Crew Energy Inc. (TSX:CR) of Calgary, Alberta is pleased to present
its operating and financial results for the three month period
ended March 31, 2013 and the results of its 2013 Montney Resource
Evaluation.
Highlights
-- An independent Total Petroleum Initially in Place ("TPIIP") evaluation
has confirmed that Crew's 292 net Montney sections are a world class
hydrocarbon accumulation of 76 TCFE made up of 33.7 TCF of natural gas
and seven billion barrels of light oil;
-- Increase in the Company's credit facility from $400 million to $430
million;
-- Funds from operations were $34.2 million or $0.28 per share in the first
quarter of 2013;
-- Production in the first quarter averaged 25,961 boe per day and has
increased to average approximately 28,000 boe per day in April;
-- Drilled 39 wells in the quarter with a 100% success rate;
-- Closed the acquisition of 59 net sections of Montney rights in northeast
British Columbia for $20 million;
-- Drilled a new pool discovery well at Princess, Alberta which averaged
176 bbls of oil per day in April;
-- Recently completed two Septimus, BC Montney wells drilled in the first
quarter that are exceeding type curves with the first producing 8.2 mmcf
per day at 1,250 psi flowing casing pressure after 10 days and the
second producing 6.6 mmcf per day flowing at 1,720 psi after 14 days,
each with associated liquids of approximately 28 bbls/mmcf (57%
condensate);
-- Plans to expand the Septimus gas plant capacity from 40 mmcf per day to
approximately 65 mmcf per day are on track for a fourth quarter
commissioning and the Company has commenced engineering work for a
second facility to significantly increase the natural gas processing
capacity in the Septimus area to up to 180 mmcf per day.
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Three months Three months
Financial ended ended
($ thousands, except per share amounts) March 31, 2013 March 31, 2012
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Petroleum and natural gas sales 91,267 123,075
Funds from operations (note 1) 34,188 48,057
Per share - basic 0.28 0.40
- diluted 0.28 0.40
Net loss (22,047) (6,430)
Per share - basic (0.18) (0.05)
- diluted (0.18) (0.05)
Exploration and Development expenditures 65,252 128,743
Property acquisitions (net of dispositions) 14,663 -
Net capital expenditures 79,915 128,743
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As at
Capital Structure As at December 31,
($ thousands) March 31, 2013 2012
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Working capital deficiency (note 2) 50,341 48,522
Bank loan 288,522 242,834
Net debt 338,863 291,356
Current bank facility 430,000 400,000
Common Shares Outstanding (thousands) 121,620 121,620
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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 and the transportation
liability charge. Funds from operations is used to analyze the
Company's operating performance and leverage. Funds from operations
does not have a standardized measure prescribed by 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 less
accounts payable and accrued liabilities.
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Three months Three months
ended ended
Operations March 31, 2013 March 31, 2012
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Daily production (note 1)
Princess and other oil (bbl/d) 4,936 6,770
Lloydminster oil (bbl/d) 5,441 6,162
Natural gas liquids (bbl/d) 2,984 3,105
Natural gas (mcf/d) 75,597 86,056
Oil equivalent (boe/d @ 6:1) 25,961 30,380
Average prices (notes 1 & 2)
Princess and other oil ($/bbl) 64.36 81.10
Lloydminster oil ($/bbl) 50.61 71.04
Natural gas liquids ($/bbl) 54.43 53.05
Natural gas ($/mcf) 3.42 2.34
Oil equivalent ($/boe) 39.06 44.52
Netback ($/boe)
Operating netback (note 3) 17.82 20.35
G&A 1.99 1.91
Interest on bank debt 1.19 1.06
Funds from operations 14.64 17.38
Drilling Activity
Gross wells 39 60
Working interest wells 36.8 57.8
Success rate, net wells 100% 97%
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Notes:
(1) Princess, Alberta oil (20 degrees to 26 degrees API oil) has
historically been classified as medium or conventional oil. Effective
December 31, 2012 Crew's reserves attributable to its Princess
property have been classified as heavy oil to accord with definitions
in the royalty regulations in Alberta. Princess and other oil
production and pricing are shown separately from Lloydminster heavy
oil volumes for clarity and comparison with historical classification.
