Crew Energy Inc. (TSX:CR) of Calgary, Alberta is pleased to present its
operating and financial results for the three and six month periods ended June
30, 2009.
Highlights
- Increased production by 43% over the second quarter of 2008 to average 13,466
boe per day;
- Production per share increased by 13% over the second quarter of 2008;
- Funds from operations improved by 21% over the first quarter of 2009 to $20.0
million;
- Closed a $43.4 million equity financing and non-core property dispositions for
net proceeds of $23.7 million;
- Net debt decreased by $73.1 million to $182.4 million from $255.4 million at
the end of 2008;
- Subsequent to quarter end, Crew has added six additional 100% owned sections,
to control a total of 190 net sections, on the Company's Montney play in
northeastern British Columbia;
- Crew has signed an agreement creating a strategic alliance with Aux Sable
Canada regarding the construction and operation of the Septimus gas plant.
Following completion of the plant in the fourth quarter of 2009, Crew will
recoup its estimated $22.5 million capital cost and significantly reduce
operating costs in the area from current levels.
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Three Three Six Six
months months months months
Financial ended ended ended ended
($ thousands, except per share June 30, June 30, June 30, June 30,
amounts) 2009 2008 2009 2008
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Petroleum and natural gas sales 39,331 60,316 85,673 111,705
Funds from operations (note 1) 20,036 34,102 36,557 63,140
Per share - basic 0.27 0.60 0.51 1.14
- diluted 0.27 0.58 0.51 1.12
Net income (loss) (12,267) 5,415 (21,285) 6,356
Per share - basic (0.17) 0.09 (0.29) 0.11
- diluted (0.17) 0.09 (0.29) 0.11
Exploration and development
investment 14,187 22,564 37,865 71,666
Property acquisitions (net of
dispositions) (23,688) 63,110 (34,378) 71,756
Net capital expenditures (9,501) 85,674 3,487 143,422
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Capital Structure As at As at
($ thousands) June 30, 2009 Dec. 31, 2008
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Working capital deficiency (note 2) 7,430 31,822
Bank loan 174,928 223,628
Net debt 182,358 255,450
Bank facility 265,000 285,000
Common Shares Outstanding
(thousands) 78,084 71,084
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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, asset
retirement expenditures and the transportation liability charge. Funds
from operations is used to analyze the Company's operating performance
and leverage. Funds from operations does not have a standardized measure
prescribed by Canadian Generally Accepted Accounting Principles and
therefore may not be comparable with the calculations of similar
measures for other companies.
(2) Working capital deficiency includes only accounts receivable less
accounts payable and accrued liabilities.
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
Operations 2009 2008 2009 2008
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Daily production
Natural gas (mcf/d) 54,036 45,599 56,773 48,653
Oil (bbl/d) 3,254 531 3,483 458
Natural gas liquids (bbl/d) 1,206 1,314 1,295 1,463
Oil equivalent (boe/d @ 6:1) 13,466 9,445 14,240 10,030
Per million diluted shares 183 162 197 178
Average prices (note 1)
Natural gas ($/mcf) 3.66 10.60 4.41 9.32
Oil ($/bbl) 60.75 120.17 51.52 110.19
Natural gas liquids ($/bbl) 30.46 77.83 33.42 70.53
Oil equivalent ($/boe) 32.10 70.18 33.24 61.19
Operating expenses
Natural gas ($/mcf) 1.91 1.27 1.81 1.22
Oil ($/bbl) 13.44 9.07 9.17 8.91
Natural gas liquids ($/bbl) 9.81 7.00 11.98 6.27
Oil equivalent ($/boe @ 6:1) 11.79 7.60 10.96 7.23
Netback
Operating netback ($/boe) (note 2) 17.89 42.44 16.16 37.47
Realized gain on financial
instruments (note 3) (0.56) - (0.20) -
G&A ($/boe) 1.15 1.14 1.14 1.11
Interest and other ($/boe) 0.95 1.61 1.03 1.78
Funds from operations ($/boe) 16.35 39.69 14.19 34.58
Drilling Activity
Gross wells 1 7 8 19
Working interest wells 1.0 7.0 2.8 16.8
Success rate, net wells 100% 86% 94% 94%
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Notes:
(1) Average prices are before deduction of transportation costs and do not
include realized gains and losses on financial instruments.
(2) Operating netback equals petroleum and natural gas sales including
realized hedging gains and losses on commodity contracts less royalties,
operating costs and transportation costs calculated on a boe basis.
Operating netback and funds from operations netback do not have a
standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
(3) Amount includes realized gains and losses on non-commodity financial
instruments.
OVERVIEW
Operations during the second quarter of 2009 were highlighted by the
commencement of construction of the Company's 25 mmcf per day Septimus, British
Columbia gas plant and associated infrastructure. This accounted for $5.4
million or 38% of the quarter's capital program. Crew was active completing and
working over existing wells during the second quarter, spending $1.5 million. A
recompletion and workover program at Princess, Alberta was very successful
adding oil production at under $5,000 per producing barrel.
Second quarter production of 13,466 boe per day was up 42% compared to the same
period in 2008 and was down compared to the first quarter 2009 production as a
result of asset sales of 670 boe per day, production declines, production
curtailments and third party facility turnarounds. Second quarter commodity
prices were substantially lower than the same period of 2008. Crew's wellhead
natural gas price averaged $3.66 per mcf which was 65% lower than the second
quarter of 2008 price of $10.60 per mcf. The Company's realized oil price was
down 49% from $120.17 per barrel in the second quarter of 2008 to $60.75 per
barrel in the same period in 2009. Crew's natural gas liquids price was $77.83
per barrel in the second quarter of 2008 and fell 61% to $30.46 per barrel in
the second quarter of 2009. As outlined below, Crew has entered into a number of
commodity and foreign exchange transactions in an effort to reduce the potential
impact of continued weak commodity pricing in 2009 and 2010.
The Company was able to significantly strengthen its balance sheet over the
quarter. On May 28, 2009, Crew closed a $43.4 million bought deal financing
issuing seven million shares at $6.20 per share and on May 31, 2009, Crew closed
the disposition of 540 boe per day of production for proceeds of $22.5 million.
Funds from operations exceeded capital expenditures by approximately $6 million
which further reduced the Company's net debt.
RISK MANAGEMENT ACTIVITY
During the second quarter Crew entered into additional commodity price hedging
contracts in order to protect corporate funds flow from operations in 2009 and
2010. Crew now has an average of 22,500 gigajoules ("gj") per day of natural gas
hedged at an average floor price of $5.78 per gj for the second half of 2009.
The Company has also hedged 1,250 boe per day of oil at an average West Texas
Intermediate ("WTI") price of CDN $77.58.
Looking forward to 2010, Crew has entered into fixed price gas contracts for an
average of 14,200 gj per day at an average $6.02 per gj for calendar 2010. The
Company has hedged oil production for 2010 with fixed price contracts for 500
bbl per day at an average of CDN $80.50 WTI per bbl and a collar on 500 bbl per
day with a floor of CDN $72 WTI per bbl and a ceiling of CDN $88 WTI per bbl.
Crew plans to continue to engage in a base level of hedging activity to protect
future capital programs and maintain financial flexibility.
Currently all of Crew's production is sold in Canadian markets and denominated
in Canadian dollars. Canadian commodities trade independently of US commodities;
however, prices in Canada are closely correlated with prices in the US and are
impacted by fluctuations in the exchange rate between the Canadian and US
dollar. When the Canadian dollar strengthens in relation to the US dollar we
generally experience a decrease in Canadian commodity prices in comparison to US
commodity prices. As a result, Crew has fixed the exchange rate on US $4 million
per month at 1.2400 for the remainder of 2009. For 2010 the Company has fixed
the exchange rate on US $2 million per month at 1.094.
As a result of the current economic downturn and the decrease in central banks'
prime lending rates, the interest rates charged on banker's acceptances are at
levels not seen in decades. In order to reduce the risk of a future increase in
the interest rate charged on banker's acceptances, the Company has entered into
contracts fixing the rate on $150 million of banker's acceptances for two year
periods ending in 2011 at an average rate of 1.106% plus the applicable stamping
fee charged by the Company's banking syndicate.
OPERATIONS UPDATE
During the quarter, the Company drilled one (1.0 net) water disposal well and
completed one (1.0 net) well. The Company also recompleted and performed
workovers on a number of wells targeting oil projects at Princess, Alberta.
Capital spending was focused at Septimus, British Columbia with the construction
of the Septimus gas plant and pipeline infrastructure. With oil prices
recovering and gas prices still depressed, Crew plans to pursue oil development
at Princess and Killam, Alberta with six wells targeting oil in the second half
of 2009. The Company will focus on operating cost control and reduction
initiatives in all areas of operations, production optimization, the drilling of
oil wells at Princess, Alberta and liquids rich natural gas wells at Septimus,
British Columbia.
Montney Play, Northeast British Columbia
Crew controls 190 net sections on the Montney play in northeast British
Columbia. Subsequent to quarter end, the Company completed a property swap
acquiring four additional sections at Septimus and purchased two sections at a
British Columbia Crown land sale. Crew has an estimated productive capacity of
over 14 mmcf per day from six wells at Septimus and is currently producing
approximately four mmcf per day on a restricted basis until the Septimus gas
plant is operational in the fall of 2009.
Crew has commenced drilling operations at Septimus, and is currently drilling
the A9-3 well. During the remainder of 2009, plans are to drill three and
complete five liquids rich natural gas horizontal wells at Septimus and one
vertical exploration well on the Company's Portage exploration block. The
Company plans to continue to develop the net 2.4 TCF of Discovered Petroleum in
Place ("DPIP") that has been assigned by an independent evaluation to the 50
section Septimus block and drill additional step out wells to add reserves and
production. The details of Crew's DPIP evaluation were set forth in its March 9,
2009 press release.
