Crew Energy Inc.
TSX : CR

Crew Energy Inc.

March 09, 2009 18:02 ET

Crew Energy Announces 2008 Fourth Quarter and Annual Financial and Operating Results

CALGARY, ALBERTA--(Marketwire - March 9, 2009) - Crew Energy Inc. ("Crew" or the "Company") (TSX:CR) of Calgary, Alberta is pleased to present its operating and financial results for the three month period and year ended December 31, 2008.

Highlights

- Achieved record funds from operations in 2008 of $127.8 million, a 57% increase over 2007 while funds from operations per share increased to $2.06, an 18% increase over 2007.

- Crew's production during the fourth quarter of 2008 averaged 14,869 boe per day, a 54% increase over the fourth quarter of 2007 and a 29% increase over the third quarter of 2008. Production for 2008 averaged 11,617 boe per day, a 34% increase over 2007.

- Production per diluted share increased 14% in the fourth quarter of 2008 compared to the fourth quarter of 2007.

- The Company's proved plus probable reserves as at December 31, 2008 increased 76% to 59.1 MMboe including 35.9 MMboe of proved reserves.

- December 31, 2008 proved plus probable reserves per diluted share increased 33% over 2007.

- Achieved finding and development costs of $15.64 per boe and all in finding, development and acquisition costs of $21.24 per boe on a proved plus probable basis.

- Crew's proved plus probable reserve life index (RLI), based on fourth quarter average production, increased by 15% to 10.9 years from 9.5 years at December 31, 2007.

- At December 31, 2008 Crew held mineral interests in 1.6 million acres of land including 627,000 net acres of undeveloped land with an internally estimated value of $227 million.

- The net present value of Crew's estimated future net revenue before income taxes from proved plus probable reserves, discounted at 10%, was $1.04 billion, an increase of 80% over the previous year.

- Crew's net asset value increased to $14.22 per diluted share based on estimated future net revenues discounted at 10%.

- Crew engaged GLJ Petroleum Consultants Ltd. ("GLJ") to prepare an independent evaluation of the Discovered Petroleum Initially in Place ("DPIP") on 50 net sections of Crew's Montney lands in the Septimus area of northeast British Columbia. The report has identified a current best estimate of a net 2.4 Tcf of DPIP in the upper Montney on the Company's lands of which 0.08 Tcf of proved plus probable reserves have been recognized.



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Three Three
Financial months months Year Year
ended ended ended ended

($ thousands, except Dec. 31, Dec. 31, Dec. 31, Dec. 31,
per share amounts) 2008 2007 2008 2007
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Petroleum and natural gas sales 58,806 38,942 235,856 140,466
Funds from operations (note 1) 29,646 22,390 127,790 81,433
Per share - basic 0.42 0.43 2.08 1.75
- diluted 0.42 0.43 2.06 1.74
Net income (loss) (74,853) 6,889 (53,319) 9,110
Per share - basic (1.05) 0.13 (0.87) 0.20
- diluted (1.05) 0.13 (0.87) 0.19

Exploration and development
expenditures 53,612 31,033 191,677 102,092
Property acquisitions
(net of dispositions) (245) (266) 70,414 (315)
Total capital expenditures 53,367 30,767 262,091 101,777

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Capital Structure As at As at
($ thousands) Dec. 31, Dec. 31,
2008 2007
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Working capital deficiency (note 2) 31,822 14,643
Bank loan 223,628 95,028
Net debt 255,450 109,671

Bank facility 285,000 180,000

Common shares outstanding (thousands) 71,084 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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Operations Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
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Daily production
Natural gas (mcf/d) 60,464 47,204 52,595 43,193
Oil (bbl/d) 3,123 445 1,393 545
Natural gas liquids (bbl/d) 1,669 1,329 1,458 952
Oil equivalent (boe/d @ 6:1) 14,869 9,641 11,617 8,696
Average prices (note 1)
Natural gas ($/mcf) 6.93 6.40 8.37 6.75
Oil ($/bbl) 50.21 83.10 74.89 71.90
Natural gas liquids ($/bbl) 37.24 63.29 62.32 57.01
Oil equivalent ($/boe) 42.99 43.90 55.47 44.45
Operating expenses
Natural gas ($/mcf) 1.61 1.06 1.42 1.04
Oil ($/bbl) 12.86 8.55 12.24 6.06
Natural gas liquids ($/bbl) 8.57 5.74 7.41 6.37
Oil equivalent ($/boe @ 6:1) 10.20 6.35 8.82 6.23
Netback
Operating netback ($/boe) (note 2) 22.08 27.73 32.80 28.46
Realized loss/(gain) on
financial instruments (1.93) (0.49) 0.16 (0.32)
G&A ($/boe) 0.91 1.09 0.98 1.05
Interest and other ($/boe) 1.44 1.88 1.60 2.08
Funds from operations ($/boe) 21.66 25.25 30.06 25.65

Drilling Activity
Gross wells 16 11 53 31
Working interest wells 9.8 7.4 43.3 25.3
Success rate, net wells 100% 86% 95% 96%

Undeveloped land (note 4)
Gross acres 1,105,639 325,967
Net acres 626,861 235,524

Reserves (Proved plus probable)(note 4)
Oil (Mbbl) 9,178 711
Ngl (Mbbl) 6,563 4,442
Natural Gas (Mmcf) 260,298 170,070
BOE (Mboe) 59,123 33,498

Finding, Development &
Acquisition Costs ($/boe)
(note 3 and 4) 21.24 15.57

Recycle Ratio (note 4) 1.5 1.8

Net Asset Value (Proved plus
probable disc. 10%)(note 4) $14.22 $9.60
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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.
(3) The acquisition costs related to corporate acquisitions reflects the
consideration paid for the shares acquired plus the net debt assumed,
both valued at closing and does not reflect the fair market value
allocated to the acquired oil and gas assets under Generally Accepted
Accounting Principles.
(4) More detailed information in respect of the results of Crew's
independent reserve evaluation for the year ended December 31, 2008
as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") and related
information was contained in Crew's press release dated February 25,
2009 and will be contained in Crew's Annual Information Form to be
filed on or before March 31, 2009.


Overview

2008 was a year that will be remembered for its volatility within the oil and gas industry and most importantly in the world's financial markets. The first half of 2008 saw a dramatic increase in commodity prices with the price of West Texas Intermediate ("WTI") oil increasing 44% from an average US $93 per bbl in January to an average US $134 per bbl in June and the price of Alberta natural gas increasing 51% from an average $6.98 per gj in January to average $10.60 per gj in July. Instability in the U.S. financial markets mid year resulted in a dramatic slow down in the U.S. economy that rapidly spread throughout the world. This resulted in a precipitous decline in the demand for commodities leading to a dramatic fall in oil and gas prices in the second half of 2008. The price of WTI oil declined 69% from its June highs to trade at an average of US $42 per bbl in December and Alberta natural gas declined 41% from its July highs to trade at an average $6.25 per gj in December.

These dramatic commodity price fluctuations had an impact on the Company's financial results. Funds from operations increased steadily from $29 million in the first quarter to peak at $35 million in the third quarter only to decline back to $29 million in the fourth quarter. This change in funds from operations occurred despite a 40% increase in production from an average of 10,614 boe per day in the first quarter to an average of 14,869 boe per day in the fourth quarter. Funds from operations were also negatively impacted by higher costs associated with inflationary pressures brought on by the high commodity prices experienced over the past few years. Net income was also impacted by fluctuating commodity prices and higher costs and, to a greater degree, by a one time non-cash charge to earnings as a result of a write-down of the Company's carried goodwill.

The Company's increase in production through the year was the result of an active exploration and development program and the acquisition of Gentry Resources Ltd. ("Gentry") in August. The Company spent $192 million in 2008 on exploration and development with expenditures focused on natural gas drilling and infrastructure spending in northeast British Columbia on the Company's Triassic Montney natural gas play, west central Alberta natural gas drilling and infrastructure spending and its Princess, Alberta Pekisko oil development. The Company spent $87.8 million on land acquisitions in 2008 which included $79.5 million on undeveloped lands in northeast British Columbia prospective for Triassic Montney natural gas.

In August, Crew closed the acquisition of Gentry adding approximately 4,000 boe per day of production, an estimated 12.3 million boe of proved and probable reserves and 280,000 acres of undeveloped land predominantly on its primary oil play at Princess in south central Alberta. As consideration the Company issued 12.3 million Common Shares and assumed $73.6 million of net debt.

Hedging Activity

With the current economic recession fully established, hedging has become more important in protecting corporate funds from operations. Crew now has over 40% of the Company's current non-royalty natural gas volumes hedged at an average floor price of $6.13 per gj from April through October 2009, in order to protect its capital program and balance sheet through the current economic downturn. These hedges include a 5,000 gj per day collar with a floor of $6.50 per gj and a ceiling of $8.40 per gj for calendar 2009. Crew has also acquired natural gas puts on 15,000 gj per day at $6.00 per gj for the period April 1, 2009 through October 31, 2009. These puts were paid for with the sale of natural gas calls on 15,000 gigajoules per day at an average price of $7.83 per gj for the period January 1, 2010 through December 31, 2010.

Currently all of Crew's production is sold in Canadian markets and denominated in Canadian dollars. Canadian commodities trade independently of US commodities; however, prices in Canada are closely correlated with prices in the US and are impacted by fluctuations in the exchange rate between the Canadian and US dollar. When the Canadian dollar strengthens in relation to the US dollar we generally experience a decrease in Canadian commodity prices in comparison to US commodity prices. As a result, Crew has entered into contracts that fix the exchange rate on US $4 million per month at 1.2400 for the period February 2009 through December 2009.

The majority of Crew's bank borrowings are drawn in the form of banker's acceptances with 30, 60 or 90 day floating interest rates plus a stamping fee which ranges from 0.95% to 1.75% depending on the Company's trailing debt to EBITDA ratio. As a result of the current economic downturn and the decrease in central banks' prime lending rates, the interest rates charged on banker's acceptances are at levels not seen in decades. In order to reduce the risk of a future increase in the interest rate charged on banker's acceptances, the Company has entered into contracts fixing the rate on $100 million of banker's acceptances for the period beginning in February 2009 to February 2011 at a rate of 1.10% plus the applicable stamping fee charged by the Company's bank syndicate.

OPERATIONS UPDATE

During the fourth quarter, the Company drilled a total of 16 (9.8 net) wells resulting in 12 (5.8 net) natural gas wells, three (3.0 net) oil wells and one (1.0 net) service well. During 2008, Crew drilled a total of 53 (43.3 net) wells resulting in 41 (31.3 net) natural gas wells, nine (9.0 net) oil wells, one (1.0 net) service well and two (2.0 net) dry and abandoned wells representing a success rate of 96% (95% net). In addition, in the quarter, the Company completed 21 (17.4 net) wells and recompleted six (5.6 net) wells. The Company also added to its infrastructure, spending 24% of its capital expenditures on equipment and facilities primarily in the Princess, Alberta and Septimus, British Columbia areas.

