Crew Energy Inc. Announces First Quarter 2014 Financial and
Operating Results and Updates Its Montney Resource Evaluation
CALGARY, ALBERTA--(Marketwired - May 7, 2014) - Crew Energy Inc.
("Crew" or the "Company") (TSX:CR) of Calgary, Alberta is pleased
to present its operating and financial results for the three month
period ended March 31, 2014.
Highlights
- Funds from operations in the first quarter increased 52% over
the first quarter of 2013 and 8% over the prior quarter to $51.8
million while the funds from operations netback increased by
40%;
- Funds from operations per diluted share increased 50% over the
first quarter of 2013 and increased 5% over the previous quarter to
$0.42 per share;
- First quarter production was previously announced on April 9,
2014 and averaged 28,021 boe per day, an 8% increase over the same
period in 2013 and a 2% decrease from the previous quarter;
- Operating netbacks improved 55% over the first quarter of 2013
to $28.49 per boe, before risk management losses, as a result of
improved commodity prices and lower costs;
- Operating costs per boe decreased 6% over the same period in
2013 to $11.35 per boe;
- Crew completed and tied-in two wells at Septimus that are
producing into the Company's gathering system averaging 1,200 boe
per day and 1,180 boe per day (16% ngl);
- The Company updated its Montney Resource Evaluation which
increased 20% to 109 TCFE of Total Petroleum Initially in Place
("TPIIP") and the Contingent Resource increased 44% to 5.0
TCFE;
- Crew added strategic production, reserves, land and
infrastructure in northeast British Columbia acquiring 1,400 boe
per day of production, 8.5 million boe of proved plus probable
reserves, 75 net sections of Montney rights and over 130 kilometers
of pipelines and 6,000 hp of field compression for $105
million;
- Subsequent to the quarter end, Crew announced the disposition
of approximately 7,000 boe per day of production concentrated in
the Deep Basin area of Alberta, 254,000 net acres of land and 60.4
million boe of proved plus probable reserves for $222 million in
cash plus approximately 400 boe per day of heavy oil
production.
|
|
|
|
|
Financial ($ thousands, except per share amounts) |
Three months ended March 31, 2014 |
|
Three months ended March 31, 2013 |
|
Petroleum and natural gas sales |
130,368 |
|
91,267 |
|
Funds from operations (note 1) |
51,810 |
|
34,188 |
|
|
Per share |
|
|
|
|
|
|
-
basic |
0.43 |
|
0.28 |
|
|
|
-
diluted |
0.42 |
|
0.28 |
|
Net loss |
(129,693 |
) |
(22,047 |
) |
|
Per share |
|
|
|
|
|
|
-
basic |
(1.07 |
) |
(0.18 |
) |
|
|
-
diluted |
(1.07 |
) |
(0.18 |
) |
|
|
|
|
|
Exploration and Development expenditures |
66,140 |
|
65,252 |
|
Property acquisitions (net of dispositions) |
102,532 |
|
14,663 |
|
Net capital expenditures |
168,672 |
|
79,915 |
|
Capital Structure ($ thousands) |
As at March 31, 2014 |
|
As at December 31, 2013 |
|
Working capital deficiency (note 2) |
53,121 |
|
40,098 |
|
Net assets held for sale (note 3) |
(231,677 |
) |
- |
|
Bank loan |
301,212 |
|
197,688 |
|
|
122,656 |
|
237,786 |
|
Senior unsecured notes |
145,785 |
|
145,623 |
|
Total net debt |
268,441 |
|
383,409 |
|
|
|
|
|
|
Bank facility after closing of the Alberta Gas
Disposition |
350,000 |
|
420,000 |
|
Common Shares Outstanding (thousands) |
121,679 |
|
121,635 |
|
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 accretion of deferred
financing charges. 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 shown above includes accounts receivable
less accounts payable and accrued liabilities. |
(3) |
Net
assets held for sale reflects the amounts reclassified from
property, plant and equipment and decommissioning obligations for
the assets less liabilities associated with the Alberta Gas
Disposition as described below. |
|
|
Operations |
Three months ended March 31, 2014 |
|
Three months ended March 31, 2013 |
|
|
|
|
|
|
Daily production (note 1) |
|
|
|
|
|
Princess and other oil (bbl/d) |
3,298 |
|
4,936 |
|
|
Lloydminster oil (bbl/d) |
6,128 |
|
5,441 |
|
|
Natural gas liquids (bbl/d) |
3,435 |
|
2,984 |
|
|
Natural gas (mcf/d) |
90,959 |
|
75,597 |
|
|
Oil
equivalent (boe/d @ 6:1) |
28,021 |
|
25,961 |
|
Average prices (notes 1 & 2) |
|
|
|
|
|
Princess and other oil ($/bbl) |
81.81 |
|
64.36 |
|
|