Crew is very pleased to announce an agreement has been reached with Aux Sable
Canada to form a strategic alliance at Septimus, British Columbia. Aux Sable
Canada ("ASC") is a limited partnership controlled equally by Enbridge Corp. and
Fort Chicago Energy Partners. ASC's affiliate, Aux Sable Liquids Products, owns
and operates a world-scale natural gas liquids extraction and fractionation
facility near Chicago at the terminus of the Alliance pipeline. The agreement
calls for Crew to sell the Septimus gas plant to ASC when the plant becomes
operational in the fall of 2009 at the cost of construction which is expected to
be approximately $22.5 million. Crew will continue to operate the facility and
will pay ASC capital throughput fees.
The following are transaction rationale and benefits of the strategic alliance:
- Crew is able to recoup its gas plant construction costs estimated to be $22.5
million in order to redeploy this capital into production additions through
acquisitions or an expanded drilling program.
- Crew has the option to either:
-- Re-purchase a 50% interest in the facility prior to any expansion based on
the original construction cost incorporating a recapture of a portion of the
tolls paid; or,
-- Prior to January 1, 2013, double the capacity of the facility at Crew's
expense to acquire a 50% interest in the expanded facility.
- Significantly reduce operating costs from the current $12 per boe. Costs will
be further reduced should Crew exercise its option to acquire an equity
ownership position.
- Maintain operatorship of the facility throughout the term of the agreement
with priority access to processing capacity.
- ASC will construct and operate a 12 mile, rich gas pipeline from the Septimus
plant to the Alliance pipeline. Crew has an option to participate as to a 50%
working interest with ASC in the pipeline. The ability to deliver gas and
liquids to Chicago provides increased access to export markets as well as
processing and transportation alternatives for British Columbia natural gas and
liquids.
- Initial plans for the next two years are to tie-in to the Alliance pipeline
and expand throughput of the facility to 50 mmcf per day allowing Crew and ASC
to continue growth objectives in the greater Septimus area.
On August 6, 2009, the British Columbia Ministry of Energy, Mines and Petroleum
Resources announced an energy investment stimulus package. Details of the
stimulus package are forthcoming; however the royalty incentives included in the
package are:
- A one-year, two percent royalty rate for all wells drilled in a ten month
window from September 2009 to June 2010;
- An increase of 15 percent in the existing royalty deductions for natural gas
deep drilling;
- Qualification of horizontal wells drilled between 1,900 and 2,300 meters into
the Deep Royalty Credit Program;
- An additional $50 million allocation for the Infrastructure Royalty Credit
Program to be offered this fall to stimulate investment in oil and gas roads and
pipelines.
Crew's Montney drilling program over the ten month window will benefit from all
of the proposed changes enhancing the economics of the Company's drilling
program in British Columbia.
Pekisko Play, Princess Alberta
During the second quarter, Crew was very active recompleting and performing
workovers on oil wells at Princess, Alberta. Production additions as a result of
the workover program were accomplished at a very attractive $5,000 per producing
barrel. Most importantly, the Company's 8-8 horizontal test well has now
produced over 80,000 barrels of oil and is currently producing 254 barrels of
oil per day helping to validate the Company's development scheme for this large
resource project. Current production at Princess is 3,200 boe per day, a 45%
increase since the property was acquired in August 2008. This is down from a
peak of over 3,500 boe per day as a result of natural declines and a number of
wells now being on maximum rate limitations ("MRL") as they await approval of
Good Production Practice ("GPP") applications.
The Company's fourth quarter 2008 water disposal well received approval and
became operational on June 17, 2009 and is now disposing of 2,000 barrels of
produced water per day saving the Company approximately $150,000 per month in
trucking and disposal costs. The Company has drilled a second disposal well that
has recently been tested at a rate of 9,000 barrels per day. An application for
disposal well status has been submitted to the ERCB with approvals and
activation of the well expected by year end. Crew has plans to drill two
additional disposal wells in the third quarter of 2009. These initiatives are
expected to further improve the Company's operations and cost structure in this
area.
Crew plans an active second half of the year at Princess as the Company
concentrates on the attractive economics associated with its oil plays. The
Company is currently drilling its second horizontal well and plans to drill a
minimum of three horizontal oil wells in the second half of 2009 and continue
its workover and recompletion program in the area.
OUTLOOK
Business Environment
North American natural gas prices continue to be weak as supply continues to
outweigh demand. The response by industry has been to significantly reduce
activity levels and defer production. This has not prevented a steady build in
gas storage levels in an environment of reduced gas demand. We believe gas
prices will recover in 2010 and remain committed to our long-term strategy of
finding and developing large resources at low costs.
The current gas price environment has rendered some of Crew's properties
marginally cash flow positive to slightly cash flow negative. As a result we
have elected to defer production from these properties until the economics of
producing them improve. As such, the Company has shut-in as much as 950 boe per
day of production during July and currently has production of 400 boe per day of
production shut-in. We will continue to monitor economics on all properties and
may shut-in additional production volumes should natural gas prices decline from
current levels. In addition, Crew has elected to defer tie-in or production of
approximately 1,900 boe per day, most of which is located at Septimus, British
Columbia awaiting better economic returns and the start up of the Septimus gas
plant. As a result of these production curtailments forecasted average 2009
production has been revised to 13,500 to 13,800 boe per day. Once oil wells at
Princess and Killam are drilled and placed on production and the Septimus gas
plant becomes operational, production is expected to ramp up resulting in an
exit production rate of 14,500 to 15,000 boe per day.
Balance Sheet Significantly Strengthened
Crew was able to significantly strengthen the Company's balance sheet during the
quarter. The Company exceeded its debt reduction target by $10 million reducing
corporate debt by $73 million over year-end 2008 levels to $182.3 million or 2.3
times second quarter annualized funds from operations. This debt level positions
the Company with over $82 million of borrowing capacity on its credit facility.
The Company plans to maintain this strong financial position through the
combination of additional commodity hedging and a disciplined capital
expenditure program.
Resource Development Continues
Crew has only drilled 2.8 net wells in the first six months of 2009. In the
second half of 2009, the Company expects to drill the following:
- Three (2.7 net) horizontal wells at Septimus, British Columbia and one
vertical exploration (1.0 net) well at Portage, British Columbia targeting
liquids rich gas;
- One well at Wapiti, Alberta targeting liquids rich gas;
- Three horizontal wells at Killam, Alberta targeting oil;
- Three horizontal wells targeting oil at Princess, Alberta; and
- Two water disposal wells at Princess, Alberta.
Crew is well positioned to ramp up gas production when natural gas prices
improve. The Company is fortunate to have the flexibility to pursue oil or
natural gas with oil providing attractive returns in the current environment.
Out of the 13 wells planned in the second half of 2009, eight are focused on oil
development and five will target natural gas and condensate exploration and
development.
With the expected sale of the Septimus gas plant for an estimated $22.5 million,
exploration and development capital expenditures for 2009 are currently expected
to be approximately $80 million. Crew will continue to monitor commodity prices,
foreign exchange rates and interest rates and continue its risk management
program in an effort to ensure funds from operations are sufficient to fund
future capital programs. The Company has been disciplined in following its
business plan in the current environment. Crew will continue to do the
following:
- High grade its asset base through non-core property dispositions redirecting
funds to debt reduction and growth initiatives on its resource based assets;
- Improve operating efficiencies to improve operating netbacks;
- Pursue risk management initiatives to protect future capital programs and
Crew's balance sheet;
- Achieve long-term reserve and production growth and continue to capture
additional resource opportunities; and,
- Preserve the balance sheet strength to position the Company to realize the
value in its diverse portfolio of resource based growth prospects.
We thank our shareholders for their patience and continued support in this low
gas price environment. With North American natural gas decline rates of
approximately 30% and significantly less gas directed drilling, we strongly
believe it is a question of "when" not "if" gas prices recover. Crew is uniquely
positioned to take full advantage of this recovery with an active second half
drilling program, strong balance sheet and large scale repeatable resource
focused drilling opportunities. We look forward to reporting our progress in the
2009 business plan in the third quarter report.
Management's Discussion and Analysis
ADVISORIES
Management's discussion and analysis ("MD&A") is the Company's explanation of
its financial performance for the period covered by the financial statements
along with an analysis of the Company's financial position. Comments relate to
and should be read in conjunction with the unaudited consolidated financial
statements of the Company for the three and six month periods ended June 30,
2009 and 2008 and the audited consolidated financial statements and Management
Discussion and Analysis for the year ended December 31, 2008. The consolidated
financial statements have been prepared in accordance with generally accepted
accounting principles ("GAAP") in Canada and all figures provided herein and in
the December 31, 2008 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, capital expenditures, methods of financing capital
expenditures and the ability to fund financial liabilities, expected commodity
prices and the impact on Crew, future operating costs, future transportation
costs, expected change in royalty rates, interest rates and the timing of and
impact of adoption of IFRS and other accounting policies may constitute
forward-looking statements under applicable securities laws and necessarily
involve risks including, without limitation, risks associated with oil and gas
exploration, development, exploitation, production, marketing and
transportation, loss of markets, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks, competition
from other producers, inability to retain drilling rigs and other services,
incorrect assessment of the value of acquisitions, failure to realize the
anticipated benefits of acquisitions, the inability to fully realize the
benefits of the acquisitions, delays resulting from or inability to obtain
required regulatory approvals and ability to access sufficient capital from
internal and external sources. As a consequence, the Company's actual results
may differ materially from those expressed in, or implied by, the forward
looking statements. Forward looking statements or information are based on a
number of factors and assumptions which have been used to develop such
statements and information but which may prove to be incorrect. Although Crew
believes that the expectations reflected in such forward-looking statements or
information are reasonable, undue reliance should not be placed on forward
looking statements because the Company can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified in this document and other documents filed
by the Company, assumptions have been made regarding, among other things: the
impact of increasing competition; the general stability of the economic and
political environment in which Crew operates; the ability of the Company to
obtain qualified staff, equipment and services in a timely and cost efficient
manner; drilling results; the ability of the operator of the projects which the
Company has an interest in to operate the field in a safe, efficient and
effective manner; Crew's ability to obtain financing on acceptable terms;
field production rates and decline rates; the ability to reduce operating costs;
the ability to replace and expand oil and natural gas reserves through
acquisition, development or exploration; the timing and costs of pipeline,
storage and facility construction and expansion; the ability of the Company to
secure adequate product transportation; future oil 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 oil 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 plant gate which is where Crew sells its
production volumes and therefore may be a misleading measure if used in
isolation.