(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.
OVERVIEW
Crew commissioned Sproule Associates Ltd. ("Sproule") to
complete an independent Resource Evaluation of the Company's
Montney lands in Northeast British Columbia which validates the
Company's strategy of acquiring prospective acreage at an
attractive valuation. Crew's 292 Montney sections have a resource
assignment of 76 TCFE (12.5 billion boe) of TPIIP with the
opportunity to materially add to this total in the coming months.
Crew also plans to become more active drilling in the northeast
British Columbia Montney formation given the improved economics of
this play. The detailed results of the Resource Evaluation are
described below.
During the first quarter of 2013, Crew continued to add to its
Montney land position with the closing of the second tranche of its
multi-option acquisition in the greater Septimus/Groundbirch area.
The transaction closed in late February and added an additional 59
net sections of land for $20 million. The Company has one
additional option as part of this transaction which, if exercised,
is anticipated to close in early July for $36 million adding
significant additional resource on 81 net sections of Montney
lands. To aid in funding this acquisition the Company has increased
its bank facility to $430 million as a result of the Company's
increased December 31, 2012 proved developed producing
reserves.
Crew's first quarter drilling program was active while remaining
disciplined with exploration and development spending coming in 12%
under its initial budget at $65.2 million. During the quarter the
Company drilled a total of 39 (36.8 net) wells including 23 (20.8
net) heavy oil wells in the Lloydminster area, 9 (9.0 net) wells at
Princess, 3 (3.0 net) wells in the Deep Basin and 4 (4.0 net)
Montney gas wells at Septimus.
First quarter production averaged 25,961 boe per day, a
reduction of 4% over the fourth quarter of 2012 due to the sale of
625 boe per day of Kobes, BC production at the end of December and
unplanned natural gas production outages at Septimus, BC and Kakwa,
AB. The Company's successful first quarter drilling program has
increased production to a field estimate average of approximately
28,000 boe per day in April which approximates current estimated
levels.
FINANCIAL
The Company's first quarter funds from operations decreased, as
compared to the fourth quarter of 2012, to $34.2 million or $0.28
per share. This decline resulted from the 4% quarter over quarter
production decrease noted above and lower netbacks caused by lower
first quarter oil prices and higher winter operating costs. The
Company's price received (excluding hedging losses) for its
production decreased 5% while total cash costs per boe including
royalties, operating costs, transportation, general and
administrative and interest costs were up 1% due to higher winter
operating costs and higher first quarter general and administrative
costs associated with annual reporting requirements. The Company's
net loss for the quarter of $22 million was in large part impacted
by a $16 million loss from realized and unrealized hedging
losses.
Crew's first quarter revenue from natural gas was positively
impacted by pricing that was higher than previously forecasted as
extended winter temperatures have impacted the highly populated
eastern regions of Canada and the U.S. The above average heating
demand has drawn North American natural gas inventories below 2012
and five year average levels which continues to bolster both NYMEX
and AECO prices. The price for natural gas delivered at the
Canadian AECO hub during the first quarter averaged $3.24 per mcf,
which was consistent with prices in the fourth quarter of 2012. The
average price received for Crew's natural gas sales during the
first quarter was $3.42 per mcf, which was also consistent with
fourth quarter 2012 pricing.
Prices received for the Company's liquids production including
conventional oil, heavy oil and natural gas liquids were down 6%
compared to those received for the fourth quarter 2012. West Texas
Intermediate ("WTI") oil, denominated in Canadian dollars,
increased 9% during the quarter compared to the fourth quarter of
2012. The prices received for the Company's conventional and heavy
oil sales correlate closely to the price of Western Canadian Select
("WCS"), which traditionally trades at a discount to WTI. During
the first quarter the differential between WTI and WCS increased to
34% from 21% in the fourth quarter which resulted in the WCS price
decreasing 7% from fourth quarter of 2012 levels. The Company's
overall liquids pricing was positively impacted by a 15% increase
in the price received for the Company's natural gas liquids. This
increase was driven by the increase in the underlying price of WTI
and an increase in prices received for condensate, ethane and
propane.
