Crew Energy Inc. ("Crew" or the "Company") (TSX:CR) of Calgary, Alberta is
pleased to present its operating and financial results for the three month
period and year ended December 31, 2008.
Highlights
- Achieved record funds from operations in 2008 of $127.8 million, a 57%
increase over 2007 while funds from operations per share increased to $2.06, an
18% increase over 2007.
- Crew's production during the fourth quarter of 2008 averaged 14,869 boe per
day, a 54% increase over the fourth quarter of 2007 and a 29% increase over the
third quarter of 2008. Production for 2008 averaged 11,617 boe per day, a 34%
increase over 2007.
- Production per diluted share increased 14% in the fourth quarter of 2008
compared to the fourth quarter of 2007.
- The Company's proved plus probable reserves as at December 31, 2008 increased
76% to 59.1 MMboe including 35.9 MMboe of proved reserves.
- December 31, 2008 proved plus probable reserves per diluted share increased
33% over 2007.
- Achieved finding and development costs of $15.64 per boe and all in finding,
development and acquisition costs of $21.24 per boe on a proved plus probable
basis.
- Crew's proved plus probable reserve life index (RLI), based on fourth quarter
average production, increased by 15% to 10.9 years from 9.5 years at December
31, 2007.
- At December 31, 2008 Crew held mineral interests in 1.6 million acres of land
including 627,000 net acres of undeveloped land with an internally estimated
value of $227 million.
- The net present value of Crew's estimated future net revenue before income
taxes from proved plus probable reserves, discounted at 10%, was $1.04 billion,
an increase of 80% over the previous year.
- Crew's net asset value increased to $14.22 per diluted share based on
estimated future net revenues discounted at 10%.
- Crew engaged GLJ Petroleum Consultants Ltd. ("GLJ") to prepare an independent
evaluation of the Discovered Petroleum Initially in Place ("DPIP") on 50 net
sections of Crew's Montney lands in the Septimus area of northeast British
Columbia. The report has identified a current best estimate of a net 2.4 Tcf of
DPIP in the upper Montney on the Company's lands of which 0.08 Tcf of proved
plus probable reserves have been recognized.
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Three Three
Financial months months Year Year
ended ended ended ended
($ thousands, except Dec. 31, Dec. 31, Dec. 31, Dec. 31,
per share amounts) 2008 2007 2008 2007
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Petroleum and natural gas sales 58,806 38,942 235,856 140,466
Funds from operations (note 1) 29,646 22,390 127,790 81,433
Per share - basic 0.42 0.43 2.08 1.75
- diluted 0.42 0.43 2.06 1.74
Net income (loss) (74,853) 6,889 (53,319) 9,110
Per share - basic (1.05) 0.13 (0.87) 0.20
- diluted (1.05) 0.13 (0.87) 0.19
Exploration and development
expenditures 53,612 31,033 191,677 102,092
Property acquisitions
(net of dispositions) (245) (266) 70,414 (315)
Total capital expenditures 53,367 30,767 262,091 101,777
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Capital Structure As at As at
($ thousands) Dec. 31, Dec. 31,
2008 2007
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Working capital deficiency (note 2) 31,822 14,643
Bank loan 223,628 95,028
Net debt 255,450 109,671
Bank facility 285,000 180,000
Common shares outstanding (thousands) 71,084 53,577
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Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital, asset
retirement expenditures and the transportation liability charge. Funds
from operations is used to analyze the Company's operating performance
and leverage. Funds from operations does not have a standardized measure
prescribed by Canadian Generally Accepted Accounting Principles and
therefore may not be comparable with the calculations of similar
measures for other companies.
(2) Working capital deficiency includes only accounts receivable less
accounts payable and accrued liabilities.
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Operations Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
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Daily production
Natural gas (mcf/d) 60,464 47,204 52,595 43,193
Oil (bbl/d) 3,123 445 1,393 545
Natural gas liquids (bbl/d) 1,669 1,329 1,458 952
Oil equivalent (boe/d @ 6:1) 14,869 9,641 11,617 8,696
Average prices (note 1)
Natural gas ($/mcf) 6.93 6.40 8.37 6.75
Oil ($/bbl) 50.21 83.10 74.89 71.90
Natural gas liquids ($/bbl) 37.24 63.29 62.32 57.01
Oil equivalent ($/boe) 42.99 43.90 55.47 44.45
Operating expenses
Natural gas ($/mcf) 1.61 1.06 1.42 1.04
Oil ($/bbl) 12.86 8.55 12.24 6.06
Natural gas liquids ($/bbl) 8.57 5.74 7.41 6.37
Oil equivalent ($/boe @ 6:1) 10.20 6.35 8.82 6.23
Netback
Operating netback ($/boe) (note 2) 22.08 27.73 32.80 28.46
Realized loss/(gain) on
financial instruments (1.93) (0.49) 0.16 (0.32)
G&A ($/boe) 0.91 1.09 0.98 1.05
Interest and other ($/boe) 1.44 1.88 1.60 2.08
Funds from operations ($/boe) 21.66 25.25 30.06 25.65
Drilling Activity
Gross wells 16 11 53 31
Working interest wells 9.8 7.4 43.3 25.3
Success rate, net wells 100% 86% 95% 96%
Undeveloped land (note 4)
Gross acres 1,105,639 325,967
Net acres 626,861 235,524
Reserves (Proved plus probable)(note 4)
Oil (Mbbl) 9,178 711
Ngl (Mbbl) 6,563 4,442
Natural Gas (Mmcf) 260,298 170,070
BOE (Mboe) 59,123 33,498
Finding, Development &
Acquisition Costs ($/boe)
(note 3 and 4) 21.24 15.57
Recycle Ratio (note 4) 1.5 1.8
Net Asset Value (Proved plus
probable disc. 10%)(note 4) $14.22 $9.60
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Notes:
(1) Average prices are before deduction of transportation costs.
(2) Operating netback equals petroleum and natural gas sales less
royalties, operating costs and transportation costs calculated on a boe
basis. Operating netback and funds from operations netback do not have
a standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
(3) The acquisition costs related to corporate acquisitions reflects the
consideration paid for the shares acquired plus the net debt assumed,
both valued at closing and does not reflect the fair market value
allocated to the acquired oil and gas assets under Generally Accepted
Accounting Principles.
(4) More detailed information in respect of the results of Crew's
independent reserve evaluation for the year ended December 31, 2008
as evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") and related
information was contained in Crew's press release dated February 25,
2009 and will be contained in Crew's Annual Information Form to be
filed on or before March 31, 2009.
Overview
2008 was a year that will be remembered for its volatility within the oil and
gas industry and most importantly in the world's financial markets. The first
half of 2008 saw a dramatic increase in commodity prices with the price of West
Texas Intermediate ("WTI") oil increasing 44% from an average US $93 per bbl in
January to an average US $134 per bbl in June and the price of Alberta natural
gas increasing 51% from an average $6.98 per gj in January to average $10.60 per
gj in July. Instability in the U.S. financial markets mid year resulted in a
dramatic slow down in the U.S. economy that rapidly spread throughout the world.
This resulted in a precipitous decline in the demand for commodities leading to
a dramatic fall in oil and gas prices in the second half of 2008. The price of
WTI oil declined 69% from its June highs to trade at an average of US $42 per
bbl in December and Alberta natural gas declined 41% from its July highs to
trade at an average $6.25 per gj in December.
These dramatic commodity price fluctuations had an impact on the Company's
financial results. Funds from operations increased steadily from $29 million in
the first quarter to peak at $35 million in the third quarter only to decline
back to $29 million in the fourth quarter. This change in funds from operations
occurred despite a 40% increase in production from an average of 10,614 boe per
day in the first quarter to an average of 14,869 boe per day in the fourth
quarter. Funds from operations were also negatively impacted by higher costs
associated with inflationary pressures brought on by the high commodity prices
experienced over the past few years. Net income was also impacted by fluctuating
commodity prices and higher costs and, to a greater degree, by a one time
non-cash charge to earnings as a result of a write-down of the Company's carried
goodwill.
The Company's increase in production through the year was the result of an
active exploration and development program and the acquisition of Gentry
Resources Ltd. ("Gentry") in August. The Company spent $192 million in 2008 on
exploration and development with expenditures focused on natural gas drilling
and infrastructure spending in northeast British Columbia on the Company's
Triassic Montney natural gas play, west central Alberta natural gas drilling and
infrastructure spending and its Princess, Alberta Pekisko oil development. The
Company spent $87.8 million on land acquisitions in 2008 which included $79.5
million on undeveloped lands in northeast British Columbia prospective for
Triassic Montney natural gas.
In August, Crew closed the acquisition of Gentry adding approximately 4,000 boe
per day of production, an estimated 12.3 million boe of proved and probable
reserves and 280,000 acres of undeveloped land predominantly on its primary oil
play at Princess in south central Alberta. As consideration the Company issued
12.3 million Common Shares and assumed $73.6 million of net debt.
Hedging Activity
With the current economic recession fully established, hedging has become more
important in protecting corporate funds from operations. Crew now has over 40%
of the Company's current non-royalty natural gas volumes hedged at an average
floor price of $6.13 per gj from April through October 2009, in order to protect
its capital program and balance sheet through the current economic downturn.
These hedges include a 5,000 gj per day collar with a floor of $6.50 per gj and
a ceiling of $8.40 per gj for calendar 2009. Crew has also acquired natural gas
puts on 15,000 gj per day at $6.00 per gj for the period April 1, 2009 through
October 31, 2009. These puts were paid for with the sale of natural gas calls on
15,000 gigajoules per day at an average price of $7.83 per gj for the period
January 1, 2010 through December 31, 2010.
Currently all of Crew's production is sold in Canadian markets and denominated
in Canadian dollars. Canadian commodities trade independently of US commodities;
however, prices in Canada are closely correlated with prices in the US and are
impacted by fluctuations in the exchange rate between the Canadian and US
dollar. When the Canadian dollar strengthens in relation to the US dollar we
generally experience a decrease in Canadian commodity prices in comparison to US
commodity prices. As a result, Crew has entered into contracts that fix the
exchange rate on US $4 million per month at 1.2400 for the period February 2009
through December 2009.
The majority of Crew's bank borrowings are drawn in the form of banker's
acceptances with 30, 60 or 90 day floating interest rates plus a stamping fee
which ranges from 0.95% to 1.75% depending on the Company's trailing debt to
EBITDA ratio. As a result of the current economic downturn and the decrease in
central banks' prime lending rates, the interest rates charged on banker's
acceptances are at levels not seen in decades. In order to reduce the risk of a
future increase in the interest rate charged on banker's acceptances, the
Company has entered into contracts fixing the rate on $100 million of banker's
acceptances for the period beginning in February 2009 to February 2011 at a rate
of 1.10% plus the applicable stamping fee charged by the Company's bank
syndicate.
OPERATIONS UPDATE
During the fourth quarter, the Company drilled a total of 16 (9.8 net) wells
resulting in 12 (5.8 net) natural gas wells, three (3.0 net) oil wells and one
(1.0 net) service well. During 2008, Crew drilled a total of 53 (43.3 net) wells
resulting in 41 (31.3 net) natural gas wells, nine (9.0 net) oil wells, one (1.0
net) service well and two (2.0 net) dry and abandoned wells representing a
success rate of 96% (95% net). In addition, in the quarter, the Company
completed 21 (17.4 net) wells and recompleted six (5.6 net) wells. The Company
also added to its infrastructure, spending 24% of its capital expenditures on
equipment and facilities primarily in the Princess, Alberta and Septimus,
British Columbia areas.
As a result of the current economic environment and continued weakening of
commodity prices, Crew has curtailed 2009 activity levels to match capital
expenditures with expected cash flow. The Company has drilled two wells in the
first quarter of 2009 and high graded its drilling program in order to optimize
economic returns in the current price environment. In addition to well
optimization programs in all areas of operation, the majority of the 2009
capital program will be directed to operating cost reductions at Princess and
facility construction, minor land acquisitions and drilling at Septimus, British
Columbia. Crew has had very positive developments on its two resource plays at
Septimus in northeast British Columbia and Princess, Alberta.
Montney Play, Northeast British Columbia
Crew controls 184 net sections on the Montney play in northeast British
Columbia. The Company has now drilled or re-completed 12 wells targeting the
Montney. Crew continues to concentrate its drilling efforts in the Septimus area
experiencing exceptional results with wells testing at rates as high as 17.8
mmcf per day. Crew is currently producing at a restricted rate of seven mmcf per
day from the Montney at Septimus and has an estimated seven to eight mmcf per
day of additional production capacity. The drilling program at Septimus has
resulted in finding and development costs, including land expenditures on the
developed lands and future development capital, of $9.56 per boe on a proved
plus probable basis. Based on Crew's evaluation of the economics of the Septimus
play, rates of return are attractive at current gas prices with a $4.40 per gj
price yielding a 25% to 35% rate of return and a recycle ratio of 1.6. With
roads and pipelines already built, the economies of scale are expected to
improve with well costs targeted to decrease to $4.5 million per well. Equipment
has been ordered and applications have been submitted for approval to the
British Columbia regulatory authorities for construction of a 25 mmcf per day
(previously estimated at 20 mmcf per day) natural gas processing facility. The
gas plant has been designed to be expanded in stages with construction expected
to start after spring breakup and commissioning currently planned for late in
the third quarter. Current plans are to drill four to seven wells targeting the
Montney in 2009 and evaluate the gas plant expansion in late 2009.
