Crew Energy Inc. (TSX:CR) of Calgary, Alberta is pleased to present its
operating and financial results for the three month period ended March 31, 2010.
Highlights
- First quarter funds from operations of $28.2 million represents a 71% increase
over the first quarter of 2009;
- Funds from operations per share increased 52% to $0.36 per share over the
first quarter of 2009;
- On April 1, 2010, Crew closed a strategic farmout and property disposition
reducing corporate debt by $123.3 million to $68.6 million;
- Production averaged 15,001 boe per day in the quarter compared to 14,470 boe
in the fourth quarter of 2009 after the sale of 600 boe per day of production in
the fourth quarter of 2009;
- Drilled and completed two Septimus, British Columbia liquids rich natural gas
wells with test rates after five days of six mmcf per day (1,040 boe per day)
and 4.8 mmcf per day (830 boe per day) and drilled and completed two wells at
Princess, Alberta with initial production rates of 755 boe per day and 508 boe
per day;
- Crew expanded its land base at Princess, Alberta to 454 sections of land
during the quarter and subsequent to the quarter end has added an additional 44
net sections with over 110 identified drilling locations to bring the total
number of drilling locations in the area to in excess of 600 firm drilling
locations.
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Three months Three months
Financial ended ended
($ thousands, except per share amounts) Mar. 31, 2010 Mar. 31, 2009
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Petroleum and natural gas sales 61,772 46,342
Funds from operations (note 1) 28,217 16,521
Per share - basic 0.36 0.23
- diluted 0.35 0.23
Net income (loss) 2,442 (9,018)
Per share - basic 0.03 (0.13)
- diluted 0.03 (0.13)
Exploration and development investment 59,075 23,678
Property acquisitions (net of dispositions) (10,916) (10,690)
Net capital expenditures 48,159 12,988
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Capital Structure As at As at
($ thousands) Mar. 31, 2010 Dec. 31, 2009
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Working capital deficiency (note 2) 38,263 46,654
Bank loan 153,601 135,601
Net debt 191,864 182,255
Net property disposition proceeds (closed
April 1, 2010) (note 3) (123,268) -
Pro-forma net debt 68,596 182,255
Current bank facility (note 4) 210,000 250,000
Common Shares Outstanding (thousands) 79,421 78,152
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Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital, asset
retirement expenditures and the transportation liability charge. Funds
from operations is used to analyze the Company's operating performance
and leverage. Funds from operations does not have a standardized measure
prescribed by Canadian Generally Accepted Accounting Principles and
therefore may not be comparable with the calculations of similar
measures for other companies.
(2) Working capital deficiency includes only accounts receivable less
accounts payable and accrued liabilities.
(3) On April 1, 2010, Crew closed the disposition of oil and gas assets in
the Edson area of west central Alberta. Details of the disposition can
be found in the Company's March 10, 2010 press release.
(4) Amount as at March 31, 2010 reflects the recently completed annual
review and extension of the Company's credit facility including the
impact of the Edson disposition.
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Three months Three months
ended ended
Operations Mar. 31, 2010 Mar. 31, 2009
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Daily production
Natural gas (mcf/d) 55,732 59,539
Oil (bbl/d) 4,261 3,714
Natural gas liquids (bbl/d) 1,451 1,385
Oil equivalent (boe/d @ 6:1) 15,001 15,022
Average prices (note 1)
Natural gas ($/mcf) 5.38 5.09
Oil ($/bbl) 72.10 43.34
Natural gas liquids ($/bbl) 54.66 36.02
Oil equivalent ($/boe) 45.75 34.28
Operating expenses
Natural gas ($/mcf) 1.75 1.71
Oil ($/bbl) 13.15 10.69
Natural gas liquids ($/bbl) 9.08 8.60
Oil equivalent ($/boe @ 6:1) 11.10 10.21
Netback
Operating netback ($/boe) (note 2) 23.54 14.58
Realized (gains) losses on financial
instruments ($/boe) (0.04) 0.12
G&A ($/boe) 1.24 1.13
Interest and other ($/boe) 1.45 1.10
Funds from operations ($/boe) 20.89 12.23
Drilling Activity
Gross wells 22 7
Working interest wells 20.2 1.8
Success rate, net wells 100% 92%
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Notes:
(1) Average prices are before deduction of transportation costs and do not
include hedging gains and losses.
(2) Operating netback equals petroleum and natural gas sales including
realized hedging gains and losses on commodity contracts less royalties,
operating costs and transportation costs calculated on a boe basis.
Operating netback and funds from operations netback do not have a
standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
Overview
Operations for the first quarter were highlighted by the drilling of 22 (20.2
net) wells with 100% success. The Company drilled 14 (14.0 net) oil wells at
Princess, Alberta, five (3.2 net) natural gas wells in northeast British
Columbia and three (3.0 net) water disposal wells at Princess. Production in the
first quarter was equivalent to the same period in 2009 averaging 15,001 boe per
day as a result of a reduced 2009 capital program and the sale of 1,270 boe per
day of production in 2009. Of the 22 wells drilled in the first quarter, 12
(11.0 net) remain to be placed on production generally as a result of an early
spring break up and persistent wet weather in southern Alberta. Production from
an additional five oil wells drilled in the fourth quarter of 2009 have been
deferred pending future land sales or production infrastructure to accommodate
sour oil and gas volumes. The majority of these wells are expected to be on
production by the end of the second quarter.
As Crew continues to focus its capital expenditures on oil related investments,
the Company's liquids production weighting will continue to increase over the
year. Subsequent to the quarter end, Crew's balance sheet was further
strengthened with the sale of 7.1 million boe of proved plus probable reserves
and 1,700 boe per day of mainly natural gas production for $123.3 million on
April 1, 2010. A portion of the proceeds from this disposition will be directed
to growth initiatives in the Company's two core areas at Septimus, British
Columbia and Princess, Alberta with approximately 70% of the 2010 capital budget
currently planned to be directed toward oil projects.
First quarter commodity prices improved over the same period in 2009. Crew's
wellhead natural gas price averaged $5.38 per mcf which was six percent higher
than the $5.09 per mcf realized in 2009. The Company's oil price was up 66% to
$72.10 per bbl over the $43.34 per bbl price achieved in 2009. Crew's natural
gas liquids price in the first quarter increased 52% to $54.66 per bbl from
$36.02 realized in 2009. The improved commodity prices resulted in a significant
increase in the Company's funds from operations to $28.2 million and $0.35 per
diluted share compared to $16.5 million and $0.23 per share in the same period
of 2009. Increased funds from operations combined with reduced depletion charges
and an unrealized gain on the Company's commodity derivative positions resulted
in the Company recognizing income of $2.4 million for the quarter compared to a
$9.0 million loss in the first quarter of 2009.
Risk Management Activity
Crew has continued to pursue commodity hedges that will protect its capital
program and balance sheet against volatile commodity prices. For 2010, the
Company currently has contracts for an average of 20.6 mmcf per day of natural
gas at an average fixed price of $6.23 per mcf. This represents approximately
41% of the Company's forecasted natural gas production during the second and
third quarters of 2010 during which natural gas prices traditionally reach their
lowest levels. Crew has also established Canadian dollar WTI oil price swaps and
floors on an average of 2,700 bbl per day for 2010. These oil focused financial
commodity transactions represent a minimum floor price of approximately CDN
$80.50 per bbl.
The Company has now begun layering in commodity contracts to secure cash flow
for 2011. To date, natural gas prices for 2011 have not reached levels which the
Company has targeted. However, strong forward oil prices for 2011 have resulted
in the Company entering into Canadian dollar WTI oil price swaps and floors on
an average of 1,750 bbl per day for 2011. These transactions average a minimum
floor price of approximately CDN $86.20 per bbl for WTI oil. A detailed list of
the Company's derivative positions is included in the first quarter management
discussion and analysis.
OPERATIONS UPDATE
Pekisko Play Continues to Expand to 496 Sections
During the first quarter, Crew drilled 14 oil wells and three salt water
disposal wells at Princess. Of the 14 oil wells drilled in the first quarter,
seven were single lateral horizontal wells, three were dual lateral horizontal
wells and four were vertically drilled. Ten of the 14 wells are awaiting
completion or production start-up. A highlight of the first quarter was the 8-2
well achieving a production rate of 750 bbls of oil per day. Crew drilled three
dual lateral horizontal wells in the quarter with initial production rates
averaging 312 boe per day per well. Production from five vertical wells drilled
in the fourth quarter has been deferred pending further land acquisition and the
construction of facilities to accommodate sour oil and gas production from the
southern most area of the Company's operations.
Crew has expanded its land base at Princess to 496 sections. The Company now has
over 600 drilling locations identified on 102 sections of land at Princess.
