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, 2009.
Highlights
- Fourth quarter funds from operations of $27.3 million represents a 39%
increase over the third quarter of 2009;
- Funds from operations per share increased by 40% over the third quarter of
2009 to $0.35 per share;
- Debt was reduced by 29% to $182.3 million from year end 2008 and was 8% lower
than the debt level at the third quarter of 2009;
- December 2009 exit production per debt adjusted share increased 43% over
December 2008 due to significant increases in production at Septimus, British
Columbia and Princess, Alberta and a $73 million reduction in net debt;
- Low commodity prices in 2009 yielded a netback of $17.96 per boe while
exceptional finding, development and acquisition costs of $9.68 per boe yielded
a recycle ratio of 1.9x.
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Three Three
Financial months months Year Year
ended ended ended ended
($ thousands, except per share Dec. 31, Dec. 31, Dec. 31, Dec. 31,
amounts) 2009 2008 2009 2008
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Petroleum and natural gas sales 57,646 58,806 181,829 235,856
Funds from operations (note 1) 27,256 29,646 83,453 127,790
Per share - basic 0.35 0.42 1.11 2.08
- diluted 0.35 0.42 1.11 2.06
Net loss (9,154) (74,853) (37,815) (53,319)
Per share - basic (0.12) (1.05) (0.50) (0.87)
- diluted (0.12) (1.05) (0.50) (0.87)
Exploration and development
expenditures 55,312 53,612 128,567 191,677
Property acquisitions (net of
dispositions) (44,315) (245) (78,693) 70,414
Total capital expenditures 10,997 53,367 49,874 262,091
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Capital Structure As at As at
($ thousands) Dec. 31, 2009 Dec. 31, 2008
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Working capital deficiency (note 2) 46,654 31,822
Bank loan 135,601 223,628
Net debt 182,255 255,450
Bank facility 250,000 285,000
Common shares outstanding (thousands) 78,152 71,084
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Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital, asset
retirement expenditures and the transportation liability charge. Funds
from operations is used to analyze the Company's operating performance
and leverage. Funds from operations does not have a standardized
measure prescribed by Canadian Generally Accepted Accounting Principles
and therefore may not be comparable with the calculations of similar
measures for other companies.
(2) Working capital deficiency includes only accounts receivable less
accounts payable and accrued liabilities.
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Operations Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2009 2008 2009 2008
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Daily production
Natural gas (mcf/d) 51,871 60,464 53,698 52,595
Oil (bbl/d) 4,413 3,123 3,690 1,393
Natural gas liquids (bbl/d) 1,412 1,669 1,362 1,458
Oil equivalent (boe/d @ 6:1) 14,470 14,869 14,002 11,617
Average prices (note 1)
Natural gas ($/mcf) 4.98 6.93 4.27 8.37
Oil ($/bbl) 68.16 50.21 59.39 74.89
Natural gas liquids ($/bbl) 47.91 37.24 36.28 62.32
Oil equivalent ($/boe) 43.30 42.99 35.58 55.47
Operating expenses
Natural gas ($/mcf) 2.02 1.61 1.91 1.42
Oil ($/bbl) 10.30 12.86 11.30 12.24
Natural gas liquids ($/bbl) 9.64 8.57 9.40 7.41
Oil equivalent ($/boe @ 6:1) 11.33 10.20 11.22 8.82
Netback
Operating netback ($/boe) (note 2) 21.63 24.01 17.96 32.64
Realized gain on financial
instruments (1.46) - (0.76) -
G&A ($/boe) 1.11 0.91 1.12 0.98
Interest and other ($/boe) 1.50 1.44 1.27 1.60
Funds from operations ($/boe) 20.48 21.66 16.33 30.06
Drilling Activity
Gross wells 23 16 43 53
Working interest wells 21.3 9.8 36.1 43.3
Success rate, net wells 95% 100% 97% 95%
Undeveloped land (note 4)
Gross acres 1,055,660 1,105,639
Net acres 585,732 626,861
Reserves (Proved plus probable)
(note 4)
Oil (Mbbl) 15,226 9,178
Ngl (Mbbl) 6,650 6,563
Natural Gas (Mmcf) 263,187 260,298
BOE (Mboe) 65,741 59,123
Finding, Development & Acquisition
Costs ($/boe) (note 3 and 4) 9.68 21.24
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Notes:
(1) Average prices are before deduction of transportation costs and do not
include realized gains and losses on financial instruments.
(2) Operating netback equals petroleum and natural gas sales including
realized hedging gains and losses on commodity contracts less
royalties, operating costs and transportation costs calculated on a
boe basis. Operating netback and funds from operations netback do not
have a standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
(3) 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, 2009 as
evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") and related
information was contained in Crew's press release dated February 23,
2010 and will be contained in Crew's Annual Information Form to be
filed on or before March 31, 2010.
OVERVIEW
The past year marked the beginning of a long recovery from the worst financial
crisis in decades. Financial intervention by governments around the world aided
in the stabilization of the world's financial system and helped inject
confidence in the global economy thereby creating increased global demand for
commodities. This recovery was evident in the world's oil markets as the price
of benchmark West Texas Intermediate ("WTI") recovered from a first quarter
average price of US$43 per barrel to a fourth quarter average of US$76 per bbl.
Natural gas prices did not experience a similar recovery. North American natural
gas markets have been dramatically impacted by low industrial demand brought on
by the recession and increasing supplies from new technologies recovering
natural gas from unconventional resource plays such as "shale gas". This has
created an oversupplied market and a weak price environment. Prices for natural
gas sold in Canada opened 2009 above $6.00 per million cubic feet but steadily
declined to average a low of $3 per million cubic feet in the third quarter.
With the anticipation of stronger demand from the winter heating season, prices
strengthened marginally in the fourth quarter to average $4.50 per million cubic
feet but the market continues to suffer from weak industrial demand and
continued oversupply.
As a result of the low commodity price environment encountered in the first half
of 2009, Crew limited its first half capital spending in order to preserve its
financial position. In addition, the Company was successful in strengthening its
balance sheet with the sale of approximately 670 boe per day of production and
2.4 mmboe of proved plus probable reserves for $33.2 million in two first half
dispositions and completed a bought deal equity financing in May for gross
proceeds of $43.4 million. The Company also entered into a number of 2009
commodity and foreign exchange hedging agreements that ensured a certain level
of cash flow to help fund a more active second half exploration and development
program.
With a strengthened financial position, the Company executed an expanded second
half exploration and development program drilling all but seven of its total 43
well 2009 program in the second half of the year. This program focused on
development of the Company's medium grade oil play at Princess, Alberta and
continued expansion of the Company's natural gas Montney resource play at
Septimus, British Columbia. At Princess, the Company has successfully applied
horizontal drilling to exploit only a small portion of the 444 net sections of
land it controls in the area to grow current production to over 5,200 boe per
day representing a 136% increase in production from when the property was
acquired in the latter half of 2008. At Septimus, the Company completed
construction of a 25 mmcf per day natural gas processing facility in October
2009 which allowed the Company to increase its production volumes in the area to
current levels of approximately 21 mmcf per day and reduce operating costs per
unit on Septimus produced natural gas by over 60%.
The Company further strengthened its balance sheet in the second half of 2009
with the sale of an additional 600 boe per day of non-core production and 1.8
mmboe of proved plus probable reserves for $25 million. The Company also sold
the Septimus gas facility to a third party for its as built cost of $19 million.
Under the arrangement Crew will operate the facility and retains an option to
expand the facility in the future and equalize into a 50% ownership position.
As a result of the limited capital spending and to a larger degree, the sale of
assets and shutting in of uneconomic natural gas production, Crew's production
declined from a first quarter average of 15,022 boe per day to average 14,002
boe per day for the year. Despite the limited first half activity and the sale
of 1,270 boe per day of production, a very successful second half drilling
program resulted in exit production, represented by December 2009 average
production, exceeding the Company's first quarter average.
The Company's financial results were impacted by the depressed gas prices and
average oil prices below 2008 levels. Funds from operations declined 34% to
$83.5 as a result of the weaker commodity price environment. This level of funds
from operations was bolstered by an $18.5 million gain realized on the Company's
risk management program. The Company's capital management program significantly
improved the Company's financial position reducing net debt by 29% to $182.3
million at year end. This level of debt equates to 1.7 times annualized fourth
quarter funds from operations which is well within current industry standards.
OPERATIONS UPDATE
Positive Pekisko Drilling Results with Production up 136%
Crew is pleased to report the Pekisko drilling program continues to expand with
the Company currently identifying over 470 drilling locations at Princess. Crew
now has 11 horizontal wells that have been on production for in excess of 90
days which are currently producing an average of 240 boe per day per well.
Current production at Princess is approximately 5,200 boe per day representing a
136% increase from the 2,200 boe per day that the property was producing when
acquired in August 2008. Crew's 2009 Princess Pekisko drilling program was very
efficient adding in excess of 7 million boe of proved plus probable reserves and
increasing the Princess proved plus probable reserves by 87% to 15.1 million
barrels at a cost of $8.19 per boe. Crew currently plans to drill up to 30 (30.0
net) horizontal wells at Princess in 2010 with 13 horizontal wells planned in
the first quarter of 2010.
Crew's operating costs at Princess are expected to continue their downward trend
from $16.50 per boe when the property was acquired to the $10 per boe range in
2010. The majority of this reduction is attributed to successful drilling of
horizontal disposal wells in the Devonian Cairn formation the last two of which
each tested at disposal capacity of 9,000 barrels per day due to the limitation
of surface equipment. Crew continues to expand and modify its existing
infrastructure to facilitate the Pekisko production growth.
Septimus, British Columbia Montney Production up 350%
The Crew constructed 25 mmcf per day Septimus gas plant became operational on
October 1, 2009 allowing the Company to increase production volumes to a current
level of approximately 21 mmcf per day. Crew's Montney completion methods have
continued to improve with the two most recent Septimus wells testing at a
restricted average rate of 5.3 mmcf per day at a flowing pressure of
approximately 2,000 psi. The Company has an additional three (1.5 net) wells to
complete and bring on production after spring breakup.
In December, Crew completed the sale of the Septimus gas processing facility to
Aux Sable Canada ("ASC") for the as built cost of approximately $19 million.
Under the arrangement with ASC, Crew operates the facility and retained an
option to expand the facility to 50 mmcf per day and equalize into a 50%
ownership position. ASC recently announced regulatory approval of a 20 inch
pipeline connecting the Septimus gas plant to the Alliance pipeline.
Construction of the pipeline is currently underway and will facilitate a
significant (350 mmcf per day) increase in takeaway capacity from the greater
Septimus area.
Crew's 2009 Septimus drilling program was very successful increasing the
property's proved plus probable reserves by 41% over 2008 to 21.6 million boe.
At Septimus, reserves per previously booked section increased by 25% to average
approximately 11 bcf per section. Only 13 net sections out of a total 215 net
sections of the Company's Montney resource land exposure have been assigned
reserves by GLJ to the end of 2009. Reserves per well of 385,000 boe and 520,000
boe have been assigned on a proved and proved plus probable basis, respectively.
