Crew Energy Inc. (TSX:CR) of Calgary, Alberta is pleased to present its
operating and financial results for the three and nine month periods ended
September 30, 2009.
Highlights
- Increased production by 14% over the third quarter of 2008 to average 13,065
boe per day, 7% ahead of forecast;
- Funds from operations were $19.6 million or $0.25 per share;
- Reached an agreement to sell certain non-core assets for $25 million with an
expected closing in November, 2009;
- Completed the construction of the Septimus gas plant which started operations
ahead of schedule on October 1, 2009 and under budget by approximately 15%;
- Production at Princess, Alberta has increased by 64% to greater than 3,600 boe
per day;
- Subsequent to quarter end, Crew has added seven (6.0 net) sections of land on
the Company's Montney play in northeastern British Columbia and now controls
over 200 net sections on this play;
- As a result of a successful drilling program and asset disposition program,
Crew has expanded its 2009 resource focused capital program and has increased
production guidance to average over 15,000 boe per day in December.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial Three months Three months Nine months Nine months
($ thousands, ended ended ended ended
except per September 30, September 30, September 30, September 30,
share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Petroleum and
natural gas sales 38,510 65,345 124,183 177,050
Funds from
operations (note 1) 19,640 35,004 56,197 98,144
Per share - basic 0.25 0.54 0.76 1.68
- diluted 0.25 0.54 0.76 1.66
Net income (loss) (7,376) 15,178 (28,661) 21,534
Per share - basic (0.09) 0.24 (0.39) 0.37
- diluted (0.09) 0.23 (0.39) 0.36
Exploration and
development
investment 35,390 66,399 73,255 138,065
Property acquisitions
(net of dispositions) - (1,097) (34,378) 70,659
Net capital
expenditures 35,390 65,302 38,877 208,724
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Structure As at As at
($ thousands) Sept. 30, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Working capital deficiency (note 2) 31,845 31,822
Bank loan 166,768 223,628
Net debt 198,613 255,450
Bank facility 265,000 285,000
Common Shares Outstanding (thousands) 78,087 71,084
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital, asset
retirement expenditures and the transportation liability charge.
Funds from operations is used to analyze the Company's operating
performance and leverage. Funds from operations does not have a
standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
(2) Working capital deficiency includes only accounts receivable less
accounts payable and accrued liabilities.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
Operations 2009 2008 2009 2008
----------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 49,478 52,523 54,314 49,953
Oil (bbl/d) 3,376 1,515 3,447 813
Natural gas liquids
(bbl/d) 1,443 1,236 1,345 1,387
Oil equivalent
(boe/d @ 6:1) 13,065 11,505 13,844 10,526
Per million diluted
shares
Average prices (note 1)
Natural gas ($/mcf) 3.23 8.30 4.04 8.96
Oil ($/bbl) 63.91 104.68 55.61 106.74
Natural gas liquids
($/bbl) 29.94 76.93 32.16 72.45
Oil equivalent
($/boe) 32.04 61.74 32.86 61.39
Operating expenses
Natural gas ($/mcf) 2.03 1.57 1.87 1.34
Oil ($/bbl) 11.23 12.96 11.73 11.45
Natural gas liquids
($/bbl) 9.58 8.51 9.32 6.94
Oil equivalent
($/boe @ 6:1) 11.65 9.79 11.18 8.17
Netback
Operating netback
($/boe) (note 2) 17.77 35.44 16.67 36.73
Realized gain on
financial
instruments (note 3) (1.20) - (0.52) -
G&A ($/boe) 1.10 0.85 1.13 1.01
Interest and other
($/boe) 1.54 1.52 1.19 1.69
Funds from operations
($/boe) 16.33 33.07 14.87 34.03
Drilling Activity
Gross wells 12 18 20 37
Working interest wells 12.0 16.8 14.8 33.6
Success rate, net wells 100% 94% 99% 94%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 for the third quarter were highlighted by the drilling of 12 (12.0
net) wells with 100% success and the completion of Crew's Septimus gas plant.
Crew drilled nine (9.0 net) oil wells, two (2.0 net) gas wells and one (1.0 net)
water disposal well during the quarter. The Septimus gas plant was commissioned
on October 1, 2009 ahead of schedule and approximately $3.5 million or 15% under
budget.
Third quarter production of 13,065 boe per day was up 14% compared to the same
period in 2008 and was down compared to the second quarter of 2009 as a result
of production declines, asset sales of 670 boe per day, and production shut-ins
of approximately 400 boe per day. Third quarter commodity prices were
substantially lower than the same period of 2008. Crew's wellhead natural gas
price averaged $3.23 per mcf which was 61% lower than the third quarter 2008
price of $8.30 per mcf. The Company's realized oil price was down 39% from the
$104.68 per barrel in the third quarter of 2008 to $63.91 per barrel in the
third quarter of 2009. Crew's natural gas liquids price was $76.93 per barrel in
the third quarter of 2008 and fell 61% to $29.94 per barrel in the third 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. This program resulted in a
net third quarter funds from operations gain to the Company of $7.8 million or
$6.48 per boe.
Over the course of 2009, Crew has been able to significantly strengthen its
balance sheet. At the end of the third quarter, net debt has been reduced by 22%
or $57 million from 2008 year-end levels to $198.6 million. In addition, during
the fourth quarter of 2009, the Company expects to receive proceeds of
approximately $25 million from a non-core asset disposition with production of
approximately 600 boe per day, total proved reserves of 1.2 mmboe and total
proved and probable reserves of 1.8 mmboe of natural gas and associated natural
gas liquids. In addition, approximately $19 million of proceeds are expected
prior to year end as a result of the previously announced Aux Sable Canada
("ASC") gas plant transaction.
RISK MANAGEMENT ACTIVITY
With the volatility experienced in the commodity markets over the past 18
months, Crew has implemented an active commodity hedging program in order to
ensure a base level of cash flow to fund its on-going capital expenditure
program. During 2009, this program has generated $14 million of funds from
operations or $0.19 per share. For the fourth quarter of 2009 Crew has an
average of 20,000 gigajoules ("gj") per day of natural gas hedged at an average
floor price of $5.74 per gj. The Company has also hedged 1,250 bbl per day of
oil at an average West Texas Intermediate ("WTI") price of CDN $77.58.
For 2010, Crew has now entered into fixed price gas contracts for an average of
14,200 gj per day at an average price of $6.02 per gj for calendar 2010. The
Company has hedged oil production for 2010 with fixed price contracts for 1,500
bbl per day at an average of CDN $82.25 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.
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.
The majority of the Company's bank borrowings are completed in the form of
banker's acceptances. In order to reduce the risk of a future increase in the
interest rate charged on those 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 under the Company's bank facility.
OPERATIONS UPDATE
During the third quarter, Crew had 100% success drilling six (6.0 net)
horizontal oil wells and one (1.0 net) water disposal well at Princess, Alberta,
three (3.0 net) horizontal oil wells at Killam, Alberta and two (2.0 net)
horizontal gas wells at Septimus, British Columbia. The Company spent $17.8
million or 50% of the quarter's capital expenditures on drilling and completion
operations. An additional $15.0 million or 41% of the quarter's capital
expenditures were spent on facilities, equipment and pipelines, the majority of
which was on the completion of the Septimus, British Columbia gas plant and
associated pipeline and wellsite infrastructure. Only $0.9 million was spent on
seismic and land acquisitions.