Lloydminster oil ($/bbl) |
69.50 |
|
50.61 |
|
|
Natural gas liquids ($/bbl) |
64.59 |
|
54.43 |
|
|
Natural gas ($/mcf) |
5.84 |
|
3.42 |
|
|
Oil
equivalent ($/boe) |
51.69 |
|
39.06 |
|
Netback ($/boe) |
|
|
|
|
|
Revenue |
51.69 |
|
39.06 |
|
|
Realized commodity hedging loss |
(3.47 |
) |
(0.55 |
) |
|
Royalties |
(10.63 |
) |
(7.41 |
) |
|
Operating costs |
(11.35 |
) |
(12.03 |
) |
|
Transportation costs |
(1.22 |
) |
(1.25 |
) |
|
Operating netback (note 3) |
25.02 |
|
17.82 |
|
|
G&A |
(2.13 |
) |
(1.99 |
) |
|
Interest on long-term debt |
(2.36 |
) |
(1.19 |
) |
|
Funds
from operations |
20.53 |
|
14.64 |
|
|
|
|
|
|
Drilling Activity |
|
|
|
|
|
Gross
wells |
21 |
|
39 |
|
|
Working interest wells |
19.0 |
|
36.8 |
|
|
Success rate, net wells |
100 |
% |
100 |
% |
Notes:
(1) |
Princess, Alberta oil (20 degree to 26 degree 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 gains and losses on financial instruments. |
(3) |
Operating netback equals petroleum and natural gas sales including
realized hedging gains and losses on commodity based financial
instruments 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 continued to execute on its corporate strategy in the first
quarter culminating in the closing of two separate transactions
that resulted in the Company acquiring certain strategic Montney
liquids rich natural gas properties in northeast British Columbia
for approximately $105 million (the "Montney Acquisition"). The
acquired assets include 75 net sections of land that are either
contiguous with existing Crew land or increase Crew's working
interest in joint interest lands. The acquired lands include
production of 1,400 boe per day of predominantly natural gas
production and 8.5 million boe of proved plus probable reserves.
Subsequent to the end of the first quarter, Crew entered into an
agreement to sell certain petroleum and natural gas assets
including approximately 7,000 boe per day of 75% natural gas
production and 60.4 mmboe of proved plus probable reserves focused
primarily in the Deep Basin of Alberta (the "Alberta Gas
Disposition"). Consideration for the Alberta Gas Disposition will
include approximately $222 million in cash, before closing
adjustments, plus approximately 400 bbls per day of heavy oil
production. This disposition is scheduled to close on or about May
30, 2014, subject to satisfaction of customary industry closing
conditions. In conjunction with the announcement of these
transactions, the Company increased its 2014 capital budget to $285
million with the incremental $39 million directed exclusively to
the Company's Montney resource development and an acceleration of
Crew's Montney five year growth plan.
As previously announced, Crew's first quarter production
averaged 28,021 boe per day as the severe winter weather along with
an unusual number of wells temporarily shut-in due to third party
drilling operations in the Lloydminster area impacted volumes by
approximately 1,000 boe per day. Toward the end of March, the
majority of the Company's 21 (19.0 net) wells drilled in the
quarter came on production resulting in the Company achieving field
estimated production rates of 30,400 boe per day in the month of
April (inclusive of the 1,400 boe per day acquired at the end of
March) consistent with budget expectations. During the first
quarter, exploration and development capital expenditures were
$66.1 million allocated $35.0 million to the northeast British
Columbia Montney, $15.4 million to Princess Mannville development,
$13.8 million to Lloydminster and $1.9 million to the Deep Basin
and Other Alberta areas.
FINANCIAL
Crew's first quarter funds from operations increased 8% over the
prior quarter and 52% over the same period in 2013 to $51.8 million
or $0.42 per diluted share. The Company's funds from operations
benefited from stronger oil and natural gas pricing experienced
during the quarter that were partially offset by a $8.7 million
realized loss on the Company's risk management program. The
Company's $130 million first quarter net loss was impacted by
realized and unrealized losses of $27.8 million incurred on the
Company's risk management program and a non-cash impairment charge
of $153.5 million on assets related to the Alberta Gas Disposition
that have been reclassified as held for sale.
