Crew Energy Inc. (TSX:CR) of Calgary, Alberta is pleased to present its
operating and financial results for the three and nine month periods ended
September 30, 2010.
Highlights
- Third quarter funds from operations of $24.1 million was 23% higher than the
third quarter of 2009;
- Production of 13,061 boe per day was 8.4% higher than the second quarter of 2010;
- During the quarter, Crew had three vertical exploration oil discoveries at
Princess that tested at rates of 1,330, 1,170 and 345 bbls of oil per day which
has led to an expanded resource and drilling inventory significantly expanding
the play;
- Operating costs per boe have decreased 12% over the third quarter of 2009;
- Crew finalized a restructured agreement with Aux Sable Canada ("ASC") that
will result in ASC funding the expansion of the Septimus gas plant scheduled to
be completed in late 2010.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
Financial ended ended ended ended
($ thousands, except per share September September September September
amounts) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Petroleum and natural gas sales 44,924 38,510 149,723 124,183
Funds from operations (note 1) 24,104 19,640 73,014 56,197
Per share - basic 0.30 0.25 0.92 0.76
- diluted 0.29 0.25 0.90 0.76
Net income (loss) (7,387) (7,376) (7,636) (28,661)
Per share - basic (0.09) (0.09) (0.10) (0.39)
- diluted (0.09) (0.09) (0.10) (0.39)
Exploration and development
investment 65,138 35,390 187,522 73,255
Property acquisitions (net of
dispositions) - - (132,640) (34,378)
Net capital expenditures 65,138 35,390 54,882 38,877
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at As at
Capital Structure Sept. 30, Dec. 31,
($ thousands) 2010 2009
----------------------------------------------------------------------------
Working capital deficiency (note 2) 36,132 46,654
Bank loan 110,770 135,601
Net debt 146,902 182,255
Bank facility 210,000 250,000
Common Shares Outstanding (thousands) 80,206 78,152
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital, asset
retirement 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 Canadian Generally Accepted Accounting Principles 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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
Operations 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 48,188 49,478 49,863 54,314
Oil (bbl/d) 3,803 3,376 3,788 3,447
Natural gas liquids (bbl/d) 1,227 1,443 1,265 1,345
Oil equivalent (boe/d @ 6:1) 13,061 13,065 13,364 13,844
Average prices (note 1)
Natural gas ($/mcf) 4.07 3.23 4.63 4.04
Oil ($/bbl) 62.86 63.91 67.16 55.61
Natural gas liquids ($/bbl) 43.21 29.94 50.13 32.16
Oil equivalent ($/boe) 37.39 32.04 41.04 32.86
Netback ($/boe)
Operating netback (note 2) 21.87 17.77 22.32 16.67
Realized gain on financial
instruments (note 3) (0.24) (1.20) (0.15) (0.52)
G&A 1.05 1.10 1.25 1.13
Interest and other 0.99 1.54 1.20 1.19
Funds from operations 20.07 16.33 20.02 14.87
Drilling Activity
Gross wells 26 12 59 20
Working interest wells 24.9 12.0 55.4 14.8
Success rate, net wells 100% 100% 100% 99%
Notes:
(1) Average prices are before deduction of transportation costs and do not
include realized gains and losses on financial instruments.
(2) 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 Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
(3) Amount includes realized gains and losses on non-commodity financial
instruments.
OVERVIEW
Operations during the third quarter of 2010 were highlighted by the drilling of
a record 26 (24.9 net) horizontal wells with 100% success. At Princess, Alberta,
the Company drilled sixteen (16.0 net) oil wells and four (4.0 net) salt water
disposal wells. In northeast British Columbia, three (3.0 net) liquids rich
natural gas wells were drilled at Septimus, and two (1.5 net) exploration wells
were drilled at the Company's Portage and Goose properties. In addition, a third
party drilled one (0.4 net) horizontal farmout well at Pine Creek, Alberta
targeting the Spirit River formation.
Production in the third quarter was 13,061 boe per day, up 8.4% from the second
quarter. Wet weather in the Princess area continued to hamper all operations,
particularly completion and tie-in of previously drilled wells. By the end of
the third quarter, fourteen wells were waiting to be placed on production at
Princess and three liquids rich gas wells at Septimus.
Crew continued to add to its land base in the third quarter, purchasing 7.4 net
sections of land for $1.65 million. These lands expanded our presence in
resource plays at Pine Creek (Cardium) and Boudreau, British Columbia (Montney)
and a new exploration area.
FINANCIAL SUMMARY
Cash flow for the third quarter increased 16.5% over the second quarter of 2010
as a result of the 8.4% increase in production and a 12% reduction in costs
combined with a $5.1 million third quarter gain on the Company's hedging
program. Year to date the Company's hedging program has added $9.7 million of
cash flow to help fund the 2010 capital program. For the fourth quarter of 2010,
the Company has an average of 17.5 mmcf per day of natural gas hedged at an
average fixed price of $6.25 per mcf and 3,400 bbl per day of oil hedged at a
minimum floor price of Canadian dollar WTI $81.70 per bbl.
The Company has also established commodity hedges to help secure cash flow for
2011. Crew has entered into Canadian dollar WTI oil price swaps and floors on an
average of 3,000 bbl per day for 2011. These transactions averaged a minimum
floor price of approximately CDN $85.80 per bbl for WTI oil. The Company has
also entered into a number of cross commodity transactions to enhance natural
gas prices for 2011. These transactions have included the sale of financial
calls against the price on 1,000 bbls per day of 2012 WTI oil at an average call
price of US$87.50 per bbl. The proceeds from the sale of these calls were used
to financially fix the price on 9.4 mmcf per day of natural gas at an average
AECO NIT price of approximately $5.30 per mcf. A detailed list of the Company's
hedge positions is included in the attached management's discussion and
analysis.
The Company's capital program during the third quarter resulted in total
expenditures for the quarter of $65.1 million. These expenditures were financed
primarily through a combination of funds flow from operations and an increase in
the Company's net debt. Total net debt at the end of the quarter was $147
million. Subsequent to the quarter end, Crew's banking syndicate re-confirmed
the Company's banking facility at total borrowing capacity of $210 million.
OPERATIONS UPDATE
Pekisko Play, Princess, Alberta
Crew plans to drill a total of 50 oil wells in 2010 at Princess out of a current
inventory of over 700 locations with a targeted 2010 exit rate of 7,000 to 8,000
boe per day. Drilling results have exceeded expectations as the Company expands
its activities at Princess.
Crew now has 30 horizontal oil wells on production and an expected 22 additional
wells to be placed on production before year end. Confidence in the play
continues to build with additional production history and positive recent test
rates. Initial production rates for the thirty wells on production averaged 210
boe per day. After six months of production, wells are averaging 150 boe per day
and after one year of production, wells are producing on average 145 boe per
day. Two wells have two years of production history and are currently producing
an average of 110 boe per day which is 95% oil.
Crew's vertical exploration well program has been very successful and continues
to expand the size of the prospective lands under Crew's control. Crew tested
three vertical exploration wells which, on initial test, produced marginal
volumes of oil however, after acid stimulation, these wells exhibited extremely
prolific test results. The first exploration test flowed at 1,330 bbls of oil
per day and gas at 500 mcf per day after three days. The second exploration test
flowed at 345 bbls of oil per day and gas at 350 mcf per day after three days
and the third exploration well swabbed oil at 1,170 bbls of oil per day after a
three day test. These results are representative of the growing geographic
expanse of the Pekisko play and its excellent reservoir quality.
The Pekisko play is in its infancy and Crew continues to learn and experiment
with a variety of drilling, completion and production practices in an effort to
optimize production and capital efficiency. The Company has fracture stimulated
older vertical wells with sand or acid and has seen oil production increased an
average of five times their previous production rates. Crew plans to continue
with its optimization and stimulation program in the fourth quarter and into
2011, expanding the scope to include horizontal wells.
Fluid handling and operating pressures are important variables in the operations
at Princess. In 2010 and 2011, Crew plans to dedicate capital for a significant
infrastructure build out to accommodate several years of future growth. This is
expected to reduce operating costs and reduce pipeline pressures enabling wells
to produce at higher rates for longer periods of time. An illustration of the
effect of flowing pressures is Crew's 8-8 well (one of Crew's first horizontal
wells) which exhibited a 65% increase in production from 90 boe per day to 150
boe per day once a new pipeline had been installed reducing area operating
pressures.
Montney Play, Septimus, British Columbia
Crew drilled three (3.0 net) liquids rich gas wells in the Montney formation at
Septimus in the third quarter of 2010. These wells are scheduled to be completed
in the fourth quarter and expected to add 1,900 boe per day of production. Three
wells were brought on production in the third quarter, highlighted by one well
which had an average first full month of production rate of 7.7 mmcf per day.
Expansion of the Septimus gas processing facility, which will double its
capacity from its current capability of 25 mmcf per day, is proceeding as
planned, with expected commissioning in mid December. Aux Sable Canada ("ASC"),
the current owner of the facility, completed the installation of a 20 inch
pipeline from the Septimus gas facility to the Alliance pipeline in the third
quarter. This pipeline is capable of transporting over 350 mmcf per day of gas
and associated liquids.
Crew is pleased to announce that it has completed a restructuring of its
agreement with ASC whereby Crew will be reimbursed for the expansion cost of the
facility expected to be approximately $16.9 million. Crew will continue to
operate the expanded facility on ASC's behalf and process the majority of its
Septimus production through the facility in exchange for a processing and
operating fee. This transaction is expected to close by year end. Crew has also
retained an option to acquire a 50% interest in the facility prior to January 1,
2014 at a cost of 50% of the expanded facility construction cost. Reduced
operating costs at Septimus are primarily responsible for the 12% reduction in
corporate operating costs as compared with the same quarter in 2009. Septimus
operating costs are expected to be in the $6.00 per boe range in 2011.
In addition to Crew's activity at Septimus, the Company also drilled two (1.5
net) horizontal Montney exploration wells in the third quarter. At Portage, the
Company drilled one (0.5 net) well following up on its gas discovery at the
property in the second quarter. Positive results were experienced while drilling
and the well will be completed in the fourth quarter. In addition, one (1.0 net)
well was drilled at the Company's Goose property, with completion expected in
2011. Two (2.0 net) sections of land were purchased in the third quarter to add
to the Company's large 100% W.I. land base in this area.
