133,346
Warrants (note 8) 1,834 1,834
Contributed surplus (note 8) 15,164 15,062
Deficit (87,595) (72,997)
----------------------------------------------------------------------------
62,749 77,245
----------------------------------------------------------------------------
$ 101,384 $ 115,422
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


FORTRESS ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE LOSS AND DEFICIT
(See Nature of Operations and Going Concern Uncertainty - note 1)
For the three and six months ended June 30
(in thousands, except per share amounts and number of shares)
(unaudited)


----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
REVENUES
Petroleum and
natural gas sales
(note 13) $ 4,346 $ 7,231 $ 9,552 $ 12,868
Royalties (442) (1,293) (920) (2,263)
Interest income - - - -
Unrealized gain
(loss) on commodity
contracts (922) 151 1,496 (2,990)
(note 9)
----------------------------------------------------------------------------
2,982 6,089 10,128 7,615
----------------------------------------------------------------------------
EXPENSES
Operating 1,855 2,051 3,670 3,426
Transportation
(note 13) 249 237 495 449
General and
administrative
(note 13) 639 566 1,361 1,054
Professional fees
(note 13) 337 149 488 337
Bad debts (note 13) 37 (53) 179 (53)
Stock-based
compensation
(note 8) 48 54 127 72
Interest (note 13) 212 361 453 741
Depletion,
depreciation and
accretion (note 4) 3,695 3,712 7,508 6,822
Ceiling test
impairment (note 4) 14,276 - 14,276 -
----------------------------------------------------------------------------
21,348 7,077 28,557 12,848
----------------------------------------------------------------------------
(18,366) (988) (18,429) (5,233)
Loss on sale of
pipeline asset - - - (552)
----------------------------------------------------------------------------
Loss before income
taxes (18,366) (988) (18,429) (5,785)
----------------------------------------------------------------------------
Income tax expense
(recovery) (note 6)
Current 18 - 36 -
Future (3,779) (244) (3,867) (1,586)
----------------------------------------------------------------------------
(3,761) (244) (3,831) (1.586)
----------------------------------------------------------------------------
Net loss and
comprehensive loss
for the period (14,605) (744) (14,598) (4,199)
----------------------------------------------------------------------------

Deficit, beginning
of period (72,990) (72,699) (72,997) (69,244)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Deficit, end of
period $ (87,595) $ (73,443) $ (87,595) $ (73,443)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Weighted average
shares outstanding
(note 8) 26,921,788 16,808,660 26,921,788 16,394,538
Net loss per share -
basic and diluted
(note 8) $ (0.54) $ (0.04) $ (0.54) $ (0.26)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


FORTRESS ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(See Nature of Operations and Going Concern Uncertainty - note 1)
For the three and six months ended June 30
(in thousands)
(unaudited)
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
CASH PROVIDED BY (USED IN):

OPERATING ACTIVITIES
Net loss for the period $ (14,605) $ (744) $ (14,598) $ (4,199)
Items not affecting cash flows:
Unrealized loss (gain) on
commodity contracts 922 (151) (1,496) 2,990
Stock-based compensation 48 54 127 72
Depletion, depreciation and
accretion 3,695 3,712 7,508 6,822
Ceiling test impairment 14,276 - 14,276 -
Loss on sale of pipeline asset - - - 552
Future income tax recovery (3,779) (244) (3,867) (1,586)
Abandonment expenditures (2) - (172) (81)
----------------------------------------------------------------------------
555 2,627 1,778 4,570
Change in non-cash operating
working capital (note 11) 1,324 4,256 698 4,008
----------------------------------------------------------------------------
Cash provided by operating
activities 1,879 6,883 2,476 8,578
----------------------------------------------------------------------------

FINANCING ACTIVITIES
Change in revolving operating
loan 483 (3,849) 2,845 (4,108)
Issue of common shares and
warrants - 14,025 - 14,025
Share issuance costs - (1,312) - (1,312)
----------------------------------------------------------------------------
Cash provided by financing
activities 483 8,864 2,845 8,605
----------------------------------------------------------------------------

