Crew Energy Inc.
TSX : CR

Crew Energy Inc.

November 10, 2008 19:01 ET

Crew Energy Issues 2008 Third Quarter Financial and Operating Results

CALGARY, ALBERTA--(Marketwire - Nov. 10, 2008) - Crew Energy Inc. (TSX:CR) of Calgary, Alberta is pleased to present its operating and financial results for the three and nine month periods ended September 30, 2008.

Highlights

- Record third quarter production of 11,505 boe per day was 24% higher than the same period of 2007 and 22% higher then the second quarter of 2008;

- Funds from operations of $0.54 per share was 23% higher than the same period of 2007;

- Earnings improved to $15.2 million or $0.23 per share over a loss of $0.4 million in 2007;

- Funds from operations netback of $33.07 per boe represents a 33% increase over the same period of 2007;

- Continued the Company's aggressive capital program drilling 18 wells and completing 26 wells with significant positive results in the Company's Montney natural gas play development and Pekisko oil development;

- Closed the acquisition of Gentry Resources Ltd. on August 22, 2008 adding approximately 12.5 million boe of proved and probable reserves, current production of approximately 4,600 boe per day and 280,000 net acres of undeveloped land;

- The Company's credit facility was increased to $285 million on closing of the Gentry acquisition.



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Three Three Nine Nine
months months months months
Financial ended ended ended ended
($ thousands, except per share September September September September
amounts) 30, 2008 30, 2007 30, 2008 30, 2007
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Petroleum and natural gas sales 65,345 33,390 177,050 101,524
Funds from operations (note 1) 35,004 21,171 98,144 59,043
Per share - basic 0.54 0.45 1.68 1.32
- diluted 0.54 0.44 1.66 1.31

Net income (loss) 15,178 (449) 21,534 2,221
Per share - basic 0.24 (0.01) 0.37 0.05
- diluted 0.23 (0.01) 0.36 0.05

Exploration and development
expenditures 66,399 25,385 138,065 71,059
Property acquisitions (net of
dispositions) (1,097) (51) 70,659 (49)
Total capital expenditures 65,302 25,334 208,724 71,010

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Capital Structure As at
As at Dec. 31,
($ thousands) Sept. 30, 2008 2007
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Working capital deficiency
(note 2) 52,384 14,643
Bank loan 179,050 95,028
Net debt 231,434 109,671

Bank facility 285,000 180,000

Common shares outstanding (thousands) 71,194 53,577
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Notes:

(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital, asset
retirement expenditures and the transportation liability charge. Funds
from operations is used to analyze the Company's operating performance
and leverage. Funds from operations does not have a standardized measure
prescribed by Canadian Generally Accepted Accounting Principles and
therefore may not be comparable with the calculations of similar
measures for other companies.

(2) Working capital deficiency includes only accounts receivable less
accounts payable and accrued liabilities.


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Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
Operations 30, 2008 30, 2007 30, 2008 30, 2007
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Daily production
Natural gas (mcf/d) 52,523 47,820 49,953 41,842
Light oil (bbl/d) 1,515 436 813 579
Natural gas liquids (bbl/d) 1,236 862 1,387 824
Oil equivalent (boe/d @ 6:1) 11,505 9,268 10,526 8,377
Average prices (note 1)
Natural gas ($/mcf) 8.30 5.69 8.96 6.88
Light oil ($/bbl) 104.68 74.61 106.74 64.91
Natural gas liquids ($/bbl) 76.93 67.69 72.45 56.48
Oil equivalent ($/boe) 61.74 39.16 61.39 44.39
Operating expenses
Natural gas ($/mcf) 1.57 1.04 1.34 1.03
Light oil ($/bbl) 12.96 6.20 11.45 5.42
Natural gas liquids ($/bbl) 8.51 6.99 6.94 6.72
Oil equivalent ($/boe @ 6:1) 9.79 6.29 8.17 6.18

Operating netback ($/boe) (note 2) 36.37 27.68 37.88 28.74
Realized loss/(gain) on financial
instruments 0.93 (0.76) 1.15 (0.26)
G&A ($/boe) 0.85 0.95 1.01 1.03
Interest and other ($/boe) 1.52 2.66 1.69 2.15
Funds from operations ($/boe) 33.07 24.83 34.03 25.82

Drilling Activity
Gross wells 18 9 37 20
Working interest wells 16.8 7.4 33.6 18.1
Success rate, net wells 94% 100% 94% 100%
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Notes:
(1) Average prices are before deduction of transportation costs.

(2) Operating netback equals petroleum and natural gas sales less royalties,
operating costs and transportation costs calculated on a boe basis.
Operating netback and funds from operations netback do not have a
standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.


OVERVIEW

The third quarter was highlighted by record funds from operations of $35.0 million and earnings of $15.2 million. Crew's average production of 11,505 boe per day was 24% higher than the 9,268 boe per day for the same period in 2007 as a result of the acquisition of Gentry Resources Ltd. ("Gentry") and drilling successes over the past year but was affected by minor facilities downtime and to a larger degree by wet weather impairing field operating activities. The Company drilled 18 (16.8 net) wells with a 94% success rate and completed 26 (24.8 net) wells in the quarter. The Company successfully continued its British Columbia Montney drilling and testing program through the quarter as well as drilled and completed a number of Pekisko oil wells at Princess, Alberta. Crew closed the acquisition of Gentry on August 22, 2008. Production from the Gentry properties averaged 3,862 boe per day in the second quarter, was approximately 4,000 boe per day at the time of closing and is now producing approximately 4,600 boe per day with approximately 700 boe per day awaiting production startup.

FINANCIAL REVIEW

Funds from operations for the quarter was $35.0 million or $0.54 per share, a 65% increase compared to $21.2 or $0.44 per share in 2007. This increase is attributable to a 58% increase in Crew's total realized commodity price and a 24% increase in production volumes. Net income for the quarter was $15.2 million or $0.23 per share compared to a loss of $0.4 million or $0.01 per share in 2007. The increase was predominantly a result of unrealized gains on financial instruments from the Company's Risk Management program.

Crew had an active capital program in the quarter spending a net $65.3 million. After the Company's capital program and the acquisition of Gentry Resources Ltd., net debt is $231.4 million or approximately 1.6 times projected annualized fourth quarter funds from operations. Crew has maintained financial flexibility with over $50 million remaining on its $285 million credit facility. The Company as expected experienced an increase in per unit operating costs as a result of the addition of the Gentry properties and inflationary pressures on the Company's existing production. A number of cost cutting measures and operational efficiency improvements have been identified that will be implemented and are expected to lower costs.

OPERATIONS UPDATE

Crew had an active third quarter drilling 18 (16.8 net) wells compared to nine (7.4 net) wells in the same quarter of 2007. Crew was very active completing and pipeline connecting wells during the quarter, completing 20 (19.1 net) wells and recompleting six (5.7 net) wells. The Company spent $30.8 million on drilling, $15.1 million on completions and $7.1 million on recompletions with the majority of the spending at Septimus, British Columbia on Crew's Montney play. Crew's focus on unconventional gas resources and the application of new technologies has resulted in the Company drilling more horizontal wells than at any time in its history resulting in a trend to higher per well capital costs.

EMERGING RESOURCE PLAYS

Triassic Montney Play - Septimus, British Columbia

Crew owns 140.5 net sections and controls an additional 31.5 sections on this world class resource play. Crew has had a very active third and fourth quarter program with promising results:

- The first horizontal well was drilled to a horizontal length of 867 meters and has been producing at a stabilized rate of 500-600 mcf per day;

- The second horizontal well was drilled to a horizontal length of 1,250 meters and tested at an average rate of 8.8 mmcf per day over a 121 hour flow period and has been on production at 3 to 4 mmcf per day on a restricted basis;

- The third Septimus well was drilled to a horizontal length of 1,250 meters and tested at a rate of 8.7 mmcf per day over a 147 hour flow period and has produced 3 to 4 mmcf per day on a restricted basis alternating with the second well;

- The fourth Septimus well was drilled to a horizontal length of 1,310 meters and tested at a rate of 8.0 mmcf per day over a 195 hour flow period and is in the process of being tied in;

- The fifth Septimus well has been drilled to a horizontal length of 1,170 meters and is currently being completed;

- A sixth well at Septimus is currently drilling;

- Crew has drilled or tested five other Montney exploration wells in British Columbia. These wells are in areas where there are additional land acquisition opportunities.

Crew expected to have throughput of 8 to 10 mmcf per day at Septimus however due to increased third party volumes, the Company's throughput was reduced to 4 mmcf per day of firm service. As a result Crew's production has been curtailed by approximately 1,100 boe per day. The facility operator is currently expanding the facility to accommodate up to an additional six mmcf per day of interruptible service. This expansion is scheduled to be completed by the end of January 2009. Crew indicated in the last release that the Company's intention was to prove adequate productive capability and reserves to support the construction of a gas plant and associated gathering system. With the well results to date and the consistency of the Upper Montney reservoir in the Septimus area, these goals have substantially been met and we are now in a position to proceed with the construction of a new gas facility. Crew has started the land acquisition, engineering and procurement of equipment for a 20 mmcf per day gas plant which is currently expected to be on production in the third quarter of 2009 provided all regulatory requirements are satisfied. The facility will be modular and will be designed to be readily expanded. Prior to year end 2008 Crew will have drilled six wells and plans to drill an additional six to nine wells at Septimus in 2009 in order to fill the expanded capacity. Crew currently has 11 sections (WI - 100%) mapped in this pool which yield another 38 additional drilling locations based on four wells per section. If plans proceed as currently expected, Crew will have 24 to 30 mmcf per day of takeaway capacity from this area in the third quarter of 2009.

In the fourth quarter, Crew plans to acquire a 30 square mile block of three dimensional seismic at Portage which is Crew's western most block of land on the Montney play with plans to drill three earning wells on this block in 2009. The Portage block has sparse well control with a number of untested structures identified on two dimensional seismic. The area has multi zone potential including the Baldonnel, Charlie Lake, Halfway, Doig, Montney and Belloy. Crew also plans on testing the Lower and Upper Montney formations at Monias which is four miles northwest of Septimus and at Tower which is seven miles east of Septimus.