As a result of the current economic environment and continued weakening of commodity prices, Crew has curtailed 2009 activity levels to match capital expenditures with expected cash flow. The Company has drilled two wells in the first quarter of 2009 and high graded its drilling program in order to optimize economic returns in the current price environment. In addition to well optimization programs in all areas of operation, the majority of the 2009 capital program will be directed to operating cost reductions at Princess and facility construction, minor land acquisitions and drilling at Septimus, British Columbia. Crew has had very positive developments on its two resource plays at Septimus in northeast British Columbia and Princess, Alberta.

Montney Play, Northeast British Columbia

Crew controls 184 net sections on the Montney play in northeast British Columbia. The Company has now drilled or re-completed 12 wells targeting the Montney. Crew continues to concentrate its drilling efforts in the Septimus area experiencing exceptional results with wells testing at rates as high as 17.8 mmcf per day. Crew is currently producing at a restricted rate of seven mmcf per day from the Montney at Septimus and has an estimated seven to eight mmcf per day of additional production capacity. The drilling program at Septimus has resulted in finding and development costs, including land expenditures on the developed lands and future development capital, of $9.56 per boe on a proved plus probable basis. Based on Crew's evaluation of the economics of the Septimus play, rates of return are attractive at current gas prices with a $4.40 per gj price yielding a 25% to 35% rate of return and a recycle ratio of 1.6. With roads and pipelines already built, the economies of scale are expected to improve with well costs targeted to decrease to $4.5 million per well. Equipment has been ordered and applications have been submitted for approval to the British Columbia regulatory authorities for construction of a 25 mmcf per day (previously estimated at 20 mmcf per day) natural gas processing facility. The gas plant has been designed to be expanded in stages with construction expected to start after spring breakup and commissioning currently planned for late in the third quarter. Current plans are to drill four to seven wells targeting the Montney in 2009 and evaluate the gas plant expansion in late 2009.

Montney Evaluation

Based on an independent evaluation by GLJ effective November 30, 2008, it is estimated that the Discovered Petroleum Initially in Place ("DPIP") for 50 net sections of Montney rights owned in Crew's Septimus area is a net 2.4 Tcf, of which 0.72 Tcf is on sections to which reserves have been assigned. GLJ have assigned proved plus probable non-associated gas reserves of 81.5 bcf to the Septimus area, which includes 35 bcf of proved reserves. The assigned proved reserves are booked based on three wells per section and will require an additional 11 wells to be drilled with future development capital of $58.36 million including the completion and tie in of two additional wells. This reserve assignment represents a 5.2% recovery on proved reserves and a 12.1% recovery on proved plus probable reserves. Once there is more production history for Crew's wells, the Company believes that the opportunity exists for improving recoveries in line with other area operators.

GLJ has estimated there exists 1.7 Tcf of DPIP (of the 2.4 Tcf in total DPIP) on sections of the Company's lands at Septimus that do not currently have any reserves assigned and there are additional Crew interest lands adjacent to these lands that have not yet been assigned any DPIP. Continued step-out drilling into the future will provide information to help assess the potential of these lands.

GLJ has provided a best estimate of the DPIP for the upper Montney on 50 out of 184 controlled net sections or 27% of Crew's prospective Montney land base. It should be noted that given the current early stage of development the best estimate of DPIP might change significantly in the future with further development activity and the amount of Contingent Resources as defined in the COGE Handbook has yet to be estimated. Crew is in the early stages of development of this Montney asset and while management is encouraged by the results to date, additional drilling and testing is required to confirm deliverability potential and commercial economic development. The resource estimates provided herein are estimates only and the actual resources may be greater than or less than the estimates provided herein. A recovery project cannot be defined for these volumes of DPIP at this time. There is no certainty that it will be commercially viable or technically feasible to produce any portion of this natural gas currently classified as DPIP.

Pekisko Play, Princess Alberta

The drilling program at Princess has been another positive development for Crew with production from the property increasing from 2,400 boe per day in August to its current rate of over 3,500 boe per day. The prospect inventory continues to expand and horizontal well production rates have exceeded Company expectations with Crew's best well producing at a steady 350 bbl per day with cumulative production of 40,900 bbls since mid October of 2008. Crew owns and controls over 440 net sections of land on this play providing the Company with a multi year drilling inventory. In 2009 Crew has been pipeline connecting and equipping wells drilled in 2008 resulting in a steady increase in production. The focus in this area will be on production optimization and the reduction of operating costs. Significant progress has been made on both of these initiatives to date. Operating costs at Princess in August were approximately $16.50 per boe and have since declined to $13.25 in December. Once operational, the Company's disposal well that was drilled in the fourth quarter is expected to reduce area operating costs by $160,000 per month or $1.50 per boe.

Management Addition

The Company is very pleased to announce that Mr. Dean Tucker, P.Eng has joined our "Crew" in the position of Vice-President, Production and Operations. Dean has over 25 years of oil and gas experience with increasing levels of responsibility. Dean is a welcome addition to our team and we look forward to his contribution to Crew.

Outlook

As the global recession continues to deepen and oil and natural gas prices continue to show weakness Crew will move forward in a cautious and conservative manner. In order to preserve the Company's financial position Crew is committed to maintain or reduce debt levels by spending within funds from operations and consider the disposition of non-core assets in order to focus its capital on the Company's three resource plays.

In this regard, the Company has reduced its previously announced budgeted capital expenditure program to $80 million for 2009 from the previously announced $120 million. This amount includes the completion of the Company's planned natural gas processing facility and the drilling of five wells at Septimus in northeast British Columbia, the drilling of wells at Portage in northeast British Columbia, Strachan and Wapiti in Alberta. It also includes the completion and tie-in of several wells in Alberta and British Columbia that were drilled in 2008 as well as maintenance capital. As a result of the reduction in the planned capital expenditures for the year, the Company has reduced its production guidance to average approximately 14,500 boe per day from the previously announced guidance of 15,500 boe per day. This updated guidance assumes the three week turnaround of the Fort Nelson natural gas processing facility which will affect approximately 970 boe per day of Crew's production in June. This represents a 25% increase in average production growth and a 9% increase in production per share growth.

Over the past few months, Crew has entered into the previously noted derivative contracts to reduce the effect of falling commodity prices, a strengthening Canadian dollar and an increase in interest rates from their current levels on the Company. Crew will continue to monitor these markets and if the opportunity arises will look to enter additional contracts in order to protect the Company's future funds from operations.

The oil and gas industry has historically experienced many boom and bust cycles; however, this cycle is decidedly different in that the downturn is global and pervasive. The Board of Directors, management and staff of Crew are well prepared and equipped to deal with the current and potentially worsening economic environment. Priorities in 2009 are to:

- Maintain or reduce debt levels by spending within cash flow and/or disposing of non core assets.

- Improve operating efficiencies to lower costs and improve netbacks.

- Actively engage in hedging activities to protect capital programs and Crew's balance sheet.

- Continue to exhibit steady production growth. With current production of 15,200 boe per day and over 1,500 boe per day of expected production additions behind pipe, Crew remains positioned to increase average production by a minimum of 20% year over year.

- Preserve the value and future growth prospects of Crew.

- Continue to capture additional resource opportunities.

- Position the Company to exit this recession in a position of strength.

I would like to thank our Board of Directors for their stewardship and support over the year and on behalf of the Board of Directors, management and staff of Crew, I would like to thank our shareholders for their continued support. We understand that these are challenging times however we are confident in the commitment of our team and the quality of our assets to weather this period and strongly believe your patience will be rewarded.

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 month periods and years ended December 31, 2008 and 2007 and the audited and consolidated financial statements and Management Discussion and Analysis for the year ended December 31, 2007.

Forward Looking Statements

This MD&A contains forward-looking statements. Management's assessment of future plans and operations, capital expenditures, methods of financing capital expenditures and the ability to fund financial liabilities, expected commodity prices and the impact on Crew, future operating costs, future transportation costs, expected change in royalty rates, interest rates and the timing of and impact of adoption of IFRS and other accounting policies may constitute forward-looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, the inability to fully realize the benefits of the acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. As a consequence, the Company's actual results may differ materially from those expressed in, or implied by, the forward looking statements. Forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Although Crew believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct.

In addition to other factors and assumptions which may be identified in this document and other documents filed by the Company, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which Crew operates; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; Crew's ability to obtain financing on acceptable terms; field production rates and decline rates; the ability to reduce operating costs; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of pipeline, storage and facility construction and expansion; the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and Crew's ability to successfully market its oil and natural gas products. 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 document are made as at the date of this document 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 defined in 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
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands) 2008 2007 2008 2007
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Cash provided by operating
activities 25,700 11,882 123,356 74,400
Asset retirement expenditures 152 205 775 237
Excess transportation liability
charge 328 313 1,313 784
Change in non-cash working capital 3,466 9,990 2,346 6,012
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Funds from operations 29,646 22,390 127,790 81,433
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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

Production

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Three months ended Three months ended
December 31, 2008 December 31, 2007
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
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Plains
Core 2,845 989 42,890 10,982 239 960 33,700 6,815
North Core 278 680 17,574 3,887 206 369 13,504 2,826
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Total 3,123 1,669 60,464 14,869 445 1,329 47,204 9,641
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Year ended Year ended
December 31, 2008 December 31, 2007
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
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Plains
Core 1,187 991 37,010 8,346 369 812 32,352 6,573
North Core 206 467 15,585 3,271 176 140 10,841 2,123
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Total 1,393 1,458 52,595 11,617 545 952 43,193 8,696
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Fourth quarter production increased over the fourth quarter of 2007 as a result of a successful drilling program that added new natural gas liquids ("ngl") rich natural gas production at Septimus, British Columbia and Ferrier, Alberta and the closing of the acquisition of Gentry in August with liquids production of approximately 1,900 bbl per day and natural gas production of approximately 13 mmcf per day at closing. Production from the Gentry properties increased throughout the fourth quarter as a result of the addition of new oil production from wells that had been drilled but not completed prior to the acquisition.

Production increased 34% in 2008 due to a successful drilling program and the previously mentioned acquisition of Gentry. Natural gas production increased 22% over 2007 due to a successful drilling program in the Company's
Septimus, British Columbia and Ferrier, Alberta areas. Oil production increased 156% due to the acquisition of Gentry with oil production in the Princess, Alberta area. The impact of these additions during the year was moderated by a higher than expected decline on the Company's Hanlan discovery and facility downtime. The facility downtime mainly occurred during the second quarter in northeastern British Columbia and west central Alberta and occurred to a lesser extent during the third quarter at Princess in southern Alberta.