Crew's current plans in British Columbia for the Montney at Septimus
(development) and Portage (exploration) include nine (7.5 net) horizontal wells
in 2010. With the new facility at Septimus, operating costs in the area are
expected to be approximately $0.80 per mcf which represents a 60% reduction in
area operating costs per unit. Liquids production is averaging over 24 bbls per
mmcf which significantly enhances the economics of this play in the current
natural gas environment.
Montney Evaluation
The following discussion regarding Crew's Montney resource at Septimus is
subject to a number of cautionary statements, assumptions and risks, some of
which are included below and others under "Information Regarding Disclosure on
Oil and Gas Reserves, Resources and Operational Information".
Based on an independent evaluation by GLJ effective as at December 31, 2009, the
best estimate of Discovered Petroleum Initially in Place ("DPIIP") for 56 net
sections of Montney rights owned in Crew's Septimus area is 2.7 Tcf net to Crew,
of which 0.91 Tcf is on the 13 net sections to which reserves have been
assigned. GLJ have assigned proved plus probable non-associated gas reserves of
110.8 bcf to the 13 net sections in the Septimus area, which includes 68.5 bcf
of proved reserves.
GLJ has assigned a best estimate of 1.8 Tcf of DPIIP (of the 2.7 Tcf in total
DPIIP) on the balance of the 43 net evaluated 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
independently evaluated. Additional drilling will be required to explore and
delineate these properties before it will be possible to define the timing of
potential development projects.
GLJ has provided a best estimate of the DPIIP for the upper Montney on only 56
out of 215 Company controlled net sections or 26% of Crew's prospective Montney
land base. It is management's belief that with drilling success on the
undeveloped acreage consistent with historical success, and further development
and completion refinements that Crew will recognize additional reserves over
time. Crew will be drilling and completing numerous wells into Montney intervals
at Septimus in 2010 to gain a better understanding of the production potential
of these lands.
It should be noted that given the current early stage of development the best
estimate of DPIIP 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. All estimates of DPIIP
of GLJ are as at December 31, 2009. A recovery project has not been defined for
the volumes of DPIIP, which are not classified as reserves. At this time, there
is no certainty that it will be technically feasible or commercially viable to
produce any of the resources.
OUTLOOK
As previously disclosed, the Company's Board of Directors has approved a base
budget that includes a net $120 million 2010 capital expenditure program which
is expected to incorporate the drilling of a minimum of 40 wells. The $120
million budget is expected to approximate 2010 funds from operations based on
average production of between 15,500 to 15,750 boe per day with an exit 2010
production rate in excess of 17,000 boe per day.
With commodity markets remaining volatile the Company intends to focus capital
investments towards the projects that have the ability to provide the best
returns on capital. The Company will continue to focus on improving operating
efficiencies in order to improve our cost structure and maximize the return on
invested capital. Crew will also remain disciplined in its financial management
in order to maintain or improve its balance sheet strength.
We are very excited about our diverse portfolio of projects and the
opportunities they provide our shareholders. With resource plays covering both
oil and natural gas and a superior cost structure, the Company is well
positioned to provide shareholders with exceptional reserve and production
growth in 2010 and beyond.
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, 2009 and
2008 and the audited consolidated financial statements and Management Discussion
and Analysis for the year ended December 31, 2008. The consolidated financial
statements have been prepared in accordance with generally accepted accounting
principles ("GAAP") in Canada and all figures provided herein and in the
December 31, 2009 consolidated financial statements are reported in Canadian
dollars.
Forward-looking Statements
This MD&A contains forward-looking statements. Management's assessment of future
plans and operations, capital expenditures, timing of capital expenditures and
methods of financing capital expenditures and the ability to fund financial
liabilities, production estimates, expected commodity prices and the impact on
Crew, future operating costs, future transportation costs, expected royalty
rates, general and administrative expenses, interest rates, anticipated
reductions in depletion and depreciation rates, debt levels, funds from
operations and the timing of and impact of adoption of IFRS and other accounting
policies may constitute forward-looking statements under applicable securities
laws and necessarily involve risks including, without limitation, risks
associated with oil and gas exploration, development, exploitation, production,
marketing and transportation, loss of markets, volatility of commodity prices,
currency fluctuations, imprecision of reserve estimates, environmental risks,
competition from other producers, inability to retain drilling rigs and other
services, incorrect assessment of the value of acquisitions, failure to realize
the anticipated benefits of acquisitions, the inability to fully realize the
benefits of acquisitions, delays resulting from or inability to obtain required
regulatory approvals and ability to access sufficient capital from internal and
external sources. As a consequence, the Company's actual results may differ
materially from those expressed in, or implied by, the forward looking
statements. Forward looking statements or information are based on a number of
factors and assumptions which have been used to develop such statements and
information but which may prove to be incorrect.
Although Crew believes that the expectations reflected in such forward-looking
statements or information are reasonable, undue reliance should not be placed on
forward looking statements because the Company can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified in this document and other documents filed
by the Company, assumptions have been made regarding, among other things: the
impact of increasing competition; the general stability of the economic and
political environment in which Crew operates; the ability of the Company to
obtain qualified staff, equipment and services in a timely and cost efficient
manner; drilling results; the ability of the operator of the projects which the
Company has an interest in to operate the field in a safe, efficient and
effective manner; Crew's ability to obtain financing on acceptable terms; field
production rates and decline rates; the ability to reduce operating costs; the
ability to replace and expand oil and natural gas reserves through acquisition,
development or exploration; the timing and costs of pipeline, storage and
facility construction and expansion; the ability of the Company to secure
adequate product transportation; future petroleum and natural gas prices;
currency, exchange and interest rates; the regulatory framework regarding
royalties, taxes and environmental matters in the jurisdictions in which the
Company operates; and Crew's ability to successfully market its petroleum and
natural gas products. Readers are cautioned that the foregoing list of factors
is not exhaustive. Additional information on these and other factors that could
affect the Company's operations and financial results are included in reports on
file with Canadian securities regulatory authorities and may be accessed through
the SEDAR website (www.sedar.com) or at the Company's website
(www.crewenergy.com). Furthermore, the forward looking statements contained in
this document are made as at the date of this document and the Company does not
undertake any obligation to update publicly or to revise any of the included
forward looking statements, whether as a result of new information, future
events or otherwise, except as may be required by applicable securities laws.
Conversions
The oil and gas industry commonly expresses production volumes and reserves on a
"barrel of oil equivalent" basis ("boe") whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved analysis of results and comparisons with other industry participants.
Throughout this MD&A, Crew has used the 6:1 boe measure which is the approximate
energy equivalency of the two commodities at the burner tip. Boe does not
represent a value equivalency at the plant gate which is where Crew sells its
production volumes and therefore may be a misleading measure if used in
isolation.
Non-GAAP Measures
One of the benchmarks Crew uses to evaluate its performance is funds from
operations. Funds from operations is a measure not defined in GAAP that is
commonly used in the oil and gas industry. It represents cash provided by
operating activities before changes in non-cash working capital, asset
retirement expenditures and the transportation liability charge. The Company
considers it a key measure as it demonstrates the ability of the business to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Funds from operations should not be considered as
an alternative to, or more meaningful than cash provided by operating activities
as determined in accordance with GAAP as an indicator of the Company's
performance. Crew's determination of funds from operations may not be comparable
to that reported by other companies. Crew also presents funds from operations
per share whereby per share amounts are calculated using weighted average shares
outstanding consistent with the calculation of income per share. The following
table reconciles Crew's cash provided by operating activity to funds from
operations:
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Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands) 2009 2008 2009 2008
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Cash provided by operating
activities 16,734 25,700 82,659 123,356
Asset retirement expenditures 111 152 589 775
Transportation liability charge 329 328 1,314 1,313
Change in non-cash working capital 10,082 3,466 (1,109) 2,346
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Funds from operations 27,256 29,646 83,453 127,790
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Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore may not be
comparable with the calculation of similar measures for other entities.
Operating netback equals total petroleum and natural gas sales including
realized gains and losses on commodity contracts less royalties, operating costs
and transportation costs calculated on a boe basis. Management considers
operating netback an important measure to evaluate its operational performance
as it demonstrates its field level profitability relative to current commodity
prices.
Production
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Three months ended Three months ended
December 31, 2009 December 31, 2008
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
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Plains
Core 4,256 828 30,844 10,224 2,845 989 42,890 10,982
North
Core 157 584 21,027 4,246 278 680 17,574 3,887
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Total 4,413 1,412 51,871 14,470 3,123 1,669 60,464 14,869
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Year ended Year ended
December 31, 2009 December 31, 2008
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
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Plains
Core 3,496 893 35,373 10,285 1,187 991 37,010 8,346
North
Core 194 469 18,325 3,717 206 467 15,585 3,271
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Total 3,690 1,362 53,698 14,002 1,393 1,458 52,595 11,617
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Fourth quarter production decreased by 3% over the fourth quarter of 2008 as a
result of property dispositions of approximately 1,270 boe per day of non-core
production in Alberta and Saskatchewan during 2009 as well as the shut-in of
approximately 400 boe per day of uneconomic natural gas production in Alberta.
These dispositions were partially offset by a successful drilling program that
added new natural gas liquids ("ngl") rich natural gas production at Septimus,
British Columbia and oil production at Killam and Princess, Alberta.
Production increased 21% in 2009 due to the previously mentioned successful
drilling program at Septimus, Killam and Princess and a full year of production
from the acquisition of Gentry Resources Ltd. ("Gentry") which closed in August
2008. Natural gas production increased 2% over 2008 due to a successful drilling
program in the Company's Septimus, British Columbia area which was partially
offset by the disposition of approximately 1,270 boe per day of predominantly
Alberta natural gas production. Oil production increased 165% due a successful
drilling program in Killam and Princess, Alberta and a full year of production
from the Gentry properties with oil production in the Princess, Alberta area.
Revenue
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Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2009 2008 2009 2008
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Revenue ($ thousands)
Natural gas 23,746 38,537 83,699 161,192
Oil 27,674 14,425 79,997 38,196
Natural gas liquids 6,226 5,720 18,035 33,249
Sulphur - 124 98 3,219
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Total 57,646 58,806 181,829 235,856
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Crew average prices
Natural gas ($/mcf) 4.98 6.93 4.27 8.37
Oil ($/bbl) 68.16 50.21 59.39 74.89
Natural gas liquids ($/bbl) 47.91 37.24 36.28 62.32
Oil equivalent ($/boe) 43.30 42.99 35.58 55.47
Benchmark pricing
Natural Gas - AECO C daily index
(Cdn $/mcf) 4.49 6.79 4.03 8.27
Oil - Bow River Crude Oil
(Cdn $/bbl) 77.45 59.30 68.71 94.40
Oil and ngl - Light Sweet @
Edmonton (Cdn $/bbl) 77.90 62.54 66.21 102.02
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Crew's 2009 fourth quarter revenue decreased by 2% over the fourth quarter of
2008 due to the 3% decrease in production partially offset by a 1% increase in
average pricing. In the fourth quarter, the Company's natural gas price
decreased 28% as compared to a 34% decrease in Crew's natural gas benchmark
price. The disproportionate decrease was attributable to a higher price received
for the Company's additional Septimus, British Columbia natural gas production.