During the third quarter, Crew also undertook the recompletion of a standing
vertical well at Tower. The Lower Montney was fracture stimulated in the well
and flowed at a test rate of 125 barrels of 42 degrees API oil per day and 70
mcf per day of natural gas. This is further verification of the oil prone nature
of the Company's lands at Tower which was initially identified by a partner
operated well drilled in the area in 2009 and completed in the Upper Montney. A
number of horizontal wells are planned to be drilled on this property in 2011
targeting Lower and Upper Montney oil.
Cardium Play, West Central Alberta
Crew owns 60 net sections of oil prone Cardium rights in the Edson-Pine Creek,
Alberta area. At Pine Creek, Crew has identified 80 net Cardium oil drilling
locations. Licensing of three Cardium horizontal wells at Pine Creek is expected
prior to year end, with drilling to commence in 2011.
In the third quarter, the first (0.33 net) of two Cardium horizontal farmout
wells at Edson was put on production at an initial rate of 272 boe per day (44%
oil). The second farmout well (0.5 net) was drilled recently and is currently
being completed.
Kobes, British Columbia
This 23 section 100% Crew controlled block is situated in the Kobes/Townsend
Montney rich fairway which has been de-risked by offsetting industry activity
and Crew's vertical completion in the heart of the Company's land base testing
at 2.5 mmcf per day of gas and 125 bbls per day of condensate. This acreage was
amassed at an average price of $609 per hectare prior to the recent run up in
area prices. The first expiries associated with this property occur in 2013.
Crew plans to drill two strategically situated horizontal wells which are
expected to continue the land beyond 2013 until 2018.
Portage, British Columbia
This 66 section contiguous block (50% Crew) has been continued for a further
five year term as a result of the Montney wells drilled by Crew under the
previously announced farm-in agreement. With the lands proven productive by
Crew's drilling activity, the earliest land expiries will not occur until 2015.
Horn River/Cordova Embayment, British Columbia
Crew's land base has been offset by industry activity that has yielded
production test rates of up to 11 mmcf per day. The Company's land base has been
continued indefinitely due to offsetting Devonian production which allows the
Company to monitor the infrastructure build out in the area and realize the
value of this resource at the appropriate time.
OUTLOOK
Business Environment
In a repeated theme, oil prices have remained relatively strong as the world's
economies continue their recovery. Natural gas prices, however, remain weak as
North American supplies continue to grow due to the aggressive development of
unconventional natural gas plays. As a result of this commodity price imbalance,
Crew has been focusing its capital and technical resources towards the pursuit
of growth of its oil and liquids production. The Company is in the enviable
position to quickly adapt to commodity price cycles in order to focus on oil or
liquids rich natural gas directed drilling. This was demonstrated in the third
quarter of 2010 with the Company drilling 20 net wells at Princess.
Despite the depressed natural gas price environment the Company's liquids rich
Septimus Montney production continues to show good economic returns. However,
the continued prospect of low natural gas prices combined with the inflating
cost of high pressure fracturing services has resulted in the economics of our
oil plays overwhelming the economics of our liquids rich natural gas plays. As
such, capital deployment for the fourth quarter of 2010 and 2011 is expected to
be largely dedicated toward oil directed drilling.
Active Fourth Quarter
Crew continues to catch up from the wet spring and summer with 22 wells at
Princess expected to be placed on production before year end. With current
production of approximately 5,500 boe per day and much improved weather
conditions at Princess, the Company expects to be producing 7,000 to 8,000 boe
per day at year end. In addition to the active drilling, completions and
infrastructure program, Crew is now actively engaged in an acid stimulation
program that has to date produced very encouraging results with three horizontal
well stimulations planned for the fourth quarter. Crew's three exploration
discoveries have converted land previously believed to be less prospective to
land that is now highly prospective with significant development potential.
Crew's net exploration and development expenditures are forecasted to be
approximately $225 million for 2010 with the majority spent at Princess. As a
result of the aforementioned persistent weather delays, Crew is forecasting
average 2010 production of 13,600 to 14,000 boe per day. Exit production is now
forecast to be 17,000 to 18,000 boe per day.
Crew's outlook continues to improve as the Company has significantly de-risked
the technical aspects and geographic scope of the Princess oil play. The Company
currently plans to dedicate the majority of its capital to this oil play
affording our shareholders exposure to, we believe, one of the most economically
attractive oil plays in North America. With the ability to switch to either
commodity, Crew is in an enviable position that offers our shareholders material
upside in oil and natural gas plays with scale and repeatability. We are very
excited about our drilling results as the success of the drilling program
continues to expand our production, hydrocarbon resource and drilling inventory.
We look forward to reporting our fourth quarter and year end results in 2011.
Management's Discussion and Analysis
ADVISORIES
Management's discussion and analysis ("MD&A") is the Company's explanation of
its financial performance for the period covered by the financial statements
along with an analysis of the Company's financial position. Comments relate to
and should be read in conjunction with the unaudited consolidated financial
statements of the Company for the three and nine month periods ended September
30, 2010 and 2009 and the audited consolidated financial statements and
Management Discussion and Analysis for the year ended December 31, 2009. The
consolidated financial statements have been prepared in accordance with
generally accepted accounting principles ("GAAP") in Canada and all figures
provided herein and in the December 31, 2009 consolidated financial statements
are reported in Canadian dollars.
Forward Looking Statements
This MD&A contains forward-looking statements. Management's assessment of future
plans and operations, drilling plans and the timing thereof, plans for the
tie-in and completion of wells and the timing thereof, capital expenditures,
timing of capital expenditures and methods of financing capital expenditures and
the ability to fund financial liabilities, production estimates, expected
commodity mix and prices and the impact on Crew, future operating costs, future
transportation costs, expected royalty rates, general and administrative
expenses, interest rates, debt levels, funds from operations and the timing of
and impact of adoption of IFRS and other accounting policies may constitute
forward-looking statements under applicable securities laws and necessarily
involve risks including, without limitation, risks associated with oil and gas
exploration, development, exploitation, production, marketing and
transportation, loss of markets, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks, competition
from other producers, inability to retain drilling rigs and other services,
incorrect assessment of the value of acquisitions, failure to realize the
anticipated benefits of acquisitions, the inability to fully realize the
benefits of acquisitions, delays resulting from or inability to obtain required
regulatory and partner approvals and ability to access sufficient capital from
internal and external sources. As a consequence, the Company's actual results
may differ materially from those expressed in, or implied by, the forward
looking statements. Forward looking statements or information are based on a
number of factors and assumptions 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 the Company can give no assurance that such
expectations will prove to be correct.
In addition to other factors and assumptions which may be identified in this
document and other documents filed by the Company, 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
ability of the Company to obtain qualified staff, regulatory and partner
approvals, equipment and services in a timely and cost efficient manner;
drilling results; the ability of the operator of the projects which the Company
has an interest in to operate the field in a safe, efficient and effective
manner; Crew's ability to obtain financing on acceptable terms; field production
rates and decline rates; the ability to reduce operating costs; the ability to
replace and expand oil and natural gas reserves through acquisition, development
or exploration; the timing and costs of pipeline, storage and facility
construction and expansion; the ability of the Company to secure adequate
product transportation; future petroleum and natural gas prices; currency,
exchange and interest rates; the regulatory framework regarding royalties, taxes
and environmental matters in the jurisdictions in which the Company operates;
and Crew's ability to successfully market its petroleum and natural gas
products. Readers are cautioned that the foregoing list of factors is not
exhaustive. Additional information on these and other factors that could affect
the Company's operations and financial results are included in reports on file
with Canadian securities regulatory authorities and may be accessed through the
SEDAR website (www.sedar.com) or at the Company's website (www.crewenergy.com).
Furthermore, the forward looking statements contained in this document are made
as at the date of this document and the Company does not undertake any
obligation to update publicly or to revise any of the included forward looking
statements, whether as a result of new information, future events or otherwise,
except as may be required by applicable securities laws.
Conversions
The oil and gas industry commonly expresses production volumes and reserves on a
"barrel of oil equivalent" basis ("boe") whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved analysis of results and comparisons with other industry participants.
Throughout this MD&A, Crew has used the 6:1 boe measure which is the approximate
energy equivalency of the two commodities at the burner tip. Boe does not
represent a value equivalency at the wellhead nor at the plant gate which is
where Crew sells its production volumes and therefore may be a misleading
measure, particularly if used in isolation.
Non-GAAP Measures
One of the benchmarks Crew uses to evaluate its performance is funds from
operations. Funds from operations is a measure not defined in GAAP that is
commonly used in the oil and gas industry. It represents cash provided by
operating activities before changes in non-cash working capital, asset
retirement expenditures and the transportation liability charge. The Company
considers it a key measure as it demonstrates the ability of the business to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Funds from operations should not be considered as
an alternative to, or more meaningful than cash provided by operating activities
as determined in accordance with GAAP as an indicator of the Company's
performance. Crew's determination of funds from operations may not be comparable
to that reported by other companies. Crew also presents funds from operations
per share whereby per share amounts are calculated using weighted average shares
outstanding consistent with the calculation of income per share. The following
table reconciles Crew's cash provided by operating activities to funds from
operations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Cash provided by operating activities 19,596 24,902 75,958 65,925
Asset retirement expenditures 201 196 906 478
Transportation liability charge
(note 1) 156 328 638 985
Change in non-cash working capital 4,151 (5,786) (4,488) (11,191)
----------------------------------------------------------------------------
Funds from operations 24,104 19,640 73,014 56,197
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(1) The amount for the nine months ended September 30, 2010 does not include
the transportation liability write-down of $344,000 as described in the
Transportation Costs section.
Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore, may not be
comparable with the calculation of similar measures for other entities.
Operating netback equals total petroleum and natural gas sales including
realized gains and losses on commodity contracts less royalties, operating costs
and transportation costs calculated on a boe basis. Management considers
operating netback an important measure to evaluate its operational performance
as it demonstrates its field level profitability relative to current commodity
prices.
RESULTS OF OPERATIONS
Production
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
September 30, 2010 September 30, 2009
Nat. Nat.
