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
-------------------------------------------------
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 $27.61 per boe.
The efficiency of the Company's capital program for the year
ended December 31, 2011 and prior periods is summarized below.
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Three Year
Average
2011 2010 2009-2011
----------------------------------------------------------------------------
Proved Proved Proved
plus plus plus
Proved Probable Proved Probable Proved Probable
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Exploration and
Development
expenditures(2 & 6)($
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.
Contacts: Crew Energy Inc. Dale Shwed President and C.E.O. (403)
231-8850dale.shwed@crewenergy.com Crew Energy Inc. John Leach
Senior Vice President and C.F.O. (403)
231-8859john.leach@crewenergy.com Crew Energy Inc. Rob Morgan
Senior Vice President and C.O.O. (403)
513-9628rob.morgan@crewenergy.com www.crewenergy.com
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