Continued drilling success will lead to the number of firm locations increasing
over an expanded area. Crew has been very successful with its drilling and
recompletion program resulting in current production capability of over 5,400
boe per day. Average production rates continue to outperform the type curves
with 18 wells having average production rates of 255 boe per day on the 30th day
of production, nine wells having average production rates of 150 boe per day on
the 180th day of production and four wells having average production rates of
120 boe per day on the 270th day of production. Based on Crew's historic
operations, recycle ratios on this play continue to be robust at approximately
three times on freehold land and five times on crown land based on 2009 finding
and development costs and current pricing.
Crew drilled three (3.0 net) horizontal water disposal wells during the quarter.
To date, the Company has drilled four horizontal disposal wells and tested
three of the wells with anticipated disposal rates to average over 10,000 bbls
per day per well with one horizontal disposal well awaiting completion. Once
regulatory approvals of these disposal wells are received, the Company expects
to see a reduction in area operating costs by as much as 25%. Crew plans to
drill an additional five horizontal disposal wells in 2010.
The Company has successfully installed in excess of 30 kilometers of pipeline
liners in the area and has initiated several pipeline projects to handle the
expected increases in fluid volumes from the Company's expanded drilling
program. In the first quarter, Crew initiated a pilot waterflood at Tilley. This
pilot project is based on a central injection well injecting approximately 3,500
bbls of water per day surrounded by four producing wells. Preliminary results of
this secondary recovery scheme are expected within a year. With current primary
recoveries of approximately 13% and waterflood modeling suggesting potential
recovery improvements to as much as 30%, we believe there remains the potential
to more than double existing recoveries at Tilley. In the first quarter, Crew
fracture stimulated two vertical wells with encouraging results. Crew plans to
fracture four vertical wells and one horizontal well in the second quarter. If
successful, fracture stimulation could significantly expand the Company's
prospective acreage at Princess.
Crew recently expanded the 2010 Princess drilling program to 50 wells. With the
addition of 54 net sections of Crown land in the first five months of 2010, the
Company now plans to again expand the drilling program to 60 to 70 wells and
exit 2010 producing over 8,000 boe per day in the area.
Montney Play, Northeast British Columbia
Crew drilled four (3.0 net) gas wells in the Montney formation in the first
quarter of 2010. Two (2.0 net) wells were production tested in the Crew operated
Septimus gas processing facility at 6.0 mmcf per day at a flowing casing
pressure of 1,644 psi and 4.8 mmcf per day at a flowing casing pressure of 1,760
psi after five days of production. Two (1.0 net) additional wells were drilled
with one (0.5 net) well being drilled to complete the earning on a five (2.5
net) section farm-in at Monias, British Columbia and one (0.5 net) well was
drilled at the Company's Portage exploration block, 50 kilometers west of
Septimus. Crew plans to complete both wells immediately following spring
breakup. Once Crew's earning has been completed at Portage, the Company will own
a 50% working interest in 55 sections of land. Crew has a number of tie-in
alternatives that are available to the Company pending successful production
testing of the well at Portage.
With the recent asset disposition in west-central Alberta, Crew announced plans
to expand the Septimus gas processing facility to 50 mmcf per day from its
current capacity of 25 mmcf per day. The expansion is expected to be completed
by year end and, upon equalization with the current owner, Aux Sable Canada
("ASC"), Crew will become a 50% owner and will remain operator of the facility.
ASC expects to complete the installation of a 20 inch pipeline from the Septimus
gas facility to the Alliance pipeline in the third quarter of 2010 which is
expected to be capable of transporting over 350 mmcf per day of gas and
associated liquids.
Economics on this play continue to be robust as a result of the reduced
operating costs and liquids rich gas yield of 24 bbls of ngl per mmcf of natural
gas. The current commodity price strip generates a recycle ratio of
approximately 2.5 times based on Crew's historic operations using 2009 finding,
development and acquisition costs.
Crew now plans on drilling up to ten horizontal Montney wells in northeast
British Columbia in 2010 and expects to exit the year producing over 4,500 boe
per day from the area.
Cardium play, West Central Alberta
In the Edson-Pine Creek, Alberta area, Crew owns 59 net sections of oil prone
Cardium rights. The Company plans to drill two to three Cardium wells at Pine
Creek in 2010 where the Company has identified 80 drilling locations. Crew owns
pipeline infrastructure and an underutilized gas processing facility in the area
to accommodate future production volume growth.
Under the terms of the previously announced Edson Cardium farmout, the third
party has the right to earn a 50% interest in the 32 net sections of Crew's
Cardium rights at Edson and, assuming the land is earned under the farmout
agreement, Crew will own 43.4 net sections of Cardium rights in the greater
Edson-Pine Creek area. The geology and reservoir characteristics of the Cardium
formation in the Pine Creek area are, in the opinion of Management, similar to
areas where horizontal drilling and multi-fracture stimulation completions have
proven successful.
Management Appointment
Crew would like to welcome Mr. Noel Cronin, P. Eng to its management team as
Vice-President, Production and Operations. Mr. Cronin has over 30 years of oil
and gas industry experience and previously held senior management positions at
Endev Energy and Petrofund Energy Trust.
Crew would like to acknowledge the contribution of Mr. Kurtis Fischer to the
Company with the promotion to Vice-President, Acquisitions and Divestitures.
Mr. Fischer has played an integral role in the success of Crew.
OUTLOOK
Natural gas prices continue to be weak as a result of low industrial demand and
increased supply from the aggresive development of unconventional gas reserves.
Conversely, oil prices have been very strong as a result of an increased global
demand for most commodities and renewed confidence in an economic recovery. Crew
is in the enviable position to be able to direct capital investments to either
oil or gas. In the current environment, it is clear that oil is the preferred
commodity for drill bit growth. As such, Crew plans to spend approximately 70%
of its 2010 exploration and development capital budget on oil related
investments.
Increased Capital Program
The success of the Company's oil program at Princess, Alberta has created a
knowledge base and operational momentum that the Company will continue to build
upon. This drilling success combined with the financial flexibility provided by
the $123.3 million sale of the Edson assets has allowed the Company to increase
its 2010 capital budget from $175 million to $225 million. The $50 million
increase will be allocated to further resource capture through land acquisitions
and oil directed drilling. The additional drilling is not expected to materially
change the Company's forecasted exit or average rate as the added wells will be
delineation wells at Princess and are scheduled to be drilled late in the fourth
quarter and many will require tie-in to planned future facilities. The increased
capital program is budgeted to result in net debt at year end of approximately
$135 million or approximately 1.1 times trailing funds from operations. Crew
expects to average between 15,000 to 15,500 boe per day of production for the
year. Exit production is expected to be over 18,000 boe per day with a greater
weighting to liquids.
Crew has transformed itself from a conventional reserve based gas weighted
Company to a resource based Company with scale, mass and repeatability in one
oil and one liquids rich gas play with some of the most attractive economics in
North America. The Company has a very active drilling program planned for the
rest of 2010 and is very well positioned to continue its growth plans for
several years. We look forward to our next update when the Company's second
quarter results are released in August.
Management's Discussion and Analysis
ADVISORIES
Management's discussion and analysis ("MD&A") is the Company's explanation of
its financial performance for the period covered by the financial statements
along with an analysis of the Company's financial position. Comments relate to
and should be read in conjunction with the unaudited interim consolidated
financial statements of the Company for the three month periods ended March 31,
2010 and 2009 and the audited consolidated financial statements and Management
Discussion and Analysis for the year ended December 31, 2009. The consolidated
financial statements have been prepared in accordance with generally accepted
accounting principles ("GAAP") in Canada and all figures provided herein and in
the December 31, 2009 consolidated financial statements are reported in Canadian
dollars.
Forward Looking Statements
This MD&A contains forward-looking statements. Management's assessment of future
plans and operations, drilling plans and the timing thereof, plans for the
tie-in and completion of wells and the timing thereof, capital expenditures,
timing of capital expenditures and methods of financing capital expenditures and
the ability to fund financial liabilities, production estimates, expected
commodity mix and prices and the impact on Crew, future operating costs, future
transportation costs, expected royalty rates, general and administrative
expenses, interest rates, debt levels, funds from operations and the timing of
and impact of adoption of IFRS and other accounting policies may constitute
forward-looking statements under applicable securities laws and necessarily
involve risks including, without limitation, risks associated with oil and gas
exploration, development, exploitation, production, marketing and
transportation, loss of markets, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks, competition
from other producers, inability to retain drilling rigs and other services,
incorrect assessment of the value of acquisitions, failure to realize the
anticipated benefits of acquisitions, the inability to fully realize the
benefits of acquisitions, delays resulting from or inability to obtain required
regulatory 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. Included herein is an estimate of Crew's year-end net debt based on
assumptions as to cash flow, capital spending in 2010 and the other assumptions
utilized in arriving at Crew's 2010 capital budget. To the extent such estimate
constitutes a financial outlook, it was approved by management of Crew on May
10, 2010 and such financial outlook is included herein to provide readers with
an understanding of estimated capital expenditures and the effect thereof on
debt levels and readers are cautioned that the information may not be
appropriate for other purposes. 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 petroleum and natural
gas prices; currency, exchange and interest rates; the regulatory framework
regarding royalties, taxes and environmental matters in the jurisdictions in
which the Company operates; and Crew's ability to successfully market its
petroleum and natural gas products. Readers are cautioned that the foregoing
list of factors is not exhaustive. Additional information on these and other
factors that could affect the Company's operations and financial results are
included in reports on file with Canadian securities regulatory authorities and
may be accessed through the SEDAR website (www.sedar.com) or at the Company's
website (www.crewenergy.com). Furthermore, the forward looking statements
contained in this document are made as at the date of this document and the
Company does not undertake any obligation to update publicly or to revise any of
the included forward looking statements, whether as a result of new information,
future events or otherwise, except as may be required by applicable securities
laws.
