Crew Energy Issues 2011 Fourth Quarter and Annual Financial and Operating Results Reporting Significant Per Share Growth in Cash Flow, Production and Reserves

CALGARY, ALBERTA--(Marketwire - March 6, 2012) - Crew Energy Inc. (TSX:CR) of Calgary, Alberta ("Crew" or the "Company") is pleased to present its financial and operating results for the three month period and year ended December 31, 2011 and to announce the results of its independent reserve evaluation for the year ended December 31, 2011 as prepared by GLJ Petroleum Consultants Ltd. ("GLJ").


  • Funds from operations increased 136% over the fourth quarter of 2010 to $64.8 million and increased 20% over the third quarter of 2011;
  • Funds from operations per share increased 59% (53% debt adjusted) over the fourth quarter of 2010 and 20% over the third quarter of 2011;
  • Fourth quarter production increased 105% to 30,034 boe per day compared to the same period in 2010 and increased 9% over the third quarter of 2011;
  • Fourth quarter production per share increased 38% (33% debt adjusted) over the fourth quarter of 2010 and 9% per share over the third quarter of 2011;
  • Proved plus probable reserves increased 84% to 137.4 million boe;
  • Reserves per share increased 23% (20% debt adjusted) over 2010;
  • Proved plus probable oil and natural gas liquids reserves increased 90% to 54.9 million bbls;
  • Proved plus probable reserve replacement was 865% and 468% on proved reserves; and
  • Recycle ratio of 2.0x excluding future development capital and 1.4x including changes in future development capital.
($ thousands, except per share amounts)
  Three months ended
December 31, 2011
  Three months ended
December 31, 2010
  Year ended
December 31, 2011
  Year ended
December 31, 2010
Petroleum and natural gas sales   142,063   56,620   388,166   206,343  
Funds from operations (note 1)   64,841   27,449   172,103   98,206  
  Per share - basic   0.54   0.34   1.69   1.23  
    - diluted   0.54   0.34   1.67   1.20  
Net income (loss)   (148,529 ) (14,215 ) (130,162 ) 17,818  
  Per share - basic   (1.24 ) (0.18 ) (1.28 ) 0.22  
    - diluted   (1.24 ) (0.18 ) (1.28 ) 0.22  
Capital expenditures   108,854   60,361   375,874   245,626  
Property acquisitions (net of dispositions)   (13,203 ) 620   (25,492 ) (132,020 )
Net capital expenditures   95,651   60,981   350,382   113,606  
Capital Structure($ thousands)           As at
December 31, 2011
  As at
December 31, 2010
Working capital deficiency (note 2)           92,452   40,707  
Bank loan           230,676   138,700  
Net debt           323,128   179,407  
Bank facility           430,000   240,000  
Common Shares Outstanding (thousands)           119,993   80,368  


(1) Funds from operations is calculated as cash provided by operating activities, adding the change in non-cash working capital, decommissioning obligation expenditures, the transportation liability charge and acquisition costs. 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 International Financial Reporting Standards and therefore may not be comparable with the calculations of similar measures for other companies.

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

Operations Three months
December 31, 2011
  Three months
December 31, 2010
  Year ended
December 31, 2011
  Year ended
December 31, 2010
Daily production                
  Conventional oil (bbl/d) (note 1) 6,784   5,321   5,737   4,175  
  Heavy oil (bbl/d) 6,145   -   3,221   -  
  Natural gas liquids (bbl/d) 2,995   1,149   2,035   1,235  
  Natural gas (mcf/d) 84,657   49,104   68,756   49,672  
  Oil equivalent (boe/d @ 6:1) 30,034   14,654   22,452   13,689  
Average prices (note 2)                
  Conventional oil ($/bbl) 86.34   68.17   78.05   67.48  
  Heavy oil ($/bbl) 77.47   -   70.30   -  
  Natural gas liquids ($/bbl) 64.15   52.57   62.68   50.70  
  Natural gas ($/mcf) 3.43   3.92   3.81   4.45  
  Oil equivalent ($/boe) 51.41   42.00   47.37   41.30  
Netback ($/boe)                
  Operating netback (note 3) 26.03   23.55   23.61   22.86  
  Realized (gain)/loss on financial instruments -   (0.02 ) -   0.10  
  G&A 1.70   2.14   1.72   1.95  
  Interest on bank debt 0.87   1.06   0.88   1.16  
  Funds from operations 23.46   20.37   21.01   19.65  
Drilling Activity                
  Gross wells 37   21   158   80  
  Working interest wells 35.0   19.8   154.5   75.2  
  Success rate, net wells 97 % 95 % 99 % 99 %


(1) Includes light and medium oil as defined in NI 51-101 of the COGE Handbook.