Mississippian, Pekisko Play - Princess, Alberta

The Princess play (WI - 100%) is on a 444 section contiguous block of freehold land that lies in a unique geographic position in Alberta where the structural effects of the Sweetgrass Arch and the regional dip of the basin intersect to form an area where the subsurface structure is essentially flat. Numerous northwest trending Mannville channels have eroded the Mississippian Pekisko formation forming hydrocarbon traps on the subcrop edge (Tilley and West Tide Lake) and in elongated outliers (Alderson). These outliers can be two to three miles wide and up to 12 miles long. Crew has three dimensional seismic control over the block and has over 100 drilling locations identified. Primary recoveries in these pools are approximately 10% while an adjacent Pekisko pool under waterflood is expected to recover approximately 30% of the original oil in place. A third party reservoir simulation study conducted on two of Crew's Tilley oil pools estimate the ultimate recovery of oil to be approximately three times greater under waterflood compared to primary recovery. The Company has submitted a waterflood application for the Tilley oil pools to the ERCB.

Since acquiring the property, Crew has identified a number of capital projects to be undertaken which are expected to increase production and lower costs. A shortage of water disposal in the area has increased trucking costs and Crew has made the decision to shut in or restrict production (350 boe per day) until cost effective water disposal becomes operational. Crew plans to inject water into the Pekisko as part of a waterflood when ERCB approvals are obtained. In addition, production at Alderson is restricted and as such, the Company plans to drill a well to dispose of water into a Devonian aquifer, as well as acidize three disposal wells to increase disposal capacity; all of which are expected to occur in the fourth quarter. Other goals include improving production efficiency and reducing operating costs from $16.50 per boe to the $10 to $12 per boe range. Crew plans to develop two to three oil pools at Princess through the drilling of up to 15 outpost wells and up to 40 development wells in 2009. Crew believes the economics of this play remain attractive at a flat $60 (Cdn) oil price. Production of 45 bbl per day per well and reserves of 55,000 barrels per well yield a rate of return of 43%.

Horn River Basin/Cordova Embayment

Muskwa Devonian Shale Gas Play

This play has garnered a significant amount of attention since industry participants have announced successful drilling and testing results. Well test rates from third party vertical wells have been 0.75 to 2.5 mmcf per day with horizontal wells testing at rates of 5 to 16 mmcf per day. Crew has 16 sections on this play with its lands offsetting recently announced high test rate wells. The Company currently has plans to drill one well on this play in 2009.

CONVENTIONAL OPERATIONS

ALBERTA

Edson, Alberta

At Edson, Crew drilled two (2.0 net) horizontal wells during the quarter. The first was drilled to 185 meter horizontal length and was subsequently cased to total depth, perforated and fracture stimulated flowing gas at low rates. The second well was drilled to a 487 meter horizontal length and is awaiting completion in an open hole using a selective fracturing technology system to stimulate the reservoir. Crew continues to experiment with completion and fracture technology to optimize well performance in this area. The Company was successful in diverting the majority of its gas production from the Suncor (Crew WI - 15%) operated Rosevear sour gas plant during a 14 day turnaround in September.

Pine Creek, Alberta

At Pine Creek, Crew drilled one well (WI - 100%) that is currently being completed which targeted the Cadomin formation. The Company owns (WI - 100%) a 15 mmcf per day gas facility and has excess capacity to accommodate future drilling. In this area, Crew has a large land base of over 59 sections and has a multi well inventory of drilling locations to continue its growth plans at Pine Creek.

Viking-Kinsella, Alberta

At Viking-Kinsella, Crew drilled two (2.0 net) horizontal oil wells in the third quarter. Both wells are onstream at a combined rate of approximately 235 barrels of oil per day. Crew is applying for downspacing on this section and has identified drilling locations on two adjacent sections.

Hanlan, Alberta

At Hanlan, the original discovery at 14-35 has now produced 4.8 BCF and is currently producing at 5.3 mmcf per day. Crew's 12-11 fourth quarter, 2007 gas discovery has continued to decline and is now producing intermittently. Crew has an inventory of two recompletion opportunities in the area with interests of 42.5% and 50%.

Carrot Creek, Alberta

At Carrot Creek, Crew owns 34 net sections of land in this multi-zone area. Crew drilled one (1.0 net) well in the third quarter which is currently producing approximately 90 boe per day. The Company has an inventory of 20 drilling locations in this area and has elected to defer drilling due to the depth and productivity of wells resulting in a punitive royalty levy under Alberta's proposed New Royalty Framework.

BRITISH COLUMBIA

Inga, British Columbia

At Inga, Crew drilled two (2.0 net) wells in the third quarter. Operations in the area were hampered by wet weather throughout the quarter with Crew only recently completing the first well and the second well currently undergoing completion operations. The first well is onstream at 1.2 mmcf per day. Subsequent to the third quarter Crew (WI - 100%) has drilled a third Baldonnel horizontal well that awaits completion. Crew has plans to drill two to three horizontal wells at Inga in 2009.

YoYo, British Columbia

At YoYo, Crew drilled one (0.8 net) horizontal well into the Jean Marie formation. The well was completed and is expected to be on production by December 1, 2008 at approximately 700 mcf per day. Crew has an inventory of four (WI - 25%) additional locations in this area.

Strachan, Alberta

At Strachan, Crew (WI - 15% bpo, 46.5% apo) plans to drill a 3,700 meter Leduc prospect in the first quarter of 2009. Crew (WI - 100%) has purchased land on a second Leduc prospect at Strachan which has been identified on three dimensional seismic. The Company is proceeding with obtaining a drilling license which can take up to two years.

OUTLOOK

Business Environment

The world has gone through some very dramatic changes over the past few weeks. The credit crisis has caused a global economic downturn that has resulted in falling commodity prices, falling stock market valuations, and tight credit and equity markets. Crew, like many others, has experienced a significant drop in its share price and commodity prices are down over 50% from summer highs. Companies must now live within their means. Fortunately, Crew has a strong balance sheet with approximately $50 million available on its credit facility and near term plans to approximate spending to cash flow. We have posted successful results early in the development of two resource plays which has led to a significant expansion of the Company's prospect inventory.

Strong Balance Sheet and Production Growth Proceeds

The Company expects to exit 2008 with approximately $50 million of available capacity on its $285 million credit facility or at approximately 1.6 times debt to annualized currently projected fourth quarter funds from operations. The Company's debt position is manageable in this lower commodity price environment and means capital expenditures will be targeted to approximate funds from operations. Crew continues to generate significant free funds from operations to fund its capital program and continuously highgrades capital expenditures to have the right balance between near term production additions and future growth.

Crew's 2008 production is expected to average 11,500 to 12,000 boe per day as a result of the previously discussed production curtailments at Septimus, British Columbia (1,100 boe per day) and Princess, Alberta (350 boe per day). With these curtailments, the Company currently expects to exit 2008 producing 15,500 to 16,000 boe per day, the midpoint of which represents a 63% increase in production and a 20% increase in production per share over the fourth quarter of 2007.

Continued Resource Focus

Over the past two years, Crew has had a resource focus in search of large hydrocarbon accumulations which when developed provide repeatable large scale drilling programs. The Company is land rich with 640,000 net undeveloped acres, most of which are on three resource plays. Crew will continue the development and delineation of its resource plays on the Montney Formation in northeast British Columbia and the Pekisko play in southern Alberta. The recent drilling and testing results into the Montney formation have occurred on a small fraction of the Company's controlled land and it is our belief that this validation extends over the majority of Crew's land in the area. At Princess, Alberta, the Company's 444 section block of land has the potential to hold significantly more recoverable oil reserves than the 6.1 million barrels currently booked. The Muskwa shale play in northeast British Columbia is progressively being validated by the industry on lands adjacent to Crew's lands with some very positive test rates of 5.5 to 16 mmcf per day reported from horizontal wells. Crew's Board of Directors is meeting on December 8, 2008 to approve the 2009 business plan and budget and at that time, we plan on releasing the Company's plan for 2009.

Management's Discussion and Analysis

ADVISORIES

Management's discussion and analysis ("MD&A") is the Company's explanation of its financial performance for the period covered by the financial statements along with an analysis of the Company's financial position. Comments relate to and should be read in conjunction with the consolidated financial statements of the Company for the three and nine month periods ended September 30, 2008 and 2007 and the audited consolidated financial statements and MD&A for the year ended December 31, 2007. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles ("GAAP") in Canada.

Forward Looking Statements

This MD&A contains statements including management's assessment of future plans and operations, capital expenditures, the timing of those expenditures and the method of funding thereof, available credit facilities, production estimates, wells to be drilled, timing of drilling, tie-in and completion of wells and the production resulting therefrom, expected royalty rates, transportation costs and operating costs, and the taxability of the Company, which may constitute forward-looking statements under applicable securities laws and necessarily involve risks. These risks include, without limitation, risks associated with oil and gas exploration, development, exploration, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, higher than projected inflation, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, the timing and length of plant turnarounds and the impact of such turnarounds and the timing thereof, delays resulting from or inability to obtain required regulatory approvals and the ability to access sufficient capital from internal and external sources. As a consequence, the Company's actual results could differ materially from those expressed in, or implied by, the forward-looking statements. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), or at the Company's website (www.crewenergy.com). Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

Conversions

The oil and gas industry commonly expresses production volumes and reserves on a "barrel of oil equivalent" basis ("boe") whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants.

Throughout this MD&A, Crew has used the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip. Boe does not represent a value equivalency at the plant gate which is where Crew sells its production volumes and therefore may be a misleading measure if used in isolation.

Non-GAAP Measures

One of the benchmarks Crew uses to evaluate its performance is funds from operations. Funds from operations is a measure not based on GAAP that is commonly used in the oil and gas industry. It represents cash provided by operating activities before changes in non-cash working capital, asset retirement expenditures and the transportation liability charge. The Company considers it a key measure as it demonstrates the ability of the business to generate the cash flow necessary to fund future growth through capital investment and to repay debt. Funds from operations should not be considered as an alternative to, or more meaningful than cash flow provided by operating activities as determined in accordance with GAAP as an indicator of the Company's performance. Crew's determination of funds from operations may not be comparable to that reported by other companies. Crew also presents funds from operations per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of income per share.