Non-GAAP Measures
One of the benchmarks Crew uses to evaluate its performance is funds from
operations. Funds from operations is a measure not defined in GAAP that is
commonly used in the oil and gas industry. It represents cash provided by
operating activities before changes in non-cash working capital, asset
retirement expenditures and the transportation liability charge. The Company
considers it a key measure as it demonstrates the ability of the business to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Funds from operations should not be considered as
an alternative to, or more meaningful than cash flow provided by operating
activities as determined in accordance with GAAP as an indicator of the
Company's performance. Crew's determination of funds from operations may not be
comparable to that reported by other companies. Crew also presents funds from
operations per share whereby per share amounts are calculated using weighted
average shares outstanding consistent with the calculation of income per share.
The following table reconciles Crew's cash provided by operating activity to
funds from operations:
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2009 2008 2009 2008
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Cash provided by operating
activities 21,517 31,908 41,023 61,448
Asset retirement expenditures 181 323 282 631
Transportation liability charge 329 328 657 657
Change in non-cash working
capital (1,991) 1,543 (5,405) 404
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Funds from operations 20,036 34,102 36,557 63,140
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Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore may not be
comparable with the calculation of similar measures for other entities.
Operating netback equals total petroleum and natural gas sales including
realized gains and losses on commodity contracts less royalties, operating costs
and transportation calculated on a boe basis. Management considers operating
netbacks an important measure to evaluate its performance as it demonstrates its
profitability relative to current commodity prices.
RESULTS OF OPERATIONS
Production
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Three months ended Three months ended
June 30, 2009 June 30, 2008
Nat. Nat.
Oil Ngl gas Total Oil Ngl gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Plains
Core 3,042 898 37,065 10,117 359 921 29,965 6,274
North Core 212 308 16,971 3,349 172 393 15,634 3,171
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Total 3,254 1,206 54,036 13,466 531 1,314 45,599 9,445
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Second quarter 2009 production increased over the second quarter of 2008 as a
result of a successful drilling program that added new natural gas production in
the Septimus, British Columbia area and oil production in the Princess, Alberta
area. Production in the second quarter was also impacted by the production
acquired through the August 22, 2008 acquisition of Gentry Resources Inc.
("Gentry") which included 4,100 boe per day comprised of liquids production of
approximately 1,900 bbl per day and natural gas production of approximately 13
mmcf per day at the date of acquisition. The impact of these additions was
partially offset by high declines on new wells in the Pine Creek, Alberta area,
decreased production due to scheduled third party facility downtime in
northeastern British Columbia, unscheduled facility downtime in eight other
facilities in Alberta, and the shut-in of approximately 400 boe per day of
uneconomic natural gas production in non-core properties in Alberta.
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Six months ended Six months ended
June 30, 2009 June 30, 2008
Nat. Nat.
Oil Ngl gas Total Oil Ngl gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Plains Core 3,264 932 38,574 10,625 294 1,068 34,255 7,071
North Core 219 363 18,199 3,615 164 395 14,398 2,959
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Total 3,483 1,295 56,773 14,240 458 1,463 48,653 10,030
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Production for the first six months of 2009 increased due to the previously
mentioned successful drilling program and the acquisition of Gentry in
August 2008.
Revenue
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue ($ thousands)
Natural gas 17,998 43,999 45,268 82,542
Oil 17,988 5,805 32,473 9,177
Natural gas liquids 3,345 9,305 7,834 18,779
Sulphur - 1,207 98 1,207
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Total 39,331 60,316 85,673 111,705
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Crew average prices
Natural gas ($/mcf) 3.66 10.60 4.41 9.32
Oil ($/bbl) 60.75 120.17 51.52 110.19
Natural gas liquids ($/bbl) 30.46 77.83 33.42 70.53
Oil equivalent ($/boe) 32.10 70.18 33.24 61.19
Benchmark pricing
Natural Gas - AECO C daily index (Cdn
$/mcf) 3.43 10.35 4.21 9.22
Oil - Bow River Crude Oil (Cdn $/bbl) 70.73 114.58 62.10 101.26
Oil and ngl - Light Sweet @ Edmonton
(Cdn $/bbl) 65.84 126.12 57.68 111.87
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Crew's second quarter 2009 revenue decreased 35% from the second quarter of 2008
due to the 54% decrease in average commodity prices partially offset by a 43%
increase in the Company's production.
Crew's average natural gas price decreased 65% in the second quarter of 2009
compared to the second quarter of 2008. This compared to a 67% decrease in the
Company's benchmark natural gas price for the same period. This disproportionate
decrease was the result of the addition of higher valued natural gas added by
the Gentry acquisition. In the second quarter of 2009, the Company's oil
production was mainly medium grade oil from the Princess area, acquired as part
of the August 2008 Gentry acquisition. Princess oil production is approximately
26 degree API that is delivered into the Bow River pipeline system. This
compares to the second quarter 2008 oil production which was light oil produced
in northeast British Columbia and central Alberta. The Company's oil price
decreased 49% in the second quarter of 2009 compared with the same period in
2008 as a result of the significant decline in oil prices and to a lesser extent
by the change in quality of Crew's oil production. The Company's ngl price
decreased 61% in the second quarter of 2009 compared to a 48% decrease in the
benchmark light sweet at Edmonton for the same period of 2008. Increased
production of lower valued ethane in the Septimus, BC area accounts for the
disproportionate decrease in ngl prices.
For the six months ended June 30, 2009, Crew's gas price decreased 53% compared
to the first six months of 2008 which was comparable to the benchmark decrease
of 54%. The Company's disproportionate decrease in its oil price compared to the
benchmark for the first six months of 2009 as compared to the same period in
2008 was a result of the change in quality of Crew's oil production as a result
of the Gentry acquisition.
Royalties
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands, except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Royalties 5,512 13,148 16,192 23,769
Per boe 4.50 15.30 6.28 13.02
Percentage of revenue 14.0% 21.8% 18.9% 21.3%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties as a percentage of revenue decreased in the second quarter and first
six months of 2009 compared to the same periods of 2008 due to lower royalty
rates on the Company's natural gas production in Alberta. Under Alberta's new
royalty structure, the Company's crown royalty percentages decrease as natural
gas prices decrease. In addition, the Company recovered additional gas cost
allowance credits through its annual gas cost allowance filings. The impact of
these reduced gas royalties was partially offset by higher royalty rates on the
freehold royalty assets acquired in the Gentry corporate acquisition in August
2008. The Company's royalties as a percentage of revenue was lower than the
forecasted range of 21% to 22% due to lower than forecasted natural gas prices
and the additional gas cost allowance credits. Corporately, Crew has revised its
forecasted annual royalties as a percentage of revenue to average 19% to 20% for
2009 for this reason.
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 downturns in commodity prices
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.
As at June 30, 2009, the Company held derivative commodity contracts as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional
Contract Quantity Term Reference
----------------------------------------------------------------------------
AECO C
2,500 January 1, 2009 - Monthly
Natural Gas gj/day December 31, 2009 Index
AECO C
Monthly
2,500 January 1, 2009 - Index less
Natural Gas gj/day December 31, 2009 $0.09
AECO C
15,000 April 1, 2009 - Monthly
Natural Gas gj/day October 31, 2009 Index
AECO C
2,500 November 1, 2009 - Monthly
Natural Gas gj/day December 31, 2010 Index
AECO C
5,000 January 1, 2010 - Monthly
Natural Gas gj/day December 31, 2010 Index
AECO C
10,000 January 1, 2010 - Monthly
Natural Gas gj/day December 31, 2010 Index
AECO C
2,500 January 1, 2010 - Monthly
Natural Gas gj/day December 31, 2010 Index
AECO C
5,000 January 1, 2010 - Monthly
Natural Gas gj/day December 31, 2010 Index
500 July 1, 2009 -
Oil bbl/day December 31, 2009 CDN$ WTI
500 July 1, 2009 -
Oil bbl/day December 31, 2009 CDN$ WTI
250 July 1, 2009 -
Oil bbl/day December 31, 2009 CDN$ WTI
250 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI
500 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI
250 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI
----------------------------------------------------------------------------
Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized
Gain
Subject of Strike Option (Loss) Fair Value
Contract Price Traded ($000s) ($000s)
----------------------------------------------------------------------------
Natural Gas $6.60 - $8.50 Collar 996 1,265
Natural Gas $6.50 - $8.30 Collar 1,216 995
Natural Gas $6.00 Put 3,459 4,090
Natural Gas $6.00 Swap - 338
Natural Gas $8.00 Call - (408)
Natural Gas $7.75 Call - (1,113)
Natural Gas $6.20 Swap - 363
Natural Gas $6.08 Swap - 511
Oil $81.70 Swap - (181)
Oil $72.00 Swap - (1,066)
Oil $80.50 Swap - (143)
Oil $78.50 Swap - (798)
Oil $72.00 - $88.00 Collar - (1,012)
Oil $82.50 Swap - (445)
----------------------------------------------------------------------------
Total 5,671 2,396
----------------------------------------------------------------------------
Foreign currency
Although all of the Company's petroleum and natural gas sales are conducted in
Canada and are denominated in Canadian dollars, Canadian commodity prices are
influenced by fluctuations in the Canadian to U.S. dollar exchange rate.