(2) Average prices are before deduction of transportation costs and do not include hedging gains and losses.

(3) Operating netback equals petroleum and natural gas sales including realized hedging gains and losses on commodity contracts 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 International Financial Reporting Standards and therefore may not be comparable with the calculations of similar measures for other companies.

2011 Overview

Crew's past year was highlighted by the July 1st acquisition of Caltex Energy Inc. ("Caltex"). The Caltex acquisition was consistent with Crew's strategy to explore, exploit and acquire large hydrocarbon in place reservoirs. The transaction provided Crew with exposure to a significant heavy oil development in the Lloydminster area of Saskatchewan and liquids rich natural gas assets in the Greater Wapiti area of Alberta. The integration of the Caltex assets into Crew added 10,500 boe per day of new production that was 68% weighted towards liquids production and 41.0 mmboe of proved plus probable reserves that were 48% liquids weighted. The Caltex acquisition was funded through the issuance of 33.6 million Crew shares and the assumption of $66 million of Caltex net debt for a total cost of $568 million.

The acquisition of Caltex has significantly strengthened Crew's asset base by providing two additional platforms for growth with over 900 new potential drilling locations. The added liquids weighted production increased Crew's corporate netbacks from $21.14 per boe in the first half of 2011 to $24.53 per boe in the second half and provides free cash flow to help fund the development of Crew's premier oil development in the Princess area of Alberta and the liquids rich Montney natural gas play in northeast British Columbia.

Crew's 2011 production was enhanced by the Caltex acquisition along with added production from the Company's successful drilling programs at Princess and Wapiti, Alberta and at Septimus in northeast British Columbia. The Company's production averaged 22,452 boe per day (49% liquids) which is a 64% increase over 2010. Production per share averaged 220 boe per day per million shares which is a 28% increase over the 172 boe per day per million shares produced in 2010. First half 2011 production averaged 16,028 boe per day (43% liquids) or 191 boe per day per million shares outstanding. Second half production increased 80% over the first half to 28,771 boe per day (52% liquids) or a 26% increase to 240 boe per day per million shares outstanding.

Strong world oil prices opened the year benefiting from positive economic growth indicators out of the US and China. West Texas Intermediate ("WTI") oil prices averaged US$98.30 per bbl during the first half of the year ranging from US$92 per bbl in January to a peak of US $110 per bbl in April. First half optimism gave way to mid-year concerns over European sovereign debt. This concern led to considerable second half market volatility. Oil prices retreated quickly from the first half highs to average US$91.90 per bbl in the second half of 2011 hitting a low of US$85 per bbl in September and eventually recovering back to US$99 per bbl at year end.

Natural gas prices continued to wilt under the weight of increasing supply from aggressive development of unconventional natural gas resource plays throughout North America. Prices for natural gas sold in Canada opened 2011 just above $4.00 per million cubic feet in January and held in that area averaging $3.88 per million cubic feet for the first half of the year. Prices moved slowly lower throughout the second half of the year due to the global economic uncertainty, reduced demand due to moderate weather patterns and a continued increase in supply. Prices averaged $3.48 per million cubic feet in the second half of the year with the year's lowest price realized in December at $3.01 per million cubic feet.

Crew's 2011 financial results were bolstered by increased levels of liquids production added through the drill bit and the Caltex acquisition combined with the strong oil price environment. The Company's revenue increased 88% over 2010 to $388 million and funds from operations increased 75% over 2010 to $172 million or $1.67 per fully diluted share, a 39% increase over 2010. The Company's financial position remains strong with net debt at year end of $323 million or 1.25 times annualized fourth quarter funds from operations borrowed on a bank facility with a total lending capacity of $430 million.

Continued weakness in natural gas pricing resulted in Crew directing its 2011 capital program primarily towards development of its oil plays in the Princess area of Southern Alberta and the newly acquired heavy oil play in the Lloydminster area of west central Saskatchewan. Capital expenditures during the year totaled $350 million net of $25.5 million of non-core asset divestitures. The Company directed 65% of its spending towards continued growth of its top tier oil plays, drilling 120.5 net oil wells and 13 service wells in the Company's oil prone areas. The Company also advanced the development of the infrastructure at Princess spending 18% of total expenditures on the expansion of facilities and gathering systems in the area.