Oil Ngl gas Total Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta 3,670 388 22,243 7,765 3,194 880 33,606 9,675
British
Columbia 133 839 25,945 5,296 182 563 15,872 3,390
----------------------------------------------------------------------------
Total 3,803 1,227 48,188 13,061 3,376 1,443 49,478 13,065
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production for the third quarter of 2010 was consistent with the same period in
2009. Natural gas and associated liquids production decreased in the third
quarter compared with the third quarter of 2009 due to the disposition of
approximately 2,300 boe per day of primarily natural gas production from two
separate dispositions in Ferrier and Edson, Alberta which closed in late 2009
and at the end of the first quarter of 2010, respectively. These dispositions
were offset by production additions from a successful drilling program which
added liquids rich natural gas production in the Septimus, British Columbia area
and oil production in the Princess, Alberta area. The weather related delays
that hampered activity in the second quarter of 2010 in southern Alberta
continued through the third quarter of 2010. This has created delays in bringing
on new oil production in the quarter and, consequently, the Company's oil
production was below its original expectations.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Nine months ended
September 30, 2010 September 30, 2009
Nat. Nat.
Oil Ngl gas Total Oil Ngl gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta 3,663 537 24,887 8,348 3,241 915 36,899 10,305
British
Columbia 125 728 24,976 5,016 206 430 17,415 3,539
----------------------------------------------------------------------------
Total 3,788 1,265 49,863 13,364 3,447 1,345 54,314 13,844
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production for the first nine months of 2010 decreased over the same period in
2009 due to the previously mentioned asset dispositions but was partially offset
by production additions from a successful drilling program as described above.
Revenue
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Revenue ($ thousands)
Natural gas 18,052 14,685 62,965 59,953
Oil 21,994 19,850 69,451 52,323
Natural gas liquids 4,878 3,975 17,307 11,809
Sulphur - - - 98
----------------------------------------------------------------------------
Total 44,924 38,510 149,723 124,183
----------------------------------------------------------------------------
Crew average prices
Natural gas ($/mcf) 4.07 3.23 4.63 4.04
Oil ($/bbl) 62.86 63.91 67.16 55.61
Natural gas liquids ($/bbl) 43.21 29.94 50.13 32.16
Oil equivalent ($/boe) 37.39 32.04 41.04 32.86
Benchmark pricing
Natural Gas - AECO C daily index
(Cdn $/mcf) 3.59 3.02 4.19 3.83
Oil - Bow River Crude Oil (Cdn $/bbl) 73.15 73.20 76.88 65.79
Oil and ngl - Cdn$ West Texas Int.
(Cdn $/bbl) 79.18 74.91 80.40 65.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's third quarter 2010 revenue increased 17% over the same period in 2009 due
to a 26% increase in its natural gas price and a 44% increase in its natural gas
liquids price partially offset by a 2% decrease in the Company's oil price.
Decreased production of lower valued natural gas production in the Sierra,
British Columbia area replaced by increased production of higher valued natural
gas from the Septimus area accounts for Crew's increased natural gas pricing as
compared to the benchmark. The Company's benchmark Bow River Crude oil price
remained consistent in the third quarter compared with the same period in 2009
which was in line with the Company's minor oil price decrease. The price
received for the Company's natural gas liquids (ngl) production increased 44%
while the Company's Cdn$ West Texas Intermediate benchmark increased 6% due to
the sale of the Company's assets in the Ferrier area in 2009 which included
lower valued ethane production. In addition, the Company increased production of
higher valued condensate from the Septimus area in the third quarter of 2010.
For the nine months ended September 30, 2010, Crew's natural gas price increased
15% compared with a 9% increase in the Company's benchmark. The aforementioned
replacement of lower valued Sierra natural gas production with higher valued
Septimus natural gas production accounts for the disproportionate increase in
pricing. Crew's oil price increased proportionately with the Bow River Crude Oil
benchmark for the nine month period ended September 30, 2010. The Company's ngl
price increased disproportionately due to the previously mentioned sale of lower
valued ethane production in the Ferrier area and increased higher valued
condensate production in the Septimus area.
Royalties
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands, except per boe) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Royalties 8,920 6,668 30,488 22,860
Per boe 7.42 5.55 8.36 6.05
Percentage of revenue 19.9% 17.3% 20.4% 18.4%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties as a percentage of revenue increased in the third quarter and first
nine months of 2010 compared to the same periods of 2009 due to new oil and
natural gas production from the Princess area which, in the current pricing
environment, attracts a higher royalty rate than the Company's older production.
Corporately, with an increase in forecasted sales from Princess area production,
Crew forecasts annual royalties as a percentage of revenue to average 20% to 22%
for 2010.
Financial Instruments
Commodities
The Company enters into derivative and physical risk management contracts in
order to reduce volatility in financial results, to protect acquisition
economics and to ensure a certain level of cash flow to fund planned capital
projects. Crew's strategy focuses on the use of puts, costless collars, swaps
and fixed price contracts to reduce exposure to fluctuations in commodity
prices, interest rates and foreign exchange rates while allowing for
participation in commodity price increases. The Company's financial derivative
trading activities are conducted pursuant to the Company's Risk Management
Policy approved by the Board of Directors. In 2010, these contracts had the
following impact on the consolidated statement of operations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Realized gain on financial
instruments 5,114 7,794 9,798 13,990
Unrealized gain (loss) on financial
instruments (5,326) 3,082 5,206 4,136
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 2010, the Company held derivative commodity contracts as
follows:
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
---------------------------------------------------------------------------
AECO C
Natural 2,500 November 1, 2009 - Monthly
Gas gj/day December 31, 2010 Index $6.00/gj Swap 581
AECO C
Natural 5,000 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $8.00/gj Call -
AECO C
Natural 10,000 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $7.75/gj Call -
AECO C
Natural 2,500 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $6.20/gj Swap 626
AECO C
Natural 5,000 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $6.08/gj Swap 1,591
AECO C
Natural 2,500 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $5.25/gj Swap 409
AECO C
Natural 2,500 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $5.55/gj Swap 477
AECO C
Natural 2,500 April 1, 2010 - Monthly
Gas gj/day October 31, 2010 Index $5.30/gj Swap 150
Natural 5,000 January 1, 2010 - AECO/NYMEX
Gas mmbtu/day December 31, 2010 Basis diff US$($0.55) Swap (73)
250 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $78.50/bbl Swap (118)
500 January 1, 2010 - $72.00 -
Oil bbl/day December 31, 2010 CDN$ WTI $88.00/bbl Collar (47)
250 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $82.50/bbl Swap (25)
500 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $80.50/bbl Swap (125)
500 January 1, 2010 - US$81.00/bbl
Oil bbl/day December 31, 2010 US$ WTI Swap (9)
250 January 1, 2010 - $80.00 -
Oil bbl/day December 31, 2010 CDN$ WTI $95.02/bbl Collar 23
250 March 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $84.00/bbl Swap 53
250 July 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $88.10/bbl Swap 102
250 July 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $91.50/bbl Swap 281
250 August 9, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $85.00/bbl Swap 31
500 January 1, 2011 - US$80.15/bbl
Oil bbl/day December 31, 2011 US$ WTI Swap (880)
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $86.00/bbl Swap (170)
250 January 1, 2011 - $82.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $94.62/bbl Collar 49
500 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $90.20/bbl Swap 410
250 January 1, 2011 - $80.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $95.45/bbl Collar (4)
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $90.00/bbl Swap 193
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $88.50/bbl Swap 53
250 January 1, 2011 - $85.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $100.50/bbl Collar 352
---------------------------------------------------------------------------
Total 3,930
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Foreign currency
Although all of the Company's petroleum and natural gas sales are conducted in
Canada and are denominated in Canadian dollars, Canadian commodity prices are
influenced by fluctuations in the Canadian to U.S. dollar exchange rate.
At September 30, 2010, the Company held the following derivative foreign
currency contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional Strike Option Fair Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
USD/CAD $ US $2M/ January 1, 2010 -
exchange Month December 31, 2010 CAD/USD 1.094 Swap 382
----------------------------------------------------------------------------
Total 382
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest rate
The Company is exposed to interest rate fluctuations on its bank loan which
bears a floating rate of interest. As shown below, at September 30, 2010, Crew
had contracts in place fixing the interest rate on $100 million of bankers'
acceptances at a rate of 1.10%. The Company pays additional stamping fees and
margins on bankers' acceptances as outlined in note 3 of the financial
statements.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
February 10, 2009 -
BA Rate $50M / year February 10, 2011 BA - CDOR 1.10% Swap 22
February 12, 2009 -
BA Rate $50M / year February 12, 2011 BA - CDOR 1.10% Swap 38
----------------------------------------------------------------------------
Total 60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subsequent to September 30, 2010, the Company entered into the following
financial instrument contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Strike
of Price Option
Contract Volume Term Reference (per bbl) Traded
----------------------------------------------------------------------------
January 1, 2011 - AECO C Monthly Swap
Gas 2,500 gj/day December 31, 2011 Index $4.85 (note 1)
January 1, 2011 - AECO C Monthly Swap
Gas 2,500 gj/day December 31, 2011 Index $4.90 (note 1)
January 1, 2011 - AECO C Monthly Swap
Gas 5,000 gj/day December 31, 2011 Index $5.00 (note 1)
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 CDN$ WTI $88.00 Swap
January 1, 2012 - US$ WTI Call
Oil 500 bbl/day December 31, 2012 US$85.00 (note 1)
January 1, 2012 - Call
Oil 500 bbl/day December 31, 2012 US$ WTI US$90.00 (note 1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(1) Derivative contracts are part of a paired transaction in which the
proceeds from the sale of 2012 oil calls were used to fund the 2011
natural gas swaps at the prices indicated.