Montney Evaluation
Based on an independent evaluation by GLJ effective November 30, 2008, it is
estimated that the Discovered Petroleum Initially in Place ("DPIP") for 50 net
sections of Montney rights owned in Crew's Septimus area is a net 2.4 Tcf, of
which 0.72 Tcf is on sections to which reserves have been assigned. GLJ have
assigned proved plus probable non-associated gas reserves of 81.5 bcf to the
Septimus area, which includes 35 bcf of proved reserves. The assigned proved
reserves are booked based on three wells per section and will require an
additional 11 wells to be drilled with future development capital of $58.36
million including the completion and tie in of two additional wells. This
reserve assignment represents a 5.2% recovery on proved reserves and a 12.1%
recovery on proved plus probable reserves. Once there is more production history
for Crew's wells, the Company believes that the opportunity exists for improving
recoveries in line with other area operators.
GLJ has estimated there exists 1.7 Tcf of DPIP (of the 2.4 Tcf in total DPIP) on
sections of the Company's lands at Septimus that do not currently have any
reserves assigned and there are additional Crew interest lands adjacent to these
lands that have not yet been assigned any DPIP. Continued step-out drilling into
the future will provide information to help assess the potential of these lands.
GLJ has provided a best estimate of the DPIP for the upper Montney on 50 out of
184 controlled net sections or 27% of Crew's prospective Montney land base. It
should be noted that given the current early stage of development the best
estimate of DPIP might change significantly in the future with further
development activity and the amount of Contingent Resources as defined in the
COGE Handbook has yet to be estimated. Crew is in the early stages of
development of this Montney asset and while management is encouraged by the
results to date, additional drilling and testing is required to confirm
deliverability potential and commercial economic development. The resource
estimates provided herein are estimates only and the actual resources may be
greater than or less than the estimates provided herein. A recovery project
cannot be defined for these volumes of DPIP at this time. There is no certainty
that it will be commercially viable or technically feasible to produce any
portion of this natural gas currently classified as DPIP.
Pekisko Play, Princess Alberta
The drilling program at Princess has been another positive development for Crew
with production from the property increasing from 2,400 boe per day in August to
its current rate of over 3,500 boe per day. The prospect inventory continues to
expand and horizontal well production rates have exceeded Company expectations
with Crew's best well producing at a steady 350 bbl per day with cumulative
production of 40,900 bbls since mid October of 2008. Crew owns and controls over
440 net sections of land on this play providing the Company with a multi year
drilling inventory. In 2009 Crew has been pipeline connecting and equipping
wells drilled in 2008 resulting in a steady increase in production. The focus in
this area will be on production optimization and the reduction of operating
costs. Significant progress has been made on both of these initiatives to date.
Operating costs at Princess in August were approximately $16.50 per boe and have
since declined to $13.25 in December. Once operational, the Company's disposal
well that was drilled in the fourth quarter is expected to reduce area operating
costs by $160,000 per month or $1.50 per boe.
Management Addition
The Company is very pleased to announce that Mr. Dean Tucker, P.Eng has joined
our "Crew" in the position of Vice-President, Production and Operations. Dean
has over 25 years of oil and gas experience with increasing levels of
responsibility. Dean is a welcome addition to our team and we look forward to
his contribution to Crew.
Outlook
As the global recession continues to deepen and oil and natural gas prices
continue to show weakness Crew will move forward in a cautious and conservative
manner. In order to preserve the Company's financial position Crew is committed
to maintain or reduce debt levels by spending within funds from operations and
consider the disposition of non-core assets in order to focus its capital on the
Company's three resource plays.
In this regard, the Company has reduced its previously announced budgeted
capital expenditure program to $80 million for 2009 from the previously
announced $120 million. This amount includes the completion of the Company's
planned natural gas processing facility and the drilling of five wells at
Septimus in northeast British Columbia, the drilling of wells at Portage in
northeast British Columbia, Strachan and Wapiti in Alberta. It also includes the
completion and tie-in of several wells in Alberta and British Columbia that were
drilled in 2008 as well as maintenance capital. As a result of the reduction in
the planned capital expenditures for the year, the Company has reduced its
production guidance to average approximately 14,500 boe per day from the
previously announced guidance of 15,500 boe per day. This updated guidance
assumes the three week turnaround of the Fort Nelson natural gas processing
facility which will affect approximately 970 boe per day of Crew's production in
June. This represents a 25% increase in average production growth and a 9%
increase in production per share growth.
Over the past few months, Crew has entered into the previously noted derivative
contracts to reduce the effect of falling commodity prices, a strengthening
Canadian dollar and an increase in interest rates from their current levels on
the Company. Crew will continue to monitor these markets and if the opportunity
arises will look to enter additional contracts in order to protect the Company's
future funds from operations.
The oil and gas industry has historically experienced many boom and bust cycles;
however, this cycle is decidedly different in that the downturn is global and
pervasive. The Board of Directors, management and staff of Crew are well
prepared and equipped to deal with the current and potentially worsening
economic environment. Priorities in 2009 are to:
- Maintain or reduce debt levels by spending within cash flow and/or disposing
of non core assets.
- Improve operating efficiencies to lower costs and improve netbacks.
- Actively engage in hedging activities to protect capital programs and Crew's
balance sheet.
- Continue to exhibit steady production growth. With current production of
15,200 boe per day and over 1,500 boe per day of expected production additions
behind pipe, Crew remains positioned to increase average production by a minimum
of 20% year over year.
- Preserve the value and future growth prospects of Crew.
- Continue to capture additional resource opportunities.
- Position the Company to exit this recession in a position of strength.
I would like to thank our Board of Directors for their stewardship and support
over the year and on behalf of the Board of Directors, management and staff of
Crew, I would like to thank our shareholders for their continued support. We
understand that these are challenging times however we are confident in the
commitment of our team and the quality of our assets to weather this period and
strongly believe your patience will be rewarded.
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 consolidated financial statements of
the Company for the three month periods and years ended December 31, 2008 and
2007 and the audited and consolidated financial statements and Management
Discussion and Analysis for the year ended December 31, 2007.
Forward Looking Statements
This MD&A contains forward-looking statements. Management's assessment of future
plans and operations, capital expenditures, methods of financing capital
expenditures and the ability to fund financial liabilities, expected commodity
prices and the impact on Crew, future operating costs, future transportation
costs, expected change in royalty rates, interest rates and the timing of and
impact of adoption of IFRS and other accounting policies may constitute
forward-looking statements under applicable securities laws and necessarily
involve risks including, without limitation, risks associated with oil and gas
exploration, development, exploitation, production, marketing and
transportation, loss of markets, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks, competition
from other producers, inability to retain drilling rigs and other services,
incorrect assessment of the value of acquisitions, failure to realize the
anticipated benefits of acquisitions, the inability to fully realize the
benefits of the acquisitions, delays resulting from or inability to obtain
required regulatory approvals and ability to access sufficient capital from
internal and external sources. As a consequence, the Company's actual results
may differ materially from those expressed in, or implied by, the forward
looking statements. Forward looking statements or information are based on a
number of factors and assumptions which have been used to develop such
statements and information but which may prove to be incorrect. Although Crew
believes that the expectations reflected in such forward-looking statements or
information are reasonable, undue reliance should not be placed on forward
looking statements because the Company can give no assurance that such
expectations will prove to be correct.
In addition to other factors and assumptions which may be identified in this
document and other documents filed by the Company, assumptions have been made
regarding, among other things: the impact of increasing competition; the general
stability of the economic and political environment in which Crew operates; the
ability of the Company to obtain qualified staff, equipment and services in a
timely and cost efficient manner; drilling results; the ability of the operator
of the projects which the Company has an interest in to operate the field in a
safe, efficient and effective manner; Crew's ability to obtain financing on
acceptable terms; field production rates and decline rates; the ability to
reduce operating costs; the ability to replace and expand oil and natural gas
reserves through acquisition, development or exploration; the timing and costs
of pipeline, storage and facility construction and expansion; the ability of the
Company to secure adequate product transportation; future oil and natural gas
prices; currency, exchange and interest rates; the regulatory framework
regarding royalties, taxes and environmental matters in the jurisdictions in
which the Company operates; and Crew's ability to successfully market its oil
and natural gas products. Readers are cautioned that the foregoing list of
factors is not exhaustive.
Additional information on these and other factors that could affect the
Company's operations and financial results are included in reports on file with
Canadian securities regulatory authorities and may be accessed through the SEDAR
website (www.sedar.com) or at the Company's website (www.crewenergy.com).
Furthermore, the forward looking statements contained in this document are made
as at the date of this document and the Company does not undertake any
obligation to update publicly or to revise any of the included forward looking
statements, whether as a result of new information, future events or otherwise,
except as may be required by applicable securities laws.
Conversions
The oil and gas industry commonly expresses production volumes and reserves on a
"barrel of oil equivalent" basis ("boe") whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved analysis of results and comparisons with other industry participants.
Throughout this MD&A, Crew has used the 6:1 boe measure which is the approximate
energy equivalency of the two commodities at the burner tip. Boe does not
represent a value equivalency at the plant gate which is where Crew sells its
production volumes and therefore may be a misleading measure if used in
isolation.
Non-GAAP Measures
One of the benchmarks Crew uses to evaluate its performance is funds from
operations. Funds from operations is a measure not defined in GAAP that is
commonly used in the oil and gas industry. It represents cash provided by
operating activities before changes in non-cash working capital, asset
retirement expenditures and the transportation liability charge. The Company
considers it a key measure as it demonstrates the ability of the business to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Funds from operations should not be considered as
an alternative to, or more meaningful than cash flow provided by operating
activities as determined in accordance with GAAP as an indicator of the
Company's performance. Crew's determination of funds from operations may not be
comparable to that reported by other companies. Crew also presents funds from
operations per share whereby per share amounts are calculated using weighted
average shares outstanding consistent with the calculation of income per share.
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Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands) 2008 2007 2008 2007
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Cash provided by operating
activities 25,700 11,882 123,356 74,400
Asset retirement expenditures 152 205 775 237
Excess transportation liability
charge 328 313 1,313 784
Change in non-cash working capital 3,466 9,990 2,346 6,012
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Funds from operations 29,646 22,390 127,790 81,433
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Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore may not be
comparable with the calculation of similar measures for other entities. Netback
equals total petroleum and natural gas sales less royalties, operating costs and
transportation calculated on a boe basis. Management considers netbacks an
important measure to evaluate its performance as it demonstrates its
profitability relative to current commodity prices.
RESULTS OF OPERATIONS
Production
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Three months ended Three months ended
December 31, 2008 December 31, 2007
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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Plains
Core 2,845 989 42,890 10,982 239 960 33,700 6,815
North Core 278 680 17,574 3,887 206 369 13,504 2,826
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Total 3,123 1,669 60,464 14,869 445 1,329 47,204 9,641
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Year ended Year ended
December 31, 2008 December 31, 2007
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Plains
Core 1,187 991 37,010 8,346 369 812 32,352 6,573
North Core 206 467 15,585 3,271 176 140 10,841 2,123
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Total 1,393 1,458 52,595 11,617 545 952 43,193 8,696
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Fourth quarter production increased over the fourth quarter of 2007 as a result
of a successful drilling program that added new natural gas liquids ("ngl") rich
natural gas production at Septimus, British Columbia and Ferrier, Alberta and
the closing of the acquisition of Gentry in August with liquids production of
approximately 1,900 bbl per day and natural gas production of approximately 13
mmcf per day at closing. Production from the Gentry properties increased
throughout the fourth quarter as a result of the addition of new oil production
from wells that had been drilled but not completed prior to the acquisition.
Production increased 34% in 2008 due to a successful drilling program and the
previously mentioned acquisition of Gentry. Natural gas production increased 22%
over 2007 due to a successful drilling program in the Company's
Septimus, British Columbia and Ferrier, Alberta areas. Oil production increased
156% due to the acquisition of Gentry with oil production in the Princess,
Alberta area. The impact of these additions during the year was moderated by a
higher than expected decline on the Company's Hanlan discovery and facility
downtime. The facility downtime mainly occurred during the second quarter in
northeastern British Columbia and west central Alberta and occurred to a lesser
extent during the third quarter at Princess in southern Alberta.
Revenue
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Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue ($ thousands)
Natural gas 38,537 27,801 161,192 106,354
Oil 14,425 3,401 38,196 14,310
Natural gas liquids 5,720 7,740 33,249 19,802
Sulphur 124 - 3,219 -
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Total 58,806 38,942 235,856 140,466
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Crew average prices
Natural gas ($/mcf) 6.93 6.40 8.37 6.75
Oil ($/bbl) 50.21 83.10 74.89 71.90
Natural gas liquids ($/bbl) 37.24 63.29 62.32 57.01
Oil equivalent ($/boe) 42.99 43.90 55.47 44.45
Benchmark pricing
Natural Gas - AECO C daily
index (Cdn $/mcf) 6.79 6.24 8.27 6.53
Oil and ngl - Light Sweet @
Edmonton (Cdn $/bbl) 62.54 84.73 102.02 75.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's 2007 fourth quarter revenue increased 51% over the fourth quarter of 2007
due to the 54% increase in production. This was partially offset by a two
percent decrease in the Company's average prices. The 8% increase in natural gas
price was consistent with the increase in Crew's benchmark price. The Company
had a disproportionate decrease in oil prices as compared with the Company's
benchmark primarily due to the addition of the sale of medium grade oil from the
Gentry production in the Princess area. Princess oil production is approximately
26 degree API that is delivered into the Bow River pipeline system which sells
at a discount to Edmonton Light due to higher density and sulphur content. The
Company had a 41% decrease in ngl pricing compared with a 26% decrease in the
benchmark due to increased sales of lower valued ethane in the Septimus, British
Columbia and Ferrier, Alberta areas.