INVESTING ACTIVITIES
Property, plant and equipment
additions (1,238) (3,249) (7,003) (22,213)
Proceeds on sale of pipeline
asset - 8,150 - 8,150
Change in non-cash investing
working capital (note 11) (1,124) (20,648) 1,572 (3,126)
----------------------------------------------------------------------------
Cash used in investing
activities (2,362) (15,747) (5,431) (17,189)
----------------------------------------------------------------------------

Net change in cash - - (110) (6)
Cash and cash equivalents -
beginning of period 70 38 180 44
----------------------------------------------------------------------------
Cash and cash equivalents - end
of period $ 70 $ 38 $ 70 $ 38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplemental cash flow
information (note 11)
Interest paid 192 248 433 588
----------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


FORTRESS ENERGY INC.
Notes to Consolidated Financial Statements
June 30, 2009
(Tabular figures are in thousands of Canadian dollars unless otherwise
indicated)
(unaudited)


1.NATURE OF OPERATIONS AND GOING CONCERN UNCERTAINTY

Fortress Energy Inc. ("Fortress" or the "Company") was incorporated on January 15, 2007 under the Business Corporations Act (Alberta). Fortress 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. Fortress is listed on the TSX under the symbol "FEI".

The financial statements include the accounts of Fortress and its wholly owned subsidiary, 1310639 Alberta Ltd. on a consolidated basis.

The Company's consolidated financial statements have been prepared on a going concern basis, which assumes the realization of assets and discharge of liabilities in the normal course of business for the foreseeable future. The Company has experienced consecutive losses, has an accumulated deficit of $87,595,000 and a working capital deficiency of $23,870,000 as at June 30, 2009. Included in this deficiency are short term borrowings of $23,378,000 under the revolving operating loan. The revolving operating loan limit is $24,000,000, bears interest at the Bank's prime lending rate plus 1% and is collateralized by an interest over all present and after acquired property of the Company and fixed charges on specific assets. The authorized limit is subject to annual review and re-determination of the Company's borrowing base by the Bank.

There is significant uncertainty regarding the Company's ability to continue as a going concern, which is dependent upon achieving on-going cash flow from operating activities and receiving additional support from its lenders and investors. In the event that natural gas prices remain at current levels or reduce, the future operations of the Company is dependent on its ability to successfully raise capital and receive the continued financial support of its lender. The outcome of these matters cannot be predicted at this time.

These financial statements do not contain any adjustments to the amounts and classification of assets and liabilities that might be necessary should the Company be unable to continue in business.

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 (GAAP) using the same accounting policies as set out in note 2 to the audited consolidated financial statements for the year ended December 31, 2008. 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, 2008.

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.

(b) Comparative figures

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

3. CHANGES IN AND FUTURE ACCOUNTING POLICIES

(a) 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.

(b) The Canadian Institute of Chartered Accountants (CICA) Handbook Section 3064, Goodwill and Intangible Assets, replaced Section 3062, Goodwill and Other Intangible Assets, and resulted in the withdrawal of Section 3450, Research and Development Costs, and amendments to Accounting Guideline (AcG) 11, Enterprises in the Development Stage and Section 1000, Financial Statement Concepts. The standard reduces the differences with IFRS in the accounting for intangible assets and results in closer alignment with U.S. GAAP. The objectives of Section 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 also provides 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. The adoption of this standard by Fortress on January 1, 2009 did not have an impact on the Company's financial statements.

(c) On January 20, 2009 the CICA Emerging Issues Committee (EIC) issued EIC-173 Credit Risk and the Fair Value of Financial Assets and Financial Liabilities. Under EIC-173, an entity's own credit risk and the credit risk of the counterparty with which it conducts transactions should be taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. Fortress adopted the requirements of EIC-173 effective January 1, 2009. The adoption of this standard did not have an impact on the Company's financial statements.