An extended cold winter across North America has reduced natural
gas storage levels to 52% below last year's level and 55% below the
five year gas storage average level. Natural gas prices continue to
reflect the reduced storage levels as the Company's realized
natural gas price increased 53% over the previous quarter to
average $5.84 per mcf for the first quarter of 2014. Oil prices
strengthened during the quarter as the discount for Canadian heavy
oil, measured as the Western Canadian Select ("WCS") price
differential to West Texas Intermediate ("WTI"), narrowed to
average CDN$25.55 per bbl as compared to CDN$33.89 for the previous
quarter. A number of positive catalysts provided support for the
increase in WCS oil prices including increased crude-by-rail
exports and increased rail loading facilities and expansions
scheduled for 2014.
The Company's hedging strategy is focused on protecting against
significant declines in commodity prices that would negatively
impact the funds from operations needed to fund the Company's
on-going capital program. Strengthening commodity prices have
significantly affected Crew's realized and unrealized losses from
its risk management program in the first quarter of 2014. In the
first quarter, the Company incurred a realized hedging loss of $8.7
million or $3.47 per boe as compared to $1.3 million or $0.55 per
boe in the same period in 2013. During the first quarter of 2014,
the Company also incurred unrealized losses on financial
instruments of $19.0 million.
The Company had a successful first quarter exploration and
development program which saw Crew spend $66.1 million focusing on
development of liquids rich natural gas from the Montney formation
at Septimus. Quarter-end net debt totaled $268 million which
included a reclassification of the Alberta Gas Disposition assets
from property, plant and equipment to current assets held for sale.
Following the closing of the Alberta Gas Disposition, the Company's
bank facility will be renewed at $350 million.
OPERATIONS
UPDATE
Septimus/Tower, British Columbia
Crew achieved the fourth consecutive quarter of production
growth at Septimus with average production of 10,140 boe per day
and a March average of 10,650 boe per day as new wells in the
quarter were brought on during the month and with the Septimus gas
plant running at 95% to 102% of projected capacity. With sub-$5 per
boe operating costs, an attractive and improving royalty structure
and improved pricing, the operating netback at Septimus has
increased 62% to $29.42 per boe compared to the first quarter of
2013 levels. The Company projects that an annual capital program of
$40 to $50 million is required to maintain the Septimus gas plant
at capacity and combined with the current pricing environment this
would result in $40 to $50 million of annual free cash flow being
generated from this first phase of Crew's Montney development.
Future economics have been further enhanced with the announcement
of a second tier to the British Columbia Deep Well Credit Program
effective April 1, 2014. Based on this addition to the program the
majority of Crew's Montney liquids rich natural gas drilling
program will now qualify resulting in an increased NPV10 of
approximately $0.8 million per well.
During the quarter, Crew conducted a second production test on
the Montney oil exploration well drilled in the fourth quarter of
2013 located 11 kilometers northwest of the Company's existing
Montney oil production. Following an 80 day shut in period, the
well was brought back on production for an 11 day test during which
it produced an average of 540 barrels of oil per day and 1.1 mmcf
per day of natural gas for a total average rate of 723 boe per day.
The well is expected to be tied into Crew's gathering system in the
third quarter. The Company is planning to begin drilling its first
well of a six well pad at Tower in June.
At Septimus, Crew drilled five (5.0 net) horizontal wells in the
quarter with two of the wells on production at 6 to 8 mmcf per day
as of the end of the quarter. With the evolution of the Company's
development strategy to pad drilling to capture additional cost
efficiencies, Crew is currently drilling the third well on a six
well pad which is expected to be completed in the third quarter and
will be brought on production following the planned turnaround at
the Septimus gas plant in August. A second rig is operating in the
Groundbirch area where the Company is drilling the second well on a
two well pad. These wells are expected to be completed and tested
in the third quarter along with one of the Attachie wells drilled
in 2013. Crew also began ordering major equipment for the second
Septimus facility anticipated to be on stream mid-2015 with a
designed capacity of 60 mmcf per day of raw gas.
Lloydminster, Alberta/Saskatchewan
At Lloydminster, Crew drilled nine (7.6 net) oil wells and
recompleted 16 (15.1 net) wells for $10.8 million. Production for
the quarter averaged 6,150 boe per day and the Company is expecting
to maintain production in the 6,000 boe per day range throughout
the year with total capital expenditures of $35 million.
