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, 2011.
Highlights
-- Third quarter production of 27,510 boe per day was 111% higher than the
same period of 2010 and 67% higher than the second quarter of 2011;
-- Production per diluted share increased 43% over the same period of 2010
and 21% over the second quarter of 2011;
-- Oil and natural gas liquids production increased 107% over the previous
quarter to 14,164 bbls per day;
-- Crew drilled a record 66 (65.2 net) wells in the third quarter of which
54 wells were oil wells;
-- Operating costs decreased 5% over the second quarter of 2011 to $10.79
per boe;
-- Funds from operations increased to $54.3 million or 131% over the same
period of 2010 and 88% over the second quarter of 2011;
-- Funds from operations per share increased 55% over the third quarter of
2010 and 36% over the second quarter of 2011;
-- The Company completed the fall review of its bank facility with its
banking syndicate who are now finalizing approvals to increase the
Company's borrowing base to $430 million;
-- Crew completed the acquisition of Caltex Energy Inc. on July 1, 2011 and
fully integrated the operations of the two companies during the quarter.
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Three Three Nine Nine
months months months months
ended ended ended ended
Financial September September September September
($ thousands, except per 30, 30, 30, 30,
share amounts) 2011 2010 2011 2010
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Petroleum and natural gas
sales 114,719 44,924 246,103 149,723
Funds from operations (note
1) 54,260 23,464 107,262 70,757
Per share - basic 0.45 0.29 1.12 0.89
- diluted 0.45 0.29 1.10 0.87
Net income (loss) 12,232 (17,281) 18,367 32,033
Per share - basic 0.10 (0.22) 0.19 0.40
- diluted 0.10 (0.22) 0.19 0.39
Capital expenditures 138,671 64,498 267,021 185,265
Property acquisitions (net of
dispositions) - - (12,289) (132,640)
Net capital expenditures 138,671 64,498 254,732 52,625
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As at As at
Capital Structure September December
($ thousands) 30, 2011 31, 2010
----------------------------------------------------------------------------
Working capital deficiency
(note 2) 100,551 40,707
Bank loan 194,038 138,700
Net debt 294,589 179,407
Bank facility (note 3) 430,000 240,000
Common Shares Outstanding
(thousands) 119,597 80,368
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Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital,
decommissioning obligation expenditures, the transportation liability
charge and acquisition costs. Funds from operations is used to analyze
the Company's operating performance and leverage. Funds from operations
does not have a standardized measure prescribed by International
Financial Reporting Standards and therefore may not be comparable with
the calculations of similar measures for other companies.
(2) Working capital deficiency includes only accounts receivable and assets
held for sale less accounts payable and accrued liabilities.
(3) The Company's bank syndicate is seeking the appropriate approvals for
the increase in the Facility.
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Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
30, 30, 30, 30,
Operations 2011 2010 2011 2010
----------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 80,078 48,188 63,398 49,863
Conventional Oil (bbl/d) 4,910 3,803 5,384 3,788
Heavy Oil (bbl/d) 6,633 - 2,235 -
Natural gas liquids (bbl/d) 2,621 1,227 1,712 1,265
Oil equivalent (boe/d @
6:1) 27,510 13,061 19,897 13,364
Average prices (note 1)
Natural gas ($/mcf) 3.90 4.07 3.98 4.63
Conventional oil ($/bbl) 71.36 62.86 74.53 67.16
Heavy oil ($/bbl) 63.66 - 63.66 -
Natural gas liquids ($/bbl) 61.69 43.21 61.81 50.13
Oil equivalent ($/boe) 45.33 37.39 45.31 41.04
Netback
Operating netback ($/boe)
(note 2) 23.75 21.87 22.36 22.32
Realized gain on financial
instruments ($/boe) - (0.24) - (0.15)
G&A ($/boe) 1.50 1.59 1.73 1.87
Interest on bank debt
($/boe) 0.81 0.99 0.88 1.20
Funds from operations
($/boe) 21.44 19.53 19.75 19.40
Drilling Activity
Gross wells 66 26 121 59
Working interest wells 65.2 24.9 119.5 55.4
Success rate, net wells 98% 100% 99% 100%
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Notes:
(1) Average prices are before deduction of transportation costs and do not
include hedging gains and losses.
(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 International Financial Reporting
Standards and therefore may not be comparable with the calculations of
similar measures for other companies.
Overview
Operations during the third quarter of 2011 were highlighted by the drilling of
a record 66 (65.2 net) wells with a 98% success rate. At Princess, Alberta, the
Company drilled 45 (45.0 net) oil wells, five (5.0 net) salt water disposal
wells and one (1.0 net) dry and abandoned well. At Lloydminster, Saskatchewan,
the Company drilled four (4.0 net) horizontal oil wells and three (2.8 net)
vertical oil wells. In the Deep Basin of west central Alberta, the Company
drilled eight (7.4 net) wells resulting in two (2.0 net) oil wells and six (5.4
net) natural gas liquids wells.
Production in the third quarter averaged 27,510 boe per day, up 67% from the
second quarter reflecting a full quarter of production from the Caltex Energy
Inc. ("Caltex") assets. On July 1, 2011, Crew closed the acquisition of Caltex
adding approximately 10,500 boe per day of production.
Financial Summary and Risk Management
The Company's funds from operations increased to $54.3 million in the third
quarter as a result of the increase in production that accompanied the Caltex
acquisition. The acquisition of Caltex has increased the strength of the
Company's financial position through an increased production weighting of higher
valued liquids and lower costs resulting in higher netbacks despite a lower
commodity price environment.
Year to date, the Company's hedging program has added $2.2 million of cash flow.
For the fourth quarter of 2011, the Company has 17.5 mmcf per day of natural gas
hedged at an average fixed price of $4.95 per mcf and 6,000 bbl per day of oil
hedged at a minimum floor price of Canadian dollar WTI $83.43 per bbl.
Crew has also established commodity hedges to help underpin cash flow for 2012.
Crew has entered into Canadian dollar WTI oil price swaps and floors on an
average of 4,500 bbl per day for 2012. These transactions averaged a minimum
floor price of approximately CDN $90.50 per bbl for WTI oil. The Company has
also entered into derivative contracts to fix the differential price between
CDN$ WTI and CDN$ Western Canadian Select crude pricing for 2,000 bbls per day
at an average of $16.63. Natural gas pricing remains depressed as a result of
oversupply in the North American market. With the forward price outlook of
Canadian natural gas through 2012 remaining flat compared to current pricing,
Crew has not entered into any 2012 natural gas hedges. The Company is continuing
to monitor the market and will consider 2012 hedges if we see an increase above
the current levels. 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 $138.7 million. These expenditures were financed
through a combination of funds flow from operations and an increase in the
Company's net debt. Crew assumed net debt of $66 million on the closing of the
Caltex acquisition bringing total net debt at the end of the third quarter to
$295 million. The Company's balance sheet remains strong with a debt to
annualized third quarter funds from operations of 1.36. The Company completed
the fall review of its bank facility with the banks now finalizing approvals on
an increase in the Company's borrowing base to $430 million.
OPERATIONS UPDATE
Pekisko Play - Princess, Alberta
During the third quarter, Crew drilled 45 (45.0 net) oil wells at Princess. The
Company also drilled five (5.0 net) water disposal wells and completed
turnarounds and infrastructure upgrades at the West Tide Lake and Alderson oil
batteries to handle the increasing fluid production from the active third
quarter drilling program. As these upgrades were recently completed, only 10 of
the wells drilled in the third quarter were on production by the end of the
quarter. With current production over 8,000 boe per day and 31 wells to place on
production, Crew will focus on the tie-in and optimization of wells to meet its
target exit rate of 10,000 to 12,000 boe per day.
Well results to date continue to track or exceed the current production type
curve. The last eleven horizontal wells tied in during October and November
tested at average swab or flow rates of 683 boe per day per well. Initial
production rates from horizontal wells are generally 35% of the test rate, or
240 boe per day, which is above the current average initial production rate of
210 boe per day. Completion of the infrastructure upgrades will result in
further production optimization from these wells and a corresponding higher
initial production rate relative to swab and test rates. Low costs of $1.3
million per well, reduced capital associated with drilling fewer water disposal
wells, declining operating costs and strong well performance result in a recycle
ratio of approximately three to four times and rates of return in excess of
300%.
At Alderson South, the original vertical exploration discovery at 15-9-16-12 W4
has produced 103,600 boe in nine months. An offset vertical well drilled in the
third quarter at 14-9 swab tested at 590 boe per day and is expected to be on
production at 175 to 225 boe per day in November. With the drilling of another
exploration well two miles south, Crew believes it has delineated a three to
four square mile area for future development.
At Tilley, a second waterflood was initiated in the third quarter as the Company
begins to implement its secondary recovery strategy with expectations that oil
recovery factors could increase from an average of 9.2% currently booked
effective December 31, 2010 on primary recovery by the Company's external
reserve engineers, to 24% to 30%. Waterflood applications are expected to be
submitted to the ERCB for an additional five pools prior to the end of the year
with implementation to occur in the third and fourth quarters of 2012. As a
result of the waterflood commencement at Tilley and Crew recently receiving
approvals to inject into four additional water disposal wells, the Company is
now only trucking oil and water from single well batteries. This initiative has
resulted in a reduction of approximately $600,000 per month in operating costs
from the area. Looking forward, the Company is not expecting to truck water from
its batteries for disposal to third parties.
Crew is expanding capacity at Alderson through the installation of a compressor
to accommodate solution gas from increased production volumes and is also
installing an additional battery in the area early in 2012 to handle additional
production. Currently 55,000 bbls per day of water are being disposed or
injected at Princess. By year end, the Company expects to have capacity in its
facilities for 17,400 bbls per day of oil and 131,000 bbls per day of water and
will have well injection/disposal capacity of 98,000 bbls per day of water. This
excess capacity is expected to adequately handle fluid volumes through 2012.
Heavy Oil, Lloydminster, Saskatchewan
Crew drilled four (4.0 net) horizontal wells for production from the Sparky
formation and three (2.8 net) vertical wells for production from the McLaren and
Sparky formations. The horizontal wells were drilled to evaluate the
effectiveness of this technology on undeveloped pools, as well as a downspacing
technique to increase recovery from pools previously developed with vertical
wells. The Company expects to drill an additional five vertical wells in the
fourth quarter and undertake up to 30 workovers and recompletions, with capital
costs of less than $0.5 million per new drilling location and less than $0.1
million per workover resulting in estimated capital efficiencies of less than
$10,000 per boe per day.
Montney Play - Northeast British Columbia
Efficiencies at Septimus continue to improve with production rates steadily
improving over the last four years. Initial production rates have improved with
wells completed in 2011 experiencing a 150% increase to an average 770 boe per
day compared to wells completed in 2008. Production at Septimus has remained
very economic in the current low gas environment. The significant condensate
weighted liquids yield from the natural gas production combined with a low
royalty rate and low operating costs resulted in an operating netback of over
$21.00 per boe in the third quarter.
Prior to the end of the third quarter, the Company spudded the first horizontal
well of a three well pad at Septimus. It is expected these wells will be
completed and producing prior to the end of the year. An additional two wells at
Septimus are planned to be drilled prior to year-end and drilling operations are
planned through spring break-up in 2012.
The Company also spudded the first of two horizontal wells in the Kobes area of
British Columbia to confirm productivity and reserve potential of the three
Montney horizons in the area.
Deep Basin, West Central Alberta
In the Deep Basin of west central Alberta, Crew drilled eight (7.4 net) wells
targeting oil and liquids rich gas. At Pine Creek, Alberta, the Company drilled
two (2.0 net) Cardium horizontal wells and at Wapiti/Elmworth, Alberta the
Company drilled two (1.6 net) Cardium horizontal wells and completed one
additional horizontal well for liquids rich natural gas. At Wapiti/Elmworth, one
well achieved a test rate of 4.3 mmcf per day with a flowing casing pressure of
5,200 kPa and an expected liquids recovery of 70 to 80 barrels per million cubic
feet. One (0.8 net) Belly River well was drilled at Wapiti testing 2.1 mmcf per
day with liquids recovery of 90 barrels per million cubic feet. The Company also
drilled three (3.0 net) wells at Pine Creek which are now being completed.
Exploration
At Tower, British Columbia, east of Septimus, Crew completed one (0.33 net)
horizontal Montney well for oil production. The well is awaiting tie-in and will
be further evaluated once on production for an extended period of time. The
Company has 23 net sections on this play which will continue to be developed and
de-risked in 2012.
Outlook
Crew had its most active quarter in its history drilling 66 wells and spending
$138.7 million. This allowed the Company to catch-up on its drilling program
which was delayed due to a prolonged spring break up. Current production is
estimated at 30,000 boe per day and the Company expects to tie in nine liquids
rich gas wells and 31 oil wells in the fourth quarter to achieve our forecasted
2011 exit production rate of 32,500 to 34,500 boe per day.
We have moved forward with plans to accelerate our winter drilling program at
Septimus and Kobes to avoid the expected shortage of available services in
northeastern British Columbia. As a result, we have added six wells to our
fourth quarter drilling program and plan to complete four of these later in the
quarter. This program will result in an additional $20 million of capital
expenditures increasing total net exploration and development expenditures to
$350 million for the year.