Montney Play, Northeast British Columbia
Crew is very pleased to announce the Company's 25 mmcf per day Septimus gas
plant was constructed ahead of schedule and for approximately $19 million, 15%
under the budgeted cost of $22.5 million. The plant commenced processing gas on
October 1, 2009 and is currently processing approximately 12 mmcf per day net to
Crew with an additional three wells awaiting completion or tie-in. Crew expects
to complete the previously announced transaction with ASC in which Crew will
sell the Septimus gas plant to ASC at the cost incurred, now expected to be
approximately $19 million. Operating costs in the Septimus area are expected to
be reduced from approximately $12 per boe to $5 per boe which includes Crew
paying processing and operating throughput fees. ASC plans to construct and
operate a twelve mile large diameter pipeline from the Septimus gas plant to the
Alliance pipeline. This pipeline, when operational, will have a capacity of
approximately 400 mmcf per day. Crew has retained the option to, and currently
plans to participate in an expansion of the Septimus gas plant to 50 to 60 mmcf
per day in 2010 pending a recovery in North American natural gas prices.
Crew recently added seven (6.0 net) sections of land at British Columbia land
sales to now control over 200 net sections on the Company's Montney resource
play. During the third quarter, Crew drilled two (2.0 net) gas wells at
Septimus. The Company is currently in the process of completing two (2.0 net)
wells, drilling the 3-12 outpost well at Septimus and drilling the Portage
C-20-E exploration well. Crew plans to drill one additional horizontal well at
Septimus in the fourth quarter as part of an expanded capital program.
The British Columbia government has initiated a drilling incentive program which
is expected to result in approximately $2 million in royalty relief for Crew's
horizontal wells drilled from September 1, 2009 to June 30, 2010. As a result,
Crew plans to drill a total of eight (7.0 net) horizontal wells to the end of
June 2010.
Pekisko Play, Princess Alberta
Crew has been very successful with its recompletion and drilling program at
Princess resulting in a 64% increase in production to over 3,600 boe per day
with several wells on maximum rate limitations ("MRL") awaiting approval of Good
Production Practice ("GPP") applications. The Company was active drilling wells
at Princess in the third quarter, drilling six (6.0 net) horizontal oil wells
and one (1.0 net) water disposal well. Production from existing wells continues
to be positive as the 8-8 horizontal well has now produced 97,000 barrels of oil
in the first year and continues to produce at approximately 240 bopd. The 11-4
vertical well has produced over 100,000 barrels of oil and continues to produce
at over 310 bopd. Three recompletions at Princess each continue to produce at
105 to 230 bopd and three out of six third quarter wells are now on production
and are exhibiting initial production rates averaging over 250 bopd.
Crew drilled one water disposal well during the quarter which tested at an
injection rate of 4,800 barrels of water 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. During the quarter, Crew received water disposal
status on the second disposal well drilled in the second quarter and the well is
now in service.
The Company has initiated a program to install liners in 30 kilometers of
pipelines in the area to protect the existing pipeline infrastructure from
corrosion. This is a preventative measure to improve area operating efficiencies
and reduce operating costs while protecting the environment. This program is
scheduled to be completed by mid November and is expected to safeguard the
existing infrastructure for several years. During the fourth quarter of 2009 and
first quarter of 2010, Crew plans to install one gas and one oil pipeline from
the Alderson battery to the West Tide Lake battery. This 18 kilometer pipeline
connection of facilities will improve operational efficiencies and lower
operating costs in the area. At the same time, the Company also plans to upgrade
the West Tide Lake facility adding an amine unit to treat sour gas volumes,
additional compression and a refrigeration unit at a cost of approximately $8
million. These additions will provide the Company with increased sour gas
processing and oil handling capability. Crew has an active fourth quarter
program planned at Princess with seven (7.0 net) horizontal wells targeting oil,
two horizontal water disposal wells, and up to twelve vertical stratigraphic
test wells.
OUTLOOK
Business Environment
Natural gas prices have improved from their September lows; however, they
continue to be weak as weekly inventory injections continue to build North
American storage to record levels. Throughout North America, natural gas
directed drilling activity levels continue to be muted although the proportion
of horizontal wells has increased to over 60% of gas wells drilled. This has
resulted in higher initial production rates per well adding to the current over
supplied market. This only reinforces Crew's plan to be a low cost producer.
Assembling an oil and gas resource focused asset base has provided the Company
with long-term, repeatable development opportunities with economies of scale to
drive costs down. Cost control will become increasingly important in a world of
resource plays and ever improving technology. As Crew strives to drive costs
down, we believe supply-demand fundamentals will improve as capital investment
in natural gas is challenged by reduced cash flows and tight credit markets as
the North American economy continues its recovery.
Increased Capital Program and Production Guidance
The success of the Company's third quarter capital program has created
operational momentum that we plan to build upon. The third quarter success
combined with the financial flexibility provided by the sale of $59 million of
non-core assets and the sale of the Septimus gas plant for $19 million will
allow the Company to increase its planned fourth quarter 2009 capital
expenditures. As such, the Company now plans to spend between $45 and $55
million on exploration and development opportunities in the fourth quarter
resulting in capital expenditures for the year totaling between $40 and $50
million, net of dispositions. The increased capital program combined with the
dispositions are expected to result in net debt at year end of $180 to $190
million or approximately two times forecasted annualized fourth quarter funds
from operations.
This increased spending is forecasted to fully replace the 1,270 boe per day of
production sold through the non-core asset dispositions, replace the 400 boe per
of uneconomic natural gas production that will remain shut-in through year-end
and replace the Company's natural production declines. The increased spending
has resulted in the Company increasing its full year production guidance to
range between 13,800 to 14,000 boe per day and its forecasted exit rate to be
15,000 boe per day as represented by average forecasted December production.
Expansion of Resource Development
Crew drilled twelve net wells in the third quarter of 2009 which was nine more
than the Company drilled in the first six months of the year. As a result of an
increased capital expenditure program, the Company now expects to drill 25 (24.3
net) wells in the fourth quarter of 2009:
- Two (1.7 net) horizontal wells at Septimus, British Columbia targeting liquids
rich gas;
- One (1.0 net) vertical exploration well at Portage, British Columbia targeting
liquids rich gas;
- One (0.6 net) vertical well at Wapiti, Alberta targeting liquids rich natural gas;
- Seven (7.0 net) horizontal wells at Princess, Alberta targeting oil;
- Two (2.0 net) horizontal water disposal wells at Princess, Alberta; and
- Twelve (12.0 net) vertical stratigraphic tests at Princess, Alberta.
Crew now has the ability to direct capital to oil or gas resource plays. In the
current environment, the Company has chosen to direct the majority of its
capital to oil plays in favour of significantly higher netbacks compared to gas
directed drilling. Of the wells planned in the fourth quarter, 19 are oil
targets, four are gas targets and two are water disposal wells.
Crew has been disciplined in following our business plan that was established in
a very challenging period. The Company has been able to materially reduce debt
while growing its production in two resource plays which form the future of the
Company. Through a challenging 2009, Crew is now in a position to accomplish:
- A strengthening of the Company's balance sheet with a forecasted reduction of
net debt of over $65 million by year end;
- Significant expansion of two resource plays;
- A reduction in the Company's cost structure;
- An increase in forecasted December 2009 debt adjusted production per share of
34% compared to the same period in 2008; and
- Most importantly, the validation of the Company's two resource plays setting
the stage for future growth.