At June 30, 2009, the Company held derivative foreign currency contracts as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized
Subject Gain Fair
of Notional Strike Option (Loss) Value
Contract Quantity Term Reference Price Traded ($000s) ($000s)
----------------------------------------------------------------------------
USD /
CAD $ US $2M / February 1, 2009 -
exchange Month December 31, 2009 CAD/USD 1.22 Swap 178 877
USD /
CAD $ US $2M / February 1, 2009 -
exchange Month December 31, 2009 CAD/USD 1.26 Swap 578 1,163
USD /
CAD $ US $2M / January 1, 2010 -
exchange Month December 31, 2010 CAD/USD 1.094 Swap - (1,610)
----------------------------------------------------------------------------
Total 756 430
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest rate
The Company is exposed to interest rate fluctuations on its bank debt which
bears a floating rate of interest. As shown below, at June 30, 2009, Crew had
contracts in place fixing the rate on $150 million of its bank debt borrowed as
banker's acceptances for a period of 24 months at rates of 1.10% to 1.12%. The
Company pays an additional stamping fee and margins on banker's acceptances as
outlined in note 3 of the financial statements.
Realized
Subject Gain Fair
of Notional Strike Option (Loss) Value
Contract Quantity Term Reference Price Traded ($000s)($000s)
----------------------------------------------------------------------------
BA Rate $50M / February 10, 2009 - BA -
year February 10, 2011 CDOR 1.10% Swap (98) (269)
BA Rate $50M / February 12, 2009 - BA -
year February 12, 2011 CDOR 1.10% Swap (101) (201)
BA Rate $50M / May 28, 2009 - BA -
year May 28, 2011 CDOR 1.12% Swap (32) (47)
----------------------------------------------------------------------------
Total (231) (517)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands, except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Operating costs 14,448 6,532 28,258 13,205
Per boe 11.79 7.60 10.96 7.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the second quarter and first six months of 2009, the Company's operating
costs per unit increased over the same periods in 2008 due to the addition of
higher cost production from the Gentry acquisition. Higher than expected prior
period equalizations and adjustments to prior period estimates combined with a
decrease in lower cost production due to facility turnarounds have increased the
Company's per boe costs in the second quarter of 2009 above the Company's
forecasted level. With plans to limit capital expenditures in 2009, the Company
has also deferred some of its cost reducing capital expenditures from its
original forecast thus deferring the reductions. With the increase in first half
costs, the deferral of these capital expenditures and reduced production
forecasts, the Company now expects operating costs to range from $11.00 to
$11.50 per boe for 2009.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands, except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Transportation costs 2,397 1,921 5,265 3,992
Per boe 1.96 2.23 2.04 2.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the second quarter of 2009, the Company's transportation costs per unit have
decreased 12% compared to the same period in 2008. In Princess, Alberta, lower
clean oil trucking costs per unit have decreased the Company's overall
transportation costs per unit. The reduction in clean oil trucking costs per
unit were partially offset by increased gas transportation costs per unit in
northeastern British Columbia where the Company has a fixed transportation
commitment and associated production was curtailed by a facility turnaround
during the second quarter. For the first six months of 2009, the Company's
transportation costs per unit have decreased as compared with the same period in
2008 as a result of lower clean oil trucking costs for oil production from the
Gentry acquisition.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
June 30, 2009 June 30, 2008
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 60.75 30.46 3.66 32.10 120.17 77.83 10.60 70.18
Realized
commodity
hedging
gain
(loss) - - 1.01 4.04 - - (0.54) (2.61)
Royalties (16.45) (9.48) (0.08) (4.50) (17.68) (23.17) (2.24) (15.30)
Operating
costs (13.44) (9.81) (1.91) (11.79) (9.07) (7.00) (1.27) (7.60)
Transportation
costs (1.28) - (0.41) (1.96) (2.71) (0.04) (0.43) (2.23)
----------------------------------------------------------------------------
Operating
netbacks 29.58 11.17 2.27 17.89 90.71 47.62 6.12 42.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended Six months ended
June 30, 2009 June 30, 2008
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 51.52 33.42 4.41 33.24 110.19 70.53 9.32 61.19
Realized
commodity
hedging
gain
(loss) - - 0.55 2.20 - - (0.26) (1.28)
Royalties (13.35) (9.97) (0.50) (6.28) (15.49) (20.22) (1.91) (13.02)
Operating
costs (11.98) (9.17) (1.81) (10.96) (8.91) (6.27) (1.22) (7.23)
Transportation
costs (1.43) - (0.42) (2.04) (2.87) (0.04) (0.42) (2.19)
----------------------------------------------------------------------------
Operating
netbacks 24.76 13.33 2.23 16.16 82.92 44.01 5.51 37.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands, except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Gross costs 3,219 2,454 6,699 5,088
Operator's recoveries (388) (486) (812) (1,034)
Capitalized costs (1,416) (984) (2,944) (2,027)
----------------------------------------------------------------------------
General and administrative expenses 1,415 984 2,943 2,027
Per boe 1.15 1.14 1.14 1.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increased general and administrative costs before recoveries and capitalization
were mainly the result of increased staff levels to accommodate the Company's
larger operations in the second quarter of 2009 compared to 2008. In the second
quarter of 2009, net general and administrative costs per boe have remained
consistent with the same period of 2008. For the first six months of 2009 net
general and administrative costs and costs per unit have increased compared to
the same period in 2008 due to a decrease in capital expenditures and a
subsequent decrease in capital recoveries. The Company expects general and
administrative expenses to average between $1.00 and $1.15 per boe for the year.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands, except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Interest expense 1,166 1,655 2,654 3,510
Average debt level 223,864 113,558 225,754 109,534
Effective interest rate 2.1% 5.1% 2.4% 6.0%
Per boe 0.95 1.93 1.03 1.92
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the second quarter and first half of 2009, despite higher average debt
levels, lower effective interest rates decreased the Company's interest expense
for the period compared with the same periods in 2008. In the latter part of
2009, the Company will have increased margins applied to its bank facility which
will negatively affect Crew's interest expense and effective interest rate;
however, lower prime interest rates and interest rates on banker's acceptances
will partially offset this increase.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Gross costs 1,663 1,864 3,421 3,572
Capitalized costs (832) (932) (1,711) (1,786)
----------------------------------------------------------------------------
Total stock-based compensation 831 932 1,710 1,786
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has decreased in the second
quarter of 2009 and the first half of 2009 as compared with the same periods in
2008 as an increase in stock options outstanding has been more than offset by a
decrease in the fair value of the stock options issued.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands, except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Depletion, depreciation and accretion 32,823 20,650 67,794 43,290
Per boe 26.79 24.03 26.30 23.71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per unit depletion has increased in the second quarter and first half of 2009
due to additional accretion associated with the added Gentry assets in August
2008 and increased depletion associated with the addition of the fair market
value of the Gentry assets at the acquisition date, which was higher than
historic Company carrying values for proved reserves.
Future Income Taxes
The provision for future income taxes was a recovery of $5.2 million in the
second quarter of 2009 compared to an expense of $1.8 million in the same period
of 2008. The decrease in future taxes was a result of a pre-tax loss in 2009.
For the first six months of 2009, the Company had a future tax recovery of $10.6
million as compared with a future tax expense of $1.3 million for the same
period of 2008. The recovery was a result of a pre-tax loss in 2009 and a
corporate rate reduction in British Columbia from 11 percent to 10 percent in
2010 and a further reduction to 10 percent in 2011.
Cash and Funds from Operations and Net Income (Loss)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
($ thousands, except per share June 30, June 30, June 30, June 30,
amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by operating activities 21,517 31,908 41,023 61,448
Funds from operations 20,036 34,102 36,557 63,140
Per share - basic 0.27 0.60 0.51 1.14
- diluted 0.27 0.58 0.51 1.12
Net income (loss) (12,267) 5,415 (21,285) 6,356
Per share - basic (0.17) 0.09 (0.29) 0.11
- diluted (0.17) 0.09 (0.29) 0.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The second quarter and first half of 2009 decrease in cash provided by
operations and funds from operations was the result of decreased commodity
pricing and higher operating costs for the periods partially offset by realized
gains on financial instruments. The second quarter and first half 2009 net loss
resulted from the decreased commodity prices and higher operating and depletion
costs partially offset by a $1.8 million net gain on financial instruments.
Capital Expenditures, Acquisitions and Dispositions
During the second quarter of 2009, the Company drilled one (1.0 net) water
disposal well. In addition, the Company also recompleted 13 (13.0 net) wells in
the Princess, Alberta area. Crew continued to add to its infrastructure,
beginning construction and procuring equipment for its Septimus facility and
pipeline in northeastern British Columbia. In the second quarter of 2009, the
Company closed three dispositions of non-core properties with approximately 540
boe per day in central Alberta and British Columbia for net proceeds of $23.7
million.
Total exploration and development capital expenditures for the second quarter
and first half of 2009 were $14.2 and $37.9 million, respectively compared to
$22.6 and $71.7 million for the same periods in 2008. The expenditures are
detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Land 716 2,201 3,868 20,065
Seismic 322 355 2,095 1,477
Drilling and completions 4,745 13,501 10,400 36,157
Facilities, equipment and pipelines 6,889 5,048 18,345 11,395
Other 1,515 1,459 3,157 2,572
----------------------------------------------------------------------------
Total exploration and development 14,187 22,564 37,865 71,666
Property acquisitions (dispositions) (23,688) 63,110 (34,378) 71,756
----------------------------------------------------------------------------
Total (9,501) 85,674 3,487 143,422
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2009, budgeted exploration and development expenditures for 2009
are estimated at $80 million. This amount does not include the impact of any
property dispositions other than the Company's negotiated sale of the Septimus
natural gas facility to Aux Sable Canada for estimated proceeds of $22.5 million
which is scheduled to close in the fourth quarter of 2009.
