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").
Highlights
-- Funds from operations increased 136% over the fourth quarter of 2010 to
$64.8 million and increased 20% over the third quarter of 2011;
-- Funds from operations per share increased 59% (53% debt adjusted) over
the fourth quarter of 2010 and 20% over the third quarter of 2011;
-- Fourth quarter production increased 105% to 30,034 boe per day compared
to the same period in 2010 and increased 9% over the third quarter of
2011;
-- Fourth quarter production per share increased 38% (33% debt adjusted)
over the fourth quarter of 2010 and 9% per share over the third quarter
of 2011;
-- Proved plus probable reserves increased 84% to 137.4 million boe;
-- Reserves per share increased 23% (20% debt adjusted) over 2010;
-- Proved plus probable oil and natural gas liquids reserves increased 90%
to 54.9 million bbls;
-- Proved plus probable reserve replacement was 865% and 468% on proved
reserves; and
-- Recycle ratio of 2.0x excluding future development capital and 1.4x
including changes in future development capital.
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Three months Three months
Financial ended ended Year ended Year ended
($ thousands, except December 31, December 31, December 31, December 31,
per share amounts) 2011 2010 2011 2010
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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
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Capital Structure($ As at As at
thousands) December 31, December 31,
2011 2010
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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
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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, 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.
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Three months Three months
ended ended Year ended Year ended
December 31, December 31, December 31, December 31,
Operations 2011 2010 2011 2010
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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%
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Notes:
(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.
OPERATIONS UPDATE
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).
Outlook
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.
LAND HOLDINGS
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:
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Developed Undeveloped Total
(acres) Gross Net Gross Net Gross Net
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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
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Total 486,507 288,722 1,213,267 710,879 1,699,774 999,602
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RESERVES
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.
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Light/Medium Oil Heavy Oil
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Comp. Comp.
Int.(1) Gross(2) Net(3) Int.(1) Gross(2) Net(3)
(Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl) (Mbbl)
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Proved
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
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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
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Total proved plus
probable 24,867 24,863 18,887 10,355 10,355 8,906
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Natural Gas Liquids Natural Gas
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Comp. Comp.
Int.(1) Gross(2) Net(3) Int.(1) Gross(2) Net(3)
(Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mmcf) (Mmcf)
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Proved
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
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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
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Total proved plus
probable 19,694 19,676 15,332 494,959 494,278 405,781
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Barrels of oil
equivalent(4)
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Comp.
Int.(1) Gross(2) Net(3)
(Mboe) (Mboe) (Mboe)
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Proved
Producing 37,048 36,968 29,341
Non-producing 7,780 7,770 6,561
Undeveloped 30,902 30,886 24,869
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Total proved 75,731 75,624 60,770
Probable 61,678 61,650 49,986
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Total proved plus
probable 137,409 137,274 110,756
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Notes:
(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:
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(MM$) (1) 0% 5% 10% 15% 20%
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Proved
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
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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
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Total proved plus probable 3,253,271 2,192,971 1,641,660 1,306,724 1,082,616
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Notes:
(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:
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Edmonton Bow River
$US/$Cdn light med. crude Natural gas
Exchange WTI @ crude oil at at AECO/NIT Westcoast
Year Rate Cushing oil Hardisty spot Station 2
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(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
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2022 + 0.98 +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr
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Notes:
(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.
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Company Interest (1) Gross(2)
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Total Proved Total Proved
Total plus Total plus
Proved Probable Proved Probable
(Mboe) (Mboe) (Mboe) (Mboe)
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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)
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Balance December 31,
2011 75,731 137,409 75,624 137,274
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Notes:
(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 $27.61 per boe.
The efficiency of the Company's capital program for the year ended December 31,
2011 and prior periods is summarized below.
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Three Year
Average
2011 2010 2009-2011
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Proved Proved Proved
plus plus plus
Proved Probable Proved Probable Proved Probable
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Exploration and
Development
expenditures(2 & 6)($
thousands) 375,874 375,874 245,626 245,626 731,011 731,011
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Acquisitions/(Disposit
ions)(1 & 2) ($
thousands) 542,327 542,327 (132,020) (132,020) 350,670 350,670
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Change in future
development capital($
thousands)
- Exploration and
Development 32,994 176,865 7,835 52,710 107,170 297,375
- Acquisitions/
Dispositions 108,016 207,125 (4,601) (10,565) 102,815 192,390
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Reserves additions
with revisions and
economic factors
(Mboe)
- Exploration and
Development 17,411 30,932 15,375 20,987 44,449 67,872
- Acquisitions/
Dispositions 20,950 39,990 (4,486) (7,041) 13,695 28,723
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38,361 70,922 10,889 13,946 58,144 96,595
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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
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Notes:
(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 $26.03 per boe (unaudited) which includes commodity related hedging
gains and losses for the quarter.
(6) Exploration and development expenditures for 2010 have been adjusted from
previous year's disclosure to comply with IFRS.
Net Asset Value
The following table provides a calculation of Crew's estimated net asset value
at December 31, 2011 based on the estimated future net revenues associated with
Crew's proved plus probable reserves before income tax and discounted at 5% and
10% as presented in the GLJ Report and including Crew's internal assessment of
undeveloped land values.
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5% 10%
Discount Discount
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($ 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
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Net asset value 2,201,496 1,650,185
Diluted Common shares outstanding (thousands) 123,025 123,025
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Net asset value per share $17.89 $13.41
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Notes:
(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 www.sedar.com. 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
www.sedar.com and are available on the Company's website at www.crewenergy.com.
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