Revenue

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Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
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Revenue ($ thousands)
Natural gas 38,537 27,801 161,192 106,354
Oil 14,425 3,401 38,196 14,310
Natural gas liquids 5,720 7,740 33,249 19,802
Sulphur 124 - 3,219 -
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Total 58,806 38,942 235,856 140,466
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Crew average prices
Natural gas ($/mcf) 6.93 6.40 8.37 6.75
Oil ($/bbl) 50.21 83.10 74.89 71.90
Natural gas liquids ($/bbl) 37.24 63.29 62.32 57.01
Oil equivalent ($/boe) 42.99 43.90 55.47 44.45

Benchmark pricing
Natural Gas - AECO C daily
index (Cdn $/mcf) 6.79 6.24 8.27 6.53
Oil and ngl - Light Sweet @
Edmonton (Cdn $/bbl) 62.54 84.73 102.02 75.67
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Crew's 2007 fourth quarter revenue increased 51% over the fourth quarter of 2007 due to the 54% increase in production. This was partially offset by a two percent decrease in the Company's average prices. The 8% increase in natural gas price was consistent with the increase in Crew's benchmark price. The Company had a disproportionate decrease in oil prices as compared with the Company's benchmark primarily due to the addition of the sale of medium grade oil from the Gentry production in the Princess area. Princess oil production is approximately 26 degree API that is delivered into the Bow River pipeline system which sells at a discount to Edmonton Light due to higher density and sulphur content. The Company had a 41% decrease in ngl pricing compared with a 26% decrease in the benchmark due to increased sales of lower valued ethane in the Septimus, British Columbia and Ferrier, Alberta areas.

The Company's 2008 revenue increased 68% as a result of its 34% increase in production and a 25% increase in product pricing. For the year, Crew's natural gas price increased 24% over 2007 compared with a 27% increase in the Company's benchmark price. This disproportionate increase was the result of additional production from the Septimus, British Columbia area which is sold at British Columbia's Spectra Station 2 pricing which is on average, lower than Alberta AECO pricing. The sales price for Crew's oil and ngl production increased 4% and 9%, respectively, compared to an increase of 35% in the benchmark. The majority of the Company's oil production is medium grade oil in the Princess area from the Gentry acquisition which occurred in late August. Due to the grade of oil, it attracted a lower price than Crew's existing oil production and the majority was produced in the fourth quarter in a lower oil price environment. Increased sales of ethane in the Septimus, British Columbia and Ferrier, Alberta areas accounted for the disproportionate decrease in ngl pricing as compared with the benchmark.



Royalties

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Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands, except per boe) 2008 2007 2008 2007
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Royalties 12,035 6,929 49,961 23,749
Per boe $ 8.80 $ 7.81 $ 11.75 $ 7.48
Percentage of revenue 20.5% 17.6% 21.2% 16.8%
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Royalties as a percentage of revenue increased in the fourth quarter compared to the same quarter of 2007 due to 2007 royalties being reduced by a larger than expected gas cost allowance credit. Royalties as a percentage of revenue were lower than the forecasted 24% in the fourth quarter of 2008 due to royalty credits from a government incentive program for summer drilling in British Columbia.

Royalties as a percentage of revenue increased in 2008 over 2007 due to decreased Alberta deep gas royalty holidays received in 2008 and higher royalty rates on the production from the Gentry acquisition. Offsetting this, the Company had additional benefits from government programs reducing royalties on production in northeastern British Columbia. Crew estimates royalties as a percentage of revenue to average 21% to 22% in 2009.

Financial Instruments

Commodities

The Company will enter into derivative and physical 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 puts, costless collars, swaps and fixed price contracts 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. In 2008, these contracts had the following effect on the consolidated statement of operations:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Realized gain (loss) on financial
instruments 2,646 432 (675) 1,011
Unrealized gain (loss) on financial
instruments 131 (840) 2,608 (423)
----------------------------------------------------------------------------
2,777 (408) 1,933 588
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2008, the Company held financial instrument contracts
and direct sales agreements as follows:

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

Fair Value
Natural Volume Floor Ceiling ($
Gas (gj/day) Term Index (Cdn $/gj) (Cdn $/gj) thousands)
----------------------------------------------------------------------------
AECO 2,500 January 1, 2009 - AECO C 6.50 8.30 632
December 31, 2009 Monthly
Index
less
$0.09

AECO 2,500 January 1, 2009 - AECO C 6.60 8.50 623
December 31, 2009 Monthly
Index
----------------------------------------------------------------------------
1,255
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Subsequent to December 31, 2008, the Company entered into the following
financial instrument contracts:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Volume Put Call
Gas (gj/day) Term Index (Cdn $/gj) (Cdn $/gj)
----------------------------------------------------------------------------
AECO 15,000 April 1, 2009 - AECO C 6.00
October 31, 2009 Monthly Index

AECO 5,000 January 1, 2010 - AECO C
December 31, 2010 Monthly Index 8.00

AECO 10,000 January 1, 2010 - AECO C
December 1, 2010 Monthly Index 7.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Foreign currency

Although 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 did not have any forward exchange rate contracts in place as at or during the period ended December 31, 2008, but subsequent to year-end, the Company entered into contracts for US $4 million per month to fix the exchange rate at 1.24 for the period February to December, 2009.

Interest rate

The Company is exposed to interest rate fluctuations on its bank debt which bears a floating rate of interest. The Company did not have any interest rate swaps or financial contracts in place as at or during the period ended December 31, 2008. Subsequent to year-end, Crew entered into contracts fixing the rate on $100 million of banker's acceptances for 24 months at a rate of 1.10% for the period running from February 11, 2009 to February 11, 2011. The Company pays an additional stamping fee and margins on banker's acceptances as outlined in note 6 of the financial statements.



Operating Costs

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------

Operating costs 13,952 5,634 37,520 19,763
Per boe $ 10.20 $ 6.35 $ 8.82 $ 6.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's operating costs increased in the fourth quarter as compared to the same period in 2007 as a result of the Company's increased production and inflationary pressures on costs experienced throughout the industry. On a per unit basis, operating costs in the fourth quarter increased over the fourth quarter of 2007 due to higher per unit costs associated with the Gentry acquisition. Operating costs associated with the Gentry properties were estimated at approximately $16.50 per boe at closing and averaged approximately $15.00 per boe for the fourth quarter. Crew has initiated a number of cost cutting initiatives that are intended to bring these costs more inline with Crew's other low cost operations. In addition, higher fuel and third party processing costs in Sierra, British Columbia and Viking and Plain Lake, Alberta areas have negatively affected the Company's operating costs.

Crew's increase in operating costs per unit in 2008 was a result of inflationary pressures experienced throughout its operations and the acquisition of Gentry with higher per unit costs. The Company also experienced facility outages and delayed field operations due to wet weather in the second and third quarter causing a decrease in production from Crew's lower operating cost areas and contributing to the increase in costs per unit. Going forward, Crew has identified a number of cost cutting measures in some of the Gentry areas and with the decline in oil prices, expects fuel costs to decline as well. The Company expects operating costs to range between $9.50 and $10.00 per boe in the first half of 2009. During the second half of 2009, with some of the cost cutting measures in the Gentry areas in place as well as the addition of a new facility currently planned in the Septimus, British Columbia area, Crew expects operating costs to decrease into the range of $9.00 to $9.50 per boe.



Transportation Costs

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------

Transportation costs 2,607 1,779 8,924 6,603
Per boe $ 1.91 $ 2.01 $ 2.10 $ 2.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's 2008 fourth quarter decrease in transportation costs per boe was a result of a reduction in its firm transportation commitments in northeastern British Columbia and lower transportation costs from the properties acquired in the Gentry acquisition. In British Columbia, the Company was able to assign some of its unutilized firm transportation and processing service to a third party thus reducing its gas transportation costs per unit compared to the fourth quarter of 2007.

In 2008, Crew's transportation costs per unit were slightly above 2007 levels. The Company's transportation costs increased with the acquisition of a private company in May 2007. This impact only affected eight months of operations in 2007. The Company forecasts transportation costs in 2009 to approximate fourth quarter 2008 levels and range between $1.85 to $2.10 per boe.



Operating Netbacks

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
Dec. 31, 2008 Dec. 31, 2007
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------

Revenue 50.21 37.24 6.93 42.99 83.10 63.29 6.40 43.90
Royalties (15.32) (11.37) (1.08) (8.80) (7.11) (21.20) (0.93) (7.81)
Operating
costs (12.86) (8.57) (1.61) (10.20) (8.55) (5.74) (1.06) (6.35)
Transportation
costs (1.54) (0.04) (0.39) (1.91) (1.60) (0.04) (0.47) (2.01)
----------------------------------------------------------------------------
Operating
netbacks 20.49 17.26 3.85 22.08 65.84 36.31 3.94 27.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------


----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
Dec. 31, 2008 Dec. 31, 2007
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------

Revenue 74.89 62.32 8.37 55.47 71.90 57.01 6.75 44.45
Royalties (15.67) (17.30) (1.67) (11.75) (7.97) (17.10) (1.02) (7.44)
Operating
costs (12.24) (7.41) (1.42) (8.82) (6.06) (6.37) (1.04) (6.21)
Transportation
costs (1.93) (0.03) (0.41) (2.10) (2.20) (0.26) (0.44) (2.33)
----------------------------------------------------------------------------
Operating
netbacks 45.05 37.58 4.87 32.80 55.67 33.28 4.25 28.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------


General and Administrative Costs

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------

Gross costs 3,076 2,355 11,099 8,328
Operator's recoveries (591) (415) (2,761) (1,666)
Capitalized costs (1,243) (970) (4,169) (3,331)
----------------------------------------------------------------------------
General and administrative
expenses 1,242 970 4,169 3,331
Per boe $ 0.91 $ 1.09 $ 0.98 $ 1.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Increased general and administrative costs before recoveries and capitalization was the result of increased staff levels and higher salary levels in the fourth quarter of 2008 compared to 2007. Increased capital expenditures and production levels in the fourth quarter of 2008 resulted in higher operator recoveries and capitalized costs. In addition, increased production levels resulted in lower per boe costs in the period.

General and administrative expenses increased in 2008 as compared to 2007 due to the addition of new staff to handle the Company's increased activity and increased rent costs for the Company's expanded office space added in the fourth quarter of 2007. Operator recoveries and capitalized costs were higher in 2008 as a result of increased capital expenditures and production in 2008. Crew expects general and administrative costs per boe to average approximately $1.00 per boe in 2009.