Liquidity and Capital Resources
Capital Funding
On May 11, 2009, the Company completed the extension of its credit facility with
a syndicate of banks (the "Syndicate"). The credit facility was amended to a
revolving line of credit of $250 million and an operating line of credit of $15
million (the "Facility"). The Facility revolves for a 364 day period and will be
subject to its next 364 day extension by June 14, 2010. If not extended, the
Facility will cease to revolve, the margins there under 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 review on
or before October 31, 2009. At June 30, 2009, the Company had committed drawings
of $174.9 million on the Facility and had issued letters of credit totaling $5.4
million of which $5.0 million expires by September 30, 2009.
On May 28, 2009, the Company closed a bought deal sale of 7,000,000 Common
Shares of the Company at a price of $6.20 per share for aggregate gross proceeds
of $43.4 million. Proceeds of the offering were initially used to pay down
drawings on the Company's Facility, which can be redrawn and applied as needed
to fund a portion of the Company's future capital program.
The Company will continue to fund its on-going operations from a combination of
cash flow, debt, asset dispositions and equity financings as needed. As the
majority of our on-going capital expenditure program is directed to the further
growth of reserves and production volumes, Crew is readily able to adjust its
budgeted capital expenditures should the need arise.
Working Capital
The capital intensive nature of Crew's activities generally results in the
Company carrying a working capital deficit. However, the Company maintains
sufficient unused bank credit lines to satisfy such working capital
deficiencies. At June 30, 2009, the Company's working capital deficiency
(including accounts receivable, accounts payable and accrued liabilities)
totaled $7.4 million which, when combined with the drawings on its bank line,
represented 69% of its current bank facility.
Share Capital
As at August 10, 2009, Crew had 78,083,668 Common Shares and 5,779,500 options
to acquire Common Shares of the Company issued and outstanding.
Capital Structure
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes adjustments
on an on-going basis in order to maintain the flexibility needed to achieve the
Company's long-term objectives. To manage the capital structure the Company may
adjust capital spending, hedge future revenue and costs, issue new equity, issue
new debt or repay existing debt through asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1. This ratio may increase at certain times as a result of acquisitions or low
commodity prices. As shown below, as at June 30, 2009, the Company's ratio of
net debt to annualized funds from operations was 2.28 to 1 (December 31, 2008 -
2.15 to 1). This amount has risen above the preferred range of the Company as a
result of the decrease in commodity prices experienced over the past year.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except ratio) June 30, 2009
----------------------------------------------------------------------------
Net debt 182,358
Funds from operations 20,036
Annualized 80,144
Net debt to annualized funds from operations ratio 2.28
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In order to restore the Company's financial flexibility, Crew will execute a
conservative capital spending program in 2009, currently estimated at $80
million. The Company has added commodity, interest rate and foreign exchange
hedging for 2009 and 2010 to provide support for its funds from operations and
assist in funding its capital expenditure program. On May 28, 2009, the Company
closed a bought deal equity financing for aggregate gross proceeds of $43.4
million. In addition, in 2009 the Company has disposed of non-core properties
for net proceeds of $34.4 million. The Company may also consider the sale of
additional non-core assets and will consider other forms of financing to improve
the Company's financial position if cash flow does not adequately fund the
programs planned to achieve the Company's long term objectives.
Contractual Obligations
Throughout the course of its ongoing business, the Company enters into various
contractual obligations such as credit agreements, purchase of services, royalty
agreements, operating agreements, processing agreements, right of way agreements
and lease obligations for office space and automotive equipment. All such
contractual obligations reflect market conditions prevailing at the time of
contract and none are with related parties. The Company believes it has adequate
sources of capital to fund all contractual obligations as they come due. The
following table lists the Company's obligations with a fixed term.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Total 2009 2010 2011
----------------------------------------------------------------------------
Bank Loan (note 1) 174,928 - - 174,928
Operating Leases 2,227 495 990 742
Capital commitments 10,955 4,455 6,500 -
Firm transportation agreements
(note 2) 17,289 3,499 7,152 6,638
----------------------------------------------------------------------------
Total 205,399 8,449 14,642 182,308
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2011. However, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.
Note 2 - The firm transportation commitments were acquired as part of the
Company's May, 2007 private company acquisition and represent firm
service commitments for transportation and processing of natural
gas in British Columbia.
Guidance
North American natural gas prices continue to be weak as supply continues to
outweigh demand. The response by industry has been to significantly reduce
activity levels and defer production. This has not prevented a steady build in
gas storage levels in an environment of reduced gas demand. We believe gas
prices will recover in 2010 and remain committed to our long-term strategy of
finding and developing large resources at low costs.
The current gas price environment has rendered some of Crew's properties
marginally cash flow positive to slightly cash flow negative. As a result we
have elected to defer production from these properties until the economics of
producing them improve. As such, the Company has shut-in as much as 950 boe per
day of production during July and currently has 400 boe per day of production
shut-in. We will continue to monitor economics on all properties and may shut-in
additional production volumes should natural gas prices decline from current
levels. In addition, Crew has elected to defer tie-in or production of
approximately 1,900 boe per day, most of which is located at Septimus, British
Columbia awaiting better economic returns and the start up of the Septimus gas
plant. As a result of these production curtailments forecasted average 2009
production has been revised to 13,500 to 13,800 boe per day. Once oil wells at
Princess and Killam are drilled and placed on production and the Septimus gas
plant becomes operational, production is expected to ramp up resulting in an
exit production rate of 14,500 to 15,000 boe per day.
Additional Disclosures
Quarterly Analysis
The following table summarizes Crew's key quarterly financial results for the
past eight financial quarters:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per June 30 Mar. 31 Dec. 31 Sept. 30
share amounts) 2009 2009 2008 2008
----------------------------------------------------------------------------
Total daily production (boe/d) 13,466 15,022 14,869 11,505
Average wellhead price ($/boe) 32.10 34.28 42.99 61.74
Petroleum and natural gas sales 39,331 46,342 58,806 65,345
Cash provided by operations 21,517 19,506 25,700 36,208
Funds from operations 20,036 16,521 29,646 35,004
Per share - basic 0.27 0.23 0.42 0.54
- diluted 0.27 0.23 0.42 0.54
Net income (loss) (12,267) (9,018) (74,853) 15,178
Per share - basic (0.17) (0.13) (1.05) 0.24
- diluted (0.17) (0.13) (1.05) 0.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per June 30 Mar. 31 Dec. 31 Sept. 30
share amounts) 2008 2008 2007 2007
----------------------------------------------------------------------------
Total daily production (boe/d) 9,445 10,614 9,641 9,268
Average wellhead price ($/boe) 70.18 53.20 43.90 39.16
Petroleum and natural gas sales 60,316 51,389 38,942 33,390
Cash provided by operations 31,908 29,540 11,882 23,035
Funds from operations 34,102 29,038 22,390 21,171
Per share - basic 0.60 0.54 0.43 0.45
- diluted 0.58 0.54 0.43 0.44
Net income (loss) 5,415 941 6,889 (449)
Per share - basic 0.09 0.02 0.13 (0.01)
- diluted 0.09 0.02 0.13 (0.01)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's petroleum and natural gas sales, cash and funds from operations and net
income are all impacted by production levels and volatile commodity pricing.
From 2007 to 2009, despite increasing production, these performance measures
have fluctuated as a result of volatile oil and natural gas prices combined with
the escalating cost of operations.
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.
- Revenue and royalties are significantly impacted by underlying commodity
prices. The Company utilizes a limited amount of derivative contracts and
forward sales contracts to reduce the exposure to commodity price fluctuations.
- From the third quarter of 2008 to the second quarter of 2009, revenue has been
negatively impacted by a decrease in oil and natural gas prices.
- Production in the second quarter of 2008 and 2009 was impacted by a scheduled
and unscheduled third party facility shutdowns.
- In August, 2008, the Company acquired Gentry Resources Ltd. with approximately
4,100 boe per day of production at closing. The increased revenue received from
this added production was partially offset by the higher cost structure of these
assets compared to Crew's costs on other assets.
- Production in the third and fourth quarter of 2007 was reduced by significant
facility outages at Sierra in northeastern British Columbia and Edson and
Ferrier, Alberta.
- Throughout 2007 and 2008, the Company's operating costs, general and
administrative costs and capital expenditures were subject to inflationary
pressures brought on by increased demand for services and supplies within the
Canadian oil and gas industry.
- During the quarter ended September 30, 2007 the Company's funds from
operations and net income were positively impacted by the one time receipt of
Alberta deep well royalty holiday credits and 2006 Alberta gas cost allowance
adjustments totalling $4.0 million.
- In the fourth quarter of 2008, Crew performed an impairment test on its
goodwill and determined that its carrying value exceeded its fair value and
therefore an impairment charge of $69.1 million was required.
- During 2008 and the first six months of 2009, the Company experienced
volatility in its net income as a result of realized and unrealized gains and
losses on commodity derivative contracts held for risk management purposes.
- In the fourth quarter of 2007, the first quarter of 2008 and the first quarter
of 2009, Crew had a future income tax recovery which positively affected income
due to Canadian provincial and federal government tax rate reductions.
New Accounting Pronouncements
International Financial Reporting Standards ("IFRS")
In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the
changeover to IFRS from Canadian GAAP will be required for publicly accountable
enterprises for interim and annual financial statements effective for fiscal
years beginning on or after January 1, 2011, including comparatives for 2010.
Crew's financial statements up to and including the December 31, 2010 financial
statements will continue to be reported in accordance with Canadian GAAP as it
exists on each reporting date. Financial statements for the quarter ended March
31, 2011, including comparative amounts, will be prepared on an IFRS basis.
In order to transition to IFRS, Management has established a project team and
formed an executive steering committee. A transition plan has been developed to
convert the financial statements to IFRS. The transition effort is proceeding as
planned. Training has been provided to key employees and the Company continues
to monitor the effect of the transition on information systems, internal
controls over financial reporting and disclosure controls and procedures.