The Company's hedging strategy is focused on partially
protecting against significant declines in commodity prices that
would negatively impact the cash flow needed to fund the Company's
on-going capital program. Crew currently has hedged approximately
47% of its forecasted 2013 natural gas production at a price of
approximately $3.22 per mcf. The Company also protects its liquids
production from a significant decline in WTI and WCS pricing. The
Company has approximately 38% of its forecasted 2013 liquids
production protected against a decline in WTI pricing with hedged
prices fixed at a floor of approximately $92.00 per barrel. The
Company has further hedged the differential between WTI and WCS
pricing on 4,200 barrels per day at a differential of $21.08 for
the second quarter of 2013, 4,500 barrels per day at $22.29 for the
third quarter and 2,500 barrels per day at $22.58 for the fourth
quarter. Crew has begun building its hedge position to provide a
base level of cash flow for 2014. The Company currently has hedged
approximately 14.0 mmcf per day of natural gas for 2014 at a price
of approximately $3.90 per mcf and 1,500 barrels per day of WTI oil
hedged at an average floor price of approximately $95.70 per barrel
for 2014 with additional hedges fixing the differential between WTI
and WCS pricing on an average of 1,000 barrels per day for 2013 at
a differential of $22.75 per barrel
OPERATIONS UPDATE
Septimus/Tower, British Columbia
Crew's Septimus development program maintained its active pace
into the first quarter with the drilling of four (4.0 net) Montney
horizontal wells. Production for the quarter averaged 6,170 boe per
day as a compressor outage at the Septimus gas plant in February
curtailed production in the quarter by approximately 265 boe per
day. Three wells were completed and brought on production in the
first quarter which led to record March production of 6,790 boe per
day. Production into the second quarter has continued this trend
with April field estimates at approximately 7,000 boe per day and
more recently approaching 7,500 boe per day (40 mmcf per day plus
associated liquids). In addition, approximately 1,100 boe per day
of existing production is currently backed out due to the high
flowing pressure of the new wells and one additional new well has
yet to come on production. One of the wells completed in the first
quarter confirmed a more liquids rich area of the Montney producing
74 bbls/mmcf of natural gas liquids in the first 25 days when
compared to a field average of approximately 28 bbls/mmcf. Crew now
has eight wells which have been completed incorporating advanced
completion practices. Based on the initial performance of seven of
these wells, the Company's estimated ultimate recoveries ("EURs")
of 4.6 BCF per well is a 44% improvement over the average year end
2012 2P booked EURs. In addition, well costs consisting of
drilling, completion and equipping have declined 22% to $4.7
million per well which when combined with the improved per well
performance results in a very competitive rate of return for
Septimus development at current natural gas prices.
Completion operations were also undertaken on Crew's first water
disposal well at Septimus which came into service early in the
second quarter. This well is expected to eliminate approximately
$1.1 million in annual trucking and third party disposal charges.
Installation of the fourth compressor at the Crew operated Septimus
gas plant is on track for start-up in the fourth quarter of 2013
which will increase the capacity of the plant by 50% to
approximately 65 mmcf per day with the intent of reaching plant
capacity by the end of the first quarter 2014. Crew has undertaken
initial scoping work on a second gas processing facility that would
increase the total capacity for the Septimus area to up to 180 mmcf
per day.
Included in the 76 TCFE of Montney TPIIP, the Resource
Evaluation included a light oil TPIIP of seven billion bbls. This
represents a significant light oil growth opportunity for Crew as
the completion technology in this oil window continues to evolve
along with a corresponding improvement in economics. Crew is in the
process of planning a development program for the Tower area that
will likely be included as part of the Company's 2014 budget
plan.