The Company's 2008 revenue increased 68% as a result of its 34% increase in
production and a 25% increase in product pricing. For the year, Crew's natural
gas price increased 24% over 2007 compared with a 27% increase in the Company's
benchmark price. This disproportionate increase was the result of additional
production from the Septimus, British Columbia area which is sold at British
Columbia's Spectra Station 2 pricing which is on average, lower than Alberta
AECO pricing. The sales price for Crew's oil and ngl production increased 4% and
9%, respectively, compared to an increase of 35% in the benchmark. The majority
of the Company's oil production is medium grade oil in the Princess area from
the Gentry acquisition which occurred in late August. Due to the grade of oil,
it attracted a lower price than Crew's existing oil production and the majority
was produced in the fourth quarter in a lower oil price environment. Increased
sales of ethane in the Septimus, British Columbia and Ferrier, Alberta areas
accounted for the disproportionate decrease in ngl pricing as compared with the
benchmark.
Royalties
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Royalties 12,035 6,929 49,961 23,749
Per boe $ 8.80 $ 7.81 $ 11.75 $ 7.48
Percentage of revenue 20.5% 17.6% 21.2% 16.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties as a percentage of revenue increased in the fourth quarter compared to
the same quarter of 2007 due to 2007 royalties being reduced by a larger than
expected gas cost allowance credit. Royalties as a percentage of revenue were
lower than the forecasted 24% in the fourth quarter of 2008 due to royalty
credits from a government incentive program for summer drilling in British
Columbia.
Royalties as a percentage of revenue increased in 2008 over 2007 due to
decreased Alberta deep gas royalty holidays received in 2008 and higher royalty
rates on the production from the Gentry acquisition. Offsetting this, the
Company had additional benefits from government programs reducing royalties on
production in northeastern British Columbia. Crew estimates royalties as a
percentage of revenue to average 21% to 22% in 2009.
Financial Instruments
Commodities
The Company will enter into derivative and physical risk management contracts in
order to reduce volatility in financial results, to protect acquisition
economics and to ensure a certain level of cash flow to fund planned capital
projects. Crew's strategy focuses on the use of puts, costless collars, swaps
and fixed price contracts to limit exposure to downturns in commodity prices
while allowing for participation in commodity price increases. The Company's
financial derivative trading activities are conducted pursuant to the Company's
Risk Management Policy approved by the Board of Directors. In 2008, these
contracts had the following effect on the consolidated statement of operations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Realized gain (loss) on financial
instruments 2,646 432 (675) 1,011
Unrealized gain (loss) on financial
instruments 131 (840) 2,608 (423)
----------------------------------------------------------------------------
2,777 (408) 1,933 588
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December 31, 2008, the Company held financial instrument contracts
and direct sales agreements as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair Value
Natural Volume Floor Ceiling ($
Gas (gj/day) Term Index (Cdn $/gj) (Cdn $/gj) thousands)
----------------------------------------------------------------------------
AECO 2,500 January 1, 2009 - AECO C 6.50 8.30 632
December 31, 2009 Monthly
Index
less
$0.09
AECO 2,500 January 1, 2009 - AECO C 6.60 8.50 623
December 31, 2009 Monthly
Index
----------------------------------------------------------------------------
1,255
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subsequent to December 31, 2008, the Company entered into the following
financial instrument contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Natural Volume Put Call
Gas (gj/day) Term Index (Cdn $/gj) (Cdn $/gj)
----------------------------------------------------------------------------
AECO 15,000 April 1, 2009 - AECO C 6.00
October 31, 2009 Monthly Index
AECO 5,000 January 1, 2010 - AECO C
December 31, 2010 Monthly Index 8.00
AECO 10,000 January 1, 2010 - AECO C
December 1, 2010 Monthly Index 7.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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. The
Company did not have any forward exchange rate contracts in place as at or
during the period ended December 31, 2008, but subsequent to year-end, the
Company entered into contracts for US $4 million per month to fix the exchange
rate at 1.24 for the period February to December, 2009.
Interest rate
The Company is exposed to interest rate fluctuations on its bank debt which
bears a floating rate of interest. The Company did not have any interest rate
swaps or financial contracts in place as at or during the period ended December
31, 2008. Subsequent to year-end, Crew entered into contracts fixing the rate on
$100 million of banker's acceptances for 24 months at a rate of 1.10% for the
period running from February 11, 2009 to February 11, 2011. The Company pays an
additional stamping fee and margins on banker's acceptances as outlined in note
6 of the financial statements.
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Operating costs 13,952 5,634 37,520 19,763
Per boe $ 10.20 $ 6.35 $ 8.82 $ 6.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's operating costs increased in the fourth quarter as compared to the
same period in 2007 as a result of the Company's increased production and
inflationary pressures on costs experienced throughout the industry. On a per
unit basis, operating costs in the fourth quarter increased over the fourth
quarter of 2007 due to higher per unit costs associated with the Gentry
acquisition. Operating costs associated with the Gentry properties were
estimated at approximately $16.50 per boe at closing and averaged approximately
$15.00 per boe for the fourth quarter. Crew has initiated a number of cost
cutting initiatives that are intended to bring these costs more inline with
Crew's other low cost operations. In addition, higher fuel and third party
processing costs in Sierra, British Columbia and Viking and Plain Lake, Alberta
areas have negatively affected the Company's operating costs.
Crew's increase in operating costs per unit in 2008 was a result of inflationary
pressures experienced throughout its operations and the acquisition of Gentry
with higher per unit costs. The Company also experienced facility outages and
delayed field operations due to wet weather in the second and third quarter
causing a decrease in production from Crew's lower operating cost areas and
contributing to the increase in costs per unit. Going forward, Crew has
identified a number of cost cutting measures in some of the Gentry areas and
with the decline in oil prices, expects fuel costs to decline as well. The
Company expects operating costs to range between $9.50 and $10.00 per boe in the
first half of 2009. During the second half of 2009, with some of the cost
cutting measures in the Gentry areas in place as well as the addition of a new
facility currently planned in the Septimus, British Columbia area, Crew expects
operating costs to decrease into the range of $9.00 to $9.50 per boe.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Transportation costs 2,607 1,779 8,924 6,603
Per boe $ 1.91 $ 2.01 $ 2.10 $ 2.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's 2008 fourth quarter decrease in transportation costs per boe was a
result of a reduction in its firm transportation commitments in northeastern
British Columbia and lower transportation costs from the properties acquired in
the Gentry acquisition. In British Columbia, the Company was able to assign some
of its unutilized firm transportation and processing service to a third party
thus reducing its gas transportation costs per unit compared to the fourth
quarter of 2007.
In 2008, Crew's transportation costs per unit were slightly above 2007 levels.
The Company's transportation costs increased with the acquisition of a private
company in May 2007. This impact only affected eight months of operations in
2007. The Company forecasts transportation costs in 2009 to approximate fourth
quarter 2008 levels and range between $1.85 to $2.10 per boe.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
Dec. 31, 2008 Dec. 31, 2007
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 50.21 37.24 6.93 42.99 83.10 63.29 6.40 43.90
Royalties (15.32) (11.37) (1.08) (8.80) (7.11) (21.20) (0.93) (7.81)
Operating
costs (12.86) (8.57) (1.61) (10.20) (8.55) (5.74) (1.06) (6.35)
Transportation
costs (1.54) (0.04) (0.39) (1.91) (1.60) (0.04) (0.47) (2.01)
----------------------------------------------------------------------------
Operating
netbacks 20.49 17.26 3.85 22.08 65.84 36.31 3.94 27.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
Dec. 31, 2008 Dec. 31, 2007
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 74.89 62.32 8.37 55.47 71.90 57.01 6.75 44.45
Royalties (15.67) (17.30) (1.67) (11.75) (7.97) (17.10) (1.02) (7.44)
Operating
costs (12.24) (7.41) (1.42) (8.82) (6.06) (6.37) (1.04) (6.21)
Transportation
costs (1.93) (0.03) (0.41) (2.10) (2.20) (0.26) (0.44) (2.33)
----------------------------------------------------------------------------
Operating
netbacks 45.05 37.58 4.87 32.80 55.67 33.28 4.25 28.47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross costs 3,076 2,355 11,099 8,328
Operator's recoveries (591) (415) (2,761) (1,666)
Capitalized costs (1,243) (970) (4,169) (3,331)
----------------------------------------------------------------------------
General and administrative
expenses 1,242 970 4,169 3,331
Per boe $ 0.91 $ 1.09 $ 0.98 $ 1.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increased general and administrative costs before recoveries and capitalization
was the result of increased staff levels and higher salary levels in the fourth
quarter of 2008 compared to 2007. Increased capital expenditures and production
levels in the fourth quarter of 2008 resulted in higher operator recoveries and
capitalized costs. In addition, increased production levels resulted in lower
per boe costs in the period.
General and administrative expenses increased in 2008 as compared to 2007 due to
the addition of new staff to handle the Company's increased activity and
increased rent costs for the Company's expanded office space added in the fourth
quarter of 2007. Operator recoveries and capitalized costs were higher in 2008
as a result of increased capital expenditures and production in 2008. Crew
expects general and administrative costs per boe to average approximately $1.00
per boe in 2009.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands, except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Interest expense 1,970 1,882 7,085 6,808
Average debt level 191,535 107,300 138,395 103,300
Effective interest rate 4.1% 7.0% 5.1% 6.6%
Per boe $ 1.44 $ 2.12 $ 1.67 $ 2.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the fourth quarter of 2008, higher average debt levels due to the Company's
2008 exploration and development capital program and the acquisition of Gentry
have increased the Company's interest expense. This was partially offset by
lower interest rates charged on the Company's outstanding bank facility.
In 2008, higher average debt levels due to the Company's 2008 exploration and
development capital program and the acquisition of Gentry have increased the
Company's interest expense. Crew's effective interest rate decreased in 2008
compared with 2007 due to lower interest rates and the deferred financing costs,
which were incurred in connection with the new credit facility in May 2007,
being fully amortized into interest expense by May 2008. In 2009, the Company is
expecting increased margins to be applied to its bank facility which will
negatively affect Crew's interest expense and effective interest rate, however;
lower prime interest rates and interest rates on banker's acceptances along with
the Company's interest rate hedges will partially offset this increase.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross costs 1,178 1,516 6,664 5,324
Capitalized costs (589) (758) (3,332) (2,662)
----------------------------------------------------------------------------
Total stock-based compensation 589 758 3,332 2,662
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has decreased in the fourth
quarter of 2008 due to the Company's declining share price creating a lower fair
value for stock options as well as the reversal of expense due to the forfeiture
of options in the period. In 2008, increased staff levels and the issuance of
stock options in early 2008 has increased the Company's compensation expense for
the year.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
($ thousands, except per BOE) ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
Depletion, depreciation and accretion 35,329 20,489 104,866 75,427
Per BOE 25.83 23.10 24.66 23.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company experienced an increase in per unit depletion, depreciation and
accretion in the fourth quarter of 2008. Increased accretion related to the
Company's asset retirement obligation accounted for $0.40 per boe of the
increase while depletion and depreciation increased $2.33 per boe. The increases
were due to additional accretion associated with the added Gentry assets and
increased depletion associated with the addition of the Gentry assets at their
fair market value at the acquisition date, which was higher than historic
Company carrying values for proved reserves.
In 2008, per unit depletion, depreciation and accretion costs increased 4%. Per
unit accretion increased $0.16 while depletion and depreciation increased $0.74
per boe. Accretion per boe increased due to the Company's increased capital
program and increased well counts from its May 2007 and August 2008 corporate
acquisitions. Per unit depletion and depreciation increased due to the higher
priced proven reserves from the aforementioned Gentry acquisition. The Company
also increased its facility capital expenditures in 2008 as compared with 2007
in order to ensure processing capacity for its increased natural gas production.
Crew performed a ceiling test as at December 31, 2008. Based on the calculation,
the carrying values of the Company's property, plant and equipment are less than
the sum of the undiscounted cash flows of the Company's proved reserves;
therefore, the Company's property, plant and equipment was considered
recoverable.
Goodwill
Crew records goodwill on corporate acquisitions when the total purchase price
exceeds the fair value of the net identifiable assets and liabilities of the
acquired company. The goodwill balance is assessed for impairment annually at
year-end or as events occur that could result in an impairment. In 2008, the
Company performed a goodwill impairment test by comparing the fair value of the
Company to its carrying value. Due to a decline in the Company's fair value as
represented by its market capitalization on December 31, 2008, Crew's carrying
amount exceeded its fair value therefore it was determined a non-cash impairment
loss should be recognized. The Company has determined that the goodwill
associated with the acquisitions in 2006, 2007, and August, 2008 was impaired
and a non-cash loss of $69.1 million was recognized. It should be noted that
there has been no impairment to the value of Crew's petroleum and natural gas
assets and no write down of petroleum and natural gas assets has been recorded
in any period.