As part of our continuous asset review process, Crew has a number of non-core
properties for sale comprised of approximately 1,400 boe per day of production
and 6.2 mmboe of proved plus probable reserves as independently evaluated
effective December 31, 2010. Bids are due by November 15 with successfully
negotiated transactions from this program expected to close in the first quarter
of 2012.
The integration of the Caltex personnel and assets has gone extremely well. We
are very pleased with the contribution of our "Crew" in this process and we
would like to commend all of our staff for making this a very successful
transaction. The Caltex assets have performed above expectation, which is
confirmation of the abilities of the personnel, the quality of the assets and
the successful integration into Crew.
Since Crew's inception in 2003, we have focused on successfully capturing
accumulations of large hydrocarbons in place. The next phase is to realize the
value of this resource through the efficient execution of our capital programs
to profitably grow production. We will continue to focus on the development and
exploration of the Princess Pekisko oil play and the Lloydminster heavy oil area
in Saskatchewan, two of the most economic oil plays in North America. As well,
Crew will continue to de-risk and add resource and reserves in the liquids rich
window of the Montney play in British Columbia. We look forward to reporting our
progress in this next phase of development in January 2012 when we will release
our 2012 budget.
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 interim consolidated
financial statements of the Company for the three and nine month periods ended
September 30, 2011 and 2010 and the audited consolidated financial statements
and Management's Discussion and Analysis for the year ended December 31, 2010.
In 2010, the CICA Handbook was revised to incorporate International Fainancial
Reporting Standards ("IFRS"), and require publicly accountable enterprises to
apply such standards effective for years beginning on or after January 1, 2011.
Previously, the Company prepared its interim and annual consolidated financial
statements in accordance with Canadian generally accepted accounting principles
("previous GAAP"). The interim consolidated financial statements have been
prepared in accordance with IFRS and all figures provided herein and in the
December 31, 2010 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, 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 implementing
accounting policies, estimates regarding undeveloped land position and estimated
future drilling, recompletion or reactivation locations and anticipated impact
upon Crew's forecasts in respect of production and cash flow for 2011 and
resulting year-end net debt 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 approvals and inability 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, 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; the anticipated increase to the Company's banking facility;
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-IFRS Measures
Funds from Operations
One of the benchmarks Crew uses to evaluate its performance is funds from
operations. Funds from operations is a measure not defined in IFRS that is
commonly used in the oil and gas industry. It represents cash provided by
operating activities before changes in non-cash working capital, decommissioning
obligation expenditures, the transportation liability charge and acquisition
costs. The Company considers it a key measure as it demonstrates the ability of
the Company's continuing operations 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 IFRS 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:
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Three Three Nine Nine
months months months months
ended ended ended ended
September September September September
30, 30, 30, 30,
($ thousands) 2011 2010 2011 2010
----------------------------------------------------------------------------
Cash provided by operating
activities 54,095 18,956 113,460 73,701
Decommissioning obligation
expenditures 540 201 661 906
Transportation liability
charge (note 1) 104 156 308 638
Acquisition costs (note 2) 455 - 2,605 -
Change in non-cash working
capital (934) 4,151 (9,772) (4,488)
----------------------------------------------------------------------------
Funds from operations 54,260 23,464 107,262 70,757
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Notes:
(1) The amount for the nine months ended September 30, 2010 does not include
the transportation liability write-down of $344,000 as shown in the
transportation costs section.
(2) This amount relates to costs incurred for the Caltex acquisition that
closed on July 1, 2011. See Finance Expenses section for further
details.
Operating Netback
Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by IFRS and therefore may not be comparable
with the calculation of similar measures for other entities. Operating netback
equals total petroleum and natural gas sales including realized gains and losses
on commodity derivative contracts less royalties, operating costs and
transportation costs calculated on a boe basis. Management considers operating
netback an important measure to evaluate its operational performance as it
demonstrates its field level profitability relative to current commodity prices.
The calculation of Crew's netbacks can be seen below in the Operating Netbacks
section.
Working Capital and Net Debt
The Company closely monitors its capital structure with a goal of maintaining a
strong balance sheet in order to fund the future growth of the Company. Crew
monitors working capital and net debt as part of its capital structure. Working
capital and net debt do not have a standardized meaning prescribed by IFRS and
therefore may not be comparable with the calculation of similar measures for
other entities. The following tables outline Crew's calculation of working
capital and net debt:
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September
30, December 31,
($ thousands) 2011 2010
----------------------------------------------------------------------------
Current assets 86,078 61,020
Current liabilities (180,640) (101,088)
Fair value of financial instruments (6,024) (982)
Current portion of other long-term obligations 35 343
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Working capital deficit (100,551) (40,707)
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----------------------------------------------------------------------------
September
30, December 31,
($ thousands) 2011 2010
----------------------------------------------------------------------------
Bank loan (194,038) (138,700)
Working capital deficit (100,551) (40,707)
----------------------------------------------------------------------------
Net debt (294,589) (179,407)
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----------------------------------------------------------------------------
RESULTS OF OPERATIONS
Acquisition of Caltex
On July 1, 2011, Crew closed the previously announced acquisition whereby the
Company acquired all of the issued and outstanding shares of Caltex Energy Inc.
("Caltex"), a Canadian private oil and gas company with operations in
Saskatchewan and Alberta (the "Transaction"). Caltex shareholders received 0.38
of a Crew common share for each Caltex share held or an aggregate of
approximately 33.6 million Crew shares. Upon closing of the Transaction, Caltex
became a wholly owned subsidiary of Crew and immediately following closing,
former Caltex shareholders owned approximately 28% of the combined entity.
Crew believes the Transaction represents the successful continuation of our
strategy of exploiting high netback assets with significant resource potential.
At the date of acquisition, the Caltex assets were producing approximately
10,500 boe per day.
The business combination has been accounted for using the purchase method with
the results of operations of Caltex included in the Company's financial and
operating results commencing July 1, 2011. The allocation of net assets acquired
is based on the best available information at this time and could be subject to
further change. The transaction was accounted for by the acquisition method,
with the preliminary allocation of the purchase price based on estimated fair
values as described in note 4 of the interim consolidated financial statements
of the Company for the period ended September 30, 2011.
Production
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
Sept. 30, 2011
Conv. Oil Heavy Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta 4,795 8 1,618 41,747 13,379
British Columbia 115 - 1,003 37,796 7,417
Saskatchewan - 6,625 535 6,714
----------------------------------------------------------------------------
Total 4,910 6,633 2,621 80,078 27,510
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
Sept. 30, 2010
Conv. Oil Heavy Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta 3,670 - 388 22,243 7,765
British Columbia 133 - 839 25,945 5,296
Saskatchewan - - - - -
----------------------------------------------------------------------------
Total 3,803 - 1,227 48,188 13,061
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's third quarter production increased 111% over the same period in 2010 due
to the acquisition of Caltex on July 1, 2011 and the Company's successful
organic drilling programs in Alberta and northeastern British Columbia. Third
quarter conventional oil production increased 29% compared to the same period in
2010 as a result of the successful drilling program in the Princess, Alberta
area. Heavy oil production was added through the acquisition of Caltex. In the
third quarter of 2011, Alberta natural gas and associated natural gas liquids
("ngl") production increased 108% over the same period in 2010 predominantly due
to production additions from the Caltex acquisition combined with additional
natural gas production in the Princess area. British Columbia natural gas and
associated ngl production increased 42% due to the successful drilling program
in late 2010 and 2011 in the Septimus, British Columbia area.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended
Sept. 30, 2011
Conv. Oil Heavy Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta 5,270 3 809 28,735 10,871
British Columbia 114 - 903 34,483 6,764
Saskatchewan - 2,232 - 180 2,262
----------------------------------------------------------------------------
Total 5,384 2,235 1,712 63,398 19,897
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended
Sept. 30, 2010
Conv. Oil Heavy Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta 3,663 - 537 24,887 8,348
British Columbia 125 - 728 24,976 5,016
Saskatchewan - - - - -
----------------------------------------------------------------------------
Total 3,788 - 1,265 49,863 13,364
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production for the first nine months of 2011 increased due to the previously
mentioned acquisition of Caltex and the successful drilling programs in the
Septimus and Princess areas partially offset by the disposition of approximately
1,700 boe per day of natural gas and associated ngl production in the Edson,
Alberta area in the second quarter of 2010.
Revenue
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2011 2010 2011 2010
----------------------------------------------------------------------------
Revenue ($ thousands)
Conventional oil 32,233 21,994 109,539 69,451
Heavy oil 38,847 - 38,847 -
Natural gas 28,765 18,052 68,833 62,965
Natural gas liquids 14,874 4,878 28,884 17,307
----------------------------------------------------------------------------
Total 114,719 44,924 246,103 149,723
----------------------------------------------------------------------------
Crew average prices
Conventional oil
($/bbl) 71.36 62.86 74.53 67.16
Heavy oil ($/bbl) 63.66 - 63.66 -
Natural gas ($/mcf) 3.90 4.07 3.98 4.63
Natural gas liquids
($/bbl) 61.69 43.21 61.81 50.13
Oil equivalent ($/boe) 45.33 37.39 45.31 41.04
Benchmark pricing
Conv. oil - Bow River
Crude Oil (Cdn $/bbl) 81.89 73.15 85.15 76.88
Heavy oil - Western
Can. Select (Cdn
$/bbl) 70.63 62.91 74.31 67.02
Natural Gas - AECO C
daily index (Cdn
$/mcf) 3.71 3.59 3.82 4.19
Oil and ngl - Cdn$
West Texas Int. (Cdn
$/bbl) 87.89 79.18 93.28 80.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's third quarter revenue increased 155% as compared to the same period in
2010 as a result of the previously discussed 111% increase in production
combined with a 21% increase in commodity prices made up of an increase in
conventional oil and ngl pricing partially offset by a decrease in the Company's
natural gas pricing.
In the third quarter of 2011, the Company's realized conventional oil price
increased 14% which was comparable with the increase in the Bow River Crude
benchmark of 12% for the same period in 2010. The Company's natural gas
benchmark price increased 3% in the third quarter compared with same period in
2010 while the Company's realized average natural gas price decreased 4% over
the same period in 2010. In the third quarter of 2010, Crew had a $5.85 per gj
fixed price physical gas sales contract which increased the realized corporate
gas price by approximately $0.25 per mcf. This contract expired in November
2010. The Company's realized ngl price increased disproportionately in the third
quarter of 2011 compared with the increase in the Company's benchmark Cdn$ West
Texas Intermediate price due to increased production of higher priced condensate
in the Septimus area in 2011 and the addition of higher priced ngl volumes from
the Caltex conventional assets in west central Alberta.
Heavy oil production was added July 1, 2011 as part of the Caltex acquisition.
Heavy oil pricing was $6.97 below the benchmark Western Canadian Select pricing
reflecting the Company's cost of diluent to blend its heavy oil production to
pipeline specifications.
For the first nine months of 2011, both the Company's realized conventional oil
price and ngl price increased proportionately to the increases in the respective
Company benchmark prices as for the same period in 2010. For the first nine
months of 2011, the Company's realized natural gas price decreased 14% over the
same period in 2010 compared to the Company's Aeco benchmark which decreased 9%
for the same period as a result of the previously mentioned $5.85 per gj fixed
price physical contract that the Company held for January through October 2010.
Royalties
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, except Sept. 30, Sept. 30, Sept. 30, Sept. 30,
per boe) 2011 2010 2011 2010
----------------------------------------------------------------------------
Royalties 25,897 8,920 56,827 30,488
Per boe 10.23 7.42 10.46 8.36
Percentage of revenue 22.6% 19.9% 23.1% 20.4%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties as a percentage of revenue increased in the third quarter and first
nine months of 2011 compared to the same period in 2010 due to the addition of
heavy oil and liquids rich natural gas production from the Caltex acquisition
which on average attracts a higher royalty rate than the Company's historical
production. In addition, the Company increased production in the Princess area
which also attracts a higher royalty rate than Crew's other producing areas.
Crew continues to project royalty rates to average between 23% and 25% for 2011.
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 limit exposure to fluctuations in commodity prices,
differentials, 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 2011, these contracts had the
following impact on the consolidated statement of income:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
($ thousands) 2011 2010 2011 2010
----------------------------------------------------------------------------
Realized gain on
financial
instruments 2,180 5,114 2,195 9,798
Unrealized
gain/(loss) on
financial
instruments 17,025 (5,326) 16,762 5,206
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 2011, the Company held derivative commodity contracts as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
AECO C
2,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $4.85 Swap(1) 313
AECO C
2,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $4.90 Swap(1) 322
AECO C
2,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $4.95 Swap(1) 333
AECO C
2,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $4.965 Swap(1) 448
AECO C
7,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $5.00 Swap(1) 1,160
500 January 1, 2011 -
Oil bbl/day December 31, 2011 US$ WTI US$80.15 Swap 37
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $86.00 Swap 64
500 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $88.00 Swap 233
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $88.50 Swap 140
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $90.00 Swap 155
500 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $90.20 Swap 317
250 January 1, 2011 - $80.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $95.45 Collar 54
250 January 1, 2011 - $82.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $94.62 Collar 56
250 January 1, 2011 - $85.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $100.50 Collar 118
1,000 July 1, 2011 - $75.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $100.00 Collar 174
1,000 July 1, 2011 - $80.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $98.50 Collar 292
1,000 July 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $89.75 Swap 709
500 January 1, 2012 -
Oil bbl/day December 31, 2012 US$ WTI US$85.00 Call(1) (1,738)
750 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $90.00 Call(1) (2,199)
500 January 1, 2012 -
Oil bbl/day December 31, 2012 US$ WTI US$90.00 Call(1) (1,418)
250 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $100.45 Swap 1,377
500 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $101.00 Swap 2,847
250 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $100.50 Swap 1,382
500 January 1, 2012 - $85.00 -
Oil bbl/day December 31, 2012 CDN$ WTI $93.55 Collar 671
500 January 1, 2012 - $85.00 -
Oil bbl/day December 31, 2012 CDN$ WTI $93.25 Collar 623
CDN$ WCS
1,000 January 1, 2012 - - WTI
Oil bbl/day December 31, 2012 Diff $17.50 Swap (446)
----------------------------------------------------------------------------
Total 6,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) These 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.