Deep Basin, Alberta
First quarter production in the Deep Basin averaged 5,540 boe
per day. Third party facility outages and natural gas liquids
apportionment in January and February negatively impacted
production in the quarter by 370 boe per day. Despite the
challenges early in the year, March production was on target at
6,020 boe per day and production continues to be on track into the
second quarter between 5,700 and 6,000 boe per day. Crew drilled
three (3.0 net) horizontal wells for production from the Cardium
formation, two of which are expected to be completed and brought on
production in the second quarter.
Princess, Alberta
At Princess, Crew drilled nine (9.0 net) wells including five
horizontal wells. A successful horizontal well at North Alderson
has confirmed a new Pekisko oil pool located east of the Company's
current development. The well came on production in February, 2013
and produced an average of 176 bbls of oil per day in April. A
Mannville vertical well drilled in the quarter confirmed the
Company's geological interpretation of this play and is currently
producing 30 to 40 bbls of oil per day. Crew has plans to drill two
to three horizontal wells to further test and delineate this play.
Expansion of the waterflood program continued in the quarter with
the initiation of injection into the Pekisko GG pool bringing the
total to nine pools currently under waterflood with an additional
two to four pools expected to be brought on by the end of the year.
Approximately 36% of the developed Pekisko resource is now under
waterflood with a plan to have it over 40% by the end of the year.
Production for the quarter averaged 5,650 boe per day with third
party natural gas facility downtime impacting production by
approximately 100 boe per day on average. With six new wells
completed and brought on late in the quarter and ongoing waterflood
support, current production levels are approximately 6,000 boe per
day consistent with expectations.
Lloydminster, Saskatchewan
Crew drilled 23 (20.8 net) wells in the quarter and has been
very pleased with the results of this program. Three (3.0 net)
horizontal wells at Wildmere were successfully placed into the
Lloydminster formation as a follow-up to our fourth quarter of 2012
program. Four (4.0 net) vertical wells at Epping encountered up to
three productive horizons in the GP, Sparky and Colony zones. Crew
initiated a development program in the Swimming area with six (6.0
net) successful wells in the Sparky sand. Throughout the winter
season and particularly in the first quarter, the Lloydminster area
was subjected to unusually high snow fall levels resulting in
production being curtailed for the quarter to 5,520 boe per day.
Crew's Lloydminster operating staff did a commendable job
recovering from these frequent and intense storms and were able to
restore production levels in April to approximately 6,000 boe per
day based on field estimates. With the return of warmer weather and
the official start of spring break-up, Crew expects Lloydminster
production will vary between 5,000 to 6,000 boe per day in the
coming weeks.
OUTLOOK
Crew is maintaining its forecasted average annual production of
27,500 to 28,500 boe per day. In April, production averaged
approximately 28,000 boe per day based on field estimates, 8% above
the first quarter average, positioning the Company to exit 2013 at
its 29,000 to 30,000 boe per day guidance. First quarter funds from
operations were impacted by WCS differentials widening dramatically
to average 34% of WTI as well as facilities related downtime.
Second quarter production is forecasted to average 27,500 boe per
day and with narrowing differentials, we are expecting to generate
significantly more funds from operations in the second quarter. The
Company was disciplined in the first quarter, spending $65.2
million or 12% less than initially budgeted exploration and
development expenditures and exited the quarter with $339 million
of net debt on a $430 million bank facility. Crew also purchased 59
net sections of land in northeast British Columbia for $20 million
and disposed of a non-core asset producing 65 boe per day for $5.2
million. Crew's exploration and development budget of $219 million
is currently planned to be funded by funds from operations, bank
debt and non-core asset dispositions.