Taxes
The future income tax expense for 2008 was $6.4 million compared to a recovery
of $6.2 million in 2007. In 2007, the Company's tax provision was impacted by
the recovery of $8.0 million relating to the federal income tax rate reduction
enacted during the year.
A summary of the Company's estimated income tax pools at December 31, 2008
is outlined below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Balance Balance
($ thousands) Dec. 31, 2008 Dec. 31, 2007
----------------------------------------------------------------------------
Cumulative Canadian Exploration Expense 85,000 46,500
Cumulative Canadian Development Expense 124,000 70,000
Cumulative Canadian Oil and Gas Property Expense 167,000 54,500
Undepreciated Capital Cost 111,000 65,000
Share issue costs 7,700 5,000
Non-capital loss 26,700 500
----------------------------------------------------------------------------
521,400 241,500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The estimated income tax pools have been reduced by the estimated deferred
partnership income for 2008 and the reduction in the CEE tax pools due to the
renunciation of the 2007 flow through expenditures. The Company did not pay cash
taxes in 2008 and estimates it has sufficient tax pools to shelter estimated
income until 2010 or beyond.
Cash and Funds from Operations and Net Income
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended Year ended Year ended
($ thousands, except December 31, December 31, December 31, December 31,
per share amounts) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash provided by operations 25,700 11,882 123,356 74,400
----------------------------------------------------------------------------
Funds from operations 29,646 22,390 127,790 81,433
Per share - basic 0.42 0.43 2.08 1.75
- diluted 0.42 0.43 2.06 1.74
----------------------------------------------------------------------------
Net Income (loss) (74,853) 6,889 (53,319) 9,110
Per share - basic (1.05) 0.13 (0.87) 0.20
- diluted (1.05) 0.13 (0.87) 0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's increase in cash provided by operations and funds from operations
resulted from the Company's increased production and higher commodity prices in
2008. Net income was negatively impacted by the goodwill writedown in 2008.
Capital Expenditures and Acquisitions
During the fourth quarter, the Company drilled a total of 16 (9.8 net) wells
resulting in 12 (5.8 net) natural gas wells, three (3.0 net) oil wells and one
(1.0 net) service well. During 2008, Crew drilled a total of 53 (43.3 net) wells
resulting in 41 (31.3 net) natural gas wells, nine (9.0 net) oil wells, one (1.0
net) service well and two (2.0 net) dry and abandoned wells representing a
success rate of 96% (95% net). In addition, in the quarter, the Company
completed 21 (17.4 net) wells and recompleted six (5.6 net) wells. The Company
also added to its infrastructure, deploying 24% of its capital expenditures on
equipment and facilities primarily in the Princess, Alberta and Septimus,
British Columbia areas.
During 2008, Crew also added to its undeveloped land base acquiring 120 sections
of undeveloped land on its developing Triassic Montney natural resource play in
northeastern British Columbia.
Total exploration and development expenditures for 2008 were $191.7 million
compared to $102.1 million for the same period in 2007. The expenditures are
detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Land 1,148 7,080 25,317 14,756
Seismic 2,779 1,750 5,595 4,492
Drilling and completions 35,283 14,836 124,894 58,271
Facilities, equipment and pipelines 13,071 5,829 30,902 19,791
Other 1,331 1,538 4,969 4,782
----------------------------------------------------------------------------
Total exploration and development 53,612 31,033 191,677 102,092
Property acquisitions (dispositions) (245) (266) 70,414 (315)
----------------------------------------------------------------------------
Total 53,367 30,767 262,091 101,777
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In addition, in August 2008 the Company closed the acquisition of Gentry
Resources Ltd. which had the majority of its operations in the Princess, Alberta
area in southern Alberta. Details of the purchase price are included in the
Business Acquisition, note 3 to the Company's December 31, 2008 consolidated
financial statements. The acquisition added approximately 4,000 boe per day of
production, an estimated 12.3 million boe of proved and probable reserves and
280,000 acres of undeveloped land.
The Company's Board of Directors has approved an $80 million exploration and
development budget for 2009. However, as a result of the current economic
climate and the Company's desire to maintain a strong financial position, the
Company plans to adjust its capital expenditure program to remain within funds
from operations until commodity prices recover or alternative forms of financing
are available as discussed in Liquidity and Capital Resources section below.
LIQUIDITY AND CAPITAL RESOURCES
Capital Funding
On August 22, 2008 the Company issued 12,276,749 Common shares in exchange for
all of the issued and outstanding shares of Gentry. This acquisition has been
accounted for using the purchase method the details of which are included in
note 3 of the Company's December 31, 2008 consolidated financial statements.
In conjunction with the acquisition, the Company's credit facility with a
syndicate of banks (the "Syndicate") was increased to a revolving line of credit
of $270 million and an operating line of credit of $15 million (the "Facility").
The Facility revolves for a 364 day period and will be subject to its next 364
day extension by June 15, 2009. If not extended, the Facility will cease to
revolve, the margins there under will increase by 0.25 percent and all
outstanding balances under the Facility will become repayable within one year.
The available lending limits of the Facility are reviewed semi-annually and are
based on the Syndicate's interpretation of the Company's reserves and future
commodity prices. There can be no assurance that the amount of the available
Facility will not be adjusted at the next scheduled review on or before June 15,
2009. Borrowing margins and fees will also be reviewed as part of the
Syndicate's annual review prior to June 15, 2009. As a result of the current
economic environment and weak global credit market, it is expected that the
Company will incur increased margins and fees over those outlined in note 6 to
the financial statements. At December 31, 2008, the Company had drawings of
$223.6 million on the Facility and had issued letters of credit totaling $5.4
million of which $5.0 million expires by March 31, 2009.
On May 1, 2008, Crew issued 5,000,000 Common shares at an issue price of $13.35
per share for total net proceeds of approximately $63.1 million. The proceeds
were used to acquire 102.0 net sections of Montney rights in northeastern
British Columbia for $63.1 million.
On October 10, 2008 Crew filed notice with the Toronto Stock Exchange ("TSX") to
make a normal course issuer bid to purchase and cancel up to a maximum of
5,587,988 of the outstanding Common Shares of the Company. The bid commenced on
October 15, 2008 and will terminate on October 14, 2009. At December 31, 2008,
the Company has purchased and cancelled 110,000 shares at an average price of
$4.64 per share. The Company will pay for any additional Common shares acquired
under the bid at the prevailing market price on the TSX at the time of the
purchase.
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. See discussion under
"Capital Structure" below.
Working Capital
The capital intensive nature of Crew's activities generally results in the
Company carrying a working capital deficit. However, the Company maintains
sufficient unused bank credit lines to satisfy such working capital
deficiencies. At December 31, 2008, the Company's working capital deficiency
totaled $31.8 million which, when combined with the drawings on its bank line,
represented 89% of its current bank facility.
Share Capital
As at December 31, 2008, Crew had 71,083,668 Common Shares outstanding along
with 4,275,900 options to acquire Common Shares of the Company.
As at March 9, 2009, Crew had 71,083,668 Common Shares outstanding along with
5,754,000 options to acquire Common Shares of the Company.
Capital Structure
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. The Company monitors debt levels based on the
ratio of net debt to annualized funds from operations. The ratio represents the
time period it would take to pay off the debt if no further capital expenditures
were incurred and if funds from operations remained constant. This ratio is
calculated as net debt, defined as outstanding bank debt plus or minus net
working capital, divided by funds from operations for the most recent calendar
quarter, annualized (multiplied by four). The Company's strategy is to maintain
a ratio of no more than 2.0 to 1. This ratio may increase at certain times as a
result of acquisitions or low commodity prices.
As at December 31, 2008, the Company's ratio of net debt to annualized funds
from operations was 2.15 to 1 (2007 - 1.22 to 1). This amount has risen above
the preferred range of the Company as a result of the dramatic decrease in
commodity prices experienced in the second half of 2008 brought on by the recent
global recession. In order to maintain the integrity of the Company's financial
position the Company plans to adjust its capital expenditure program to remain
within funds from operations until commodity prices recover or an alternative
form of financing is consummated.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31,
($ thousands, except ratio) 2008
----------------------------------------------------------------------------
Accounts receivable 42,800
Accounts payable and accrued liabilities (74,622)
----------------------------------------------------------------------------
Working capital deficiency (31,822)
Bank loan (223,628)
----------------------------------------------------------------------------
Net debt (255,450)
Fourth quarter funds from operations 29,646
Annualized 118,584
Net debt to annualized funds from operations ratio 2.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contractual Obligations
Throughout the course of its ongoing business, the Company enters into various
contractual obligations such as credit agreements, purchase of services, royalty
agreements, operating agreements, processing agreements, right of way agreements
and lease obligations for office space and automotive equipment. All such
contractual obligations reflect market conditions prevailing at the time of
contract and none are with related parties. The Company believes it has adequate
sources of capital to fund all contractual obligations as they come due. The
following table lists the Company's obligations with a fixed term.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Total 2009 2010 2011
----------------------------------------------------------------------------
Bank Loan (note 1) 223,628 - 223,628 -
Operating Leases 2,722 990 990 742
Capital commitments 11,500 11,500 - -
Firm transportation agreements (note 2) 20,793 7,003 7,152 6,638
----------------------------------------------------------------------------
Total 258,643 19,493 231,770 7,380
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2010. However, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.
Note 2 - The firm transportation commitments were acquired as part of the
Company's May, 2007 private company acquisition and represent firm
service commitments for transportation and processing of natural
gas in British Columbia.
OUTLOOK
As the global recession continues to deepen and oil and natural gas prices
continue to show weakness Crew will move forward in a cautious and conservative
manner. In order to preserve the Company's financial position Crew is committed
to maintain or reduce debt levels by spending within funds from operations and
consider the disposition of non-core assets in order to focus its capital on the
Company's three resource plays.
In this regard, the Company has reduced its previously announced budgeted
capital expenditure program to $80 million for 2009 from the previously
announced $120 million. This amount includes the completion of the Company's
planned natural gas processing facility, the drilling of wells at Septimus and
Portage in northeast British Columbia and Strachan and Wapiti in Alberta. It
also includes the completion and tie-in of several wells in Alberta and British
Columbia that were drilled in 2008 as well as maintenance capital. As a result
of the reduction in the planned capital expenditures for the year, the Company
has reduced its production guidance to average approximately 14,500 boe per day
from the previously announced guidance of 15,500 boe per day. This updated
guidance assumes the three week turnaround of the Fort Nelson natural gas
processing facility which will affect approximately 970 boe per day of Crew's
production in June but represents an increase in year over year average
production growth of 25% and a 9% year over year increase in per share
production growth.
Over the past few months the Company has entered into the previously noted
derivative contracts to reduce the effect of falling commodity prices, a
strengthening Canadian dollar and an increase in interest rates from their
current levels on the Company. Crew will continue to monitor these markets and
if the opportunity arises will look to enter additional contracts in order to
protect the Company's future funds from operations.
ADDITIONAL DISCLOSURES
Risk Assessment
There are a number of risks facing participants in the Canadian oil and gas
industry. Some risks are common to all businesses while others are specific to
the Company. The following are a number of identifiable business risks faced by
Crew which will evolve and additional risks will emerge periodically. The risks
shown are those identified by management at the date of completion of this
report and may not describe all of the risks faced by the Company.
Global Financial Crisis
Recent market events and conditions, including disruptions in the international
credit markets and other financial systems and the deterioration of global
economic conditions, have caused significant volatility in commodity prices.
These conditions worsened in 2008 and are continuing in 2009, causing a loss of
confidence in the broader U.S. and global credit and financial markets and
resulting in the collapse of, and government intervention in, major banks,
financial institutions and insurers and creating a climate of greater
volatility, less liquidity, widening of credit spreads, a lack of price
transparency, increased credit losses and tighter credit conditions.
Notwithstanding various actions by governments, concerns about the general
condition of the capital markets, financial instruments, banks, investment
banks, insurers and other financial institutions caused the broader credit
markets to further deteriorate and stock markets to decline substantially. These
factors have negatively impacted company valuations and will impact the
performance of the global economy going forward.
Commodity prices are expected to remain volatile for the near future as a result
of market uncertainties over the supply and demand of these commodities due to
the current state of the world economies, OPEC actions and the ongoing global
credit and liquidity concerns.
Substantial Capital Requirements
The Company anticipates making substantial capital expenditures for the
acquisition, exploration, development and production of oil and natural gas
reserves in the future. As the Company's revenues may decline as a result of
decreased commodity pricing, it may be required to reduce capital expenditures.
In addition, uncertain levels of near term industry activity coupled with the
present global credit crisis exposes the Company to additional access to capital
risk. There can be no assurance that debt or equity financing, or funds
generated by operations will be available or sufficient to meet these
requirements or for other corporate purposes or, if debt or equity financing is
available, that it will be on terms acceptable to the Company. The inability of
the Company to access sufficient capital for its operations could have a
material adverse effect on the Company's business financial condition, results
of operations and prospects.
Third Party Credit Risk
The Company may be exposed to third party credit risk through its contractual
arrangements with its current or future joint venture partners, marketers of its
petroleum and natural gas production and other parties. In the event such
entities fail to meet their contractual obligations to the Company, such
failures may have a material adverse effect on the Company's business, financial
condition, results of operations and prospects. In addition, poor credit
conditions in the industry and of joint venture partners may impact a joint
venture partner's willingness to participate in the Company's ongoing capital
program, potentially delaying the program and the results of such program until
the Company finds a suitable alternative partner.