External advisors have been retained and will assist management with the project
on an as needed basis. Staff training programs will continue in 2009 and be
ongoing as the project unfolds. Analysis of differences between IFRS and Crew's
current accounting policies continues, and the impact of various alternatives is
being assessed. Changes in accounting policy are likely and may materially
impact the financial statements. Due to anticipated changes in IFRS prior to the
conversion date, the final impact of the conversion on Crew's financial
statements cannot be measured.
In May 2009, the CICA amended Section 3862, "Financial Instruments -
Disclosures," to include additional disclosure requirements about fair value
measurement for financial instruments and liquidity risk disclosures. These
amendments require a three level hierarchy that reflects the significance of the
inputs used in making the fair value measurements. Fair values of assets and
liabilities included in Level 1 are determined by reference to quoted prices in
active markets for identical assets and liabilities. Assets and liabilities in
Level 2 include valuations using inputs other than quoted prices for which all
significant outputs are observable, either directly or indirectly. Level 3
valuations are based on inputs that are unobservable and significant to the
overall fair value measurement. These amendments are effective for Crew on
December 31, 2009.
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 filings
are being prepared; and (ii) information required to be disclosed by the Company
in its annual filings, interim filings or other reports filed or submitted by it
under securities legislation is recorded, processed, summarized and reported
within the time period specified in securities legislation.
Crew's CEO and CFO have designed, or caused to be designed under their
supervision, internal controls over financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with generally
accepted accounting principles. The Company is required to disclose herein any
change in the design of the Company's internal control over financial reporting
that occurred during the quarter ended on June 30, 2009 that has materially
affected, or is reasonably likely to materially affect, the Company's internal
control over financial reporting. No material changes in the Company's design of
internal control over financial reporting were identified during such period,
that have materially affected, or are reasonably likely to materially affect,
the Company's internal control over financial reporting.
It should be noted that a control system, including the Company's disclosure and
internal controls and procedures, no matter how well conceived, can provide only
reasonable, but not absolute, assurance that the objectives of the control
system will be met and it should not be expected that the disclosure and
internal controls and procedures will prevent all errors or fraud.
Dated as of August 10, 2009
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 forgoing, 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; 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; 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; the number of wells to be drilled and
completed; the amount and timing of capital projects including, without
limitation completion of the Septimus gas plant; operating costs; the total
future capital associated with development of reserves and resources; and
forecast reductions in operating expenses.
Forward-looking statements or information are based on a number of material
factors, expectations or assumptions of Crew which have been used to develop
such statements and information but which may prove to be incorrect. Although
Crew believes that the expectations reflected in such forward-looking statements
or information are reasonable, undue reliance should not be placed on
forward-looking statements because Crew can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified herein, assumptions have been made
regarding, among other things: the impact of increasing competition; the general
stability of the economic and political environment in which Crew operates; the
timely receipt of any required regulatory approvals; the ability of Crew to
obtain qualified staff, equipment and services in a timely and cost efficient
manner; drilling results; the ability of the operator of the projects in which
Crew has an interest in to operate the field in a safe, efficient and effective
manner; the ability of Crew to obtain financing on acceptable terms; field
production rates and decline rates; the ability to replace and expand oil and
natural gas reserves through acquisition, development and exploration; the
timing and cost of pipeline, storage and facility construction and expansion and
the ability of Crew to secure adequate product transportation; future commodity
prices; currency, exchange and interest rates; regulatory framework regarding
royalties, taxes and environmental matters in the jurisdictions in which Crew
operates; and the ability of Crew to successfully market its oil and natural gas
products.
The forward-looking information and statements included in this news release are
not guarantees of future performance and should not be unduly relied upon. Such
information and statements; including the assumptions made in respect thereof,
involve known and unknown risks, uncertainties and other factors that may cause
actual results or events to defer materially from those anticipated in such
forward-looking information or statements including, without limitation: changes
in commodity prices; changes in the demand for or supply of Crew's products;
unanticipated operating results or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters; changes in
development plans of Crew or by third party operators of Crew's properties,
increased debt levels or debt service requirements; inaccurate estimation of
Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack
of access to capital markets; increased costs; a lack of inadequate 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.
Discovered Petroleum Initially in Place
This press release contains references to estimates of gas classified as
Discovered Petroleum initially in Place (DPIP) in the Company's Septimus area in
British Columbia which are not, and should not be confused with oil and gas
reserves. "Discovered Petroleum Initially in Place" is defined in the Canadian
Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of
hydrocarbons that are estimated, as of a given date, to be contained in known
accumulations. DPIP is divided into recoverable and unrecoverable portions, with
the estimated future recoverable portion classified as reserves and contingent
resources. There is no certainty that it will be commercially viable or
technically feasible to produce any portion of this discovered petroleum
initially in place except to the extent identified as proved or probable
reserves. Resources do not constitute, and should not be confused with,
reserves.
There are a number of assumptions associated with the development of the
Company's lands at Septimus relating to performance from new and existing wells,
future drilling programs, the lack of infrastructure, well density per section,
recovery factors and development necessarily involves known and unknown risks
and uncertainties, including those risks identified in this press release.
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
Crew is an oil and gas exploration and production company whose shares are
traded on The Toronto Stock Exchange under the trading symbol "CR".
Financial statements for the three and six month periods ended June 30, 2009 and
2008 are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
2009 2008
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 28,518 $ 42,800
Fair value of financial instruments (note 7) 2,309 1,255
Future income taxes - 15
----------------------------------------------------------------------------
30,827 44,070
Property, plant and equipment (note 2) 940,149 1,001,440
----------------------------------------------------------------------------
$ 970,976 $ 1,045,510
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 35,948 $ 74,622
Future income taxes 251 -
Current portion of other long-term obligations
(note 4) 1,313 1,313
----------------------------------------------------------------------------
37,512 75,935
Bank loan (note 3) 174,928 223,628
Other long-term obligations (note 4) 789 1,446
Asset retirement obligations (note 5) 35,385 34,941
Future income taxes 105,332 116,292
Shareholders' Equity
Share capital (note 6) 616,817 575,191
Contributed surplus (note 6) 19,777 16,356
Retained earnings (deficit) (19,564) 1,721
----------------------------------------------------------------------------
Commitments (note 10) 617,030 593,268
----------------------------------------------------------------------------
$ 970,976 $ 1,045,510
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Operations, Comprehensive Income (Loss) and
Retained Earnings (Deficit)
(unaudited)
(thousands, except per share amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas
sales $ 39,331 $ 60,316 $ 85,673 $ 111,705
Royalties (5,512) (13,148) (16,192) (23,769)
Realized gain (loss) on
financial instruments
(note 7) 5,643 (2,242) 6,196 (2,330)
Unrealized gain (loss) on
financial instruments
(note 7) (3,816) (5,260) 1,054 (10,426)
Other income - 268 - 268
----------------------------------------------------------------------------
35,646 39,934 76,731 75,448
Expenses
Operating 14,448 6,532 28,258 13,205
Transportation 2,397 1,921 5,265 3,992
General and administrative 1,415 984 2,943 2,027
Interest 1,166 1,655 2,654 3,510
Stock-based compensation 831 932 1,710 1,786
Depletion, depreciation and
accretion 32,823 20,650 67,794 43,290
----------------------------------------------------------------------------
53,080 32,674 108,624 67,810
----------------------------------------------------------------------------
Income (loss) before income
taxes (17,434) 7,260 (31,893) 7,638
Future income tax expense
(reduction) (5,167) 1,845 (10,608) 1,282
----------------------------------------------------------------------------
Net income (loss) and
comprehensive income (loss) (12,267) 5,415 (21,285) 6,356
Retained earnings (deficit),
beginning of period (7,297) 55,981 1,721 55,040
----------------------------------------------------------------------------
Retained earnings (deficit),
end of period $ (19,564) $ 61,396 $ (19,564) $ 61,396
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per share
(note 6(e))
Basic $ (0.17) $ 0.09 $ (0.29) $ 0.11
Diluted $ (0.17) $ 0.09 $ (0.29) $ 0.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements
CREW ENERGY INC.
Consolidated Statements of Cash Flows
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Net income (loss) $ (12,267) $ 5,415 $ (21,285) $ 6,356
Items not involving cash:
Depletion, depreciation and
accretion 32,823 20,650 67,794 43,290
Stock-based compensation 831 932 1,710 1,786
Future income tax expense
(reduction) (5,167) 1,845 (10,608) 1,282
Unrealized (gain) loss on
financial instruments 3,816 5,260 (1,054) 10,426
Transportation liability
charge (note 4) (329) (328) (657) (657)
Asset retirement
expenditures (181) (323) (282) (631)
Change in non-cash working
capital (note 9) 1,991 (1,543) 5,405 (404)
----------------------------------------------------------------------------
21,517 31,908 41,023 61,448
Financing activities:
Increase (decrease) in bank
loan (64,762) (4,795) (48,700) 24,320
Issue of common shares 43,400 69,097 43,400 69,762
Share issue costs (2,439) (3,507) (2,439) (3,521)
----------------------------------------------------------------------------
(23,801) 60,795 (7,739) 90,561
Investing activities:
Exploration and development (14,187) (22,564) (37,865) (71,666)
Property acquisitions - (63,110) - (71,756)
Property dispositions 23,688 - 34,378 -
Change in non-cash working
capital (note 9) (7,217) (7,029) (29,797) (8,587)
----------------------------------------------------------------------------
2,284 (92,703) (33,284) (152,009)
----------------------------------------------------------------------------
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 six months ended June 30, 2009 and 2008
(Unaudited)
(Tabular amounts in thousands)
1. Significant accounting policies:
The interim consolidated financial statements of Crew Energy Inc. ("Crew" or the
"Company") have been prepared by management in accordance with accounting
principles generally accepted in Canada. The interim consolidated financial
statements have been prepared following the same accounting policies and methods
of computation as the consolidated financial statements for the year ended
December 31, 2008. The disclosure which follows is incremental to the disclosure
included with the December 31, 2008 consolidated financial statements. These
interim consolidated financial statements should be read in conjunction with the
audited consolidated financial statements and notes thereto for the year ended
December 31, 2008.