The recently completed Resource Evaluation validates the
Company's strategy of acquiring prospective acreage at an
attractive valuation. Crew's 292 Montney sections have a resource
assignment of 76 TCFE (12.5 billion boe) of TPIIP with the
opportunity to materially add to this total if we exercise the
option to acquire 81 additional sections for $36 million. Crew
plans to become more active drilling in the northeast British
Columbia Montney play and will drill three exploratory horizontal
wells and will continue with development drilling targeting to fill
the expanded Septimus gas plant to approximately 65 mmcf per day by
the end of the first quarter of 2014.
Crew would like to welcome Mr. Jamie L. Bowman to its management
team as Vice-President, Marketing. Mr. Bowman has over 25 years of
oil and gas industry experience and will be a valuable addition to
the Company's executive team.
We would like to thank our shareholders for their continued
support as well as our employees, consultants and Board of
Directors for their hard work and dedication. We look forward to
reporting our second quarter results and our progress for long-term
value creation initiatives in August, 2013.
NORTHEAST BRITISH COLUMBIA MONTNEY RESOURCE EVALUATION
The following discussion in "Northeast British Columbia Montney
Resource Evaluation" is subject to a number of cautionary
statements, assumptions and risks as set forth therein. See
"Information Regarding Disclosure on Oil and Gas Reserves,
Resources and Operational Information" for additional cautionary
language, explanations and discussion and "Forward Looking
Information and Statements" for a statement of principal
assumptions and risks that may apply. See also "Definitions of Oil
and Gas Resources and Reserves". The discussion includes reference
to TPIIP, DPIIP, UPIIP and Contingent Resources per the Sproule
Associates Ltd. ("Sproule") Resources Evaluation effective as at
May 1, 2013, prepared in accordance with the Canadian Oil and Gas
Evaluation Handbook ("COGE Handbook"). Unless indicated otherwise
in this news release, all references to Contingent Resource volumes
are Best Estimate Contingent Resource volumes.
Sproule was engaged to conduct an independent Montney resource
evaluation of Crew's 292 net Montney sections located in Northeast
British Columbia ("NEBC") (the "Evaluated Areas") effective as of
May 1, 2013 (the "Resource Evaluation"). The Resource Evaluation
confirms the development and resource potential on the Company's
land base. Crew's NEBC Montney assets allow us to navigate through
commodity price cycles given the range of Crew's Montney
landholdings with exposure to liquids rich gas, crude oil and dry
natural gas (gas containing greater than 95% methane). The Resource
Evaluation reaffirms Crew's belief in the considerable potential
that exists to further increase our current reserve base,
highlighting the world class potential of the NEBC Montney.
The Resource Evaluation has included the recognition of Crew's
lands in the Montney "oil window" where Crew has 99.7 net sections.
Previously there was very little production or analysis in the
Montney in this area, however, the last two years have provided
evidence of the potential on these lands.
Crew started acquiring land on the Montney play in 2007
recognizing there was a significant resource in this Formation.
Technology at the time was limited to horizontal drilling and plug
and perforation energized frac completions using low volumes of
water. At the time, the Company was producing 83% natural gas and
17% oil and liquids. With the coming unconventional natural gas
boom, Crew elected to diversify its asset mix to become more
liquids weighted. In 2008, Crew bought Gentry Resources Inc. to
gain access to the Princess play in southeast Alberta. The Company
continued to build its Montney land base, slowly growing production
but focused on the newly acquired oil assets as a growth vehicle
with high netbacks. Given the challenges with short-term production
growth at Princess and as part of Crew's ongoing evaluation of its
portfolio of assets, the Company concluded that the northeast
British Columbia Montney play had evolved to where the economics
were competing with other plays in our portfolio. Costs were
decreasing, results were improving, infrastructure is readily
accessible, our understanding of the play was evolving, type curves
were improving, well results were becoming more predictable and
most importantly Crew had developed a significant acreage position
with an associated world class resource. With this as a backdrop,
we made a decision to divest of our 23 net section Kobes asset for
$108 million and purchase 200 sections for $78 million proximal to
our lands and infrastructure between the two Spectra pipelines that
provide a west coast delivery option and an east takeaway option
through Aux Sable and the Alliance pipeline.