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Three Three Nine Nine
months months months months
ended ended ended ended
Sept 30, Sept 30, Sept 30, Sept 30,
($ thousands) 2008 2007 2008 2007
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Cash provided by operating
activities 36,208 23,035 97,656 62,518
Asset retirement expenditures (8) 18 623 32
Transportation liability charge 328 283 985 471
Change in non-cash working capital (1,524) (2,165) (1,120) (3,978)
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Funds from operations 35,004 21,171 98,144 59,043
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Management uses certain industry benchmarks such as operating netback to analyze financial and operating performance. This benchmark as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore may not be comparable with the calculation of similar measures for other entities. Netback equals total petroleum and natural gas sales less royalties, operating costs and transportation calculated on a boe basis. Management considers netbacks an important measure to evaluate its performance as it demonstrates its profitability relative to current commodity prices.

RESULTS OF OPERATIONS

Overview

The third quarter was highlighted by funds from operations of $35 million and record earnings of $15.2 million. Crew's average production of 11,505 boe per day was 24% higher than the 9,268 boe per day for the same period in 2007 as a result of the acquisition of Gentry Resources Ltd. ("Gentry") and drilling successes over the past year but was negatively affected by minor facilities downtime and to a larger degree by wet weather impairing field operating activities. The Company drilled 18 (16.8 net) wells with a 94% success rate and completed 26 (24.8 net) wells in the quarter. Crew closed the acquisition of Gentry on August 22, 2008 adding approximately 4,000 boe per day of production, an estimated 12.5 million boe of proved and probable reserves and 280,000 acres of net undeveloped land. As consideration, the Company issued 12.3 million common shares and assumed $74.3 million in net debt.



Production
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Three months ended Three months ended
Sept 30, 2008 Sept 30, 2007

Light Nat. Light Nat.
oil Ngl gas Total oil Ngl gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
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Plains
Core 1,297 841 36,578 8,234 212 784 31,053 6,134
North Core 218 395 15,945 3,271 224 78 16,767 3,134
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Total 1,515 1,236 52,523 11,505 436 862 47,820 9,268
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Nine months ended Nine months ended
Sept 30, 2008 Sept 30, 2007

Light Nat. Light Nat.
oil Ngl gas Total oil Ngl gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
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Plains
Core 595 992 35,035 7,463 413 761 31,322 6,340
North Core 218 395 14,918 3,063 166 63 10,520 2,037
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Total 813 1,387 49,953 10,526 579 824 41,842 8,377
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Production for the three and nine months ended September 30, 2008 increased over the same periods in 2007 as a result of drilling successes at Ferrier, Pine Creek, and Carrot Creek, Alberta and at Septimus and Inga, British Columbia. In addition, production was enhanced during the period as a result of the closing of the Gentry acquisition on August 22, 2008. The impact of these additions were negatively impacted during the period as a result of a higher than expected decline on the Company's previously announced Hanlan discovery, delays in bringing new production onstream due to wet weather, and facility downtime. The facility downtime predominantly occurred during the second quarter in northeastern British Columbia and west central Alberta but also occurred to a lesser extent during the third quarter in west central Alberta and at Princess in southern Alberta.



Revenue
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Three Three Nine Nine
months months months months
ended ended ended ended
Sept 30, Sept 30, Sept 30, Sept 30,
2008 2007 2008 2007
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Revenue ($ thousands)
Natural gas 40,113 25,028 122,655 78,553
Light oil 14,594 2,994 23,771 9,224
Natural gas liquids 8,750 5,368 27,529 13,747
Sulphur 1,888 - 3,095 -
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Total 65,345 33,390 177,050 101,524
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Crew average prices
Natural gas ($/mcf) 8.30 5.69 8.96 6.88
Light oil ($/bbl) 104.68 74.61 106.74 64.91
Natural gas liquids ($/bbl) 76.93 67.69 72.45 56.48
Oil equivalent ($/boe) 61.74 39.16 61.39 44.39

Benchmark pricing
Natural Gas - AECO C daily
index (Cdn $/mcf) 7.85 5.31 8.76 6.82
Oil and ngl - Light Sweet
@ Edmonton (Cdn $/bbl) 121.83 79.79 115.19 72.65
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Crew's third quarter revenue increased 96% over the same period in 2007 as a result of a 24% increase in the Company's production and a 58% increase in commodity pricing.

The Company's natural gas price for the third quarter increased proportionately with the benchmark price. The sales price for the Company's light oil production has increased 40% as compared with a 53% increase in the benchmark. The disproportionate increase was a result of additional sales of lower quality oil from the acquired Gentry assets. The natural gas liquids price increased 14% in the quarter compared with the benchmark increase of 53% due to the addition of lower value ethane production from the Company's production at Ferrier, Alberta and northeastern British Columbia.

Revenue for the nine months ended September 30, 2008 has increased 74% as compared to the same period in 2007. This increase was the result of 26% increase in production and a 38% increase in commodity prices.

During the first nine months of 2008, Crew's natural gas and light oil prices increased proportionately with Company's benchmark prices. Natural gas liquids pricing during the nine months increased at a lower rate than the benchmark as a result of the added lower valued ethane production as described above.



Royalties

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Three Three Nine Nine
months months months months
ended ended ended ended
Sept 30, Sept 30, Sept 30, Sept 30,
($ thousands except per boe) 2008 2007 2008 2007
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Royalties 14,157 2,009 37,926 16,820
Per boe 13.38 2.36 13.15 7.36
Percentage of revenue 21.7% 6.0% 21.4% 16.6%
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Royalties as a percentage of revenue for the three months ended September 30, 2008 have increased over the same period in 2007 and slightly increased over Crew's average rate for the year to date. Royalties in 2007 were reduced by royalty holidays received for natural gas wells drilled in Alberta and 2006 Alberta gas cost allowance recoveries that were greater than estimated. In 2007, the Company benefited from the receipt of $2.3 million of deep gas well royalty credits primarily related to wells drilled at Hanlan and Ferrier. In addition, the acquired Gentry assets have traditionally attracted a 23% to 25% royalty rate which has impacted Crew's combined 2008 third quarter royalty rate. The Company estimates the addition of the Gentry assets will increase its royalties as a percentage of revenue to approximately 24% for the remainder of 2008.

Financial Instruments

On occasion, the Company will enter into commodity price risk management contracts in order to reduce volatility in financial results, to protect acquisition economics and to ensure a certain level of cash flow to fund planned capital projects. Crew's strategy focuses on the use of natural gas price "puts" and costless "collars" to limit exposure to downturns in commodity prices, while allowing for participation in commodity price increases. The Company's financial derivative trading activities are conducted pursuant to the Company's Risk Management Policy approved by the Board of Directors.



Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands) 30, 2008 30, 2007 30, 2008 30, 2007
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Realized gain (loss) on
financial instruments (991) 647 (3,321) 579
Unrealized gain (loss) on
financial instruments 12,903 (542) 2,477 417
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11,912 105 (844) 996
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As at September 30, 2008, the Company held derivative contracts and direct
sales agreements to sell natural gas and light oil as follows:


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Natural Volume Term Price Floor Ceiling Fair Value
Gas (gj/day) (Cdn $/gj)(Cdn $/gj)(Cdn $/gj)($ thousands)
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AECO 10,000 April 1, 2008 - AECO C - $7.00 $8.00 305
October 31, 2008 Monthly
Index

AECO 10,000 April 1, 2008 - AECO C - $7.00 $8.30 307
October 31, 2008 Daily
Average

AECO 10,000 April 1, 2008 - AECO C - $7.50 $9.25 492
October 31, 2008 Monthly
Index

AECO/
Station 2 AECO C -
Differential Daily
Swap 10,000 November 1, 2007 - Average
October 31, 2008 less
$0.16 - - 23

AECO 4,000 August 22, 2008 - AECO Daily $7.51 7.51 184
October 31, 2008 Average
----------------------------------------------------------------------------
1,311
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
Volume Price Floor Ceiling Fair Value
Oil (bbl/day) Term (US$/bbl) (US$/bbl)(US$/bbl)($ thousands)
----------------------------------------------------------------------------

NYMEX - 500 August 22, 2008 - NYMEX - $85.00 $104.00 (187)
WTI December 31, 2008 WTI Daily
Avg
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating Costs

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept. Sept. Sept. Sept.
($ thousands except per boe) 30, 2008 30, 2007 30, 2008 30, 2007
----------------------------------------------------------------------------

Operating costs 10,363 5,361 23,568 14,129
Per boe 9.79 6.29 8.17 6.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's operating costs per unit increased during the third quarter as a result of added production from higher operating costs areas in particular from the acquired Gentry assets. Operating costs associated with the assets acquired from Gentry have been estimated at $16.50 per boe at the time of acquisition. Crew is currently reviewing these costs and feels that with improved operational efficiencies and cost cutting measures, these costs can be substantially reduced. The Company has also continued to experience inflationary pressures on all operations in particular increased fuel costs in northeastern British Columbia and increased third party processing fees in the Viking, Plain Lake and Ferrier areas. Operating costs per unit for the first nine months of 2008 were also negatively affected by facility outages and delayed field operations due to wet weather causing decreased production in the Company's lower cost areas in the first nine months of the year. As a result of the higher costs experienced in the third quarter and the additional higher cost production from the Gentry assets, the Company is estimating its operating costs to range between $9.75 and $10.25 per boe in the fourth quarter of 2008. Crew has identified a number of cost cutting measures to be implemented. With fuel costs expecting to decline with falling oil prices, the Company's operating costs are expected to decline from projected fourth quarter levels.