These results are supportive of the success of Crew's strategy and we will
continue to do the following:
- High grade our asset base through non-core property dispositions and redeploy
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 understand our shareholders have had to endure a very volatile period and we
thank you for your continued support and patience. We believe the worst of this
recession is behind us and we are staying focused on cost cutting and
positioning the Company to take advantage of all opportunities that may arise.
Our "Crew" is excited about the Company's results which we firmly believe set
the stage for repeatable predictable future success. We are looking forward to a
busy fourth quarter drilling program and look forward to presenting Crew's
fourth quarter and year end results in 2010.
Management's Discussion and Analysis
ADVISORIES
Management's discussion and analysis ("MD&A") is the Company's explanation of
its financial performance for the period covered by the financial statements
along with an analysis of the Company's financial position. Comments relate to
and should be read in conjunction with the unaudited consolidated financial
statements of the Company for the three and nine month periods ended September
30, 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 royalty rates, general and administrative expenses, interest
rates, debt levels, funds from operations and the timing of and impact of
adoption of IFRS and other accounting policies may constitute forward-looking
statements under applicable securities laws and necessarily involve risks
including, without limitation, risks associated with oil and gas exploration,
development, exploitation, production, marketing and transportation, loss of
markets, volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risks, competition from other producers,
inability to retain drilling rigs and other services, incorrect assessment of
the value of acquisitions, failure to realize the anticipated benefits of
acquisitions, the inability to fully realize the benefits of 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 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:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by
operating activities 24,902 36,208 65,925 97,656
Asset retirement
expenditures 196 (8) 478 623
Transportation
liability charge 328 328 985 985
Change in non-cash
working capital (5,786) (1,524) (11,191) (1,120)
----------------------------------------------------------------------------
Funds from
operations 19,640 35,004 56,197 98,144
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore may not be
comparable with the calculation of similar measures for other entities.
Operating netback equals total petroleum and natural gas sales including
realized gains and losses on commodity contracts less royalties, operating costs
and transportation costs calculated on a boe basis. Management considers
operating netbacks an important measure to evaluate its operational performance
as it demonstrates its field level profitability relative to current commodity
prices.
RESULTS OF OPERATIONS
Production
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
September 30, 2009 September 30, 2008
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Plains
Core 3,194 880 33,606 9,675 1,297 841 36,578 8,234
North
Core 182 563 15,872 3,390 218 395 15,945 3,271
----------------------------------------------------------------------------
Total 3,376 1,443 49,478 13,065 1,515 1,236 52,523 11,505
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production increased in the third quarter of 2009 compared to the same period in
2008 as a result of a successful drilling program that added oil production in
the Princess, Alberta area and natural gas production in the Septimus, British
Columbia area. Production was also positively impacted in the third quarter due
to the production acquired through the August 22, 2008 acquisition of Gentry
Resources Inc. ("Gentry") which included 4,100 boe per day at the date of
acquisition. The impact of these additions was partially offset by the shut-in
of approximately 400 boe per day of uneconomic natural gas production in Alberta
and property dispositions completed during the first half of 2009 of
approximately 670 boe per day of non-core production in Alberta and
Saskatchewan.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Nine months ended
September 30, 2009 September 30, 2008
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Plains
Core 3,241 915 36,899 10,305 631 992 35,035 7,463
North
Core 206 430 17,415 3,539 182 395 14,918 3,063
----------------------------------------------------------------------------
Total 3,447 1,345 54,314 13,844 813 1,387 49,953 10,526
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production for the first nine months of 2009 increased due to the previously
mentioned successful drilling program and the acquisition of Gentry in August
2008.
Revenue
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue ($ thousands)
Natural gas 14,685 40,113 59,953 122,655
Oil 19,850 14,594 52,323 23,771
Natural gas liquids 3,975 8,750 11,809 27,529
Sulphur - 1,888 98 3,095
----------------------------------------------------------------------------
Total 38,510 65,345 124,183 177,050
----------------------------------------------------------------------------
Crew average prices
Natural gas ($/mcf) 3.23 8.30 4.04 8.96
Oil ($/bbl) 63.91 104.68 55.61 106.74
Natural gas liquids
($/bbl) 29.94 76.93 32.16 72.45
Oil equivalent
($/boe) 32.04 61.74 32.86 61.39
Benchmark pricing
Natural Gas -
AECO C daily index
(Cdn $/mcf) 3.02 7.85 3.83 8.76
Oil - Bow River Crude
Oil (Cdn $/bbl) 73.20 115.75 65.79 106.08
Oil and ngl - Light
Sweet @ Edmonton
(Cdn $/bbl) 71.61 121.83 62.32 115.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's third quarter 2009 revenue decreased 41% from the third quarter of 2008
due to the 48% decrease in average commodity prices partially offset by a 14%
increase in the Company's production. Revenue for the nine months ended
September 30, 2009 has decreased 30% compared to the first nine months of 2008
due to the 46% decline in average commodity prices partially offset by a 32%
increase in production.
Crew's average natural gas price decreased 61% in the third quarter of 2009
compared to the third quarter of 2008. This is comparable to a 62% decrease in
the Company's benchmark natural gas price for the same period. In the third
quarter of 2009, the Company's oil price decreased 39% which was comparable with
a 37% decrease in the medium grade oil Bow River benchmark and a 41% decrease in
the Light Sweet Edmonton par benchmark. In the third quarter of 2009, 80% of the
Company's total oil production was medium grade oil from the Princess, Alberta
area acquired as part of the Gentry acquisition in August 2008 compared to only
49% of the Company's total oil production for the same period in 2008. The
Company's ngl price decreased 61% in the third quarter of 2009 compared to a 41%
decrease in the benchmark light sweet at Edmonton for the same period of 2008.
Increased production of lower valued ethane in the Septimus, British Columbia
area accounts for the disproportionate decrease in ngl prices.
For the nine months ended September 30, 2009, Crew's gas price decreased 59%
compared to the first nine months of 2008 while the benchmark decreased 56% for
the same period. In 2009, decreased production of higher heat content natural
gas from the Company's Edson, Alberta property has decreased the Company's
corporate natural gas price compared to the benchmark. The Company's oil price
decreased 48% as compared with a 38% decrease in the medium grade oil Bow River
benchmark and 46% in the Light Sweet Edmonton par benchmark. The Company's
disproportionate decrease in its oil price compared to the benchmark for the
first nine 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. Ngl prices decreased 56% in the first nine months of 2009 compared
to the same period of 2008. This compares to a 46% decrease in the price at
Edmonton. The disproportionate decrease in Crew's ngl price is due to the above
mentioned increase in ethane production.
Royalties
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, September 30, September 30, September 30, September 30,
except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Royalties 6,668 14,157 22,860 37,926
Per boe 5.55 13.38 6.05 13.15
Percentage of revenue 17.3% 21.7% 18.4% 21.4%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties as a percentage of revenue decreased in the third quarter and first
nine 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. Corporately, Crew forecasts annual royalties as a percentage of revenue to
average 18% to 20% for 2009, a reduction from the prior quarter's annual
forecast due to lower expected royalties from continued weak natural gas
pricing.