Subsequent to September 30, 2011, the Company entered into the following
financial instrument contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Strike Price Option
Contract Volume Term Reference (per bbl) Traded
----------------------------------------------------------------------------
1,000 January 1, 2012 - $85.00 -
Oil bbl/day December 31, 2012 CDN$ WTI $95.00 Collar
500 January 1, 2012 - $85.00 -
Oil bbl/day December 31, 2012 CDN$ WTI $94.50 Collar
1,000 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $94.00 Swap
CDN$ WCS
1,000 January 1, 2012 - - WTI
Oil bbl/day December 31, 2012 Diff $15.75 Swap
Sell US
US$ / CAD$ $1.0 mm January 1, 2012 -
exchange per month December 31, 2012 US$/CDN$ 1.0531 Swap
Buy US
US$ / CAD$ $1.0 mm January 1, 2012 -
exchange per month December 31, 2012 US$/CDN$ 1.037 Swap
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, except Sept. 30, Sept. 30, Sept. 30, Sept. 30,
per boe) 2011 2010 2011 2010
----------------------------------------------------------------------------
Operating costs 27,303 12,318 60,754 39,967
Per boe 10.79 10.25 11.18 10.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the third quarter of 2011, the Company's operating costs per unit increased
over the same period in 2010 due to the higher cost production added as part of
the Caltex acquisition and increased higher cost production from the Princess
area. This was partially offset by increased production in the Septimus area
which has a lower cost per unit than the Company's average operating cost per
boe. For the first nine months of 2011, the Company's operating costs per unit
increased as compared to the same period in 2010 due to the second quarter 2010
sale of the Edson properties which had a lower cost per boe and the addition of
the higher cost Caltex production on July 1, 2011. With the addition of the
Caltex properties, the Company forecasts operating costs to average $11.00 to
$11.50 per boe for 2011.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, except Sept. 30, Sept. 30, Sept. 30, Sept. 30,
per boe) 2011 2010 2011 2010
----------------------------------------------------------------------------
Transportation costs
including liability
write-down 3,598 2,243 9,265 6,763
Transportation
liability write-down - - - 344
----------------------------------------------------------------------------
Transportation costs 3,598 2,243 9,265 7,107
Per boe 1.42 1.87 1.71 1.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the third quarter and first nine months of 2011, the Company's transportation
costs per boe decreased compared to the same periods in 2010 due to additional
production at Princess and Septimus combined with production from the
acquisition of Caltex which all attract a lower transportation cost per boe
compared with the Company's other producing areas. The Company expects
transportation costs per boe to range between $1.60 and $1.70 per boe for 2011.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
Sept. 30, 2011 Sept. 30, 2010
Oil and Natural Oil and Natural
ngl gas Total ngl gas Total
($/bbl) ($/mcf) ($/boe) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 65.97 3.90 45.33 58.07 4.07 37.39
Realized commodity
hedging gain
(loss) (0.10) 0.31 0.86 2.29 0.85 4.02
Royalties (17.49) (0.42) (10.23) (15.88) (0.35) (7.42)
Operating costs (13.57) (1.31) (10.79) (12.17) (1.51) (10.25)
Transportation
costs (1.16) (0.30) (1.42) (1.44) (0.36) (1.87)
----------------------------------------------------------------------------
Operating netbacks 33.65 2.18 23.75 30.87 2.70 21.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Nine months ended
Sept. 30, 2011 Sept. 30, 2010
Oil and Natural Oil and Natural
ngl gas Total ngl gas Total
($/bbl) ($/mcf) ($/boe) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 69.59 3.98 45.31 62.90 4.63 41.04
Realized commodity
hedging gain
(loss) (1.76) 0.39 0.40 0.98 0.58 2.54
Royalties (19.88) (0.36) (10.46) (17.24) (0.50) (8.36)
Operating costs (13.78) (1.48) (11.18) (12.69) (1.65) (10.95)
Transportation
costs (1.41) (0.35) (1.71) (1.38) (0.38) (1.95)
----------------------------------------------------------------------------
Operating netbacks 32.76 2.18 22.36 32.57 2.68 22.32
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, except Sept. 30, Sept. 30, Sept. 30, Sept. 30,
per boe) 2011 2010 2011 2010
----------------------------------------------------------------------------
Gross costs 5,976 3,624 14,571 11,723
Operator's recoveries (150) (242) (370) (610)
Capitalized costs (2,034) (1,477) (4,786) (4,281)
----------------------------------------------------------------------------
General and
administrative
expenses 3,792 1,905 9,415 6,832
Per boe 1.50 1.59 1.73 1.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increased general and administrative costs after recoveries and capitalization
for the third quarter and first nine months of 2011 were the result of increased
staff levels to accommodate the Company's increased production levels and the
acquisition of Caltex. The Company's general and administrative costs per boe
have decreased in the third quarter and first nine months of 2011 due to the
increased production levels over the same periods in 2010. The introduction of
IFRS has resulted in the Company altering the recoveries and the capitalization
of some general and administrative costs. As such, net general and
administrative expenses for the three and nine months ended September 30, 2010,
increased to $1.9 million and $6.8 million from $1.3 million and $4.6 million as
reported under previous GAAP. The Company expects general and administrative
expenses to average between $1.50 and $1.75 per boe for 2011.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
($ thousands) 2011 2010 2011 2010
----------------------------------------------------------------------------
Gross costs 4,215 2,514 8,927 7,303
Capitalized costs (2,023) (1,158) (4,191) (3,360)
----------------------------------------------------------------------------
Total stock-based
compensation 2,192 1,356 4,736 3,943
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the third quarter of 2011, the Company's stock-based compensation expense has
increased compared with the same period in 2010 due to an increase in the number
of stock options outstanding combined with the Company incurring higher
stock-based compensation costs in the first year of the option grants due to a
graded vesting schedule under IFRS.
Depletion and Depreciation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, except Sept. 30, Sept. 30, Sept. 30, Sept. 30,
per boe) 2011 2010 2011 2010
----------------------------------------------------------------------------
Depletion and
depreciation 51,699 20,332 95,793 57,919
Per boe 20.43 16.92 17.64 15.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total depletion and depreciation costs per boe have increased in the third
quarter and first nine months of 2011 compared to the same periods in 2010 due
to the addition of the fair market value of the Caltex assets at July 1, 2011
which was higher than the Company's book value for proved plus probable
reserves. This was partially offset by successful lower cost reserve additions
from the Company's drilling program over the past year. Under IFRS, Crew
depletes its assets on a component basis utilizing total proved plus probable
reserves including future development capital as opposed to depleting using
total proved reserves under previous GAAP.
Finance Expenses
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, except Sept.30, Sept.30, Sept.30, Sept.30,
per boe) 2011 2010 2011 2010
----------------------------------------------------------------------------
Interest on bank debt 2,049 1,188 4,775 4,370
Accretion of the
decommissioning
obligation 737 479 1,743 1,488
Acquisition costs 455 - 2,605 -
----------------------------------------------------------------------------
Total finance expense 3,241 1,667 9,123 5,858
Average debt level 155,053 79,623 118,329 88,431
Effective interest rate
on bank debt 5.2% 5.9% 5.4% 6.6%
Interest on bank debt
per boe 0.81 0.99 0.88 1.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the third quarter of 2011, interest on bank debt increased 72% over the same
period in 2010 as higher average debt levels from the acquisition of Caltex and
increased capital spending were partially offset by lower margins on the
Company's bank facility. For the first nine months of 2011, the Company's
effective interest rate on bank debt was lower than the same period in 2010 due
to lower margins on the Company's bank facility combined with reduced deferred
financing costs. The Company projects its effective interest rate on bank debt
will average 5.0% to 5.5% in 2011.
The accretion of the decommissioning obligation increased in the third quarter
and first nine months of 2011 compared to the same period in 2010 due to
additional accretion on the Caltex decommissioning obligation which was acquired
on July 1, 2011. Acquisition costs are those expenditures incurred by Crew
during the three and nine months ended September 30, 2011 related to the
acquisition of Caltex. Under IFRS, costs such as legal, accounting and
regulatory fees associated with the acquisition of a business are expensed in
the period in which they are incurred.
Deferred Income Taxes
In the third quarter of 2011, the provision for deferred income taxes was $4.0
million compared to a $5.5 million recovery for the same period in 2010 due to
higher pre-tax earnings in the third quarter of 2011. For the first nine months,
the provision for deferred incomes taxes was $5.5 million compared to $10.4
million for the same period in 2010 due to higher pre-tax earnings in 2010.
Cash and Funds from Operations and Net Income
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, except Sept. 30, Sept. 30, Sept. 30, Sept. 30,
per share amounts) 2011 2010 2011 2010
----------------------------------------------------------------------------
Cash provided by
operating activities 54,095 18,956 113,460 73,701
Funds from operations 54,260 23,464 107,262 70,757
Per share - basic 0.45 0.29 1.12 0.89
- diluted 0.45 0.29 1.10 0.87
Net income 12,232 (17,281) 18,367 32,033
Per share - basic 0.10 (0.22) 0.19 0.40
- diluted 0.10 (0.22) 0.19 0.39
----------------------------------------------------------------------------
The third quarter and first nine months of 2011 increase in cash provided by
operating activities and funds from operations was the result of increased oil
and ngl pricing combined with higher production levels. The increase in the
third quarter net income compared with the same period in 2010 was the result of
an impairment loss of approximately $18.7 million being recorded on the
Company's natural gas properties in 2010. The decrease in net income in the
first nine months of 2011 compared with the same period in 2010 was the result
of a significant gain on sale recorded on the disposition of the Edson
properties in the second quarter of 2010.
Capital Expenditures, Property Acquisitions and Dispositions
During the third quarter, the Company drilled a total of 66 (65.2 net) wells
resulting in 54 (53.8 net) oil wells, six (5.4 net) natural gas wells, five (5.0
net) service wells and one (1.0 net) dry and abandoned well. In addition, the
Company completed 64 (63.3 net) wells and recompleted 36 (33.6 net) wells in the
quarter. The Company continued to add to its infrastructure spending $28.0
million on pipelines and upgrading its batteries and facilities predominantly in
the Princess area. Total net capital expenditures for the quarter are detailed
below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
($ thousands) 2011 2010 2011 2010
----------------------------------------------------------------------------
Land 1,299 2,866 3,715 37,738
Seismic 2,502 182 10,678 5,277
Drilling and
completions 103,902 47,719 190,437 114,610
Facilities, equipment
and pipelines 28,032 11,304 56,160 23,074
Other 2,936 2,427 6,031 4,566
----------------------------------------------------------------------------
Total exploration and
development 138,671 64,498 267,021 185,265
Property acquisitions
(dispositions) - - (12,289) (132,640)
----------------------------------------------------------------------------
Total 138,671 64,498 254,732 52,625
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liquidity and Capital Resources
Capital Funding
The Company has completed the fall review of its bank facility with its
syndicate of lending banks (the "Syndicate"). The Syndicate is currently
finalizing approvals on an increase in the Company's facility to $430 million.
The increased credit facility will include a revolving line of credit of $400
million and an operating line of credit of $30 million (the "Facility"). The
Facility revolves for a 364 day period and will be subject to its next 364 day
extension by June 11, 2012. 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. 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 borrowing base review on or before June
11, 2012. At September 30, 2011, the Company had drawings of $194.0 million on
the Facility and had issued letters of credit totaling $10.2 million.
On March 2, 2011, the Company closed a bought deal sale of 4,820,000 Common
Shares of the Company at a price of $20.75 per share for aggregate gross
proceeds of $100 million.
During the first nine months of 2011, the Company received proceeds of $7.4
million upon the exercise of 801,800 employee stock options.
The Company will continue to fund its on-going operations from a combination of
cash flow, debt, non-core 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. Working capital deficit includes
accounts receivable less accounts payable and accrued liabilities. The Company
maintains sufficient unused bank credit lines to satisfy working capital
deficits. At September 30, 2011, the Company's working capital deficiency
totaled $100.6 million which, when combined with the drawings on its bank line
at September 30, 2011, represented approximately 69% of its increased $430
million bank facility.
Share Capital
As at November 7, 2011, Crew had 119,695,438 Common Shares and options to
acquire 7,668,300 Common Shares of the Company issued and outstanding.