The Resource Evaluation that is presented below and the results
we have had at Septimus to date highlight the quality of the lands
that Crew has successfully acquired over the past six years. With
the improved economics of this play and the visibility of continued
development of infrastructure in the Septimus corridor we are
committed to continue to pursue opportunities in this region and it
is our intent to aggressively exploit the 34 TCF and seven billion
barrels of TPIIP on our acreage in order to grow production,
reserves and cashflow into the future.
The following tables summarize the results of the Resource
Evaluation.
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Natural Gas Resource Categories (1)(2)(3) Tcf
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Total Petroleum Initially In Place (TPIIP) 33.7
Discovered Petroleum Initially In Place (DPIIP) 12.0
Undiscovered Petroleum Initially In Place (UPIIP) 21.7
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(1) All volumes in table are company gross and raw gas volumes.
(2) Sproule's analysis identified four intervals in the Montney consisting
of one interval in the Upper Montney and three intervals in the Lower
Montney.
(3) Crew's acreage was divided into six (6) areas in the "gas window". Crew
owns 192 net sections in the gas window at May 1, 2013.
Oil Resource Categories (1)(2)(3)(4) Mmbbls
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Total Petroleum Initially In Place (TPIIP) 7,031.5
Discovered Petroleum Initially In Place (DPIIP) 880.0
Undiscovered Petroleum Initially In Place (UPIIP) 6,151.5
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(1) All volumes in table are company gross.
(2) The oil volumes are quoted as Stock Tank Barrels ("STB").
(3) Sproule's analysis identified four intervals in the Montney consisting
of one interval in the Upper Montney and three intervals in the Lower
Montney.
(4) Crew's acreage was divided into five (5) areas in the "oil window". Crew
owns 100 net sections in the oil window at May 1, 2013.
Reserves and Contingent Resources (1)(2) Best Estimate
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Natural Gas (Tcf)
Reserves (3) 0.2
Contingent Resources (6) 2.3
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Natural Gas Liquids (mmbbls) (4)(5)
Reserves (3) 7.3
Contingent Resources (6) 102.1
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Oil (mmbbls)
Reserves (3) 0.3
Contingent Resources 7.7
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(1) All DPIIP other than cumulative production, reserves, and Contingent
Resources has been categorized as unrecoverable at this time.
(2) All volumes in table are company gross and sales volumes.
(3) For reserves, the volume under the heading Best Estimate are proved plus
probable reserves as at December 31, 2012.
(4) The liquid yields are based on average yield over the producing life of
the property.
(5) Liquid yields are unique to each area. They are estimated based on gas
composition of gas samples in the area and expected plant recoveries.
(6) Project economic Status is currently undetermined. There is no certainty
that it will be commercially viable to produce any of the resources.
Prospective Resources (1)(2) Best Estimate
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Natural gas (Tcf) 3.8
Natural gas liquids (mmbbls) 158.7
Oil (mmbbls) 16.4
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(1) All UPIIP other than Prospective Resources has been categorized as
unrecoverable at this time.
(2) All volumes in table are company gross and sales volumes.
Based upon the foregoing analysis and Crew's expertise in the
Montney formation in NEBC, it is expected that significant
additional reserves will be developed in the future with continued
drilling success on currently undeveloped Montney acreage together
with further development, completion refinements and improved
economic conditions. Additional drilling, completion, and test
results are required before Crew can commit to development and
these contingent resources can be converted to reserves and a
larger component of Prospective Resources is converted to
Contingent Resource.