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 September 30, 2009, the Company held derivative commodity contracts as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Realized Fair
of Notional Strike Option Gain Value
Contract Quantity Term Reference Price Traded ($000s) ($000s)
----------------------------------------------------------------------------
Natural 2,500 January 1, AECO C $ 6.60- Collar 1,855 520
Gas gj/day 2009 - Monthly $8.50
December 31, Index
2009
Natural 2,500 January 1, AECO C $ 6.50- Collar 2,079 230
Gas gj/day 2009 - Monthly $8.30
December 31, Index
2009 less
$0.09
Natural 15,000 April 1, 2009 AECO C $6.00 Put 7,781 1,451
Gas gj/day - October 31, Monthly
2009 Index
Natural 2,500 November 1, AECO C $6.00 Swap - 361
Gas gj/day 2009 - Monthly
December 31, Index
2010
Natural 5,000 January 1, AECO C $8.00 Call - (278)
Gas gj/day 2010 - Monthly
December 31, Index
2010
Natural 10,000 January 1, AECO C $7.75 Call - (821)
Gas gj/day 2010 - Monthly
December 31, Index
2010
Natural 2,500 January 1, AECO C $6.20 Swap - 425
Gas gj/day 2010 - Monthly
December 31, Index
2010
Natural 5,000 January 1, AECO C $6.08 Swap - 617
Gas gj/day 2010 - Monthly
December 31, Index
2010
Oil 500 July 1, 2009 CDN$ WTI $ 81.70 Swap 314 357
bbl/day - December 31,
2009
Oil 500 July 1, 2009 CDN$ WTI $ 72.00 Swap (133) (188)
bbl/day - December 31,
2009
Oil 250 July 1, 2009 CDN$ WTI $ 80.50 Swap 129 141
bbl/day - December 31,
2009
Oil 250 January 1, CDN$ WTI $ 78.50 Swap - (106)
bbl/day 2010 -
December 31,
2010
Oil 500 January 1, CDN$ WTI $72.00- Collar - 16
bbl/day 2010 - $ 88.00
December 31,
2010
Oil 250 January 1, CDN$ WTI $ 82.50 Swap - 258
bbl/day 2010 -
December 31,
2010
Oil 500 January 1, CDN$ WTI $ 82.50 Swap - 152
bbl/day 2010 -
December 31,
2010
----------------------------------------------------------------------------
Total 12,025 3,135
----------------------------------------------------------------------------
Foreign currency
Although all of the Company's petroleum and natural gas sales are conducted in
Canada and are denominated in Canadian dollars, Canadian commodity prices are
influenced by fluctuations in the Canadian to U.S. dollar exchange rate.
At September 30, 2009, the Company held derivative foreign currency
contracts as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized Fair
Subject of Notional Strike Option Gain Value
Contract Quantity Term Reference Price Traded ($000s) ($000s)
----------------------------------------------------------------------------
USD / CAD $ US $2M / February 1, CAD/USD 1.22 Swap 913 895
exchange Month 2009 -
December 31,
2009
USD / CAD $ US $2M / February 1, CAD/USD 1.26 Swap 1,554 1,136
exchange Month 2009 -
December 31,
2009
USD / CAD $ US $2M / January 1, CAD/USD 1.094 Swap - 554
exchange Month 2010 -
December 31,
2010
----------------------------------------------------------------------------
Total 2,467 2,585
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 September 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 Fair
Subject of Notional Strike Option Loss Value
Contract Quantity Term Reference Price Traded ($000s) ($000s)
----------------------------------------------------------------------------
BA Rate $50M / February 10, BA - 1.10% Swap (190) (185)
year 2009 - CDOR
February 10,
2011
BA Rate $50M / February 12, BA - 1.10% Swap (190) (138)
year 2009 CDOR
February 12,
2011
BA Rate $50M / May 28, 2009 BA - 1.12% Swap (122) (6)
year - May 28, CDOR
2011
----------------------------------------------------------------------------
Total (502) (329)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subsequent to September 30, 2009, the Company entered into the following
financial derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional Strike Option
Contract Quantity Term Reference Price Traded
----------------------------------------------------------------------------
Gas 5,000 January 1, AECO/NYMEX Basis US$ ($0.55) Swap
mmbtu/d 2010 - diff less $0.55/mmbtu
December 31,
2010
Oil 500 bbl/day January 1, US$ WTI $81.00 Swap
2010 -
December 31,
2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, September 30, September 30, September 30, September 30,
except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Operating costs 14,000 10,363 42,258 23,568
Per boe 11.65 9.79 11.18 8.17
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the third quarter and first nine 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. A combination of higher than
expected prior period equalizations and a decrease in lower cost production due
to the sale of non-core Alberta natural gas assets have increased the Company's
per boe costs for the three and nine month periods ended September 30, 2009. The
Company expects operating costs to range from $11.00 to $11.50 per boe for 2009.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, September 30, September 30, September 30, September 30,
except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Transportation
costs 2,830 2,325 8,095 6,317
Per boe 2.35 2.20 2.14 2.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the third quarter of 2009, the Company's transportation costs per unit have
increased 7% compared to the same period in 2008. A decrease in natural gas
production has increased gas transportation costs per unit in northeastern
British Columbia where the Company has a fixed transportation commitment. In
addition, adjustments to prior period clean oil trucking estimates in Princess,
Alberta increased the Company's overall transportation costs per unit. For the
first nine months of 2009, the Company's transportation costs per unit have
slightly decreased as compared with the same period in 2008 as a result of lower
per unit costs for oil production in the Princess, Alberta area added in the
Gentry acquisition in August 2008. Transportation costs are forecasted to remain
in the $2.00 to $2.25 per boe range for 2009.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
September 30, 2009
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 63.91 29.94 3.23 32.04
Realized commodity hedging
gain (loss) 0.70 - 1.33 5.28
Royalties (17.61) (8.22) (0.02) (5.55)
Operating costs (11.23) (9.58) (2.03) (11.65)
Transportation costs (2.11) (0.20) (0.47) (2.35)
----------------------------------------------------------------------------
Operating netbacks 33.66 11.94 2.04 17.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
September 30, 2008
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 104.68 76.93 8.30 61.74
Realized commodity hedging
gain (loss) (0.01) - (0.24) (0.93)
Royalties (16.48) (18.47) (1.93) (13.38)
Operating costs (12.96) (8.51) (1.57) (9.79)
Transportation costs (2.18) (0.02) (0.42) (2.20)
----------------------------------------------------------------------------
Operating netbacks 73.05 49.93 4.14 35.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended
September 30, 2009
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 55.61 32.16 4.04 32.86
Realized commodity hedging
gain (loss) 0.24 - 0.79 3.18
Royalties (14.75) (9.94) (0.36) (6.05)
Operating costs (11.73) (9.32) (1.87) (11.18)
Transportation costs (1.65) (0.07) (0.44) (2.14)
----------------------------------------------------------------------------
Operating netbacks 27.72 12.83 2.16 16.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended
September 30, 2008
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 106.74 72.45 8.96 61.39
Realized commodity hedging
gain (loss) - - (0.66) (1.15)
Royalties (16.11) (19.70) (1.91) (13.15)
Operating costs (11.45) (6.94) (1.34) (8.17)
Transportation costs (2.44) (0.03) (0.42) (2.19)
----------------------------------------------------------------------------
Operating netbacks 76.74 45.78 4.63 36.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, September 30, September 30, September 30, September 30,
except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Gross costs 3,436 2,936 10,134 8,024
Operator's recoveries (797) (1,136) (1,609) (2,170)
Capitalized costs (1,319) (900) (4,262) (2,927)
----------------------------------------------------------------------------
General and
administrative
expenses 1,320 900 4,263 2,927
Per boe 1.10 0.85 1.13 1.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 third quarter of 2009 compared to 2008. In the third
quarter of 2009 and the first nine months of 2009, net general and
administrative costs per boe have increased due to decreased capital recoveries
as a result of reduced capital expenditures. The Company expects general and
administrative expenses to average between $1.00 and $1.15 per boe for the year.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, September 30, September 30, September 30, September 30,
except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Interest expense 1,846 1,605 4,500 5,115
Average debt level 169,837 139,090 206,910 119,495
Effective interest rate 4.4% 4.6% 2.9% 5.7%
Per boe 1.54 1.52 1.19 1.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the first nine months of 2009 compared to the same period in 2008, decreased
effective interest rates were the result of lower prime interest rates and
interest rates on banker's acceptances. In the third quarter of 2009 compared
with the same period in 2008, lower prime interest rates and interest rates on
banker's acceptances have been partially offset by increased lending margins
charged on the Company's bank facility.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Gross costs 1,635 1,914 5,056 5,486
Capitalized costs (817) (957) (2,528) (2,743)
----------------------------------------------------------------------------
Total stock-based
compensation 818 957 2,528 2,743
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has decreased in the third
quarter of 2009 and the first nine months of 2009 as compared with the same
periods in 2008 due to a lower share price resulting in a decrease in the fair
value of the stock options issued.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
($ thousands, September 30, September 30, September 30, September 30,
except per boe) 2009 2008 2009 2008
----------------------------------------------------------------------------
Depletion,
depreciation and
accretion 32,142 26,247 99,936 69,537
Per boe 26.74 24.80 26.44 24.11
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per unit depletion has increased in the third quarter and first nine months of
2009 due to increased depletion associated with the addition of the fair market
value of the Gentry assets at the acquisition date in August 2008, which was
higher than historic Company carrying values for proved reserves.