(d) In June 2009, the AcSB amended Section 3862, Financial Instruments - Disclosures, to converge with Improving Disclosures about Financial Instruments (Amendments to IFRS 7). The amendments expand the disclosures required in respect of recognized fair value measurements and clarify existing principles for disclosures about the liquidity risk associated with financial instruments. This standard will be effective for the annual period ending December 31, 2009.

4. PROPERTY, PLANT AND EQUIPMENT



----------------------------------------------------------------------------
Accumulated
Depletion and Net Book
Cost Depreciation Value
June 30, 2009 $ $ $
----------------------------------------------------------------------------
Oil and gas properties 143,442 53,486 89,956
Other 410 216 194
----------------------------------------------------------------------------
143,852 53,702 90,150
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Accumulated
Depletion
and Net Book
Cost Depreciation Value
December 31, 2008 $ $ $
----------------------------------------------------------------------------
Oil and gas properties 136,544 31,857 104,687
Other 393 176 217
----------------------------------------------------------------------------
136,937 32,033 104,904
----------------------------------------------------------------------------
----------------------------------------------------------------------------


For the three and six months ended June 30, 2009, the Company capitalized general and administrative expenses of $278,000 and $465,000, respectively (three and six months ended June 30, 2008 - $207,000 and $400,000, respectively) directly attributable to exploration and development activities. In addition, the Company capitalized stock-based compensation expense related to exploration and development activities and recorded a recovery of capitalized stock-based compensation expense of $22,000 for the three months ended June 30, 2009 and an expense of $6,000 for the six months ended June 30, 2009 (three months and six months ended June 30, 2008 - $80,000).

Estimated future development costs of $11,235,000 (June 30, 2008 - $15,842,000) were included in the calculation of depletion expense for the six months ended June 30, 2009. As at June 30, 2009, undeveloped land costs of $7,477,000 (June 30, 2008 - $7,362,000) were excluded from assets subject to depletion.

The Company performed a ceiling test calculation at June 30, 2009 which resulted in the carrying amount of the Company's oil and gas properties exceeding the estimated undiscounted future cash flows associated with the Company's proved reserves. As a result, the Company performed the second step of the ceiling test by comparing the discounted cash flows from proven plus probable reserves to the carrying amount of oil and gas properties. As a result of performing this second step, a ceiling test impairment charge of $14,276,000 has been recorded in the consolidated statements of operations. The natural gas prices used in the ceiling test calculation are based on the June 30, 2009 commodity price forecast of our independent reserve evaluators and are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year AECO Gas (Cdn$/MMbtu)
----------------------------------------------------------------------------
2009 4.50
2010 6.15
2011 6.85
2012 7.23
2013 7.50
2014 7.67
2015 7.84
2016 8.02
2017 8.20
2018 8.38
2019 8.57
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Prices increase at a rate of 2% per year after 2019. The benchmark prices were adjusted for quality and transportation.

Liens totaling $146,000 have been registered against certain oil and gas properties.

5. REVOLVING OPERATING LOAN

The Company has a $24,000,000 demand revolving operating loan facility with its bank (the "Bank"), bearing interest at the Bank's prime lending rate plus 1.0 percent. The effective interest rate for the three and six months ended June 30, 2009 was 3.3 and 3.6 percent, respectively (three and six months ended June 30, 2008 - 5.0 and 5.25 percent, respectively). At June 30, 2009, a total of $23,378,000 was drawn on this facility. The Company also has a $1,000,000 letter of guarantee facility of which $900,000 is drawn at June 30, 2009 (December 31, 2008 - $1,000,000). These facilities are collateralized by an interest over all present and subsequently acquired property of the Company and fixed charges on specific assets.