Interest

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------

Interest expense 1,970 1,882 7,085 6,808

Average debt level 191,535 107,300 138,395 103,300

Effective interest rate 4.1% 7.0% 5.1% 6.6%

Per boe $ 1.44 $ 2.12 $ 1.67 $ 2.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In the fourth quarter of 2008, higher average debt levels due to the Company's 2008 exploration and development capital program and the acquisition of Gentry have increased the Company's interest expense. This was partially offset by lower interest rates charged on the Company's outstanding bank facility.

In 2008, higher average debt levels due to the Company's 2008 exploration and development capital program and the acquisition of Gentry have increased the Company's interest expense. Crew's effective interest rate decreased in 2008 compared with 2007 due to lower interest rates and 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. In 2009, the Company is expecting increased margins to be applied to its bank facility which will negatively affect Crew's interest expense and effective interest rate, however; lower prime interest rates and interest rates on banker's acceptances along with the Company's interest rate hedges will partially offset this increase.



Stock-Based Compensation

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------

Gross costs 1,178 1,516 6,664 5,324
Capitalized costs (589) (758) (3,332) (2,662)
----------------------------------------------------------------------------
Total stock-based compensation 589 758 3,332 2,662
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's stock-based compensation expense has decreased in the fourth quarter of 2008 due to the Company's declining share price creating a lower fair value for stock options as well as the reversal of expense due to the forfeiture of options in the period. In 2008, increased staff levels and the issuance of stock options in early 2008 has increased the Company's compensation expense for the year.



Depletion, Depreciation and Accretion

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
($ thousands, except per BOE) ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
----------------------------------------------------------------------------

Depletion, depreciation and accretion 35,329 20,489 104,866 75,427
Per BOE 25.83 23.10 24.66 23.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company experienced an increase in per unit depletion, depreciation and accretion in the fourth quarter of 2008. Increased accretion related to the Company's asset retirement obligation accounted for $0.40 per boe of the increase while depletion and depreciation increased $2.33 per boe. The increases were due to additional accretion associated with the added Gentry assets and increased depletion associated with the addition of the Gentry assets at their fair market value at the acquisition date, which was higher than historic Company carrying values for proved reserves.

In 2008, per unit depletion, depreciation and accretion costs increased 4%. Per unit accretion increased $0.16 while depletion and depreciation increased $0.74 per boe. Accretion per boe increased due to the Company's increased capital program and increased well counts from its May 2007 and August 2008 corporate acquisitions. Per unit depletion and depreciation increased due to the higher priced proven reserves from the aforementioned Gentry acquisition. The Company also increased its facility capital expenditures in 2008 as compared with 2007 in order to ensure processing capacity for its increased natural gas production.

Crew performed a ceiling test as at December 31, 2008. Based on the calculation, the carrying values of the Company's property, plant and equipment are less than the sum of the undiscounted cash flows of the Company's proved reserves; therefore, the Company's property, plant and equipment was considered recoverable.

Goodwill

Crew records goodwill on corporate acquisitions when the total purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired company. The goodwill balance is assessed for impairment annually at year-end or as events occur that could result in an impairment. In 2008, the Company performed a goodwill impairment test by comparing the fair value of the Company to its carrying value. Due to a decline in the Company's fair value as represented by its market capitalization on December 31, 2008, Crew's carrying amount exceeded its fair value therefore it was determined a non-cash impairment loss should be recognized. The Company has determined that the goodwill associated with the acquisitions in 2006, 2007, and August, 2008 was impaired and a non-cash loss of $69.1 million was recognized. It should be noted that there has been no impairment to the value of Crew's petroleum and natural gas assets and no write down of petroleum and natural gas assets has been recorded in any period.

Taxes

The future income tax expense for 2008 was $6.4 million compared to a recovery of $6.2 million in 2007. In 2007, the Company's tax provision was impacted by the recovery of $8.0 million relating to the federal income tax rate reduction enacted during the year.



A summary of the Company's estimated income tax pools at December 31, 2008
is outlined below:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance Balance
($ thousands) Dec. 31, 2008 Dec. 31, 2007
----------------------------------------------------------------------------

Cumulative Canadian Exploration Expense 85,000 46,500
Cumulative Canadian Development Expense 124,000 70,000
Cumulative Canadian Oil and Gas Property Expense 167,000 54,500
Undepreciated Capital Cost 111,000 65,000
Share issue costs 7,700 5,000
Non-capital loss 26,700 500
----------------------------------------------------------------------------
521,400 241,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The estimated income tax pools have been reduced by the estimated deferred partnership income for 2008 and the reduction in the CEE tax pools due to the renunciation of the 2007 flow through expenditures. The Company did not pay cash taxes in 2008 and estimates it has sufficient tax pools to shelter estimated income until 2010 or beyond.



Cash and Funds from Operations and Net Income

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended Year ended Year ended
($ thousands, except December 31, December 31, December 31, December 31,
per share amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------

Cash provided by operations 25,700 11,882 123,356 74,400
----------------------------------------------------------------------------
Funds from operations 29,646 22,390 127,790 81,433
Per share - basic 0.42 0.43 2.08 1.75
- diluted 0.42 0.43 2.06 1.74
----------------------------------------------------------------------------
Net Income (loss) (74,853) 6,889 (53,319) 9,110
Per share - basic (1.05) 0.13 (0.87) 0.20
- diluted (1.05) 0.13 (0.87) 0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The Company's increase in cash provided by operations and funds from operations resulted from the Company's increased production and higher commodity prices in 2008. Net income was negatively impacted by the goodwill writedown in 2008.

Capital Expenditures and Acquisitions

During the fourth quarter, the Company drilled a total of 16 (9.8 net) wells resulting in 12 (5.8 net) natural gas wells, three (3.0 net) oil wells and one (1.0 net) service well. During 2008, Crew drilled a total of 53 (43.3 net) wells resulting in 41 (31.3 net) natural gas wells, nine (9.0 net) oil wells, one (1.0 net) service well and two (2.0 net) dry and abandoned wells representing a success rate of 96% (95% net). In addition, in the quarter, the Company completed 21 (17.4 net) wells and recompleted six (5.6 net) wells. The Company also added to its infrastructure, deploying 24% of its capital expenditures on equipment and facilities primarily in the Princess, Alberta and Septimus, British Columbia areas.

During 2008, Crew also added to its undeveloped land base acquiring 120 sections of undeveloped land on its developing Triassic Montney natural resource play in northeastern British Columbia.

Total exploration and development expenditures for 2008 were $191.7 million compared to $102.1 million for the same period in 2007. The expenditures are detailed below:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------


Land 1,148 7,080 25,317 14,756
Seismic 2,779 1,750 5,595 4,492
Drilling and completions 35,283 14,836 124,894 58,271
Facilities, equipment and pipelines 13,071 5,829 30,902 19,791
Other 1,331 1,538 4,969 4,782
----------------------------------------------------------------------------
Total exploration and development 53,612 31,033 191,677 102,092
Property acquisitions (dispositions) (245) (266) 70,414 (315)
----------------------------------------------------------------------------
Total 53,367 30,767 262,091 101,777
----------------------------------------------------------------------------
----------------------------------------------------------------------------


In addition, in August 2008 the Company closed the acquisition of Gentry Resources Ltd. which had the majority of its operations in the Princess, Alberta area in southern Alberta. Details of the purchase price are included in the Business Acquisition, note 3 to the Company's December 31, 2008 consolidated financial statements. The acquisition added approximately 4,000 boe per day of production, an estimated 12.3 million boe of proved and probable reserves and 280,000 acres of undeveloped land.

The Company's Board of Directors has approved an $80 million exploration and development budget for 2009. However, as a result of the current economic climate and the Company's desire to maintain a strong financial position, the Company plans to adjust its capital expenditure program to remain within funds from operations until commodity prices recover or alternative forms of financing are available as discussed in Liquidity and Capital Resources section below.

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 December 31, 2008 consolidated financial statements.

In conjunction with the acquisition, the Company's credit facility with a syndicate of banks (the "Syndicate") 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, the margins there under will increase by 0.25 percent and all outstanding balances under the Facility will become repayable within one year. The available lending limits of the Facility are reviewed semi-annually and are based on the Syndicate's interpretation of the Company's reserves and future commodity prices. There can be no assurance that the amount of the available Facility will not be adjusted at the next scheduled review on or before June 15, 2009. Borrowing margins and fees will also be reviewed as part of the Syndicate's annual review prior to June 15, 2009. As a result of the current economic environment and weak global credit market, it is expected that the Company will incur increased margins and fees over those outlined in note 6 to the financial statements. At December 31, 2008, the Company had drawings of $223.6 million on the Facility and had issued letters of credit totaling $5.4 million of which $5.0 million expires by March 31, 2009.

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 102.0 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. At December 31, 2008, the Company has purchased and cancelled 110,000 shares at an average price of $4.64 per share. The Company will pay for any additional 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. See discussion under "Capital Structure" below.

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 December 31, 2008, the Company's working capital deficiency totaled $31.8 million which, when combined with the drawings on its bank line, represented 89% of its current bank facility.

Share Capital

As at December 31, 2008, Crew had 71,083,668 Common Shares outstanding along with 4,275,900 options to acquire Common Shares of the Company.

As at March 9, 2009, Crew had 71,083,668 Common Shares outstanding along with 5,754,000 options to acquire Common Shares of the Company.

Capital Structure

The Company considers its capital structure to include working capital, bank debt, and shareholders' equity. The Company monitors debt levels 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 low commodity prices.

As at December 31, 2008, the Company's ratio of net debt to annualized funds from operations was 2.15 to 1 (2007 - 1.22 to 1). This amount has risen above the preferred range of the Company as a result of the dramatic decrease in commodity prices experienced in the second half of 2008 brought on by the recent global recession. In order to maintain the integrity of the Company's financial position the Company plans to adjust its capital expenditure program to remain within funds from operations until commodity prices recover or an alternative form of financing is consummated.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31,
($ thousands, except ratio) 2008
----------------------------------------------------------------------------
Accounts receivable 42,800
Accounts payable and accrued liabilities (74,622)
----------------------------------------------------------------------------
Working capital deficiency (31,822)
Bank loan (223,628)
----------------------------------------------------------------------------
Net debt (255,450)
Fourth quarter funds from operations 29,646
Annualized 118,584

Net debt to annualized funds from operations ratio 2.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 2009 2010 2011
----------------------------------------------------------------------------


Bank Loan (note 1) 223,628 - 223,628 -
Operating Leases 2,722 990 990 742
Capital commitments 11,500 11,500 - -
Firm transportation agreements (note 2) 20,793 7,003 7,152 6,638
----------------------------------------------------------------------------
Total 258,643 19,493 231,770 7,380
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
Note 2 - 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.