In the fourth quarter of 2009, the Company's oil price increased
disproportionately as compared with the Company's benchmark Bow River Crude oil
price primarily due to the oil volumes in the Princess, Alberta area attracting
a price that includes a fixed price quality differential off of the Bow River
stream price. The Company's ngl price increased 29% in the fourth quarter of
2009 compared to a 25% increase in the Company's benchmark Light Sweet at
Edmonton due to the Company's 2009 property dispositions which included lower
valued ethane production which historically has decreased the overall corporate
ngl realized price.
The Company's 2009 revenue decreased 23% as a result of its 36% decrease in
product pricing partially offset by a 21% increase in production. For the year,
Crew's natural gas price decreased 49% over 2008 which was comparable to the 51%
decrease in the Company's benchmark price. The sales price for Crew's oil
production decreased 21% compared to a 27% decrease in the benchmark. In 2008,
the majority of the Company's oil production came from the Princess, Alberta
property acquired in August 2008 and was therefore produced in a lower price
environment thus lowering the overall corporate average oil price for 2008 as
compared to the average benchmark for the same period. In 2009, with a full year
of oil production from the Princess property, Crew's average oil price is within
expectations as compared to the benchmark. Crew's average ngl price decreased
42% as compared with the benchmark decrease of 35% due to additional lower
valued ethane production from wells in northeastern British Columbia.
Royalties
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Three Three
months months Year Year
($ thousands, except per boe) ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2009 2008 2009 2008
----------------------------------------------------------------------------
Royalties 13,167 12,035 36,027 49,961
Per boe $ 9.89 $ 8.80 $ 7.05 $ 11.75
Percentage of revenue 22.8% 20.5% 19.8% 21.2%
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Royalties as a percentage of revenue increased in the fourth quarter of 2009
compared to the same quarter of 2008 due to the addition of oil volumes on
freehold lands in the Princess, Alberta area which currently attract a higher
royalty rate. This was partially offset by lower gas royalties as a percentage
of revenue due to a lower natural gas price experienced during the fourth
quarter of 2009 compared with the same period in 2008.
Overall, royalties as a percentage of revenue decreased in 2009 over 2008 due to
decreased Alberta natural gas royalties associated with lower natural gas
prices. In Alberta, under the new royalty structure, the Company's Crown royalty
percentages decrease as natural gas prices decrease. This was partially offset
by the royalties from the additional oil volumes on the Company's freehold lands
in the Princess, Alberta area. Crew estimates royalties as a percentage of
revenue to average 23% to 25% in 2010.
Financial Instruments
Commodities
The Company enters into derivative and physical risk management contracts in
order to reduce volatility in financial results, to protect acquisition
economics and to ensure a certain level of cash flow to fund planned capital
projects. Crew's strategy focuses on the use of puts, costless collars, swaps
and fixed price contracts to limit exposure to fluctuations in commodity prices,
interest rates and foreign exchange rates while allowing for participation in
commodity price increases. The Company's financial derivative trading activities
are conducted pursuant to the Company's Risk Management Policy approved by the
Board of Directors. In 2009, these contracts had the following impact on the
consolidated statements of operations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands) 2009 2008 2009 2008
----------------------------------------------------------------------------
Realized gain (loss) on financial
instruments 4,471 2,646 18,461 (675)
Unrealized gain (loss) on financial
instruments (6,225) 131 (2,089) 2,608
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December 31, 2009, the Company held derivative commodity contracts as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
Natural 2,500 November 1, 2009 - AECO C $6.00 Swap 534
Gas gj/day December 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO C $8.00 Call (183)
Gas gj/day December 31, 2010 Monthly
Index
Natural 10,000 January 1, 2010 - AECO C $7.75 Call (434)
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $6.20 Swap 724
Gas gj/day December 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO C $6.08 Swap 1,214
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $5.25 Swap (148)
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $5.55 Swap 133
Gas gj/day December 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO/NYMEX US$($0.55) Swap (356)
Gas mmbtu/day December 31, 2010 Basis
diff
Oil 250 January 1, 2010 - CDN$ WTI $78.50 Swap (734)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - CDN$ WTI $72.00 - Collar (700)
bbl/day December 31, 2010 $88.00
Oil 250 January 1, 2010 - CDN$ WTI $82.50 Swap (366)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - CDN$ WTI $80.50 Swap (1,100)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - US$ WTI US$81.00 Swap (249)
bbl/day December 31, 2010
Oil 250 January 1, 2010 - CDN$ WTI $80.00 - Collar 81
bbl/day December 31, 2010 $95.02
----------------------------------------------------------------------------
Total (1,584)
----------------------------------------------------------------------------
Foreign currency
Although all of the Company's petroleum and natural gas sales are conducted in
Canada and are denominated in Canadian dollars, Canadian commodity prices are
influenced by fluctuations in the Canadian to U.S. dollar exchange rate.
At December 31, 2009, the Company held derivative foreign currency
contracts as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
USD / CAD $ US $2M / January 1, 2010 -
exchange Month December 31, 2010 CAD/USD 1.094 Swap 1,022
----------------------------------------------------------------------------
Total 1,022
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest rate
The Company is exposed to interest rate fluctuations on its bank loan which
bears a floating rate of interest. As shown below, at December 31, 2009, Crew
had contracts in place fixing the rate on $150 million of its bank loan borrowed
as banker's acceptances for a period of 24 months at rates of 1.10% to 1.12%.
The Company pays an additional stamping fee and margins on bankers' acceptances
as outlined in note 6 of the financial statements.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
BA Rate $50M February 10, 2009 -
/ year February 10, 2011 BA - CDOR 1.10% Swap (156)
BA Rate $50M February 12, 2009 -
/ year February 12, 2011 BA - CDOR 1.10% Swap (116)
BA Rate $50M May 28, 2009 -
/ year May 28, 2011 BA - CDOR 1.12% Swap -
----------------------------------------------------------------------------
Total (272)
----------------------------------------------------------------------------
Subsequent to December 31, 2009, the Company entered into the following
financial instrument contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Strike Option
Contract Volume Term Reference Price Traded
----------------------------------------------------------------------------
April 1, 2010 - AECO C - $5.30 /
Natural Gas 2,500 gj/day October 31, 2010 Monthly Index gj Swap
Oil 250 bbl/day March 1, 2010 - $84.00 /
December 31, 2010 CDN $WTI bbl Swap
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
($ thousands, months months Year Year
except ended ended ended ended
per boe) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Operating costs 15,084 13,952 57,342 37,520
Per boe $ 11.33 $ 10.20 $ 11.22 $ 8.82
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's operating costs and operating costs per unit increased in the
fourth quarter as compared to the same period in 2008 as a result of additional
oil production from the Company's Princess, Alberta area which currently has
higher operating costs per unit than the Company's natural gas production.
During 2009, the Company disposed of lower cost natural gas production which
increased the Company's per unit costs in the fourth quarter of 2009 as compared
with the same period in 2008. In addition, in the fourth quarter, the Company
also received higher than expected third party prior year equalizations
inflating its operating costs and operating costs per unit.
Crew's increase in operating costs per unit in 2009 was a result of the higher
operating cost oil properties acquired in the Gentry acquisition in August 2008.
A combination of the increasing oil production in the Princess area throughout
2009 and the disposition of lower operating cost natural gas properties in 2009
has also contributed to the Company's overall increase in operating costs per
unit. Crew has identified a number of cost cutting measures associated with
water handling at Princess and expects lower operating costs per unit from
production in the Septimus, British Columbia area which will reduce the
Company's operating costs per unit in 2010. The Company expects operating costs
to range between $10.00 and $10.50 per boe in 2010.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
($ thousands, months months Year Year
except ended ended ended ended
per boe) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Transportation
costs 3,134 2,607 11,229 8,924
Per boe $ 2.35 $ 1.91 $ 2.20 $ 2.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's 2009 fourth quarter increase in transportation costs per boe was a
result of an increase in unutilized demand charges for transportation and
treatment through northeastern British Columbia pipelines and facilities in
which Crew's production is decreasing. This production was replaced by
production at Septimus, British Columbia where gas transportation costs are
lower. Additional trucking costs associated with ngl production in the Septimus,
British Columbia area also increased the Company's transportation costs in the
fourth quarter of 2009.
In 2009, Crew's transportation costs per unit were slightly above 2008 levels. A
combination of a reduction in certain British Columbia gas sales to offset the
Company's fixed transportation commitments in northeastern British Columbia with
additional trucking costs of natural gas liquids produced in the Septimus,
British Columbia has increased the transportation costs and transportation costs
per unit for the year. This has been partially offset by lower clean oil
trucking costs per unit in the Princess, Alberta area. The Company forecasts
transportation costs in 2010 to approximate fourth quarter 2009 levels and range
between $2.00 and $2.50 per boe.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
Dec. 31, 2009 Dec. 31, 2008
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 68.16 47.91 4.98 43.30 50.21 37.24 6.93 42.99
Realized
commodity
hedging
gain (loss) (0.61) - 0.60 1.90 5.12 - 0.21 1.93
Royalties (21.07) (10.51) (0.68) (9.89) (15.32) (11.37) (1.08) (8.80)
Operating
costs (10.30) (9.64) (2.02) (11.33) (12.86) (8.57) (1.61) (10.20)
Transportation
costs (1.45) (0.89) (0.51) (2.35) (1.54) (0.04) (0.39) (1.91)
----------------------------------------------------------------------------
Operating
netbacks 34.73 26.87 2.37 21.63 25.61 17.26 4.06 24.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
Dec. 31, 2009 Dec. 31, 2008
Natural Natural
Oil Ngl gas Total Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe) ($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 59.39 36.28 4.27 35.58 74.89 62.32 8.37 55.47
Realized
commodity
hedging gain
(loss) (0.01) - 0.74 2.85 2.88 - (0.11) (0.16)
Royalties (16.66) (10.09) (0.43) (7.05) (15.67) (17.30) (1.67) (11.75)
Operating
costs (11.30) (9.40) (1.91) (11.22) (12.24) (7.41) (1.42) (8.82)
Transportation
Costs (1.59) (0.29) (0.46) (2.20) (1.93) (0.03) (0.41) (2.10)
----------------------------------------------------------------------------
Operating
netbacks 29.83 16.50 2.21 17.96 47.93 37.58 4.76 32.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
($ thousands, ended ended Year ended Year ended
except per boe) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Gross costs 4,026 3,076 14,160 11,099
Operator's
recoveries (1,080) (591) (2,689) (2,761)
Capitalized costs (1,473) (1,243) (5,735) (4,169)
----------------------------------------------------------------------------
General and
administrative
expenses 1,473 1,242 5,736 4,169
Per boe $ 1.11 $ 0.91 $ 1.12 $ 0.98
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 2009 compared to 2008. Increased capital expenditures and production
levels in the fourth quarter of 2009 resulted in higher operator recoveries and
capitalized costs.