Future Income Taxes
The provision for future income taxes was a recovery of $2.9 million in the
third quarter of 2009 compared to an expense of $5.5 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 nine months of 2009, the Company had a future tax recovery of
$13.5 million as compared with a future tax expense of $6.8 million for the same
period of 2008. The recovery was a result of a pre-tax loss in 2009 and a
corporate rate reduction in British Columbia from 11 percent to 10.5 percent in
2010 and a further reduction to 10 percent in 2011.
Cash and Funds from Operations and Net Income (Loss)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
($ thousands, ended ended ended ended
except per September 30, September 30, September 30, September 30,
share amounts) 2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by
operating activities 24,902 36,208 65,925 97,656
Funds from operations 19,640 35,004 56,197 98,144
Per share - basic 0.25 0.54 0.76 1.68
- diluted 0.25 0.54 0.76 1.66
Net income (loss) (7,376) 15,178 (28,661) 21,534
Per share - basic (0.09) 0.24 (0.39) 0.37
- diluted (0.09) 0.23 (0.39) 0.36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the third quarter and first nine months of 2009, a 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. For the third quarter and first nine months of
2009, a net loss resulted from the decreased commodity prices and higher
operating and depletion costs partially offset by a net gain on financial
instruments.
Capital Expenditures, Acquisitions and Dispositions
During the third quarter of 2009, the Company drilled 12 (12.0 net) wells
resulting in nine (9.0 net) oil wells, two (2.0 net) gas wells and one (1.0 net)
water disposal well. In addition, the Company also completed eight (8.0 net)
wells and recompleted four (4.0 net) wells in the Princess area. In the third
quarter of 2009, Crew added to its infrastructure, constructing its gas plant at
Septimus, British Columbia and pipeline connecting five wells to the facility.
The Company has an agreement in place to sell the Septimus gas plant for
approximately $19 million in the fourth quarter of 2009. In the third quarter,
in Princess, Alberta, Crew added to its infrastructure, equipping and pipeline
connecting six wells and upgrading fluid handling capacity at the West Tide Lake
battery.
Total exploration and development capital expenditures for the third quarter and
first nine months of 2009 were $35.4 and $73.3 million, respectively compared to
$66.4 and $138.1 million for the same periods in 2008. The expenditures are
detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months Nine months Nine months
ended ended ended ended
September 30, September 30, September 30, September 30,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Land 1,013 4,104 4,881 24,169
Seismic 81 1,339 2,176 2,816
Drilling and
completions 17,767 52,966 28,167 89,611
Facilities, equipment
and pipelines 15,040 7,475 33,384 18,860
Other 1,489 515 4,647 2,609
----------------------------------------------------------------------------
Exploration and
development 35,390 66,399 73,255 138,065
Property acquisitions
(dispositions) - (1,097) (34,378) 70,659
----------------------------------------------------------------------------
Total net 35,390 65,302 38,877 208,724
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 2009, budgeted net capital expenditures for 2009 are
estimated at between $40 and $50 million. This amount includes the impact of all
planned property dispositions and the Company's negotiated sale of the Septimus
natural gas facility for estimated proceeds of $19 million.
Liquidity and Capital Resources
Capital Funding
The Company has a credit facility with a syndicate of banks (the "Syndicate")
that includes a revolving line of credit of $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 thereunder will
increase by 0.50 percent and all outstanding balances under the Facility will
become repayable in one year. The available lending limits of the Facility are
reviewed semi-annually and are based on the Syndicate's interpretation of the
Company's reserves and future commodity prices. There can be no assurance that
the amount of the available Facility will not be adjusted at the next scheduled
review which is expected to be completed in November 2009. At September 30,
2009, the Company had committed drawings of $166.8 million on the Facility and
had issued letters of credit totaling $5.4 million of which $5.0 million expires
by November 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, the proceeds from future asset dispositions and equity
financings as needed. As the majority of our on-going capital expenditure
program is directed to the further growth of reserves and production volumes,
Crew is readily able to adjust its budgeted capital expenditures should the need
arise.
Working Capital
The capital intensive nature of Crew's activities generally results in the
Company carrying a working capital deficit. However, the Company maintains
sufficient unused bank credit lines to satisfy such working capital
deficiencies. At September 30, 2009, the Company's working capital deficiency
(including accounts receivable, accounts payable and accrued liabilities)
totaled $31.8 million which, when combined with the drawings on its bank line,
represented 75% of its current bank facility.
Share Capital
As at November 9, 2009, Crew had 78,086,668 Common Shares and 5,818,200 options
to acquire Common Shares of the Company issued and outstanding.
Capital Structure
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes adjustments
on an on-going basis in order to maintain the flexibility needed to achieve the
Company's long-term objectives. To manage the capital structure the Company may
adjust capital spending, hedge future revenue and costs, issue new equity, issue
new debt or repay existing debt through asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1. This ratio may increase at certain times as a result of acquisitions or low
commodity prices. As shown below, as at September 30, 2009, the Company's ratio
of net debt to annualized funds from operations was 2.53 to 1 (December 31, 2008
- 2.15 to 1). This amount has risen above the preferred range of the Company as
a result of the decrease in commodity prices experienced over the past nine
months.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30,
($ thousands, except ratio) 2009
----------------------------------------------------------------------------
Net debt 198,613
Third quarter funds from operations 19,640
Annualized funds from operations 78,560
Net debt to annualized funds from operations ratio 2.53
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In order to restore the Company's financial flexibility, Crew will execute a
conservative capital spending program in 2009, currently estimated at $40 to $50
million, net of dispositions. 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. In 2009, the
Company has disposed of non-core properties for net proceeds of $34.2 million
and has agreements to sell an additional 600 boe per day of non-core production
in central Alberta for proceeds of approximately $25 million. These non-core
dispositions as well as the sale of the Septimus facility for approximately $19
million are scheduled to close in the fourth quarter of 2009. The Company may
also consider the sale of additional non-core assets and will consider other
forms of financing to improve the Company's financial position if cash flow does
not adequately fund the capital programs planned to achieve the Company's long
term growth objectives.