Princess, Alberta
During the first quarter, production at Princess averaged 3,950
boe per day as the majority of the wells in the Company's first
quarter drilling program came on production early in the second
quarter. Current production is approximately 4,500 boe per day
based on field estimates with new wells still being optimized. Crew
drilled six (6.0 net) wells with total capital expenditures of $14
million including well optimizations. The first quarter drilling
program targeted new Mannville opportunities on the Company's Crown
acreage and represents the first phase of delineation of a number
of these lands. Crew is projecting to maintain production in the
4,000 to 4,500 boe per day range throughout the year as the Company
continues to delineate its Mannville acreage.
Deep Basin, Alberta
Crew's Deep Basin and other minor Alberta properties produced an
average of 7,220 boe per day during the quarter. Crew has announced
an agreement to sell these assets pursuant to the Alberta Gas
Disposition with an anticipated closing date of May 30, 2014.
OUTLOOK
With the announced Alberta Gas Disposition, the Company revised
forecasted 2014 average production to 25,500 to 26,500 boe per day
and forecasts to exit the year at 26,000 to 27,000 boe per day,
subject to closing the disposition on May 30, 2014. Exploration and
development capital expenditures are now budgeted at $285 million,
a $39 million increase over the previous budget. Net debt after
closing of the transaction is forecasted to be approximately $280
million.
For the remainder of 2014, Crew plans to:
- Continue to develop and delineate our Montney resource which is
now over 109 TCFE of TPIIP and 5.0 TCFE of Contingent
Resource;
- Apply new and evolving drilling and completion technologies to
improve Expected Ultimate Recoveries and initial production
rates;
- Invest in Montney production infrastructure which is estimated
at $35 million in 2014 in addition to pre-drilling the majority of
the 18 wells planned to initially fill the new 60 mmcf per day
facility;
- Evaluate the Montney potential at Crew's Attachie, Groundbirch
and Tower, British Columbia properties;
- Continue to high-grade our asset base and consolidate acreage
in the Montney in northeast British Columbia;
- Maintain aggregate production levels at Lloydminster and
Princess with free funds from operations to be distributed to our
Montney growth initiatives.
Our 2014 capital program has positioned the Company with an
expanded resource and drilling inventory, important infrastructure
as well as land that is strategic to our future growth plans.
Crew's five year growth plan anticipates the construction of
facilities to process 240 mmcf per day of natural gas and 10,000
bbls per day of light oil with targeted exit 2018 Montney
production of approximately 45,000 boe per day.
We would like to thank our employees and Board of Directors for
their steadfast commitment to Crew's success and our shareholders
for their continued support. We are excited about our prospects and
future and look forward to reporting our second quarter operating
and financial results in August.
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
April 30, 2014, prepared in accordance with the Canadian Oil and
Gas Evaluation Handbook ("COGE Handbook"). Unless indicated
otherwise in this news release, all references to Contingent and
Prospective Resource volumes are Best Estimate Contingent and
Prospective Resource volumes.
Sproule was engaged to conduct an updated independent Montney
resource evaluation of Crew's 452 net Montney sections located in
Northeast British Columbia ("NEBC") (the "Evaluated Areas")
effective as of April 30, 2014 (the "Resource Evaluation"). The
Resource Evaluation confirms the development and resource potential
on the Company's land base providing us with significant
opportunities to add reserves above the current booked reserves and
to increase the current Contingent Resource. The commodity
diversity of 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.
TPIIP in the Montney "gas window" increased to 60.6 TCF from
44.6 TCF due to the Montney Acquisition completed in the first
quarter. The Resource Evaluation also included recognition of
Crew's lands in the Montney "oil window" where Crew has 138 net
sections. On the oil bearing lands, TPIIP increased from 7.8
billion barrels of oil to 8.1 billion barrels of oil. The tight
Montney oil potential is in the early stages of development and
requires additional data to realize the recoverable potential of
these lands. The continued improvement of technology and the early
results are very encouraging to the recovery of this vast
resource.
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 60.6 TCF and 8.1 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.