The Prospective Resources have not been risked for chance of
discovery. There is no certainty that any portion of the
Prospective Resources will be discovered. The Prospective and
Contingent Resources have not been risked for chance of
development. There is no certainty that it will be commercially
viable to produce any portion of the Prospective (if discovered) or
Contingent Resources. The Contingent Resource contingencies are
identified as economic or non-technical, there are no technical
contingencies. Significant positive factors are historic drilling
success and production history on the more fully developed Montney
acreage, abundant well log and production test data. Potential
negative factors include lack of long term production history over
the majority of Crew lands, lack of infrastructure, potential for
variations in the quality of the Montney formation where minimal
well data currently exists, access to the substantial amount of
capital which would be required to develop the resources, low
commodity prices that would curtail the economics of development
and the future performance of wells, regulatory approvals, access
to the required services at the appropriate cost and topographic or
surface restrictions.
Definitions of Oil and Gas Resources and Reserves
Reserves are estimated remaining quantities of oil and natural
gas and related substances anticipated to be recoverable from known
accumulations, as of a given date, based on the analysis of
drilling, geological, geophysical and engineering data; the use of
established technology; and specified economic conditions, which
are generally accepted as being reasonable. Reserves are classified
according to the degree of certainty associated with the estimates
as follows:
Proved Reserves are those reserves that can be estimated with a
high degree of certainty to be recoverable. It is likely that the
actual remaining quantities recovered will exceed the estimated
proved reserves.
Probable Reserves are those additional reserves that are less
certain to be recovered than proved reserves. It is equally likely
that the actual remaining quantities recovered will be greater or
less than the sum of the estimated proved plus probable
reserves.
Possible Reserves are those additional reserves that are less
certain to be recovered than probable reserves. It is unlikely that
the actual remaining quantities recovered will exceed the sum of
the estimated proved plus probable plus possible reserves.
Cumulative Production is the cumulative quantity of petroleum
that has been recovered at a given date.
Resources encompasses all petroleum quantities that originally
existed on or within the earth's crust in naturally occurring
accumulations, including Discovered and Undiscovered (recoverable
and unrecoverable) plus quantities already produced. "Total
resources" is equivalent to "Total Petroleum Initially-In-Place".
Resources are classified in the following categories:
Total Petroleum Initially-In-Place ("TPIIP") is that quantity of
petroleum that is estimated to exist originally in naturally
occurring accumulations. It includes that quantity of petroleum
that is estimated, as of a given date, to be contained in known
accumulations, prior to production, plus those estimated quantities
in accumulations yet to be discovered.
Discovered Petroleum Initially-In-Place ("DPIIP") is that
quantity of petroleum that is estimated, as of a given date, to be
contained in known accumulations prior to production. The
recoverable portion of discovered petroleum initially in place
includes production, reserves, and contingent resources; the
remainder is unrecoverable.
Contingent Resources are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
known accumulations using established technology or technology
under development but which are not currently considered to be
commercially recoverable due to one or more contingencies.
Contingences may include such factors as economic, legal,
environmental, political and regulatory matters or a lack of
markets. It is also appropriate to classify as Contingent Resources
the estimated discovered recoverable quantities associated with a
project in the early evaluation stage.
Undiscovered Petroleum Initially-In-Place ("UPIIP") given date,
to be contained in accumulations yet to be petroleum initially in
place is referred to as "prospective is that quantity of petroleum
that is estimated, on a discovered. The recoverable portion of
undiscovered resources" and the remainder as "unrecoverable."
Prospective Resources are those quantities of petroleum
estimated, as of a given date, to be potentially recoverable from
undiscovered accumulations by application of future development
projects. Prospective resources have both an associated chance of
discovery and a chance of development.
Unrecoverable is that portion of DPIIP and UPIIP quantities
which is estimated, as of a given date, not to be recoverable by
future development projects. A portion of these quantities may
become recoverable in the future as commercial circumstances change
or technological developments occur; the remaining portion may
never be recovered due to the physical/chemical constraints
represented by subsurface interaction of fluids and reservoir
rocks.
Uncertainty Ranges are described by the Canadian Oil and Gas
Evaluation Handbook as low, best, and high estimates for reserves
and resources. The Best Estimate is considered to be the best
estimate of the quantity that will actually be recovered. It is
equally likely that the actual remaining quantities recovered will
be greater or less than the best estimate. If probabilistic methods
are used, there should be at least a 50 percent probability (P50)
that the quantities actually recovered will equal or exceed the
best estimate.