Crew continued to develop its Montney assets in northeast British Columbia in 2011. The primary focus of the Company's efforts was the continued development of liquids rich natural gas development at Septimus. During the year the Company directed 21% of its total exploration and development budget toward Septimus, drilling a total of 11 wells. In addition, Crew successfully drilled its first two Montney development wells at Kobes, British Columbia.

During 2011 the Company continued its program of divesting of non-core properties to help fund development of its core properties. This program resulted in two minor property sales for total proceeds of $25.5 million. These properties had production of approximately 280 boe per day and proven plus probable reserves of 1.0 mmboe as at December 31, 2010.


Pekisko Play - Princess, Alberta

At Princess, Alberta, Crew continues to progress both its short term strategy (infrastructure investment and individual pool delineation) and long term strategy (new pool identification and improved recovery of existing pools through waterflood implementation). In 2011, Crew drilled 62 horizontal, 45 vertical and 13 salt water disposal wells and invested over $59 million in sustaining infrastructure to ensure the long term economics of this oil play.

Production of 10,400 boe per day was achieved in December 2011 and as we have experienced historically since acquiring the property in 2008, production volumes are projected to decline through spring break-up as flush declines from the 2011 program take effect. These declines will be somewhat offset by production additions from the first quarter 2012 drilling program. Production is then projected to steadily increase throughout the year as volumes are added from the 2012 drilling program, optimization of our 2011 program and we begin to see volume increases from the secondary recovery projects.

The 2011 program consisted of 45 vertical and 62 horizontal wells which allowed the Company to compare and contrast the benefits of both horizontal and vertical well drilling. While we have previously stated that we would focus on horizontal wells in our 2012 program, we are finding that vertical wells are also an effective tool in pool development. They are also more effective at pool delineation which allows us to better understand reservoir distribution both laterally and stratigraphically. With our growing focus on secondary recovery and waterfloods, this understanding is critical and will allow Crew to plan future drilling programs to most effectively deplete the reservoir once waterflood has been implemented. As result of this, Crew will drill a greater number of vertical wells in the initial phase of the 2012 program. The vertical wells are a mix of existing pool delineation wells, water injection wells, separate stratigraphic interval tests within existing areas and exploratory wells. To date in the first quarter, we have drilled 25 wells of which 18 wells are vertical and seven are horizontal. While 16 wells remain to be completed, the program has resulted in positive initial test rates with four vertical new pool exploratory discoveries, one of which tested at a final rate of 377 bbl per day of oil after a three day test and one vertical delineation well tested at a final rate of 761 bbl per day of oil after a five day test. Crew's horizontals tested thus far in the first quarter have averaged 243 bbl per day of oil after two days of testing which is in line with the existing type curve for horizontals in the Pekisko formation at Princess.

Pekisko Secondary Recovery

As production continues to grow at Princess, a greater portion of the production growth from drilling new wells is required to offset production declines from an ever increasing number of existing wells. The key to sustainable development is to reduce the decline rate on existing pools so that additional "layers" of production from drilling become additive on a year to year basis. In recognizing this, Crew has rapidly progressed implementation of our improved recovery projects, and we expect to have projects operational in the second quarter. The attraction of these projects is the relatively low capital requirement (less that $5 per bbl recoverable oil), and the sustaining nature of a reduction in our field wide decline rate. Crew has been able to historically book a recovery factor in the order of 9% of the estimated resource based on primary development alone. As part of our 2011 year end reserves, GLJ has completed their evaluation of the "K" pool and has assigned a 20% recovery factor to the pool based on initial results from waterflood. The Pekisko "N" pool was also evaluated and a 25% recovery factor was assigned to this pool as a result of waterflood implementation. Modeling has further shown that recovery factors will benefit from early implementation of secondary recovery leading to the Company's aggressive approach.

In addition to the positive initial results at Crew's waterfloods at the Pekisko "K" and "N" pools, Crew has received regulatory approval for all five of its 2012 waterflood projects six to nine months ahead of expectation and has begun the process of converting water injection wells and pipeline construction to implement these projects.