Capital Structure
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes adjustments
on an on-going basis in order to maintain the flexibility needed to achieve the
Company's long-term objectives. To manage the capital structure the Company may
adjust capital spending, hedge future revenue and costs, issue new equity, issue
new debt or repay existing debt through asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1.0. This ratio may increase at certain times as a result of acquisitions or low
commodity prices. As shown below, as at September 30, 2011, the Company's ratio
of net debt to annualized funds from operations was 1.36 to 1 (December 31, 2010
- 1.63 to 1).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except ratio) Sept. 30, 2011 Dec. 31, 2010
----------------------------------------------------------------------------
Working capital deficit (100,551) (40,707)
Bank loan (194,038) (138,700)
----------------------------------------------------------------------------
Net debt (294,589) (179,407)
Funds from operations 54,260 27,449
Annualized 217,040 109,796
Net debt to annualized funds from operations
ratio 1.36 1.63
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contractual Obligations
Throughout the course of its ongoing business, the Company enters into various
contractual obligations such as credit agreements, purchase 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
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 2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
Bank Loan (note
1) 194,038 - - 194,038 - - -
Operating
leases 14,008 592 3,796 2,210 2,340 2,470 2,600
Capital
commitments 2,100 - 2,100 - - - -
Firm
transportation
agreements 19,632 1,613 1,535 1,535 2,110 2,110 10,728
Firm processing
agreement 73,055 1,645 6,526 6,526 8,239 8,239 41,880
----------------------------------------------------------------------------
Total 302,833 3,850 13,957 204,309 12,689 12,819 55,208
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2013. However, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.
The operating leases include the Company's contractual obligation to a third
party for its new five year lease of additional office space.
The transportation agreements include an $18.4 million commitment to a third
party to transport natural gas from a gas processing facility in the Septimus
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. 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 committed to process a minimum monthly
volume of gas through the facility commencing on December 1, 2009 and continuing
through November 30, 2019.
In the fourth quarter of 2010, the Company amended the agreement with the owner
of this facility. Under the terms of the amended agreement, Crew constructed a
facility expansion during the fourth quarter of 2010 and subsequently closed the
sale of the Septimus facility expansion in the first quarter of 2011. Upon
completion of the expansion, Crew was reimbursed for the cost of the facility
expansion of $16.9 million in return for an expanded processing commitment that
will extend to December 2020. As part of the amended agreement, 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. If the Company re-purchases a 50% interest on
January 1, 2014 for approximately $18.0 million, the remaining commitment would
be reduced by approximately $29.0 million.
Guidance
Crew had its most active quarter in its history drilling 66 wells and spending
$138.7 million. This allowed the Company to catch-up on its drilling program
which was delayed due to a prolonged spring break up. Current production is
estimated at 30,000 boe per day and the Company expects to tie in nine liquids
rich gas wells and 31 oil wells in the fourth quarter to achieve our forecasted
2011 exit production rate of 32,500 to 34,500 boe per day.
We have moved forward with plans to accelerate our winter drilling program at
Septimus and Kobes to avoid the expected shortage of available services in
northeastern British Columbia. As a result, we have added six wells to our
fourth quarter drilling program and plan to complete four of these later in the
quarter. This program will result in an additional $20 million of capital
expenditures increasing total net exploration and development expenditures to
$350 million for the year.
As part of our continuous asset review process, Crew has a number of non-core
properties for sale comprised of approximately 1,400 boe per day of production
and 6.2 mmboe of proved plus probable reserves as independently evaluated
effective December 31, 2010. Successfully negotiated transactions from this
program are expected to close in the first quarter of 2012.
Additional Disclosures
Quarterly Analysis
The following table summarizes Crew's key quarterly financial results for the
past eight financial quarters:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per share Sept. 30 June 30 Mar. 31 Dec. 31
amounts) 2011 2011 2011 2010
----------------------------------------------------------------------------
Total daily production (boe/d) 27,510 16,443 15,607 14,654
Average wellhead price ($/boe) 45.33 46.94 43.53 42.00
Petroleum and natural gas sales 114,719 70,236 61,148 56,620
Cash provided by operations 54,095 32,896 26,469 20,225
Funds from operations 54,260 28,891 24,111 27,449
Per share - basic 0.45 0.34 0.29 0.34
- diluted 0.45 0.33 0.29 0.34
Net income (loss) 12,232 16,261 (10,126) (14,214)
Per share - basic 0.10 0.19 (0.12) (0.18)
- diluted 0.10 0.19 (0.12) (0.18)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per share Sept. 30 June 30 Mar. 31 Dec. 31
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 18,956 23,422 31,323 16,734
Funds from operations 23,464 19,966 27,327 27,256
Per share - basic 0.29 0.25 0.35 0.35
- diluted 0.29 0.24 0.34 0.35
Net income (loss) (17,281) 31,544 17,770 (9,154)
Per share - basic (0.22) 0.39 0.23 (0.12)
- diluted (0.22) 0.39 0.22 (0.12)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The 2010 and 2011 quarterly results have been adjusted to conform to
IFRS. The quarterly results for 2009 have not been adjusted and reflect
the results in accordance with previous GAAP.
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.
-- Over the past two years, the price of natural gas has been negatively
impacted by an increasing supply of natural gas coming from new
technology tapping into abundant supplies of tight shale gas reservoirs
in North America. With depressed natural gas prices, Crew has focused
its capital expenditures towards oil development with higher netbacks.
This has resulted in the commodity mix moving towards more oil and the
Company's overall netbacks improving revenues and funds from operations.
-- Production in the second quarters of 2010 and 2011 was negatively
impacted by scheduled and unscheduled third party facility shutdowns and
poor weather experienced in southern Alberta during the second quarters
of 2010 and 2011 and third quarter of 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. 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.
-- From 2009 to 2011, the Company sold assets with approximately 2,440 boe
per day of production for $182.9 million. The major dispositions closed
as follows:
-- Fourth quarter 2009 - 600 boe per day for $25.3 million
-- Second quarter 2010 - 1,700 boe per day for $123.3 million
-- Second quarter 2011 - 140 boe per day for $12.6 million
-- Three dispositions of assets in the Ferrier and Edson areas resulted in
gains on sale of assets of $9.9 million, $37.0 million and $4.7 million
in the first and second quarters of 2010 and the second quarter of 2011,
respectively.
-- The Company acquired Caltex Energy Inc. on July 1, 2011 adding
approximately 10,500 boe per day of production and the results of
operations of Caltex are included in the Company's financial and
operating results commencing July 1, 2011.
-- The Company incurred impairment charges of $18.7 million and $10.4
million on two of its natural gas weighted CGUs in the third and fourth
quarters of 2010, respectively.
New Accounting Pronouncements
International Financial Reporting Standards
Effective January 1, 2011, Canadian public companies are required to adopt
International Financial Reporting Standards ("IFRS") which will include
comparatives for 2010. Note 15 to the interim consolidated financial statements
provides reconciliations between the Company's 2010 previous GAAP results and
its 2010 results under IFRS. The reconciliations include the consolidated
statement of financial position as at September 30, 2010, and consolidated
statements of income and comprehensive income for the three and nine months
ended September 30, 2010.
The following provides summary reconciliations of Crew's January 1, 2010
previous GAAP to IFRS transitional Summary Statement of Financial Position
reconciliations along with a discussion of the significant IFRS accounting
policy changes:
Summary Statement of Financial Position Reconciliations
As at Date of IFRS Transition - January 1, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effect of
Previous Transition
($ thousands) GAAP Note to IFRS IFRS
----------------------------------------------------------------------------
Current assets 38,116 (542) 37,574
Exploration and evaluation - (1) 35,591 35,591
Property, plant and equipment 925,132 (1) (35,591) 889,541
----------------------------------------------------------------------------
963,248 (542) 962,706
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current liabilities 86,375 - 86,375
Bank loan 135,601 - 135,601
Other long-term obligations 132 - 132
Decommissioning obligations 35,341 (6) 17,722 53,063
Deferred tax liability 101,519 (6) (5,031) 96,488
Share capital 617,605 (8) 3,383 620,988
Contributed surplus 22,769 (7) 2,737 25,506
Deficit (36,094) (6,7,8) (19,353) (55,447)
----------------------------------------------------------------------------
963,248 (542) 962,706
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On transition to IFRS, on January 1, 2010, Crew used certain exemptions allowed
under IFRS 1 First Time Adoption of International Financial Reporting Standards.
The exemptions used were as follows:
1. Oil and gas properties are classified as Property, Plant and Equipment
("PP&E") or Exploration and Evaluation assets ("E&E"). Crew reclassified
all E&E expenditures included in the PP&E balance under previous GAAP,
as a separate item under IFRS. These assets are measured at cost and are
not depleted but will be assessed for impairment when indicators suggest
the possibility of impairment. Once these E&E assets have reached
technical feasibility and commercial viability, they are transferred to
PP&E. At the time of transfer, they were subjected to an impairment
test. Crew's E&E assets primarily consist of undeveloped exploration
lands and at January 1, 2010 were valued at $35.6 million.
2. Under IFRS, PP&E assets are grouped into areas designated as cash
generating units ("CGU") for the purposes of impairment testing and
further broken down into components within the CGU for purposes of
depletion and depreciation. IFRS 1 provides for the allocation of the
previous GAAP net book value of PP&E assets, excluding E&E assets, to
CGUs and components on a pro rata basis using the reserve volumes or
values as at December 31, 2009. Crew has elected to allocate the PP&E
balance using reserve values and at January 1, 2010, the value allocated
to the PP&E assets is $889.5 million.
3. Under previous GAAP, impairment testing of oil and gas properties is
performed at a cost centre level. Under IFRS, impairment testing is
performed at the CGU level. This will result in a greater number of
impairment tests. At January 1, 2010, Crew did not have any impairment
of its PP&E under IFRS.
4. Depletion and depreciation of PP&E is calculated at a component level.
Depletion of resource properties within PP&E is calculated using the
unit-of-production method under IFRS using proved plus probable
reserves. Depreciation of office equipment will continue to be
calculated using a declining balance method.
5. IFRS 1 allows Crew to use the IFRS rules for business combinations on a
prospective basis rather than restating all business combinations. Crew
elected to use this exemption; therefore, Crew did not record any
adjustments to retrospectively restate any of its business combinations
that have occurred prior to January 1, 2010.
6. Under previous GAAP, Crew's decommissioning obligation was discounted
over its life based on a credit adjusted risk free rate which was 8% to
10% at December 31, 2009. Under IFRS, Crew is required to revalue its
liability for decommissioning costs at each balance sheet date using a
current liability-specific discount rate. As a result, the Company's
decommissioning obligation increased upon transition to IFRS as the
liability was re-valued using a discount rate of 4% to reflect the
Company's estimated risk-free rate of interest. The re-valued
decommissioning obligation at the transition date was $53.1 million with
the offsetting $17.7 million (net of $4.5 million of the deferred tax
liability) increase in the liability being charged to retained earnings
as also provided for under the deemed cost election for full cost oil
and gas companies.
7. Under previous GAAP, Crew expensed stock-based compensation on a
straight-line basis. Under IFRS, share-based payments are expensed based
on a graded vesting schedule. Crew also incorporated a forfeiture
multiplier rather than account for forfeitures as they occur as was
practiced under previous GAAP. The adjustment to contributed surplus to
account for the graded vesting and forfeitures was an increase of $2.7
million with the offset being charged to retained earnings.
8. Under previous GAAP, the deferred tax liability associated with the
renouncement of tax deductions from the issuance of flow through shares
was recorded as a reduction in share capital at the time of
renouncement. Under IFRS, the difference between the deferred tax
liability associated with the renouncement of the tax deductions and the
premium price received on the issuance of flow through shares over the
market value of the Company's common shares at the time of issue is
recorded as a deferred tax expense at the time of the renouncement. This
deferred tax expense effectively represents the net loss on the
distribution of the tax deductions to investors. The transitional
adjustment resulted in an increase of $3.4 million to share capital with
a resulting offset being charged to retained earnings.
Use of estimates and judgments:
The preparation of financial statements in conformity with IFRS requires
management to make judgments, estimates and assumptions that affect the
application of accounting policies and the reported amounts of assets,
liabilities, income and expenses. Actual results may differ from these
estimates.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions
to accounting estimates are recognized in the year in which the estimates are
revised and in any future years affected.
Reserve estimates including production profiles, future development costs, and
discount rates are a critical part of many of the estimated amounts and
calculations contained in the financial statements. These estimates are verified
by third party professional engineers, who work with information provided by the
Company to establish reserve determinations. These determinations are updated at
least on an annual basis, and more frequently as significant business
combinations take place.
Significant areas of estimation, uncertainty and critical judgments in applying
accounting policies that impact the amounts recognized in the interim
consolidated financial statements include:
-- Impairment testing - estimates of reserves, future commodity prices,
future costs, production profiles, discount rates, market value of land.
-- Depletion and depreciation - oil and natural gas reserves, including
future prices, costs and reserve base to use on calculation of
depletion.
-- Decommissioning obligations - estimates relating to amounts, likelihood,
timing, inflation and discount rates.
-- Stock-based compensation - forfeiture rates and volatility.
-- Derivatives - expected future oil and natural gas prices and expected
volatility in these prices; expected interest rates; expected future
foreign exchange rates.