Scheduled reviews of the revolving operating loan focus on the borrowing base supporting lending limits and are influenced by the lender's willingness to lend in general, commodity price forecasts used to determine the lending base, lender's interest in particular business sectors, such as energy and the relative strength of the borrower. Given these constraints, there is no assurance that the Company will be able to sustain its current borrowing base and may be required to reduce its outstanding loan. Should there be a requirement of the Company to reduce its outstanding loan, there are a number of options available including, but not limited to:

a) Issuance of additional equity;

b) Negotiation of incremental borrowings with subordinated lenders; and

c) Divestiture of assets.

Any adjustment to the revolving operating loan will be completed in connection with the annual bank review, which was scheduled for June 30, 2009 and is currently on-going.

The Company is required to maintain its working capital ratio at 1:1 or greater while the facilities are 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, 2009. The Company's ability to maintain compliance with this financial covenant is dependent on certain factors, certain of which are outside the Company's control. Such factors include future industry and capital market conditions and commodity pricing. Based on current market conditions and commodity prices, the Company may have difficulty maintaining compliance with this financial covenant in the next 12 month period. The Bank can demand repayment of the operating loan facility.

6. INCOME TAXES



The provision for income tax recovery is summarized as follows:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
----------------------------------------------------------------------------
2009 2008 2009 2008
$ $ $ $
----------------------------------------------------------------------------
Current income tax expense 18 - 36 -
Future income tax recovery (3,779) (244) (3,867) (1,586)
----------------------------------------------------------------------------
Income tax recovery (3,761) (244) (3,831) (1,586)
----------------------------------------------------------------------------


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 ended Six months ended
June 30, June 30,
2009 2008 2009 2008
$ $ $ $
----------------------------------------------------------------------------
Loss before tax (18,366) (988) (18,429) (5,785)
----------------------------------------------------------------------------
Expected tax recovery at 29.5% (5,418) (299) (5,437) (1,750)
(June 30, 2008 - 30.25%)
Add (deduct) income tax effect of:
Stock-based compensation 14 17 37 22
Non-taxable ARTC 18 - 18 -
Non-deductible expenses 3 - 6 -
Non-deductible interest expenses 18 (12) 36 (7)
Rate adjustments and other (50) 50 (145) 149
Valuation allowance 1,654 - 1,654 -
----------------------------------------------------------------------------
Income tax recovery (3,761) (244) (3,831) (1,586)
----------------------------------------------------------------------------


The Company recorded a ceiling test impairment charge of $14,276,000 in the six months ended June 30, 2009 which resulted in the Company having tax basis in excess of the carrying amount. The Company recognized a future income tax asset to the extent of future income tax liabilities and recorded a valuation allowance against the remaining future income tax asset due to the Company's history of losses.

7. 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, 2009 to be $3,531,000 (December 31, 2008 - $3,395,000) based on a total future liability of $5,102,000 (December 31, 2008 - $5,027,000) which will be primarily incurred between 2011 and 2029. An inflation rate of 2.0 percent (December 31, 2008 - 2.0 percent) and a credit-adjusted risk-free rate of 7.5 percent (December 31, 2008 - 7.5 percent) were used to calculate the fair value of the asset retirement obligations.



----------------------------------------------------------------------------
$
----------------------------------------------------------------------------
Balance, December 31, 2008 3,395
Liabilities incurred 37
Accretion expense 114
Abandonment expenditures (15)
----------------------------------------------------------------------------
Balance, June 30, 2009 3,531
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. 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, June 30, 2009 and December 31, 2008 26,921,788 133,346
----------------------------------------------------------------------------


(c) Warrants issued and outstanding:

----------------------------------------------------------------------------
Number of
Warrants $
----------------------------------------------------------------------------
Balance, June 30, 2009 and December 31, 2008 5,516,700 1,834
----------------------------------------------------------------------------


(d) Contributed surplus:

----------------------------------------------------------------------------
$
----------------------------------------------------------------------------
Balance, December 31, 2008 15,062
Stock-based compensation expense 102
----------------------------------------------------------------------------
Balance, June 30, 2009 15,164
----------------------------------------------------------------------------


(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.