Conversions
The oil and gas industry commonly expresses production volumes and reserves on a
"barrel of oil equivalent" basis ("boe") whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved analysis of results and comparisons with other industry participants.
Throughout this MD&A, Crew has used the 6:1 boe measure which is the approximate
energy equivalency of the two commodities at the burner tip. Boe does not
represent a value equivalency at the wellhead nor at the plant gate which is
where Crew sells its production volumes and therefore may be a misleading
measure, particularly if used in isolation.
Non-GAAP Measures
One of the benchmarks Crew uses to evaluate its performance is funds from
operations. Funds from operations is a measure not defined in GAAP that is
commonly used in the oil and gas industry. It represents cash provided by
operating activities before changes in non-cash working capital, asset
retirement expenditures and the transportation liability charge. The Company
considers it a key measure as it demonstrates the ability of the business to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Funds from operations should not be considered as
an alternative to, or more meaningful than cash provided by operating activities
as determined in accordance with GAAP as an indicator of the Company's
performance. Crew's determination of funds from operations may not be comparable
to that reported by other companies. Crew also presents funds from operations
per share whereby per share amounts are calculated using weighted average shares
outstanding consistent with the calculation of income per share. The following
table reconciles Crew's cash provided by operating activities to funds from
operations:
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Three months Three months
ended ended
($ thousands) Mar. 31, 2010 Mar. 31, 2009
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Cash provided by operating activities 32,213 19,506
Asset retirement expenditures 576 101
Transportation liability charge (note 1) 328 328
Change in non-cash working capital (4,900) (3,414)
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Funds from operations 28,217 16,521
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Notes:
(1) The amount for the three months ended March 31, 2010 does not include
the transportation liability write-down of $344,000 as shown in the
transportation costs section.
Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore may not be
comparable with the calculation of similar measures for other entities.
Operating netback equals total petroleum and natural gas sales including
realized gains and losses on commodity contracts less royalties, operating costs
and transportation costs calculated on a boe basis. Management considers
operating netback an important measure to evaluate its operational performance
as it demonstrates its field level profitability relative to current commodity
prices.
RESULTS OF OPERATIONS
Production
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Three months ended Three months ended
March 31, 2010 March 31, 2009
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)
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Alberta 4,138 805 30,881 10,090 3,491 970 40,287 11,175
British
Columbia 123 646 24,851 4,911 223 415 19,252 3,847
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Total 4,261 1,451 55,732 15,001 3,714 1,385 59,539 15,022
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Natural gas production decreased 6% compared to the prior year's first quarter
while oil production increased by 15%. During the latter part of 2009, the
Company disposed of approximately 1,270 boe per day of non-core, predominantly
natural gas producing properties. These dispositions were partially offset by a
successful drilling program that added new natural gas liquids ("ngl") rich
natural gas production in the Septimus, British Columbia area and oil production
at Killam and Princess, Alberta.
Revenue
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Three months Three months
ended ended
Mar. 31, 2010 Mar. 31, 2009
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Revenue ($ thousands)
Natural gas 26,984 27,270
Oil 27,648 14,485
Natural gas liquids 7,140 4,489
Sulphur - 98
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Total 61,772 46,342
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Crew average prices
Natural gas ($/mcf) 5.38 5.09
Oil ($/bbl) 72.10 43.34
Natural gas liquids ($/bbl) 54.66 36.02
Oil equivalent ($/boe) 45.75 34.28
Benchmark pricing
Natural Gas - AECO C daily index (Cdn $/mcf) 5.03 4.99
Oil - Bow River Crude Oil (Cdn $/bbl) 81.99 53.46
Oil and ngl - Cdn$ West Texas Intermediate
(Cdn $/bbl) 81.91 53.69
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Crew's first quarter 2010 revenue increased 33% over the first quarter 2009 due
to a 33% increase in average commodity prices, as volumes remained relatively
consistent.
In the first quarter of 2010, the Company's average natural gas price increased
disproportionately as compared to the Company's benchmark natural gas price due
to additional sales of higher heat content natural gas produced in the Septimus,
British Columbia area. The Company's realized oil price increased 66% while the
Bow River Crude benchmark increased 55% primarily due to higher 2010 Bow River
Oil pricing combined with the Company receiving a similar fixed price quality
differential off of the Bow River price for the Company's oil volumes in the
Princess, Alberta area during both periods. The Company's ngl price increased
52% while the benchmark Cdn$ West Texas Intermediate increased 53%.
Royalties
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Three months Three months
ended ended
($ thousands, except per boe) Mar. 31, 2010 Mar. 31, 2009
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Royalties 13,149 10,680
Per boe $ 9.74 $ 7.90
Percentage of revenue 21.3% 23.0%
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Royalties as a percentage of revenue slightly decreased in the quarter compared
to the same quarter in 2009. In the first quarter of 2009, the Company incurred
a one time charge for additional freehold mineral taxes relating to the assets
acquired in the Gentry acquisition, which closed in August 2008, inflating its
royalties as a percentage of revenue for 2009. Corporately, Crew continues to
forecast an annual royalty rate of 23% to 25% as the Company forecasts an
increase in its oil sales in the Princess area which currently attracts a higher
overall royalty rate as compared to the Company's natural gas assets.
Financial Instruments
Commodities
The Company enters into derivative and physical risk management contracts in
order to reduce volatility in financial results, to protect acquisition
economics and to ensure a certain level of cash flow to fund planned capital
projects. Crew's strategy focuses on the use of puts, costless collars, swaps
and fixed price contracts to limit exposure to fluctuations in commodity prices,
interest rates and foreign exchange rates while allowing for participation in
commodity price increases. The Company's financial derivative trading activities
are conducted pursuant to the Company's Risk Management Policy approved by the
Board of Directors. In 2010, these contracts had the following impact on the
consolidated statement of operations:
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Three months Three months
($ thousands) ended ended
Mar. 31, 2010 Mar. 31, 2009
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Realized gain on financial instruments 928 553
Unrealized gain on financial instruments 8,198 4,870
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As at March 31, 2010, the Company held derivative commodity contracts as
follows:
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Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
Natural 2,500 November 1, 2009 - AECO C $6.00/gj Swap 1,491
Gas gj/day December 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO C $8.00/gj Call (7)
Gas gj/day December 31, 2010 Monthly
Index
Natural 10,000 January 1, 2010 - AECO C $7.75/gj Call (15)
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $6.20/gj Swap 1,631
Gas gj/day December 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO C $6.08/gj Swap 3,284
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $5.25/gj Swap 977
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $5.55/gj Swap 1,185
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 April 1, 2010 - AECO C $5.30/gj Swap 915
Gas gj/day October 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO/NYMEX US$($0.55) Swap (351)
Gas mmbtu/day December 31, 2010 Basis diff
Oil 250 January 1, 2010 - CDN$ WTI $78.50/bbl Swap (543)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - CDN$ WTI $72.00 - Collar (459)
bbl/day December 31, 2010 $88.00/bbl
Oil 250 January 1, 2010 - CDN$ WTI $82.50/bbl Swap (265)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - CDN$ WTI $80.50/bbl Swap (826)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - US$ WTI US$81.00/bbl Swap (557)
bbl/day December 31, 2010
Oil 250 January 1, 2010 - CDN$ WTI $80.00 - Collar 34
bbl/day December 31, 2010 $95.02/bbl
Oil 250 March 1, 2010 - CDN$ WTI $84.00/bbl Swap (157)
bbl/day December 31, 2010
Oil 250 January 1, 2011 - CDN$ WTI $86.00/bbl Swap (194)
bbl/day December 31, 2011
----------------------------------------------------------------------------
Total 6,143
----------------------------------------------------------------------------
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 March 31, 2010, the Company held derivative foreign currency contracts as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
USD / CAD $ US $2M/ January 1, 2010 -
exchange Month December 31, 2010 CAD/USD 1.094 Swap 1,389
----------------------------------------------------------------------------
Total 1,389
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest rate
The Company is exposed to interest rate fluctuations on its bank loan which
bears a floating rate of interest. As shown below, at March 31, 2010, Crew had
contracts in place fixing the rate on $150 million of its bank loan borrowed as
banker's acceptances at rates of 1.10% to 1.12%. The Company pays an additional
stamping fee and margins on bankers' acceptances as outlined in note 3 of the
financial statements.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
BA Rate $50M/year February 10, 2009 -
February 10, 2011 BA - CDOR 1.10% Swap (91)
BA Rate $50M/year February 12, 2009 -
February 12, 2011 BA - CDOR 1.10% Swap (59)
BA Rate $50M/year May 28, 2009 -
May 28, 2011 BA - CDOR 1.12% Swap (18)