OUTLOOK

As the global recession continues to deepen and oil and natural gas prices continue to show weakness Crew will move forward in a cautious and conservative manner. In order to preserve the Company's financial position Crew is committed to maintain or reduce debt levels by spending within funds from operations and consider the disposition of non-core assets in order to focus its capital on the Company's three resource plays.

In this regard, the Company has reduced its previously announced budgeted capital expenditure program to $80 million for 2009 from the previously announced $120 million. This amount includes the completion of the Company's planned natural gas processing facility, the drilling of wells at Septimus and Portage in northeast British Columbia and Strachan and Wapiti in Alberta. It also includes the completion and tie-in of several wells in Alberta and British Columbia that were drilled in 2008 as well as maintenance capital. As a result of the reduction in the planned capital expenditures for the year, the Company has reduced its production guidance to average approximately 14,500 boe per day from the previously announced guidance of 15,500 boe per day. This updated guidance assumes the three week turnaround of the Fort Nelson natural gas processing facility which will affect approximately 970 boe per day of Crew's production in June but represents an increase in year over year average production growth of 25% and a 9% year over year increase in per share production growth.

Over the past few months the Company has entered into the previously noted derivative contracts to reduce the effect of falling commodity prices, a strengthening Canadian dollar and an increase in interest rates from their current levels on the Company. Crew will continue to monitor these markets and if the opportunity arises will look to enter additional contracts in order to protect the Company's future funds from operations.

ADDITIONAL DISCLOSURES

Risk Assessment

There are a number of risks facing participants in the Canadian oil and gas industry. Some risks are common to all businesses while others are specific to the Company. The following are a number of identifiable business risks faced by Crew which will evolve and additional risks will emerge periodically. The risks shown are those identified by management at the date of completion of this report and may not describe all of the risks faced by the Company.

Global Financial Crisis

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

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

Substantial Capital Requirements

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

Third Party Credit Risk

The Company may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner.

Quarterly Analysis



The following table summarizes the Company's key quarterly financial
results in 2008 and 2007:

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

Total daily production (boe/d) 14,869 11,505 9,445 10,614
Average wellhead price ($/boe) 42.99 61.74 70.18 53.20
Petroleum and natural gas sales 58,806 65,345 60,316 51,389
Cash provided by operations 25,700 36,208 31,908 29,540
Funds from operations 29,646 35,004 34,102 29,038
Per share - basic 0.42 0.54 0.60 0.54
- diluted 0.42 0.54 0.58 0.54
Net income (loss) (74,853) 15,178 5,415 941
Per share - basic (1.05) 0.24 0.09 0.02
- diluted (1.05) 0.23 0.09 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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

Total daily production (boe/d) 9,641 9,268 8,967 6,869
Average wellhead price ($/boe) 43.90 39.16 47.43 47.61
Petroleum and natural gas sales 38,942 33,390 38,703 29,431
Cash provided by operations 11,882 23,035 24,467 15,016
Funds from operations 22,390 21,171 20,885 16,987
Per share - basic 0.43 0.45 0.46 0.41
- diluted 0.43 0.44 0.46 0.41
Net income (loss) 6,889 (449) 1,351 1,319
Per share - basic 0.13 (0.01) 0.03 0.03
- diluted 0.13 (0.01) 0.03 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Crew's petroleum and natural gas sales, cash provided by operations, funds from operations and net income are all impacted by production levels and commodity pricing. These performance measures have all fluctuated throughout 2007 and 2008 despite increasing production as a result of volatile oil and natural gas prices combined with the increased cost of the Company's operations.



The following table summarizes Crew's key financial results over the past
three years:

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

($ thousands, except Year ended Year ended Year ended
per share amounts) Dec. 31, 2008 Dec. 31, 2007 Dec. 31, 2006
----------------------------------------------------------------------------

Petroleum and natural gas sales 235,856 140,466 92,813

Cash provided by operations 123,356 74,400 57,455
Funds from operations 127,790 81,433 56,658
Per share - basic 2.08 1.75 1.62
- diluted 2.06 1.74 1.59

Net income (loss) (53,319) 9,110 10,776
Per share - basic (0.87) 0.20 0.31
- diluted (0.87) 0.19 0.30

Daily production (boe/d) 11,617 8,696 5,695
Crew average sales price ($/boe) 55.47 44.45 44.65

Total assets 1,045,510 602,193 375,281
Working capital deficiency 31,822 14,643 17,714
Bank loan 223,628 95,028 41,157
Total other long-term liabilities 152,679 98,472 50,037
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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.

- Production in the second quarter of 2008 was impacted by a scheduled third party facility shutdown which disrupted approximately 1,400 boe per day of production for three weeks in June. Production in the second quarter was also impacted by several other non-scheduled facility outages.

- In August, 2008, the Company acquired Gentry Resources Inc. with approximately 4,000 boe per day of production at closing.

- 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.

- Production in the third and fourth quarter of 2007 was reduced by significant facility outages at Sierra in northeastern British Columbia and Edson and Ferrier, Alberta.

- Revenue and royalties are significantly impacted by underlying commodity prices. The Company utilizes a limited amount of derivative contracts and forward sales contracts to reduce the exposure to commodity price fluctuations.

- Throughout 2007 and 2008, the Company's operating costs, general and administrative 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.

- During the quarter ended September 30, 2007 the Company's funds from operations and net income were positively impacted by the one time receipt of Alberta deep well royalty holiday credits and 2006 Alberta gas cost allowance adjustments totalling $4.0 million.

- In the fourth quarter of 2008, Crew performed an impairment test on its goodwill and determined that its carrying value exceeded its fair value and therefore an impairment charge of $69.1 million was required.

- During the first three quarters of 2008, the Company experienced volatility in its net income as a result of unrealized gains and losses on commodity derivative contracts held for risk management purposes.

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


Dated as of March 9, 2009

Cautionary Statements

Unaudited financial information

Certain financial and operating information included in this press release for the quarter and year ended December 31, 2008, such as finding and development costs, production information, recycle ratios, operating netbacks and net asset value, are based on estimated unaudited financial results for the quarter and year then ended, and are subject to the same limitations as discussed under Forward Looking Information set out below. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2008 and changes could be material.

Forward-looking information and statements

This news release contains certain forward-looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the forgoing, this news release contains forward-looking information and statements pertaining to the following: the volumes and estimated value of Crew's oil and gas reserves; the life of Crew's reserves; resource estimates; the volume and product mix of Crew's oil and gas production; future oil and natural gas prices and Crew's commodity risk management programs; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition and development activities and related capital expenditures; the number of wells to be drilled and completed; the amount and timing of capital projects; operating costs; the total future capital associated with development of reserves and resources; and forecast reductions in operating expenses.

The recovery, reserve and resources estimates of Crew's reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves or resources with be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Crew which have been used to develop such statements and information but which may prove to be incorrect. Although Crew believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Crew can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which Crew operates; the timely receipt of any required regulatory approvals; the ability of Crew to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Crew has an interest in to operate the field in a safe, efficient and effective manner; the ability of Crew to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Crew to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Crew operates; and the ability of Crew to successfully market its oil and natural gas products.

The forward-looking information and statements included in this news release are not guarantees of future performance and should not be unduly relied upon. Such information and statements; including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of Crew's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Crew or by third party operators of Crew's properties, increased debt levels or debt service requirements; inaccurate estimation of Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of inadequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Crew's public disclosure documents, (including, without limitation, those risks identified in this news release and Crew's Annual Information Form).

The forward-looking information and statements contained in this news release speak only as of the date of this news release, and Crew does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

BOE equivalent

Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Discovered Petroleum Initially in Place

This press release contains references to estimates of gas classified as Discovered Petroleum initially in Place (DPIP) in the Company's Septimus area in British Columbia which are not, and should not be confused with oil and gas reserves. "Discovered Petroleum Initially in Place" is defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of hydrocarbons that are estimated, as of a given date, to be contained in known accumulations. DPIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources. There is no certainty that it will be commercially viable or technically feasible to produce any portion of this discovered petroleum initially in place except to the extent identified as proved or probable reserves. Resources do not constitute, and should not be confused with, reserves.

There are a number of assumptions associated with the development of the Company's lands at Septimus relating to performance from new and existing wells, future drilling programs, the lack of infrastructure, well density per section, recovery factors and development necessarily involves known and unknown risks and uncertainties, including those risks identified in this press release.

Crew is a junior 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 periods and years ended December 31, 2008 and 2007 are attached.



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


----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2008 2007
----------------------------------------------------------------------------

Assets

Current Assets:
Accounts receivable $ 42,800 $ 28,588
Fair value of financial instruments (note 10) 1,255 -
Future income taxes (note 12) 15 -
----------------------------------------------------------------------------
44,070 28,588

Property, plant and equipment (note 4) 1,001,440 552,805

Goodwill (note 5) - 20,800
----------------------------------------------------------------------------
$ 1,045,510 $ 602,193
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Liabilities and Shareholders' Equity

Current Liabilities:
Accounts payable and accrued liabilities $ 74,622 $ 43,231
Fair value of financial instruments (note 10) - 423
Current portion of other long-term
obligations (note 7) 1,313 1,313
----------------------------------------------------------------------------
75,935 44,967

Bank loan (note 6) 223,628 95,028

Other long-term obligations (note 7) 1,446 2,759

Asset retirement obligations (note 8) 34,941 18,668

Future income taxes (note 12) 116,292 77,045

Shareholders' Equity
Share capital (note 9) 575,191 298,129
Contributed surplus (note 9) 16,356 10,557
Retained earnings 1,721 55,040
----------------------------------------------------------------------------
593,268 363,726
Commitments (note 14)
----------------------------------------------------------------------------
$ 1,045,510 $ 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
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
----------------------------------------------------------------------------

Revenue

Petroleum and natural gas
sales $ 58,806 $ 38,942 $235,856 $140,466
Royalties (12,035) (6,929) (49,961) (23,749)
Gain (loss) on financial
instruments (note 10) 2,777 (408) 1,933 588
Other income - 210 268 210
----------------------------------------------------------------------------
49,548 31,815 188,096 117,515

Expenses

Operating 13,952 5,634 37,520 19,763
Transportation 2,607 1,779 8,924 6,603
General and administrative 1,242 970 4,169 3,331
Interest 1,970 1,882 7,085 6,808
Stock-based compensation 589 758 3,332 2,662
Depletion, depreciation
and accretion 35,329 20,489 104,866 75,427
Write-down of goodwill
(note 5) 69,071 - 69,071 -
----------------------------------------------------------------------------
124,760 31,512 234,967 114,594