The following table summarizes stock option transactions for the six months ended June 30, 2009:



----------------------------------------------------------------------------
Weighted
average
exercise
price
Number $
----------------------------------------------------------------------------
Outstanding, December 31, 2008 1,805,873 1.56
Expired (18,000) (19.50)
Forfeited (364,327) (1.35)
----------------------------------------------------------------------------
Outstanding, June 30, 2009 1,423,546 1.39
----------------------------------------------------------------------------
Exercisable, June 30, 2009 78,992 2.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The Company has the following stock options outstanding:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Outstanding at June 30, 2009 Exercisable at June 30, 2009
Weighted Weighted Weighted
average Average Average
Exercise years to Exercise Number Exercise
Price Number expiry Price exercisable Price
$ $ $
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1.18 - 1.35 1,419,546 3.9 1.32 74,992 1.18
19.50 - 50.00 4,000 0.8 26.40 4,000 26.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1,423,546 3.9 1.39 78,992 2.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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. The Company did not grant any stock options in the three months and six months ended June 30, 2009 and 2008.

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 $0.56 per share (June 30, 2008 - $0.50) is amortized to expense over the vesting period on a straight-line basis. For the three and six months ended June 30, 2009; the Company recorded compensation expense of $35,000 and $96,000, respectively, related to stock options (June 30, 2008 - $14,000 and $32,000, respectively). The Company capitalized stock-based compensation expense related to exploration and development activities in the three and six months ended June 30, 2009 of a recovery of $22,000 and an expense of $6,000, respectively (three months and six months ended June 30, 2008 - $80,000).

(f) Restricted stock unit plan:

As at June 30, 2009, there were 950,000 restricted stock units outstanding of which 300,000 mature on December 31, 2010 and 650,000 mature on November 17, 2011. All vest over a three year period on a straight-line basis. The Company recorded a liability at June 30, 2009 based on the intrinsic value of the units. For the three and six months ended June 30, 2009, the Company recorded compensation expense related to the restricted stock unit plan of $13,000 and $31,000, respectively (June 30, 2008 - $48,000).

(g) Per share amounts:

The weighted average number of common shares outstanding for the three and six months ended June 30, 2009 and 2008 are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Weighted average
- basic and diluted 26,921,788 16,808,660 26,921,788 16,394,538
----------------------------------------------------------------------------


The dilutive effect of the Company's issuable securities at June 30, 2009, which consists of 1,423,546 options (June 30, 2008 - 397,000) and 5,516,700 warrants (June 30, 2008 - 5,516,700) to issue common shares, was nil shares. These options and warrants are available for dilution in future periods.

9. FINANCIAL INSTRUMENTS

Overview

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

- Credit risk;

- Liquidity risk;

- Market risk;

- Foreign currency exchange risk;

- Commodity price risk; and

- Interest rate 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. 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.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due (see note 1). 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 5) 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, 2009.

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, 2009 are as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Type Period Volume (GJ/d) Fixed Price
($/GJ)
----------------------------------------------------------------------------

Swap April 1, 2009 to December 31, 2009 5,100 7.20
Swap January 1, 2010 to March 31, 2010 2,600 8.38
Swap January 1, 2010 to March 31, 2010 2,500 6.80
----------------------------------------------------------------------------


For the three and six months ended June 30, 2009, the Company realized a gain related to commodity contracts of $1,733,000 and $3,192,000, respectively (three and six months ended June 30, 2008 - realized loss of $1,072,000 and $1,185,000) which has been included in petroleum and natural gas sales. In the three and six months ended June 30, 2009 the Company also recorded an unrealized gain on commodity contracts of $922,000 and $1,496,000, respectively (recorded an unrealized gain of $151,000 for the three months ended June 30, 2008 and an unrealized loss of $2,990,000 for the six months ended June 30, 2008). A $1.00/GJ change in the AECO price would increase or decrease the unrealized gain on commodity contracts for the three and six months ended June 30, 2009 by $1,397,000.