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands, except per boe) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Operating costs 12,318 14,000 39,967 42,258
Per boe 10.25 11.65 10.95 11.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the third quarter and first nine months of 2010, the Company's operating
costs and costs per unit decreased over the same periods in 2009 due to the
addition of lower cost natural gas and associated liquids production in the
Septimus area. This was partially offset by the addition of higher cost
production from the Princess area and the disposition of lower cost production
in the Ferrier and Edson areas in late 2009 and early 2010. With additional
forecasted production to offset fixed costs in the Princess and Septimus areas
and cost cutting measures associated with water handling at Princess, the
Company continues to expect costs to average between $10.00 and $10.75 per boe
for 2010.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands, except per boe) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Transportation costs 2,243 2,830 6,763 8,095
Transportation liability write-down - - 344 -
----------------------------------------------------------------------------
Transportation costs excluding
liability write down 2,243 2,830 7,107 8,095
Per boe 1.87 2.35 1.95 2.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the third quarter and first nine months of 2010, the Company's transportation
costs and transportation costs per unit decreased over the same period in 2009
due to the Company permanently assigning its unutilized firm transportation
commitment in northeastern British Columbia in March 2010. The Company forecasts
transportation costs to range between $1.75 and $2.00 per boe for 2010.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
September 30, 2010 September 30, 2009
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 62.86 43.21 4.07 37.39 63.91 29.94 3.23 32.04
Realized
commodity
hedging gain 3.03 - 0.85 4.02 0.70 - 1.33 5.28
Royalties (18.73) (7.05) (0.35) (7.42) (17.61) (8.22) (0.02) (5.55)
Operating
costs (14.03) (6.42) (1.51) (10.25) (11.23) (9.58) (2.03) (11.65)
Transportation
costs (1.50) (1.25) (0.36) (1.87) (2.11) (0.20) (0.47) (2.35)
----------------------------------------------------------------------------
Operating
netbacks 31.63 28.49 2.70 21.87 33.66 11.94 2.04 17.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Nine months ended
September 30, 2010 September 30, 2009
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 67.16 50.13 4.63 41.04 55.61 32.16 4.04 32.86
Realized
commodity
hedging gain 1.31 - 0.58 2.54 0.24 - 0.79 3.18
Royalties (19.46) (10.57) (0.50) (8.36) (14.75) (9.94) (0.36) (6.05)
Operating
costs (14.11) (8.45) (1.65) (10.95) (11.73) (9.32) (1.87) (11.18)
Transportation
costs (1.42) (1.26) (0.38) (1.95) (1.65) (0.07) (0.44) (2.14)
----------------------------------------------------------------------------
Operating
netbacks 33.48 29.85 2.68 22.32 27.72 12.83 2.16 16.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands, except per boe) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Gross costs 3,675 3,436 11,722 10,134
Operator's recoveries (1,146) (797) (2,573) (1,609)
Capitalized costs (1,264) (1,319) (4,574) (4,262)
----------------------------------------------------------------------------
General and administrative expenses 1,265 1,320 4,575 4,263
Per boe 1.05 1.10 1.25 1.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increased third quarter 2010 general and administrative costs before recoveries
and capitalization were mainly due to the cost of additional office space added
in late 2009 in order to accommodate the Company's future growth plans. In the
third quarter of 2010, net general and administrative costs and costs per boe
have decreased due to additional operator's recoveries from the Company's
increased capital expenditures as compared with the same period in 2009. For the
first nine months of 2010, gross costs before recoveries and capitalization as
well as net general and administrative costs have increased as a result of
increased staff levels and increased office rent costs to accommodate the
Company's larger operations in Princess and Septimus. The Company expects
general and administrative expenses to average between $1.10 and $1.25 per boe
for the year.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands, except per boe) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Interest expense 1,188 1,846 4,370 4,500
Average debt level 79,623 169,837 88,431 206,910
Effective interest rate 5.9% 4.4% 6.6% 2.9%
Per boe 0.99 1.54 1.20 1.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's third quarter and first nine months of 2010 interest expense has
decreased over the same periods in 2009 due to a significant decrease in
outstanding average debt levels. During the third quarter, the margin charged on
the Company's borrowings under its prime loans and the stamping fees charged on
its outstanding bankers' acceptances have decreased but this has been partially
offset by increased prime interest rates and interest rates charged on bankers'
acceptances. Effective interest rates increased for the three and nine months
ended September 30, 2010 due to increased standby fees charged on the unutilized
facility and the amortization of annual renewal fees against the significantly
decreased drawn facility as the denominator.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Gross costs 2,069 1,635 6,848 5,056
Capitalized costs (1,035) (817) (3,424) (2,528)
----------------------------------------------------------------------------
Total stock-based compensation 1,034 818 3,424 2,528
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has increased in the third
quarter and first nine months of 2010 as compared with the same periods in 2009
due to an increase in the fair value of stock options that were issued to Crew
employees and service providers, resulting from the Company's increased share
price.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands, except per boe) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Depletion, depreciation and accretion 27,711 32,142 85,478 99,936
Per boe 23.06 26.74 23.43 26.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Depletion, depreciation and accretion costs and per unit costs have decreased in
the third quarter and first nine months of 2010 due to low cost reserve
additions from a successful drilling program in the Company's Septimus and
Princess areas as well as the sale of the Edson assets which received a greater
price per unit than the Company's corporate depletion rate.
Future Income Taxes
The provision for future income taxes was a recovery of $2.6 million in the
third quarter of 2010 and a recovery of $2.7 million for the first nine months
of 2010 compared to recoveries of $2.9 million and $13.5 million, respectively
for the same periods of 2009. The decreased recoveries were the result of
greater pre-tax losses in 2009 as compared to the same periods in 2010.
Cash and Funds from Operations and Net Loss
Three Three Nine Nine
months months months months
ended ended ended ended
($ thousands, except per share September September September September
amounts) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Cash provided by operating
activities 19,596 24,902 75,598 65,925
Funds from operations 24,104 19,640 73,014 56,197
Per share - basic 0.30 0.25 0.92 0.76
- diluted 0.29 0.25 0.90 0.76
Net loss (7,387) (7,376) (7,636) (28,661)
Per share - basic (0.09) (0.09) (0.10) (0.39)
- diluted (0.09) (0.09) (0.10) (0.39)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the third quarter and first nine months of 2010, an increase in funds from
operations was the result of increased commodity pricing and lower operating and
transportation costs for the periods. For the third quarter of 2010, the net
loss was consistent with the same period in 2009 as reduced depletion costs were
offset by a net unrealized loss on financial instruments. The net loss for the
first nine months of 2010 decreased compared to the same period in 2009
primarily due to increased revenue from increased commodity pricing and
decreased depletion, depreciation and accretion costs from the sale of assets in
late 2009 and early 2010.
Capital Expenditures, Acquisitions and Dispositions
During the third quarter of 2010, the Company drilled 26 (24.9 net) wells
resulting in 16 (16.0 net) oil wells, six (4.9 net) gas wells and four (4.0 net)
water disposal wells. In addition, the Company also completed 33 (33.0 net)
wells at Septimus, Princess and Pine Creek, Alberta and recompleted four (4.0
net) well in the Septimus, Plain Lake and Provost, Alberta areas. Continued wet
weather hampered tying in many of these wells as only 15 of the 33 completed
wells were brought on production in the third quarter. The Company also added to
its infrastructure at Princess by expanding and upgrading fluid handling
capacity and pipelines to its oil batteries in the area. In the third quarter of
2010, Crew began the expansion of the Septimus facility by procuring equipment
for the scheduled fourth quarter construction of the expansion. The Company has
an agreement in place to sell the Septimus gas plant expansion for its as built
cost of approximately $16.9 million. The sale is scheduled to close after
completion of the expansion, expected to be in the fourth quarter of 2010.
Details can be found in the Contractual Obligations section.
During the third quarter, the Company was notified that it was granted a $7.6
million infrastructure credit from the British Columbia government. This credit
was issued as a result of the Company's work with a third party processor in the
Septimus area to expand and increase the natural gas takeaway capacity
associated with the Company's Montney gas development in the area. The third
quarter capital expenditures are reported net of the $7.6 million of government
incentives confirmed during the quarter.
Exploration and development capital expenditures for the third quarter and first
nine months of 2010 were $65.1 and $187.5 million, respectively, compared to
$35.4 and $73.3 million for the same periods in 2009. The expenditures are
detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
($ thousands) 30, 2010 30, 2009 30, 2010 30, 2009
----------------------------------------------------------------------------
Land 2,866 1,013 37,738 4,881
Seismic 182 81 5,277 2,176
Drilling and completions 49,681 17,767 116,573 28,167
Facilities, equipment and pipelines 11,304 15,040 23,074 33,384
Other 1,105 1,489 4,860 4,647
----------------------------------------------------------------------------
Exploration and development 65,138 35,390 187,522 73,255
Property acquisitions (dispositions) - - (132,640) (34,378)
----------------------------------------------------------------------------
Total net 65,138 35,390 54,882 38,877
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 2010, budgeted net expenditures for 2010 are estimated at
approximately $95 million.
Liquidity and Capital Resources
Capital Funding
The Company has a credit facility with a syndicate of banks (the "Syndicate")
that includes a revolving line of credit of $190 million and an operating line
of credit of $20 million (the "Facility"). The Facility revolves for a 364 day
period and will be subject to its next 364 day extension by June 13, 2011. If
not extended, the Facility will cease to revolve, the margins thereunder will
increase by 0.50 percent and all outstanding balances under the Facility will
become repayable in one year from the renew date. The available lending limits
of the Facility are reviewed semi-annually and are based on the Syndicate's
interpretation of the Company's reserves and future commodity prices. There can
be no assurance that the amount of the available Facility will not be adjusted
at the next scheduled review on or before June 13, 2011. At September 30, 2010,
the Company had committed drawings of $110.8 million on the Facility and had
issued letters of credit totaling $3.6 million.
During the first nine months of 2010, the Company has received proceeds of $18.8
million due to the exercise of 2,053,366 employee stock options.
The Company will continue to fund its on-going operations from a combination of
cash flow, debt, the proceeds from future asset dispositions and equity
financings as needed. As the majority of our on-going capital expenditure
program is directed to the further growth of reserves and production volumes,
Crew is readily able to adjust its budgeted capital expenditures should the need
arise.
Working Capital
The capital intensive nature of Crew's activities generally results in the
Company carrying a working capital deficit. However, the Company maintains
sufficient unused bank credit lines to satisfy such working capital
deficiencies. At September 30, 2010, the Company's working capital deficiency
(including accounts receivable, accounts payable and accrued liabilities)
totaled $36.1 million which, when combined with the drawings on its bank line,
represented 70% of its current bank facility.
Share Capital
As at November 8, 2010, Crew had issued and outstanding 80,283,534 Common Shares
and had options to acquire 5,416,400 Common Shares outstanding.