----------------------------------------------------------------------------
Total (168)
----------------------------------------------------------------------------
Subsequent to March 31, 2010, the Company entered into the following
financial instrument contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Strike Price Option
Contract Volume Term Reference (per bbl) Traded
----------------------------------------------------------------------------
Oil 250 bbl/day July 1, 2010 -
December 31, 2010 CDN$ WTI $88.10 Swap
Oil 250 bbl/day July 1, 2010 -
December 31, 2010 CDN$ WTI $91.50 Swap
Oil 250 bbl/day January 1, 2011 $90.00 Swap
- December 31, 2011 CDN$ WTI
Oil 500 bbl/day January 1, 2011
- December 31, 2011 CDN$ WTI $90.20 Collar
Oil 250 bbl/day January 1, 2011 $82.00 -
- December 31, 2011 CDN$ WTI $94.62 Collar
Oil 250 bbl/day January 1, 2011 $80.00 -
- December 31, 2011 CDN$ WTI $95.45 Collar
Oil 250 bbl/day January 1, 2011 $85.00 -
- December 31, 2011 CDN$ WTI $100.50 Collar
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
($ thousands, except per boe) Mar. 31, 2010 Mar. 31, 2009
----------------------------------------------------------------------------
Operating costs 14,986 13,810
Per boe $ 11.10 $ 10.21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the first quarter of 2010, the Company's operating costs per unit increased
over the same period in 2009 due to the disposition of lower cost production in
the latter half of 2009 and the additional oil production from the Company's
Princess, Alberta area which currently has high water handling costs causing the
area to have higher operating costs per unit than the Company's natural gas
production. As the Company has identified a number of cost cutting measures
associated with water handling at Princess, the Company continues to forecast
total corporate operating costs to decrease from the current level to average in
a range between $10.00 and $10.50 per boe for 2010.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
($ thousands, except per boe) Mar. 31, 2010 Mar. 31, 2009
----------------------------------------------------------------------------
Transportation costs including liability
write-down 2,377 2,868
Transportation liability write-down 344 -
----------------------------------------------------------------------------
Transportation costs 2,721 2,868
Per boe $2.02 $2.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the first quarter of 2010, the Company's transportation costs per unit
decreased compared to the same period in 2009 due to an increase in oil
production in the Princess, Alberta area which has a lower per unit
transportation cost compared to the Company's natural gas transportation costs.
Additional ngl trucking costs in the Septimus, British Columbia area and
increased unutilized demand charges for transportation and treatment through
northeastern British Columbia pipelines and facilities partially offset the
decrease in total transportation costs.
In March 2010, the Company permanently assigned, at no cost, a portion of the
firm transportation agreements that it had acquired as part of a private company
acquisition completed in May 2007 (see note 4 to the financial statements). As a
result, a portion of the liability totaling $0.3 million that was associated
with the assigned contracts was written off during the quarter as a reduction of
the transportation expense. For the remainder of 2010, Crew's transportation
costs per unit will decrease as the majority of the unutilized demand charges in
northeastern British Columbia have been permanently assigned to third parties.
Crew is now forecasting average transportation costs to range between $1.50 and
$2.00 per boe for 2010.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
March 31, 2010
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 72.10 54.66 5.38 45.75
Realized commodity hedging
gain (loss) (0.05) - 0.18 0.65
Royalties (21.05) (13.51) (0.65) (9.74)
Operating costs (13.15) (9.08) (1.75) (11.10)
Transportation costs (0.94) (1.40) (0.43) (2.02)
----------------------------------------------------------------------------
Operating netbacks 36.91 30.67 2.73 23.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
March 31, 2009
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 43.34 36.02 5.09 34.28
Realized commodity hedging
gain (loss) - - 0.13 0.53
Royalties (10.59) (12.17) (1.25) (7.90)
Operating costs (10.69) (8.60) (1.71) (10.21)
Transportation costs (1.57) (0.01) (0.44) (2.12)
----------------------------------------------------------------------------
Operating netbacks 20.49 15.24 1.82 14.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
($ thousands, except per boe) Mar. 31, 2010 Mar. 31, 2009
----------------------------------------------------------------------------
Gross costs 4,172 3,480
Operator's recoveries (832) (424)
Capitalized costs (1,670) (1,528)
----------------------------------------------------------------------------
General and administrative expenses 1,670 1,528
Per boe $1.24 $1.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increased general and administrative costs before recoveries and capitalization
were mainly the result of increased staff levels, higher salary levels and
increased office rent costs for the Company's expanded office space added in the
first quarter of 2010. Net general and administrative costs per boe increased in
2010 compared to the same period in 2009 due to the additional gross costs being
partially offset by additional capital recoveries from an increased capital
expenditure program in the first quarter of 2010 as compared with the same
period in 2009. The Company expects general and administrative expenses to
average between $1.00 and $1.15 per boe for the year with higher amounts
incurred in the first half of the year due to the payment of annual costs
associated with regulatory filings.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
($ thousands, except per boe) Mar. 31, 2010 Mar. 31, 2009
----------------------------------------------------------------------------
Interest expense 1,957 1,488
Average debt level 135,842 234,298
Effective interest rate 5.8% 2.6%
Per boe $1.45 $1.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In 2010, despite lower average debt levels, higher effective interest rates
increased the Company's interest expense for the period. In June 2009, the
Company's banking syndicate increased margins on its bank facility which
negatively affected Crew's interest expense and effective interest rate. The
Company expects interest rates to be reduced by 0.5% to 0.75% in the second half
of 2010 as a result of newly negotiated margins on the Company's bank facility
and lower overall debt levels.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
($ thousands) Mar. 31, 2010 Mar. 31, 2009
----------------------------------------------------------------------------
Gross costs 2,640 1,758
Capitalized costs (1,320) (879)
----------------------------------------------------------------------------
Total stock-based compensation 1,320 879
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has increased in 2010 compared
with 2009 due to an increase in options outstanding with a higher fair value due
to the Company's increased share price.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
($ thousands, except per boe) Mar. 31, 2010 Mar. 31, 2009
----------------------------------------------------------------------------
Depletion, depreciation and accretion 32,120 34,971
Per boe $23.79 $25.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total depletion, depreciation and accretion costs and costs per unit have
decreased in the first quarter of 2010 due to low cost reserve additions from a
successful drilling program in the Company's Septimus, British Columbia and
Princess, Alberta areas.
Future Income Taxes
In the first quarter of 2010, the provision for future income taxes was an
expense of $1.0 million compared to a recovery of $5.4 million in the first
quarter of 2009. The increase in future taxes was a result of the Company having
pre-tax earnings in 2010 compared to a loss in the first quarter of 2009.
Cash and Funds from Operations and Net Income (loss)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
($ thousands, except per share amounts) Mar. 31, 2010 Mar. 31, 2009
----------------------------------------------------------------------------
Cash provided by operating activities 32,213 19,506
Funds from operations 28,217 16,521
Per share - basic 0.36 0.23
- diluted 0.35 0.23
Net income (loss) 2,442 (9,018)
Per share - basic 0.03 (0.13)
- diluted 0.03 (0.13)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The first quarter 2010 increase in cash provided by operating activities and
funds from operations was the result of increased commodity pricing and an
increase in higher priced oil production. The first quarter 2010 net income
resulted from the higher commodity prices combined with an $8.2 million
unrealized gain on financial instruments and lower depletion, depreciation and
accretion costs.
Capital Expenditures, Acquisitions and Dispositions
During the first quarter, the Company drilled a total of 22 (20.2 net) wells
resulting in five (3.2 net) natural gas wells, 14 (14.0 net) oil wells and three
(3.0 net) service wells. In addition, the Company completed 12 (11.3 net) wells
and recompleted three (3.0 net) wells in the quarter. In the quarter, the
Company continued to add to its inventory of undeveloped land in southern
Alberta spending $7.7 million at Alberta land sales. The Company also closed a
disposition of non-core undeveloped land with no associated production for $10.0
million in central Alberta. On April 1, 2010, the Company closed the disposition
of approximately 1,700 boe per day of production in the Edson, Alberta area for
net proceeds of $123.3 million, before adjustments.
Total net capital expenditures for the quarter are detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended
($ thousands) Mar. 31, 2010 Mar. 31, 2009
----------------------------------------------------------------------------
Land 7,717 3,150
Seismic 4,931 1,773
Drilling and completions 40,329 5,654
Facilities, equipment and pipelines 4,280 11,456
Other 1,818 1,645
----------------------------------------------------------------------------
Total exploration and development 59,075 23,678
Property acquisitions (dispositions) (10,916) (10,690)
----------------------------------------------------------------------------
Total 48,159 12,988
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As a result of the disposition that closed on April 1, 2010, the Company has
increased its budgeted capital expenditure program to $225 million for 2010.