-- Deferred tax - estimates of reversal of temporary differences, tax rates
substantively enacted, and likelihood of assets being realized.
-- Provisions and contingencies - estimates relating to onerous contracts,
including discount rates associated with long term contracts.
The following provides summary reconciliations of Crew's 2010 previous GAAP to
IFRS results:
Summary Statement of Financial Position Reconciliations
As at December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effect of
Previous Transition
($ thousands) GAAP Note to IFRS IFRS
----------------------------------------------------------------------------
Current assets 61,020 - 61,020
Exploration and evaluation - (1) 72,281 72,281
Property, plant and equipment 937,050 (1) (24,410) 912,640
----------------------------------------------------------------------------
998,070 47,871 1,045,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Current liabilities 101,088 - 101,088
Bank loan 138,700 - 138,700
Fair value of financial instruments 9,196 - 9,196
Decommissioning obligations 36,073 (2) 18,755 54,828
Deferred tax liability 96,330 (1,2) 6,149 102,479
Share capital 646,385 3,383 649,768
Contributed surplus 23,553 (3) 3,958 27,511
Deficit (53,255) (1,2,3) 15,626 (37,629)
----------------------------------------------------------------------------
998,070 47,871 1,045,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
1. The PP&E adjustment includes the impact of the reclassification of E&E
assets ($72.3 million decrease in PP&E), lower depletion as a result of
using proved plus probable reserves to calculate depletion ($31.6
million increase in PP&E), gains on sale of assets and gains on farmout
of assets ($48.2 million increase in PP&E), impairment on the Company's
gas focused CGUs ($29.1 million decrease in PP&E), reduction of
capitalized G&A, capital recoveries and associated deferred tax impact
($2.8 million decrease in PP&E).
2. Includes the adjustment to revalue the liability to a risk free interest
rate of 3.50% at December 31, 2010 and the related deferred tax impact.
3. Includes recalculation of stock based compensation incorporating graded
vesting and a forfeiture multiplier.
Summary Net Earnings Reconciliations
2010
----------------------------------------------------------------------------
($ thousands) Annual Q4 Q3 Q2 Q1
----------------------------------------------------------------------------
Net earnings/(loss) - previous
GAAP (17,161) (9,525) (7,387) (2,691) 2,442
Addition/(deduction):
General and administrative (3,244) (987) (640) (727) (890)
Stock-based compensation (1,020) (501) (322) (178) (19)
Depletion and depreciation 31,559 6,002 6,739 7,489 11,329
Decommissioning obligation
accretion 674 160 161 175 178
Gain on divestitures and
farmouts 48,242 - - 38,360 9,882
Property, plant and equipment
impairment (29,072) (10,336) (18,736) - -
Deferred income tax (12,159) 973 2,904 (10,884) (5,152)
----------------------------------------------------------------------------
34,980 (4,689) (9,894) 34,235 15,328
----------------------------------------------------------------------------
Net earnings/(loss) - IFRS 17,819 (14,214) (17,281) 31,544 17,770
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Impact of Transition to IFRS on 2010 Results:
-- Exploration and Evaluation ("E&E") - In 2010, Crew incurred $36.7
million of E&E expenditures acquiring undeveloped land and evaluating
its undeveloped land with seismic acquisitions. This amount was
reclassified from PP&E, under previous GAAP, to E&E under IFRS.
-- Divestitures and farmouts - Under previous GAAP, proceeds from
divestitures were deducted from the full cost pool without recognition
of a gain or loss unless the divestiture resulted in a change in the
depletion rate of 20% or greater in which case a gain or loss was
recorded. Under IFRS, gains and losses are recorded on divestitures and
farmouts and are calculated as the difference between the proceeds and
the net book value of the asset disposed of. For the year ended December
31, 2010, the Company recorded a $46.9 million gain on disposition of
oil and gas properties and an additional $1.3 million gain on farmouts
for IFRS as compared to nil under previous GAAP.
-- Impairment of PP&E - Under IFRS, impairment tests of PP&E are performed
at a CGU level as opposed to the entire Company's PP&E balance with a
full cost ceiling test under previous GAAP. Impairment is recognized if
the carrying value exceeds the recoverable amount for a CGU. The
recoverable amount is determined using fair value less costs to sell
based on discounted future cash flows of proved plus probable reserves
using forecast prices and costs. In the third quarter of 2010, as a
result of decreased natural gas prices and a subsequent decrease in the
Company's future natural gas prices used in the Company's reserves, Crew
incurred an $18.7 million impairment charge in certain CGUs. Further
deterioration in future natural gas pricing in the fourth quarter of
2010 resulted in the Company incurring an additional $10.4 million
impairment charge on the same natural gas weighted CGUs. PP&E
impairments can be reversed in the future if the recoverable amount
increases.
-- Depletion and depreciation expense - Under IFRS, Crew has chosen to
calculate the depletion expense utilizing proved plus probable reserves
as opposed to proved reserves under previous GAAP. This has resulted in
a reduction of depletion and depreciation expense of approximately $31.6
million in 2010.
Future Accounting Changes
The following pronouncements may have an impact on the Company's financial
statements and will become effective for financial reporting periods beginning
on or after January 1, 2013 and have not yet been adopted by the Company.
-- In November 2009, the IASB published IFRS 9, "Financial Instruments,"
which covers the classification and measurement of financial assets as
part of its project to replace IAS 39, "Financial Instruments;
Recognition and Measurement." In October 2010, the requirements for
classifying and measuring financial liabilities were added to IFRS 9.
Under this guidance, entities have the option to recognize financial
liabilities at fair value through earnings. If this option is elected,
entities would be required to reverse the portion of the fair value
change due to a company's own credit risk out of earnings and recognize
the change in other comprehensive income. IFRS 9 is effective for the
Company on January 1, 2013. Early adoption is permitted and the standard
is required to be applied retrospectively. The Company is currently
evaluating the impact of adopting IFRS 9.
-- IFRS 10 - Consolidated Financial Statements builds on existing
principles and standards and identifies the concept of control as the
determining factor in whether an entity should be included in the
consolidated financial statements of the parent company.
-- IFRS 11 - Joint Arrangements establishes the principles for financial
reporting by entities when they have an interest in jointly controlled
operations.
-- IFRS 12 - Fair Value Measurement defines fair value and requires
disclosure about fair value measurements.
-- IAS 27 - Separate Financial Statements revised the existing standard
which addresses the presentation of parent company financial statements
that are not consolidated financial statements.
-- IAS 28 - Investments in Associates and Joint Ventures revised the
existing standard and prescribes the accounting for investments and set
out the requirements for the application of the equity method when
accounting for investments in associates and joint ventures.
The Company has not completed its evaluation of the effect of adopting these
standards on its financial statements.
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.
The Company'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 IFRS. 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, 2011 and ended on September 30, 2011 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. There were no changes to internal controls
over financial reporting as a result of the transition to IFRS or the
acquisition of Caltex.
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 7, 2011
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" 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; year-end production; 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 including new infrastructure at Princess and anticipated capacity;
operating costs; the total future capital associated with development of
reserves and resources; anticipated increases in recovery factors related to the
Company's Tilley waterflood and forecast reductions in operating expenses; and
the impact of possible non-core asset dispositions and the timing thereof.
Forward-looking statements or information are based on a number of material
factors, expectations or assumptions of Crew which have been used to develop
such statements and information but which may prove to be incorrect. Although
Crew believes that the expectations reflected in such forward-looking statements
or information are reasonable, undue reliance should not be placed on
forward-looking statements because Crew can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified herein, assumptions have been made
regarding, among other things: the impact of increasing competition; the general
stability of the economic and political environment in which Crew operates; the
timely receipt of any required regulatory approvals; the ability of Crew to
obtain qualified staff, equipment and services in a timely and cost efficient
manner; drilling results; the ability of the operator of the projects in which
Crew has an interest in to operate the field in a safe, efficient and effective
manner; the ability of Crew to obtain financing on acceptable terms; the
anticipated increase to the Company's banking facility; field production rates
and decline rates; the ability to replace and expand oil and natural gas
reserves through acquisition, development and exploration; the timing and cost
of pipeline, storage and facility construction and expansion and the ability of
Crew to secure adequate product transportation; future commodity prices;
currency, exchange and interest rates; regulatory framework regarding royalties,
taxes and environmental matters in the jurisdictions in which Crew operates; the
ability of Crew to successfully market its oil and natural gas products; ability
to improve upon historical recovery factors.
The forward-looking information and statements included in this news release are
not guarantees of future performance and should not be unduly relied upon. Such
information and statements, including the assumptions made in respect thereof,
involve known and unknown risks, uncertainties and other factors that may cause
actual results or events to defer materially from those anticipated in such
forward-looking information or statements including, without limitation: changes
in commodity prices; changes in the demand for or supply of Crew's products;
unanticipated operating results or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters; changes in
development plans of Crew or by third party operators of Crew's properties,
increased debt levels or debt service requirements; inaccurate estimation of
Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack
of access to capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors; and certain other risks detailed from
time-to-time in Crew's public disclosure documents (including, without
limitation, those risks identified in this news release and Crew's Annual
Information Form).
The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Crew does not assume any
obligation to publicly update or revise any of the included forward-looking
statements or information, whether as a result of new information, future events
or otherwise, except as may be required by applicable securities laws.
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
Crew is an oil and gas exploration and production company whose shares are
traded on The Toronto Stock Exchange under the trading symbol "CR".
CREW ENERGY INC.
Consolidated Statements of Financial Position
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2011 2010
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 80,054 $ 44,922
Fair value of financial instruments (note 11) 6,024 982
Assets held for sale - 15,116
----------------------------------------------------------------------------
86,078 61,020
Exploration and evaluation assets (note 5) 76,923 72,281
Property, plant and equipment (note 6) 1,817,567 912,640
----------------------------------------------------------------------------
$ 1,980,568 $ 1,045,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 180,605 $ 100,745
Current portion of other long-term
obligations (note 8) 35 343
----------------------------------------------------------------------------
180,640 101,088
Fair value of financial instruments (note 11) - 9,196
Bank loan (note 7) 194,038 138,700
Decommissioning obligations (note 9) 99,465 54,828
Deferred tax liability 234,374 102,479
Shareholders' Equity
Share capital (note 10) 1,257,907 649,768
Contributed surplus 33,406 27,511
Deficit (19,262) (37,629)
----------------------------------------------------------------------------
1,272,051 639,650
Commitments (note 14)
----------------------------------------------------------------------------
$ 1,980,568 $ 1,045,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)
(unaudited)
(thousands, except per share amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
2011 2010 2011 2010
----------------------------------------------------------------------------
(note 15) (note 15)
Revenue
Petroleum and
natural gas sales $ 114,719 $ 44,924 $ 246,103 $ 149,723
Royalties (25,897) (8,920) (56,827) (30,488)
Realized gain on
financial
instruments (note
11) 2,180 5,114 2,195 9,798
Unrealized gain
(loss) on financial
instruments (note
11) 17,025 (5,326) 16,762 5,206
----------------------------------------------------------------------------
108,027 35,792 208,233 134,239
Expenses
Operating 27,303 12,318 60,754 39,967
Transportation (note
8) 3,598 2,243 9,265 6,763
General and
administrative 3,792 1,905 9,415 6,832
Share-based
compensation 2,192 1,356 4,736 3,943
Depletion and
depreciation 51,699 20,332 95,793 57,919
----------------------------------------------------------------------------
88,584 38,154 179,963 115,424
----------------------------------------------------------------------------
Income (loss) from
operations 19,443 (2,362) 28,270 18,815
Financing (note 13) (3,241) (1,667) (9,123) (5,858)
Gain on divestitures - - 4,697 48,242
Impairment of
property, plant and
equipment - (18,736) - (18,736)
----------------------------------------------------------------------------
Income (loss) before
income taxes 16,202 (22,765) 23,884 42,463
Deferred tax expense
(recovery) 3,970 (5,484) 5,477 10,430
----------------------------------------------------------------------------
Net income (loss)
and comprehensive
income (loss) $ 12,232 $ (17,281) $ 18,367 $ 32,033
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss)
per share (note 10)
Basic $ 0.10 $ (0.22) $ 0.19 $ 0.40
Diluted $ 0.10 $ (0.22) $ 0.19 $ 0.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Changes in Shareholders' Equity
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total
Number of Share Contributed Shareholders'
shares capital surplus Deficit equity
----------------------------------------------------------------------------
Balance January
1, 2011 80,368 $ 649,768 $ 27,511 $(37,629) $ 639,650
Net income for
the period - - - 18,367 18,367
Issue of shares
(net of issue
costs) 4,820 95,777 - - 95,777
Shares issued on
acquisition
(note 4) 33,606 501,911 - - 501,911
Share-based
compensation
expensed - - 4,736 - 4,736
Share-based
compensation
capitalized - - 4,191 - 4,191
Transfer of
stock-based
compensation on
exercises - 3,032 (3,032) - -
Issued on
exercise of
options 803 7,419 - - 7,419
----------------------------------------------------------------------------
Balance September
30, 2011 119,597 $ 1,257,907 $ 33,406 $(19,262) $ 1,272,051
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total
Number of Share Contributed Shareholders'
shares capital surplus Deficit equity
----------------------------------------------------------------------------
Balance January 1,
2010 78,152 $ 620,988 $ 25,506 $(55,447) $ 591,047
Net income for the
period - - - 32,033 32,033
Issue of shares
(net of issue
costs) - (36) - - (36)
Share-based
compensation
expensed - - 3,943 - 3,943
Share-based
compensation
capitalized - - 3,359 - 3,359
Transfer of stock-
based
compensation on
exercises - 7,535 (7,535) - -
Issued on exercise
of options 2,054 18,813 - - 18,813
----------------------------------------------------------------------------
Balance September
30, 2010 80,206 $ 647,300 $ 25,273 $(23,414) $ 649,159
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Cash Flows
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
2011 2010 2011 2010
----------------------------------------------------------------------------
Cash provided by
(used in):
Operating
activities:
Net income $ 12,232 $ (17,281) $ 18,367 $ 32,033
Adjustments:
Depletion and
depreciation 51,699 20,332 95,793 57,919
Financing expenses
(note 13) 3,241 1,667 9,123 5,858
Interest expense
(note 13) (2,049) (1,188) (4,775) (4,370)
Acquisition costs
(note 13) (455) - (2,605) -
Share-based
compensation 2,192 1,356 4,736 3,943
Deferred tax
expense
(recovery) 3,970 (5,484) 5,477 10,430
Unrealized (gain)
loss on financial
instruments (17,025) 5,326 (16,762) (5,206)
Gain on
divestitures - - (4,697) (48,242)
Impairment of
property, plant
and equipment - 18,736 - 18,736
Transportation
liability charge
(note 8) (104) (156) (308) (982)
Decommissioning
obligations
settled (540) (201) (661) (906)
Change in non-cash
working capital
(note 12) 934 (4,151) 9,772 4,488
----------------------------------------------------------------------------
54,095 18,956 113,460 73,701
Financing
activities:
Increase (decrease)
in bank loan 40,209 38,925 4,100 (24,831)
Issue of common
shares - - 100,015 -
Proceeds from
exercise of share
options 17 1,220 7,419 18,813
Share issue costs (420) - (5,664) (48)
----------------------------------------------------------------------------
39,806 40,145 105,870 (6,066)
Investing
activities:
Exploration and
evaluation asset
expenditures - (1,687) (8,819) (37,206)
Property, plant and
equipment
expenditures (138,671) (62,811) (258,202) (148,059)
Property
divestitures (net
of acquisitions) - - 12,289 132,640
Proceeds on sale of
asset held for
sale - - 15,116 -
Change in non-cash
working capital
(note 12) 44,770 5,397 20,286 (15,010)
----------------------------------------------------------------------------
(93,901) (59,101) (219,330) (67,635)
----------------------------------------------------------------------------
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, 2011 and 2010
(Unaudited)
(Tabular amounts in thousands)
1. Reporting entity:
Crew Energy Inc. ("Crew" or the "Company") is an oil and gas exploration,
development and production Company based in Calgary, Alberta, Canada. Crew
conducts its operations in the Western Canadian Sedimentary basin, primarily in
the provinces of Alberta, British Columbia and Saskatchewan. The consolidated
financial statements of the Company as at and for the three and nine months
ended September 30, 2011 comprise of the Company and its wholly owned
subsidiaries; Crew Resources Inc., Caltex Energy Inc., 1401466 Alberta Ltd. and
1401477 Alberta Ltd. (all of which are incorporated in Canada) and three
partnerships; Crew Energy Partnership, Caltex Heavy Oil Partnership and Caltex
Conventional Partnership. The consolidated financial statements of the Company
as at and for the three and nine months ended September 30, 2010 comprise of the
Company and its wholly owned subsidiary Crew Resources Inc. which are
incorporated in Canada, and a partnership, Crew Energy Partnership. The Company
conducts many of its activities jointly with others; these financial statements
reflect only the Company's proportionate interest in such activities.