Quarterly Analysis
The following table summarizes the Company's key quarterly financial
results in 2008 and 2007:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per share Dec 31 Sept 30 June 30 Mar. 31
amounts) 2008 2008 2008 2008
----------------------------------------------------------------------------
Total daily production (boe/d) 14,869 11,505 9,445 10,614
Average wellhead price ($/boe) 42.99 61.74 70.18 53.20
Petroleum and natural gas sales 58,806 65,345 60,316 51,389
Cash provided by operations 25,700 36,208 31,908 29,540
Funds from operations 29,646 35,004 34,102 29,038
Per share - basic 0.42 0.54 0.60 0.54
- diluted 0.42 0.54 0.58 0.54
Net income (loss) (74,853) 15,178 5,415 941
Per share - basic (1.05) 0.24 0.09 0.02
- diluted (1.05) 0.23 0.09 0.02
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per share Dec. 31 Sept. 30 June 30 Mar. 31
amounts) 2007 2007 2007 2007
----------------------------------------------------------------------------
Total daily production (boe/d) 9,641 9,268 8,967 6,869
Average wellhead price ($/boe) 43.90 39.16 47.43 47.61
Petroleum and natural gas sales 38,942 33,390 38,703 29,431
Cash provided by operations 11,882 23,035 24,467 15,016
Funds from operations 22,390 21,171 20,885 16,987
Per share - basic 0.43 0.45 0.46 0.41
- diluted 0.43 0.44 0.46 0.41
Net income (loss) 6,889 (449) 1,351 1,319
Per share - basic 0.13 (0.01) 0.03 0.03
- diluted 0.13 (0.01) 0.03 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's petroleum and natural gas sales, cash provided by operations, funds from
operations and net income are all impacted by production levels and commodity
pricing. These performance measures have all fluctuated throughout 2007 and 2008
despite increasing production as a result of volatile oil and natural gas prices
combined with the increased cost of the Company's operations.
The following table summarizes Crew's key financial results over the past
three years:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except Year ended Year ended Year ended
per share amounts) Dec. 31, 2008 Dec. 31, 2007 Dec. 31, 2006
----------------------------------------------------------------------------
Petroleum and natural gas sales 235,856 140,466 92,813
Cash provided by operations 123,356 74,400 57,455
Funds from operations 127,790 81,433 56,658
Per share - basic 2.08 1.75 1.62
- diluted 2.06 1.74 1.59
Net income (loss) (53,319) 9,110 10,776
Per share - basic (0.87) 0.20 0.31
- diluted (0.87) 0.19 0.30
Daily production (boe/d) 11,617 8,696 5,695
Crew average sales price ($/boe) 55.47 44.45 44.65
Total assets 1,045,510 602,193 375,281
Working capital deficiency 31,822 14,643 17,714
Bank loan 223,628 95,028 41,157
Total other long-term liabilities 152,679 98,472 50,037
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 was impacted by a scheduled third
party facility shutdown which disrupted approximately 1,400 boe per day of
production for three weeks in June. Production in the second quarter was also
impacted by several other non-scheduled facility outages.
- In August, 2008, the Company acquired Gentry Resources Inc. with approximately
4,000 boe per day of production at closing.
- In May, 2007, the Company acquired a private oil and gas company with
approximately 3,100 boe per day of production at closing, consisting mainly of
natural gas in the northeastern British Columbia area.
- Production in the third and fourth quarter of 2007 was reduced by significant
facility outages at Sierra in northeastern British Columbia and Edson and
Ferrier, Alberta.
- Revenue and royalties are significantly impacted by underlying commodity
prices. The Company utilizes a limited amount of derivative contracts and
forward sales contracts to reduce the exposure to commodity price fluctuations.
- Throughout 2007 and 2008, the Company's operating costs, general and
administrative costs and capital expenditures have been subject to inflationary
pressures brought on by increasing demand for services and supplies within the
Canadian oil and gas industry.
- During the quarter ended September 30, 2007 the Company's funds from
operations and net income were positively impacted by the one time receipt of
Alberta deep well royalty holiday credits and 2006 Alberta gas cost allowance
adjustments totalling $4.0 million.
- In the fourth quarter of 2008, Crew performed an impairment test on its
goodwill and determined that its carrying value exceeded its fair value and
therefore an impairment charge of $69.1 million was required.
- During the first three quarters of 2008, the Company experienced volatility in
its net income as a result of unrealized gains and losses on commodity
derivative contracts held for risk management purposes.
- In the fourth quarter of 2007, Crew had a future tax recovery which positively
affected net income due to Canadian provincial and federal government tax rate
reductions.
Dated as of March 9, 2009
Cautionary Statements
Unaudited financial information
Certain financial and operating information included in this press release for
the quarter and year ended December 31, 2008, such as finding and development
costs, production information, recycle ratios, operating netbacks and net asset
value, are based on estimated unaudited financial results for the quarter and
year then ended, and are subject to the same limitations as discussed under
Forward Looking Information set out below. These estimated amounts may change
upon the completion of audited financial statements for the year ended December
31, 2008 and changes could be material.
Forward-looking information and statements
This news release contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of any of the words
"expect", "anticipate", "continue", "estimate", "may", "will", "project",
"should", "believe", "plans", "intends" and similar expressions are intended to
identify forward-looking information or statements. In particular, but without
limiting the forgoing, this news release contains forward-looking information
and statements pertaining to the following: the volumes and estimated value of
Crew's oil and gas reserves; the life of Crew's reserves; resource estimates;
the volume and product mix of Crew's oil and gas production; future oil and
natural gas prices and Crew's commodity risk management programs; future
liquidity and financial capacity; future results from operations and operating
metrics; future costs, expenses and royalty rates; future interest costs; the
exchange rate between the $US and $Cdn; future development, exploration,
acquisition and development activities and related capital expenditures; the
number of wells to be drilled and completed; the amount and timing of capital
projects; operating costs; the total future capital associated with development
of reserves and resources; and forecast reductions in operating expenses.
The recovery, reserve and resources estimates of Crew's reserves and resources
provided herein are estimates only and there is no guarantee that the estimated
reserves or resources with be recovered. In addition, forward-looking statements
or information are based on a number of material factors, expectations or
assumptions of Crew which have been used to develop such statements and
information but which may prove to be incorrect. Although Crew believes that the
expectations reflected in such forward-looking statements or information are
reasonable, undue reliance should not be placed on forward-looking statements
because Crew can give no assurance that such expectations will prove to be
correct. In addition to other factors and assumptions which may be identified
herein, assumptions have been made regarding, among other things: the impact of
increasing competition; the general stability of the economic and political
environment in which Crew operates; the timely receipt of any required
regulatory approvals; the ability of Crew to obtain qualified staff, equipment
and services in a timely and cost efficient manner; drilling results; the
ability of the operator of the projects in which Crew has an interest in to
operate the field in a safe, efficient and effective manner; the ability of Crew
to obtain financing on acceptable terms; field production rates and decline
rates; the ability to replace and expand oil and natural gas reserves through
acquisition, development and exploration; the timing and cost of pipeline,
storage and facility construction and expansion and the ability of Crew to
secure adequate product transportation; future commodity prices; currency,
exchange and interest rates; regulatory framework regarding royalties, taxes and
environmental matters in the jurisdictions in which Crew operates; and the
ability of Crew to successfully market its oil and natural gas products.
The forward-looking information and statements included in this news release are
not guarantees of future performance and should not be unduly relied upon. Such
information and statements; including the assumptions made in respect thereof,
involve known and unknown risks, uncertainties and other factors that may cause
actual results or events to defer materially from those anticipated in such
forward-looking information or statements including, without limitation: changes
in commodity prices; changes in the demand for or supply of Crew's products;
unanticipated operating results or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters; changes in
development plans of Crew or by third party operators of Crew's properties,
increased debt levels or debt service requirements; inaccurate estimation of
Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack
of access to capital markets; increased costs; a lack of inadequate insurance
coverage; the impact of competitors; and certain other risks detailed from
time-to-time in Crew's public disclosure documents, (including, without
limitation, those risks identified in this news release and Crew's Annual
Information Form).
The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Crew does not assume any
obligation to publicly update or revise any of the included forward-looking
statements or information, whether as a result of new information, future events
or otherwise, except as may be required by applicable securities laws.
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
Discovered Petroleum Initially in Place
This press release contains references to estimates of gas classified as
Discovered Petroleum initially in Place (DPIP) in the Company's Septimus area in
British Columbia which are not, and should not be confused with oil and gas
reserves. "Discovered Petroleum Initially in Place" is defined in the Canadian
Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of
hydrocarbons that are estimated, as of a given date, to be contained in known
accumulations. DPIP is divided into recoverable and unrecoverable portions, with
the estimated future recoverable portion classified as reserves and contingent
resources. There is no certainty that it will be commercially viable or
technically feasible to produce any portion of this discovered petroleum
initially in place except to the extent identified as proved or probable
reserves. Resources do not constitute, and should not be confused with,
reserves.
There are a number of assumptions associated with the development of the
Company's lands at Septimus relating to performance from new and existing wells,
future drilling programs, the lack of infrastructure, well density per section,
recovery factors and development necessarily involves known and unknown risks
and uncertainties, including those risks identified in this press release.
Crew is a junior 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 and years ended December 31,
2008 and 2007 are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2008 2007
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 42,800 $ 28,588
Fair value of financial instruments (note 10) 1,255 -
Future income taxes (note 12) 15 -
----------------------------------------------------------------------------
44,070 28,588
Property, plant and equipment (note 4) 1,001,440 552,805
Goodwill (note 5) - 20,800
----------------------------------------------------------------------------
$ 1,045,510 $ 602,193
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 74,622 $ 43,231
Fair value of financial instruments (note 10) - 423
Current portion of other long-term
obligations (note 7) 1,313 1,313
----------------------------------------------------------------------------
75,935 44,967
Bank loan (note 6) 223,628 95,028
Other long-term obligations (note 7) 1,446 2,759
Asset retirement obligations (note 8) 34,941 18,668
Future income taxes (note 12) 116,292 77,045
Shareholders' Equity
Share capital (note 9) 575,191 298,129
Contributed surplus (note 9) 16,356 10,557
Retained earnings 1,721 55,040
----------------------------------------------------------------------------
593,268 363,726
Commitments (note 14)
----------------------------------------------------------------------------
$ 1,045,510 $ 602,193
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Operations, Comprehensive Income (Loss) and
Retained Earnings
(unaudited)
(thousands, except per share amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas
sales $ 58,806 $ 38,942 $235,856 $140,466
Royalties (12,035) (6,929) (49,961) (23,749)
Gain (loss) on financial
instruments (note 10) 2,777 (408) 1,933 588
Other income - 210 268 210
----------------------------------------------------------------------------
49,548 31,815 188,096 117,515
Expenses
Operating 13,952 5,634 37,520 19,763
Transportation 2,607 1,779 8,924 6,603
General and administrative 1,242 970 4,169 3,331
Interest 1,970 1,882 7,085 6,808
Stock-based compensation 589 758 3,332 2,662
Depletion, depreciation
and accretion 35,329 20,489 104,866 75,427
Write-down of goodwill
(note 5) 69,071 - 69,071 -
----------------------------------------------------------------------------
124,760 31,512 234,967 114,594
----------------------------------------------------------------------------
Income (loss) before
income taxes (75,212) 303 (46,871) 2,921
Future income taxes
(reduction) (note 12) (359) (6,586) 6,448 (6,189)
----------------------------------------------------------------------------
Net income (loss) and
comprehensive income (loss) (74,853) 6,889 (53,319) 9,110
Retained earnings,
beginning of period 76,574 48,151 55,040 45,930
----------------------------------------------------------------------------
Retained earnings, end of
period $ 1,721 $ 55,040 $ 1,721 $ 55,040
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per
share (note 9(e))
Basic $ (1.05) $ 0.13 $ (0.87) $ 0.20
Diluted $ (1.05) $ 0.13 $ (0.87) $ 0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Cash Flows
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Net income (loss) $ (74,853) $ 6,889 $(53,319) $ 9,110
Items not involving cash:
Depletion, depreciation and
accretion 35,329 20,489 104,866 75,427
Write-down of goodwill (note 5) 69,071 - 69,071 -
Stock-based compensation 589 758 3,332 2,662
Future income taxes
(reduction) (359) (6,586) 6,448 (6,189)
Unrealized (gain) loss on
financial instruments (131) 840 (2,608) 423
Transportation liability
charge (note 7) (328) (313) (1,313) (784)
Asset retirement expenditures (152) (205) (775) (237)
Change in non-cash working
capital (note 13) (3,466) (9,990) (2,346) (6,012)
----------------------------------------------------------------------------
25,700 11,882 123,356 74,400
Financing activities:
Increase (decrease) in bank
loan 44,578 (44,363) 60,396 54,217
Issue of common shares - 54,606 69,846 113,880
Repurchase of common shares (514) - (514) -
Share issue costs - (2,988) (3,654) (6,315)
----------------------------------------------------------------------------
44,064 7,255 126,074 161,782
Investing activities:
Exploration and development (53,612) (31,033) (191,677) (102,092)
Property acquisitions, net of
dispositions 245 266 (70,414) 315
Business acquisitions (note 3) - 405 (1,500) (136,920)
Change in non-cash working
capital (note 13) (16,397) 11,225 14,161 2,515
----------------------------------------------------------------------------
(69,764) (19,137) (249,430) (236,182)
----------------------------------------------------------------------------
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 and years ended December 31, 2008 and 2007
(Unaudited)
(Tabular amounts in thousands)
1. Significant accounting policies:
The consolidated financial statements of Crew Energy Inc. ("Company") have been
prepared by management in accordance with Canadian generally accepted accounting
principles. Since the determination of certain assets, liabilities, revenues and
expenses is dependent upon future events, the preparation of these financial
statements requires the use of estimates and assumptions, which have been made
with careful judgement. Specifically, the amounts recorded for depletion and
depreciation of property, plant and equipment and the provision for asset
retirement obligations and abandonment costs are based on estimates. The ceiling
test is based on estimates of reserves, future production rates, future
petroleum and natural gas prices, future costs and other relevant assumptions.