General and administrative expenses increased in 2009 as compared to 2008 due to
the addition of new staff to handle the Company's increased activity. Operator
recoveries were marginally lower in 2009 as a result of decreased capital
expenditures in 2009. Crew expects general and administrative costs per boe to
average approximately $1.00 to $1.15 per boe in 2010.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
($ thousands, ended ended Year ended Year ended
except per boe) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Interest expense 2,003 1,970 6,503 7,085
Average debt level 158,937 191,535 194,818 138,395
Effective
interest rate 5.1% 4.1% 3.3% 5.1%
Per boe $ 1.50 $ 1.44 $ 1.27 $ 1.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the fourth quarter of 2009, increased margins applied to the Company's bank
facility have increased the Company's interest expense and effective interest
rate over the same period in 2008. The additional interest has been partially
offset due to lower prime and bankers' acceptance interest rates and lower
average debt levels that were the result of a reduced 2009 exploration and
development capital program, asset dispositions and the equity financing
completed in May, 2009.
In 2009, despite higher average debt levels, lower prime interest rates and
rates on bankers' acceptances have decreased the Company's interest expense and
effective interest rate. This has been partially offset by increased margins
applied to the Company's bank facility in the last half of 2009. In 2010, the
Company's interest rate hedges will continue to partially offset the higher
margins charged on the Company's bank facility. The Company's effective interest
rate is expected to average between 4.75% and 5.25% in 2010.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended Year ended Year ended
($ thousands) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Gross costs 1,586 1,178 6,642 6,664
Capitalized costs (793) (589) (3,321) (3,332)
----------------------------------------------------------------------------
Total stock-based
compensation 793 589 3,321 3,332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has increased in the fourth
quarter of 2009 due to the Company's increasing share price creating a higher
fair value for stock options issued. In the fourth quarter of 2008, there was a
reversal of expense due to the forfeiture of options in the fourth quarter of
2008. In 2009, stock based compensation expense has been equivalent to the same
period in 2008, but is expected to increase in 2010 as the fair value of the
Company's stock options issued increases as its share price increases.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
($ thousands, ended ended Year ended Year ended
except per boe) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Depletion,
depreciation
and accretion 31,677 35,329 131,613 104,866
Per boe 23.80 25.83 25.75 24.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's per unit depletion, depreciation and accretion decreased in the
fourth quarter of 2009 compared to the fourth quarter of 2008 due to low cost
reserve additions from a successful drilling program in the Company's Septimus,
British Columbia and Princess, Alberta areas.
In 2009, per unit depletion, depreciation and accretion costs increased 4%. Per
unit costs increased due to a full year of depletion, depreciation and accretion
on the Gentry assets acquired in August 2008. The assets acquired were recorded
at the fair market value at the acquisition date which was higher than the
Company's historic carrying value for proved reserves. However, as observed with
the fourth quarter 2009 rate of $23.80 per boe, the Company expects depletion
and depreciation rates to decrease in 2010 with continued successful drilling
results.
Crew performed a ceiling test as at December 31, 2009. 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.
Taxes
The future income tax recovery for 2009 was $15.8 million compared to an expense
of $6.4 million in 2008. The recovery was as expected given the loss before
income taxes for the year. In 2008, the Company's loss was the result of a
write-down of goodwill which was non-deductible for tax purposes.
A summary of the Company's estimated income tax pools at December 31, 2009
is outlined below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Cumulative Canadian Exploration Expense 108,900 85,000
Cumulative Canadian Development Expense 132,200 124,000
Cumulative Canadian Oil and Gas
Property Expense 110,000 167,000
Undepreciated Capital Cost 103,800 111,000
Share issue costs 5,000 7,700
Non-capital loss 32,000 26,700
----------------------------------------------------------------------------
491,900 521,400
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The estimated income tax pools have been reduced by the estimated deferred
partnership income for 2009 and were impacted by the sale of properties in 2009
totaling $59.6 million. The Company did not pay cash taxes in 2009 and estimates
it has sufficient tax pools to shelter estimated income until 2011 or beyond.
Cash and Funds from Operations and Net Income
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, Three months Three months
except per ended ended Year ended Year ended
share amounts) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Cash provided by
operations 16,734 25,700 82,659 123,356
----------------------------------------------------------------------------
Funds from
operations 27,256 29,646 83,453 127,790
Per share - basic 0.35 0.42 1.11 2.08
- diluted 0.35 0.42 1.11 2.06
----------------------------------------------------------------------------
Net loss (9,154) (74,853) (37,815) (53,319)
Per share - basic (0.12) (1.05) (0.50) (0.87)
- diluted (0.12) (1.05) (0.50) (0.87)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The fourth quarter 2009 decline in cash provided by operations and funds from
operations was the result of decreased production and an increase in costs.
The Company's 2009 decrease in cash provided by operations and funds from
operations primarily resulted from the decrease in the Company's price received
for oil and natural gas in 2009 as compared to 2008. The Company's net loss
decreased in the fourth quarter and year as the 2008 net loss was largely the
result of the goodwill write-down in 2008.
Capital Expenditures, Acquisitions and Dispositions
During the fourth quarter, the Company drilled a total of 23 (21.3 net) wells
resulting in four (2.3 net) natural gas wells, 17 (17.0 net) oil wells, one (1.0
net) service well and one (1.0 net) dry and abandoned well. In addition, in the
quarter, the Company completed 13 (12.8 net) wells and recompleted nine (8.6
net) wells. During the fourth quarter, the Company added to its undeveloped land
base, acquiring crown land in northeastern British Columbia and closed the
disposition of approximately 600 boe per day of non-core Alberta natural gas
production for $25.3 million. In the fourth quarter, the Company also completed
construction of the Septimus gas processing facility, which in December was sold
to a third party for its as built cost of $19.1 million.
During 2009, Crew drilled a total of 43 (36.1 net) wells resulting in 12 (5.9
net) natural gas wells, 26 (26.0 net) oil wells, three (3.0 net) service wells
and two (1.2 net) dry and abandoned wells representing a success rate of 95%
(97% net). In 2009, Crew closed non-core property dispositions of approximately
1,270 boe per day of production and 4.2 mmboe of proved plus probable reserves
for $59.6 million as well as the aforementioned Septimus facility for $19.1
million. During 2009, the Company reduced its capital expenditures by $4.9
million due to government incentive programs for drilling and infrastructure
credits in Alberta and British Columbia.
Total exploration and development expenditures for 2009 were $128.6 million
compared to $191.7 million for the same period in 2008. The expenditures are
detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended Year ended Year ended
($ thousands) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Land 5,619 1,148 10,500 25,317
Seismic 2,426 2,779 4,602 5,595
Drilling and
completions 37,302 35,283 65,469 124,894
Facilities,
equipment and
pipelines 8,371 13,071 41,755 30,902
Other 1,594 1,331 6,241 4,969
----------------------------------------------------------------------------
Total
exploration and
development 55,312 53,612 128,567 191,677
Property
acquisitions
(dispositions) (44,315) (245) (78,693) 70,414
----------------------------------------------------------------------------
Total 10,997 53,367 49,874 262,091
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's Board of Directors has approved a net $120 million exploration and
development budget for 2010.
LIQUIDITY AND CAPITAL RESOURCES
Capital Funding
The Company has a credit facility with a syndicate of banks (the "Syndicate")
that includes a revolving line of credit of $235 million and an operating line
of credit of $15 million (the "Facility"). The Facility revolves for a 364 day
period and will be subject to its next 364 day extension by June 14, 2010. If
not extended, the Facility will cease to revolve, the margins thereunder will
increase by 0.50 percent and all outstanding balances under the Facility will
become repayable in one year. The available lending limits of the Facility are
reviewed semi-annually and are based on the Syndicate's interpretation of the
Company's reserves and future commodity prices. There can be no assurance that
the amount of the available Facility will not be adjusted at the next scheduled
review on or before June 14, 2010. Borrowing margins and fees will also be
reviewed as part of the Syndicate's annual review prior to June 14, 2010. At
December 31, 2009, the Company had drawings of $135.6 million on the Facility
and had issued letters of credit totaling $2.8 million.
On May 28, 2009, Crew issued 7,000,000 Common shares at an issue price of $6.20
per share for total gross proceeds of approximately $43.4 million. The proceeds
were used to pay down the Company's bank debt and to fund the Company's ongoing
capital program.
The Company will continue to fund its on-going operations from a combination of
cash flow, debt, asset dispositions, and equity financings as needed. As the
majority of Crew's 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 a
sufficient amount of unused bank credit facility to satisfy such working capital
deficiencies. At December 31, 2009, the Company's working capital deficiency
totaled $46.7 million which, when combined with the drawings on its bank line,
represented 73% of its current bank facility.
Share Capital
As at December 31, 2009, Crew had 78,152,368 Common Shares outstanding along
with 5,751,500 options to acquire Common Shares of the Company. As at March 8,
2010, Crew had 78,607,368 Common Shares outstanding along with 7,158,900 options
to acquire Common Shares of the Company.
Capital Structure
The Company considers its capital structure to include working capital, bank
loan, and shareholders' equity. The Company monitors debt levels based on the
ratio of net debt to annualized funds from operations. The ratio represents the
time period it would take to pay off the debt if no further capital expenditures
were incurred and if funds from operations remained constant. This ratio is
calculated as net debt, defined as outstanding bank loan plus or minus net
working capital, divided by funds from operations for the most recent calendar
quarter, annualized (multiplied by four). The Company's strategy is to maintain
a ratio of no more than 2.0 to 1. This ratio may increase at certain times as a
result of acquisitions or low commodity prices.
As at December 31, 2009, the Company's ratio of net debt to annualized funds
from operations was 1.67 to 1 (2008 - 2.15 to 1). Despite a decrease in
commodity prices, the ratio decreased due to non-core property dispositions and
the equity raised in May 2009.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except ratio) Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Accounts receivable 37,574 42,800
Accounts payable and accrued liabilities (84,228) (74,622)
----------------------------------------------------------------------------
Working capital deficiency (46,654) (31,822)
Bank loan (135,601) (223,628)
----------------------------------------------------------------------------
Net debt (182,255) (255,450)
Fourth quarter funds from operations 27,256 29,646
Annualized 109,024 118,584
Net debt to annualized funds from operations
ratio 1.67 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 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Bank Loan (note 1) 135,601 - 135,601 - - - -
Operating Leases 4,795 1,743 1,743 1,309 - - -
Capital commitments 6,000 3,000 3,000 - - - -
Firm transportation
agreements 13,977 7,339 6,638 - - - -
Firm processing
agreement 29,935 2,493 3,049 3,049 3,049 3,049 15,246
----------------------------------------------------------------------------
Total 190,308 14,575 150,031 4,358 3,049 3,049 15,246
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2011. However, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.