Liquidity and Capital Resources
Capital Funding
The Company has completed the extension of its credit facility with a syndicate
of banks (the "Syndicate") taking into consideration the sale of the Edson
property which closed on April 1, 2010. The credit facility has been amended to
include a revolving line of credit of $190 million and an operating line of
credit of $20 million (the "Facility"). The Facility revolves for a 364 day
period and will be subject to its next 364 day extension by June 13, 2011. If
not extended, the Facility will cease to revolve, the margins thereunder will
increase by 0.50 percent and all outstanding balances under the Facility will
become repayable in one year. The available lending limits of the Facility are
reviewed semi-annually and are based on the Syndicate's interpretation of the
Company's reserves and future commodity prices. There can be no assurance that
the amount of the available Facility will not be adjusted at the next scheduled
borrowing base review on or before October 31, 2010. At March 31, 2010, the
Company had drawings of $153.6 million on the Facility and had issued letters of
credit totaling $2.8 million. On April 1, 2010, following the closing of the
Edson disposition, the Company's drawings on the facility were approximately
$39.5 million.
During the first quarter of 2010, the Company received proceeds of $11.2 million
upon the exercise of 1,269,000 employee stock options.
The Company will continue to fund its on-going operations from a combination of
cash flow, debt, asset dispositions and equity financings as needed. As the
majority of our on-going capital expenditure program is directed to the further
growth of reserves and production volumes, Crew is readily able to adjust its
budgeted capital expenditures should the need arise.
Working Capital
The capital intensive nature of Crew's activities generally results in the
Company carrying a working capital deficit. Working capital deficiency includes
only accounts receivable less accounts payable and accrued liabilities. The
Company maintains sufficient unused bank credit lines to satisfy working capital
deficiencies. At March 31, 2010, the Company's working capital deficiency
totaled $38.3 million which, when combined with the drawings on its bank line,
represented 77% of its bank facility at March 31, 2010. After taking into effect
the proceeds from the Edson disposition which closed on April 1, 2010, the
Company's working capital deficiency was $28.8 million, which when combined with
the drawings on its bank line at that date, represented 33% of its current bank
facility.
Share Capital
As at March 31, 2010, Crew had 79,421,368 Common Shares outstanding along with
6,344,900 options to acquire Common Shares of the Company. As at May 10, 2010,
Crew had 79,924,268 Common Shares and 5,938,000 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
1.0. This ratio may increase at certain times as a result of acquisitions or low
commodity prices. As shown below, as at March 31, 2010, the Company's ratio of
net debt to annualized funds from operations was 1.70 to 1 (December 31, 2009 -
1.67 to 1). Subsequent to the closing of the Edson sale on April 1, 2010, the
pro-forma ratio of net debt to annualized funds from operations was 0.6 to 1.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except ratio) Mar. 31, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
Accounts receivable 39,768 37,574
Accounts payable and accrued liabilities (78,031) (84,228)
----------------------------------------------------------------------------
Working capital deficiency (38,263) (46,654)
Bank loan (153,601) (135,601)
----------------------------------------------------------------------------
Net debt (191,864) (182,255)
Funds from operations 28,217 27,256
Annualized 112,868 109,024
Net debt to annualized funds from operations
ratio 1.70 1.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contractual Obligations
Throughout the course of its ongoing business, the Company enters into various
contractual obligations such as credit agreements, purchase of services, royalty
agreements, operating agreements, processing agreements, right of way agreements
and lease obligations for office space and automotive equipment. All such
contractual obligations reflect market conditions prevailing at the time of
contract and none are with related parties. The Company believes it has adequate
sources of capital to fund all contractual obligations as they come due. The
following table lists the Company's obligations with a fixed term.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Total 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Bank Loan (note 1) 153,601 - - 153,601 - - -
Operating Leases 4,365 1,307 1,743 1,315 - - -
Capital commitments 8,000 4,000 4,000 - - - -
Firm transportation
agreements 5,900 2,835 3,065 - - - -
Firm processing
agreement 29,507 2,065 3,049 3,049 3,049 3,049 15,246
----------------------------------------------------------------------------
Total 201,373 10,207 11,857 157,965 3,049 3,049 15,246
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2012. However, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.
The 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. In 2010, the
Company permanently assigned approximately $6.2 million of its firm
transportation commitments to third parties. The amount shown represents the
remaining contractual obligation.
During 2009, Crew entered into the firm processing agreement to process natural
gas through a third party owned gas processing facility in the Septimus area of
northeast British Columbia. Under the terms of the agreement Crew has committed
to process a minimum monthly volume of gas through the facility commencing on
December 1, 2009 and continuing through November 30, 2019. The commitment is
included in the above table.
The agreement additionally provides Crew the option to participate in an
expansion of the facility at a cost of 50% of the total expanded facility
construction costs and subsequently become a 50% owner in the facility. If the
facility is not expanded prior to January 1, 2013, the current owner of the
facility can require Crew to purchase the existing facility for the total
construction costs of $19.1 million plus $0.7 million or alter the fees
associated with Crew's commitment in order to recover the amount of Crew's full
commitment prior to January 1, 2016.
Guidance
Natural gas prices continue to be weak as a result of low industrial demand and
increased supply from the continued development of unconventional gas reserves.
Oil prices have been very strong as a result of an increased global demand for
most commodities and renewed confidence in an economic recovery. Crew is in the
unique position to be able to direct capital investments to either oil or gas.
In the current environment, it is clear that oil is the preferred commodity for
drill bit growth. As such, Crew plans to spend approximately 70% of its 2010
exploration and development capital budget on oil related investments.
The success of the Company's oil program at Princess, Alberta has created a
knowledge base and operational momentum that the Company intends to build upon.
This drilling success combined with the financial flexibility provided by the
$123.3 million sale of the Edson assets has allowed the Company to increase its
2010 capital budget from $175 million to $225 million. The $50 million increase
will be allocated to further resource capture through land acquisitions and oil
directed drilling. The additional drilling is not expected to materially change
the Company's exit or average rate as these wells are scheduled to be drilled
late in the fourth quarter and many will require tie-in to planned future
facilities. The increased capital program is expected to result in net debt at
year end of approximately $135 million or approximately 1.1 times trailing funds
from operations. Crew expects to average between 15,000 and 15,500 boe per day
of production for the year. Exit production is expected to be over 18,000 boe
per day with a greater weighting to liquids.
Additional Disclosures
Quarterly Analysis
The following table summarizes Crew's key quarterly financial results for
the past eight financial quarters:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per Mar. 31 Dec. 31 Sept. 30 June 30
share amounts) 2010 2009 2009 2009
----------------------------------------------------------------------------
Total daily production (boe/d) 15,001 14,470 13,065 13,466
Average wellhead price ($/boe) 45.75 43.30 32.04 32.10
Petroleum and natural gas sales 61,772 57,646 38,510 39,331
Cash provided by operations 32,213 16,734 24,902 21,517
Funds from operations 28,217 27,256 19,640 20,036
Per share - basic 0.36 0.35 0.25 0.27
- diluted 0.35 0.35 0.25 0.27
Net income (loss) 2,442 (9,154) (7,376) (12,267)
Per share - basic 0.03 (0.12) (0.10) (0.17)
- diluted 0.03 (0.12) (0.10) (0.17)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per Mar. 31 Dec. 31 Sept. 30 June 30
share amounts) 2009 2008 2008 2008
----------------------------------------------------------------------------
Total daily production (boe/d) 15,022 14,869 11,505 9,445
Average wellhead price ($/boe) 34.28 42.99 61.74 70.18
Petroleum and natural gas sales 46,342 58,806 65,345 60,316
Cash provided by operations 19,506 25,700 36,208 31,908
Funds from operations 16,521 29,646 35,004 34,102
Per share - basic 0.23 0.42 0.54 0.60
- diluted 0.23 0.42 0.54 0.58
Net income (loss) (9,018) (74,853) 15,178 5,415
Per share - basic (0.13) (1.05) 0.24 0.09
- diluted (0.13) (1.05) 0.23 0.09
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Significant factors and trends that have impacted the Company's results during
the above periods include:
- Revenue is directly impacted by the Company's ability to replace existing
declining production and add incremental production through its on-going capital
expenditure program.
- Production in the second quarter of 2008 and 2009 was negatively impacted by
scheduled and unscheduled third party facility shutdowns.
- In August 2008, the Company acquired Gentry Resources Ltd. with approximately
4,000 boe per day of production at closing.
- Revenue and royalties are significantly impacted by underlying commodity
prices. The Company utilizes derivative contracts and forward sales contracts to
reduce the exposure to commodity price fluctuations. These contracts can cause
volatility in net income as a result of unrealized gains and losses on commodity
derivative contracts held for risk management purposes.