Capital Structure
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes adjustments
on an on-going basis in order to maintain the flexibility needed to achieve the
Company's long-term objectives. To manage the capital structure the Company may
adjust capital spending, hedge future revenue and some costs, issue new equity,
issue new debt or repay existing debt through asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1. This ratio may increase at certain times as a result of acquisitions or low
commodity prices. As shown below, as at September 30, 2010, the Company's ratio
of net debt to annualized funds from operations was 1.52 to 1 (December 31, 2009
- 1.67 to 1).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Sept. 30, Dec. 31,
($ thousands, except ratio) 2010 2009
----------------------------------------------------------------------------
Accounts receivable 43,182 37,574
Accounts payable and accrued liabilities (79,314) (84,228)
----------------------------------------------------------------------------
Working capital deficiency (36,132) (46,654)
Bank loan (110,770) (135,601)
----------------------------------------------------------------------------
Net debt (146,902) (182,255)
Funds from operations 24,104 27,256
Annualized 96,416 109,024
Net debt to annualized funds from operations ratio 1.52 1.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contractual Obligations
Throughout the course of its ongoing business, the Company enters into various
contractual obligations such as credit agreements, purchases of services,
royalty agreements, operating agreements, processing agreements, right of way
agreements and lease obligations for office space and automotive equipment. All
such contractual obligations reflect market conditions prevailing at the time of
the contract and none are with related parties. The Company believes it has
adequate sources of capital to fund all contractual obligations as they come
due. The following table lists the Company's obligations with a fixed term.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Total 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Bank Loan (note 1) 110,770 - - 110,770 - - -
Operating Leases 3,490 432 1,743 1,315 - - -
Capital commitments 5,000 3,000 2,000 - - - -
Transportation
agreements 12,802 1,157 4,018 955 953 953 4,766
Processing agreement 28,204 762 3,049 3,049 3,049 3,049 15,246
----------------------------------------------------------------------------
Total 160,266 5,351 10,810 116,089 4,002 4,002 20,012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2012; however, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.
The transportation agreements include an $8.8 million commitment to a third
party to transport natural gas from the gas processing facility in the Septimus,
British Columbia area to the Alliance pipeline system. The remaining commitment
relates to firm transportation commitments that were acquired as part of the
Company's May 2007 private company acquisition, of which, in 2010, the Company
permanently assigned approximately $6.2 million of its firm commitments to third
parties.
During 2009, Crew entered into the firm processing agreement to process natural
gas through a third party owned gas processing facility in the Septimus area.
Under the terms of the agreement Crew has committed to process a minimum monthly
volume of gas through the facility commencing on December 1, 2009 and continuing
through November 30, 2019. The commitment is included in the above table.
Subsequent to the quarter end, the Company amended the agreement with the owner
of this facility. Under the terms of the amended agreement, Crew has begun
expansion of the existing facility. On completion of the expansion, Crew will be
reimbursed for the full cost of the facility in return for an expanded
processing commitment that will extend to December 2020. Crew has also retained
the option to re-purchase a 50% interest in the facility at certain dates prior
to January 1, 2014, at a cost of 50% of the total expanded facility's
construction cost.
Guidance
In a repeated theme, oil prices have remained relatively strong as the world's
economies continue their recovery. Natural gas prices, however, remain weak as
North American supplies continue to grow due to the aggressive development of
unconventional natural gas plays. As a result of this commodity price imbalance,
Crew has been focusing its capital and technical resources towards the pursuit
of growth of its oil and liquids production. The Company is in the enviable
position to quickly adapt to commodity price cycles in order to focus on oil or
liquids rich natural gas directed drilling. This was demonstrated in the third
quarter of 2010 with the Company drilling 20 net wells at Princess.
Despite the depressed natural gas price environment, the Company's liquids rich
Septimus Montney production continues to show good economic returns. However,
the continued prospect of low natural gas prices combined with the inflating
cost of high pressure fracturing services has resulted in the economics of our
oil plays overwhelming the economics of our liquids rich natural gas plays. As
such, capital deployment for the fourth quarter of 2010 and 2011 is expected to
be largely dedicated toward oil directed drilling.
Crew's net exploration and development expenditures are forecasted to be
approximately $225 million for 2010 with the majority being spent at Princess.
As a result of the aforementioned persistent weather delays, Crew is forecasting
average 2010 production of 13,600 to 14,000 boe per day. Exit production is now
forecast to be 17,000 to 18,000 boe per day.
Additional Disclosures
Quarterly Analysis
The following table summarizes Crew's key quarterly financial results for the
past eight financial quarters:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per Sept. 30 June 30 Mar. 31 Dec. 31
share amounts) 2010 2010 2010 2009
----------------------------------------------------------------------------
Total daily production (boe/d) 13,061 12,048 15,001 14,470
Average wellhead price ($/boe) 37.39 39.25 45.75 43.30
Petroleum and natural gas sales 44,924 43,027 61,772 57,646
Cash provided by operations 19,596 24,149 32,213 16,734
Funds from operations 24,104 20,693 28,217 27,256
Per share - basic 0.30 0.26 0.36 0.35
- diluted 0.29 0.25 0.35 0.35
Net income (loss) (7,387) (2,691) 2,442 (9,154)
Per share - basic (0.09) (0.03) 0.03 (0.12)
- diluted (0.09) (0.03) 0.03 (0.12)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per Sept. 30 June 30 Mar. 31 Dec. 31
share amounts) 2009 2009 2009 2008
----------------------------------------------------------------------------
Total daily production (boe/d) 13,065 13,466 15,022 14,869
Average wellhead price ($/boe) 32.04 32.10 34.28 42.99
Petroleum and natural gas sales 38,510 39,331 46,342 58,806
Cash provided by operations 24,902 21,517 19,506 25,700
Funds from operations 19,640 20,036 16,521 29,646
Per share - basic 0.25 0.27 0.23 0.42
- diluted 0.25 0.27 0.23 0.42
Net income (loss) (7,376) (12,267) (9,018) (74,853)
Per share - basic (0.10) (0.17) (0.13) (1.05)
- diluted (0.10) (0.17) (0.13) (1.05)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's petroleum and natural gas sales, cash and funds from operations and net
income are all impacted by production levels and volatile commodity pricing.
From 2008 to 2010, these performance measures have fluctuated as a result of
volatile oil and natural gas prices.
Significant factors and trends that have impacted the Company's results during
the above periods include:
- Revenue is directly impacted by the Company's ability to replace existing
declining production and add incremental production through its on-going capital
expenditure program.
- Production in the second quarter of 2009 and 2010 was negatively impacted by
scheduled and unscheduled third party facility shutdowns and poor weather
experienced in southern Alberta in 2010.
- Revenue and royalties are significantly impacted by underlying commodity
prices. The Company utilizes derivative contracts and forward sales contracts to
reduce the exposure to commodity price fluctuations on a portion of its
production. These contracts can cause volatility in net income as a result of
unrealized gains and losses on commodity derivative contracts held for risk
management purposes.
- In the fourth quarter of 2008, Crew performed an impairment test on its
goodwill and determined that its carrying value exceeded its fair value and
therefore an impairment charge of $69.1 million was required.
- In 2009 and 2010, the Company sold assets with approximately 2,970 boe per day
of production for $182.9 million. The major dispositions closed as follows:
-- First quarter 2009 - 130 boe per day for $10.7 million
-- Second quarter 2009 - 540 boe per day for $22.5 million
-- Fourth quarter 2009 - 600 boe per day for $25.3 million
-- Second quarter 2010 - 1,700 boe per day for $123.3 million
New Accounting Pronouncements
International Financial Reporting Standards
Effective January 1, 2011, Canadian public companies are required to adopt
International Financial Reporting Standards ("IFRS") which will include
comparatives for 2010. Crew's financial statements up to and including the
December 31, 2010 financial statements will continue to be reported in
accordance with Canadian GAAP as it exists on each reporting date. Financial
statements for the quarter ended March 31, 2011, including comparative amounts,
will be prepared on an IFRS basis.
In order to transition to IFRS, management has established a project team and
formed an executive steering committee. A transition plan has been developed to
convert the financial statements to IFRS. External advisors have been retained
and will continue to assist management with the project on an as needed basis.
Training has been provided to key employees and staff training programs will
continue throughout 2010. The Company continues to assess the effect of the
transition on information systems, internal controls over financial reporting
and disclosure controls and procedures. Systems and controls are being updated
as IFRS accounting processes are implemented. Significant system and control
changes are not anticipated. The project team and steering committee continue to
provide updates to senior management and the Audit Committee. The Company's
auditors are involved throughout the process to ensure the Company's policies
are in accordance with the new standards.
Analysis of differences between IFRS and Canadian GAAP is continuing. There are
significant accounting policy changes anticipated on adoption of IFRS which are
described in more detail below. Management is continuing to finalize its
accounting policies and as such is unable to quantify the impact on the
financial statements at this time. In addition, anticipated changes to IFRS and
International Accounting Standards prior to adoption could cause changes to
certain items based on new facts and circumstances.
Many of the differences between IFRS and Canadian GAAP are being quantified;
however, Crew has not yet prepared a full set of annual financial statements
under IFRS. The impacts of the identified differences are still being
determined. Most adjustments required on transition to IFRS will be made
retrospectively against opening retained earnings as of the date of the first
comparative balance sheet. In July 2009, the International Accounting Standards
Board ("IASB") issued amendments to IFRS 1 "First time adoption of IFRS"
allowing additional exemptions for first-time adopters. Under these amendments,
full cost oil and gas companies can elect to use the recorded amount under a
previous GAAP as the deemed cost for oil and gas assets on the transition date
to IFRS. Crew is currently planning to adopt this exemption. Management has
analyzed the various other accounting policy choices available under IFRS 1 and
has determined the following to be most appropriate for Crew:
- Depletion and depreciation of Property, Plant and Equipment ("PP&E") will be
based on significant components. Under IFRS 1, the net book value of the PP&E
can be allocated to the new cost centres on the basis of Crew's reserve volumes
or values as per the deemed cost election. Depletion of resource properties will
generally continue to be calculated using the unit-of-production method but Crew
has the option to base the calculation on proved reserves or proved plus
probable reserves. Crew has concluded that it will allocate the PP&E balance
using Crew's reserve values and expects to use proved plus probable reserves to
calculate the depletion of resource properties.