Natural Gas Resource Categories (1)(2)(3) |
Tcf |
Total
Petroleum Initially In Place (TPIIP) |
60.6 |
Discovered Petroleum Initially In Place (DPIIP) |
26.1 |
Undiscovered Petroleum Initially In Place (UPIIP) |
34.5 |
(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 276 net sections in the gas window at April 30,
2014. |
|
|
Oil Resource Categories (1)(2)(3)(4) |
Mmbbls |
Total
Petroleum Initially In Place (TPIIP) |
8,052 |
Discovered Petroleum Initially In Place (DPIIP) |
1,363 |
Undiscovered Petroleum Initially In Place (UPIIP) |
6,689 |
(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 138 net sections in the oil window at April 30,
2014. |
|
|
Reserves and Contingent Resources (1)(2)(3)(6)(7) |
Best Estimate |
|
|
Natural gas (Tcf) |
|
|
Reserves (3) |
0.5 |
|
Contingent Resources |
4.0 |
|
|
Natural gas liquids (Mmbbls) (4)(5) |
|
|
Reserves (3) |
14.7 |
|
Contingent Resources |
160.7 |
|
|
Oil (Mmbbls) |
|
|
Reserves (3) |
0.4 |
|
Contingent Resources |
10.9 |
(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, 2013. |
(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) |
There
is no certainty that it will be commercially viable to produce any
of the resources. |
(7) |
Contingent Resources includes an 85% development factor. |
|
|
Prospective Resources (1)(2)(5)(6) |
Best Estimate |
|
|
Natural gas (Tcf) |
6.3 |
Natural gas liquids (Mmbbls) (3)(4) |
254.4 |
Oil (Mmbbls) |
14.4 |
(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. |
(3) |
The
liquid yields are based on average yield over the producing life of
the property. |
(4) |
Liquid yields are unique to each area. They are estimated based on
gas composition of gas samples in the area and expected plant
recoveries. |
(5) |
There
is no certainty that it will be commercially viable to produce any
of the resources. |
(6) |
Prospective Resources includes an 85% development factor. |
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. 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. Crew anticipates that a large
portion of the Contingent Resources will be economically viable to
develop. 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.
Contingencies 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") is that
quantity of petroleum that is estimated, on a given date, to be
contained in accumulations yet to be discovered. The recoverable
portion of undiscovered petroleum initially in place is referred to
as "prospective 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,
2013 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 proved
plus probable reserves attributed to the assets acquired by the
Company pursuant to the Montney Acquisition. Such reserves reflect
Company internally estimated "gross" reserves prepared by a
qualified reserves evaluator effective December 31, 2013 in
accordance with the definitions and provisions contained in the
COGE Handbook. Estimates of proved plus probable reserves contained
herein attributed to the assets being disposed of pursuant to the
Alberta Gas Disposition reflect "gross" reserves assigned by the
Company's independent reserves evaluator, Sproule Associates
Limited, effective December 31, 2013.
This news release contains references to estimates of oil
and gas classified as TPIIP, DPIIP, UPIIP and Contingent Resources
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: completion of the Alberta Gas
Disposition and the timing thereof and anticipated benefits to be
derived therefrom; the effect of the Alberta Gas Disposition on
continuing operations and plans to expand the 2014 capital program
on a post-transaction basis; forecasted net debt after closing of
the Alberta Gas Disposition; the volume and product mix of Crew's
oil and gas production; production estimates including 2014
forecast average and exit productions; 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; future results from operations and operating
metrics; anticipated reductions in operating costs and potential to
improve ultimate recoveries and initial production rates; 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 anticipated timing
of the new Septimus facility; the total future capital associated
with development of reserves and resources; and methods of funding
our capital program, including possible non-core asset divestitures
and asset swaps. In this news release reference is made to the
Company's five year growth plan including future processing
capacity in Northeast British Columbia and a 2018 Montney
production target of 45,000 boe per day which are not estimates or
forecasts of rates that may actually be achieved. Such information
reflects internal projections used by management for the purposes
of making capital investment decisions and for internal long range
planning and budget preparation. Accordingly, undue reliance should
not be placed on same.
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: that all conditions
to closing of the Alberta Gas Disposition are satisfied or waived;
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 and the funding
thereof, 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 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.
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.
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 period ended March 31, 2014 and 2013 will be
filed on SEDAR at www.sedar.com and are available on the Company's
website at www.crewenergy.com.
Crew Energy Inc.Dale ShwedPresident and C.E.O.(403)
231-8850dale.shwed@crewenergy.comCrew Energy Inc.John LeachSenior
Vice President and C.F.O.(403)
231-8859john.leach@crewenergy.comCrew Energy Inc.Rob MorganSenior
Vice President and C.O.O.(403)
513-9628rob.morgan@crewenergy.comwww.crewenergy.com
Crew Energy (TSX:CR)
Historical Stock Chart
From May 2024 to Jun 2024
Crew Energy (TSX:CR)
Historical Stock Chart
From Jun 2023 to Jun 2024