2. Basis of preparation:
(a) Statement of compliance:
The interim consolidated financial statements have been prepared in accordance
with IAS 34 - Interim Financial Reporting of the International Financial
Reporting Standards ("IFRS"). IFRS 1 - First-time adoption of International
Financial Reporting Standards ("IFRS 1") has been applied to these interim
consolidated financial statements.
An explanation of how the transition to IFRS has affected the reported financial
position, financial performance and cash flows of the Company is provided in
note 15. The note includes reconciliations of equity and net loss for
comparative periods from former Canadian GAAP ("previous GAAP") to IFRS.
These interim consolidated financial statements follow the same accounting
policies and method of computation as shown in note 3 of the Company's interim
consolidated financial statements for the three months ended March 31, 2011.
These are the accounting policies the Company expects to adopt in its annual
consolidated financial statements for the year ended December 31, 2011, with the
exception of certain disclosures that are normally required to be included in
annual consolidated financial statements which have been condensed or omitted.
The consolidated financial statements were authorized for issue by the Board of
Directors on November 7, 2011.
(b) Basis of measurement:
The consolidated financial statements have been prepared on the historical cost
basis except for the derivative financial instruments that are measured at fair
value.
The methods used to measure fair values are discussed in note 3.
(c) Functional and presentation currency:
These consolidated financial statements are presented in Canadian dollars, which
is the Company's functional currency.
(d) Use of estimates and judgments:
The preparation of financial statements in conformity with IFRS requires
management to make judgments, estimates and assumptions that affect the
application of accounting policies and the reported amounts of assets,
liabilities, income and expenses. Actual results may differ from these
estimates.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions
to accounting estimates are recognized in the year in which the estimates are
revised and in any future years affected.
Reserve estimates including production profiles, future development costs, and
discount rates are a critical part of many of the estimated amounts and
calculations contained in the financial statements. These estimates are verified
by third party professional engineers, who work with information provided by the
Company to establish reserve determinations. These determinations are updated at
least on an annual basis.
Significant areas of estimation, uncertainty and critical judgments in applying
accounting policies that impact the amounts recognized in the interim
consolidated financial statements include:
-- Impairment testing - estimates of reserves, future commodity prices,
future costs, production profiles, discount rates, market value of land.
-- Depletion and depreciation - oil and natural gas reserves, including
future prices, costs and reserve base to use on calculation of
depletion.
-- Decommissioning obligations - estimates relating to amounts, likelihood,
timing, inflation and discount rates.
-- Stock-based compensation - forfeiture rates and volatility.
-- Derivatives - expected future oil and natural gas prices and expected
volatility in these prices; expected interest rates; expected future
foreign exchange rates.
-- Deferred tax - estimates of reversal of temporary differences, tax rates
substantively enacted, and likelihood of assets being realized.
-- Provisions and contingencies - estimates relating to onerous contracts,
including discount rates associated with long term contracts.
3. Determination of fair values:
A number of the Company's accounting policies and disclosures require the
determination of fair value, for both financial and non-financial assets and
liabilities. Fair values have been determined for measurement and/or disclosure
purposes based on the following methods. When applicable, further information
about the assumptions made in determining fair values is disclosed in the notes
specific to that asset or liability.
(i) Property, plant and equipment and intangible exploration assets:
The fair value of property, plant and equipment recognized in an acquisition is
based on market values. The market value of property, plant and equipment is the
estimated amount for which property, plant and equipment could be exchanged on
the acquisition date between a willing buyer and a willing seller in an arm's
length transaction after proper marketing wherein the parties had each acted
knowledgeably, prudently and without compulsion. The market value of oil and
natural gas interests (included in property, plant and equipment) and intangible
exploration assets is estimated with reference to the discounted cash flows
expected to be derived from oil and natural gas production based on externally
prepared reserve reports. The risk-adjusted discount rate is specific to the
asset with reference to general market conditions.
The market value of other items of property, plant and equipment is based on the
quoted market prices for similar items.
(ii) Cash and cash equivalents, accounts receivable, bank loans and accounts
payable:
The fair value of cash and cash equivalents, accounts receivable, bank loans and
accounts payable are estimated as the present value of future cash flows,
discounted at the market rate of interest at the reporting date. At September
30, 2011 and December 31, 2010, the fair value of these balances approximated
their carrying value due to their short term to maturity. Bank loans bear a
floating rate of interest and therefore carrying value approximates fair value.
(iii) Derivatives:
The fair value of forward contracts and swaps is determined by discounting the
difference between the contracted prices and published forward price curves as
at the balance sheet date, using the remaining contracted oil and natural gas
volumes and a risk-free interest rate (based on published government rates). The
fair value of options and costless collars is based on option models that use
published information with respect to volatility, prices and interest rates.
(iv) Stock options:
The fair value of employee stock options is measured using the Black Scholes
option pricing model. Measurement inputs include share price on measurement
date, exercise price of the instrument, expected volatility (based on weighted
average historic volatility adjusted for changes expected due to publicly
available information), weighted average expected life of the instruments (based
on historical experience and general option holder behaviour), expected
dividends, and the risk-free interest rate (based on government bonds).
4. Corporate Acquisition
On July 1, 2011, Crew Energy Inc. acquired all of the issued and outstanding
shares of Caltex Energy Inc. ("Caltex Energy"), a private exploration and
development company pursuing petroleum and natural gas production and reserves
in western Canada for total consideration of $501.9 million. The Company issued
33,606,404 shares at $14.93 per share based on the Company's trading price on
June 30, 2011, the last date of trading before Crew acquired control.
Acquisition related costs of approximately $2.6 million have been expensed as
period costs in the interim consolidated statement of income for the periods
ending September 30, 2011 (note 13).
The Company believes that the acquisition of Caltex Energy will allow its
shareholders to participate in the benefits of increased access to lower
geological risk plays with large resources in place which include multi-zone,
medium depth natural gas opportunities and multi-zone, shallow heavy oil
opportunities.
The acquisition has been accounted for using the purchase method with the
results of Caltex Energy's operations included in the Company's financial and
operating results commencing July 1, 2011. The allocation of net assets acquired
is based on the best available information at this time and could be subject to
further change. The transaction was accounted for by the acquisition method,
with the preliminary allocation of the purchase price based on estimated fair
values as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consideration:
Issue of 33,606,404 common shares $ 501,911
----------------------------------------------------------------------------
Net assets acquired:
Property, plant and equipment 729,074
Accounts receivable and other current assets 24,258
Accounts payable and other current liabilities (38,928)
Risk management contract (2,524)
Bank loan (51,238)
Deferred tax liability (127,844)
Decommissioning obligations (30,887)
----------------------------------------------------------------------------
$ 501,911
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The value attributed to the property, plant and equipment acquired was
determined in reference to an engineering report prepared by Caltex's third
party reserve engineers using proved plus probable reserves discounted at a rate
of 10%. Accounts receivable and payable are recognized at the contractual amount
and are expected to be collected and paid. Estimates regarding deferred taxes
may change as tax returns are finalized at the change of control and could
result in changes to the allocation.
Included in the consolidated statements of income and comprehensive income are
the following amounts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Caltex Energy amounts since acquisition
----------------------------------------------------------------------------
Petroleum and natural gas revenue $ 52,826
Loss and comprehensive loss (4,109)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
If Caltex Energy had been acquired on January 1, 2011, the incremental petroleum
and natural gas revenue and income recognized for the period ended September 30,
2011 and the pro forma results would have been as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Caltex Energy
prior to
Period ended September 30, 2011 As stated acquisition Pro Forma
----------------------------------------------------------------------------
Petroleum and natural gas
revenue $ 246,103 $ 108,150 $ 354,253
Income and comprehensive
income 18,367 8,396 26,763
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. Exploration and evaluation assets:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost or deemed cost Total
----------------------------------------------------------------------------
Balance, January 1, 2010 $ 35,591
Additions 37,234
Transfer to property, plant and equipment (544)
----------------------------------------------------------------------------
Balance, December 31, 2010 $ 72,281
Additions 8,819
Transfer to property, plant and equipment (4,177)
----------------------------------------------------------------------------
Balance, September 30, 2011 $ 76,923
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exploration and evaluation assets consist of the Company's exploration projects
which are pending the determination of proven or probable reserves. Additions
represent the Company's share of costs incurred on exploration and evaluation
assets during the period.
(a) Impairment charge:
The impairment of exploration and evaluation assets, and any eventual reversal
thereof, is recognized as additional depletion and depreciation expense in the
statement of income.
(b) Recoverability of exploration and evaluation assets:
The Company assesses the recoverability of exploration and evaluation assets,
before and at the moment of reclassification to property, plant and equipment,
using Cash Generating Units ("CGUs"). The CGU includes both the exploration and
evaluation CGU and CGUs related to oil and natural gas interests for that area,
but not larger than a segment.
6. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost or deemed cost Total
----------------------------------------------------------------------------
Balance, January 1, 2010 $ 889,541
Additions 223,508
Property acquisition 2,522
Transfer from exploration and evaluation assets 544
Divestitures (93,975)
Asset held for sale (15,116)
Change in decommissioning obligations 6,524
Capitalized stock-based compensation 4,717
----------------------------------------------------------------------------
Balance, December 31, 2010 $ 1,018,265
Additions 258,563
Transfer from exploration and evaluation assets 4,177
Divestitures (9,221)
Corporate acquisition (note 4) 729,074
Change in decommissioning obligations 13,671
Capitalized stock-based compensation 4,191
----------------------------------------------------------------------------
Balance, September 30, 2011 $ 2,018,720
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation Total
----------------------------------------------------------------------------
Balance, January 1, 2010 $ -
Depletion and depreciation expense 79,016
Divestitures (2,463)
Impairment 29,072
----------------------------------------------------------------------------
Balance, December 31, 2010 $ 105,625
Divestitures (265)
Depletion and depreciation expense 95,793
----------------------------------------------------------------------------
Balance, September 30, 2011 $ 201,153
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value Total
----------------------------------------------------------------------------
Balance, January 1, 2010 $ 889,541
Balance, December 31, 2010 $ 912,640
Balance, September 30, 2011 $ 1,817,567
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The calculation of depletion for the period ended September 30, 2011 included
estimated future development costs of $441.5 million (December 31, 2010 - $297.4
million) associated with the development of the Company's proved plus probable
reserves and excludes salvage value of $83.9 million (December 31, 2010 - $51.1
million) and undeveloped land of $131.2 million (December 31, 2010 - $110.6
million) related to development acreage.
(a) Impairment charge:
The impairment of property, plant and equipment, and any eventual reversal
thereof, are recognized in depletion and depreciation in the statement of
income.
(b) Contingencies:
Although the Company believes that it has title to its oil and natural gas
properties, it cannot control or completely protect itself against the risk of
title disputes or challenges.
7. Bank loan:
The Company's bank facility as at September 30, 2011 consisted of a revolving
line of credit of $370 million and an operating line of credit of $30 million
(the "Facility"). The Facility revolves for a 364 day period and will be subject
to its next 364 day extension by June 11, 2012. If not extended, the Facility
will cease to revolve, the margins thereunder will increase by 0.50 per cent 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. The Company's bank syndicate has completed its most
recent borrowing base review and is finalizing approvals on an increase in the
Company's facility to $430 million. The increased credit facility will include a
revolving line of credit of $400 million and an operating line of credit of $30
million. 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 11, 2012.
Advances under the Facility are available by way of prime rate loans with
interest rates between 1.00 percent and 2.50 percent over the bank's prime
lending rate and bankers' acceptances and LIBOR loans, which are subject to
stamping fees and margins ranging from 2.00 percent to 3.50 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 0.50 percent to 0.875 percent depending upon the debt to EBITDA
ratio.
As at September 30, 2011, the Company's applicable pricing included a 1.25
percent margin on prime lending and a 2.25 percent stamping fee and margin on
bankers' acceptances and LIBOR loans along with a 0.563 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, 2011, the Company had issued letters of credit totaling $10.2
million (December 31, 2010 - $1.1 million). The effective interest rate on the
Company's borrowings under its bank facility for the three months ended
September 30, 2011 was 5.2% (2010 - 5.9%).
8. Other long-term obligations:
As part of a May 3, 2007 private company acquisition, the Company acquired
several firm transportation agreements. These agreements had a fair value at the
time of acquisition of $4.9 million liability. This amount was accounted for as
part of the acquisition cost and is charged as a reduction to transportation
expenses over the life of the contracts as they are incurred. The charge for the
three months and nine months ended September 30, 2011 was $0.1 million and $0.3
million respectively (2010 - $0.2 million and $0.7 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.
9. Decommissioning obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at As at
September 30, December 31,
2011 2010
----------------------------------------------------------------------------
Decommissioning obligations, beginning of period $ 54,828 $ 53,063
Obligations incurred 4,920 3,383
Obligations settled (661) (1,512)
Obligations divested (1,003) (5,212)
Obligations acquired (note 4) 30,887 -
Change in estimates 8,751 3,141
Accretion of decommissioning liabilities 1,743 1,965
----------------------------------------------------------------------------
Decommissioning obligations, end of period $ 99,465 $ 54,828
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's decommissioning obligations result from its ownership interest in
oil and natural gas assets including well sites and facilities. The total
decommissioning obligation is estimated based on the Company's net ownership
interest in all wells and facilities, estimated costs to reclaim and abandon
these wells and facilities and the estimated timing of the costs to be incurred
in future years. The Company has estimated the net present value of the
decommissioning obligations to be $99.5 million as at September 30, 2011
(December 31, 2010 - $54.8 million) based on an undiscounted total future
liability of $108.3 million (December 31, 2010 - $63.4 million). These payments
are expected to be made over the next 25 years with the majority of costs to be
incurred between 2012 and 2036. The discount factor, being the risk-free rate
related to the liability, is 2.70% (December 31, 2010 - 3.50%).
10. Share capital:
At September 30, 2011, the Company was authorized to issue an unlimited number
of common shares with the holders of common shares entitled to one vote per
share.
Share based payments:
The Company has an option program that entitles officers, directors, employees
and certain consultants to purchase shares in the Company. Options are granted
at the market price of the shares at the date of grant, have a four year term
and vest over three years.
The number and weighted average exercise prices of share options are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number
of Weighted average
options exercise price
----------------------------------------------------------------------------
Balance January 1, 2010 5,751 $ 8.33
Granted 2,237 $ 15.18
Exercised (2,216) $ 9.28
Forfeited (442) $ 9.50
----------------------------------------------------------------------------
Balance December 31, 2010 5,330 $ 10.79
Granted 3,938 $ 16.40
Exercised (802) $ 9.25
Forfeited (615) $ 17.23
----------------------------------------------------------------------------
Balance at September 30, 2011 7,851 $ 13.26
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table summarizes information about the stock options outstanding
at September 30, 2011:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
average Weighted Exercisable Weighted
Range of Outstanding remaining average at average
exercise at September life exercise September exercise
prices 30, 2011 (years) price 30, 2011 price
----------------------------------------------------------------------------
$ 3.43 to
$ 7.01 1,020 1.3 $ 5.16 590 $ 5.17
$ 7.02 to
$ 9.94 1,055 0.4 $ 7.48 1,000 $ 7.38
$ 9.95 to
$14.63 516 2.9 $ 12.29 152 $ 12.96
$14.64 to
$19.40 5,260 3.1 $ 16.08 743 $ 15.30
----------------------------------------------------------------------------
7,851 2.4 $ 13.26 2,485 $ 9.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fair value of the options was estimated using a Black Scholes model with the
following weighted average inputs:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended, ended ended,
September 30, September 30, September 30, September 30,
Assumptions 2011 2010 2011 2010
----------------------------------------------------------------------------
Risk free interest
rate (%) 1.9 1.9 2.2 2.3
Expected life
(years) 4.0 4.0 4.0 4.0
Expected volatility
(%) 60 61 60 61
Forfeiture rate (%) 16.7 17.3 16.4 17.3
Weighted average
fair value of
options $ 6.76 $ 7.07 $ 7.77 $ 8.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per share:
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, 2011 was 119,595,000 (2010 - 80,129,000) and for the nine
month period ended September 30, 2011, the weighted average number of shares
outstanding was 96,069,000 (2010 - 79,561,000).
In computing diluted earnings per share for the three month period ended
September 30, 2011, 1,091,000 (2010 - nil) were added to the weighted average
Common Shares outstanding to account for the dilution of stock options and for
the nine month period ended September 30, 2011, 1,334,000 (2010 - 1,983,000)
were added to the weighted average number of common shares for the dilution.
There were 2,145,000 (2010 - 5,492,000) stock options that were not included in
the diluted earnings per share calculation because they were anti-dilutive.
11. Derivative contracts and capital management:
(a) Derivative contracts:
It is the Company's policy to economically hedge some oil and natural gas sales
through the use of various financial derivative forward sales contracts and
physical sales contracts. The Company does not apply hedge accounting for these
contracts. The Company's production is usually sold using "spot" or near term
contracts, with prices fixed at the time of transfer of custody or on the basis
of a monthly average market price. The Company, however, may give consideration
in certain circumstances to the appropriateness of entering into long term,
fixed price marketing contracts. The Company does not enter into commodity
contracts other than to meet the Company's expected sale requirements.
At September 30, 2011, the Company held derivative commodity contracts as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
AECO C
2,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $4.85 Swap(1) 313
AECO C
2,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $4.90 Swap(1) 322
AECO C
2,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $4.95 Swap(1) 333
AECO C
2,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $4.965 Swap(1) 448
AECO C
7,500 January 1, 2011 - Monthly
Natural Gas gj/day December 31, 2011 Index $5.00 Swap(1) 1,160
500 January 1, 2011 -
Oil bbl/day December 31, 2011 US$ WTI US$80.15 Swap 37
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $86.00 Swap 64
500 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $88.00 Swap 233
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $88.50 Swap 140
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $90.00 Swap 155
500 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $90.20 Swap 317
250 January 1, 2011 - $80.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $95.45 Collar 54
250 January 1, 2011 - $82.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $94.62 Collar 56
250 January 1, 2011 - $85.00 -
Oil bbl/day December 31, 2011 CDN$ WTI $100.50 Collar 118
1,000bbl/ July 1, 2011 - $75.00 -
Oil day December 31, 2011 CDN$ WTI $100.00 Collar 174
1,000bbl/ July 1, 2011 - $80.00 -
Oil day December 31, 2011 CDN$ WTI $98.50 Collar 292
1,000bbl/ July 1, 2011 -
Oil day December 31, 2011 CDN$ WTI $89.75 Swap 709
500 January 1, 2012 -
Oil bbl/day December 31, 2012 US$ WTI US$85.00 Call(1) (1,738)
750 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $90.00 Call(1) (2,199)
500 January 1, 2012 -
Oil bbl/day December 31, 2012 US$ WTI US$90.00 Call(1) (1,418)
500 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $100.45 Swap 1,377
500 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $101.00 Swap 2,847
250 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $100.50 Swap 1,382
250 January 1, 2012 - $85.00 -
Oil bbl/day December 31, 2012 USD$ WTI $93.55 Collar 671
500 January 1, 2012 - $85.00 -
Oil bbl/day December 31, 2012 CDN$ WTI $93.25 Collar 623
CDN$ WCS
1,000 January 1, 2012 - - WTI
Oil bbl/day December 31, 2012 Diff $17.50 Swap (446)
----------------------------------------------------------------------------
6,024
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) These 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.
Subsequent to September 30, 2011, the Company entered into the following
financial instrument contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Strike Price Option
Contract Volume Term Reference (per bbl) Traded
----------------------------------------------------------------------------
1,000 January 1, 2012 - $85.00 -
Oil bbl/day December 31, 2012 CDN$ WTI $95.00 Collar
500 January 1, 2012 - $85.00 -
Oil bbl/day December 31, 2012 CDN$ WTI $94.50 Collar
1,000 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN$ WTI $94.00 Swap
CDN$ WCS
1,000 January 1, 2012 - - WTI
Oil bbl/day December 31, 2012 Diff $15.75 Swap
Sell US
US$ / CAD$ $1.0 mm January 1, 2012 -
exchange per month December 31, 2012 CDN$/US$ 1.0531 Swap
Buy US
US$ / CAD$ $1.0 mm January 1, 2012 -
exchange per month December 31, 2012 CDN$/US$ 1.037 Swap
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(b) Capital management:
The Company's policy is to maintain a strong capital base so as to maintain
investor, creditor and market confidence and to sustain future development of
the business. The Company manages its capital structure and makes adjustments to
it in light of changes in economic conditions and risk characteristics of the
underlying oil and natural gas assets. The Company considers its capital
structure to include shareholders' equity, bank loans and working capital. In
order to maintain or adjust the capital structure, the Company may issue shares
and adjust its capital spending to manage current and projected debt levels.
The Company monitors capital based on the ratio of net debt to annualized cash
flow. This ratio is calculated as net debt, defined as outstanding bank loans
plus or minus working capital, divided by cash flow from operations before
decommissioning obligations settled, transportation liability charges,
acquisition costs and changes in non-cash working capital for the most recent
calendar quarter and then annualized. The Company's strategy is to maintain a
ratio of no more than 2 to 1. This ratio may increase at certain times as a
result of acquisitions. In order to facilitate the management of this ratio, the
Company prepares annual capital expenditure budgets, which are updated as
necessary depending on varying factors including current and forecast prices,
successful capital deployment and general industry conditions. The annual and
updated budgets are approved by the Board of Directors.
As at September 30, 2011, the Company's ratio of net debt to annualized cash
flow was 1.36 to 1, (December 31, 2010 - 1.63 to 1) within the range established
by the Company. There were no changes in the Company's approach to capital
management during the period.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2011 2010
----------------------------------------------------------------------------
Net debt:
Accounts receivable (including assets held for
sale) $ 80,054 $ 60,038
Accounts payable and accrued liabilities (180,605) (100,745)
----------------------------------------------------------------------------
Working capital deficiency $(100,551) $ (40,707)
Bank loan (194,038) (138,700)
----------------------------------------------------------------------------
Net debt $(294,589) $(179,407)
----------------------------------------------------------------------------
Annualized funds from operations:
Cash provided by operating activities $ 54,095 $ 20,225
Decommissioning obligations settled 540 606
Transportation liability charge 104 120
Acquisition costs 455 -
Change in non-cash working capital (934) 6,498
----------------------------------------------------------------------------
Funds from operations 54,260 27,449
Annualized $ 217,040 $ 109,796
Net debt to annualized funds from operations 1.36 1.63
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Neither the Company nor any of its subsidiaries are subject to externally
imposed capital requirements. The credit facilities are subject to a semi-annual
review of the borrowing base which is directly impacted by the value of the oil
and natural gas reserves.