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, 2009. A difference in the average effective interest rate of 1.0 percent would change net income by an estimated $56,000 for the three months ended June 30, 2009.

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, 2009 December 31, 2008

----------------------------------------------------------------------------
Current assets $ 11,234 $ 10,350
Current liabilities (35,104) (31,343)
----------------------------------------------------------------------------
Net debt and working capital deficiency $ (23,870) $ (20,993)
----------------------------------------------------------------------------


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. The Company's lands can only be accessed during winter months and it is in these months when the Company incurs most of its annual capital expenditures. Net debt and working capital deficiency 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, 2009 include cash and cash equivalents, accounts receivable, commodity contracts, accounts payable and the revolving operating loan. The fair value of cash and cash equivalents, 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 as at June 30, 2009 are as follows:



----------------------------------------------------------------------------
Classification Carrying
Value Fair Value
$ $
----------------------------------------------------------------------------
Held-for-trading (cash and cash equivalents and
commodity contracts) 4,053 4,053
Loans and receivables (accounts receivable) 6,400 6,400
Held-to-maturity - -
Other liabilities (accounts payable and revolving
operating loan) (34,932) (34,932)
----------------------------------------------------------------------------
Total (24,479) (24,479)
----------------------------------------------------------------------------


10. 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 2009 6 229 235
2010 11 470 481
2011 9 475 484
2012 - 474 474
2013 - 119 119
----------------------------------------------------------------------------
26 1,767 1,793
----------------------------------------------------------------------------


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 paying 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 2009 612
2010 1,088
2011 767
2012 767
2013 767
Thereafter 895
----------------------------------------------------------------------------
4,896
----------------------------------------------------------------------------


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 its 50 percent working interest in this area. Accordingly, committed payments listed above represent only the Company's 50 percent working interest.

Letter of Credit

On February 1, 2009, the Company issued a letter of credit of $900,000 with an expiry of February 1, 2010, related to a natural gas transportation and processing agreement.

Claims and Litigation

The Company maintains liability insurance for its directors and officers and indemnifies its directors and officers against any and all claims or losses reasonably incurred in the performance of their service to the Company to the extent permitted by law.

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 favour. If the outcome is unfavourable, it could have a materially adverse impact on the Company's financial position or results of operations.

Income Tax Refund

In September 2008, the Company re-filed its income tax returns for the 1997 to 1999 tax years to claim additional scientific research and experimental development credits related to the bio-technology business of its predecessor company. These additional claims could result in a refund to the Company the amount of which cannot be determined at this time.

Income Tax Reassessment

Based on the results of an audit concluded in March 2009 by the Canada Revenue Agency (CRA) on the 2004 flow-through expenditures of a business acquired by the Company in 2006, the Company was reassessed by CRA for interest and penalties of $300,000 on expenditures not qualifying for renunciation under the flow-through share program in the amount of $1,916,000. The Company filed a Notice of Objection with CRA on July 31, 2009 after consultation with its tax advisors and legal counsel and is appealing this reassessment. The Company has indemnified the subscribers of this flow-through share offering from income taxes related to the offering. The amount of the potential indemnification cannot be determined at this time.

Letter of Intent to Acquire Natural Gas Property

On June 29, 2009, the Company entered into a Letter of Intent to acquire a 50 percent working interest in a producing natural gas property in the Square Creek area of Alberta for cash consideration of $7,000,000 subject to the execution of a formal purchase and sale agreement and financing.