Contractual Obligations
Throughout the course of its ongoing business, the Company enters into various
contractual obligations such as credit agreements, purchases of services,
royalty agreements, operating agreements, processing agreements, right of way
agreements and lease obligations for office space and automotive equipment. All
such contractual obligations reflect market conditions prevailing at the time of
the contract and none are with related parties. The Company believes it has
adequate sources of capital to fund all contractual obligations as they come
due. The following table lists the Company's obligations with a fixed term.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Total 2009 2010 2011
----------------------------------------------------------------------------
Bank Loan (note 1) 166,768 - - 166,768
Operating Leases 1,980 248 990 742
Capital commitments 7,700 2,700 5,000 -
Firm transportation agreements
(note 2) 15,844 1,867 7,339 6,638
----------------------------------------------------------------------------
Total 192,292 4,815 13,329 174,148
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
The success of the Company's third quarter capital program has created
operational momentum that we plan to build upon. The third quarter success
combined with the financial flexibility provided by the sale of $59 million of
non-core assets and $19 million for the Septimus gas plant will allow the
Company to increase its planned fourth quarter 2009 capital expenditures. As
such, the Company now plans to spend between $45 and $55 million on exploration
and development opportunities in the fourth quarter resulting in capital
expenditures for the year totaling between $40 and $50 million, net of
dispositions. The increased capital program combined with the dispositions are
expected to result in net debt at year end of $180 to $190 million or
approximately two times forecasted annualized fourth quarter funds from
operations.
This increased spending is forecasted to fully replace the 1,270 boe per day of
production sold through the non-core asset dispositions, replace the 400 boe per
of uneconomic natural gas production that will remain shut-in through year-end
and replace the Company's natural production declines. The increased spending
has resulted in the Company increasing its full year production guidance to
range between 13,800 to 14,000 boe per day and its forecasted exit rate to be
15,000 boe per day as represented by average forecasted December production.
Additional Disclosures
Quarterly Analysis
The following table summarizes Crew's key quarterly financial results for
the past eight financial quarters:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands,
except per Sept. June Mar. Dec. Sept. June Mar. Dec.
share 30 30 31 31 30 30 31 31
amounts) 2009 2009 2009 2008 2008 2008 2008 2007
----------------------------------------------------------------------------
Total daily
production
(boe/d) 13,065 13,466 15,022 14,869 11,505 9,445 10,614 9,641
Average
wellhead
price
($/boe) 32.04 32.10 34.28 42.99 61.74 70.18 53.20 43.90
Petroleum
and natural
gas sales 38,510 39,331 46,342 58,806 65,345 60,316 51,389 38,942
Cash provided
by
operations 24,902 21,517 19,506 25,700 36,208 31,908 29,540 11,882
Funds from
operations 19,640 20,036 16,521 29,646 35,004 34,102 29,038 22,390
Per share
- basic 0.25 0.27 0.23 0.42 0.54 0.60 0.54 0.43
- diluted 0.25 0.27 0.23 0.42 0.54 0.58 0.54 0.43
Net income
(loss) (7,376)(12,267) (9,018)(74,853) 15,178 5,415 941 6,889
Per share
- basic (0.10) (0.17) (0.13) (1.05) 0.24 0.09 0.02 0.13
- diluted (0.10) (0.17) (0.13) (1.05) 0.23 0.09 0.02 0.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 fourth quarter of 2008 to the third quarter of 2009, revenue, cash
provided by operations, funds from operations and net income have been
negatively impacted by a significant decrease in oil and natural gas prices.
- Production in the second quarters of 2008 and 2009 were impacted by 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.
- In the first half of 2009, the Company sold non-core assets with average
production of approximately 670 boe per day.
- 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.
- 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 recorded.
- During 2008 and the first nine months of 2009, the Company has 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 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 effects 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 throughout 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 at this time.
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 controls over financial reporting
that occurred during the quarter ended on September 30, 2009 that has materially
affected, or is reasonably likely to materially affect, the Company's internal
controls over financial reporting. No material changes in the Company's design
of internal controls over financial reporting were identified during such period
that have materially affected, or are reasonably likely to materially affect,
the Company's internal controls over financial reporting.
It should be noted that a control system, including the Company's disclosure and
internal controls and procedures, no matter how well conceived, can provide only
reasonable, but not absolute, assurance that the objectives of the control
system will be met and it should not be expected that the disclosure and
internal controls and procedures will prevent all errors or fraud.
Dated as of November 9, 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 foregoing, this news release contains forward-looking information
and statements pertaining to the following: the volume and product mix of Crew's
oil and gas production; 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.
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
Crew is an oil and gas exploration and production company whose shares are
traded on The Toronto Stock Exchange under the trading symbol "CR".