The firm transportation commitments were acquired as part of the Company's May
2007 private company acquisition and represent firm service commitments for
transportation and processing of natural gas in British Columbia.
During 2009, Crew entered into the firm processing agreement to process natural
gas through a third party owned gas processing facility in the Septimus area of
northeast British Columbia. Under the terms of the agreement, Crew has committed
to process a minimum monthly volume of gas through the facility commencing on
December 1, 2009 and continuing through November 30, 2019. The commitment is
included in the above table.
The agreement additionally provides Crew the option to participate in an
expansion of the facility at a cost of 50% of the total expanded facility
construction costs and subsequently become a 50% owner in the facility. If the
facility is not expanded prior to January 1, 2013, the current owner of the
facility can require Crew to purchase the existing facility for the total
construction costs plus $0.7 million or alter the fees associated with Crew's
commitment in order to recover the amount of Crew's full commitment prior to
January 1, 2016.
OUTLOOK
One year ago we were mired in one of the worst recessions in decades. The
situation has improved dramatically with the world's economy and banking systems
generally stabilizing and moving into the early stages of a recovery. Commodity
prices have rebounded with oil leading the group; however, natural gas prices
remain depressed due to an oversupplied market. Crew intends to focus its
capital investments on projects that have the ability to provide the best
returns on capital in the current commodity price environment.
The Board of Directors of Crew has approved a net $120 million 2010 capital
expenditure budget which is expected to incorporate the drilling of a minimum of
40 wells of which the majority will be horizontal wells targeting oil at
Princess, Alberta. The $120 million budget is expected to result in average
production of between 15,500 and 15,750 boe per day with an exit 2010 production
rate in excess of 17,000 boe per day.
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.
Substantial Capital Requirements
The Company anticipates making substantial capital expenditures for the
acquisition, exploration, development and production of petroleum 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
uncertainty in global markets 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 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 the financial condition of its 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.
Global Financial Crisis
Past market events and conditions, including disruptions in international credit
markets and other financial systems and the deterioration of global economic
conditions, have caused significant volatility in commodity prices. These
conditions, which began in 2008 and continued into 2009, caused a loss of
confidence in the broader U.S. and global credit and financial markets and
resulted in the collapse of, and government intervention in, major banks,
financial institutions and insurers and created 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 taken by governments around the world, 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 deteriorate and stock markets to decline substantially.
During the second half of 2009, the environment improved and the world's credit
markets, financial systems and general economy have generally stabilized.
Despite this improvement, these factors will continue to fuel economic
volatility which will impact the performance of the global economy and may
negatively impact company valuations and performance for the foreseeable future.
Quarterly Analysis
The following table summarizes the Company's key quarterly financial results
in 2009 and 2008:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per share Dec. 31 Sept. 30 June 30 Mar. 31
amounts) 2009 2009 2009 2009
----------------------------------------------------------------------------
Total daily production (boe/d) 14,470 13,065 13,466 15,022
Average wellhead price ($/boe) 43.30 32.04 32.10 34.28
Petroleum and natural gas sales 57,646 38,510 39,331 46,342
Cash provided by operations 16,734 24,902 21,517 19,506
Funds from operations 27,256 19,640 20,036 16,521
Per share - basic 0.35 0.25 0.27 0.23
- diluted 0.35 0.25 0.27 0.23
Net income (loss) (9,154) (7,376) (12,267) (9,018)
Per share - basic (0.12) (0.10) (0.17) (0.13)
- diluted (0.12) (0.10) (0.17) (0.13)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ 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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Significant factors and trends that have impacted the Company's results during
the above periods include:
- Revenue is directly impacted by the Company's ability to replace existing
declining production and add incremental production through its on-going capital
expenditure program.
- Production in the second quarter of 2008 and 2009 was negatively impacted by
scheduled and unscheduled third party facility shutdowns.
- In August 2008, the Company acquired Gentry Resources Ltd. with approximately
4,000 boe per day of production at closing.
- Revenue and royalties are significantly impacted by underlying commodity
prices. The Company utilizes derivative contracts and forward sales contracts to
reduce the exposure to commodity price fluctuations. These contracts can cause
volatility in net income as a result of unrealized gains and losses on commodity
derivative contracts held for risk management purposes.
- Throughout 2008, the Company's operating costs, general and administrative
costs and capital expenditures were subject to inflationary pressures brought on
by increasing demand for services and supplies within the Canadian oil and gas
industry.
- In the fourth quarter of 2008, Crew performed an impairment test on its
goodwill and determined that its carrying value exceeded its fair value and
therefore an impairment charge of $69.1 million was required.
- In 2009, the Company sold non-core assets with approximately 1,270 boe per day
of production for $59.6 million. The major dispositions closed as follows:
-- First quarter 2009 - 130 boe per day for $10.7 million
-- Second quarter 2009 - 540 boe per day for $22.5 million
-- Fourth quarter 2009 - 600 boe per day for $25.3 million
- In the fourth quarter of 2009, the Company completed the construction of its
Septimus gas processing facility and subsequently sold it to a third party for
it's as built cost of $19.1 million.
The following table summarizes Crew's key financial results over the past
three years:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per share Year ended Year ended Year ended
amounts) Dec. 31, 2009 Dec. 31, 2008 Dec. 31, 2007
----------------------------------------------------------------------------
Petroleum and natural gas sales 181,829 235,856 140,466
Cash provided by operations 82,660 123,356 74,400
Funds from operations 83,453 127,790 81,433
Per share - basic 1.11 2.08 1.75
- diluted 1.11 2.06 1.74
Net income (loss) (37,815) (53,319) 9,110
Per share - basic (0.50) (0.87) 0.20
- diluted (0.50) (0.87) 0.19
Daily production (boe/d) 14,002 11,617 8,696
Crew average sales price
($/boe) 35.58 55.47 44.45
Total assets 963,248 1,045,510 602,193
Working capital deficiency 46,654 31,822 14,643
Bank loan 135,601 223,628 95,028
Total other long-term
liabilities 136,992 152,679 98,472
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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. Despite increasing production, these performance measures have all
fluctuated throughout 2008 and 2009 as a result of volatile oil and natural gas
prices combined with the increased cost of the Company's operations.
Change in Accounting Policies
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 January 1, 2011 for
the Company. Early adoption is permitted. This section replaces Section 1581,
"Business Combinations" and harmonizes the Canadian standards with International
Financial Reporting Standards ("IFRS").
In January 2009, the AcSB issued Section 1601, "Consolidated Financial
Statements", and Section 1602, "Non-controlling Interests", which together
replace Section 1600, "Consolidated Financial Statements", and harmonize the
Canadian standards with International Financial Reporting Standards. Section
1601 establishes standards for the preparation of consolidated financial
statements subsequent to a business combination. These sections are effective on
or after January 1, 2011 for the Company. Early adoption is permitted.
New Accounting Pronouncements
International Financial Reporting Standards (IFRS)
In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the
changeover to IFRS from Canadian GAAP will be required for publicly accountable
enterprises for interim and annual financial statements effective for fiscal
years beginning on or after January 1, 2011, including comparatives for 2010.
Crew's financial statements up to and including the December 31, 2010 financial
statements will continue to be reported in accordance with Canadian GAAP as it
exists on each reporting date. Financial statements for the quarter ended March
31, 2011, including comparative amounts, will be prepared on an IFRS basis.
In July 2009, the International Accounting Standards Board ("IASB") issued
amendments to IFRS 1 "First time adoption of IFRS" allowing additional
exemptions for first-time adopters. Under these amendments, full cost oil and
gas companies can elect to use the recorded amount under a previous GAAP as the
deemed cost for oil and gas assets on the transition date to IFRS. Crew is
currently planning to adopt this exemption.
In order to transition to IFRS, Management has established a project team and
formed an executive steering committee. A transition plan has been developed to
convert the financial statements to IFRS. External advisors have been retained
and will assist management with the project on an as needed basis. Staff
training programs will continue throughout 2010. During 2009, the project team
completed the diagnostic phase of our project and identified key differences
between Canadian GAAP and IFRS. Subsequently, we focused on accounting policy
decisions, modifications to our IT systems and accounting processes as well as
reviewing our internal controls over financial reporting. The project team and
steering committee continue to provide updates to senior management and the
Audit Committee. Changes in IFRS are likely and may materially impact the
financial statements. Possible differences between current accounting policies
under Canadian GAAP and expected accounting policies under IFRS include the
following:
- Depletion and depreciation of property, plant and equipment ("PP&E") will be
based on significant components. Under IFRS 1, the net book value of the PP&E
will be allocated to the new cost centres on the basis of Crew's reserve volumes
or values as per the deemed cost election. Depletion of resource properties will
generally continue to be calculated using the unit-of-production method but Crew
has the option to base the calculation using proved reserves or proved and
probable reserves. Crew has not concluded at this time which method it will use
and will continue to monitor its peers to ensure comparability.
- Oil and gas properties will be classified as either PP&E or Exploration and
Evaluation assets (E&E). Upon transition to IFRS, Crew will reclassify all E&E
expenditures that are currently included in the PP&E balance on the Consolidated
Balance Sheet. These assets will be measured at cost and will not be depleted
but will be assessed for impairment when indicators suggest the possibility of
impairment. E&E will primarily consist of undeveloped land and exploratory
drilling costs.
- Business Combinations - IFRS 1 allows Crew to use the IFRS rules for business
combinations on a prospective basis rather than re-stating all business
combinations. Crew will likely use this exemption on any acquisitions prior to
January 1, 2010.
- Currently Crew expenses its stock-based compensation on a straight-line basis
while under IFRS, share-based payments are expensed based on a graded vesting
schedule. Crew will also be required to incorporate a forfeiture multiplier
rather than account for forfeitures as they occur under Canadian GAAP.
- Under Canadian GAAP, impairment testing on oil and gas properties is performed
at a cost centre level, while under IFRS, it will be performed at a lower level,
referred to as a cash generating unit. This will result in a greater number of
impairment tests.
- Under Canadian GAAP, Crew's Asset Retirement Obligation calculation utilizes a
credit adjusted risk free rate; however, IFRS requires the use of a discount
rate that reflects the risks specific to the obligation.
- Due to the recent withdrawal of the exposure draft on IAS 12 Income Taxes in
November 2009, and the issuance of the exposure draft on IAS 37 Provisions,
Contingent Liabilities and Contingent Assets in January 2010, Crew is still
determining the impact of these revised standards on its IFRS transition.
In addition to accounting policy differences, Crew's transition to IFRS will
impact the internal controls over financial reporting, disclosure controls and
procedures, Crew's business activities and IT systems as follows:
- Throughout 2010, Crew will be updating our internal control documentation but
do not expect that the transition to IFRS will have a significant impact on
either our internal controls over financial reporting or our disclosure controls
and procedures.
- With ongoing communication throughout the Company, management does not expect
the adoption of IFRS to have a significant impact or influence on our business
activities or strategies.