12. Supplemental cash flow information:
Changes in non-cash working capital is comprised of:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
2011 2010 2011 2010
----------------------------------------------------------------------------
Changes in non-cash
working capital:
Accounts receivable $(37,802) $(13,548) $(35,132) $ (5,608)
Accounts payable and
accrued liabilities 98,176 14,794 79,860 (4,914)
Non-cash working
capital acquired (14,670) - (14,670) -
----------------------------------------------------------------------------
$ 45,704 $ 1,246 $ 30,058 $(10,522)
Operating activities $ 934 $ (4,151) $ 9,772 $ 4,488
Investing activities 44,770 5,397 20,286 (15,010)
----------------------------------------------------------------------------
$ 45,704 $ 1,246 $ 30,058 $(10,522)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ (1,536) $ (1,325) $ (4,262) $ (3,887)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
13. Financing:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
2011 2010 2011 2010
----------------------------------------------------------------------------
Accretion of
decommissioning
obligations $ 737 $ 479 $ 1,743 $ 1,488
Interest expense 2,049 1,188 4,775 4,370
Acquisition costs 455 - 2,605 -
----------------------------------------------------------------------------
$ 3,241 $ 1,667 $ 9,123 $ 5,858
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Acquisition costs relate to the Company's acquisition of Caltex Energy Inc.
(note 4).
14. Commitments:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
There-
Total 2011 2012 2013 2014 2015 after
----------------------------------------------------------------------------
Operating
Leases $ 14,008 $ 592 $ 3,796 $ 2,210 $ 2,340 $ 2,470 $ 2,600
Capital
commitments 2,100 - 2,100 - - - -
Firm trans-
portation
agreements 19,631 1,613 1,535 1,535 2,110 2,110 10,728
Firm
processing
agreement 73,055 1,645 6,526 6,526 8,239 8,239 41,880
----------------------------------------------------------------------------
Total $ 108,794 $ 3,850 $ 13,957 $ 10,271 $ 12,689 $ 12,819 $ 55,208
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The operating leases include the Company's contractual obligation to a third
party for its new five year lease of additional office space.
The transportation agreements include an $18.4 million commitment to a third
party to transport natural gas from a gas processing facility in the Septimus
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. In 2010, the Company permanently assigned
approximately $6.2 million of its firm commitments to third parties.
During 2009, Crew entered into a 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 committed to process a minimum monthly
volume of gas through the facility commencing on December 1, 2009 and continuing
through November 30, 2019.
In the fourth quarter of 2010, the Company amended the agreement with the owner
of this facility. Under the terms of the amended agreement, Crew constructed a
facility expansion during the fourth quarter of 2010 and subsequently closed the
sale of the Septimus facility expansion in the first quarter of 2011. Upon
completion of the expansion, Crew was reimbursed for the cost of the facility
expansion of $16.9 million in return for an expanded processing commitment that
will extend to December 2020. As part of the amended agreement, 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. If the Company re-purchases a 50% interest on
January 1, 2014 for approximately $18.0 million, the remaining commitment would
be reduced by approximately $29.0 million.
15. Reconciliation of equity and income from previous GAAP to IFRS:
These interim consolidated financial statements are the Company's third under IFRS.
The adoption of IFRS requires the application of IFRS 1. IFRS 1 generally
requires that an entity retrospectively apply all IFRS effective at the end of
its first IFRS reporting period; however IFRS 1 provides certain mandatory
exceptions and permits limited optional exemptions. Certain IFRS 1 optional
exemptions have been applied including:
-- Deemed cost exemption for full cost oil and gas entities whereby
exploration and evaluation assets were classified from the full cost
pool to intangible exploration assets at the amount that was recorded
under previous GAAP and the remaining full cost pool was allocated to
the development assets and components pro rata using reserve values.
-- Decommissioning obligation exemption that allows any changes in
decommissioning obligations on transition to IFRS to be adjusted through
opening retained earnings.
-- Stock-based compensation exemption that allows a company to only
evaluate share based compensation awards that were unvested as of the
date of transition and that were issued subsequent to November 7, 2002.
-- Business combinations exemption that allows a company to not restate any
business combinations that occurred prior to the date of transition.
The accounting policies in note 3 of the interim consolidated financial
statements for the three months ended March 31, 2011 have been applied in
preparing the interim consolidated financial statements for the three and nine
months ended September 30, 2011 and the comparative information for the three
and nine months ended September 30, 2010.
In preparing comparative information for the three and nine months ended
September 30, 2010, the Company adjusted amounts previously reported in
financial statements prepared in accordance with previous GAAP. An explanation
of how the transition from previous GAAP to IFRS has affected the Company's
financial position, financial performance and cash flows is set out in the
following tables and the notes accompanying the tables.
As at September 30, 2010:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effect of
Previous transition
GAAP to IFRS Note IFRS
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 43,182 $ - $ 43,182
Fair value of financial
instruments 4,372 - 4,372
----------------------------------------------------------------------------
47,554 - 47,554
Exploration and evaluation
assets - 72,617 B 72,617
Property, plant and equipment 898,413 (20,917) B,C,F 877,496
----------------------------------------------------------------------------
$ 945,967 $ 51,700 $ 997,667
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders'
Equity
Current Liabilities:
Accounts payable and accrued
liabilities $ 79,314 $ - $ 79,314
Deferred tax liability 991 (991) A -
Current portion of other long-
term obligations 463 - 463
----------------------------------------------------------------------------
80,768 (991) 79,777
Bank loan 110,770 - 110,770
Decommissioning obligations 33,735 17,320 D 51,055
Deferred tax liability 98,425 8,481 E 106,906
Shareholders' Equity
Share capital 643,917 3,383 E 647,300
Contributed surplus 22,082 3,191 G 25,273
Deficit (43,730) 20,316 (23,414)
----------------------------------------------------------------------------
622,269 26,890 649,159
----------------------------------------------------------------------------
$ 945,967 $ 51,700 $ 997,667
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of consolidated statement of income (loss) for the three months
ended September 30, 2010:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effect of
Previous transition
GAAP to IFRS Note IFRS
----------------------------------------------------------------------------
Revenue
Gross petroleum and natural gas
sales $ 44,924 $ - $ 44,924
Royalties (8,920) - (8,920)
Realized gain on financial
instruments 5,114 - 5,114
Unrealized loss on financial
instruments (5,326) - (5,326)
----------------------------------------------------------------------------
35,792 - 35,792
Expenses
Operating 12,318 - 12,318
Transportation 2,243 - 2,243
General and administrative 1,265 640 H 1,905
Share-based compensation 1,034 322 G 1,356
Depletion and depreciation 27,711 (7,379) C 20,332
----------------------------------------------------------------------------
44,571 (6,417) 38,154
----------------------------------------------------------------------------
Income (loss) from operations (8,779) 6,417 (2,362)
Financing (1,188) (479) D (1,667)
Impairment of property, plant
and equipment - (18,736) I (18,736)
----------------------------------------------------------------------------
Net loss before taxes (9,967) (12,798) (22,765)
Deferred tax expense (recovery) (2,580) (2,904) E (5,484)
----------------------------------------------------------------------------
Net loss and comprehensive loss $ (7,387) $ (9,894) $ (17,281)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net loss per share
Basic $ (0.09) $ (0.22)
Diluted $ (0.09) $ (0.22)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of consolidated statement of income (loss) for the nine months
ended September 30, 2010:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Effect of
Previous transition
GAAP to IFRS Note IFRS
----------------------------------------------------------------------------
Revenue
Gross petroleum and natural gas
sales $ 149,723 $ - $ 149,723
Royalties (30,488) - (30,488)
Realized gain on financial
instruments 9,798 - 9,798
Unrealized gain on financial
instruments 5,206 - 5,206
----------------------------------------------------------------------------
134,239 - 134,239
Expenses
Operating 39,967 - 39,967
Transportation 6,763 - 6,763
General and administrative 4,575 2,257 H 6,832
Share-based compensation 3,424 519 G 3,943
Depletion and depreciation 85,478 (27,559) C 57,919
----------------------------------------------------------------------------
140,207 (24,783) 115,424
----------------------------------------------------------------------------
Income (loss) from operations (5,968) 24,783 18,815
Financing (4,370) (1,488) D (5,858)
Gain on divestitures - 48,242 F 48,242
Impairment of plant, property
and equipment - (18,736) I (18,736)
----------------------------------------------------------------------------
Net income (loss) before taxes (10,338) 52,801 42,463
Deferred tax expense (recovery) (2,702) 13,132 E 10,430
----------------------------------------------------------------------------
Net income (loss) and
comprehensive income (loss) $ (7,636) $ 39,669 $ 32,033
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per share
Basic $ (0.10) $ 0.40
Diluted $ (0.10) $ 0.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Impact of Transition to IFRS on 2010 Results:
A. Under IFRS, all deferred tax assets and liabilities are classified as
long-term. Under previous GAAP, deferred tax assets and liabilities were
presented according to the classification of the underlying asset or
liability that created the difference in the deferred tax amount.
B. Exploration and Evaluation assets - As required under IFRS 6, the
Company reclassified $72.6 million at September 30, 2010.
C. Depletion and depreciation expense - Under IFRS, Crew has chosen to
calculate depletion expense based on proved plus probable reserves as
opposed to proved reserves under previous GAAP. This has resulted in a
reduction of depletion and depreciation expense of approximately $7.4
million for the three months ended September 30, 2010 and $27.6 million
for the nine months ended September 30, 2010.
D. Decommissioning obligations - Under previous GAAP, Crew's
decommissioning obligations were discounted based on a credit adjusted
risk-free rate which was 8-10% at December 31, 2009. Under IFRS, the
Company is required to revalue its obligation at each balance sheet date
using a current liability-specific discount rate. At transition, Crew
revalued the obligation based on a risk-free rate of 4%, resulting in a
$17.7 million increase (net of tax) to the liability, with the offset
charged to retained earnings.
As a result of the change in the discount rate applied, accretion of
decommissioning obligation expense decreased by $161,000 for the three
months ended September 30, 2010 and $513,000 for the nine months ended
September 30, 2010.
E. Under previous GAAP, the deferred tax liability associated with the
renouncement of tax deductions from the issuance of flow through shares
was recorded as a reduction in share capital at the time of
renouncement. Under IFRS, the difference between the deferred tax
liability associated with the renouncement of the tax deductions and the
premium price received on the issuance of flow through shares over the
market value of the Company's common shares at the time of issue is
recorded as a deferred tax expense as the expenditures are incurred.
This deferred tax expense effectively represents the net loss on the
distribution of the tax deductions to investors. This resulted in an
increase of $3.4 million to share capital with a resulting offset being
charged to retained earnings.
An additional deferred tax expense of $2.9 million for the three months
and $13.1 million for the nine months ended September 30, 2010 was
recognized as a result of changes in the temporary difference between
the net book value and the tax basis of the assets and liabilities due
to other adjustments discussed.
F. Divestitures - Under previous GAAP, proceeds from divestitures were
deducted from the full cost pool without recognition of a gain or loss
unless the divestiture resulted in a change in the depletion rate of 20%
or greater in which case, a gain or loss was recorded. Under IFRS, gains
and losses are recorded on divestitures and are calculated as the
difference between the proceeds and the net book value of the asset
disposed of. A gain on disposition of oil and gas properties of $48.2
million for the nine months ended September 30, 2010 was recorded under
IFRS compared to nil under previous GAAP.
G. Under previous GAAP, Crew expensed stock-based compensation on a
straight-line basis. Under IFRS, share-based payments are expensed based
on a graded vesting schedule. Crew also incorporated a forfeiture
multiplier rather than accounting for forfeitures as they occur as
practiced under previous GAAP. At December 31, 2010, the adjustment to
contributed surplus to account for the graded vesting and forfeitures
was an increase of $2.7 million with the offset being charged to
retained earnings. During the three and nine months ended September 30,
2010 Crew recognized an additional $0.3 million and $0.5 million of
additional stock-based compensation to account for the graded vesting
and forfeitures.
H. Under IFRS, the criteria for which general and administrative expenses
("G&A") can be capitalized is different than previous GAAP and as a
result a greater portion of G&A costs have been expensed. This resulted
in an additional $0.6 million of G&A expenses being recorded for the
three months ended September 30, 2010 and $2.3 million for the nine
months ended September 30, 2010.
I. Under IFRS, impairment tests of property, plant and equipment are
performed at the CGU level, which is the smallest identifiable grouping
of assets that generates largely independent cash inflows. The
impairment assessment is based on the recoverable amount, which is the
greater of value in use or fair value less costs to sell, compared with
the asset's carrying amount. Under previous GAAP, impairment tests of
property, plant and equipment are performed on the entire balance and is
assessed based on the estimated undiscounted future cash flows compared
with carrying amount and if impairment is indicated, discounted cash
flows are used to quantify the amount of the impairment. Crew
determined the recoverable amount using value in use based on discounted
future cash flows of proved plus probable reserves using forecast prices
and costs. In the periods ending September 30, 2010, an impairment
charge of $18.8 million was recognized as a result of low forecast
natural gas pricing. Under IFRS, property, plant and equipment
impairments can be reversed in the future if the recoverable amount
increases.
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