Heavy Oil, Lloydminster, Saskatchewan

We continue to be pleased with the performance of our heavy oil assets acquired through the Caltex acquisition in July, 2011. In addition to providing a very strong netback with average fourth quarter wellhead prices in excess of $77 per bbl, production has remained essentially flat since the close of the acquisition at 6,100 boe per day. Crew has increased its activity level drilling 11 wells in the first quarter of 2012, with expectations that we will drill over 50% of our 2012 program (36 gross wells) in the first quarter.

Tower, British Columbia

Crew will spud one horizontal well in the first quarter at Tower to follow-up on the Company's Montney oil discovery completed in the previous quarter. This well was flowing at 610 boe per day (342 bbls of oil and liquids, and 1.7 mmcf per day of natural gas) at the end of a 23 day test. Crew has a 33% working interest in this well. The Company has 30 net sections of Montney land at Tower including 27 sections with 100 percent working interest and plans to drill an additional eight (6.0 net) wells on these lands in 2012.

Septimus, British Columbia

During the first quarter, Crew has drilled three horizontal wells in the Montney play at Septimus and is currently drilling one horizontal and one vertical well. Two of these wells have been completed to date and are currently producing at 720 boe per day and 900 boe per day (15% liquids), after twelve and eight days of production, respectively.

Kobes, British Columbia

Crew completed the second of the Company's two Montney horizontal wells at Kobes in the first quarter. This well began producing in February at an initial production rate of 1,320 boe per day (29% liquids). This well confirmed the previously observed high liquids cuts of Crew's other two producers at Kobes. Of importance, the two Kobes horizontal wells both tested the middle and upper Montney sections and exhibited flow rates in line with per frac rates in the lower Montney section. The Company plans to drill one additional well in the play in 2012.

Wapiti, Alberta

Following the closing of the Caltex acquisition in July 2011, Crew has continued to develop the Cardium at Wapiti. To date in the first quarter, Crew has drilled five (4.6 net) horizontal wells and one vertical well targeting high liquids rich gas (approximately 90 bbls per mmcf). The Company is also in the process of installing additional compression to allow for complete optimization of all the wells in the Elmworth and Wapiti areas. Two of the recent drills have been completed to date with test rates of 730 boe per day and 390 boe per day (35% liquids).


The Company previously announced its Board of Directors approved capital budget and 2012 guidance on January 11, 2012. Since the budget release, natural gas prices have continued to decline to the $2.00 per mcf level with oil prices rising to over $105 per bbl. Crew's oil weighting combined with the current oil price offsets the effect of reduced natural gas prices. The differential between West Texas Intermediate ("WTI") and all grades of western Canadian crude oil has widened dramatically over the last six weeks as a result of tightening pipeline and refining capacity in the United States. This development is being closely monitored to ensure we are approximating capital spending to funds from operations over the course of the year.

Crew currently has seven drilling rigs active with three at Princess, two rigs drilling for heavy oil in Alberta and Saskatchewan and two rigs drilling for liquids rich natural gas and oil in northeast British Columbia. The results to date in 2012 have been very positive with the Company expecting to drill 55 wells in the first quarter of the year. The 2012 capital program will be concentrated on an active secondary recovery program at Princess, continued development of our heavy oil assets and exploration for oil at Princess and Tower in northeast British Columbia. A focus and goal in 2012 is to improve our cash netbacks through the emphasis on oil drilling and cost controls. The success of waterflooding at Princess will play a significant role in arresting corporate declines, improving recovery factors and reducing costs such that the project is expected to be cash flow positive by year end.

Over the past four years, Crew has committed to growing its oil production and this commitment has been very successful. In 2007, our liquids weighting was 17% and in 2012, the liquids component is expected to be approximately 60% of total production. We will continue to emphasize the efficient execution of our capital program which is expected to lead to improved operating and financial metrics. Our assets can deliver top tier liquids production growth as well as providing our shareholders with a significant option on our large resource of liquids rich natural gas in northeast British Columbia and the deep basin in Alberta. We look forward to updating our progress in our first quarter report.

We would like to thank our employees and consultants for their hard work and dedication in the successful execution of our business plan. On behalf of Crew, we would like to express our sincere appreciation to our shareholders for their continued support.


The Company has completed an internal evaluation of the fair market value of the Company's undeveloped land holdings as at December 31, 2011. This evaluation was completed principally using industry activity levels, third party transactions and land acquisitions that occurred in proximity to Crew's undeveloped lands during the past year. The Company has estimated the value of its net undeveloped acreage at $307 million.