Transportation

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands except per boe) 30, 2008 30, 2007 30, 2008 30, 2007
----------------------------------------------------------------------------

Transportation costs 2,325 2,413 6,317 4,824
Per boe 2.20 2.83 2.19 2.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company experienced lower transportation costs in the third quarter of 2008 compared to the same period in 2007 due to a reduction in its firm transportation commitments in northeastern British Columbia. The Company was able to assign some of its firm service to a third party thus reducing its gas transportation costs and its costs per unit. Transportation costs per unit also decreased due to increased production from the Gentry assets which have lower gas transportation costs and clean oil trucking costs. Transportation costs are expected to remain between $2.00 and $2.35 per boe for the remainder of the year.



Operating Netbacks

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
Sept 30, 2008 Sept 30, 2007
Light Natural Light Natural
oil Ngl gas Total oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------

Revenue 104.68 76.93 8.30 61.74 74.61 67.69 5.69 39.16
Royalties (16.48) (18.47) (1.93) (13.38) (9.41) (12.96) (0.13) (2.36)
Operating
costs (12.96) (8.51) (1.57) (9.79) (6.20) (6.99) (1.04) (6.29)
Transportation
costs (2.18) (0.02) (0.42) (2.20) (4.39) (0.18) (0.51) (2.83)
----------------------------------------------------------------------------
Operating
netbacks 73.06 49.93 4.38 36.37 54.61 47.56 4.01 27.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Nine months ended
Sept 30, 2008 Sept 30, 2007
Light Natural Light Natural
oil Ngl gas Total oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------

Revenue 106.74 72.45 8.96 61.39 64.91 56.48 6.88 44.39
Royalties (16.11) (19.70) (1.91) (13.15) (8.19) (14.87) (1.07) (7.36)
Operating
costs (11.45) (6.94) (1.34) (8.17) (5.42) (6.72) (1.03) (6.18)
Transportation
costs (2.44) (0.03) (0.42) (2.19) (2.35) (0.37) (0.38) (2.11)
----------------------------------------------------------------------------
Operating
netbacks 76.74 45.78 5.29 37.88 48.95 34.52 4.40 28.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------


General and Administrative

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

Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands except per boe) 30, 2008 30, 2007 30, 2008 30, 2007
----------------------------------------------------------------------------

Gross costs 2,936 2,143 8,024 5,973
Operator's recoveries (1,136) (519) (2,170) (1,251)
Capitalized costs (900) (812) (2,927) (2,361)
----------------------------------------------------------------------------
General and administrative expenses 900 812 2,927 2,361
Per boe 0.85 0.95 1.01 1.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Increased general and administrative costs before recoveries and capitalization in the third quarter and first nine months of 2008 compared to 2007 are the result of increased staff levels as well as increased rent costs for the Company's expanded office space added in the fourth quarter of 2007. Net general and administrative expenses per boe are lower in the third quarter of 2008 due to increased production and increased operator's recoveries which is a function of the increased capital expenditures in the third quarter of 2008 compared with 2007. The Company continues to forecast general and administrative costs per unit at between $0.80 and $1.00 per boe.



Interest

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands except per boe) 30, 2008 30, 2007 30, 2008 30, 2007
----------------------------------------------------------------------------

Interest expense 1,605 2,271 5,115 4,926
Average debt level 139,090 138,356 119,495 101,965
Effective interest rate 4.6% 6.3% 5.7% 6.4%
Per boe 1.52 2.66 1.77 2.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Crew's effective interest rate decreased in the third quarter and for the nine months ended September 30, 2008 compared with the same periods in 2007 due to the deferred financing costs, which were incurred in connection with the new credit facility in May 2007, being fully amortized into interest expense by May 2008 as well as lower interest rates paid on borrowings under the Company's credit facility.



Stock-Based Compensation

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept Sept Sept Sept
($ thousands) 30, 2008 30, 2007 30, 2008 30, 2007
----------------------------------------------------------------------------

Gross costs 1,914 1,544 5,486 3,808
Capitalized costs (957) (772) (2,743) (1,904)
----------------------------------------------------------------------------
Total stock-based compensation 957 772 2,743 1,904
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's stock-based compensation expense has increased in 2008 as a result of an increase in stock options issued due to increased staff levels over the same period in 2007.



Depletion, Depreciation and Accretion

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept Sept Sept Sept
($ thousands except per boe) 30, 2008 30, 2007 30, 2008 30, 2007
----------------------------------------------------------------------------

Depletion, depreciation and
accretion 26,247 20,565 69,537 54,938
Per boe 24.80 24.12 24.11 24.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Per unit depletion, depreciation and accretion have slightly increased in the third quarter of 2008 and first nine months of 2008 compared with the same periods in 2007 due to the higher cost of the reserves added through the Gentry acquisition.

Future Income Taxes

The provision for future income taxes was $5.5 million in the third quarter of 2008 compared to a recovery of $0.3 million in the same period of 2007. For the first nine months of 2008, the future tax expense was $6.8 million compared with $0.4 million for the same period in 2007. The increase in future taxes was a result of higher pre-tax earnings partially offset by a corporate rate reduction in British Columbia from 12 percent to 11.5 percent in 2008 and a further reduction to 11 percent in 2009.



Funds from Operations and Net Income

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept Sept Sept Sept
($ thousands) 30, 2008 30, 2007 30, 2008 30, 2007
----------------------------------------------------------------------------

Cash provided by operating
activities 36,208 23,035 97,656 62,518
Funds from operations 35,004 21,171 98,144 59,043
Per share - basic 0.54 0.45 1.68 1.32
- diluted 0.54 0.44 1.66 1.31
Net income (loss) 15,178 (449) 21,534 2,221
Per share - basic 0.24 (0.01) 0.37 0.05
- diluted 0.23 (0.01) 0.36 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's increase in cash provided by operating activities, funds from operations and net income for the third quarter and the first nine months of 2008 was the result of the increased production levels and increased commodity pricing. In the third quarter, net income was also positively impacted by unrealized gains on financial instruments from the Company's risk management program.

Capital Expenditures and Acquisitions

During the third quarter, the Company drilled 18 (16.8 net) wells resulting in 13 (11.8 net) successful natural gas wells, four (4.0 net) light oil wells and one (1.0 net) dry and abandoned well. In addition, the Company also completed 20 (19.1 net) wells, recompleted six (5.7 net) wells and spent $4.1 million on Crown land sales adding to its inventory of undeveloped land in central Alberta and northeastern British Columbia. Total exploration and development expenditures for the third quarter of 2008 were $66.4 million compared to $25.4 million for the same period in 2007. The expenditures are detailed below:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept Sept Sept Sept
($ thousands) 30, 2008 30, 2007 30, 2008 30, 2007
----------------------------------------------------------------------------
Land 4,104 3,407 24,169 7,676
Seismic 1,339 1,090 2,816 2,742
Drilling and completions 52,966 15,647 89,611 43,435
Facilities, equipment and pipelines 7,475 3,750 18,860 13,962
Other 515 1,491 2,609 3,244
----------------------------------------------------------------------------
Total exploration and development 66,399 25,385 138,065 71,059
Property acquisitions
(net of dispositions) (1,097) (51) 70,659 (49)
----------------------------------------------------------------------------
Total 65,302 25,334 208,724 71,010
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In addition, Crew closed the corporate acquisition of Gentry on August 22, 2008 adding approximately 4,000 boe per day of production, an estimated 12.5 million boe of proved and probable reserves and 280,000 acres of net undeveloped land. As consideration, the Company issued 12.3 million common shares and assumed $74.3 million in net debt.

The Company has budgeted exploration and development expenditures for 2008 of $175 million and combined with the Company's first half property and facility acquisitions, total capital expenditures are currently forecasted to be approximately $246 million. The Company's increased capital expenditure budget has resulted from increased land expenditures incurred to acquire additional mineral rights on the company's Montney natural gas resource play in northeast British Columbia, added drilling on the Montney resource play and drilling and completion at Princess in southern Alberta on lands acquired as part of the Gentry acquisition.

Liquidity and Capital Resources

Capital Funding

On August 22, 2008 the Company issued 12,276,749 common shares in exchange for all of the issued and outstanding shares of Gentry. This acquisition has been accounted for using the purchase method the details of which are included in note 3 of the Company's September 30, 2008 consolidated financial statements.

In conjunction with the acquisition, the Company's credit facility with a syndicate of banks was increased to a revolving line of credit of $270 million and an operating line of credit of $15 million (the "Facility"). The Facility revolves for a 364 day period and will be subject to its next 364 day extension by June 15, 2009. If not extended, the Facility will cease to revolve, and all outstanding balances under the Facility will become payable within one year. At September 30, 2008, the Company had drawings of $179.0 million on the Facility.

On May 1, 2008, Crew issued 5,000,000 Common shares at an issue price of $13.35 per share for total net proceeds of approximately $63.1 million. The proceeds were used to acquire 102.2 net sections of Montney rights in northeastern British Columbia for $63.1 million.

On October 10, 2008 Crew filed notice with the Toronto Stock Exchange ("TSX") to make a normal course issuer bid to purchase and cancel up to a maximum of 5,587,988 of the outstanding Common Shares of the Company. The bid commenced on October 15, 2008 and will terminate on October 14, 2009. The Company will pay for any Common Shares acquired under the bid at the prevailing market price on the TSX at the time of the purchase.

The Company will continue to fund its on-going operations from a combination of cash flow, debt, asset dispositions, and equity financings as needed. As the majority of our on-going capital expenditure program is directed to the further growth of reserves and production volumes, Crew is readily able to adjust its budgeted capital expenditures should the need arise.

Working Capital

The capital intensive nature of Crew's activities generally results in the Company carrying a working capital deficit. However, the Company maintains sufficient unused bank credit lines to satisfy such working capital deficiencies. At September 30, 2008, the Company's working capital deficiency including only accounts receivable and accounts payable and accrued liabilities totaled $52.4 million which, when combined with the drawings on its credit facility represented 81% of its available bank facility at that time.