----------------------------------------------------------------------------
Income (loss) before
income taxes (75,212) 303 (46,871) 2,921

Future income taxes
(reduction) (note 12) (359) (6,586) 6,448 (6,189)
----------------------------------------------------------------------------

Net income (loss) and
comprehensive income (loss) (74,853) 6,889 (53,319) 9,110

Retained earnings,
beginning of period 76,574 48,151 55,040 45,930

----------------------------------------------------------------------------
Retained earnings, end of
period $ 1,721 $ 55,040 $ 1,721 $ 55,040
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income (loss) per
share (note 9(e))
Basic $ (1.05) $ 0.13 $ (0.87) $ 0.20
Diluted $ (1.05) $ 0.13 $ (0.87) $ 0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


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

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
----------------------------------------------------------------------------

Cash provided by (used in):

Operating activities:
Net income (loss) $ (74,853) $ 6,889 $(53,319) $ 9,110
Items not involving cash:
Depletion, depreciation and
accretion 35,329 20,489 104,866 75,427
Write-down of goodwill (note 5) 69,071 - 69,071 -
Stock-based compensation 589 758 3,332 2,662
Future income taxes
(reduction) (359) (6,586) 6,448 (6,189)
Unrealized (gain) loss on
financial instruments (131) 840 (2,608) 423
Transportation liability
charge (note 7) (328) (313) (1,313) (784)
Asset retirement expenditures (152) (205) (775) (237)
Change in non-cash working
capital (note 13) (3,466) (9,990) (2,346) (6,012)
----------------------------------------------------------------------------
25,700 11,882 123,356 74,400

Financing activities:
Increase (decrease) in bank
loan 44,578 (44,363) 60,396 54,217
Issue of common shares - 54,606 69,846 113,880
Repurchase of common shares (514) - (514) -
Share issue costs - (2,988) (3,654) (6,315)
----------------------------------------------------------------------------
44,064 7,255 126,074 161,782

Investing activities:
Exploration and development (53,612) (31,033) (191,677) (102,092)
Property acquisitions, net of
dispositions 245 266 (70,414) 315
Business acquisitions (note 3) - 405 (1,500) (136,920)
Change in non-cash working
capital (note 13) (16,397) 11,225 14,161 2,515
----------------------------------------------------------------------------
(69,764) (19,137) (249,430) (236,182)

----------------------------------------------------------------------------
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 months and years ended December 31, 2008 and 2007
(Unaudited)
(Tabular amounts in thousands)


1. Significant accounting policies:

The consolidated financial statements of Crew Energy Inc. ("Company") have been prepared by management in accordance with Canadian generally accepted accounting principles. Since the determination of certain assets, liabilities, revenues and expenses is dependent upon future events, the preparation of these financial statements requires the use of estimates and assumptions, which have been made with careful judgement. Specifically, the amounts recorded for depletion and depreciation of property, plant and equipment and the provision for asset retirement obligations and abandonment costs are based on estimates. The ceiling test is based on estimates of reserves, future production rates, future petroleum and natural gas prices, future costs and other relevant assumptions. The amounts for stock-based compensation are based on estimates of risk-free rates, expected option life and volatility. Future incomes taxes are based on estimates as to the timing of the reversal of temporary differences and tax rates currently substantively enacted. The fair value of derivative contracts are based on the discounted value of the market for future commodity prices, interest rates and the exchange rate between United States and Canadian dollars. By their nature, these estimates and amounts are subject to measurement uncertainty and the effect on the financial statements of such changes in such estimates in future periods could be significant. In the opinion of management, these financial statements have been properly prepared in accordance with Canadian generally accepted accounting principles within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

(a) Principles of consolidation:

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Crew Resources Inc., Gentry Resources Ltd. ("Gentry"), and a partnership, Crew Energy Partnership. On January 1, 2009, Gentry was amalgamated into Crew Energy Inc. All inter-entity balances and transactions have been eliminated.

(b) Cash and cash equivalents:

Cash and cash equivalents include monies on deposit and highly liquid short-term investments having a maturity date of not more than 90 days.

(c) Petroleum and natural gas properties:

The Company follows the full cost method of accounting for petroleum and natural gas properties, whereby all costs of exploring for and developing petroleum and natural gas properties and related reserves are capitalized. Capitalized costs include land acquisition costs, geological and geophysical expenses, cost of drilling both productive and non-productive wells, production facilities, the fair value of asset retirement obligations and related overhead expenses.

Capitalized costs, excluding costs relating to unproved properties, are depleted using the unit-of-production method based on estimated proved reserves of petroleum and natural gas before royalties determined using forecast product prices and as determined by independent petroleum engineers. For purposes of the depletion calculation, natural gas reserves and production are converted to equivalent volumes of crude oil based on relative energy content of six thousand cubic feet of gas to one barrel of oil. Proceeds from the sale of petroleum and natural gas properties are applied against capitalized costs, with no gain or loss recognized unless such a sale would alter depletion by more than 20%.

The cost of acquiring unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically for impairment. When proved reserves are assigned or the property is considered impaired the costs of the property or the amount of impairment is added to the costs subject to depletion.

Petroleum and natural gas assets are evaluated in each reporting period (the "ceiling test") to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. The carrying amounts are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The cash flows are estimated using forecast product prices and costs and are discounted using a risk-free interest rate.

(d) Goodwill

Goodwill is the residual amount that results when the purchase price of a business exceeds the fair value of the net identifiable assets and liabilities acquired. Goodwill is stated at cost and is not amortized. The goodwill balance is assessed for impairment each year end or more frequently if events or changes in circumstances indicate that the asset may be impaired. The test for impairment is conducted by comparing the book value to the fair value of the reporting entity. Impairment is charged to income in the period it occurs.

(e) Interest in joint operations:

A portion of the Company's petroleum and natural gas exploration and development activity is conducted jointly with others and, accordingly, the financial statements reflect only the Company's proportionate interest in such activities.

(f) Asset retirement obligations:

The fair value of the liability for the Company's asset retirement obligation is recorded in the period in which it is incurred, discounted to its present value using Crew's credit adjusted risk-free interest rate and the corresponding amount is recognized by increasing the carrying amount of the petroleum and natural gas properties. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related petroleum and natural gas properties. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would result in an increase or decrease to the asset retirement obligation. Actual costs incurred upon settlement of the asset retirement obligation are charged against the asset retirement obligation.

(g) Revenue recognition:

Revenue from the sale of petroleum and natural gas are recorded when title passes to a third party.

(h) Financial instruments:

A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument to another entity. Upon initial recognition all financial instruments, including all derivatives, are recognized on the balance sheet at fair value. Subsequent measurement is then based on the financial instruments being classified into one of five categories: held for trading, held to maturity, loans and receivables, available for sale and other liabilities. The Company has designated its cash and cash equivalents as held for trading which are measured at fair value.

Accounts receivable are classified as loans and receivables which are measured at amortized cost. Accounts payable and accrued liabilities and the bank loan are classified as other liabilities which are measured at amortized cost, which is determined using the effective interest method.

The Company will assess at each reporting period whether its financial assets are impaired.

The Company is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments may be used by the Company to reduce its exposure to fluctuations in commodity prices, foreign exchange rates, and interest rates. The Company does not use these derivative instruments for trading or speculative purposes. The Company considers all of these transactions to be economic hedges, however, the majority of the Company's contracts do not qualify or have not been designated as hedges for accounting purposes.

As a result, all derivative contracts are classified as held for trading and are recorded on the balance sheet at fair value, with changes in the fair value recognized in net income, unless specific hedge criteria are met. The fair values of these derivative instruments are based on an estimate of the amounts that would have been received or paid to settle these instruments prior to maturity given future market prices and other relevant factors. Proceeds and costs realized from holding the derivative contracts are recognized in net income at the time each transaction under a contract is settled.

The Company measures and recognizes embedded derivatives separately from the host contracts when the economic characteristics and risks of the embedded derivative are not closely related to those of the host contract, when it meets the definition of a derivative and when the entire contract is not measured at fair value. Embedded derivatives are recorded at fair value.

The Company immediately expenses all transaction costs incurred in relation to the acquisition of a financial asset or liability. The bank loan is presented net of deferred interest payments, with interest recognized in net income on an effective interest basis.

The Company applies trade-date accounting for the recognition of a purchase or sale of cash equivalents and derivative contracts.

(i) Flow through shares:

Flow through shares are issued at a fixed price and the proceeds are used to fund qualifying exploration expenditures within a defined period. The expenditures funded by flow through arrangements are renounced to investors in accordance with income tax legislation. Share capital is reduced and future income tax liability is increased by the total estimated future income tax costs of the renounced income tax deductions in the period of renouncement.

(j) Per share amounts:

Basic per share amounts are calculated using the weighted average number of shares outstanding during the period. Diluted per share amounts are calculated based on the treasury-stock method, which assumes that any proceeds obtained on exercise of options, warrants and performance shares would be used to purchase common shares at the average market price. The weighted average number of shares outstanding is then adjusted by the net change.

(k) Stock-based compensation plans:

The Company accounts for its stock-based compensation program, which includes stock options, using the fair value method. Under this method compensation expense related to these programs is recorded in net income over the vesting period with a corresponding increase in contributed surplus. Consideration received on the exercise of stock options together with the amount previously recognized in contributed surplus is credited to share capital.

(l) Income taxes:

The Company uses the asset and liability method of accounting for future income taxes. The future income tax asset or liability is calculated assuming the financial assets and liabilities will be settled at their carrying amount. This amount is compared to the income tax assets and the difference is multiplied by the substantively enacted income tax rate when the temporary differences are expected to reverse.

(m) Comparative amounts:

Certain comparative amounts have been reclassified to conform with presentation adopted in the current year.

2. Changes 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 10.

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 11.

Future Accounting Pronouncements

Goodwill and intangible assets

In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets. Effective for fiscal years beginning on or after October 1, 2008, this section provides guidance on the recognition, measurement, presentation and disclosure for goodwill and intangible assets, other than the initial recognition of goodwill or intangible assets acquired in a business combination. Retroactive application to prior-period financial statements will be required. The Company is still assessing the impact of this new standard on its financial statements.

Business combinations

In January 2009, the CICA issued Section 1582, Business Combinations. This section is effective January 1, 2011 and applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after January 1, 2011 for the Company. Early adoption is permitted. This section replaces Section 1581, Business Combination and harmonizes the Canadian standards with IFRS.

International financial reporting standards

In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the changeover to IFRS from Canadian GAAP will be required for publicly accountable enterprises for interim and annual financial statements effective for fiscal years beginning on or after January 1, 2011, including comparatives for 2010.

