Crew Energy Inc. (TSX:CR) of Calgary, Alberta is pleased to present its
operating and financial results for the three month period and year ended
December 31, 2010.
Highlights
- Fourth quarter funds from operations of $28.4 million represents an 18%
increase over the third quarter of 2010 and annual funds from operations
increased 22% to $101.5 million over 2009;
- Funds from operations per share increased 21% over the third quarter of 2010
and annual funds from operations per share increased 12% over 2009;
- Achieved all in finding, development and acquisition costs of $11.03 per boe
on proved reserves and $11.40 per boe on proved plus probable reserves including
future development costs and revisions;
- Fourth quarter production averaged 14,654 boe per day which was a 12% increase
over the third quarter of 2010;
- A fourth quarter 2010 operating netback of $23.55 per boe and exceptional
finding, development and acquisition costs of $11.40 per boe yielded a recycle
ratio of 2.1x representing a 10% improvement over 2009;
- Operating costs were 8% lower in the fourth quarter of 2010 compared with the
same period in 2009.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
Financial months ended months ended Year ended Year ended
($ thousands, except December 31, December 31, December 31, December 31,
per share amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Petroleum and natural
gas sales 56,620 57,646 206,343 181,829
Funds from operations
(note 1) 28,436 27,256 101,450 83,453
Per share - basic 0.35 0.35 1.27 1.11
- diluted 0.35 0.35 1.24 1.11
Net income (loss) (9,525) (9,154) (17,161) (37,815)
Per share - basic (0.12) (0.12) (0.22) (0.50)
- diluted (0.12) (0.12) (0.22) (0.50)
Exploration and
development investment 61,348 55,312 248,870 128,567
Property acquisitions
(net of dispositions) 620 (44,315) (132,020) (78,693)
Net capital
expenditures 61,968 10,997 116,850 49,874
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at As at
Capital Structure Dec. 31, Dec. 31,
($ thousands) 2010 2009
----------------------------------------------------------------------------
Working capital deficiency (note 2) 40,707 46,654
Bank loan 138,700 135,601
Net debt 179,407 182,255
Bank facility 240,000 250,000
Common Shares Outstanding (thousands) 80,368 78,152
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 accounts receivable and assets held
for sale less accounts payable and accrued liabilities.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months ended months ended Year ended Year ended
December 31, December 31, December 31, December 31,
Operations 2010 2009 2010 2009
----------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 49,104 51,871 49,672 53,698
Oil (bbl/d) 5,321 4,413 4,175 3,690
Natural gas liquids (bbl/d) 1,149 1,412 1,235 1,362
Oil equivalent (boe/d @ 6:1) 14,654 14,470 13,689 14,002
Average prices (note) 1)
Natural gas ($/mcf) 3.92 4.98 4.45 4.27
Oil ($/bbl) 68.17 68.16 67.48 59.39
Natural gas liquids ($/bbl) 52.57 47.91 50.70 36.28
Oil equivalent ($/boe) 42.00 43.30 41.30 35.58
Netback ($/boe)
Operating netback (note 2) 23.55 23.29 22.86 18.87
Realized loss/(gain) on
financial instruments
(note 3) (0.02) 0.20 0.10 0.15
G&A 1.41 1.11 1.30 1.12
Interest and other 1.06 1.50 1.16 1.27
Funds from operations 21.10 20.48 20.30 16.33
Drilling Activity
Gross wells 21 23 80 43
Working interest wells 19.8 21.3 75.2 36.1
Success rate, net wells 95% 95% 99% 97%
Undeveloped land
Gross acres 1,108,552 1,055,660
Net acres 612,003 585,732
Reserves (Proved plus
probable) (note 4)
Oil (Mbbl) 22,186 15,226
Ngl (Mbbl) 6,724 6,650
Gas (Mmcf) 274,685 263,187
BOE (Mboe) 74,691 65,741
Finding, Development &
Acquisition Costs ($/boe) 11.40 9.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 related contracts less
royalties, operating costs and transportation costs calculated on a boe
basis. Operating netback and funds from operations netback do not have a
standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
(3) Amount includes realized gains and losses on non-commodity related
financial instruments.