In May 2009, the CICA amended Section 3862, "Financial Instruments -
Disclosures," to include additional disclosure requirements about fair value
measurement for financial instruments and liquidity risk disclosures. These
amendments require a three level hierarchy that reflects the significance of the
inputs used in making the fair value measurements. Fair values of assets and
liabilities included in Level 1 are determined by reference to quoted prices in
active markets for identical assets and liabilities. Assets and liabilities in
Level 2 include valuations using inputs other than quoted prices for which all
significant outputs are observable, either directly or indirectly. Level 3
valuations are based on inputs that are unobservable and significant to the
overall fair value measurement. These amendments are effective for Crew on
December 31, 2009.
Certain comparative amounts have been reclassified to conform to current period
presentation.
2. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and Net book
June 30, 2009 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $ 1,254,976 $ 314,827 $ 940,149
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and Net book
December 31, 2008 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $ 1,249,859 $ 248,419 $1,001,440
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The cost of unproved properties at June 30, 2009 of $163,820,000 (2008 -
$118,740,000) was excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $106,968,000 (2008 - $28,594,000) have been included in the
depletion calculation and estimated salvage values of $38,246,000 (2008 -
$25,026,000) have been excluded from the depletion calculation.
The following corporate expenses related to exploration and development
activities were capitalized.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months Year ended
ended December 31,
June 30, 2009 2008
----------------------------------------------------------------------------
General and administrative expense $ 2,943 $ 4,169
Stock-based compensation expense, including
future income taxes 2,290 4,485
----------------------------------------------------------------------------
$ 5,233 $ 8,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. Bank loan:
The Company's bank facility was extended on May 11, 2009 and consists of a
revolving line of credit of $250 million and an operating line of credit of $15
million (the "Facility"). The Facility revolves for a 364 day period and will be
subject to its next 364 day extension by June 14, 2010. If not extended, the
Facility will cease to revolve, the margins there under will increase by 0.50
percent and all outstanding advances there under will become repayable in one
year. The available lending limits of the Facility are reviewed semi-annually
and are based on the bank syndicate's interpretation of the Company's reserves
and future commodity prices. There can be no assurance that the amount of the
available Facility will not be adjusted at the next scheduled review on or
before October 31, 2009. The facility is secured by a first floating charge
debenture over the Company's consolidated assets.
Advances under the Facility are available by way of prime rate loans with
interest rates of between 1.75 percent and 3.5 percent over the bank's prime
lending rate and bankers' acceptances and LIBOR loans which are subject to
stamping fees and margins ranging from 2.75 percent to 4.5 percent depending
upon the debt to EBITDA ratio of the Company calculated at the Company's
previous quarter end. The Company's facility will be subject to an additional
0.50 percent increase in these fees and margins at any time drawings on the
facility exceed $250 million. Standby fees are charged on the undrawn facility
at rates ranging from 0.70 percent to 1.2 percent depending upon the debt to
EBITDA ratio.
As at June 30, 2009, the Company's applicable pricing included a 2.25 percent
margin on prime lending and a 3.25 percent stamping fee and margin on Bankers'
Acceptances and LIBOR loans along with a 0.80 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 June 30,
2009, the Company had issued letters of credit totaling $5.4 million. The
effective interest rate on the Company's borrowings under its bank facility for
the period ended June 30, 2009 was 2.4% (2008 - 5.9%).
4. Other long-term obligations:
As part of a May, 2007 private company acquisition, the Company acquired several
firm transportation agreements. These agreements had a fair value at the time of
the acquisition of a $4.9 million liability. This amount was accounted for as
part of the acquisition cost and will be charged as a reduction to
transportation expenses over the life of the contracts as they are incurred. The
last of these contracts expires in October 2011. The charge for the three and
six months ended June 30, 2009 was $0.3 million and $0.7 million, respectively
(June 30, 2008 - $0.3 million and $0.7 million).
5. Asset retirement obligations:
Total future asset retirement obligations were determined by management and were
based on Crew's net ownership interest, the estimated future costs to reclaim
and abandon the wells and facilities and the estimated timing of when the costs
will be incurred. Crew estimated the net present value of its total asset
retirement obligation as at June 30, 2009 to be $35,385,000 (December 31, 2008 -
$34,941,000) based on a total future liability of $66,242,000 (December 31, 2008
- $67,588,000). These payments are expected to be made over the next 30 years.
An 8% to 10% (2008 - 8% to 10%) credit adjusted risk free discount rate and 2%
(2008 - 2%) inflation rate were used to calculate the present value of the asset
retirement obligation.
The following table reconciles Crew's asset retirement obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended Year ended
June 30, 2009 December 31, 2008
----------------------------------------------------------------------------
Carrying amount, beginning of period $ 34,941 $ 18,668
Liabilities incurred 42 1,228
Liabilities acquired (disposed) (702) 13,927
Accretion expense 1,386 1,893
Liabilities settled (282) (775)
----------------------------------------------------------------------------
Carrying amount, end of period $ 35,385 $ 34,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Share capital:
(a) Authorized:
Unlimited number of Common Shares
(b) Common Shares issued:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
shares Amount
----------------------------------------------------------------------------
Common shares, December 31, 2008 71,084 $ 575,191
Public offering issued for cash 7,000 43,400
Share issue costs, net of income taxes of $665 - (1,774)
----------------------------------------------------------------------------
Common shares, June 30, 2009 78,084 $ 616,817
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On May 28, 2009, the Company issued 7,000,000 Common Shares at a price of
$6.20 per share for aggregate gross proceeds of $43.4 million.
(c) Contributed Surplus:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Contributed surplus, December 31, 2008 $ 16,356
Stock-based compensation 3,421
----------------------------------------------------------------------------
Contributed surplus, June 30, 2009 $ 19,777
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(d) Stock-based compensation:
The Company measures compensation costs associated with stock-based compensation
using the fair market value method under which the cost is recognized over the
vesting period of the underlying security. The fair value of each stock option
is determined at each grant date using the Black-Scholes model with the
following weighted average assumptions used for options granted during the three
month period ended June 30, 2009: risk free interest rate 1.55% (2008 - 4.15%),
expected life 4 years (2008 - 4 years), volatility 52% (2008 - 45%), and an
expected dividend of nil (2008 - nil). The Company has not incorporated an
estimated forfeiture rate for stock options that will not vest rather the
Company accounts for actual forfeitures as they occur.
During the first six months of 2009, the Company recorded $3,421,000, (2008 -
$3,572,000) of stock-based compensation expense related to the stock options, of
which $1,711,000 (2008 - $1,786,000) was capitalized in accordance with the
Company's full cost accounting policy. As stock-based compensation is
non-deductible for income tax purposes, a future income tax liability of
$579,000 (2008 - $623,000) associated with the current year's capitalized
stock-based compensation has been recorded.
(i) Stock options
The average fair value of the stock options granted during the six months
ended June 30, 2009, as calculated by the Black-Scholes method, was $2.03
per option (2008 - $3.34).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Number of Price average
Options Range exercise price
----------------------------------------------------------------------------
Balance December 31, 2008 4,276 $ 3.50 to $ 18.70 $9.76
Granted 1,658 $ 2.78 to $ 5.30 $4.88
Forfeited (154) $ 5.30 to $ 14.77 $10.99
----------------------------------------------------------------------------
Balance June 30, 2009 5,780 $ 2.78 to $ 18.70 $8.32
Exercisable 1,765 $ 7.23 to $ 18.70 $9.69
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(e) Per share amounts:
Per share amounts have been calculated on the weighted average number of shares
outstanding. The weighted average shares outstanding for the three month period
ended June 30, 2009 was 73,622,000 (June 30, 2008 - 57,162,000) and for the six
month period ended June 30, 2009 the weighted average number of shares
outstanding was 72,360,000 (June 30, 2008 - 55,394,000).
In computing diluted per share amounts for the three month period ended June 30,
2009, no (June 30, 2008 - 1,212,000) shares were added to the weighted average
number of Common Shares outstanding for the dilution added by the stock options
and for the six month period ended June 30, 2009, no (June 30, 2008 - 850,000)
shares were added to the weighted average number of common shares for the
dilution. There were 5,780,000 (June 30, 2008 - 190,500) stock options that were
not included in the diluted earnings per share calculation because they were
anti-dilutive.
7. Financial Instruments:
(a) Credit risk:
Credit risk is the risk of financial loss to the Company if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Company's receivables from
petroleum and natural gas marketers and joint venture partners.
The carrying amount of accounts receivable and the fair value of financial
instruments represent the maximum credit exposure. As at June 30, 2009 the
Company's receivables consisted of $12.2 (2008 - $18.4) million of receivables
from petroleum and natural gas marketers of which the majority has subsequently
been collected, $7.5 (2008 - $12.4) million from joint venture partners of which
$0.9 million has subsequently been collected, and $8.8 (2008 - $12.0) million of
Crown deposits, prepaids and other accounts receivable. The Company does not
have an allowance for doubtful accounts as at June 30, 2009 and did not provide
for any doubtful accounts nor was it required to write-off any receivables
during the period ended June 30, 2009.
(b) Liquidity risk:
Accounts payable and financial instruments have contractual maturities of less
than one year. The Company maintains a revolving credit facility, as outlined in
note 3, that is reviewed semi-annually by the lenders and has a contractual
maturity in 2011. The Company maintains and monitors a certain level of cash
flow which is used to partially finance operating and capital expenditures. The
Company does not pay dividends.
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity
prices, interest rates, and foreign exchange rates, will affect the Company's
net income or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
limits, while maximizing the Company's returns.
The Company utilizes both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with the Company's risk management policy that has been approved by
the Board of Directors.