A summary of the Company's land holdings at December 31, 2011 is outlined below:

    Developed   Undeveloped   Total
(acres)   Gross   Net   Gross   Net   Gross   Net
Alberta   348,908   219,469   521,192   451,750   870,100   671,219
British Columbia   113,170   50,959   272,715   182,467   385,885   233,426
Saskatchewan   24,269   18,294   42,440   38,970   66,709   57,265
Other   160   -   376,920   37,692   377,080   37,692
Total   486,507   288,722   1,213,267   710,879   1,699,774   999,602


The reserves data set forth below is based upon an independent reserves assessment and evaluation prepared by GLJ with an effective date of December 31, 2011 (the "GLJ Report"). The following presentation summarizes the Company's crude oil, natural gas liquids and natural gas reserves and the net present values before income tax of future net revenue for the Company's reserves using forecast prices and costs based on the GLJ Report. The GLJ Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101.

All evaluations and reviews of future net cash flows are stated prior to any provisions for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of our crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

See "Information Regarding Disclosure on Oil and Gas Reserves and Operational Information" for additional cautionary language, explanations and discussions and "Forward Looking Information and Statements" for a statement of principal assumptions and risks that may apply.

Reserves Summary

The Company's total proved plus probable reserves increased by 84% in 2011 to 137.4 mmboe and proved reserves increased by 66% to 75.7 mmboe.

The following table provides summary reserve information based upon the GLJ Report and using the published GLJ (2012-01) price forecast.

    Light/Medium Oil   Heavy Oil
  Net(3) (Mbbl)   Comp.
  Producing   8,301   8,298   6,338   3,159   3,159   2,700
  Non-producing   670   670   531   1,537   1,537   1,333
  Undeveloped   5,353   5,353   4,034   814   814   709
Total proved   14,324   14,320   10,902   5,510   5,510   4,742
Probable   10,543   10,543   7,985   4,845   4,845   4,164
Total proved plus probable   24,867   24,863   18,887   10,355   10,355   8,906
    Natural Gas Liquids   Natural Gas
  Producing   4,440   4,427   3,275   126,891   126,506   102,166
  Non-producing   746   746   607   28,970   28,910   24,544
  Undeveloped   4,967   4,967   3,924   118,609   118,512   97,211
Total proved   10,152   10,139   7,806   274,469   273,927   223,921
Probable   9,541   9,538   7,526   220,490   220,351   181,860
Total proved plus probable   19,694   19,676   15,332   494,959   494,278   405,781
    Barrels of oil equivalent(4)
  Producing   37,048   36,968   29,341
  Non-producing   7,780   7,770   6,561
  Undeveloped   30,902   30,886   24,869
Total proved   75,731   75,624   60,770
Probable   61,678   61,650   49,986
Total proved plus probable   137,409   137,274   110,756


(1) "Comp. Int." reserves means Crew's working interest (operating and non-operating) share before deduction of royalties and including any royalty interest of the Company.

(2) "Gross" reserves means Crew's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company.

(3) "Net" reserves means Crew's working interest (operated and non-operated) share after deduction of royalty obligations, plus Crew's royalty interest in reserves.

(4) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

(5) May not add due to rounding.

Reserves Values

The estimated before tax future net revenues associated with Crew's reserves effective December 31, 2011 and based on the published GLJ (2012 - 01) future price forecast are summarized in the following table:

(MM$) (1)   0%   5%   10%   15%   20%
  Producing   882,117   726,706   626,687   556,188   503,448
  Non-producing   191,380   151,149   124,494   105,647   91,669
  Undeveloped   610,358   385,065   262,080   186,568   136,361
Total proved   1,683,856   1,262,920   1,013,261   848,404   731,479
Probable   1,569,415   930,051   628,399   458,320   351,137
Total proved plus probable   3,253,271   2,192,971   1,641,660   1,306,724   1,082,616


(1) The estimated future net revenues are stated before deducting future estimated site restoration costs and are reduced for estimated future abandonment costs and estimated capital for future development associated with the reserves.

(2) May not add due to rounding.