The International Accounting Standards Board ("IASB") has also issued an exposure draft relating to certain amendments and exemptions to IFRS 1. It is anticipated that this exposure draft will not result in an amended IFRS 1 standard until late 2009.

The amendment, if implemented, will permit the Company to apply IFRS prospectively by utilizing its current reserves at the transition date to allocate the Company's full cost pool, with the provision that a ceiling test, under IFRS standards, be conducted at the transition date.

Although the amended IFRS 1 standard would provide relief, the changeover to IFRS represents a significant change in accounting standards and the transition from current Canadian GAAP to IFRS will be a significant undertaking that may materially affect the Company's reported financial position and reported results of operations.

In response, the Company has completed its high-level IFRS changeover plan and established a preliminary timeline for the execution and completion of the conversion project. The changeover plan was determined following a preliminary assessment of the differences between Canadian GAAP and IFRS and the potential effects of IFRS to accounting and reporting processes, information systems, business processes and external disclosures. This assessment has provided insight into what are anticipated to be the most significant areas of difference applicable to the Company.

During the next phase of the project, scheduled to take place during 2009, the Company will perform an in-depth review of the significant areas of difference, identified during the preliminary assessment, in order to identify all specific Canadian GAAP and IFRS differences and select ongoing IFRS policies. Key areas addressed will also be reviewed to determine any information technology issues, the impact on internal controls over financial reporting and the impact on business activities including the effect, if any, on covenants and compensation arrangements. External advisors have been retained and will assist management with the project on an as needed basis. Staff training programs will commence in 2009 and be ongoing as the project unfolds.

The Company will also continue to monitor standards development as issued by the IASB and the AcSB as well as regulatory developments as issued by the Canadian Securities Administrators, which may affect the timing, nature or disclosure of its adoption of IFRS.

3. Business acquisitions:

On August 22, 2008, Crew acquired all of the issued and outstanding shares of 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:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 48,271
Working capital deficiency (5,364)
Fair value of financial instruments (930)
Bank loan (68,204)
Asset retirement obligations (13,854)
Future income taxes (27,436)
----------------------------------------------------------------------------
$ 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.

In May, 2007, Crew acquired all of the issued and outstanding shares of a private oil and gas company with producing oil and natural gas properties in northeast British Columbia and central Alberta. Total consideration paid for the acquisition was approximately $137.1 million which was financed through a financing and a credit facility. The operating results of the acquired company were included in the accounts of Crew from May 3, 2007.



The acquisition has been accounted for using the purchase method of
accounting as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------

Consideration
Cash $ 136,775
Transaction costs 276
----------------------------------------------------------------------------
$ 137,051
Net assets received at fair value
Income tax receivable 6,159
Property and equipment 182,397
Goodwill 6,242
Working capital deficiency (includes cash of $131) (6,108)
Excess transportation obligation (note 7) (4,856)
Asset retirement obligations (6,646)
Future income taxes (40,137)
----------------------------------------------------------------------------
$ 137,051
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The income tax receivable relates to non-capital loss carrybacks from the acquired company's May 3, 2007 and December 31, 2006 tax returns. These amounts were pledged to the vendor upon receipt by the Company. As at December 31, 2008, the Company had received the full $6.159 million and forwarded it to the vendor. The income tax receivable is offset by an equivalent amount included in accounts payable.



4. Property, plant and equipment:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
December 31, 2008 Cost depreciation value
----------------------------------------------------------------------------

Petroleum and natural gas
properties and equipment $1,249,859 $ 248,419 $1,001,440
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 December 31, 2008 of $170,453,000 (2007 - $40,359,000) was excluded from the depletion calculation. Estimated future development costs associated with the development of the Company's proved reserves of $108,258,000 (2007 - $31,057,000) have been included in the depletion calculation and estimated salvage values of $38,514,000 (2007 - $21,231,000) 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:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, December 31,
2008 2007
----------------------------------------------------------------------------

General and administrative expense $ 4,169 $ 3,331
Stock-based compensation expense, including
future income taxes 4,485 3,624
----------------------------------------------------------------------------
$ 8,654 $ 6,955
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Crew performed a ceiling test as at December 31, 2008. Based on the calculation, the carrying values of the Company's property, plant and equipment are less than the sum of the undiscounted cash flows of the Company's proved reserves based on the following benchmark and Company prices.



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----------------------------------------------------------------------------
WTI F/X Edmonton Company Company
Oil Rate Oil Liquids AECO Gas Gas
Years ($US/Bbl) ($Cdn/$US) ($/bbl) ($/bbl) ($/mmbtu) ($/mcf)
----------------------------------------------------------------------------

2009 $ 57.50 0.825 $ 68.61 $46.44 $7.58 $ 7.53
2010 $ 68.00 0.850 $ 78.94 $56.04 $7.94 $ 8.00
2011 $ 74.00 0.875 $ 83.54 $59.60 $8.34 $ 8.43
2012 $ 85.00 0.925 $ 90.92 $64.19 $8.70 $ 8.80
2013 $ 92.01 0.950 $ 95.91 $67.32 $8.95 $ 9.13
2014 $ 93.85 0.950 $ 97.84 $68.42 $9.14 $ 9.30
2015 $ 95.73 0.950 $ 99.82 $69.76 $9.34 $ 9.51
2016 $ 97.64 0.950 $101.83 $71.15 $9.54 $ 9.73
2017 $ 99.59 0.950 $103.89 $72.72 $9.75 $ 9.96
2018 $101.59 0.950 $105.99 $74.75 $9.95 $10.17
Annual escalation thereafter +2.0%/yr.
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5. Goodwill:

The Company reviewed the valuation of goodwill as of December 31, 2008 and determined that the fair value of the reporting entity had declined. Based upon this review, an impairment of goodwill of $69.1 million (2007 - nil) has been recorded as a non-cash charge to net income as of December 31, 2008. There has been no impairment to the value of Crew's petroleum and natural gas assets during 2008.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2008 2007
----------------------------------------------------------------------------

Balance, beginning of year $ 20,800 $ 14,558
Business acquisitions (note 3) 48,271 6,242
Goodwill impairment recognized (69,071) -
----------------------------------------------------------------------------
Balance, end of year $ - $ 20,800
----------------------------------------------------------------------------
----------------------------------------------------------------------------


6. 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. The available lending limits of the Facility are reviewed semi-annually and are based on the bank syndicate's interpretation of the Company's reserves and future commodity prices. There can be no assurance that the amount of the available Facility will not be adjusted at the next scheduled review on or before June 15, 2009.

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 December 31, 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. Borrowing margins and fees will be reviewed as part of the bank syndicate annual renewal prior to June 15, 2009. The facility is secured by a first floating charge debenture over the Company's consolidated assets. At December 31, 2008, the Company had issued letters of credit totaling $5.4 million of which $5.0 million expires by March 31, 2009. The effective interest rate on the Company's borrowings under its bank facility for the period ended December 31, 2008 was 4.9% (2007 - 6.4%).

7. Other long-term obligations:

As part of the May 3, 2007 private company acquisition (note 3), the Company 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 twelve months ended December 31, 2008 was $0.3 million and $1.3 million, respectively (2007 - $0.3 million and $0.8 million).

8. 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 obligations as at December 31, 2008 to be $34,941,000 (2007 - $18,668,000) based on a total future liability of $67,588,000 (2007 - $35,166,000). These payments are expected to be made over the next 30 years. An 8% to 10% (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:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, December 31,
2008 2007
----------------------------------------------------------------------------

Carrying amount, beginning of year $ 18,668 $ 10,485
Liabilities incurred 1,228 845
Liabilities acquired (note 3) 13,927 6,646
Accretion expense 1,893 929
Liabilities settled (775) (237)
----------------------------------------------------------------------------
Carrying amount, end of year $ 34,941 $ 18,668
----------------------------------------------------------------------------
----------------------------------------------------------------------------


9. Share capital:

(a) Authorized:

Unlimited number of Common Shares

1,881,000 Class C non-voting performance shares ("performance shares")



(b) Common Shares issued:

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

Common Shares, December 31, 2006 41,440 $ 192,810
Public offering issued for cash 9,932 93,725
Public offering of flow through shares issued
for cash 1,860 20,000
Exercise of Class C performance shares 315 4
Exercise of stock options 30 155
Stock-based compensation - 333
Share issue costs, net of income taxes of $1,818 - (4,497)
Flow through shares income tax adjustment on 2006
issuance - (4,401)
----------------------------------------------------------------------------
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
Shares repurchased under normal course issuer bid (110) (890)
Stock-based compensation - 1,241
Share issue costs, net of future income taxes
of $1,005 - (2,649)
Flow through shares income tax adjustment on 2007
issuance - (5,200)
----------------------------------------------------------------------------
Common Shares, December 31, 2008 71,084 $ 575,191
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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 ("NCIB") 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. During the period and year ended December 31, 2008 the Company repurchased and cancelled 110,000 Common Shares at a net cost of $0.5 million. The average carrying value of the Common Shares repurchased of $0.9 million was charged to share capital with the excess of $0.4 million included in contributed surplus.

In conjunction with the Company's August 22, 2008 acquisition (note 3), the Company issued 12,276,749 Common Shares to Gentry shareholders in exchange for 100% of the Gentry common shares.

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 December 31, 2008, the Company had renounced all required income tax deductions and had incurred all qualifying expenditures under this flow through offering.

In conjunction with the Company's private company acquisition on May 3, 2007 (note 3), Crew issued 5,750,000 Common Shares at $10.30 per share for aggregate gross proceeds of $59.2 million ($56 million net of issue costs).



(c) Contributed Surplus:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------

Contributed surplus, December 31, 2006 $ 5,566
Stock-based compensation 5,324
Conversion of Class C performance shares and stock options (333)
----------------------------------------------------------------------------
Contributed surplus, December 31, 2007 $ 10,557
Stock-based compensation 6,664
Excess of Common Share redemption amount over Common
Share carrying amount 376
Exercise of stock options (1,241)
----------------------------------------------------------------------------
Contributed surplus, December 31, 2008 $ 16,356
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(d) Stock-based compensation:

The Company measures compensation costs associated with stock-based compensation using the fair market value method and 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: risk free interest rate 4.05% (2007 - 4.20%), 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 2008 the Company recorded $6,664,000, (2007 - $5,324,000) of stock-based compensation expense related to the stock options, of which $3,332,000 (2007 - $2,662,000) 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 $1,153,000 (2007 - $962,000) associated with the current year's capitalized stock-based compensation has been recorded.