11. 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,
2009 2008 2009 2008
----------------------------------------------------------------------------

$ $ $ $
Accounts receivable 2,267 (1,087) 597 (3,519)
Prepaid expenses and deposits 447 481 73 179
Accounts payable and accrued
Liabilities (2,532) (15,746) 1,564 4,237
Income taxes payable 18 - 36 -
----------------------------------------------------------------------------
200 (16,352) 2,270 897
Accounts payable settled through
issuance of shares - - - 25
Stock-based compensation included
in accounts payable - (40) - (40)
----------------------------------------------------------------------------

200 (16,392) 2,270 882

Attributable to investing activities (1,124) (20,648) 1,572 (3,126)
----------------------------------------------------------------------------
Attributable to operating activities 1,324 4,256 698 4,008
----------------------------------------------------------------------------
----------------------------------------------------------------------------


12. RELATED-PARTY TRANSACTIONS

(a) In the three and six months ended June 30, 2009, the Company was charged $36,000 and $84,000 (three and six months ended June 30, 2008 - $246,000 and $576,000), in legal fees by a law firm of which a director of the Company is a partner.

(b) In the three and six months ended June 30, 2009, the Company was charged and recorded $30,000 and $65,000 (three and six months ended June 30, 2008 - $nil) by a director for consulting services of which $10,000 is included in accrued liabilities.

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.

13. RECLASSIFICATION

In 2008, the Company changed its presentation of petroleum and natural gas sales, transportation costs, realized gain or loss on commodity contracts, and general and administrative expenses. The Company previously reported petroleum and natural gas sales net of transportation costs and before realized gain or loss on commodity contracts. The Company also changed its presentation of general and administrative expenses to provide separate disclosure of professional fees and bad debts. At June 30, 2008 bad debts expense was recorded as part of interest expense. There is no impact on the reported net loss for the three and six months ended June 30, 2008. The effect of these changes for the three and six months ended June 30, 2008 is as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three
months Three
ended June months
30, 2008 As ended June
Previously 30, 2008
Classified Adjustments Reclassified
$ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales 8,066 (835) 7,231
Realized loss on commodity
contracts (1,072) 1,072 -
Transportation expense - 237 237
General and administrative
expenses 715 (149) 566
Professional fees - 149 149
Bad debts - (53) (53)
Interest 308 53 361
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months
ended June Six months
30, 2008 As ended June
Previously 30, 2008
Classified Adjustments Reclassified
$ $ $
----------------------------------------------------------------------------
Petroleum and natural gas sales 13,604 (736) 12,868
Realized loss on commodity
contracts (1,185) 1,185 -
Transportation expense - 449 449
General and administrative
expenses 1,391 (337) 1,054
Professional fees - 337 337
Bad debts - (53) (53)
Interest 688 53 741
----------------------------------------------------------------------------


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

Certain statements in this press release may contain forward-looking information including expenditures 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. Without limiting the generality of the foregoing, the Company has made materially forward-looking statements:

1. under North American Natural Gas Market Overview - decline in supply of surplus natural gas, future gas supplies in the analysis of North American Natural Gas Markets, "Has Anyone Done the Math" and the effects on supply and drilling rig activity, future supply shortages and natural gas price increases, and

2. under Recent Initiatives - effects of initiatives to assist in improving future profitability, including completion of the acquisition of additional interests in the Square Creek area.

The reader is cautioned that assumptions used in the preparation of such information, including the effect of decreased drilling activity on gas supply and prices may prove to be incorrect. The Company cautions the reader that actual performance will be affected by a number of factors, including 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 (applicable to the forward-looking statements (i) through (iii) above), delays or changes in plans (applicable to the forward-looking statements identified in (i) through (iii) above); 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.

Forward-looking statements contained herein are made as of the date hereof subject to the requirements of applicable securities legislation and except as otherwise required by law, the Company assumes no obligation to update any forward-looking statements, whether as a result of new information, future events and results, or otherwise. There can be no assurance that forward-looking statements will prove to be accurate, as actual results and future events could differ materially from those anticipated in such statements. Accordingly, the reader is cautioned not to place undue reliance on forward-looking statements.

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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