Price Forecast

The GLJ (2012-01) price forecast is summarized as follows:

Year   $US/$Cdn
  WTI @ Cushing   Edmonton light crude oil   Bow River med. crude oil at Hardisty   Natural gas at AECO/NIT spot   Westcoast Station 2
        (US$/bbl)   (C$/bbl)   (C$/bbl)   (C$/MMbtu)   (C$/MMbtu)
2012   0.98   97.00   97.96   83.27   3.49   3.29
2013   0.98   100.00   101.02   84.35   4.13   3.93
2014   0.98   100.00   101.02   84.35   4.59   4.39
2015   0.98   100.00   101.02   84.35   5.05   4.85
2016   0.98   100.00   101.02   84.35   5.51   5.31
2017   0.98   100.00   101.02   84.35   5.97   5.77
2018   0.98   101.35   102.40   85.50   6.21   6.01
2019   0.98   103.38   104.47   87.23   6.33   6.13
2020   0.98   105.45   106.58   89.00   6.46   6.26
2021   0.98   107.56   108.73   90.79   6.58   6.38
2022 +   0.98   +2.0%/yr   +2.0%/yr   +2.0%/yr   +2.0%/yr   +2.0%/yr


(1) Inflation is accounted for at 2.0% per year.

Reserves Reconciliation

The following summary reconciliation of Crew's Company Interest reserves compares changes in the Company's reserves as at December 31, 2011 to the reserves as at December 31, 2010 based on the GLJ (2012-01) future price forecast.

  Company Interest (1)   Gross(2)  
  Total Proved plus Probable   Total
  Total Proved plus Probable  
  (Mboe ) (Mboe ) (Mboe ) (Mboe )
Balance December 31, 2010 45,574   74,691   45,467   74,560  
  Technical revisions (925 ) (1,541 ) (939 ) (1,558 )
  Economic factors (909 ) (531 ) (909 ) (531 )
  Exploration Discoveries 1,134   1,807   1,134   1,807  
  Extensions and improved recoveries 18,102   31,188   18,103   31,188  
  Acquisitions 21,741   41,007   21,741   41,007  
  Dispositions (791 ) (1,017 ) (791 ) (1,017 )
  Production (8,195 ) (8,195 ) (8,182 ) (8,182 )
Balance December 31, 2011 75,731   137,409   75,624   137,274  


(1) "Company Interest" reserves means, Crew's working interest (operating and non-operating) share before deduction of royalties and including any royalty interest of the Company.

(2) "Gross" reserves means Crew's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company.

(3) May not add due to rounding

Capital Program Efficiency

During 2011, Crew's capital expenditures and corporate acquisition of Caltex, net of dispositions, resulted in proved plus probable reserve additions of 70.9 MMboe at a net finding, development and acquisition ("FD&A") cost of $18.36 per boe. Proved reserve additions in 2011 were 38.4 MMboe which were added at a net FD&A cost of $27.61 per boe.

The efficiency of the Company's capital program for the year ended December 31, 2011 and prior periods is summarized below.

  2011   2010   Three Year Average
  Proved   Proved plus Probable   Proved     Proved plus Probable   Proved Proved plus Probable
Exploration and Development expenditures(2 & 6)($ thousands) 375,874   375,874   245,626     245,626   731,011 731,011
Acquisitions/(Dispositions)(1 & 2) ($ thousands) 542,327   542,327   (132,020 )   (132,020 ) 350,670 350,670
Change in future development capital($ thousands)                      
  - Exploration and Development 32,994   176,865   7,835     52,710   107,170 297,375
  - Acquisitions/
108,016   207,125   (4,601 )   (10,565 ) 102,815 192,390
Reserves additions with revisions and economic factors (Mboe)                      
  - Exploration and Development 17,411   30,932   15,375     20,987   44,449 67,872
  - Acquisitions/
20,950   39,990   (4,486 )   (7,041 ) 13,695 28,723
  38,361   70,922   10,889     13,946   58,144 96,595
Finding & Development Costs(2 & 3)($/boe)                      
  - without revisions and economic factors 21.25   16.75   18.44     14.68   19.22 14.67
  - with revisions and economic factors 23.48   17.87   16.49     14.22   18.86 15.15
Finding, Development & Acquisition Costs(3 & 4) ($/boe)                      
  - without revisions and economic factors 26.36   17.84   12.62     11.71   22.54 15.90
  - with revisions and economic factors 27.61   18.36   10.73     11.17   22.21 16.27
Recycle Ratio(5) 0.9x   1.4x   2.1x     2.0x      
Reserves Replacement 468 % 865 % 218 %   279 %    
Reserve Life Index based on annualized 2011 fourth quarter production (years) 6.9   12.5   8.5     14.0      


(1) Acquisition costs related to the 2011 corporate acquisition of Caltex 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 International Financial Reporting Standards ("IFRS").