- Oil and gas properties will be classified as either PP&E or Exploration and
Evaluation assets (E&E). Upon transition to IFRS, Crew will reclassify all E&E
expenditures that are currently included in the PP&E balance on the Consolidated
Balance Sheet. These assets will be measured at cost and will not be depleted
but will be assessed for impairment when indicators suggest the possibility of
impairment. Crew is currently finalizing its policy on E&E assets, which will
primarily consist of undeveloped exploration lands.
- IFRS 1 allows Crew to use the IFRS rules for business combinations on a
prospective basis rather than restating all business combinations. Crew will
elect to use this exemption; therefore, Crew will not be recording any
adjustments to retrospectively restate any of its business combinations that
have occurred prior to January 1, 2010.
- Currently Crew expenses stock-based compensation on a straight-line basis.
Under IFRS, share-based payments are expensed based on a graded vesting
schedule. Crew will also be required to incorporate a forfeiture multiplier
rather than account for forfeitures as they occur as currently practiced under
Canadian GAAP.
- Under Canadian GAAP, impairment testing on oil and gas properties is performed
at a cost centre level. Under IFRS, impairment testing will be performed at a
lower level, referred to as a cash generating unit. This will result in a
greater number of impairment tests. At January 1, 2010, Crew does not expect any
impairment on its PP&E.
- Under Canadian GAAP, Crew's Asset Retirement Obligation calculation is based
on a credit adjusted risk free rate. Under IFRS, Crew is required to revalue its
entire liability for asset retirement costs at each balance sheet date using a
current liability-specific discount rate. It is expected that the asset
retirement obligation will increase upon transition to IFRS if the liability is
revalued to reflect the estimated risk-free rate of interest.
In accordance with its transition plan, Crew has analyzed accounting policy
alternatives and drafted its IFRS position papers. Crew is in the process of
finalizing its January 1, 2010 IFRS opening balance sheet and having its
external auditors review the Company's draft IFRS balance sheet impacts. In the
fourth quarter, the Company also plans to begin drafting its 2010 IFRS
comparative quarterly financial statements and will assess and review the impact
of the IFRS changes on disclosure controls and internal controls, including
identification of instances where controls may require amendments or additions
in order to address the accounting policy changes required under IFRS. No
material changes in control procedures are presently expected. The Company
expects to be in a position to provide quantitative information about the impact
of IFRS on its financial statements following the fourth quarter of 2010.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
The Company's Chief Executive Officer ("CEO") and Chief Financial Officer
("CFO") have designed, or caused to be designed under their supervision,
disclosure controls and procedures to provide reasonable assurance that: (i)
material information relating to the Company is made known to the Company's CEO
and CFO by others, particularly during the period in which the annual and
interim filings are being prepared; and (ii) information required to be
disclosed by the Company in its annual filings, interim filings or other reports
filed or submitted by it under securities legislation is recorded, processed,
summarized and reported within the time period specified in securities
legislation.
Crew's CEO and CFO have designed, or caused to be designed under their
supervision, internal controls over financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with Canadian
generally accepted accounting principles. The Company is required to disclose
herein any change in the Company's internal controls over financial reporting
that occurred during the period beginning on July 1, 2010 and ended on September
30, 2010 that has materially affected, or is reasonably likely to materially
affect, the Company's internal controls over financial reporting. No material
changes in the Company's internal controls over financial reporting were
identified during such period that have materially affected, or are reasonably
likely to materially affect, the Company's internal controls over financial
reporting.
It should be noted that a control system, including the Company's disclosure and
internal controls and procedures, no matter how well conceived, can provide only
reasonable, but not absolute assurance that the objectives of the control system
will be met and it should not be expected that the disclosure and internal
controls and procedures will prevent all errors or fraud.
Dated as of November 8, 2010
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", "forecasts" 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 forecast
2010 exit rates; anticipated disposal rates on water disposal wells; future oil
and natural gas prices and Crew's commodity risk management programs; future
liquidity and financial capacity; future results from operations and operating
metrics; anticipated reductions in operating costs; future costs, expenses and
royalty rates; future interest costs; the exchange rate between the $US and
$Cdn; future development, exploration, acquisition and development activities
and related capital expenditures and the timing thereof; the number of wells to
be drilled, completed and tied-in and the timing thereof; the amount and timing
of capital projects; planned expansion of the Septimus gas processing facility
and Crew's reimbursement of costs thereunder; operating costs; the total future
capital associated with development of reserves and resources; forecasts in
operating expenses.
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 and partner approvals; the ability of
Crew to obtain qualified staff, regulatory and partner approvals, 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; and the ability of Crew to
successfully market its oil and natural gas products.
The forward-looking information and statements included in this news release are
not guarantees of future performance and should not be unduly relied upon. Such
information and statements, including the assumptions made in respect thereof,
involve known and unknown risks, uncertainties and other factors that may cause
actual results or events to defer materially from those anticipated in such
forward-looking information or statements including, without limitation: changes
in commodity prices; changes in the demand for or supply of Crew's products;
unanticipated operating results or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters; changes in
development plans of Crew or by third party operators of Crew's properties,
increased debt levels or debt service requirements; inaccurate estimation of
Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack
of access to capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors and partners; and certain other risks
detailed from time-to-time in Crew's public disclosure documents (including,
without limitation, those risks identified in this news release and Crew's
Annual Information Form).
The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Crew does not assume any
obligation to publicly update or revise any of the included forward-looking
statements or information, whether as a result of new information, future events
or otherwise, except as may be required by applicable securities laws.
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
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 for the three and nine month periods ended September 30,
2010 and 2009 are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2010 2009
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 43,182 $ 37,574
Fair value of financial instruments (note 7) 4,372 -
Future income taxes - 542
----------------------------------------------------------------------------
47,554 38,116
Property, plant and equipment (note 2) 898,413 925,132
----------------------------------------------------------------------------
$ 945,967 $ 963,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 79,314 $ 84,228
Fair value of financial instruments (note 7) - 834
Future income taxes 991 -
Current portion of other long-term
obligations (note 4) 463 1,313
----------------------------------------------------------------------------
80,768 86,375
Bank loan (note 3) 110,770 135,601
Other long-term obligations (note 4) - 132
Asset retirement obligations (note 5) 33,735 35,341
Future income taxes 98,425 101,519
Shareholders' Equity
Share capital (note 6) 643,917 617,605
Contributed surplus (note 6 (c)) 22,082 22,769
Deficit (43,730) (36,094)
----------------------------------------------------------------------------
622,269 604,280
Commitments (note 10)
Subsequent events (note 7,10)
----------------------------------------------------------------------------
$ 945,967 $ 963,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Operations, Comprehensive Loss and Retained
Earnings (Deficit)
(unaudited)
(thousands, except per share amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue
Petroleum and natural
gas sales $ 44,924 $ 38,510 $ 149,723 $ 124,183
Royalties (8,920) (6,668) (30,488) (22,860)
Realized gain on
financial instruments
(note 7) 5,114 7,794 9,798 13,990
Unrealized gain (loss)
on financial instruments
(note 7) (5,326) 3,082 5,206 4,136
----------------------------------------------------------------------------
35,792 42,718 134,239 119,449
Expenses
Operating 12,318 14,000 39,967 42,258
Transportation (note 4) 2,243 2,830 6,763 8,095
General and
administrative 1,265 1,320 4,575 4,263
Interest 1,188 1,846 4,370 4,500
Stock-based
compensation (note 6(d)) 1,034 818 3,424 2,528
Depletion, depreciation
and accretion 27,711 32,142 85,478 99,936
----------------------------------------------------------------------------
45,759 52,956 144,577 161,580
----------------------------------------------------------------------------
Loss before income taxes (9,967) (10,238) (10,338) (42,131)
Future income tax
reduction (2,580) (2,862) (2,702) (13,470)
----------------------------------------------------------------------------
Loss and comprehensive
loss (7,387) (7,376) (7,636) (28,661)
Retained earnings
(deficit), beginning of
period (36,343) (19,564) (36,094) 1,721
----------------------------------------------------------------------------
Deficit, end of period $ (43,730) $ (26,940) $ (43,730) $ (26,940)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Loss per share
(note 6(e))
Basic $ (0.09) $ (0.09) $ (0.10) $ (0.39)
Diluted $ (0.09) $ (0.09) $ (0.10) $ (0.39)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Cash Flows
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2010 2009 2010 2009
----------------------------------------------------------------------------
Cash provided by
(used in):
Operating activities:
Loss $ (7,387) $ (7,376) $ (7,636) $ (28,661)
Items not involving
cash:
Depletion, depreciation
and accretion 27,711 32,142 85,478 99,936
Stock-based
compensation 1,034 818 3,424 2,528
Future income tax
reduction (2,580) (2,862) (2,702) (13,470)
Unrealized (gain) loss
on financial instruments 5,326 (3,082) (5,206) (4,136)
Transportation
liability charge (note 4) (156) (328) (982) (985)
Asset retirement
expenditures (201) (196) (906) (478)
Change in non-cash
working capital (note 9) (4,151) 5,786 4,488 11,191
----------------------------------------------------------------------------
19,596 24,902 75,958 65,925
Financing activities:
Increase (decrease) in
bank loan 38,925 (8,160) (24,831) (56,860)
Issue of common shares 1,220 22 18,813 43,422
Share issue costs - (3) (48) (2,442)
----------------------------------------------------------------------------
40,145 (8,141) (6,066) (15,880)
Investing activities:
Exploration and
development (65,138) (35,390) (187,522) (73,255)
Property dispositions - - 132,640 34,378
Change in non-cash
working capital (note 9) 5,397 18,629 (15,010) (11,168)
----------------------------------------------------------------------------
(59,741) (16,761) (69,892) (50,045)
----------------------------------------------------------------------------
Change in cash and cash
equivalents - - - -
Cash and cash
equivalents, beginning
of period - - - -
----------------------------------------------------------------------------
Cash and cash
equivalents, end of
period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Notes to Consolidated Financial Statements
For the three and nine months ended September 30, 2010 and 2009
(Unaudited)
(Tabular amounts in thousands)
1. Significant accounting policies:
The interim consolidated financial statements of Crew Energy Inc. ("Crew" or the
"Company") have been prepared by management in accordance with accounting
principles generally accepted in Canada. The interim consolidated financial
statements have been prepared following the same accounting policies and methods
of computation as the consolidated financial statements for the year ended
December 31, 2009. The disclosure which follows is incremental to the disclosure
included with the December 31, 2009 consolidated financial statements. These
interim consolidated financial statements should be read in conjunction with the
audited consolidated financial statements and notes thereto for the year ended
December 31, 2009.