- Throughout 2008, the Company's operating costs, general and administrative
costs and capital expenditures were subject to inflationary pressures brought on
by increasing 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 required.
- In 2009, the Company sold non-core assets with approximately 1,270 boe per day
of production for $59.6 million. The major dispositions closed as follows:
-- First quarter 2009 - 130 boe per day for $10.7 million
-- Second quarter 2009 - 540 boe per day for $22.5 million
-- Fourth quarter 2009 - 600 boe per day for $25.3 million
- In the fourth quarter of 2009, the Company completed the construction of its
Septimus gas processing facility and subsequently sold it to a third party for
its as built cost of $19.1 million.
New Accounting Pronouncements
International Financial Reporting Standards
Effective January 1, 2011, Canadian public companies are required to adopt
International Financial Reporting Standards ("IFRS") which will include
comparatives for 2010. Crew's financial statements up to and including the
December 31, 2010 financial statements will continue to be reported in
accordance with Canadian GAAP as it exists on each reporting date. Financial
statements for the quarter ended March 31, 2011, including comparative amounts,
will be prepared on an IFRS basis.
In order to transition to IFRS, management has established a project team and
formed an executive steering committee. A transition plan has been developed to
convert the financial statements to IFRS. External advisors have been retained
and will assist management with the project on an as needed basis. Staff
training programs will continue throughout 2010. The Company continues to assess
the effect of the transition on information systems, internal controls over
financial reporting and disclosure controls and procedures. The project team and
steering committee continue to provide updates to senior management and the
Audit Committee. The Company's auditors are involved throughout the process to
ensure the Company's policies are in accordance with the new standards.
Analysis of differences between IFRS and Canadian GAAP is continuing. There are
significant accounting policy changes anticipated on adoption of IFRS which are
described in more detail in the Company's December 31, 2009 MD&A. Management is
continuing to finalize its accounting policies and as such is unable to quantify
the impact on the financial statements at this time. In addition, anticipated
changes to IFRS and International Accounting Standards prior to adoption could
cause changes to certain items based on new facts and circumstances.
In accordance with its plan, Crew has updated its accounting and reporting
systems in the first quarter of 2010. We are currently assessing the impact of
adopting IFRS 1, "First time adoption of IFRS" as it applies to Crew for the
Company's IFRS opening balance sheet with consideration to the specific optional
exemptions as discussed in our December 31, 2009 MD&A.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
The Company's Chief Executive Officer ("CEO") and Chief Financial Officer
("CFO") have designed, or caused to be designed under their supervision,
disclosure controls and procedures to provide reasonable assurance that: (i)
material information relating to the Company is made known to the Company's CEO
and CFO by others, particularly during the period in which the annual and
interim filings are being prepared; and (ii) information required to be
disclosed by the Company in its annual filings, interim filings or other reports
filed or submitted by it under securities legislation is recorded, processed,
summarized and reported within the time period specified in securities
legislation.
Crew's CEO and CFO have designed, or caused to be designed under their
supervision, internal controls over financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with generally
accepted accounting principles. The Company is required to disclose herein any
change in the Company's internal control over financial reporting that occurred
during the period beginning on January 1, 2010 and ended on March 31, 2010 that
has materially affected, or is reasonably likely to materially affect, the
Company's internal control over financial reporting. No material changes in the
Company's internal control over financial reporting were identified during such
period that have materially affected, or are reasonably likely to materially
affect, the Company's internal control over financial reporting.
It should be noted that a control system, including the Company's disclosure and
internal controls and procedures, no matter how well conceived, can provide only
reasonable, but not absolute, assurance that the objectives of the control
system will be met and it should not be expected that the disclosure and
internal controls and procedures will prevent all errors or fraud.
Dated as of May 10, 2010
Cautionary Statements
Forward-looking information and statements
This news release contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of any of the words
"expect", "anticipate", "continue", "estimate", "may", "will", "project",
"should", "believe", "plans", "intends" and similar expressions are intended to
identify forward-looking information or statements. In particular, but without
limiting the foregoing, this news release contains forward-looking information
and statements pertaining to the following: the volume and product mix of Crew's
oil and gas production; production estimates; anticipated disposal rates on
water disposal wells; future oil and natural gas prices and Crew's commodity
risk management programs; future liquidity and financial capacity; future
results from operations and operating metrics; anticipated reductions in
operating costs; future costs, expenses and royalty rates; future interest
costs; the exchange rate between the $US and $Cdn; future development,
exploration, acquisition and development activities and related capital
expenditures and the timing thereof; the number of wells to be drilled,
completed and tied-in and the timing thereof; the amount and timing of capital
projects; the anticipated recoveries from Crew's waterflood program at Tilley;
planned expansion of the Septimus gas processing facility; ASC completion of the
Septimus pipeline and delivery capability thereof; 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. Included herein is an estimate of Crew's year-end net debt based on
assumptions as to cash flow, capital spending in 2010 and the other assumptions
utilized in arriving at Crew's 2010 capital budget. To the extent such estimate
constitutes a financial outlook, it was approved by management of Crew on May
10, 2010 and such financial outlook is included herein to provide readers with
an understanding of estimated capital expenditures and the effect thereof on
debt levels and readers are cautioned that the information may not be
appropriate for other purposes.
The forward-looking information and statements included in this news release are
not guarantees of future performance and should not be unduly relied upon. Such
information and statements, including the assumptions made in respect thereof,
involve known and unknown risks, uncertainties and other factors that may cause
actual results or events to defer materially from those anticipated in such
forward-looking information or statements including, without limitation: changes
in commodity prices; changes in the demand for or supply of Crew's products;
unanticipated operating results or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters; changes in
development plans of Crew or by third party operators of Crew's properties,
increased debt levels or debt service requirements; inaccurate estimation of
Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack
of access to capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors; and certain other risks detailed from
time-to-time in Crew's public disclosure documents (including, without
limitation, those risks identified in this news release and Crew's Annual
Information Form).
The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Crew does not assume any
obligation to publicly update or revise any of the included forward-looking
statements or information, whether as a result of new information, future events
or otherwise, except as may be required by applicable securities laws.
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
Crew is an oil and gas exploration and production company whose shares are
traded on The Toronto Stock Exchange under the trading symbol "CR".
Financial statements for the three month periods ended March 31, 2010 and 2009
are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, December 31,
2010 2009
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 39,768 $ 37,574
Fair value of financial instruments (note 7) 7,364 -
Future income taxes - 542
----------------------------------------------------------------------------
47,132 38,116
Property, plant and equipment (note 2) 943,880 925,132
----------------------------------------------------------------------------
$ 991,012 $ 963,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 78,031 $ 84,228
Fair value of financial instruments (note 7) - 834
Future income taxes 1,740 -
Current portion of other long-term
obligations (note 4) 773 1,313
----------------------------------------------------------------------------
80,544 86,375
Bank loan (note 3) 153,601 135,601
Other long-term obligations (note 4) - 132
Asset retirement obligations (note 5) 35,709 35,341
Future income taxes 100,559 101,519
Shareholders' Equity
Share capital (note 6) 633,348 617,605
Contributed surplus (note 6(c)) 20,903 22,769
Deficit (33,652) (36,094)
----------------------------------------------------------------------------
620,599 604,280
Commitments (note 10)
Subsequent event (note 11)
----------------------------------------------------------------------------
$ 991,012 $ 963,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
months months
ended ended
March 31, March 31,
2010 2009
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales $ 61,772 $ 46,342
Royalties (13,149) (10,680)
Realized gain on financial instruments
(note 7) 928 553
Unrealized gain on financial instruments
(note 7) 8,198 4,870
----------------------------------------------------------------------------
57,749 41,085
Expenses
Operating 14,986 13,810
Transportation (note 4) 2,377 2,868
Interest 1,957 1,488
General and administrative 1,670 1,528
Stock-based compensation (note 6(d)) 1,320 879
Depletion, depreciation and accretion 32,120 34,971
----------------------------------------------------------------------------
54,430 55,544
----------------------------------------------------------------------------
Income (loss) before income taxes 3,319 (14,459)
Future income tax expense (reduction) 877 (5,441)
----------------------------------------------------------------------------
Net income (loss) and comprehensive income
(loss) 2,442 (9,018)
Retained earnings (deficit), beginning of
period (36,094) 1,721
----------------------------------------------------------------------------
Deficit, end of period $ (33,652) $ (7,297)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per share (note 6(e))
Basic $ 0.03 $ (0.13)
Diluted $ 0.03 $ (0.13)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Cash Flows
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months
ended ended
March 31, March 31,
2010 2009
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Net income (loss) $ 2,442 $ (9,018)
Items not involving cash:
Depletion, depreciation and accretion 32,120 34,971
Stock-based compensation 1,320 879
Future income tax expense (reduction) 877 (5,441)
Unrealized gain on financial instruments (8,198) (4,870)
Transportation liability charge (note 4) (672) (328)
Asset retirement expenditures (576) (101)
Change in non-cash working capital (note 9) 4,900 3,414
----------------------------------------------------------------------------
32,213 19,506
Financing activities:
Increase in bank loan 18,000 16,062
Issue of common shares 11,237 -
----------------------------------------------------------------------------
29,237 16,062
Investing activities:
Exploration and development (59,075) (23,678)
Property dispositions 10,916 10,690
Change in non-cash working capital (note 9) (13,291) (22,580)
----------------------------------------------------------------------------
(61,450) (35,568)
----------------------------------------------------------------------------
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 months ended March 31, 2010 and 2009
(Unaudited)
(Tabular amounts in thousands)
1. Significant accounting policies:
The interim consolidated financial statements of Crew Energy Inc. ("Crew" or the
"Company") have been prepared by management in accordance with accounting
principles generally accepted in Canada. The interim consolidated financial
statements have been prepared following the same accounting policies and methods
of computation as the consolidated financial statements for the year ended
December 31, 2009. The disclosure which follows is incremental to the disclosure
included with the December 31, 2009 consolidated financial statements. These
interim consolidated financial statements should be read in conjunction with the
audited consolidated financial statements and notes thereto for the year ended
December 31, 2009.