(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year.

(3) Calculation includes changes in future development costs.

(4) Crew calculates finding, development and acquisition ("FD&A") costs which incorporate both the costs and associated reserve additions related to acquisitions net of any dispositions during the year. Since acquisitions and divestitures have had a significant impact on Crew's annual reserve replacement costs, the Company believes that FD&A costs provide a meaningful portrayal of Crew's cost structure.

(5) The 2011 recycle ratio is calculated using the Company's Q4 2011 operating net back of $26.03 per boe (unaudited) which includes commodity related hedging gains and losses for the quarter.

(6) Exploration and development expenditures for 2010 have been adjusted from previous year's disclosure to comply with IFRS.

Net Asset Value

The following table provides a calculation of Crew's estimated net asset value at December 31, 2011 based on the estimated future net revenues associated with Crew's proved plus probable reserves before income tax and discounted at 5% and 10% as presented in the GLJ Report and including Crew's internal assessment of undeveloped land values.

  5%   10%  
  Discount   Discount  
($ thousands)        
Proved plus probable reserves 2,192,971   1,641,660  
Undeveloped Land (note 1) 306,812   306,812  
Bank debt as at December 31, 2011 (230,676 ) (230,676 )
Working capital deficiency as at December 31, 2011 (92,452 ) (92,452 )
Proceeds from dilutive stock options 24,841   24,841  
Net asset value 2,201,496   1,650,185  
Diluted Common shares outstanding (thousands) 123,025   123,025  
Net asset value per share $17.89   $13.41  


(1) Internally estimated value (see "Land Holdings")

Cautionary Statements

Information Regarding Disclosure on Oil and Gas Reserves and Operational Information

In accordance with Canadian practice, production volumes are reported on a gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserve volumes in this news release and all information derived therefrom are based on "company interest reserves" using forecast prices and costs. "Company interest reserves" consist of "company gross reserves" (as defined in National Instrument 51-101 adopted by the Canadian Securities Regulators ("NI 51-101")) plus Crew's royalty interests in reserves. "Company interest reserves" are not a measure defined in NI 51-101 and does not have a standardized meaning under NI 51-101. Accordingly our Company interest reserves may not be comparable to reserves presented or disclosed by other issuers. Our oil and gas reserves statement for the year ended December 31, 2011, which will include complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, will be contained within our Annual Information Form which will be available on our SEDAR profile at The recovery and reserve estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.

In relation to the disclosure of net asset value ("NAV"), the NAV table shows what is normally referred to as a "produce-out" NAV calculation under which the current value of the Company's reserves would be produced at forecast future prices and costs and do not necessarily represent a "going concern" value of the Company. The value is a snapshot in time and is based on various assumptions including commodity price forecasts and foreign exchange rates that vary over time. It should not be assumed that the future net revenues estimated by GLJ represent the fair market value of the reserves, nor should it be assumed that Crew's internally estimated value for its undeveloped land holdings represent the current fair market value of the lands.

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 foregoing, this news release contains forward-looking information and statements pertaining to the following: the recognition of significant reserves under the heading "Reserves"; the volumes and estimated value of Crew's oil and natural gas reserves; the life of Crew's reserves; the volume and product mix of Crew's oil and gas production; production estimates; year-end 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; anticipated reductions in operating costs; 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 and the timing thereof; the number of wells to be drilled, completed and tied-in and the timing thereof; the amount and timing of capital projects including new infrastructure; operating costs; the total future capital associated with development of reserves and resources.

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; the ability of Crew to successfully market its oil and natural gas products; ability to improve upon historical recovery factors.

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 adequate 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.

Test Results and Initial Production Rates

A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.

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

Annual financial statements and Management's Discussion and Analysis for the three months and year ended December 31, 2011 will be filed on SEDAR at and are available on the Company's website at


Crew Energy Inc.
Dale Shwed
President and C.E.O.
(403) 231-8850

Crew Energy Inc.
John Leach
Senior Vice President and C.F.O.
(403) 231-8859

Crew Energy Inc.
Rob Morgan
Senior Vice President and C.O.O.
(403) 513-9628