Certain comparative amounts have been reclassified to conform to current period
presentation.
2. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and Net book
September 30, 2010 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 1,359,156 $ 460,743 $ 898,413
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and Net book
December 31, 2009 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 1,302,399 $ 377,267 $ 925,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The cost of unproved properties at September 30, 2010 of $173,711,000 (2009 -
$159,751,000) was excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $136,955,000 (2009 - $93,818,000) have been included in the
depletion calculation and estimated salvage values of $35,234,000 (2009 -
$38,851,000) have been excluded from the depletion calculation.
In April 2010, the Company closed the disposition of oil and gas assets in the
Edson, Alberta area for gross proceeds of $126 million, before closing
adjustments.
The following directly attributable general and administrative and stock-based
compensation expenses related to exploration and development activities were
capitalized.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months Year
ended ended
Sept. 30, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
General and administrative expense $ 4,463 $ 5,736
Stock-based compensation expense, including
future income taxes 4,577 4,442
----------------------------------------------------------------------------
$ 9,040 $ 10,178
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. Bank loan:
The Company's bank facility consists of a revolving line of credit of $190
million and an operating line of credit of $20 million (the "Facility"). The
Facility revolves for a 364 day period and will be subject to its next 364 day
extension by June 13, 2011. If not extended, the Facility will cease to revolve,
the margins thereunder will increase by 0.50 percent and all outstanding
advances thereunder will become repayable in one year. The available lending
limits of the Facility are reviewed semi-annually and are based on the bank
syndicate's interpretation of the Company's reserves and future commodity
prices. There can be no assurance that the amount of the available Facility will
not be adjusted at the next scheduled borrowing base review on or before June
13, 2011.
Advances under the Facility are available by way of prime rate loans with
interest rates of between 1.25 percent and 2.75 percent over the bank's prime
lending rate and bankers' acceptances and LIBOR loans, which are subject to
stamping fees and margins ranging from 2.25 percent to 3.75 percent depending
upon the debt to EBITDA ratio of the Company calculated at the Company's
previous quarter end. Standby fees are charged on the undrawn facility at rates
ranging from 0.56 percent to 0.94 percent depending upon the same debt to EBITDA
ratio.
As at September 30, 2010, the Company's applicable pricing included a 1.75
percent margin on prime lending and a 2.75 percent stamping fee and margin on
bankers' acceptances and LIBOR loans along with a 0.69 percent per annum standby
fee on the portion of the Facility that is not drawn. Borrowing margins and fees
are reviewed annually as part of the bank syndicate's annual renewal. At
September 30, 2010, the Company had issued letters of credit totaling $3.6
million. The effective interest rate on the Company's borrowings under its bank
Facility for the three months ended September 30, 2010 was 5.9% (2009 - 2.4%).
4. Other long-term obligations:
As part of the May, 2007 private company acquisition, the Company acquired
several firm transportation agreements. These agreements had a fair value at the
time of the acquisition of a $4.9 million liability. This amount was accounted
for as part of the acquisition cost and will be charged as a reduction to
transportation expenses over the life of the contracts as they are incurred. The
charge for the three and nine months ended September 30, 2010 was $0.2 million
and $0.7 million, respectively (2009 - $0.3 million and $1.0 million).
In March 2010, the Company permanently assigned a portion of the firm
transportation agreements to third parties at no cost to Crew. As a result, the
remaining liability associated with the assigned contracts was written-off
during the first quarter of 2010 as a $0.3 million reduction of transportation
expense.
5. Asset retirement obligations:
Total future asset retirement obligations were determined by management and were
based on Crew's net ownership interest, the estimated future costs to reclaim
and abandon the wells and facilities and the estimated timing of when the costs
will be incurred. Crew estimated the net present value of its total asset
retirement obligation as at September 30, 2010 to be $33,735,000 (December 31,
2009 - $35,341,000) based on a total future liability of $61,180,000 (December
31, 2009 - $64,030,000). These payments are expected to be made over the next 30
years. An 8% to 10% (2009 - 8% to 10%) credit adjusted risk free discount rate
and 2% (2009 - 2%) inflation rate were used to calculate the present value of
the asset retirement obligation.
The following table reconciles Crew's asset retirement obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Year ended
Sept. 30, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
Carrying amount, beginning of period $ 35,341 $ 34,941
Liabilities incurred 729 385
Liabilities disposed (3,431) (2,161)
Accretion expense 2,002 2,765
Liabilities settled (906) (589)
----------------------------------------------------------------------------
Carrying amount, end of period $ 33,735 $ 35,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Share capital:
(a) Authorized:
Unlimited number of Common Shares
(b) Common Shares issued:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
shares Amount
----------------------------------------------------------------------------
Common shares, December 31, 2009 78,152 $ 617,605
Exercise of stock options 2,054 18,813
Stock-based compensation - 7,535
Share issue costs, net of income taxes of $12 - (36)
----------------------------------------------------------------------------
Common shares, September 30, 2010 80,206 $ 643,917
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(c) Contributed Surplus:
Amount
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contributed surplus, December 31, 2009
Contributed surplus, December 31, 2009 $ 22,769
Exercise of options (7,535)
Stock-based compensation 6,848
----------------------------------------------------------------------------
Contributed surplus, September 30, 2010 $ 22,082
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(d) Stock-based compensation:
The Company measures compensation costs associated with stock-based compensation
using the fair market value method under which the cost is recognized over the
vesting period of the underlying security. The fair value of each stock option
is determined at each grant date using the Black-Scholes model with the
following weighted average assumptions used for options granted during the three
month period ended September 30, 2010: risk free interest rate 1.89% (2009 -
2.16%), expected life 4 years (2009 - 4 years), volatility 61% (2009 - 60%), and
an expected dividend of nil (2009 - nil). The Company has not incorporated an
estimated forfeiture rate for stock options that will not vest, rather the
Company accounts for actual forfeitures as they occur.
During the first nine months of 2010, the Company recorded $6,848,000, (2009 -
$5,056,000) of stock-based compensation expense related to the stock options, of
which $3,424,000 (2009 - $2,528,000) was capitalized in accordance with the
Company's full cost accounting policy. As stock-based compensation is
non-deductible for income tax purposes, a future income tax liability of
$1,153,000 (2009 - $854,000) associated with the current year's capitalized
stock-based compensation has been recorded.
The average fair value of the stock options granted during the nine months ended
September 30, 2010, as calculated by the Black-Scholes method, was $8.03 per
option (2009 - $2.04).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Number of Price average
Options Range exercise price
----------------------------------------------------------------------------
Balance December 31, 2009 5,751 $ 2.78 to $18.70 $ 8.33
Granted 2,235 $13.36 to $18.36 $ 15.17
Exercised (2,054) $ 2.78 to $16.60 $ 9.16
Forfeited (440) $ 2.78 to $16.60 $ 8.49
----------------------------------------------------------------------------
Balance September 30, 2010 5,492 $ 3.43 to $18.70 $ 10.79
Exercisable 1,687 $ 3.43 to $18.70 $ 9.00
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(e) Per share amounts:
Per share amounts have been calculated on the weighted average number of shares
outstanding. The weighted average shares outstanding for the three month period
ended September 30, 2010 was 80,129,000 (2009 - 78,084,000) and for the nine
month period ended September 30, 2010 the weighted average number of shares
outstanding was 79,561,000 (2009 - 74,289,000).
In computing diluted per share amounts for the three month period ended
September 30, 2010, no shares (2009 - nil) were added to the weighted average
number of Common Shares outstanding for the dilution added by the stock options
and for the nine month period ended September 30, 2010, no shares (2009 - nil)
were added to the weighted average number of common shares for the dilution.
There were 5,492,000 (2009 - 5,770,000) stock options that were not included in
the diluted earnings per share calculation because they were anti-dilutive.
7. Financial Instruments:
Overview
The Company has exposure to credit, liquidity and market risks from its use of
financial instruments. This note provides information about the Company's
exposure to each of these risks, the Company's objectives, policies and
processes for measuring and managing risk. Further quantitative disclosures are
included throughout these financial statements.
The Board of Directors has overall responsibility for the establishment and
oversight of the Company's risk management framework. The Board has implemented
and monitors compliance with risk management policies. The Company's risk
management policies are established to identify and analyze the risks faced by
the Company, to set appropriate risk limits and controls, and to monitor risks
and adherence to market conditions and the Company's activities.
(a) Credit risk:
Credit risk is the risk of financial loss to the Company if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Company's receivables from
petroleum and natural gas marketers and joint venture partners and the fair
value of derivative instruments.
The carrying amount of accounts receivable and derivative assets, when
outstanding, represents the maximum credit exposure. As at September 30, 2010
the Company's receivables consisted of $17.0 (2009 - $17.2) million of
receivables from petroleum and natural gas marketers which has subsequently been
collected, $10.2 (2009 - $9.2) million from joint venture partners of which $0.8
million has been subsequently collected, and $16.0 (2009 - $11.2) million of
government deposits and incentives, prepaids and other accounts receivable. The
Company does not consider any receivables to be past due.
(b) Liquidity risk:
Accounts payable and financial instruments have contractual maturities of less
than one year. The Company maintains a revolving credit facility, as outlined in
note 3, that is subject to renewal annually by the lenders and has a contractual
maturity in 2012. The Company also maintains and monitors a certain level of
cash flow which is used to finance operating and capital expenditures as the
Company does not pay dividends. See Capital Management note 8.
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity
prices, interest rates, and foreign exchange rates will affect the Company's net
income or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
limits, while maximizing the Company's returns.
The Company utilizes both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with the Company's risk management policy that has been approved by
the Board of Directors.
(i) Commodity price risk
The Company has attempted to mitigate a portion of the commodity price risk
through the use of various financial derivative and physical delivery sales
contracts as outlined below. The Company's Board of Directors approved policy is
to enter into commodity price contracts when considered appropriate to a maximum
of 50% of forecasted production volumes for a period of not more than two years.