- We have completed a review of the expected changes that will be required for
our IT systems. Testing has been completed and upgrades and system changes will
commence in 2010.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
The Company's Chief Executive Officer and Chief Financial Officer have designed,
or caused to be designed under their supervision, disclosure controls and
procedures to provide reasonable assurance that: (i) material information
relating to the Company is made known to the Company's Chief Executive Officer
and Chief Financial Officer by others, particularly during the period in which
the annual and interim filings are being prepared; and (ii) information required
to be disclosed by the Company in its annual filings, interim filings or other
reports filed or submitted by it under securities legislation is recorded,
processed, summarized and reported within the time period specified in
securities legislation. Such officers have evaluated, or caused to be evaluated
under their supervision, the effectiveness of the Company's disclosure controls
and procedures at the financial year end of the Company and have concluded that
the Company's disclosure controls and procedures are effective at the financial
year end of the Company for the foregoing purposes.
The Company's Chief Executive Officer and Chief Financial Officer have designed,
or caused to be designed under their supervision, internal controls over
financial reporting to provide reasonable assurance regarding the reliability of
the Company's financial reporting and the preparation of financial statements
for external purposes in accordance with Canadian GAAP. Such officers have
evaluated, or caused to be evaluated under their supervision, the design and
effectiveness of the Company's internal control over financial reporting at the
financial year end of the Company and concluded that the Company's internal
control over financial reporting is effective, at the financial year end of the
Company, for the foregoing purpose. From 2006 to 2009 Crew engaged external
consultants to assist in documenting and assessing the Company's internal
controls over financial reporting.
The Company is required to disclose herein any change in the Company's internal
control over financial reporting that occurred during the period beginning on
October 1, 2009 and ended on December 31, 2009 that has materially affected, or
is reasonably likely to materially affect, the Company's internal control over
financial reporting. No material changes in the Company's internal control over
financial reporting were identified during such period, that has materially
affected, or are reasonably likely to materially affect, the Company's internal
control over financial reporting.
It should be noted that a control system, including the Company's disclosure and
internal controls and procedures, no matter how well conceived, can provide only
reasonable, but not absolute, assurance that the objectives of the control
system will be met and it should not be expected that the disclosure and
internal controls and procedures will prevent all errors or fraud.
Additional information relating to Crew, including the Company's Annual
Information Form, can be found on SEDAR at www.sedar.com.
Dated as of March 8, 2010
Cautionary Statements
Forward-looking information and statements
This news release contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of any of the words
"expect", "anticipate", "continue", "estimate", "may", "will", "project",
"should", "believe", "plans", "intends" and similar expressions are intended to
identify forward-looking information or statements. In particular, but without
limiting the 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; production
estimates; 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 and the timing thereof; the number of wells to be drilled
and completed and the timing thereof; the amount and timing of capital projects;
completion of the Septimus pipeline project, and the timing thereof and
resultant anticipated increase in takeaway capacity at Septimus; 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 adequate insurance
coverage; the impact of competitors; and certain other risks detailed from
time-to-time in Crew's public disclosure documents, (including, without
limitation, those risks identified in this news release and Crew's Annual
Information Form).
The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Crew does not assume any
obligation to publicly update or revise any of the included forward-looking
statements or information, whether as a result of new information, future events
or otherwise, except as may be required by applicable securities laws.
Information Regarding Disclosure On Oil And Gas Reserves, Resources And
Operational Information
All amounts in this news release are stated in Canadian dollars unless otherwise
specified. Where applicable, natural gas has been converted to barrels of oil
equivalent ("BOE") based on 6 Mcf:1 BOE. The BOE rate is based on an energy
equivalent conversion method primarily applicable at the burner tip and does not
represent a value equivalent at the well head. Use of BOE in isolation may be
misleading.
In accordance with Canadian practice, production volumes and revenues are
reported on a company gross basis, before deduction of Crown and other
royalties, unless otherwise stated. Unless otherwise specified, all reserve
volumes in this news release and all information derived therefrom are based on
"company interest reserves" using forecast prices and costs. "Company interest
reserves" consist of "company gross reserves" (as defined in National Instrument
51-101 adopted by the Canadian Securities Regulators ("NI 51-101")) plus Crew's
royalty interests in reserves. "Company interest reserves" are not a measure
defined in NI 51-101 and does not have a standardized meaning under NI 51-101.
Accordingly our Company interest reserves may not be comparable to reserves
presented or disclosed by other issuers. Our oil and gas reserves statement for
the year ended December 31, 2009, which will include complete disclosure of our
oil and gas reserves and other oil and gas information in accordance with NI
51-101, will be contained within our Annual Information Form which will be
available on our SEDAR profile at www.sedar.com. In relation to the disclosure
of estimates of reserves for individual properties in the Princess and Septimus
areas, such estimates for individual properties may not reflect the same
confidence level as estimates of reserves for all properties, due to the effects
of aggregation.
This news release contains references to estimates of gas classified as
discovered petroleum initially in place in the area of Septimus in British
Columbia which are not, and should not be confused with, oil and gas reserves.
"Discovered Petroleum Initially in Place" ("DPIIP") is defined in the Canadian
Oil and Gas Evaluation Handbook (the "COGE Handbook") as the quantity of
hydrocarbons that are estimated to be in place with a known accumulation. DPIIP
is divided into recoverable and unrecoverable portions, with the estimated
future recoverable portion classified as reserves and contingent resources and
the remainder as at evaluation date is by definition unrecoverable. There is no
certainty that it will be economically viable or technically feasible to produce
any portion of this DPIIP. Resources do not constitute, and should not be
confused with, reserves.
Crew has not categorized the resources disclosed as DPIIP into all of the
sub-categories of discovered resources as projects have not been defined to
develop them as at the evaluation date. Such projects, in the case of the
Montney resource described, have historically been developed sequentially over a
number of drilling seasons and are subject to annual budget constraints, Crew's
policy of orderly development on a staged basis, the timing of the growth of
third party infrastructure, the short and long term view of Crew on commodity
prices, the results of exploration and development activities of Crew and others
in the area and possible infrastructure capacity constraints.
Crew's belief that it will recognize additional reserves in the Septimus area is
based on a combination of historic recoveries of the more fully developed
acreage, available well log and production test data, and the application of
drilling densities of Crew and third parties in the areas and assumes continuous
development through multi-year exploration and development programs, changing
economic circumstances and further development and completion refinements. The
principal risks of not achieving reserve additions on these lands relate to the
potential for variations in the quality of the Montney formation where no
current well data exists, access to capital, low gas prices that would impact
the economics of development and the future performance of the wells.
Crew's belief that it will establish additional reserves over time in the
discussion of the Montney resource at Septimus is a forward looking statement
and is based on certain assumptions and is subject to certain risks, as
discussed above under the heading "Forward Looking Information and Statements".
Financial statements for the three month periods and years ended December 31,
2009 and 2008 are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(thousands)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2009 2008
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 37,574 $ 42,800
Fair value of financial instruments (note 10) - 1,255
Future income taxes (note 12) 542 15
----------------------------------------------------------------------------
38,116 44,070
Property, plant and equipment (note 4) 925,132 1,001,440
----------------------------------------------------------------------------
$ 963,248 $ 1,045,510
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 84,228 $ 74,622
Fair value of financial instruments (note 10) 834 -
Current portion of other long-term
obligations (note 7) 1,313 1,313
----------------------------------------------------------------------------
86,375 75,935
Bank loan (note 6) 135,601 223,628
Other long-term obligations (note 7) 132 1,446
Asset retirement obligations (note 8) 35,341 34,941
Future income taxes (note 12) 101,519 116,292
Shareholders' Equity
Share capital (note 9) 617,605 575,191
Contributed surplus (note 9(c)) 22,769 16,356
Retained earnings (deficit) (36,094) 1,721
----------------------------------------------------------------------------
604,280 593,268
Commitments (note 14)
----------------------------------------------------------------------------
$ 963,248 $ 1,045,510
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Operations, Comprehensive Loss and Retained
Earnings (Deficit)
(thousands, except per share amounts)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2009 2008 2009 2008
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales $ 57,646 $ 58,806 $181,829 $235,856
Royalties (13,167) (12,035) (36,027) (49,961)
Realized gain (loss) on financial
instruments (note 10) 4,471 2,646 18,461 (675)
Unrealized gain (loss) on financial
instruments (note 10) (6,225) 131 (2,089) 2,608
Other income - - - 268
----------------------------------------------------------------------------
42,725 49,548 162,174 188,096
Expenses
Operating 15,084 13,952 57,342 37,520
Transportation 3,134 2,607 11,229 8,924
Interest 2,003 1,970 6,503 7,085
General and administrative 1,473 1,242 5,736 4,169
Stock-based compensation (note 9(d)) 793 589 3,321 3,332
Depletion, depreciation and
accretion 31,677 35,329 131,613 104,866
Write-down of goodwill (note 5) - 69,071 - 69,071
----------------------------------------------------------------------------
54,164 124,760 215,744 234,967
----------------------------------------------------------------------------
Loss before income taxes (11,439) (75,212) (53,570) (46,871)
Future income tax expense
(reduction) (note 12) (2,285) (359) (15,755) 6,448
----------------------------------------------------------------------------
Loss and comprehensive loss (9,154) (74,853) (37,815) (53,319)
Retained earnings (deficit),
beginning of period (26,940) 76,574 1,721 55,040
----------------------------------------------------------------------------
Retained earnings (deficit), end of
period $(36,094) $ 1,721 $(36,094) $ 1,721
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Loss per share (note 9(e))
Basic $ (0.12) $ (1.05) $ (0.50) $ (0.87)
Diluted $ (0.12) $ (1.05) $ (0.50) $ (0.87)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Cash Flows
(thousands)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
2009 2008 2009 2008
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Net loss $ (9,154) $(74,853) $ (37,815) $ (53,319)
Items not involving cash:
Depletion, depreciation and
accretion 31,677 35,329 131,613 104,866
Write-down of goodwill (note 5) - 69,071 - 69,071
Stock-based compensation 793 589 3,321 3,332
Future income tax expense
(reduction) (2,285) (359) (15,755) 6,448
Unrealized (gain) loss on
financial instruments (note 10) 6,225 (131) 2,089 (2,608)
Transportation liability charge
(note 7) (329) (328) (1,314) (1,313)
Asset retirement expenditures
(note 8) (111) (152) (589) (775)
Change in non-cash working
capital (note 13) (10,082) (3,466) 1,109 (2,346)
----------------------------------------------------------------------------
16,734 25,700 82,659 123,356
Financing activities:
Increase (decrease) in bank loan (31,167) 44,578 (88,027) 60,396
Issue of common shares 539 - 43,961 69,846
Share issue costs - - (2,442) (3,654)
Repurchase of common shares - (514) - (514)
----------------------------------------------------------------------------
(30,628) 44,064 (46,508) 126,074
Investing activities:
Exploration and development (55,312) (53,612) (128,567) (191,677)
Property acquisitions - 245 - (70,414)
Property dispositions 44,315 - 78,693 -
Business acquisition (note 3) - - - (1,500)
Change in non-cash working
capital (note 13) 24,891 (16,397) 13,723 14,161
----------------------------------------------------------------------------
13,894 (69,764) (36,151) (249,430)
----------------------------------------------------------------------------
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 years ended December 31, 2009 and 2008
(Tabular amounts in thousands)
1. Significant accounting policies:
The consolidated financial statements of Crew Energy Inc. ("the 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 judgment. 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 subsidiary, Crew Resources Inc., and a partnership, Crew Energy
Partnership. 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 the depletion rate by more than
20%.