As a result of the current global economic downturn and credit crisis, capital markets with respect to both equities and debt have tightened significantly. The syndicate of banks in Crew's credit facility have remained stable and the Company believes that it has adequate liquidity to fund its current working capital deficit and currently budgeted capital expenditures through a combination of funds generated from operations and limited amounts of additional debt. Should commodity prices continue to weaken for a protracted period the Company is prepared to cut budgeted capital expenditures to match the reduced cash flows resulting from the weaker commodity prices.

Share Capital

As at November 10, 2008, Crew had 71,193,668 Common Shares and 4,549,900 options to acquire Common Shares of the Company issued and outstanding.

Capital Structure

The Company considers its capital structure to include working capital, bank debt, and shareholders' equity. The Company monitors capital based on the ratio of net debt to annualized funds from operations. The ratio represents the time period it would take to pay off the debt if no further capital expenditures were incurred and if funds from operations remained constant. This ratio is calculated as net debt, defined as outstanding bank debt plus or minus net working capital, divided by funds from operations for the most recent calendar quarter, annualized (multiplied by four). The Company's strategy is to maintain a ratio of no more than 2.0 to 1. This ratio may increase at certain times as a result of acquisitions or very low commodity prices. As at September 30, 2008, the Company's ratio of net debt to annualized funds from operations was 1.65 to 1 (December 31, 2007 - 1.22 to 1), which is within the range established by the Company.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
($ thousands, except ratio) 2008 2007
----------------------------------------------------------------------------
Accounts receivable (49,072) (28,588)
Accounts payable and accrued liabilities 101,456 43,231
----------------------------------------------------------------------------
Working capital deficiency 52,384 14,643
Bank loan 179,050 95,028
----------------------------------------------------------------------------
Net debt 231,434 109,671
Funds from operations 35,004 22,390
Annualized 140,016 89,560

Net debt to annualized funds from operations ratio 1.65 1.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Contractual Obligations

Throughout the course of its ongoing business, the Company enters into various contractual obligations such as credit agreements, purchase of services, royalty agreements, operating agreements, processing agreements, right of way agreements and lease obligations for office space and automotive equipment. All such contractual obligations reflect market conditions prevailing at the time of contract and none are with related parties. The Company believes it has adequate sources of capital to fund all contractual obligations as they come due. The following table lists the Company's obligations with a fixed term.



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

($ thousands) Total 2008 2009 2010 2011
----------------------------------------------------------------------------

Bank Loan (note 1) 179,050 - - 179,050 -
Operating leases 2,970 248 990 990 742
Capital commitments 12,150 5,400 6,750 - -
Firm transportation
agreements 22,535 1,677 6,892 7,117 6,849
----------------------------------------------------------------------------
Total 216,705 7,325 14,632 187,157 7,591
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2010. However, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.


The firm transportation commitments were acquired as part of the Company's May 2007 private company acquisition and represent firm service commitments for transportation and processing of natural gas in British Columbia.

Guidance

The Company expects to exit 2008 with approximately $50 million of available capacity on its $285 million credit facility or at approximately 1.6 times debt to annualized currently projected fourth quarter funds from operations. The debt position, although higher than Crew is accustomed, is manageable in this lower commodity price environment and means capital expenditures will be targeted to approximate funds from operations. Crew continues to generate significant free funds from operations to fund its capital program and continuously highgrades capital expenditures to have the right balance between near term production additions and future growth.

Crew's 2008 production is expected to average 11,500 to 12,000 boe per day as a result of production curtailments at Septimus, British Columbia (1,100 boe per day) and Princess, Alberta (350 boe per day). With these curtailments, the Company currently expects to exit 2008 producing 15,500 to 16,000 boe per day, the midpoint of which represents a 63% increase in production and a 20% increase in production per share over the fourth quarter of 2007.



Additional Disclosures

Quarterly Analysis

The following table summarizes Crew's key quarterly financial results for
the past eight financial quarters:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands,
except per Sept June Mar. Dec. Sept. June Mar. Dec.
share 30 30 31 31 30 30 31 31
amounts) 2008 2008 2008 2007 2007 2007 2007 2006
----------------------------------------------------------------------------

Total daily
production (boe/d) 11,505 9,445 10,614 9,641 9,268 8,967 6,869 6,227

Average wellhead
price ($/boe) 61.74 70.18 53.20 43.90 39.16 47.43 47.61 46.41

Petroleum and
natural gas sales 65,345 60,316 51,389 38,942 33,390 38,703 29,431 26,590

Cash provided by
operations 36,208 31,908 29,540 11,882 23,035 24,467 15,016 16,522

Funds from
operations 35,004 34,102 29,038 22,390 21,171 20,885 16,987 16,705

Per share
- basic 0.54 0.60 0.54 0.43 0.45 0.46 0.41 0.43
- diluted 0.54 0.58 0.54 0.43 0.44 0.46 0.41 0.43

Net income (loss) 15,178 5,415 941 6,889 (449) 1,351 1,319 1,796

Per share
- basic 0.24 0.09 0.02 0.13 (0.01) 0.03 0.03 0.05
- diluted 0.23 0.09 0.02 0.13 (0.01) 0.03 0.03 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Crew's petroleum and natural gas sales, cash and funds from operations and net income are all impacted by production levels and volatile commodity prices. From 2006 to 2008, despite increasing production, these performance measures have fluctuated as a result of volatile natural gas prices combined with the escalating cost of operations.

Significant factors and trends that have impacted the Company's results during the above periods include:

- Revenue is directly impacted by the Company's ability to replace existing declining production and add incremental production through its on-going capital expenditure program.

- In August 2008, the Company acquired Gentry with approximately 4,000 boe per day of production at closing with light oil and natural gas production mainly in the Company's Plains core.

- Production was negatively impacted by scheduled and unscheduled facility outages in Alberta and northeastern British Columbia in the second quarter of 2008 reducing volumes below the first quarter of 2008.

- In May 2007, the Company acquired a private oil and gas company with approximately 3,100 boe per day of production at closing, consisting mainly of natural gas in the northeastern British Columbia area.

- In November 2006, the Company acquired a private oil and gas company with approximately 1,000 boe per day of production at closing.

- Revenue and royalties are significantly impacted by underlying commodity prices. Prior to March 31, 2008, the Company had used a limited amount of derivative contracts or forward sales contracts to reduce the exposure to commodity price fluctuations.

- In the first and second quarters of 2008, the Company had unrealized losses on financial instruments of $5.2 million and $5.2 million, respectively, primarily relating to contracts covering the period of April 1, 2008 to October 31, 2008.

- In the third quarter, the Company had significant unrealized gains on financial instruments of $12.9 million relating to contracts covering the period of April 1, 2008 to December 31, 2008.

- In the second quarter and third quarter of 2008, the Company had realized losses on financial instruments of $2.2 million and $0.8 million, respectively.

- The Company's operating costs and capital expenditures have been subject to inflationary pressures brought on by increasing demand for services and supplies within the Canadian oil and gas industry and increased fuel and steel costs. These increases have resulted in higher depletion and operating costs reducing net income.

- In the fourth quarter of 2007 and the first quarter of 2008, Crew had future tax recoveries which positively affected net income due to Canadian federal and provincial tax rate reductions.

Disclosure Controls and Procedures and Internal Controls over Financial Reporting

Crew's Chief Executive Officer and Chief Financial Officer are required to cause the Company to disclose herein any change in Crew's disclosure controls and procedures and internal controls over financial reporting that occurred during the Company's most recent interim period that has materially affected, or is reasonably likely to materially affect the Company's internal controls over financial reporting. No material changes in Crew's disclosure controls and procedures and internal controls over financial reporting were identified during the nine months ended September 30, 2008 that have materially affected, or are reasonably likely to materially affect the Company's internal controls over financial reporting.

It should be noted that a control system, including Crew's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

Regulatory Matters

On August 15, 2008, the Canadian Securities Administrators published the National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. There is a requirement to provide certification of the effectiveness of internal controls over financial reporting for years ending after December 15, 2008. Crew has plans in place to test the operating effectiveness of internal controls over financial reporting and to provide the required certification.

New Accounting Pronouncements

Financial Instruments

On January 1, 2008, the Company adopted CICA Handbook Section 3862, "Financial Instruments - Disclosures", and Section 3863, "Financial Instruments - Presentation". Section 3862 and 3863 establish standards for the presentation and disclosure of information that enable users to evaluate the significance of financial instruments to the entity's financial position, and the nature and extent of risks arising from financial instruments and how the entity manages these risks. The implementation of these standards did not impact the Company's financial results, however it did result in additional disclosure presented in note 9 of the Company's notes to the consolidated financial statements.

Capital Disclosures

On January 1, 2008, the Company adopted CICA Handbook Section 1535 "Capital Disclosures". Section 1535 establishes standards for disclosing information about an entity's capital and how it is managed. This section specifies disclosure about objectives, policies and processes for managing capital, quantitative data about what an entity regards as capital, whether an entity has complied with all capital requirements, and if it has not complied, the consequences of such non-compliances. The implementation of this standard did not impact the Company's financial results, however it did result in additional disclosure presented in note 10 of the Company's notes to the consolidated financial statements.

Goodwill

As of January 1, 2009, Crew will be required to adopt CICA Handbook Section 3064 "Goodwill and Intangible Assets", which defines the criteria for the recognition of intangible assets.

Convergence with International Reporting Standards

In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the changeover to International Financial Reporting Standards ("IFRS") from Canadian GAAP will be required for publicly accountable enterprises interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011. The AcSB issued the "omnibus" exposure draft of IFRS with comments due by July 31, 2008, wherein early adoption by Canadian entities is also permitted. The Canadian Securities Administrators ("CSA") has also issued Concept Paper 52-402, which requested feedback on the early adoption of IFRS as well as the continued use of US GAAP by domestic issuers. The eventual changeover to IFRS represents a change due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations.

The IASB has issued an exposure draft relating to certain amendments and exemptions to IFRS 1. One such exemption relating to full cost oil and gas accounting is expected to reduce the administrative burden in the transition from the current Canadian Accounting Guideline 16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late 2009. The amendment will potentially permit the Company to apply IFRS prospectively to their full cost pool, rather than the retrospective assessment of capitalized exploration and development expenses, with the proviso that an impairment test, under IFRS standards, be conducted at the transition date.