Certain comparative amounts have been reclassified to conform to current period
presentation.
2. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and Net book
March 31, 2010 Cost depreciation value
Petroleum and natural gas
properties and equipment $ 1,352,557 $ 408,677 $ 943,880
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and Net book
December 31, 2009 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 1,302,399 $ 377,267 $ 925,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The costs of unproved properties at March 31, 2010 of $158,333,000 (2009 -
$168,779,000) was excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $159,174,000 (2009 - $106,968,000) have been included in the
depletion calculation and estimated salvage values of $38,916,000 (2009 -
$38,640,000) have been excluded from the depletion calculation.
The following directly attributable general and administrative and stock-based
compensation expenses related to exploration and development activities were
capitalized:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Year ended
ended December 31,
March 31, 2010 2009
----------------------------------------------------------------------------
General and administrative expense $ 1,670 $ 5,736
Stock-based compensation expense, including
future income taxes 1,765 4,442
----------------------------------------------------------------------------
$ 3,435 $ 10,178
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. Bank loan:
Subsequent to March 31, 2010, the annual renewal of the Company's bank facility
was completed taking into consideration the sale of the Edson property which
closed on April 1, 2010. After completion of the renewal, the facility consists
of a revolving line of credit of $190 million and an operating line of credit of
$20 million (the "Facility"). The Facility revolves for a 364 day period and
will be subject to its next 364 day extension by June 13, 2011. If not extended,
the Facility will cease to revolve, the margins thereunder will increase by 0.50
percent and all outstanding advances thereunder will become repayable in one
year. The available lending limits of the Facility are reviewed semi-annually
and are based on the bank syndicate's interpretation of the Company's reserves
and future commodity prices. There can be no assurance that the amount of the
available Facility will not be adjusted at the next scheduled borrowing base
review on or before October 31, 2010.
Advances under the Facility are available by way of prime rate loans with
interest rates of between 1.25 percent and 2.75 percent over the bank's prime
lending rate and bankers' acceptances and LIBOR loans, which are subject to
stamping fees and margins ranging from 2.25 percent to 3.75 percent depending
upon the debt to EBITDA ratio of the Company calculated at the Company's
previous quarter end. Standby fees are charged on the undrawn facility at rates
ranging from 0.56 percent to 0.94 percent depending upon the debt to EBITDA
ratio.
As at March 31, 2010, the Company's applicable pricing included a 2.50 percent
margin on prime lending and a 3.50 percent stamping fee and margin on bankers'
acceptances and LIBOR loans along with a 0.875 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 March 31,
2010, the Company had issued letters of credit totaling $2.8 million. The
effective interest rate on the Company's borrowings under its bank Facility for
the three months ended March 31, 2010 was 5.8% (2009 - 2.6%).
4. Other long-term obligations:
As part of the May, 2007 private company acquisition, the Company acquired
several firm transportation agreements. These agreements had a fair value at the
time of the acquisition of a $4.9 million liability. This amount was accounted
for as part of the acquisition cost and will be charged as a reduction to
transportation expenses over the life of the contracts as they are incurred. The
charge for the three months ended March 31, 2010 was $0.3 million (2009 - $0.3
million).
In March 2010, the Company permanently assigned a portion of the firm
transportation agreements to third parties at no cost to Crew. As a result, the
remaining liability associated with the assigned contracts was written-off
during the quarter as a $0.3 million reduction of transportation expense.
5. Asset retirement obligations:
Total future asset retirement obligations were determined by management and were
based on Crew's net ownership interest, the estimated future costs to reclaim
and abandon the wells and facilities and the estimated timing of when the costs
will be incurred. Crew estimated the net present value of its total asset
retirement obligation as at March 31, 2010 to be $35,709,000 (December 31, 2009
- $35,341,000) based on a total future liability of $64,725,000 (December 31,
2009 - $64,030,000). These payments are expected to be made over the next 30
years. An 8% to 10% (2009 - 8% to 10%) credit adjusted risk free discount rate
and 2% (2009 - 2%) inflation rate were used to calculate the present value of
the asset retirement obligation.
The following table reconciles Crew's asset retirement obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Year ended
March 31, December 31,
2010 2009
----------------------------------------------------------------------------
Carrying amount, beginning of period $ 35,341 $ 34,941
Liabilities incurred 234 385
Liabilities disposed - (2,161)
Accretion expense 710 2,765
Liabilities settled (576) (589)
----------------------------------------------------------------------------
Carrying amount, end of period $ 35,709 $ 35,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Share capital:
(a) Authorized:
Unlimited number of Common Shares
(b) Common Shares issued:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
shares Amount
----------------------------------------------------------------------------
Common shares, December 31, 2009 78,152 $ 617,605
Exercise of stock options 1,269 11,237
Stock-based compensation - 4,506
----------------------------------------------------------------------------
Common shares, March 31, 2010 79,421 $ 633,348
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(c) Contributed Surplus:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Contributed surplus, December 31, 2009 $ 22,769
Exercise of stock options (4,506)
Stock-based compensation 2,640
----------------------------------------------------------------------------
Contributed surplus, March 31, 2010 $ 20,903
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 March 31, 2010: risk free interest rate 2.34% (2009 - 1.55%),
expected life 4 years (2009 - 4 years), volatility 61% (2009 - 52%), and an
expected dividend of nil (2009 - nil). The Company has not incorporated an
estimated forfeiture rate for stock options that will not vest rather the
Company accounts for actual forfeitures as they occur.
During the first three months of 2010, the Company recorded $2,640,000 (2009 -
$1,758,000) of stock-based compensation expense related to the stock options, of
which $1,320,000 (2009 - $879,000) 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
$445,000 (2009 - $299,000) associated with the current year's capitalized
stock-based compensation has been recorded.
The average fair value of the stock options granted during the three months
ended March 31, 2010, as calculated by the Black-Scholes method, was $7.07 per
option (2009 - $2.03).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Number of Price average
Options Range exercise price
----------------------------------------------------------------------------
Balance December 31, 2009 5,751 $2.50 to $18.70 $ 8.33
Granted 1,862 $13.36 to $14.68 $ 14.67
Exercised (1,269) 2.78 to $12.72 $ 8.85
----------------------------------------------------------------------------
Balance March 31, 2010 6,344 $2.78 to $18.70 $ 10.08
Exercisable 2,111 $3.43 to $18.70 $ 8.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 March 31, 2010 was 78,649,000 (March 31, 2009-71,084,000).
In computing diluted per share amounts for the three month period ended March
31, 2010, 2,082,000 shares (March 31, 2009-nil) were added to the weighted
average number of Common Shares outstanding for the dilution added by the stock
options. There were 2,104,000 (March 31, 2009 - 5,934,000) stock options that
were not included in the diluted earnings per share calculation because they
were anti-dilutive.
7. Financial Instruments:
Overview
The Company has exposure to credit, liquidity and market risks from its use of
financial instruments. This note provides information about the Company's
exposure to each of these risks, the Company's objectives, policies and
processes for measuring and managing risk. Further quantitative disclosures are
included throughout these financial statements.
The Board of Directors has overall responsibility for the establishment and
oversight of the Company's risk management framework. The Board has implemented
and monitors compliance with risk management policies. The Company's risk
management policies are established to identify and analyze the risks faced by
the Company, to set appropriate risk limits and controls, and to monitor risks
and adherence to market conditions and the Company's activities.
(a) Credit risk:
Credit risk is the risk of financial loss to the Company if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Company's receivables from
petroleum and natural gas marketers and joint venture partners and the fair
value of derivative instruments.