(i) Commodity price risk
The Company has attempted to mitigate a portion of the commodity price risk
through the use of various financial derivative and physical delivery sales
contracts. The Company's policy is to enter into commodity price contracts when
considered appropriate to a maximum of 50% of forecasted production volumes for
a period of not more than two years.
Derivatives are recorded on the balance sheet at fair value at each reporting
period with the change in fair value being recognized as an unrealized gain or
loss on the consolidated statement of operations, comprehensive income and
retained earnings.
(ii) Foreign currency exchange rate risk
The Company has attempted to mitigate a portion of its foreign exchange
fluctuation risk through the use of financial derivatives as outlined below.
(iii) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result
of changes in market interest rates. The Company is exposed to interest rate
fluctuations on its bank debt which bears a floating rate of interest. For the
three and six months ended June 30, 2009, a 1.0 percent change to the effective
interest rate would have a $0.4 million and $0.9 million impact on net income,
respectively (2008 - $0.2 and $0.4 million). The sensitivity for 2009 is higher
as compared to 2008 because of an increase in average outstanding bank debt in
2009 compared to 2008.
The Company has attempted to mitigate the impact of future fluctuations in
interest rates on its outstanding debt by entering into contracts fixing the
base interest rate on $150 million of banker's acceptance borrowings as outlined
below. These rates are, under the Company's recently amended banking Facility,
subject to additional stamping fees ranging from 2.75 per cent to 4.50 per cent
depending upon the debt to EBITDA ratio calculated at the Company's previous
quarter end.
The Company's derivative contracts in place as of June 30, 2009 are as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notional
Subject of Contract Quantity Term Reference
----------------------------------------------------------------------------
Commodity contracts
Natural Gas 2,500 gj/day January 1, 2009 - AECO C Monthly
December 31, 2009 Index
Natural Gas 2,500 gj/day January 1, 2009 - AECO C Monthly
December 31, 2009 Index less $0.09
Natural Gas 15,000 gj/day April 1, 2009 - AECO C Monthly
October 31, 2009 Index
Natural Gas 2,500 gj/day November 1, 2009 - AECO C Monthly
December 31, 2010 Index
Natural Gas 5,000 gj/day January 1, 2010 - AECO C Monthly
December 31, 2010 Index
Natural Gas 10,000 gj/day January 1, 2010 - AECO C Monthly
December 31, 2010 Index
Natural Gas 2,500 gj/day January 1, 2010 - AECO C Monthly
December 31, 2010 Index
Natural Gas 5,000 gj/day January 1, 2010 - AECO C Monthly
December 31, 2010 Index
Oil 500 bbl/day July 1, 2009 - CDN$ WTI
December 31, 2009
Oil 500 bbl/day July 1, 2009 - CDN$ WTI
December 31, 2009
Oil 250 bbl/day July 1, 2009 - CDN$ WTI
December 31, 2009
Oil 250 bbl/day January 1, 2010 - CDN$ WTI
December 31, 2010
Oil 500 bbl/day January 1, 2010 - CDN$ WTI
December 31, 2010
Oil 250 bbl/day January 1, 2010 - CDN$ WTI
December 31, 2010
----------------------------------------------------------------------------
Total commodity
contracts
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized
Gain
Strike Option (Loss) Fair Value
Subject of Contract Price Traded ($000s) ($000s)
----------------------------------------------------------------------------
Commodity contracts
Natural Gas $ 6.60 - $ 8.50 Collar 996 1,265
Natural Gas $ 6.50 - $ 8.30 Collar 1,216 995
Natural Gas $ 6.00 Put 3,459 4,090
Natural Gas $ 6.00 Swap - 338
Natural Gas $ 8.00 Call - (408)
Natural Gas $ 7.75 Call - (1,113)
Natural Gas $ 6.20 Swap - 363
Natural Gas $ 6.08 Swap - 511
Oil $81.70 Swap - (181)
Oil $72.00 Swap - (1,066)
Oil $80.50 Swap - (143)
Oil $78.50 Swap - (798)
Oil $72.00 - $88.00 Collar - (1,012)
Oil $82.50 Swap - (445)
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Total commodity contracts 5,671 2,396
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Subject of Notional
Contract Quantity Term Reference
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Foreign exchange contracts
USD / CAD $ US $2M / February 1, 2009 -
exchange Month December 31, 2009 CAD/USD
USD / CAD $ US $2M / February 1, 2009 -
exchange Month December 31, 2009 CAD/USD
USD / CAD $ US $2M / January 1, 2010 -
exchange Month December 31, 2010 CAD/USD
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Total foreign exchange contracts
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Interest rate contracts
BA Rate $50M / February 10, 2009 - BA -
year February 10, 2011 CDOR
BA Rate $50M / February 12, 2009 - BA -
year February 12, 2011 CDOR
BA Rate $50M / May 28, 2009 - May BA -
year 28, 2011 CDOR
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Total interest rate contracts
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Total financial instruments
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Realized
Gain
Strike Option (Loss) Fair Value
Subject of Contract Price Traded ($000s) ($000s)
----------------------------------------------------------------------------
Foreign exchange contracts
USD / CAD $ exchange 1.22 Swap 178 877
USD / CAD $ exchange 1.26 Swap 578 1,163
USD / CAD $ exchange 1.094 Swap - (1,610)
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Total foreign exchange contracts 756 430
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Interest rate contracts
BA Rate 1.10% Swap (98) (269)
BA Rate 1.10% Swap (101) (201)
BA Rate 1.12% Swap (32) (47)
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Total interest rate contracts (231) (517)
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Total financial instruments 6,196 2,309
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As at June 30, 2009, a $0.10 change to the price per thousand cubic feet of
natural gas on the contracts outlined above would have a $0.1 million impact on
net income.
As at June 30, 2009, a $1.00 per barrel change to the price on the oil contract
outlined above would have a $0.5 million impact on net income.
As at June 30, 2009, a $0.01 change to the exchange rate on the foreign exchange
contracts would have a $0.4 million impact on net income.
As at June 30, 2009, a 0.1% change to the interest rate on the interest rate
contracts would have a $0.2 million impact on net income.
Fair value of financial instruments
The Company's financial instruments as at June 30, 2009 and 2008 include
accounts receivable, derivative contracts, accounts payable and accrued
liabilities, and bank debt. The fair value of accounts receivable and accounts
payable and accrued liabilities approximate their carrying amounts due to their
short-terms to maturity.
The fair value of derivative contracts is determined by discounting the
difference between the contracted price and published forward price curves as at
the balance sheet date, using the remaining contracted notional volumes.
Bank debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.
8. Capital management:
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes
adjustments on an on-going basis in order to maintain the flexibility needed to
achieve the Company's long-term objectives. To manage the capital structure the
Company may adjust capital spending, hedge future revenue and 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 in a normalized commodity price environment. This ratio may increase at
certain times as a result of acquisitions or low commodity prices. As shown
below, as at June 30, 2009, the Company's ratio of net debt to annualized funds
from operations was 2.28 to 1 (December 31, 2008 - 2.15 to 1). This amount has
risen above the preferred range of the Company as a result of the decrease in
commodity prices experienced over the past nine months.
----------------------------------------------------------------------------
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June 30, December 31,
2009 2008
----------------------------------------------------------------------------
Net debt:
Accounts receivable $ 28,518 $ 42,800
Accounts payable and accrued liabilities (35,948) (74,622)
----------------------------------------------------------------------------
Working capital deficiency $ (7,430) $ (31,822)
Bank loan (174,928) (223,628)
----------------------------------------------------------------------------
Net debt $ (182,358) $ (255,450)
Annualized funds from operations:
Cash provided by operating activities $ 21,517 $ 25,700
Asset retirement expenditures 181 152
Transportation liability charge 329 328
Change in non-cash working capital (1,991) 3,466
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Funds from operations 20,036 29,646
Annualized $ 80,144 $ 118,584
Net debt to annualized funds from operations 2.28 2.15
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In order to restore the Company's financial flexibility Crew will execute a
conservative capital spending program in 2009 currently estimated at $80
million. The Company has added commodity, interest rate and foreign exchange
hedging for 2009 and 2010 to provide support for its funds from operations and
assist in funding its capital expenditure program. On May 28, 2009, the Company
closed a bought deal equity financing for aggregate gross proceeds of $43.4
million. In addition, in 2009 the Company has disposed of non-core properties
for net proceeds of $34.4 million. The Company may also consider the sale of
additional non-core assets and will consider other forms of financing to improve
the Company's financial position if cash flow does not adequately fund the
programs planned to achieve the Company's long term objectives.
There has been no change in the Company's approach to capital management during
the period ended June 30, 2009.
9. Supplemental cash flow information:
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----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Changes in non-cash working capital:
Accounts receivable $ 3,335 $ 154 $ 14,282 $ (6,180)
Accounts payable and accrued
liabilities (8,561) (8,726) (38,674) (2,811)
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$ (5,226) $ (8,572) $(24,392) $ (8,991)
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Operating activities $ 1,991 $ (1,543) $ 5,405 $ (404)
Investing activities (7,217) (7,029) (29,797) (8,587)
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$ (5,226) $ (8,572) $(24,392) $ (8,991)
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The Company made the following cash outlays in respect of interest expense:
----------------------------------------------------------------------------
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Interest $ 2,457 $ 1,099 $ 4,188 $ 2,851
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10. Commitments:
The Company has the following fixed term commitments related to its on-going
business:
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Total 2009 2010 2011
----------------------------------------------------------------------------
Operating Leases $ 2,227 $ 495 $ 990 $ 742
Capital commitments 10,955 4,455 6,500 -
Firm transportation agreements 17,289 3,499 7,152 6,638
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Total $ 30,471 $ 8,449 $ 14,642 $ 7,380
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The firm transportation commitments were acquired as part of the Company's May
2007 private company acquisition and represent firm service commitments for
transportation and processing of natural gas in British Columbia.
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