Although, the Company has not completed development of its IFRS changeover plan, when finalized it will include project structure and governance, resourcing and training, an analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential IFRS 1 exemptions. The Company anticipates completing its project scoping, which will include a timetable for assessing the impact on data systems, internal controls over financial reporting, and business activities, such as financing and compensation arrangements, by the end of the fourth quarter of 2008.

Dated as of November 10, 2008

Cautionary Statement

This press release contains forward-looking statements relating to Management's approach to operations, expectations relating to the number of wells, amount and timing of capital projects, Company production, commodity prices in Canada, royalties, operating costs, transportation costs, general and administrative costs and cash flow. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable by Crew at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; competitive action by other companies; fluctuations in oil and gas prices; the ability to produce and transport crude oil and natural gas to markets; higher than projected inflation; the result of exploration and development drilling and related activities; fluctuation in foreign currency exchange rates; the imprecision of reserve estimates; the ability of suppliers to meet commitments; actions by governmental authorities including increases in taxes; decisions or approvals of administrative tribunals; change in environmental and other regulations; risks associated with oil and gas operations; the weather in the Company's areas of operations; and other factors, many of which are beyond the control of the Company. There is no representation by Crew that actual results achieved during the forecast period will be the same in whole or in part as that forecast.

Crew is an oil and gas exploration and production company whose shares are traded on The Toronto Stock Exchange under the trading symbol "CR".

Financial statements for the three month and nine month periods ended September 30, 2008 and 2007 are attached.



CREW ENERGY INC.
Consolidated Balance Sheets
(unaudited)
(thousands)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2008 2007
----------------------------------------------------------------------------
Assets
Current assets:
Accounts receivable $ 49,072 $ 28,588
Fair value of financial instruments (note 9) 1,124 -
----------------------------------------------------------------------------
50,196 28,588

Property, plant and equipment (notes 3 and 4) 981,646 552,805

Goodwill (note 3) 73,599 20,800
----------------------------------------------------------------------------
$ 1,105,441 $ 602,193
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities:
Accounts payable and accrued liabilities $ 101,456 $ 43,231
Fair value of financial instruments (note 9) - 423
Future income taxes 289 -
Current portion of other long-term
obligations (note 6) 1,313 1,313
----------------------------------------------------------------------------
103,058 44,967

Bank loan (note 5) 179,050 95,028

Other long-term obligations (note 6) 1,774 2,759

Asset retirement obligations (note 7) 34,129 18,668

Future income taxes 119,973 77,045

Shareholders' Equity
Share capital (note 8) 576,081 298,129
Contributed surplus (note 8) 14,802 10,557
Retained earnings 76,574 55,040
----------------------------------------------------------------------------
667,457 363,726
Commitments (note 12)
----------------------------------------------------------------------------
$ 1,105,441 $ 602,193
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


CREW ENERGY INC.
Consolidated Statements of Operations, Comprehensive Income (Loss)
and Retained Earnings
(unaudited)
(thousands, except per share amounts)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept 30, Sept 30, Sept 30, Sept 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

Revenue

Petroleum and natural gas sales $ 65,345 $ 33,390 $177,050 $101,524
Royalties (14,157) (2,009) (37,926) (16,820)
Gain (loss) on financial
instruments (note 9) 11,912 105 (844) 996
Other income - - 268 -
----------------------------------------------------------------------------
63,100 31,486 138,548 85,700

Expenses

Operating 10,363 5,361 23,568 14,129
Transportation 2,325 2,413 6,317 4,824
Interest 1,605 2,271 5,115 4,926
General & administrative 900 812 2,927 2,361
Stock-based compensation 957 772 2,743 1,904
Depletion, depreciation &
accretion 26,247 20,565 69,537 54,938
----------------------------------------------------------------------------
42,397 32,194 110,207 83,082

----------------------------------------------------------------------------
Income (loss) before income taxes 20,703 (708) 28,341 2,618

Future Income taxes 5,525 (259) 6,807 397
----------------------------------------------------------------------------

Net income (loss) and
comprehensive income (loss) 15,178 (449) 21,534 2,221
Retained earnings,
beginning of period 61,396 48,600 55,040 45,930
----------------------------------------------------------------------------

Retained earnings, end of period $ 76,574 $ 48,151 $ 76,574 $ 48,151
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income (loss) per share
(note 8(d))
Basic $ 0.24 $ (0.01) $ 0.37 $ 0.05
Diluted $ 0.23 $ (0.01) $ 0.36 $ 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


CREW ENERGY INC.
Consolidated Statements of Cash Flows
(unaudited)
(thousands)

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept 30, Sept 30, Sept 30, Sept 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

Cash provided by (used in):

Operating activities:
Net income (loss) $ 15,178 $ (449) $ 21,534 $ 2,221
Items not involving cash:
Depletion, depreciation &
accretion 26,247 20,565 69,537 54,938
Stock-based compensation 957 772 2,743 1,904
Future income taxes 5,525 (259) 6,807 397
Unrealized (gain) loss on
financial instruments (12,903) 542 (2,477) (417)
Transportation liability
charge (note 6) (328) (283) (985) (471)
Asset retirement expenditures 8 (18) (623) (32)
Change in non-cash working
capital (note 11) 1,524 2,165 1,120 3,978
----------------------------------------------------------------------------
36,208 23,035 97,656 62,518

Financing activities:
Increase (decrease) in bank loan (8,502) (1,074) 15,818 98,580
Issue of common shares 84 (53) 69,846 55,947
Share issue costs (133) - (3,654) -
----------------------------------------------------------------------------
(8,551) (1,127) 82,010 154,527

Investing activities:
Exploration and development (66,399) (25,385) (138,065) (71,059)
Property acquisitions, net
of dispositions 1,097 51 (70,659) 49
Business acquisition (note 3) (1,500) - (1,500) (137,325)
Change in non-cash working
capital (note 11) 39,145 3,426 30,558 (8,710)
----------------------------------------------------------------------------
(27,657) (21,908) (179,666) (217,045)

----------------------------------------------------------------------------
Change in cash and cash equivalents - - - -
Cash and cash equivalents,
beginning of period - - - -
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


CREW ENERGY INC.
Notes to Consolidated Financial Statements
For the three and nine months ended September 30, 2008 and 2007
(Unaudited)
(Tabular amounts in thousands)


1. Significant accounting policies:

The interim consolidated financial statements of Crew Energy Inc. ("Crew" or the "Company") have been prepared by management in accordance with accounting principles generally accepted in Canada. The interim consolidated financial statements have been prepared following the same accounting policies and methods of computation as the consolidated financial statements for the year ended December 31, 2007, except as disclosed below. The disclosure which follows is incremental to the disclosure included with the December 31, 2007 consolidated financial statements. These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto for the year ended December 31, 2007.

Certain comparative amounts have been reclassified to conform to current period presentation.

2. Change in accounting policy:

Financial Instruments

On January 1, 2008, the Company adopted CICA Handbook Section 3862, "Financial Instruments - Disclosures", and Section 3863, "Financial Instruments - Presentation". Section 3862 and 3863 establish standards for the presentation and disclosure of information that enable users to evaluate the significance of financial instruments to the entity's financial position, and the nature and extent of risks arising from financial instruments and how the entity manages these risks. The implementation of these standards did not impact the Company's financial results; however it did result in additional disclosure presented in note 9.

Capital Disclosures

On January 1, 2008, the Company adopted CICA Handbook Section 1535 "Capital Disclosures". Section 1535 establishes standards for disclosing information about an entity's capital and how it is managed. This section specifies disclosure about objectives, policies and processes for managing capital, quantitative data about what an entity regards as capital, whether an entity has complied with all capital requirements, and if it has not complied, the consequences of such non-compliances. The implementation of this standard did not impact the Company's financial results; however it did result in additional disclosure presented in note 10.

New Accounting Pronouncements

Goodwill

As of January 1, 2009, Crew will be required to adopt CICA Handbook Section 3064 "Goodwill and Intangible Assets", which defines the criteria for the recognition of intangible assets.

Convergence with International Reporting Standards

In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the changeover to International Financial Reporting Standards ("IFRS") from Canadian GAAP will be required for publicly accountable enterprises interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011. The AcSB issued the "omnibus" exposure draft of IFRS with comments due by July 31, 2008, wherein early adoption by Canadian entities is also permitted. The Canadian Securities Administrators ("CSA") has also issued Concept Paper 52-402, which requested feedback on the early adoption of IFRS as well as the continued use of US GAAP by domestic issuers. The eventual changeover to IFRS represents a change due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations.

The IASB has issued an exposure draft relating to certain amendments and exemptions to IFRS 1. One such exemption relating to full cost oil and gas accounting is expected to reduce the administrative burden in the transition from the current Canadian Accounting Guideline 16 to IFRS. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late 2009. The amendment will potentially permit the Company to apply IFRS prospectively to their full cost pool, rather than the retrospective assessment of capitalized exploration and development expenses, with the proviso that an impairment test, under IFRS standards, be conducted at the transition date.

Although, the Company has not completed development of its IFRS changeover plan, when finalized it will include project structure and governance, resourcing and training, an analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential IFRS 1 exemptions. The Company anticipates completing its project scoping, which will include a timetable for assessing the impact on data systems, internal controls over financial reporting, and business activities, such as financing and compensation arrangements, by the end of the fourth quarter of 2008.

3. Business acquisition:

On August 22, 2008, Crew acquired all of the issued and outstanding shares of Gentry Resources Ltd. ("Gentry"). As consideration, Crew issued an aggregate of 12,276,749 common shares at an ascribed value of $17.49 per share. The ascribed value per share was determined based on Crew's five-day weighted average trading price before and after the announcement of the acquisition on June 23, 2008. The operating results of Gentry were included in the accounts of the Company from August 22, 2008.
The acquisition has been accounted for using the purchase method of accounting as follows:



The acquisition has been accounted for using the purchase method of
accounting as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Consideration
Shares issued $ 214,714
Transaction costs 1,500
----------------------------------------------------------------------------
$ 216,214
Net assets received at fair value
Property, plant and equipment 283,731
Goodwill 52,799
Working capital deficiency (6,063)
Fair value of financial instruments (930)
Bank loan (68,204)
Asset retirement obligations (13,854)
Future income taxes (31,265)
----------------------------------------------------------------------------
$ 216,214
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The above amounts are estimates made by management based on currently available information. Amendments may be made to the purchase equation as the cost estimates and balances are finalized.