The amounts for stock-based compensation are based on estimates of risk-free
rates, expected option life and volatility. Future incomes taxes are based on
estimates as to the timing of the reversal of temporary differences and tax
rates currently substantively enacted. The fair value of derivative contracts
are based on the discounted value of the market for future commodity prices,
interest rates and the exchange rate between United States and Canadian dollars.
By their nature, these estimates and amounts are subject to measurement
uncertainty and the effect on the financial statements of such changes in such
estimates in future periods could be significant. In the opinion of management,
these financial statements have been properly prepared in accordance with
Canadian generally accepted accounting principles within reasonable limits of
materiality and within the framework of the significant accounting policies
summarized below.
(a) Principles of consolidation:
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiaries, Crew Resources Inc., Gentry Resources Ltd.
("Gentry"), and a partnership, Crew Energy Partnership. On January 1, 2009,
Gentry was amalgamated into Crew Energy Inc. All inter-entity balances and
transactions have been eliminated.
(b) Cash and cash equivalents:
Cash and cash equivalents include monies on deposit and highly liquid short-term
investments having a maturity date of not more than 90 days.
(c) Petroleum and natural gas properties:
The Company follows the full cost method of accounting for petroleum and natural
gas properties, whereby all costs of exploring for and developing petroleum and
natural gas properties and related reserves are capitalized. Capitalized costs
include land acquisition costs, geological and geophysical expenses, cost of
drilling both productive and non-productive wells, production facilities, the
fair value of asset retirement obligations and related overhead expenses.
Capitalized costs, excluding costs relating to unproved properties, are depleted
using the unit-of-production method based on estimated proved reserves of
petroleum and natural gas before royalties determined using forecast product
prices and as determined by independent petroleum engineers. For purposes of the
depletion calculation, natural gas reserves and production are converted to
equivalent volumes of crude oil based on relative energy content of six thousand
cubic feet of gas to one barrel of oil. Proceeds from the sale of petroleum and
natural gas properties are applied against capitalized costs, with no gain or
loss recognized unless such a sale would alter depletion by more than 20%.
The cost of acquiring unproved properties are initially excluded from depletion
calculations. These unevaluated properties are assessed periodically for
impairment. When proved reserves are assigned or the property is considered
impaired the costs of the property or the amount of impairment is added to the
costs subject to depletion.
Petroleum and natural gas assets are evaluated in each reporting period (the
"ceiling test") to determine that the carrying amount in a cost centre is
recoverable and does not exceed the fair value of the properties in the cost
centre. The carrying amounts are assessed to be recoverable if the sum of the
undiscounted cash flows expected from the production of proved reserves, the
lower of cost and market of unproved properties and the cost of major
development projects exceeds the carrying amount of the cost centre. When the
carrying amount is not assessed to be recoverable, an impairment loss is
recognized to the extent that the carrying amount of the cost centre exceeds the
sum of the discounted cash flows expected from the production of proved and
probable reserves, the lower of cost and market of unproved properties and the
cost of major development projects of the cost centre. The cash flows are
estimated using forecast product prices and costs and are discounted using a
risk-free interest rate.
(d) Goodwill
Goodwill is the residual amount that results when the purchase price of a
business exceeds the fair value of the net identifiable assets and liabilities
acquired. Goodwill is stated at cost and is not amortized. The goodwill balance
is assessed for impairment each year end or more frequently if events or changes
in circumstances indicate that the asset may be impaired. The test for
impairment is conducted by comparing the book value to the fair value of the
reporting entity. Impairment is charged to income in the period it occurs.
(e) Interest in joint operations:
A portion of the Company's petroleum and natural gas exploration and development
activity is conducted jointly with others and, accordingly, the financial
statements reflect only the Company's proportionate interest in such activities.
(f) Asset retirement obligations:
The fair value of the liability for the Company's asset retirement obligation is
recorded in the period in which it is incurred, discounted to its present value
using Crew's credit adjusted risk-free interest rate and the corresponding
amount is recognized by increasing the carrying amount of the petroleum and
natural gas properties. The liability is accreted each period, and the
capitalized cost is depreciated over the useful life of the related petroleum
and natural gas properties. Revisions to the estimated timing of cash flows or
to the original estimated undiscounted cost would result in an increase or
decrease to the asset retirement obligation. Actual costs incurred upon
settlement of the asset retirement obligation are charged against the asset
retirement obligation.
(g) Revenue recognition:
Revenue from the sale of petroleum and natural gas are recorded when title
passes to a third party.
(h) Financial instruments:
A financial instrument is any contract that gives rise to a financial asset of
one entity and a financial liability or equity instrument to another entity.
Upon initial recognition all financial instruments, including all derivatives,
are recognized on the balance sheet at fair value. Subsequent measurement is
then based on the financial instruments being classified into one of five
categories: held for trading, held to maturity, loans and receivables, available
for sale and other liabilities. The Company has designated its cash and cash
equivalents as held for trading which are measured at fair value.
Accounts receivable are classified as loans and receivables which are measured
at amortized cost. Accounts payable and accrued liabilities and the bank loan
are classified as other liabilities which are measured at amortized cost, which
is determined using the effective interest method.
The Company will assess at each reporting period whether its financial assets
are impaired.
The Company is exposed to market risks resulting from fluctuations in commodity
prices, foreign exchange rates and interest rates in the normal course of
operations. A variety of derivative instruments may be used by the Company to
reduce its exposure to fluctuations in commodity prices, foreign exchange rates,
and interest rates. The Company does not use these derivative instruments for
trading or speculative purposes. The Company considers all of these transactions
to be economic hedges, however, the majority of the Company's contracts do not
qualify or have not been designated as hedges for accounting purposes.
As a result, all derivative contracts are classified as held for trading and are
recorded on the balance sheet at fair value, with changes in the fair value
recognized in net income, unless specific hedge criteria are met. The fair
values of these derivative instruments are based on an estimate of the amounts
that would have been received or paid to settle these instruments prior to
maturity given future market prices and other relevant factors. Proceeds and
costs realized from holding the derivative contracts are recognized in net
income at the time each transaction under a contract is settled.
The Company measures and recognizes embedded derivatives separately from the
host contracts when the economic characteristics and risks of the embedded
derivative are not closely related to those of the host contract, when it meets
the definition of a derivative and when the entire contract is not measured at
fair value. Embedded derivatives are recorded at fair value.
The Company immediately expenses all transaction costs incurred in relation to
the acquisition of a financial asset or liability. The bank loan is presented
net of deferred interest payments, with interest recognized in net income on an
effective interest basis.
The Company applies trade-date accounting for the recognition of a purchase or
sale of cash equivalents and derivative contracts.
(i) Flow through shares:
Flow through shares are issued at a fixed price and the proceeds are used to
fund qualifying exploration expenditures within a defined period. The
expenditures funded by flow through arrangements are renounced to investors in
accordance with income tax legislation. Share capital is reduced and future
income tax liability is increased by the total estimated future income tax costs
of the renounced income tax deductions in the period of renouncement.
(j) Per share amounts:
Basic per share amounts are calculated using the weighted average number of
shares outstanding during the period. Diluted per share amounts are calculated
based on the treasury-stock method, which assumes that any proceeds obtained on
exercise of options, warrants and performance shares would be used to purchase
common shares at the average market price. The weighted average number of shares
outstanding is then adjusted by the net change.
(k) Stock-based compensation plans:
The Company accounts for its stock-based compensation program, which includes
stock options, using the fair value method. Under this method compensation
expense related to these programs is recorded in net income over the vesting
period with a corresponding increase in contributed surplus. Consideration
received on the exercise of stock options together with the amount previously
recognized in contributed surplus is credited to share capital.
(l) Income taxes:
The Company uses the asset and liability method of accounting for future income
taxes. The future income tax asset or liability is calculated assuming the
financial assets and liabilities will be settled at their carrying amount. This
amount is compared to the income tax assets and the difference is multiplied by
the substantively enacted income tax rate when the temporary differences are
expected to reverse.
(m) Comparative amounts:
Certain comparative amounts have been reclassified to conform with presentation
adopted in the current year.
2. Changes in accounting policy:
Financial Instruments
On January 1, 2008, the Company adopted CICA Handbook Section 3862, "Financial
Instruments - Disclosures", and Section 3863, "Financial Instruments -
Presentation". Section 3862 and 3863 establish standards for the presentation
and disclosure of information that enable users to evaluate the significance of
financial instruments to the entity's financial position, and the nature and
extent of risks arising from financial instruments and how the entity manages
these risks. The implementation of these standards did not impact the Company's
financial results; however it did result in additional disclosure presented in
note 10.
Capital Disclosures
On January 1, 2008, the Company adopted CICA Handbook Section 1535 "Capital
Disclosures". Section 1535 establishes standards for disclosing information
about an entity's capital and how it is managed. This section specifies
disclosure about objectives, policies and processes for managing capital,
quantitative data about what an entity regards as capital, whether an entity has
complied with all capital requirements, and if it has not complied, the
consequences of such non-compliances. The implementation of this standard did
not impact the Company's financial results; however it did result in additional
disclosure presented in note 11.
Future Accounting Pronouncements
Goodwill and intangible assets
In February 2008, the CICA issued Section 3064, Goodwill and Intangible Assets.
Effective for fiscal years beginning on or after October 1, 2008, this section
provides guidance on the recognition, measurement, presentation and disclosure
for goodwill and intangible assets, other than the initial recognition of
goodwill or intangible assets acquired in a business combination. Retroactive
application to prior-period financial statements will be required. The Company
is still assessing the impact of this new standard on its financial statements.
Business combinations
In January 2009, the CICA issued Section 1582, Business Combinations. This
section is effective January 1, 2011 and applies prospectively to business
combinations for which the acquisition date is on or after the first annual
reporting period beginning on or after January 1, 2011 for the Company. Early
adoption is permitted. This section replaces Section 1581, Business Combination
and harmonizes the Canadian standards with IFRS.
International financial reporting standards
In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the
changeover to IFRS from Canadian GAAP will be required for publicly accountable
enterprises for interim and annual financial statements effective for fiscal
years beginning on or after January 1, 2011, including comparatives for 2010.
The International Accounting Standards Board ("IASB") has also issued an
exposure draft relating to certain amendments and exemptions to IFRS 1. It is
anticipated that this exposure draft will not result in an amended IFRS 1
standard until late 2009.
The amendment, if implemented, will permit the Company to apply IFRS
prospectively by utilizing its current reserves at the transition date to
allocate the Company's full cost pool, with the provision that a ceiling test,
under IFRS standards, be conducted at the transition date.
Although the amended IFRS 1 standard would provide relief, the changeover to
IFRS represents a significant change in accounting standards and the transition
from current Canadian GAAP to IFRS will be a significant undertaking that may
materially affect the Company's reported financial position and reported results
of operations.
In response, the Company has completed its high-level IFRS changeover plan and
established a preliminary timeline for the execution and completion of the
conversion project. The changeover plan was determined following a preliminary
assessment of the differences between Canadian GAAP and IFRS and the potential
effects of IFRS to accounting and reporting processes, information systems,
business processes and external disclosures. This assessment has provided
insight into what are anticipated to be the most significant areas of difference
applicable to the Company.
During the next phase of the project, scheduled to take place during 2009, the
Company will perform an in-depth review of the significant areas of difference,
identified during the preliminary assessment, in order to identify all specific
Canadian GAAP and IFRS differences and select ongoing IFRS policies. Key areas
addressed will also be reviewed to determine any information technology issues,
the impact on internal controls over financial reporting and the impact on
business activities including the effect, if any, on covenants and compensation
arrangements. External advisors have been retained and will assist management
with the project on an as needed basis. Staff training programs will commence in
2009 and be ongoing as the project unfolds.
The Company will also continue to monitor standards development as issued by the
IASB and the AcSB as well as regulatory developments as issued by the Canadian
Securities Administrators, which may affect the timing, nature or disclosure of
its adoption of IFRS.
3. Business acquisitions:
On August 22, 2008, Crew acquired all of the issued and outstanding shares of
Gentry. As consideration, Crew issued an aggregate of 12,276,749 common shares
at an ascribed value of $17.49 per share. The ascribed value per share was
determined based on Crew's five-day weighted average trading price before and
after the announcement of the acquisition on June 23, 2008. The operating
results of Gentry were included in the accounts of the Company from August 22,
2008.