Financial statements for the three and nine month periods ended September 30,
2009 and 2008 are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 27,756 $ 42,800
Fair value of financial instruments
(note 7) 5,391 1,255
Future income taxes - 15
----------------------------------------------------------------------------
33,147 44,070
Property, plant and equipment (note 2) 945,311 1,001,440
----------------------------------------------------------------------------
$ 978,458 $ 1,045,510
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 59,601 $ 74,622
Future income taxes 1,029 -
Current portion of other long-term
obligations (note 4) 1,313 1,313
----------------------------------------------------------------------------
61,943 75,935
Bank loan (note 3) 166,768 223,628
Other long-term obligations (note 4) 461 1,446
Asset retirement obligations (note 5) 36,011 34,941
Future income taxes 101,966 116,292
Shareholders' Equity
Share capital (note 6) 616,850 575,191
Contributed surplus (note 6(c)) 21,399 16,356
Retained earnings (deficit) (26,940) 1,721
----------------------------------------------------------------------------
611,309 593,268
Commitments (note 10)
----------------------------------------------------------------------------
$ 978,458 $ 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 Nine Nine
months months months months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue
Petroleum and natural
gas sales $ 38,510 $ 65,345 $ 124,183 $ 177,050
Royalties (6,668) (14,157) (22,860) (37,926)
Realized gain (loss) on
financial instruments
(note 7) 7,794 (991) 13,990 (3,321)
Unrealized gain on
financial instruments
(note 7) 3,082 12,903 4,136 2,477
Other income - - - 268
----------------------------------------------------------------------------
42,718 63,100 119,449 138,548
Expenses
Operating 14,000 10,363 42,258 23,568
Transportation 2,830 2,325 8,095 6,317
Interest 1,846 1,605 4,500 5,115
General and administrative 1,320 900 4,263 2,927
Stock-based compensation
(note 6(d)) 818 957 2,528 2,743
Depletion, depreciation
and accretion 32,142 26,247 99,936 69,537
----------------------------------------------------------------------------
52,956 42,397 161,580 110,207
----------------------------------------------------------------------------
Income (loss) before
income taxes (10,238) 20,703 (42,131) 28,341
Future income tax
expense (reduction) (2,862) 5,525 (13,470) 6,807
----------------------------------------------------------------------------
Net income (loss) and
comprehensive income
(loss) (7,376) 15,178 (28,661) 21,534
Retained earnings
(deficit), beginning of
period (19,564) 61,396 1,721 55,040
----------------------------------------------------------------------------
Retained earnings
(deficit), end of period $ (26,940) $ 76,574 $ (26,940) $ 76,574
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per
share (note 6(e))
Basic $ (0.09) $ 0.24 $ (0.39) $ 0.37
Diluted $ (0.09) $ 0.23 $ (0.39) $ 0.36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Cash Flows
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept. 30, Sept. 30, Sept. 30, Sept. 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Net income (loss) $ (7,376) $ 15,178 $ (28,661) $ 21,534
Items not involving
cash:
Depletion, depreciation
and accretion 32,142 26,247 99,936 69,537
Stock-based compensation 818 957 2,528 2,743
Future income tax
expense (reduction) (2,862) 5,525 (13,470) 6,807
Unrealized gain on
financial instruments (3,082) (12,903) (4,136) (2,477)
Transportation liability
charge (note 4) (328) (328) (985) (985)
Asset retirement
expenditures (196) 8 (478) (623)
Change in non-cash
working capital (note 9) 5,786 1,524 11,191 1,120
----------------------------------------------------------------------------
24,902 36,208 65,925 97,656
Financing activities:
Increase (decrease) in
bank loan (8,160) (8,502) (56,860) 15,818
Issue of common shares 22 84 43,422 69,846
Share issue costs (3) (133) (2,442) (3,654)
----------------------------------------------------------------------------
(8,141) (8,551) (15,880) 82,010
Investing activities:
Exploration and
development (35,390) (66,399) (73,255) (138,065)
Property acquisitions - 1,097 - (70,659)
Property dispositions - - 34,378 -
Business acquisitions - (1,500) - (1,500)
Change in non-cash
working capital (note 9) 18,629 39,145 (11,168) 30,558
----------------------------------------------------------------------------
(16,761) (27,657) (50,045) (179,666)
----------------------------------------------------------------------------
Change in cash and cash
equivalents - - - -
Cash and cash
equivalents, beginning of
period - - - -
----------------------------------------------------------------------------
Cash and cash
equivalents, end of
period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Notes to Consolidated Financial Statements
For the three and nine months ended September 30, 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
September 30, 2009 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $1,291,590 $ 346,279 $ 945,311
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 September 30, 2009 of $159,751,000 (2008 -
$172,835,000) was excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $93,818,000 (2008 - $31,692,000) have been included in the depletion
calculation and estimated salvage values of $38,851,000 (2008 - $36,731,000)
have been excluded from the depletion calculation.
The following corporate expenses related to exploration and development
activities were capitalized.
Nine months ended Year ended
Sept. 30, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
General and administrative expense $ 4,263 $ 4,169
Stock-based compensation expense, including
future income taxes 3,382 4,485
----------------------------------------------------------------------------
$ 7,645 $ 8,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. Bank loan:
The Company's bank facility 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 thereunder 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 which is expected to be completed
in November 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 September 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
September 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 September 30, 2009 was 4.4% (2008 - 5.4%).
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
nine months ended September 30, 2009 was $0.3 million and $1.0 million,
respectively (September 30, 2008 - $0.3 million and $1.0 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 September 30, 2009 to be $36,011,000 (December 31,
2008 - $34,941,000) based on a total future liability of $66,726,000 (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:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Nine months ended Year ended
September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Carrying amount, beginning of period $ 34,941 $ 18,668
Liabilities incurred 174 1,228
Liabilities acquired (disposed) (702) 13,927
Accretion expense 2,076 1,893
Liabilities settled (478) (775)
----------------------------------------------------------------------------
Carrying amount, end of period $ 36,011 $ 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 $666 - (1,776)
Exercise of options 3 35
----------------------------------------------------------------------------
Common shares, September 30, 2009 78,087 $ 616,850
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 5,056
Conversion of stock options (13)
----------------------------------------------------------------------------
Contributed surplus, September 30, 2009 $ 21,399
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(d) Stock-based compensation:
The Company measures compensation costs associated with stock-based compensation
using the fair market value method under which the cost is recognized over the
vesting period of the underlying security. The fair value of each stock option
is determined at each grant date using the Black-Scholes model with the
following weighted average assumptions used for options granted during the three
month period ended September 30, 2009: risk free interest rate 2.16% (2008 -
4.09%), expected life 4 years (2008 - 4 years), volatility 60% (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 nine months of 2009, the Company recorded $5,056,000, (2008 -
$5,486,000) of stock-based compensation expense related to the stock options, of
which $2,528,000 (2008 - $2,743,000) 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
$854,000 (2008 - $950,000) associated with the current year's capitalized
stock-based compensation has been recorded.
Stock options
The weighted average fair value of the stock options granted during the nine
months ended September 30, 2009, as calculated by the Black-Scholes method, was
$2.04 per option (2008 - $3.66).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Number of Price average
Options Range exercise price
----------------------------------------------------------------------------
Balance December 31, 2008 4,276 $ 3.50 to $18.70 $ 9.76
Granted 1,670 $ 2.78 to $5.30 $ 4.89
Exercised (3) 7.23 $ 7.23
Forfeited (173) $ 5.30 to $14.77 $ 11.11
----------------------------------------------------------------------------
Balance September 30, 2009 5,770 $ 2.78 to $18.70 $ 8.31
Exercisable 1,911 $ 7.23 to $18.70 $ 9.92
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(e) Per share amounts:
Per share amounts have been calculated on the weighted average number of shares
outstanding. The weighted average shares outstanding for the three month period
ended September 30, 2009 was 78,084,000 (September 30, 2008 - 64,254,000) and
for the nine month period ended September 30, 2009 the weighted average number
of shares outstanding was 74,289,000 (September 30, 2008 - 58,369,000).
In computing diluted per share amounts for the three month period ended
September 30, 2009, no (September 30, 2008 - 737,000) shares were added to the
weighted average number of Common Shares outstanding for the dilution added by
the stock options and for the nine month period ended September 30, 2009, no
(September 30, 2008 - 787,000) shares were added to the weighted average number
of common shares for the dilution. There were 5,770,000 (September 30, 2008 -
289,500) 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 September 30, 2009 the
Company's receivables consisted of $12.8 (2008 - $18.4) million of receivables
from petroleum and natural gas marketers of which the majority has subsequently
been collected, $9.6 (2008 - $12.4) million from joint venture partners of which
$2.1 million has subsequently been collected, and $5.4 (2008 - $12.0) million of
Crown deposits, prepaids and other accounts receivable. The Company does not
have an allowance for doubtful accounts as at September 30, 2009 and did not
provide for any doubtful accounts nor was it required to write-off any
receivables during the nine month period ended September 30, 2009.