The costs 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. Any 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 depleted 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:
Revenues 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 assesses 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. 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 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:
Future accounting pronouncements
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 January 1, 2011 for
the Company. Early adoption is permitted. This section replaces Section 1581,
"Business Combinations" and harmonizes the Canadian standards with International
Financial Reporting Standards.
In January 2009, the AcSB issued Section 1601, "Consolidated Financial
Statements", and Section 1602, "Non-controlling Interests", which together
replace Section 1600, "Consolidated Financial Statements", and harmonize the
Canadian standards with International Financial Reporting Standards. Section
1601 establishes standards for the preparation of consolidated financial
statements subsequent to a business combination. These sections are effective on
or after January 1, 2011 for the Company. Early adoption is permitted.
3. Business acquisition:
On August 22, 2008, Crew acquired all of the issued and outstanding shares of
Gentry Resources Ltd. ("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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
December 31, 2009 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 1,302,399 $ 377,267 $ 925,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The costs of unproved properties at December 31, 2009 of $153,674,000 (2008 -
$170,453,000) were excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $173,999,000 (2008 - $108,258,000) have been included in the
depletion calculation and estimated salvage values of $38,039,000 (2008 -
$38,514,000) have been excluded from the depletion calculation.
The following directly attributable general and administrative and stock-based
compensation expenses related to exploration and development activities were
capitalized:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
General and administrative expense $ 5,736 $ 4,169
Stock-based compensation expense,
including future income taxes 4,442 4,485
----------------------------------------------------------------------------
$ 10,178 $ 8,654
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew performed a ceiling test as at December 31, 2009. 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 Bow River Company Company
Oil Rate Oil Liquids AECO Gas Gas
Years ($US/Bbl) ($Cdn/$US) ($/bbl) ($/bbl) ($/mmbtu) ($/mcf)
----------------------------------------------------------------------------
2010 $ 80.00 0.950 $71.61 $69.09 $5.96 $5.81
2011 $ 83.00 0.950 $72.59 $70.56 $6.79 $6.79
2012 $ 86.00 0.950 $73.45 $72.13 $6.89 $6.91
2013 $ 89.00 0.950 $74.19 $73.97 $6.95 $6.99
2014 $ 92.00 0.950 $76.72 $76.18 $7.05 $7.12
2015 $ 93.84 0.950 $78.27 $77.38 $7.16 $7.20
2016 $ 95.72 0.950 $79.85 $78.72 $7.42 $7.48
2017 $ 97.64 0.950 $81.46 $80.19 $7.95 $8.04
2018 $ 99.59 0.950 $83.11 $81.56 $8.52 $8.66
2019 $101.58 0.950 $84.78 $83.02 $8.69 $8.84
Annual escalation thereafter +2.0%/yr.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
5. Goodwill:
As at December 31, 2008, the Company determined that its corporate fair value
was below the Company's book value. As a result, an impairment of the Company's
carried goodwill was recognized and the full amount of $69.1 million was
written-off as a non-cash charge to income in 2008.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Balance, beginning of year $ - $ 20,800
Business acquisition (note 3) - 48,271
Goodwill impairment recognized - (69,071)
----------------------------------------------------------------------------
Balance, end of year $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Bank loan:
The Company's bank facility consists of a revolving line of credit of $235
million and an operating line of credit of $15 million (the "Facility"). The
Facility revolves for a 364 day period and will be subject to its next 364 day
extension by June 14, 2010. If not extended, the Facility will cease to revolve,
the margins thereunder will increase by 0.50 per cent and all outstanding
advances thereunder will become repayable in one year. The available lending
limits of the Facility are reviewed semi-annually and are based on the bank
syndicate's interpretation of the Company's reserves and future commodity
prices. 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 14, 2010.
Advances under the Facility are available by way of prime rate loans with
interest rates between 1.75 percent and 3.5 percent over the bank's prime
lending rate and bankers' acceptances and LIBOR loans, which are subject to
stamping fees and margins ranging from 2.75 percent to 4.5 percent depending
upon the debt to EBITDA ratio of the Company calculated at the Company's
previous quarter end. Drawings on the facility will be subject to unanimous
syndicate approval and an additional 0.50 percent increase in fees and margins
at any time drawings on the facility exceed $235 million. Standby fees are
charged on the undrawn facility at rates ranging from 0.70 percent to 1.2
percent depending upon the debt to EBITDA ratio.
As at December 31, 2009, the Company's applicable pricing included a 2.25
percent margin on prime lending and a 3.25 percent stamping fee and margin on
bankers' acceptances and LIBOR loans along with a 0.80 percent per annum standby
fee on the portion of the facility that is not drawn. Borrowing margins and fees
are reviewed annually as part of the bank syndicate's annual renewal. At
December 31, 2009, the Company had issued letters of credit totaling $2.8
million which are considered to be drawings on the facility. The effective
interest rate on the Company's borrowings under its bank facility for the year
ended December 31, 2009 was 3.3% (2008 - 4.9%).
7. Other long-term obligations:
As part of a May 3, 2007 private company acquisition, the Company acquired
several firm transportation agreements. These agreements had a fair value at the
time of the acquisition of a $4.9 million liability. This amount was accounted
for as part of the acquisition cost and is charged as a reduction to
transportation expenses over the life of the contracts as they are incurred. The
charge for the year ended December 31, 2009 was $1.3 million (2008 - $1.3
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, 2009 to be $35,341,000 (2008 -
$34,941,000) based on a total future liability of $64,030,000 (2008 -
$67,588,000). These payments are expected to be made over the next 30 years. An
8% to 10% (2008 - 8% to 10%) credit adjusted risk free discount rate and 2%
(2008 - 2%) inflation rate were used to calculate the present value of the asset
retirement obligation.
The following table reconciles Crew's asset retirement obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, 2009 December 31, 2008
----------------------------------------------------------------------------
Carrying amount, beginning of year $ 34,941 $ 18,668
Liabilities incurred 385 1,228
Liabilities acquired (disposed) (2,161) 13,927
Accretion expense 2,765 1,893
Liabilities settled (589) (775)
----------------------------------------------------------------------------
Carrying amount, end of year $ 35,341 $ 34,941
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 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
Public offering issued for cash 7,000 43,400
Exercise of stock options 68 561
Stock-based compensation - 229
Share issue costs, net of future income taxes of $666 - (1,776)
----------------------------------------------------------------------------
Common Shares, December 31, 2009 78,152 $ 617,605
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On May 28, 2009, the Company issued 7,000,000 Common Shares at a price of $6.20
per share for aggregate gross proceeds of $43.4 million ($40.9 million net of
issue costs).
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 terminated on October 14, 2009. The Company
paid for all Common Shares acquired under the bid at the prevailing market price
on the TSX at the time of the purchase. During the 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. The Company did not repurchase any Common
Shares in 2009.
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).
(c) Contributed Surplus:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
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
Stock-based compensation 6,642
Exercise of stock options (229)
----------------------------------------------------------------------------
Contributed surplus, December 31, 2009 $ 22,769
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 1.58% (2008 - 4.05%),
expected life 4 years (2008 - 4 years), volatility 53% (2008 - 45%), and an
expected dividend of nil (2008 - nil). The Company has not incorporated an
estimated forfeiture rate for stock options that will not vest, rather the
Company accounts for actual forfeitures as they occur.
During 2009 the Company recorded $6,642,000, (2008 - $6,664,000) of stock-based
compensation expense related to the stock options, of which $3,321,000 (2008 -
$3,332,000) 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 $1,121,000 (2008 - $1,153,000)
associated with the current year's capitalized stock-based compensation has been
recorded.
Stock options
The Company has a floating stock option plan by 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 $2.14 per option (2008 - $3.66).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of Weighted average
options exercise price
----------------------------------------------------------------------------
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
Granted 1,742 $ 5.08
Exercised (68) $ 8.17
Forfeited (199) $ 10.64
----------------------------------------------------------------------------
Balance December 31, 2009 5,751 $ 8.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table summarizes information about the stock options
outstanding at December 31, 2009:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted Weighted Weighted
Outstanding at average average Exercisable at average
Range of December 31, remaining exercise December 31, exercise
exercise prices 2009 life (years) price 2009 price
----------------------------------------------------------------------------
$2.50 to $6.50 1,625 3.0 $ 4.87 2 $ 4.50
$6.51 to $9.50 1,804 2.0 $ 7.45 637 $ 7.49
$9.51 to $12.50 1,822 1.4 $ 10.45 1,142 $ 10.55
$12.51 to $18.70 500 2.5 $ 14.96 167 $ 14.96
----------------------------------------------------------------------------
5,751 2.1 $ 8.33 1,948 $ 9.92
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(e) Per share amounts:
Per share amounts have been calculated on the weighted average number of shares
outstanding. The weighted average shares outstanding for the year ended December
31, 2009 was 75,252,000 (2008 - 61,580,000).
In computing diluted earnings per share for the year ended December 31, 2009,
nil (2008 - nil) shares were added to the weighted average Common Shares
outstanding to account for the dilution of stock options. There were 5,751,000
(2008 - 4,276,000) 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 derivative assets, when
outstanding, represents the maximum credit exposure. As at December 31, 2009 the
Company's receivables consisted of $17.2 (2008 - $18.4) million of receivables
from petroleum and natural gas marketers which has subsequently been collected,
$9.2 (2008 - $12.4) million from joint venture partners of which $1.5 million
has been subsequently collected, and $11.2 (2008 - $12.0) million of Crown
deposits, prepaids and other accounts receivable. The Company does not consider
any receivables to be past due.
(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 loan. 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 2011. 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 as outlined below. The
Company's policy is to enter into commodity price contracts when considered
appropriate to a maximum of 50% of forecasted production volumes for a period of
not more than two years.
Derivatives are recorded on the balance sheet at fair value at each reporting
period with the change in fair value being recognized as an unrealized gain or
loss on the consolidated statement of operations.
(ii) Foreign currency exchange rate risk
Foreign currency exchange 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 has
attempted to mitigate a portion of its foreign exchange fluctuation risk through
the use of financial derivatives as outlined below.
(iii) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result
of changes in market interest rates. The Company is exposed to interest rate
fluctuations on its bank loan which bears a floating rate of interest. For the
three months and year ended December 31, 2009, a 1.0 percent change to the
effective interest rate would have a $0.3 million and $1.5 million impact on net
income, respectively (2008 - $0.4 and $0.8 million). The sensitivity for 2009 is
higher as compared to 2008 because of an increase in average outstanding bank
debt in 2009 compared to 2008.