The acquisition has been accounted for using the purchase method of
accounting as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Consideration
Shares issued $ 214,714
Transaction costs 1,500
----------------------------------------------------------------------------
$ 216,214
Net assets received at fair value
Property, plant and equipment 283,731
Goodwill 48,271
Working capital deficiency (5,364)
Fair value of financial instruments (930)
Bank loan (68,204)
Asset retirement obligations (13,854)
Future income taxes (27,436)
----------------------------------------------------------------------------
$ 216,214
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The above amounts are estimates made by management based on currently available
information. Amendments may be made to the purchase equation as the cost
estimates and balances are finalized.
As at August 22, 2008, Gentry had accounts receivable from SemGroup LP totaling
$4.6 million. On July 22, 2008, SemGroup LP filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code and two of SemGroup LP's Canadian
subsidiaries, SemCanada Energy Company and SemCanada Crude Company (collectively
"SemCanada"), filed for creditor protection in Canada. As a result, the Company
has provided an allowance for doubtful accounts totaling $4.6 million in the
above purchase equation for amounts outstanding from SemCanada.
In May, 2007, Crew acquired all of the issued and outstanding shares of a
private oil and gas company with producing oil and natural gas properties in
northeast British Columbia and central Alberta. Total consideration paid for the
acquisition was approximately $137.1 million which was financed through a
financing and a credit facility. The operating results of the acquired company
were included in the accounts of Crew from May 3, 2007.
The acquisition has been accounted for using the purchase method of
accounting as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Consideration
Cash $ 136,775
Transaction costs 276
----------------------------------------------------------------------------
$ 137,051
Net assets received at fair value
Income tax receivable 6,159
Property and equipment 182,397
Goodwill 6,242
Working capital deficiency (includes cash of $131) (6,108)
Excess transportation obligation (note 7) (4,856)
Asset retirement obligations (6,646)
Future income taxes (40,137)
----------------------------------------------------------------------------
$ 137,051
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The income tax receivable relates to non-capital loss carrybacks from the
acquired company's May 3, 2007 and December 31, 2006 tax returns. These amounts
were pledged to the vendor upon receipt by the Company. As at December 31, 2008,
the Company had received the full $6.159 million and forwarded it to the vendor.
The income tax receivable is offset by an equivalent amount included in accounts
payable.
4. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
December 31, 2008 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $1,249,859 $ 248,419 $1,001,440
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
December 31, 2007 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 698,251 $ 145,446 $ 552,805
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The cost of unproved properties at December 31, 2008 of $170,453,000 (2007 -
$40,359,000) was excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $108,258,000 (2007 - $31,057,000) have been included in the
depletion calculation and estimated salvage values of $38,514,000 (2007 -
$21,231,000) have been excluded from the depletion calculation.
On May 12, 2008, the Company acquired certain working interests in undeveloped
land for cash proceeds of $63.1 million.
The following corporate expenses related to exploration and development
activities were capitalized:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, December 31,
2008 2007
----------------------------------------------------------------------------
General and administrative expense $ 4,169 $ 3,331
Stock-based compensation expense, including
future income taxes 4,485 3,624
----------------------------------------------------------------------------
$ 8,654 $ 6,955
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew performed a ceiling test as at December 31, 2008. Based on the calculation,
the carrying values of the Company's property, plant and equipment are less than
the sum of the undiscounted cash flows of the Company's proved reserves based on
the following benchmark and Company prices.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
WTI F/X Edmonton Company Company
Oil Rate Oil Liquids AECO Gas Gas
Years ($US/Bbl) ($Cdn/$US) ($/bbl) ($/bbl) ($/mmbtu) ($/mcf)
----------------------------------------------------------------------------
2009 $ 57.50 0.825 $ 68.61 $46.44 $7.58 $ 7.53
2010 $ 68.00 0.850 $ 78.94 $56.04 $7.94 $ 8.00
2011 $ 74.00 0.875 $ 83.54 $59.60 $8.34 $ 8.43
2012 $ 85.00 0.925 $ 90.92 $64.19 $8.70 $ 8.80
2013 $ 92.01 0.950 $ 95.91 $67.32 $8.95 $ 9.13
2014 $ 93.85 0.950 $ 97.84 $68.42 $9.14 $ 9.30
2015 $ 95.73 0.950 $ 99.82 $69.76 $9.34 $ 9.51
2016 $ 97.64 0.950 $101.83 $71.15 $9.54 $ 9.73
2017 $ 99.59 0.950 $103.89 $72.72 $9.75 $ 9.96
2018 $101.59 0.950 $105.99 $74.75 $9.95 $10.17
Annual escalation thereafter +2.0%/yr.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. Goodwill:
The Company reviewed the valuation of goodwill as of December 31, 2008 and
determined that the fair value of the reporting entity had declined. Based upon
this review, an impairment of goodwill of $69.1 million (2007 - nil) has been
recorded as a non-cash charge to net income as of December 31, 2008. There has
been no impairment to the value of Crew's petroleum and natural gas assets
during 2008.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2008 2007
----------------------------------------------------------------------------
Balance, beginning of year $ 20,800 $ 14,558
Business acquisitions (note 3) 48,271 6,242
Goodwill impairment recognized (69,071) -
----------------------------------------------------------------------------
Balance, end of year $ - $ 20,800
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Bank loan:
The Company's bank facility consists of a revolving line of credit of $270
million and an operating line of credit of $15 million (the "Facility"). The
Facility revolves for a 364 day period and will be subject to its next 364 day
extension by June 15, 2009. If not extended, the Facility will cease to revolve,
the margins there under will increase by 0.25 per cent and all outstanding
advances there under will become repayable in one year. The available lending
limits of the Facility are reviewed semi-annually and are based on the bank
syndicate's interpretation of the Company's reserves and future commodity
prices. There can be no assurance that the amount of the available Facility will
not be adjusted at the next scheduled review on or before June 15, 2009.
Advances under the Facility are available by way of prime rate loans with
interest rates of up to 0.75 per cent over the bank's prime lending rate and
bankers' acceptances and LIBOR loans which are subject to stamping fees and
margins ranging from 0.95 per cent to 1.75 per cent depending upon the debt to
EBITDA ratio of the Company calculated at the Company's previous quarter end. As
at December 31, 2008, the Company's applicable pricing included a 0.10 percent
margin on prime lending and a 1.10 percent stamping fee and margin on Bankers'
Acceptances and LIBOR loans along with a 0.20 percent per annum standby fee on
the portion of the facility that is not drawn. Borrowing margins and fees will
be reviewed as part of the bank syndicate annual renewal prior to June 15, 2009.
The facility is secured by a first floating charge debenture over the Company's
consolidated assets. At December 31, 2008, the Company had issued letters of
credit totaling $5.4 million of which $5.0 million expires by March 31, 2009.
The effective interest rate on the Company's borrowings under its bank facility
for the period ended December 31, 2008 was 4.9% (2007 - 6.4%).
7. Other long-term obligations:
As part of the May 3, 2007 private company acquisition (note 3), 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. This charge for the three and twelve months ended December 31, 2008
was $0.3 million and $1.3 million, respectively (2007 - $0.3 million and $0.8
million).
8. 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 obligations as at December 31, 2008 to be $34,941,000 (2007 -
$18,668,000) based on a total future liability of $67,588,000 (2007 -
$35,166,000). These payments are expected to be made over the next 30 years. An
8% to 10% (2007 - 8%) credit adjusted risk free discount rate and 2% (2007 - 2%)
inflation rate were used to calculate the present value of the asset retirement
obligation.
The following table reconciles Crew's asset retirement obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, December 31,
2008 2007
----------------------------------------------------------------------------
Carrying amount, beginning of year $ 18,668 $ 10,485
Liabilities incurred 1,228 845
Liabilities acquired (note 3) 13,927 6,646
Accretion expense 1,893 929
Liabilities settled (775) (237)
----------------------------------------------------------------------------
Carrying amount, end of year $ 34,941 $ 18,668
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. Share capital:
(a) Authorized:
Unlimited number of Common Shares
1,881,000 Class C non-voting performance shares ("performance shares")
(b) Common Shares issued:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
shares Amount
----------------------------------------------------------------------------
Common Shares, December 31, 2006 41,440 $ 192,810
Public offering issued for cash 9,932 93,725
Public offering of flow through shares issued
for cash 1,860 20,000
Exercise of Class C performance shares 315 4
Exercise of stock options 30 155
Stock-based compensation - 333
Share issue costs, net of income taxes of $1,818 - (4,497)
Flow through shares income tax adjustment on 2006
issuance - (4,401)
----------------------------------------------------------------------------
Common Shares, December 31, 2007 53,577 $ 298,129
Business acquisition (note 3) 12,277 214,714
Public offering issued for cash 5,000 66,750
Exercise of stock options 340 3,096
Shares repurchased under normal course issuer bid (110) (890)
Stock-based compensation - 1,241
Share issue costs, net of future income taxes
of $1,005 - (2,649)
Flow through shares income tax adjustment on 2007
issuance - (5,200)
----------------------------------------------------------------------------
Common Shares, December 31, 2008 71,084 $ 575,191
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On October 10, 2008 Crew filed notice with the Toronto Stock Exchange ("TSX") to
make a normal course issuer bid to purchase and cancel up to a maximum of
5,587,988 of the outstanding Common Shares of the Company. The bid ("NCIB")
commenced on October 15, 2008 and will terminate on October 14, 2009. The
Company will pay for any Common Shares acquired under the bid at the prevailing
market price on the TSX at the time of the purchase. During the period and year
ended December 31, 2008 the Company repurchased and cancelled 110,000 Common
Shares at a net cost of $0.5 million. The average carrying value of the Common
Shares repurchased of $0.9 million was charged to share capital with the excess
of $0.4 million included in contributed surplus.
In conjunction with the Company's August 22, 2008 acquisition (note 3), the
Company issued 12,276,749 Common Shares to Gentry shareholders in exchange for
100% of the Gentry common shares.
On May 1, 2008, Crew issued 5,000,000 Common Shares at $13.35 per share for
aggregate proceeds of $66.8 million ($63.1 million net of issue costs). The
proceeds were used to acquire certain working interests in undeveloped land as
presented in note 4.
On October 25, 2007, the Company closed a public offering resulting in the
issuance of 6,042,360 shares for aggregate proceeds of $54.5 million ($51.5
million net of issue costs). Of the shares issued, 1,860,500 shares were issued
on a flow through basis in which the Company committed to renounce to the
purchasers certain Canadian income tax deductions totaling $20.0 million. At
December 31, 2008, the Company had renounced all required income tax deductions
and had incurred all qualifying expenditures under this flow through offering.
In conjunction with the Company's private company acquisition on May 3, 2007
(note 3), Crew issued 5,750,000 Common Shares at $10.30 per share for aggregate
gross proceeds of $59.2 million ($56 million net of issue costs).
(c) Contributed Surplus:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Contributed surplus, December 31, 2006 $ 5,566
Stock-based compensation 5,324
Conversion of Class C performance shares and stock options (333)
----------------------------------------------------------------------------
Contributed surplus, December 31, 2007 $ 10,557
Stock-based compensation 6,664
Excess of Common Share redemption amount over Common
Share carrying amount 376
Exercise of stock options (1,241)
----------------------------------------------------------------------------
Contributed surplus, December 31, 2008 $ 16,356
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(d) Stock-based compensation:
The Company measures compensation costs associated with stock-based compensation
using the fair market value method and 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: risk free interest rate 4.05% (2007 - 4.20%),
expected life 4 years (2007 - 4 years), volatility 45% (2007 - 45%), and an
expected dividend of nil (2007 - 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 2008 the Company recorded $6,664,000, (2007 - $5,324,000) of stock-based
compensation expense related to the stock options, of which $3,332,000 (2007 -
$2,662,000) was capitalized in accordance with the Company's full cost
accounting policy. As stock-based compensation is non-deductible for income tax
purposes, a future income tax liability of $1,153,000 (2007 - $962,000)
associated with the current year's capitalized stock-based compensation has been
recorded.
(i) Performance shares
On September 1, 2003 the Company issued 1,881,000 performance shares to
employees, officers and directors at a price of $0.01 per share. Each
performance share was convertible into a fraction of a Common Share over a
three-year period with the conversion rights expiring on September 1, 2007. On
conversion, each performance share converted at the rate determined by
subtracting $1.65 from the current market price of the Company's Common Shares
and dividing the result by the current market price of the Company's Common
Shares. The fair value of the performance shares at the date of issue, as
calculated by the Black-Scholes method, was $0.67 per share. All remaining
performance shares were converted in 2007 and cannot be re-issued.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
shares Amount
----------------------------------------------------------------------------
Class C, performance shares, December 31, 2006 402 $ 4
Converted to Common Shares during 2007 (402) (4)
----------------------------------------------------------------------------
Class C, performance shares, December 31, 2007
and 2008 - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) Stock options
The Company has a floating stock option plan in which the Company may grant
options to its employees, directors and consultants for up to 10% of its
outstanding Common Shares. Under this plan, the exercise price of each option
equals the market price of the Company's Common Shares on the date of grant. All
granted options vest over a three-year period and have a four-year term to
expiry. Stock options are granted periodically throughout the year. The fair
value of the stock options granted during the year as calculated by the
Black-Scholes method was $3.66 per option (2007 - $3.99).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
average
exercise
Number of options price
----------------------------------------------------------------------------
Balance December 31, 2006 2,019 $ 14.97
Granted 2,402 $ 10.02
Exercised (30) $ 5.18
Forfeited (477) $ 13.41
Cancelled (643) $ 16.22
----------------------------------------------------------------------------
Balance December 31, 2007 3,271 $ 11.41
Granted 2,664 $ 9.19
Exercised (340) $ 9.12
Forfeited (875) $ 10.43
Cancelled (444) $ 17.75
----------------------------------------------------------------------------
Balance December 31, 2008 4,276 $ 9.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table summarizes information about the stock options
outstanding at December 31, 2008:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted Weighted Exercisable Weighted
Range of Outstanding at average average at average
exercise December 31, remaining exercise December 31, exercise
prices 2008 life price 2008 price
----------------------------------------------------------------------------
(years)
$ 3.50 to $6.50 8 3.9 $ 4.85 - -
$ 6.51 to $9.50 1,865 3.0 $ 7.45 82 $ 8.02
$ 9.51 to $12.50 1,807 2.3 $10.48 506 $10.65
$ 12.51 to $18.70 596 3.5 $14.83 - -
----------------------------------------------------------------------------
4,276 2.8 $9.76 588 $10.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 December 31, 2008 was 71,145,000 (2007 - 51,929,000) and for the year
ended December 31, 2008, the weighted average number of shares outstanding was
61,580,000 (2007 - 46,483,000).