Any contracts extending beyond two years requires Board approval.
Derivatives are recorded on the balance sheet at fair value at each reporting
period with the change in fair value being recognized as an unrealized gain or
loss on the consolidated statement of operations.
(ii) Foreign currency exchange rate risk
The Company has attempted to mitigate a portion of its foreign exchange
fluctuation risk through the use of financial derivatives as outlined below.
(iii) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result
of changes in market interest rates. The Company is exposed to interest rate
fluctuations on its bank loan which bears a floating rate of interest. For the
three and nine months ended September 30, 2010, a 1.0 percent change to the
effective interest rate would have a $0.1 million and $0.5 million impact on net
income (2009 - $0.3 and $1.1 million).
The Company has attempted to mitigate the impact of future fluctuations in
interest rates on its outstanding debt by entering into contracts fixing the
base interest rate on $100 million of banker's acceptance borrowings as outlined
below. These rates are, under the Company's bank Facility, subject to an
additional stamping fee of 2.75 percent as of September 30, 2010.
The Company's derivative contracts in place as of September 30, 2010 are as follows:
Subject of Notional Strike Option Fair
Value
Contract Quantity Term Reference Price Traded ($000s)
AECO C
Natural 2,500 November 1, 2009 - Monthly
Gas gj/day December 31, 2010 Index $6.00 Swap 581
AECO C
Monthly
Natural 5,000 January 1, 2010 - Index
Gas gj/day December 31, 2010 less $0.09 $8.00 Call -
AECO C
Natural 10,000 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $7.75 Call -
AECO C
Natural 2,500 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $6.20 Swap 626
AECO C
Natural 5,000 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $6.08 Swap 1,591
AECO C
Natural 2,500 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $5.25 Swap 409
AECO C
Natural 2,500 January 1, 2010 - Monthly
Gas gj/day December 31, 2010 Index $5.55 Swap 477
AECO C
Natural 2,500 April 1, 2010 - Monthly
Gas gj/day October 31, 2010 Index $5.30 Swap 150
AECO/NYMEX
Natural 5,000 January 1, 2010 - Basis
Gas day December 31, 2010 diff US$(0.55) Swap (73)
250 January 1, 2010 - CDN$ WTI $78.50 Swap (118)
Oil bbl/day December 31, 2010
500 January 1, 2010 - CDN$ WTI $72.00 - Collar (47)
Oil bbl/day December 31, 2010 $88.00
250 January 1, 2010 - CDN$ WTI $82.50 Swap (25)
Oil bbl/day December 31, 2010
500 January 1, 2010 - CDN$ WTI $80.50 Swap (125)
Oil bbl/day December 31, 2010
500 January 1, 2010 -
Oil bbl/day December 31, 2010 US$ WTI US$81.00 Swap (9)
250 January 1, 2010 - CDN$ WTI $80.00 - Collar 23
Oil bbl/day December 31, 2010 $95.02
250 March 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $84.00 Swap 53
250 July 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $88.10 Swap 102
250 July 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $91.50 Swap 281
250 August 9, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $85.00 Swap 31
500 January 1, 2011 -
Oil bbl/day December 31, 2011 US$ WTI US$80.15 Swap (880)
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $86.00 Swap (170)
250 January 1, 2011 - $82.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $94.62 Collar 49
500 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $90.20 Swap 410
250 January 1, 2011 - $80.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $95.45 Collar (4)
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $90.00 Swap 193
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $88.50 Swap 53
250 January 1, 2011 - $85.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $100.50 Collar 352
----------------------------------------------------------------------------
Total commodity contracts 3,930
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional Strike Option Fair Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
USD /
CAD $ US $2M / January 1, 2010 -
exchange Month December 31, 2010 CAD/USD 1.094 Swap 382
----------------------------------------------------------------------------
Total foreign exchange contract 382
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional Strike Option Fair Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
$50M / February 10, 2009 -
BA Rate year February 10, 2011 BA - CDOR 1.10% Swap 22
$50M / February 12, 2009 -
BA Rate year February 12, 2011 BA - CDOR 1.10% Swap 38
----------------------------------------------------------------------------
Total interest rate contracts 60
----------------------------------------------------------------------------
Total financial instruments 4,372
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 2010, a $0.10 change to the price per thousand cubic feet of
natural gas on the contracts outlined above would have a $0.1 million impact on
net income.
As at September 30, 2010, a $1.00 per barrel change to the price of oil on the
contracts outlined above would have a $0.9 million impact on net income.
As at September 30, 2010, a $0.01 change to the exchange rate on the foreign
exchange contracts outlined above would have less than a $0.1 million impact on
net income.
As at September 30, 2010, a 0.1% change to the interest rate on the interest
rate contracts outlined above would have less than a $0.1 million impact on net
income.
Subsequent to September 30, 2010, the Company entered into the following
financial derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional Strike
Contract Quantity Term Reference Price Option Traded
----------------------------------------------------------------------------
2,500 January 1, 2011 - AECO C Monthly
Gas gj/day December 31, 2011 Index $4.85 Swap (note 1)
2,500 January 1, 2011 - AECO C Monthly
Gas gj/day December 31, 2011 Index $4.90 Swap (note 1)
5,000 January 1, 2011 - AECO C Monthly
Gas gj/day December 31, 2011 Index $5.00 Swap (note 1)
500 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $88.00 Swap
500 January 1, 2012 -
Oil bbl/day December 31, 2012 US$ WTI US$85.00 Call (note 1)
500 January 1, 2012 -
Oil bbl/day December 31, 2012 US$ WTI US$90.00 Call (note 1)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Derivative contracts are part of a paired transaction in which the
proceeds from the sale of 2012 oil calls were used to fund the 2011
natural gas swaps at the prices indicated.
Fair value of financial instruments
The Company's financial instruments as at September 30, 2010 and 2009 include
accounts receivable, derivative contracts, accounts payable and accrued
liabilities, and bank debt. The fair values of accounts receivable and accounts
payable and accrued liabilities approximate their carrying amounts due to their
short-terms to maturity.
The fair value of derivative contracts is determined by discounting the
difference between the contracted price and published forward price curves as at
the balance sheet date, using the remaining contracted notional volumes.
Bank debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.
8. Capital management:
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes adjustments
on an on-going basis in order to maintain the flexibility needed to achieve the
Company's long-term objectives. To manage the capital structure the Company may
adjust capital spending, hedge future revenue and some costs, issue new equity,
issue new debt or repay existing debt through asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1.0. This ratio may increase at certain times as a result of acquisitions or low
commodity prices. As shown below, as at September 30, 2010, the Company's ratio
of net debt to annualized funds from operations was 1.52 to 1 (December 31, 2009
- 1.67 to 1).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2010 2009
----------------------------------------------------------------------------
Net debt:
Accounts receivable $ 43,182 $ 37,574
Accounts payable and accrued liabilities (79,314) (84,228)
----------------------------------------------------------------------------
Working capital deficiency $ (36,132) $ (46,654)
Bank loan (110,770) (135,601)
----------------------------------------------------------------------------
Net debt $ (146,902) $ (182,255)
----------------------------------------------------------------------------
Annualized funds from operations:
Cash provided by operating activities $ 19,596 $ 16,734
Asset retirement expenditures 201 111
Transportation liability charge 156 329
Change in non-cash working capital 4,151 10,082
----------------------------------------------------------------------------
Funds from operations 24,104 27,256
Annualized $ 96,416 $ 109,024
Net debt to annualized funds from operations 1.52 1.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company has commodity, interest rate and foreign exchange hedging for 2010
and 2011 to provide support for its funds from operations and assist in funding
its capital expenditure program.
There has been no change in the Company's approach to capital management during
the period ended September 30, 2010.
9. Supplemental cash flow information:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2010 2009 2010 2009
----------------------------------------------------------------------------
Changes in non-cash working
capital:
Accounts receivable $ (13,548) $ 762 $ (5,608) $ 15,044
Accounts payable and
accrued liabilities 14,794 23,653 (4,914) (15,021)
----------------------------------------------------------------------------
$ 1,246 $ 24,415 $ (10,522) $ 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities $ (4,151) $ 5,786 $ 4,488 $ 11,191
Investing activities 5,397 18,629 (15,010) (11,168)
----------------------------------------------------------------------------
$ 1,246 $ 24,415 $ (10,522) $ 23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company made the following cash outlays in respect of interest expense:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
Sept. 30, 2010 Sept. 30, 2009 Sept. 30, 2010 Sept. 30, 2009
----------------------------------------------------------------------------
Interest $ 1,325 $ 1,662 $ 3,887 $ 5,850
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. Commitments:
The Company has the following fixed term commitments related to its on-going
business:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Operating
Leases $ 3,490 $ 432 $ 1,743 $ 1,315 $ - $ - $ -
Capital
commitments 5,000 3,000 2,000 - - - -
Transportation
agreements 12,802 1,157 4,018 955 953 953 4,766
Processing
agreement 28,204 762 3,049 3,049 3,049 3,049 15,246
----------------------------------------------------------------------------
Total $ 49,496 $ 5,351 $10,810 $ 5,319 $ 4,002 $ 4,002 $ 20,012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The transportation agreements include an $8.8 million commitment to a third
party to transport natural gas from the gas processing facility in the Septimus,
British Columbia area to the Alliance pipeline system. The remaining commitment
relates to firm transportation commitments that were acquired as part of the
Company's May 2007 private company acquisition, of which, in 2010, the Company
permanently assigned approximately $6.2 million of its firm commitments to third
parties.
During 2009, Crew entered into an agreement to process natural gas through a
third party owned gas processing facility in the Septimus area of northeast
British Columbia. Under the terms of the agreement, Crew has committed to
process a minimum monthly volume of gas through the facility commencing on
December 1, 2009 and continuing through November 30, 2019. The commitment is
included in the above table.
Subsequent to the quarter end, the Company amended the agreement with the owner
of this facility. Under the terms of the amended agreement, Crew has begun
expansion of the existing facility. On completion of the facility, Crew will be
reimbursed for the full cost of the facility in return for an expanded
processing commitment that will extend to December 2020. Crew has also retained
the option to re-purchase a 50% interest in the facility at certain dates prior
to January 1, 2014 at a cost of 50% of the total expanded facility's
construction cost.
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