The Company has attempted to mitigate the impact of future fluctuations in
interest rates on its outstanding debt by entering into contracts fixing the
base interest rate on $150 million of banker's acceptance borrowings as outlined
below. These rates are, under the Company's bank Facility, subject to additional
stamping fees ranging from 2.75 per cent to 4.50 per cent depending upon the
debt to EBITDA ratio calculated at the Company's previous quarter end.
The Company's derivative contracts in place as of December 31, 2009 are as
follows:
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
Commodity contracts
November 1, AECO C
Natural 2,500 2009 - December Monthly $6.00 Swap 534
Gas gj/day 31, 2010 Index
January 1, 2010 AECO C
Natural 5,000 - December 31, Monthly $8.00 Call (183)
Gas gj/day 2010 Index
January 1, 2010 AECO C
Natural 10,000 - December 31, Monthly $7.75 Call (434)
Gas gj/day 2010 Index
January 1, 2010 AECO C
Natural 2,500 - December 31, Monthly $6.20 Swap 724
Gas gj/day 2010 Index
January 1, 2010 AECO C
Natural 5,000 - December 31, Monthly $6.08 Swap 1,214
Gas gj/day 2010 Index
January 1, 2010 AECO C
Natural 2,500 - December 31, Monthly $5.25 Swap (148)
Gas gj/day 2010 Index
January 1, 2010 AECO C
Natural 2,500 - December 31, Monthly $5.55 Swap 133
Gas gj/day 2010 Index
January 1, 2010
Natural 5,000 - December 31, AECO/NYMEX US$($0.55) Swap (356)
Gas mmbtu/day 2010 Basis diff
January 1, 2010
Oil 250 - December 31, CDN$ WTI $78.50 Swap (734)
bbl/day 2010
January 1, 2010
Oil 500 - December 31, CDN$ WTI $72.00 - Collar (700)
bbl/day 2010 $88.00
January 1, 2010
Oil 250 - December 31, CDN$ WTI $82.50 Swap (366)
bbl/day 2010
January 1, 2010
Oil 500 - December 31, CDN$ WTI $80.50 Swap (1,100)
bbl/day 2010
January 1, 2010
Oil 500 - December 31, US$ WTI US$81.00 Swap (249)
bbl/day 2010
January 1, 2010
Oil 250 - December 31, CDN$ WTI $80.00 - Collar 81
bbl/day 2010 $95.02
----------------------------------------------------------------------------
Total commodity contracts (1,584)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Term Reference Strike Option Value
Contract Quantity Price Traded ($000s)
----------------------------------------------------------------------------
Foreign exchange contracts
January 1, 2010
USD / CAD $ US $2M / - December 31, CAD/USD 1.094 Swap 1,022
exchange Month 2010
----------------------------------------------------------------------------
Total foreign exchange contracts 1,022
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Term Reference Strike Option Value
Contract Quantity Price Traded($000s)
----------------------------------------------------------------------------
Interest rate contracts
$50M / February 10, 2009 -
BA Rate year February 10, 2011 BA - CDOR 1.10% Swap (156)
$50M / February 12, 2009 -
BA Rate year February 12, 2011 BA - CDOR 1.10% Swap (116)
$50M / May 28, 2009 -
BA Rate year May 28, 2011 BA - CDOR 1.12% Swap -
----------------------------------------------------------------------------
Total interest rate contracts (272)
----------------------------------------------------------------------------
Total financial instruments (834)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December 31, 2009, a $0.10 change to the price per thousand cubic feet of
natural gas on the natural gas contracts outlined above would have a $0.1
million impact on net income.
As at December 31, 2009, a $1.00 per barrel change to the price on the oil
contracts outlined above would have a $0.6 million impact on net income.
As at December 31, 2009, a $0.01 change to the exchange rate on the foreign
exchange contracts outlined above would have a $0.2 million impact on net
income.
As at December 31, 2009, a 0.1% change to the interest rate on the interest rate
contracts outlined above would have a $0.1 million impact on net income.
Subsequent to December 31, 2009, the Company entered into the following
financial derivative contracts:
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Subject of Notional Strike Option
Contract Quantity Term Reference Price Traded
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Natural Gas 2,500 gj/day April 1, 2010 - AECO C - $ 5.30/
October 31, 2010 Monthly Index gj Swap
Oil 250 bbl/day March 1, 2010 - $84.00/
December 31, 2010 CDN $WTI bbl Swap
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Fair value of financial instruments
The Company's financial instruments as at December 31, 2009 and 2008 include
accounts receivable, derivative contracts, accounts payable and accrued
liabilities, and bank debt. The fair value of accounts receivable and accounts
payable and accrued liabilities approximate their carrying amounts due to their
short-terms to maturity.
The fair value of derivative contracts is determined by discounting the
difference between the contracted price and published forward price curves as at
the balance sheet date, using the remaining contracted petroleum and natural gas
volumes.
Bank debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.
Financial Instrument Classification and Measurement
Financial instruments of Crew carried on the consolidated balance sheet are
carried at amortized cost with the exception of risk management contracts, which
are carried at fair value. There were no significant differences between the
carrying value of financial instruments and their estimated fair values as at
December 31, 2009.
All of Crew's risk management contracts are transacted in active markets. Crew
classifies the fair value of these transactions according to the following
hierarchy based on the amount of observable inputs used to value the instrument.
- Level 1: Quoted prices are available in active markets for identical assets
or liabilities as of the reporting date. Active markets are those in which
transactions occur in sufficient frequency and volume to provide pricing
information on an ongoing basis.
- Level 2: Pricing inputs are other than quoted prices in active markets
included in Level 1. Prices in Level 2 are either directly or indirectly
observable as of the reporting date. Level 2 valuations are based on inputs
including quoted forward prices for commodities, time value and volatility
factors, which can be substantially observed or corroborated in the marketplace.
- Level 3: Valuations in this level are those with inputs for the asset or
liability that are not based on observable market data.
Crew's risk management contracts have been assessed on the fair value hierarchy
described above. Crew's risk management contracts are classified as Level 2.
Assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the placement within the fair value
hierarchy level.
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
loan, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes
adjustments on an on-going basis in order to maintain the flexibility needed to
achieve the Company's long-term objectives. To manage the capital structure the
Company may adjust capital spending, hedge future revenue and costs, issue new
equity, issue new debt or repay existing debt through asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1.0 in a normalized commodity price environment. This ratio may increase at
certain times as a result of acquisitions or low commodity prices. As shown
below, as at December 31, 2009, the Company's ratio of net debt to annualized
funds from operations was 1.67 to 1 (December 31, 2008 - 2.15 to 1). The ratio
improved over the prior year as a result of the equity financing completed in
May 2009 and non-core asset dispositions during the year.
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2009 2008
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Net debt:
Accounts receivable $ 37,574 $ 42,800
Accounts payable and accrued liabilities (84,228) (74,622)
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Working capital deficiency $ (46,654) $ (31,822)
Bank loan (135,601) (223,628)
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Net debt $ (182,255) $ (255,450)
Three months Three months
ended ended
Dec. 31, 2009 Dec. 31, 2008
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Annualized funds from operations:
Cash provided by operating activities $ 16,734 $ 25,700
Asset retirement expenditures 111 152
Transportation liability charge 329 328
Change in non-cash working capital 10,082 3,466
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Fourth quarter funds from operations 27,256 29,646
Annualized $ 109,024 $ 118,584
Net debt to annualized funds from operations 1.67 2.15
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The Company will execute a conservative capital spending program in 2010
currently estimated at a net $120 million. The Company has commodity, interest
rate and foreign exchange hedging for 2010 to provide support for its funds from
operations and assist in funding its capital expenditure program. The Company
may also consider the sale of additional non-core assets and will consider other
forms of financing to improve the Company's financial position if cash flow does
not adequately fund the programs planned to achieve the Company's long term
objectives.
There has been no change in the Company's approach to capital management during
the year ended December 31, 2009.
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 loss before income taxes. This
difference results from the following items:
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Year ended, Year ended
Dec. 31, 2009 Dec. 31, 2008
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Loss before income taxes $ (53,570) $ (46,871)
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Combined federal and provincial income tax rate 29.10% 29.70%
Computed "expected" income tax reduction $ (15,589) $ (13,921)
Increase (decrease) in income taxes
resulting from:
Non-deductible stock-based compensation 966 990
Non-deductible write-down of goodwill - 20,514
Benefits relating to change in income tax rates (731) (1,169)
Other (401) 34
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Future income tax expense (reduction) $ (15,755) $ 6,448
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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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December 31, December 31,
2009 2008
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Future income tax:
Property, plant and equipment $ 121,282 $ 136,597
Asset retirement obligations (8,953) (9,062)
Share issue costs (2,381) (2,956)
Non-capital loss (8,287) (7,813)
Other (684) (489)
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Future income tax liability $ 100,977 $ 116,277
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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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Year ended, Year ended
Dec. 31, 2009 Dec. 31, 2008
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Changes in non-cash working capital:
Accounts receivable $ 5,226 $ 8,660
Accounts payable and accrued liabilities 9,606 3,155
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$ 14,832 $ 11,815
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Operating activities $ 1,109 $ (2,346)
Investing activities 13,723 14,161
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$ 14,832 $ 11,815
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The Company made the following cash outlays in respect of interest expense:
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Year ended, Year ended
Dec. 31, 2009 Dec. 31, 2008
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Interest $ 6,246 $ 6,471
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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 2010 2011 2012 2013 2014 Thereafter
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Operating
leases $ 4,795 $ 1,743 $ 1,743 $ 1,309 - - -
Capital
commitments 6,000 3,000 3,000 - - - -
Transportation
agreements 13,977 7,339 6,638 - - - -
Processing
agreement 29,935 2,493 3,049 3,049 3,049 3,049 15,246
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Total $54,707 $14,575 $14,430 $ 4,358 $ 3,049 $ 3,049 $15,246
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The firm transportation commitments were acquired as part of the Company's May
2007 private company acquisition and represent firm service commitments for
transportation and processing of natural gas in British Columbia.
During 2009, Crew entered into an agreement to process natural gas through a
third party owned gas processing facility in the Septimus area of northeast
British Columbia. Under the terms of the agreement, Crew has committed to
process a minimum monthly volume of gas through the facility commencing on
December 1, 2009 and continuing through November 30, 2019. The commitment is
included in the above table.
The agreement additionally provides Crew the option to participate in an
expansion of the facility at a cost of 50% of the total expanded facility
construction costs and subsequently become a 50% owner in the facility. If the
facility is not expanded prior to January 1, 2013, the current owner of the
facility can require Crew to purchase the existing facility for the total
construction costs of $19.1 million plus $0.7 million or alter the fees
associated with Crew's commitment in order to recover the amount of Crew's full
commitment prior to January 1, 2016.
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