(i) Performance shares

On September 1, 2003 the Company issued 1,881,000 performance shares to employees, officers and directors at a price of $0.01 per share. Each performance share was convertible into a fraction of a Common Share over a three-year period with the conversion rights expiring on September 1, 2007. On conversion, each performance share converted at the rate determined by subtracting $1.65 from the current market price of the Company's Common Shares and dividing the result by the current market price of the Company's Common Shares. The fair value of the performance shares at the date of issue, as calculated by the Black-Scholes method, was $0.67 per share. All remaining performance shares were converted in 2007 and cannot be re-issued.



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

Class C, performance shares, December 31, 2006 402 $ 4
Converted to Common Shares during 2007 (402) (4)
----------------------------------------------------------------------------
Class C, performance shares, December 31, 2007
and 2008 - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(ii) Stock options

The Company has a floating stock option plan in which the Company may grant options to its employees, directors and consultants for up to 10% of its outstanding Common Shares. Under this plan, the exercise price of each option equals the market price of the Company's Common Shares on the date of grant. All granted options vest over a three-year period and have a four-year term to expiry. Stock options are granted periodically throughout the year. The fair value of the stock options granted during the year as calculated by the Black-Scholes method was $3.66 per option (2007 - $3.99).



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
average
exercise
Number of options price
----------------------------------------------------------------------------

Balance December 31, 2006 2,019 $ 14.97
Granted 2,402 $ 10.02
Exercised (30) $ 5.18
Forfeited (477) $ 13.41
Cancelled (643) $ 16.22
----------------------------------------------------------------------------
Balance December 31, 2007 3,271 $ 11.41
Granted 2,664 $ 9.19
Exercised (340) $ 9.12
Forfeited (875) $ 10.43
Cancelled (444) $ 17.75
----------------------------------------------------------------------------
Balance December 31, 2008 4,276 $ 9.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The following table summarizes information about the stock options
outstanding at December 31, 2008:

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

Weighted Weighted Exercisable Weighted
Range of Outstanding at average average at average
exercise December 31, remaining exercise December 31, exercise
prices 2008 life price 2008 price
----------------------------------------------------------------------------
(years)

$ 3.50 to $6.50 8 3.9 $ 4.85 - -
$ 6.51 to $9.50 1,865 3.0 $ 7.45 82 $ 8.02
$ 9.51 to $12.50 1,807 2.3 $10.48 506 $10.65
$ 12.51 to $18.70 596 3.5 $14.83 - -
----------------------------------------------------------------------------
4,276 2.8 $9.76 588 $10.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(e) Per share amounts:

Per share amounts have been calculated on the weighted average number of shares outstanding. The weighted average shares outstanding for the three month period ended December 31, 2008 was 71,145,000 (2007 - 51,929,000) and for the year ended December 31, 2008, the weighted average number of shares outstanding was 61,580,000 (2007 - 46,483,000).

In computing diluted earnings per share for the three month period ended December 31, 2008 nil (2007 - 379,000) shares were added to the weighted average number of Common Shares outstanding to account for the dilution of stock options and for the year ended December 31, 2008, nil (379,000) shares were added to the weighted average Common Shares outstanding to account for the dilution of the stock options. There were 4,276,000 (2007 - 2,892,000) stock options that were not included in the diluted earnings per share calculation because they were anti-dilutive.

10. 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 can cash call for major projects and does have the ability in most cases to withhold production from joint venture partners in the event of non-payment.

Derivative assets can consist of commodity, interest rate and foreign exchange contracts used to manage the Company's exposure to fluctuations in commodity prices, interest rates and the exchange rate between United States and Canadian dollars. The Company manages the credit risk exposure related to derivative assets by selecting investment grade counterparties and by not entering into contracts for trading or speculative purposes.

The carrying amount of accounts receivable and derivatives represents the maximum credit exposure. As at December 31, 2008 the Company's receivables consisted of $18.4 (2007 - $16.2) million of receivables from petroleum and natural gas marketers which has subsequently been collected, $12.4 (2007 - $6.5) million from joint venture partners of which $4.6 million has been subsequently collected, and $12.0 (2007 - $5.9) million of Crown deposits, prepaids and other accounts receivable. 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 December 31, 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 6, 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 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 December 31, 2008 were as follows:



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volume Floor Ceiling Fair
(gj/day) Term Index (Cdn $/gj) (Cdn $/gj) Value
----------------------------------------------------------------------------
AECO C -
Monthly
AECO 2,500 January 1, 2009 - Index less $6.50 $8.30 $ 632
December 31, 2009 $0.09
AECO C -
AECO 2,500 January 1, 2009 - Monthly $6.60 $8.50 623
December 31, 2009 Index
----------------------------------------------------------------------------
$ 1,255
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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
months months Year Year
ended ended ended ended
Dec 31, Dec 31, Dec 31, Dec 31,
2008 2007 2008 2007
----------------------------------------------------------------------------

Realized gain (loss) on financial
instruments $ 2,646 $ 432 $ (675) $ 1,011
Unrealized gain (loss) on financial
instruments 131 (840) 2,608 (423)
----------------------------------------------------------------------------
$ 2,777 $ (408) $1,933 $ 588
----------------------------------------------------------------------------
----------------------------------------------------------------------------


As at December 31, 2008, a $0.10 change to the price per thousand cubic feet of natural gas on the costless collars would have had a $0.1 million impact on net income.



Subsequent to December 31, 2008, the Company entered into the following
financial derivative contracts:

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

Volume Put Call
(gj/day) Term Index (Cdn $/gj) (Cdn $/gj)
----------------------------------------------------------------------------

AECO 15,000 April 1, 2009 -
October 31, 2009 AECO C - Monthly Index $6.00

AECO 5,000 January 1, 2010 -
December 31, 2010 AECO C - Monthly Index $8.00

AECO 10,000 January 1, 2010 -
December 31, 2010 AECO C - Monthly Index $7.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------


(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 year ended December 31, 2008. Subsequent to December 31, 2008, the Company entered into contracts for US $4 million per month to fix the US dollar to Canadian dollar exchange rate at 1.24 for the period of February through December 2009.

(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 twelve months ended December 31, 2008, a 100 basis point change to the effective interest rate would have a $0.4 million and $0.8 million impact on net income, respectively (2007 - $0.2 million and $0.6 million). The sensitivity for 2008 is higher as compared to 2007 because of an increase in average outstanding bank debt in 2008 compared to 2007. The Company had no interest rate swaps or financial contracts in place as at or during the year ended December 31, 2008. Subsequent to December 31, 2008, the Company entered into contracts fixing the rate on $100 million of banker's acceptances for the period from February 10, 2009 to February 10, 2011 at a rate of 1.10 per cent which is subject to additional stamping fees ranging from 0.95 per cent to 1.75 per cent depending upon the debt to EBITDA ratio calculated at the Company's previous quarter end.

Fair value of financial instruments

The Company's financial instruments as at December 31, 2008 and 2007 include accounts receivable, derivative contracts, accounts payable and accrued liabilities, and bank debt. The fair value of accounts receivable and 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.

11. 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 debt levels 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 December 31, 2008, the Company's ratio of net debt to annualized funds from operations was 2.15 to 1 (2007 - 1.22 to 1). This amount has risen above the preferred range of the Company as a result of the dramatic decrease in commodity prices experienced in the second half of 2008. In order to maintain the integrity of the Company's financial position the Company plans to adjust its capital expenditure program to remain within funds from operations until commodity prices recover or an alternative form of financing is available as discussed below.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
2008 2007
----------------------------------------------------------------------------

Net debt:

Accounts receivable $ 42,800 $ 28,588
Accounts payable and accrued liabilities (74,622) (43,231)
----------------------------------------------------------------------------
Working capital deficiency $ (31,822) $ (14,643)
Bank loan (223,628) (95,028)
----------------------------------------------------------------------------
Net debt $ (255,450) $ (109,671)


Three months Three months
ended Dec. 31, ended Dec. 31,
2008 2007
----------------------------------------------------------------------------
Annualized funds from operations:

Cash provided by operating activities $ 25,700 $ 11,882
Asset retirement expenditures 152 205
Transportation liability charge 328 313
Change in non-cash working capital 3,466 9,990
----------------------------------------------------------------------------
Fourth quarter funds from operations 29,646 22,390

Annualized $ 118,584 $ 89,560

Net debt to annualized funds from operations 2.15 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 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 year ended December 31, 2008.

12. Income taxes:

(a) Future income tax expense:

The provision for income tax expense in the financial statements differs from the result, which would have been obtained by applying the combined federal and provincial income tax rate to the Company's income (loss) before income taxes. This difference results from the following items:



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

2008 2007
----------------------------------------------------------------------------
Income (loss) before income taxes $ (46,871) $ 2,921
----------------------------------------------------------------------------
Combined federal and provincial income tax rate 29.70% 32.33%

Computed "expected" income tax expense (reduction) $ (13,921) $ 944

Increase (decrease) in income taxes resulting from:
Non-deductible stock-based compensation 990 861
Non-deductible write-down of goodwill 20,514 -
Benefits relating to change in income tax rates (1,169) (8,019)
Other 34 25
----------------------------------------------------------------------------
Future income tax expense (reduction) $ 6,448 $ (6,189)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(b) Future income tax liability:

The components of the Company's future income tax liability are as follows:

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

2008 2007
----------------------------------------------------------------------------

Future income tax:
Property, plant and equipment $ 136,597 $ 84,877
Asset retirement obligations (9,062) (4,935)
Share issue costs (2,956) (1,458)
Non-capital loss (7,813) (154)
Other (489) (1,285)
----------------------------------------------------------------------------
Future income tax liability $ 116,277 $ 77,045
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The non-capital losses expire during the years 2026 to 2028, except for $1.2
million which expires in the year 2015.

13. Supplemental cash flow information:

----------------------------------------------------------------------------
----------------------------------------------------------------------------
2008 2007
----------------------------------------------------------------------------
Changes in non-cash working capital:
Accounts receivable $ 8,660 $ 4,633
Accounts payable and accrued liabilities 3,155 (8,130)
----------------------------------------------------------------------------
$ 11,815 $ (3,497)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Operating activities $ (2,346) $ (6,012)
Investing activities 14,161 2,515
----------------------------------------------------------------------------
$ 11,815 $ (3,497)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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

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

2008 2007
----------------------------------------------------------------------------
Interest $ 6,471 $ 7,509
----------------------------------------------------------------------------
----------------------------------------------------------------------------

14. Commitments:

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

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

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

Operating leases $ 2,722 $ 990 $ 990 $ 742
Capital commitments 11,500 11,500 - -
Firm transportation agreements 20,793 7,003 7,152 6,638
----------------------------------------------------------------------------
Total $ 35,015 $ 19,493 $ 8,142 $ 7,380
----------------------------------------------------------------------------
----------------------------------------------------------------------------


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