Information Regarding Disclosure on Oil and Gas Reserves,
Resources and Operational Information
All amounts in this news release are stated in Canadian dollars
unless otherwise specified. Throughout this press release, the
terms Boe (barrels of oil equivalent), Mmboe (millions of barrels
of oil equivalent), and Tcfe (trillion cubic feet of gas
equivalent) are used. Such terms when used in isolation, may be
misleading. Where applicable, natural gas has been converted to
barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE and oil and
liquids have been converted to natural gas equivalent on the basis
of 1 bbl:6 mcfe. The BOE rate is based on an energy equivalent
conversion method primarily applicable at the burner tip, and 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 the 6:1 conversion ratio, utilizing the 6:1
conversion ratio may be misleading as an indication of value. The
BOE rate is based on an energy equivalent conversion method
primarily applicable at the burner tip and does not represent a
value equivalent at the wellhead. In accordance with Canadian
practice, production volumes and revenues are reported on a company
gross basis, before deduction of Crown and other royalties, unless
otherwise stated. Unless otherwise specified, all reserves volumes
in this news release (and all information derived therefrom) are
based on "company gross reserves" using forecast prices and costs.
Our oil and gas reserves statement for the year-ended December 31,
2012 includes complete disclosure of our oil and gas reserves and
other oil and gas information in accordance with NI 51- 101, and is
contained within our Annual Information Form which is available on
our SEDAR profile at www.sedar.com.
This news release contains references to estimates of oil and
gas classified as TPIIP and DPIIP in the Montney region in
northeastern British Columbia which are not, and should not be
confused with, oil and gas reserves. See "Definitions of Oil and
Gas Resources and Reserves". TPIIP, DPIIP and UPIIP have been
estimated using a zero percent porosity cutoff.
Projects have not been defined to develop the resources in the
Evaluated Areas as at the evaluation date. Such projects, in the
case of the Montney resource development, have historically been
developed sequentially over a number of drilling seasons and are
subject to annual budget constraints, Crew's policy of orderly
development on a staged basis, the timing of the growth of third
party infrastructure, the short and long-term view of Crew on gas
prices, the results of exploration and development activities of
Crew and others in the area and possible infrastructure capacity
constraints. As with any resource estimates, the evaluation will
change over time as new information becomes available.
Crew's belief that it will establish significant additional
reserves over time with the conversion of Prospective Resource into
Contingent Resource, Contingent Resource into probable reserves and
probable reserves into proved reserves is a forward looking
statement and is based on certain assumptions and is subject to
certain risks, as discussed below under the heading "Forward
Looking Information and Statements".
Cautionary Statements
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" "forecast" 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 volume and product mix of Crew's oil and gas
production; production estimates including 2013 forecast average
production; the recognition of significant resources under the
heading "Northeast British Columbia Montney Resource Evaluation";
future oil and natural gas prices and Crew's commodity risk
management programs; future liquidity and financial capacity;
projected debt levels; future results from operations and operating
metrics; management's expectations in regards to waterfloods at
Princess; 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 number
of potential drilling locations; the amount and timing of capital
projects; operating costs; the total future capital associated with
development of reserves and resources; and methods of funding our
capital program.
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. There are a number of assumptions associated with the
potential of resource volumes assigned to the Evaluated Areas
including the quality of the Montney reservoir, future drilling
programs, continued performance from existing wells and performance
of new wells, the growth of infrastructure, well density per
section, and recovery factors and discovery and development
necessarily involves known and unknown risks and uncertainties,
including those identified in this press release.
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; the early stage of
development of some areas in the Evaluated Areas; the potential for
variation in the quality of the Montney formation; 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.
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".
Financial statements and Management's Discussion and Analysis
for the three month periods ended March 31, 2013 and 2012 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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