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.
FOR FURTHER INFORMATION PLEASE CONTACT:
Crew Energy Inc.
Dale Shwed
President and C.E.O.
(403) 231-8850
dale.shwed@crewenergy.com
Crew Energy Inc.
John Leach
Senior Vice President and C.F.O.
(403) 231-8859
john.leach@crewenergy.com
Crew Energy Inc.
Rob Morgan
Senior Vice President and C.O.O.
(403) 513-9628
rob.morgan@crewenergy.com
www.crewenergy.com
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