As at August 22, 2008, Gentry had accounts receivable from SemGroup LP totaling $4.6 million. On July 22, 2008, SemGroup LP filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code and two of SemGroup LP's Canadian subsidiaries, SemCanada Energy Company and SemCanada Crude Company (collectively "SemCanada"), filed for creditor protection in Canada. As a result, the Company has provided an allowance for doubtful accounts totaling $4.6 million in the above purchase equation for amounts outstanding from SemCanada.



4. Property, plant and equipment:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
September 30, 2008 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 1,195,417 $ 213,771 $ 981,646
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
December 31, 2007 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 698,251 $ 145,446 $ 552,805
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The cost of unproved properties at September 30, 2008 of $172,835,000 (2007 - $35,603,000) was excluded from the depletion calculation. Estimated future development costs associated with the development of the Company's proved reserves of $31,692,000 (2007 - $31,295,000) have been included in the depletion calculation and estimated salvage values of $36,731,000 (2007 - $20,953,000) have been excluded from the depletion calculation.

On May 12, 2008, the Company acquired certain working interests in undeveloped land for cash proceeds of $63.1 million.

The following corporate expenses related to exploration and development activities were capitalized:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months
ended Year ended
September 30, December 31,
2008 2007
----------------------------------------------------------------------------
General and administrative expense $ 2,927 $ 3,331
Stock-based compensation expense, including
future income taxes 3,693 3,624
----------------------------------------------------------------------------
$ 6,620 $ 6,955
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5. Bank loan:

The Company's bank facility consists of a revolving line of credit of $270 million and an operating line of credit of $15 million (the "Facility"). The Facility revolves for a 364 day period and will be subject to its next 364 day extension by June 15, 2009. If not extended, the Facility will cease to revolve, the margins there under will increase by 0.25 per cent and all outstanding advances there under will become repayable in one year.

Advances under the Facility are available by way of prime rate loans with interest rates of up to 0.75 per cent over the bank's prime lending rate and bankers' acceptances and LIBOR loans which are subject to stamping fees and margins ranging from 0.95 per cent to 1.75 per cent depending upon the debt to EBITDA ratio of the Company calculated at the Company's previous quarter end. As at September 30, 2008, the Company's applicable pricing included a 0.10 percent margin on prime lending and a 1.10 percent stamping fee and margin on Bankers' Acceptances and LIBOR loans along with a 0.20 percent per annum standby fee on the portion of the facility that is not drawn. The facility is secured by a first floating charge debenture over the Company's consolidated assets. The effective interest rate on the Company's borrowings under its bank facility for the period ended September 30, 2008 was 5.4% (September 30, 2007 - 6.4%).

6. Other long-term obligations:

As part of the Company's May 3, 2007 private company acquisition, Crew acquired several firm transportation agreements. These agreements had a fair value at the time of the acquisition of a $4.9 million liability. This amount was accounted for as part of the acquisition cost and will be charged as a reduction to transportation expenses over the life of the contracts as they are incurred. This charge for the three and nine months ended September 30, 2008 was $0.3 million and $1.0 million, respectively (September 30, 2007 - $0.3 million and $0.5 million).

7. Asset retirement obligations:

Total future asset retirement obligations were determined by management and were based on Crew's net ownership interest, the estimated future costs to reclaim and abandon the wells and facilities and the estimated timing of when the costs will be incurred. Crew estimated the net present value of its total asset retirement obligation as at September 30, 2008 to be $34,129,000 (December 31, 2007 - $18,668,000) based on a total future liability of $66,613,000 (December 31, 2007 - $35,166,000). These payments are expected to be made over the next 49 years. An 8% (2007 - 8%) credit adjusted risk free discount rate and 2% (2007 - 2%) inflation rate were used to calculate the present value of the asset retirement obligation.

The following table reconciles Crew's asset retirement obligations:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months
ended Year ended
September 30, December 31,
2008 2007
----------------------------------------------------------------------------
Carrying amount, beginning of period $ 18,668 $ 10,485
Liabilities acquired (note 3) 13,927 6,646
Accretion expense 1,212 929
Liabilities incurred 945 845
Liabilities settled (623) (237)
----------------------------------------------------------------------------
Carrying amount, end of period $ 34,129 $ 18,668
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8. Share capital:

(a) Common Shares:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
shares Amount
----------------------------------------------------------------------------

Common shares, December 31, 2007 53,577 $ 298,129
Business acquisition (note 3) 12,277 214,714
Public offering issued for cash 5,000 66,750
Exercise of stock options 340 3,096
Stock-based compensation - 1,241
Flow through share income tax adjustment on
2007 issuance - (5,200)
Share issue costs, net of future income
taxes of $1,005 - (2,649)
----------------------------------------------------------------------------
Common shares, September 30, 2008 71,194 $ 576,081
----------------------------------------------------------------------------
----------------------------------------------------------------------------


On October 10, 2008 Crew filed notice with the Toronto Stock Exchange ("TSX") to make a normal course issuer bid to purchase and cancel up to a maximum of 5,587,988 of the outstanding Common Shares of the Company. The bid will commence on October 15, 2008 and will terminate on October 14, 2009. The Company will pay for any Common Shares acquired under the bid at the prevailing market price on the TSX at the time of the purchase.

On May 1, 2008, Crew issued 5,000,000 Common Shares at $13.35 per share for aggregate proceeds of $66.8 million ($63.1 million net of issue costs). The proceeds were used to acquire certain working interests in undeveloped land as presented in note 4.

On October 25, 2007, the Company closed a public offering resulting in the issuance of 6,042,360 shares for aggregate proceeds of $54.5 million ($51.5 million net of issue costs). Of the shares issued, 1,860,500 shares were issued on a flow through basis in which the Company committed to renounce to the purchasers certain Canadian income tax deductions totaling $20.0 million. At September 30, 2008, the Company had renounced all required income tax deductions and had incurred all qualifying expenditures under this flow through offering.



(b) Contributed Surplus:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Contributed surplus, December 31, 2007 $ 10,557
Stock-based compensation 5,486
Conversion of stock options (1,241)
----------------------------------------------------------------------------
Contributed surplus, September 30, 2008 $ 14,802
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(c) Stock-based compensation:

The Company measures compensation costs associated with stock-based compensation using the fair value method under which the cost is recognized over the vesting period of the underlying security. The fair value of each stock option is determined at each grant date using the Black-Scholes model with the following weighted average assumptions used for options granted during the nine month period ended September 30, 2008: risk free interest rate 4.09% (2007 - 3.85%), expected life 4 years (2007 - 4 years), volatility 45% (2007 - 45%), and an expected dividend of nil (2007 - nil). The Company has not incorporated an estimated forfeiture rate for stock options that will not vest; rather the Company accounts for actual forfeitures as they occur.

During the first nine months of 2008, the Company recorded $5,486,000, (2007 - $3,808,000) of stock-based compensation expense related to the stock options, of which $2,743,000 (2007 - $1,904,000) was capitalized in accordance with the Company's full cost accounting policy. As stock-based compensation is non-deductible for income tax purposes, a future income tax liability of $950,000 (2007 - $774,000) associated with the current year's capitalized stock-based compensation has been recorded.

i) Stock options

The average fair value of the stock options granted during the nine months ended September 30, 2008, as calculated by the Black-Scholes method, was $3.66 per option (September 30, 2007 - $4.04).



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Number of Price average
Options Range exercise price
----------------------------------------------------------------------------

Balance December 31, 2007 3,271 $4.70 to $17.80 $11.41
Granted 2,508 $7.23 to $18.70 $9.19
Exercised (340) $4.70 to $12.18 $9.12
Forfeited (593) $7.23 to $17.80 $10.79
Cancelled (444) $17.73 to $17.80 $17.75
----------------------------------------------------------------------------
Balance September 30, 2008 4,402 $7.23 to $18.70 $9.77
Exercisable 627 $7.44 to $12.25 $10.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(d) Per share amounts:

Per share amounts have been calculated on the weighted average number of shares outstanding. The weighted average number of shares outstanding for the three month period ended September 30, 2008 was 64,254,000 (September 30, 2007 - 47,321,000) and for the nine month period ended September 30, 2008, the weighted average number of shares outstanding were 58,369,000 (September 30, 2007 - 44,648,000).

In computing diluted earnings per share for the three month period ended September 30, 2008, 737,000 (September 30, 2007 - nil) shares were added to the weighted average number of common shares outstanding for the dilution added by the stock options and for the nine months ended September 30, 2008, 787,000 (September 30, 2007 - 384,000) shares were added to the weighted average number of common shares for the dilution. There were 289,500 (September 30, 2007 - 2,928,000) stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive.

9. Financial Instruments:

Overview

The Company has exposure to credit, liquidity and market risks from its use of financial instruments. This note provides information about the Company's exposure to each of these risks, the Company's objectives, policies and processes for measuring and managing risk. Further quantitative disclosures are included throughout these financial statements.

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

(a) Credit risk:

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Company's receivables from petroleum and natural gas marketers and joint venture partners and the fair value of derivative instruments.

Substantially all of the Company's petroleum and natural gas production is marketed under standard industry terms. Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company's policy to mitigate credit risk associated with these balances is to establish marketing relationships with large credit worthy purchasers and to sell through multiple purchasers. The Company historically has not experienced any collection issues with its petroleum and natural gas marketers. Joint venture receivables are typically collected within one to three months of the joint venture bill being issued to the partner. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to the expenditure. However, the receivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances can be impacted by industry factors such as commodity price fluctuations, limited capital availability and unsuccessful drilling programs. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however the Company does have the ability in most cases to withhold production from joint venture partners in the event of non-payment.