(b) Liquidity risk:
Accounts payable and financial instruments have contractual maturities of less
than two years. The Company maintains a revolving credit facility, as outlined
in note 3, which 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 nine months ended September 30, 2009, a 1.0 percent change to the
effective interest rate would have a $0.3 million and $1.1 million impact on net
income, respectively (2008 - $0.3 and $0.7 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 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 September 30, 2009 are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Realized
Subject Gain Fair
of Notional Strike Option (Loss) Value
Contract Quantity Term Reference Price Traded($000s)($000s)
----------------------------------------------------------------------------
Commodity contracts
AECO C
Natural Gas 2,500 January 1, 2009 - Monthly $ 6.60-
gj/day December 31, 2009 Index $ 8.50 Collar 1,855 520
AECO C
Natural Gas 2,500 January 1, 2009 - Monthly $ 6.50-
gj/day December 31, 2009 Index $ 8.30 Collar 2,079 230
less $0.09
Natural Gas 15,000 April 1, 2009 - AECO C
gj/day October 31, 2009 Monthly $ 6.00 Put 7,781 1,451
Index
Natural Gas 2,500 November 1, 2009 - AECO C
gj/day December 31, 2010 Monthly $ 6.00 Swap - 361
Index
Natural Gas 5,000 January 1, 2010 - AECO C
gj/day December 31, 2010 Monthly $ 8.00 Call - (278)
Index
Natural Gas 10,000 January 1, 2010 - AECO C
gj/day December 31, 2010 Monthly $ 7.75 Call - (821)
Index
Natural Gas 2,500 January 1, 2010 - AECO C
gj/day December 31, 2010 Monthly $ 6.20 Swap - 425
Index
Natural Gas 5,000 January 1, 2010 - AECO C
gj/day December 31, 2010 Monthly $ 6.08 Swap - 617
Index
Oil 500 July 1, 2009 - CDN$ WTI $81.70 Swap 314 357
bbl/day December 31, 2009
Oil 500 July 1, 2009 - CDN$ WTI $72.00 Swap (133) (188)
bbl/day December 31, 2009
Oil 250 July 1, 2009 - CDN$ WTI $80.50 Swap 129 141
bbl/day December 31, 2009
Oil 250 January 1, 2010 - CDN$ WTI $78.50 Swap - (106)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - CDN$ WTI $72.00- Collar - 16
bbl/day December 31, 2010 $88.00
Oil 250 January 1, 2010 - CDN$ WTI $82.50 Swap - 258
bbl/day December 31, 2010
Oil 500 January 1, 2010 - CDN$ WTI $82.50 Swap - 152
bbl/day December 31, 2010
----------------------------------------------------------------------------
Total commodity contracts 12,025 3,135
----------------------------------------------------------------------------
Foreign exchange contracts
USD/ US $2M/ February 1, 2009 -
CAD $ Month December 31, 2009 CAD/USD 1.22 Swap 913 895
exchange
USD/ US $2M/ February 1, 2009 -
CAD $ Month December 31, 2009 CAD/USD 1.26 Swap 1,554 1,136
exchange
USD/ US $2M/ January 1, 2010 -
CAD $ Month December 31, 2010 CAD/USD 1.094 Swap - 554
exchange
----------------------------------------------------------------------------
Total foreign exchange contracts 2,467 2,585
----------------------------------------------------------------------------
Interest rate contracts
$50M/ February 10, 2009 - BA - 1.10% Swap (190) (185)
BA Rate year February 10, 2011 CDOR
$50M/ February 12, 2009 - BA - 1.10% Swap (190) (138)
BA Rate year February 12, 2011 CDOR
$50M/ May 28, 2009 - BA - 1.12% Swap (122) (6)
BA Rate year May 28, 2011 CDOR
----------------------------------------------------------------------------
Total interest rate contracts (502) (329)
----------------------------------------------------------------------------
Total financial instruments 13,990 5,391
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at September 30, 2009, a $0.10 change to the price per thousand cubic feet of
natural gas on the natural gas contracts outlined above would have a $0.05
million impact on net income.
As at September 30, 2009, a $1.00 per barrel change to the price on the oil
contracts outlined above would have a $0.4 million impact on net income.
As at September 30, 2009, a $0.01 change to the exchange rate on the foreign
exchange contracts outlined above would have a $0.3 million impact on net
income.
As at September 30, 2009, a 0.1% change to the interest rate on the interest
rate contracts outlined above would have a $0.2 million impact on net income.
Subsequent to September 30, 2009, the Company entered into the following
financial derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional Option
Contract Quantity Term Reference Strike Price Traded
----------------------------------------------------------------------------
5,000 January 1, 2010 - AECO/NYMEX
Gas mmbtu/d December 31, 2010 Basis diff - US$ ($0.55) Swap
$0.55/mmbtu
500 January 1, 2010 -
Oil bbl/day December 31, 2010 US$ WTI $81.00 Swap
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair value of financial instruments
The Company's financial instruments as at September 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 September 30, 2009, the Company's ratio of net debt to annualized
funds from operations was 2.53 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.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
September 30, December 31,
2009 2008
----------------------------------------------------------------------------
Net debt:
Accounts receivable $ 27,756 $ 42,800
Accounts payable and accrued liabilities (59,601) (74,622)
----------------------------------------------------------------------------
Working capital deficiency $ (31,845) $ (31,822)
Bank loan (166,768) (223,628)
----------------------------------------------------------------------------
Net debt $ (198,613) $ (255,450)
Annualized funds from operations:
Cash provided by operating activities $ 24,902 $ 25,700
Asset retirement expenditures 196 152
Transportation liability charge 328 328
Change in non-cash working capital (5,786) 3,466
----------------------------------------------------------------------------
Funds from operations 19,640 29,646
Annualized $ 78,560 $ 118,584
Net debt to annualized funds from operations 2.53 2.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In order to restore the Company's financial flexibility Crew will execute a
conservative capital spending program in 2009 currently estimated at $40 to $50
million, net of dispositions. 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 2009, the Company has disposed of non-core
properties for net proceeds of $34.2 million and has agreements to sell an
additional 600 boe per day of non-core production in central Alberta for
proceeds of approximately $25 million. These non-core dispositions as well as
the sale of the Septimus facility for approximately $19 million are scheduled to
close in the fourth quarter of 2009. 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 September 30, 2009.
9. Supplemental cash flow information:
Three Three Nine Nine
months months months months
ended ended ended ended
Sept. Sept. Sept. Sept.
30, 30, 30, 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Changes in non-cash working
capital:
Accounts receivable $ 762 $ 8,568 $ 15,044 $ 2,388
Accounts payable and accrued
liabilities 23,653 32,101 (15,021) 29,290
----------------------------------------------------------------------------
$ 24,415 $ 40,669 $ 23 $ 31,678
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities $ 5,786 $ 1,524 $ 11,191 $ 1,120
Investing activities 18,629 39,145 (11,168) 30,558
----------------------------------------------------------------------------
$ 24,415 $ 40,669 $ 23 $ 31,678
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company made the following cash outlays in respect of interest expense:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Nine Nine
months months months months
ended ended ended ended
Sept. Sept. Sept. Sept.
30, 30, 30, 30,
2009 2008 2009 2008
----------------------------------------------------------------------------
Interest $ 1,662 $ 1,748 $ 5,850 $ 4,599
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. Commitments:
The Company has the following fixed term commitments related to its on-going
business:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 2009 2010 2011
----------------------------------------------------------------------------
Operating Leases $ 1,980 $ 248 $ 990 $ 742
Capital commitments 7,700 2,700 5,000 -
Firm transportation agreements 15,844 1,867 7,339 6,638
----------------------------------------------------------------------------
Total $ 25,524 $ 4,815 $ 13,329 $ 7,380
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
Crew Energy (TSX:CR)
Historical Stock Chart
From May 2024 to Jun 2024
Crew Energy (TSX:CR)
Historical Stock Chart
From Jun 2023 to Jun 2024