The carrying amount of accounts receivable and derivative assets, when
outstanding, represents the maximum credit exposure. As at March 31, 2010 the
Company's receivables consisted of $19.9 (2009 - $17.2) million of receivables
from petroleum and natural gas marketers which has subsequently been collected,
$9.1 (2009-$9.2) million from joint venture partners of which $1.4 million has
been subsequently collected, and $10.8 (2009-$11.2) million of Crown deposits,
prepaids and other accounts receivable. The Company does not consider any
receivables to be past due.
(b) Liquidity risk:
Accounts payable and financial instruments have contractual maturities of less
than one year. The Company maintains a revolving credit facility, as outlined in
note 3, that is subject to renewal annually by the lenders and has a contractual
maturity in 2012. The Company also maintains and monitors a certain level of
cash flow which is used to partially finance all operating and capital
expenditures as 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 as outlined below. 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.
(ii) Foreign currency exchange rate risk
The Company has attempted to mitigate a portion of its foreign exchange
fluctuation risk through the use of financial derivatives as outlined below.
(iii) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result
of changes in market interest rates. The Company is exposed to interest rate
fluctuations on its bank loan which bears a floating rate of interest. For the
three months ended March 31, 2010, a 1.0 percent change to the effective
interest rate would have a $0.5 million impact on net income(2009 - $0.4
million).
The Company has attempted to mitigate the impact of future fluctuations in
interest rates on its outstanding debt by entering into contracts fixing the
base interest rate on $150 million of banker's acceptance borrowings as outlined
below. These rates are, under the Company's bank Facility, subject to an
additional stamping fee of 3.50 percent as of March 31, 2010.
The Company's contracts in place as of March 31, 2010 are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
Natural 2,500 November 1, 2009 - AECO C
Gas gj/day December 31, 2010 Monthly Index $ 6.00 Swap 1,491
AECO C
Natural 5,000 January 1, 2010 - Monthly Index
Gas gj/day December 31, 2010 less $0.09 $ 8.00 Call (7)
Natural 10,000 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly Index $ 7.75 Call (15)
Natural 2,500 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly Index $ 6.20 Swap 1,631
Natural 5,000 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly Index $ 6.08 Swap 3,284
Natural 2,500 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly Index $ 5.25 Swap 977
Natural 2,500 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly Index $ 5.55 Swap 1,185
Natural 2,500 April 1, 2010 - AECO C
Gas gj/day October 31, 2010 Monthly Index $ 5.30 Swap 915
Natural 5,000 January 1, 2010 - AECO/NYMEX
Gas mmbtu/day December 31, 2010 Basis diff US$(0.55) Swap (351)
250 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $ 78.50 Swap (543)
500 January 1, 2010 - $ 72.00-
Oil bbl/day December 31, 2010 CDN$ WTI $ 88.00 Collar (459)
250 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $ 82.50 Swap (265)
500 January 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $ 80.50 Swap (826)
500 January 1, 2010 -
Oil bbl/day December 31, 2010 US$ WTI US$81.00 Swap (557)
250 January 1, 2010 - $ 80.00-
Oil bbl/day December 31, 2010 CDN$ WTI $ 95.02 Collar 34
250 March 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $ 84.00 Swap (157)
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $ 86.00 Swap (194)
----------------------------------------------------------------------------
Total commodity contracts 6,143
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
USD/
CAD $ US $2M/ January 1, 2010 - CAD/USD 1.094 Swap 1,389
exchange Month December 31, 2010
----------------------------------------------------------------------------
Total foreign exchange contracts 1,389
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
February 10, 2009-
BA Rate $50M/year February 10, 2011 BA-CDOR 1.10% Swap (91)
February 12, 2009-
BA Rate $50M/year February 12, 2011 BA-CDOR 1.10% Swap (59)
May 28, 2009-
BA Rate $50M/year May 28, 2011 BA-CDOR 1.12% Swap (18)
----------------------------------------------------------------------------
Total interest rate contracts (168)
----------------------------------------------------------------------------
Total financial instruments 7,364
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at March 31, 2010, a $0.10 change to the price per thousand cubic feet of
natural gas on the contracts outlined above would have a $0.2 million impact on
net income.
As at March 31, 2010, a $1.00 per barrel change to the price on the oil
contracts outlined above would have a $0.2 million impact on net income.
As at March 31, 2010, a $0.01 change to the exchange rate on the foreign
exchange contracts outlined above would have a $0.2 million impact on net
income.
As at March 31, 2010, a 0.1% change to the interest rate on the interest rate
contracts outlined above would have a $0.1 million impact on net income.
Subsequent to March 31, 2010, the Company entered into the following financial
derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional Option
Contract Quantity Term Reference Strike Price Traded
----------------------------------------------------------------------------
250 July 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $ 88.10 Swap
250 July 1, 2010 -
Oil bbl/day December 31, 2010 CDN$ WTI $ 91.50 Swap
Oil 250 January 1, 2011 -
bbl/day December 31, 2011 CDN$ WTI $ 90.00 Swap
500 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $ 90.20 Swap
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $ 82.00 - $94.62 Collar
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $ 80.00 - $95.45 Collar
250 January 1, 2011 -
Oil bbl/day December 31, 2011 CDN$ WTI $85.00 - $100.50 Collar
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair value of financial instruments
The Company's financial instruments as at March 31, 2010 and 2009 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 March 31, 2010, the Company's ratio of net debt to annualized funds
from operations was 1.70 to 1 (December 31, 2009 - 1.67 to 1).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
March 31, December 31,
2010 2009
----------------------------------------------------------------------------
Net debt:
Accounts receivable $ 39,768 $ 37,574
Accounts payable and accrued liabilities (78,031) (84,228)
----------------------------------------------------------------------------
Working capital deficiency $ (38,263) $ (46,654)
Bank loan (153,601) (135,601)
----------------------------------------------------------------------------
Net debt $ (191,864) $ (182,255)
Annualized funds from operations:
Cash provided by operating activities $ 32,213 $ 16,734
Asset retirement expenditures 576 111
Transportation liability charge 328 329
Change in non-cash working capital (4,900) 10,082
----------------------------------------------------------------------------
Funds from operations 28,217 27,256
Annualized $ 112,868 $ 109,024
Net debt to annualized funds from operations 1.70 1.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company has commodity, interest rate and foreign exchange hedging for 2010
and 2011 to provide support for its funds from operations and assist in funding
its capital expenditure program. In addition, on April 1, 2010, the Company
closed an agreement to dispose of oil and gas assets in the Edson area of west
central Alberta for gross proceeds of $126 million, before closing adjustments.
There has been no change in the Company's approach to capital management during
the period ended March 31, 2010.
9. Supplemental cash flow information:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Changes in non-cash working capital:
Accounts receivable $ (2,194) $ 10,947
Accounts payable and accrued liabilities (6,197) (30,113)
----------------------------------------------------------------------------
$ (8,391) $ (19,166)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities $ 4,900 $ 3,414
Investing activities (13,291) (22,580)
----------------------------------------------------------------------------
$ (8,391) $ (19,166)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company made the following cash outlays in respect of interest expense:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
March 31, 2010 March 31, 2009
----------------------------------------------------------------------------
Interest $ 1,090 $ 1,731
----------------------------------------------------------------------------
----------------------------------------------------------------------------
10. Commitments:
The Company has the following fixed term commitments related to its on-going
business:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Operating Leases $ 4,365 $ 1,307 $ 1,743 $1,315 - - -
Capital commitments 8,000 4,000 4,000 - - - -
Transportation
agreements 5,900 2,835 3,065 - - - -
Processing
agreement 29,507 2,065 3,049 3,049 3,049 3,049 15,246
----------------------------------------------------------------------------
Total $47,772 $10,207 $11,857 $4,364 $3,049 $3,049 $ 15,246
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The firm transportation commitments were acquired as part of the Company's May
2007 private company acquisition and represent firm service commitments for
transportation and processing of natural gas in British Columbia. In 2010, the
Company permanently assigned approximately $6.2 million of its firm commitments
to third parties. The amount shown represents the remaining contractual
obligations.
During 2009, Crew entered into an agreement to process natural gas through a
third party owned gas processing facility in the Septimus area of northeast
British Columbia. Under the terms of the agreement, Crew has committed to
process a minimum monthly volume of gas through the facility commencing on
December 1, 2009 and continuing through November 30, 2019. The commitment is
included in the above table.
The agreement additionally provides Crew the option to participate in an
expansion of the facility at a cost of 50% of the total expanded facility
construction costs and subsequently become a 50% owner in the facility. If the
facility is not expanded prior to January 1, 2013, the current owner of the
facility can require Crew to purchase the existing facility for the total
construction costs of $19.1 million plus $0.7 million or alter the fees
associated with Crew's commitment in order to recover the amount of Crew's full
commitment prior to January 1, 2016.
11. Subsequent event:
On April 1, 2010, the Company closed the disposition of oil and gas assets in
the Edson, Alberta area for gross proceeds of $126 million, before closing
adjustments. The Company received a $9.5 million deposit in March 2010 for this
sale which has been included in accounts payable as it was refundable until
closing.
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