Derivative assets consist of commodity contracts used to manage the Company's exposure to fluctuations in commodity prices. The Company manages the credit risk exposure related to derivative assets by selecting counterparties based on credit ratings and financial stability and by not entering into commodity contracts for trading or speculative purposes.

The carrying amount of accounts receivable and derivatives represents the maximum credit exposure. As at September 30, 2008 the Company's receivables consisted of $33.7 million of receivables from petroleum and natural gas marketers which has subsequently been collected, $10.7 million from joint venture partners of which $3.4 million has been subsequently collected, and $4.7 million of Crown deposits and prepaids. The Company does not consider any receivables to be past due, except as noted in note 3, where the Company in conjunction with the purchase equation, recorded an allowance for doubtful accounts of $4.6 million regarding amounts outstanding from SemCanada. There were no changes to this allowance during the period from August 22, 2008 to September 30, 2008. Although no value has been assigned, the Company will continue to pursue collection of this receivable.

(b) Liquidity risk:

Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with the financial liabilities. The Company's financial liabilities consist of accounts payable and bank debt. Accounts payable consists of invoices payable to trade suppliers for office, field operating activities and capital expenditures. The Company processes invoices within a normal payment period. Accounts payable and financial instruments have contractual maturities of less than one year. The Company maintains a revolving credit facility, as outlined in note 5, that is subject to renewal annually by the lenders and has a contractual maturity in 2010. The Company also maintains and monitors a certain level of cash flow which is used to partially finance all operating and capital expenditures as the Company does not pay dividends.

(c) Market risk:

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

The Company utilizes both financial derivatives and physical delivery sales contracts to manage market risks. All such transactions are conducted in accordance with the Company's risk management policy that has been approved by the Board of Directors.

(i) Commodity price risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by not only the relationship between the Canadian and United States dollar, as outlined below, but also global economic events that dictate the levels of supply and demand. The Company has attempted to mitigate a portion of the commodity price risk through the use of various financial derivative and physical delivery sales contracts. The Company's policy is to enter into commodity price contracts when considered appropriate to a maximum of 50% of forecasted production volumes. The Company's contracts in place as of September 30, 2008 are as follows:



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

Floor
Volume Price (Cdn Ceiling
(gj/day) Term (Cdn $/gj) $/gj)(Cdn $/gj)
----------------------------------------------------------------------------
April 1, 2008- AECO C
AECO 10,000 October 31, 2008 Monthly Index $7.00 $8.00

April 1, 2008- AECO Daily
AECO 10,000 October 31, 2008 Average $7.00 $8.30

April 1, 2008- AECO C
AECO 10,000 October 31, 2008 Monthly Index $7.50 $9.25

AECO/
Station 2
Differential November 1, 2007- AECO C less
Swap 10,000 October 31, 2008 $0.16 - -

August 22, 2008- AECO Daily
AECO 4,000 October 31, 2008 Average $7.51 $7.51
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volume Floor Ceiling
(barrel/ Price (USD (USD
day) Term (USD $/bbl) $/bbl) $/bbl)
----------------------------------------------------------------------------
August 22, 2008- NYMEX - WTI
NYMEX - WTI 500 December 31, 2008 Daily Average $85.00 $104.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Derivatives are recorded on the balance sheet at fair value at each reporting period with the change in fair value being recognized as an unrealized gain or loss on the consolidated statement of operations, comprehensive income and retained earnings. These contracts had the following effect on the consolidated statement of operations, comprehensive income and retained earnings:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept 30, Sept 30, Sept 30, Sept 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Realized gain (loss) on financial $ (991) $ 647 $ (3,321) $ 579
instruments
Unrealized gain (loss) on financial
instruments 12,903 (542) 2,477 417
----------------------------------------------------------------------------
$ 11,912 $ 105 $ (844) $ 996
----------------------------------------------------------------------------
----------------------------------------------------------------------------



As at September 30, 2008, a $0.10 change to the price per thousand cubic feet of natural gas and $1.00 change to the price of crude oil on the costless collars would have a $0.1 million impact on net income.

(ii) Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. All of the Company's petroleum and natural gas sales are conducted in Canada and are denominated in Canadian dollars. Canadian commodity prices are influenced by fluctuations in the Canadian to U.S. dollar exchange rate. The Company had no forward exchange rate contracts in place as at or during the period ended September 30, 2008.

(iii) Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. For the three and nine months ended September 30, 2008, a 100 basis point change to the effective interest rate would have a $0.3 million and $0.7 million impact on net income, respectively (2007 - $0.3 and $0.5 million). The sensitivity for the nine months ended September 30, 2008 is higher as compared to 2007 because of an increase in outstanding bank debt in the first nine months of 2008 compared to 2007. The Company had no interest rate swap or financial contracts in place as at or during the period ended September 30, 2008.

Fair value of financial instruments

The Company's financial instruments as at September 30, 2008 and December 31, 2007 include accounts receivable, derivative contracts, accounts payable and accrued liabilities, and bank debt. The fair value of accounts receivable, accounts payable and accrued liabilities approximate their carrying amounts due to their short-terms to maturity.

The fair value of derivative contracts is determined by discounting the difference between the contracted price and published forward price curves as at the balance sheet date, using the remaining contracted petroleum and natural gas volumes.

Bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value.

10. Capital management:

The Company's objective when managing capital is to maintain a flexible capital structure which will allow it to execute on its capital expenditure program, which includes expenditures on oil and gas activities which may or may not be successful. Therefore, the Company monitors the level of risk incurred in its capital expenditures to balance the proportion of debt and equity in its capital structure.

The Company considers its capital structure to include working capital, bank debt, and shareholders' equity. The Company monitors capital based on the ratio of net debt to annualized funds from operations. The ratio represents the time period it would take to pay off the debt if no further capital expenditures were incurred and if funds from operations remained constant. This ratio is calculated as net debt, defined as outstanding bank debt plus or minus net working capital, divided by funds from operations for the most recent calendar quarter, annualized (multiplied by four). The Company's strategy is to maintain a ratio of no more than 2.0 to 1. This ratio may increase at certain times as a result of acquisitions or very low commodity prices. As at September 30, 2008, the Company's ratio of net debt to annualized funds from operations was 1.65 to 1 (December 31, 2007 - 1.22 to 1), which is within the range established by the Company.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2008 2007
----------------------------------------------------------------------------

Net debt:

Accounts receivable $ 49,072 $ 28,588
Accounts payable and accrued liabilities (101,456) (43,231)
----------------------------------------------------------------------------
Working capital deficiency $ (52,384) $ (14,643)
Bank loan (179,050) (95,028)
----------------------------------------------------------------------------
Net debt $ (231,434) $ (109,671)


Annualized funds from operations:

Cash provided by operating activities $ 36,208 $ 11,882
Asset retirement expenditures (8) 205
Transportation liability charge 328 313
Change in non-cash working capital (1,524) 9,990
----------------------------------------------------------------------------
Funds from operations 35,004 22,390
Annualized $ 140,016 $ 89,560

Net debt to annualized funds from operations 1.65 1.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In order to facilitate the management of this ratio, the Company prepares annual funds from operations and capital expenditure budgets, which are updated as necessary, and are reviewed and periodically approved by the Company's Board of Directors.

The Company manages its capital structure and makes adjustments by continually monitoring its business conditions, including; the current economic conditions; the risk characteristics of the Company's petroleum and natural gas assets; the depth of its investment opportunities; current and forecasted net debt levels; current and forecasted commodity prices; and other facts that influence commodity prices and funds from operations, such as quality and basis differential, royalties, operating costs and transportation costs.

In order to maintain or adjust the capital structure, the Company will consider; its forecasted ratio of net debt to forecasted funds from operations while attempting to finance an acceptable capital expenditure program including acquisition opportunities; the current level of bank credit available from the Company's lenders; the level of bank credit that may be attainable from its lenders as a result of oil and gas reserve growth; the availability of other sources of debt with different characteristics than the existing bank debt; the sale of assets; limiting the size of the capital expenditure program and new equity if available on favourable terms. The Company's share capital is not subject to external restrictions, however the Company's bank facility is determined by the lenders and based on the lenders' borrowing base models which are based on the Company's petroleum and natural gas reserves.

There has been no change in the Company's approach to capital management during the period ended September 30, 2008.



11. Supplemental cash flow information:

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

Three Three Nine Nine
months months months months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

Changes in non-cash working
capital:

Accounts receivable $ 8,568 $ (400) $ 2,388 $ 3,327
Accounts payable and accrued
liabilities 32,101 5,991 29,290 (8,059)
----------------------------------------------------------------------------
$ 40,669 $ 5,591 $ 31,678 $ (4,732)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating activities $ 1,524 $ 2,165 $ 1,120 $ 3,978
Investing activities 39,145 3,426 30,558 (8,710)
----------------------------------------------------------------------------
$ 40,669 $ 5,591 $ 31,678 $ (4,732)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company made the following cash outlays in respect of interest expense:

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

Three Three Nine Nine
months months months months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2008 2007 2008 2007
----------------------------------------------------------------------------

Interest $ 1,748 $ 2,096 $ 4,599 $ 6,098

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


12. Commitments:

The Company has the following fixed term commitments related to its on-going
business:

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

Total 2008 2009 2010 2011
----------------------------------------------------------------------------

Operating Leases $ 2,970 $ 248 $ 990 $ 990 $ 742
Capital commitments 12,150 5,400 6,750 - -
Firm transportation
agreements 22,535 1,677 6,892 7,117 6,849
----------------------------------------------------------------------------
Total $ 37,655 $ 7,325 $ 14,632 $ 8,107 $ 7,591
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The firm transportation commitments were acquired as part of the Company's May 2007 private company acquisition and represent firm service commitments for transportation and processing of natural gas in British Columbia.

Contact Information

  • Crew Energy Inc.
    Dale Shwed
    President and C.E.O.
    (403) 231-8850
    or
    Crew Energy Inc.
    John Leach
    Vice President, Finance and C.F.O.
    (403) 231-8859
    Website: www.crewenergy.com