In computing diluted earnings per share for the three month period ended
December 31, 2008 nil (2007 - 379,000) shares were added to the weighted average
number of Common Shares outstanding to account for the dilution of stock options
and for the year ended December 31, 2008, nil (379,000) shares were added to the
weighted average Common Shares outstanding to account for the dilution of the
stock options. There were 4,276,000 (2007 - 2,892,000) stock options that were
not included in the diluted earnings per share calculation because they were
anti-dilutive.
10. 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.
Substantially all of the Company's petroleum and natural gas production is
marketed under standard industry terms. Receivables from petroleum and natural
gas marketers are normally collected on the 25th day of the month following
production. The Company's policy to mitigate credit risk associated with these
balances is to establish marketing relationships with large credit worthy
purchasers and to sell through multiple purchasers. The Company historically has
not experienced any collection issues with its petroleum and natural gas
marketers. Joint venture receivables are typically collected within one to three
months of the joint venture bill being issued to the partner. The Company
attempts to mitigate the risk from joint venture receivables by obtaining
partner approval of significant capital expenditures prior to the expenditure.
However, the receivables are from participants in the petroleum and natural gas
sector, and collection of the outstanding balances can be impacted by industry
factors such as commodity price fluctuations, limited capital availability and
unsuccessful drilling programs. The Company does not typically obtain collateral
from petroleum and natural gas marketers or joint venture partners; however the
Company can cash call for major projects and does have the ability in most cases
to withhold production from joint venture partners in the event of non-payment.
Derivative assets can consist of commodity, interest rate and foreign exchange
contracts used to manage the Company's exposure to fluctuations in commodity
prices, interest rates and the exchange rate between United States and Canadian
dollars. The Company manages the credit risk exposure related to derivative
assets by selecting investment grade counterparties and by not entering into
contracts for trading or speculative purposes.
The carrying amount of accounts receivable and derivatives represents the
maximum credit exposure. As at December 31, 2008 the Company's receivables
consisted of $18.4 (2007 - $16.2) million of receivables from petroleum and
natural gas marketers which has subsequently been collected, $12.4 (2007 - $6.5)
million from joint venture partners of which $4.6 million has been subsequently
collected, and $12.0 (2007 - $5.9) million of Crown deposits, prepaids and other
accounts receivable. The Company does not consider any receivables to be past
due, except as noted in note 3, where the Company in conjunction with the
purchase equation, recorded an allowance for doubtful accounts of $4.6 million
regarding amounts outstanding from SemCanada. There were no changes to this
allowance during the period from August 22, 2008 to December 31, 2008. Although
no value has been assigned, the Company will continue to pursue collection of
this receivable.
(b) Liquidity risk:
Liquidity risk is the risk that the Company will encounter difficulty in meeting
obligations associated with the financial liabilities. The Company's financial
liabilities consist of accounts payable and bank debt. Accounts payable consists
of invoices payable to trade suppliers for office, field operating activities
and capital expenditures. The Company processes invoices within a normal payment
period. Accounts payable and financial instruments have contractual maturities
of less than one year. The Company maintains a revolving credit facility, as
outlined in note 6, that is subject to renewal annually by the lenders and has a
contractual maturity in 2010. 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
Commodity price risk is the risk that future cash flows will fluctuate as a
result of changes in commodity prices. Commodity prices for petroleum and
natural gas are impacted by not only the relationship between the Canadian and
United States dollar, as outlined below, but also global economic events that
dictate the levels of supply and demand. The Company has attempted to mitigate a
portion of the commodity price risk through the use of various financial
derivative and physical delivery sales contracts. The Company's policy is to
enter into commodity price contracts when considered appropriate to a maximum of
50% of forecasted production volumes. The Company's contracts in place as of
December 31, 2008 were as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volume Floor Ceiling Fair
(gj/day) Term Index (Cdn $/gj) (Cdn $/gj) Value
----------------------------------------------------------------------------
AECO C -
Monthly
AECO 2,500 January 1, 2009 - Index less $6.50 $8.30 $ 632
December 31, 2009 $0.09
AECO C -
AECO 2,500 January 1, 2009 - Monthly $6.60 $8.50 623
December 31, 2009 Index
----------------------------------------------------------------------------
$ 1,255
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivatives are recorded on the balance sheet at fair value at each reporting
period with the change in fair value being recognized as an unrealized gain or
loss on the consolidated statement of operations, comprehensive income and
retained earnings. These contracts had the following effect on the consolidated
statement of operations, comprehensive income and retained earnings:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec 31, Dec 31, Dec 31, Dec 31,
2008 2007 2008 2007
----------------------------------------------------------------------------
Realized gain (loss) on financial
instruments $ 2,646 $ 432 $ (675) $ 1,011
Unrealized gain (loss) on financial
instruments 131 (840) 2,608 (423)
----------------------------------------------------------------------------
$ 2,777 $ (408) $1,933 $ 588
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December 31, 2008, a $0.10 change to the price per thousand cubic feet of
natural gas on the costless collars would have had a $0.1 million impact on net
income.
Subsequent to December 31, 2008, the Company entered into the following
financial derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volume Put Call
(gj/day) Term Index (Cdn $/gj) (Cdn $/gj)
----------------------------------------------------------------------------
AECO 15,000 April 1, 2009 -
October 31, 2009 AECO C - Monthly Index $6.00
AECO 5,000 January 1, 2010 -
December 31, 2010 AECO C - Monthly Index $8.00
AECO 10,000 January 1, 2010 -
December 31, 2010 AECO C - Monthly Index $7.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(ii) Foreign currency exchange rate risk
Foreign currency exchange rate risk is the risk that the fair value of future
cash flows will fluctuate as a result of changes in foreign exchange rates. 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. The Company had no
forward exchange rate contracts in place as at or during the year ended December
31, 2008. Subsequent to December 31, 2008, the Company entered into contracts
for US $4 million per month to fix the US dollar to Canadian dollar exchange
rate at 1.24 for the period of February through December 2009.
(iii) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result
of changes in market interest rates. The Company is exposed to interest rate
fluctuations on its bank debt which bears a floating rate of interest. For the
three and twelve months ended December 31, 2008, a 100 basis point change to the
effective interest rate would have a $0.4 million and $0.8 million impact on net
income, respectively (2007 - $0.2 million and $0.6 million). The sensitivity for
2008 is higher as compared to 2007 because of an increase in average outstanding
bank debt in 2008 compared to 2007. The Company had no interest rate swaps or
financial contracts in place as at or during the year ended December 31, 2008.
Subsequent to December 31, 2008, the Company entered into contracts fixing the
rate on $100 million of banker's acceptances for the period from February 10,
2009 to February 10, 2011 at a rate of 1.10 per cent which is subject to
additional stamping fees ranging from 0.95 per cent to 1.75 per cent depending
upon the debt to EBITDA ratio calculated at the Company's previous quarter end.
Fair value of financial instruments
The Company's financial instruments as at December 31, 2008 and 2007 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 petroleum and natural gas
volumes.
Bank debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.
11. Capital management:
The Company's objective when managing capital is to maintain a flexible capital
structure which will allow it to execute on its capital expenditure program,
which includes expenditures on oil and gas activities which may or may not be
successful. Therefore, the Company monitors the level of risk incurred in its
capital expenditures to balance the proportion of debt and equity in its capital
structure.
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. 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 plus or minus net
working capital, divided by funds from operations for the most recent calendar
quarter, annualized (multiplied by four). The Company's strategy is to maintain
a ratio of no more than 2.0 to 1. This ratio may increase at certain times as a
result of acquisitions or very low commodity prices. As at December 31, 2008,
the Company's ratio of net debt to annualized funds from operations was 2.15 to
1 (2007 - 1.22 to 1). This amount has risen above the preferred range of the
Company as a result of the dramatic decrease in commodity prices experienced in
the second half of 2008. In order to maintain the integrity of the Company's
financial position the Company plans to adjust its capital expenditure program
to remain within funds from operations until commodity prices recover or an
alternative form of financing is available as discussed below.
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2008 2007
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Net debt:
Accounts receivable $ 42,800 $ 28,588
Accounts payable and accrued liabilities (74,622) (43,231)
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Working capital deficiency $ (31,822) $ (14,643)
Bank loan (223,628) (95,028)
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Net debt $ (255,450) $ (109,671)
Three months Three months
ended Dec. 31, ended Dec. 31,
2008 2007
----------------------------------------------------------------------------
Annualized funds from operations:
Cash provided by operating activities $ 25,700 $ 11,882
Asset retirement expenditures 152 205
Transportation liability charge 328 313
Change in non-cash working capital 3,466 9,990
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Fourth quarter funds from operations 29,646 22,390
Annualized $ 118,584 $ 89,560
Net debt to annualized funds from operations 2.15 1.22
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In order to facilitate the management of this ratio, the Company prepares annual
funds from operations and capital expenditure budgets, which are updated as
necessary, and are reviewed and periodically approved by the Company's Board of
Directors.
The Company manages its capital structure and makes adjustments by continually
monitoring its business conditions, including; the current economic conditions;
the risk characteristics of the Company's petroleum and natural gas assets; the
depth of its investment opportunities; current and forecasted net debt levels;
current and forecasted commodity prices; and other facts that influence
commodity prices and funds from operations, such as quality and basis
differential, royalties, operating costs and transportation costs.
In order to maintain or adjust the capital structure, the Company will consider;
its forecasted ratio of net debt to forecasted funds from operations while
attempting to finance an acceptable capital expenditure program including
acquisition opportunities; the current level of bank credit available from the
Company's lenders; the level of bank credit that may be attainable from its
lenders as a result of oil and gas reserve growth; the availability of other
sources of debt with different characteristics than the existing bank debt; the
sale of assets; limiting the size of the capital expenditure program and new
equity if available on favourable terms. The Company's share capital is not
subject to external restrictions, however the Company's bank facility is
determined by the lenders based on the lenders' borrowing base models which are
based on the Company's petroleum and natural gas reserves.
There has been no change in the Company's approach to capital management during
the year ended December 31, 2008.
12. Income taxes:
(a) Future income tax expense:
The provision for income tax expense in the financial statements differs from
the result, which would have been obtained by applying the combined federal and
provincial income tax rate to the Company's income (loss) before income taxes.
This difference results from the following items:
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2008 2007
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Income (loss) before income taxes $ (46,871) $ 2,921
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Combined federal and provincial income tax rate 29.70% 32.33%
Computed "expected" income tax expense (reduction) $ (13,921) $ 944
Increase (decrease) in income taxes resulting from:
Non-deductible stock-based compensation 990 861
Non-deductible write-down of goodwill 20,514 -
Benefits relating to change in income tax rates (1,169) (8,019)
Other 34 25
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Future income tax expense (reduction) $ 6,448 $ (6,189)
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(b) Future income tax liability:
The components of the Company's future income tax liability are as follows:
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2008 2007
----------------------------------------------------------------------------
Future income tax:
Property, plant and equipment $ 136,597 $ 84,877
Asset retirement obligations (9,062) (4,935)
Share issue costs (2,956) (1,458)
Non-capital loss (7,813) (154)
Other (489) (1,285)
----------------------------------------------------------------------------
Future income tax liability $ 116,277 $ 77,045
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The non-capital losses expire during the years 2026 to 2028, except for $1.2
million which expires in the year 2015.
13. Supplemental cash flow information:
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2008 2007
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Changes in non-cash working capital:
Accounts receivable $ 8,660 $ 4,633
Accounts payable and accrued liabilities 3,155 (8,130)
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$ 11,815 $ (3,497)
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Operating activities $ (2,346) $ (6,012)
Investing activities 14,161 2,515
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$ 11,815 $ (3,497)
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The Company made the following cash outlays in respect of interest expense:
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2008 2007
----------------------------------------------------------------------------
Interest $ 6,471 $ 7,509
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14. Commitments:
The Company has the following fixed term commitments related to its on-going
business:
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Total 2009 2010 2011
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Operating leases $ 2,722 $ 990 $ 990 $ 742
Capital commitments 11,500 11,500 - -
Firm transportation agreements 20,793 7,003 7,152 6,638
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Total $ 35,015 $ 19,493 $ 8,142 $ 7,380
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The firm transportation commitments were acquired as part of the Company's May
2007 private company acquisition and represent firm service commitments for
transportation and processing of natural gas in British Columbia.
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