(4) More detailed information in respect of the results of Crew's
independent reserve evaluation for the year ended December 31, 2010 as
evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") and related
information was contained in Crew's press release dated February 23,
2011 and will be contained in Crew's Annual Information Form to be filed
on or before March 31, 2011.
OVERVIEW
During 2010, economies around the world continued to slowly recover from the
financial crisis of 2008 and 2009. The financial stimulus that was injected by
governments around the globe continued to aid this recovery as modest economic
growth was experienced in many countries including the United States and Canada.
Asia, and in particular, China remained a bright spot as its economy continued
its torrid growth with an insatiable appetite for raw materials. Oil prices
benefited from improved demand for commodities as the pricing volatility that
had been experienced in the previous two years calmed with West Texas
Intermediate ("WTI") prices trading between US$75 to US $85 for most of the
year.
The North American natural gas market paints a contrasting picture. With
continued aggressive development of unconventional natural gas resource plays
throughout North America the supply of natural gas has significantly outpaced
North American demand. Prices for natural gas sold in Canada opened 2010 above
$5.00 per million cubic feet in January and February as a result of a cold North
American winter but rapidly declined in March to average below $4 per million
cubic feet for the remainder of the year.
With a depressed natural gas market, Crew focused more of its 2010 capital
expenditure program towards development of its oil resource play in the Princess
area of Southern Alberta. The Company directed 62% of its exploration and
development budget towards continued growth of this top tier oil play drilling
54 net oil wells and eight service wells in the area, increasing area production
to approximately 8,000 boe per day at year end. Expenditures at Princess were
also directed to continued development of the area's extensive pipeline and
facility infrastructure and the acquisition of 58 sections of undeveloped lands
prospective for Pekisko and Mannville development.
During 2010, Crew also continued to develop its Montney assets in northeast
British Columbia. The primary focus of the Company's efforts was the continued
development of liquids rich natural gas development at Septimus. During the year
the Company directed 24% of its total exploration and development budget toward
Septimus, drilling a total of 10 (9.5 net) wells which increased production 81%
from January to December. To accommodate the Company's planned Septimus
production growth, Crew proceeded with the expansion of the area's gas
processing facility that was completed in the first quarter of 2011. Crew also
drilled and completed a horizontal Montney exploration well at Portage, British
Columbia which completed the earning of 32 net sections of land prospective for
Doig and Montney natural gas.
The Company strengthened its balance sheet in the second quarter of 2010 with
the sale of assets in the Edson, Alberta area which included 1,700 boe per day
of natural gas and natural gas liquids production and 7.1 mmboe of proved plus
probable reserves for proceeds of $126 million. The sale of these natural gas
assets allowed the Company to continue to accelerate development of its oil
assets and resource capture at Princess.
The sale of assets at Edson and the impact of poor spring and summer weather on
production at Princess resulted in a decline in production from a first quarter
average of 15,001 boe per day to an average of 13,689 boe per day for the year.
While the Company's average production was impacted by an unusually wet summer
in southern Alberta, an aggressive third and fourth quarter capital expenditure
program resulted in the Company averaging 16,900 boe per day in December with
production over 17,500 boe per day in the latter part of December.
The Company's financial results were aided by increased oil production, stronger
oil prices and lower operating costs in 2010 with funds from operations
increasing 22% to $101.5 million. The Company's financial position remained
strong with net debt at year end of $179 million or 1.6 times annualized fourth
quarter funds from operations.
OPERATIONS UPDATE
Pekisko Play, Princess, Alberta
Crew is pleased with the progress made in the Pekisko play at Princess. In 2010,
Crew increased proved plus probable reserves by 59% to 24.1 million boe and 240%
since the asset was acquired in 2008. At the end of 2010, Crew had 52 horizontal
wells on production that have first month initial production rates averaging 218
boe per day (90% oil) which led to an exit rate of approximately 8,000 boe per
day in the area. Crew currently plans on drilling 73 net horizontal wells, 25
net vertical wells and 21 net service wells in 2011 which is expected to
generate average annual production of approximately 9,400 boe per day and exit
production of over 12,000 boe per day.
In the first quarter of 2011, Crew currently has five drilling rigs and five
service rigs working at Princess. To date, the Company has drilled 16 net
horizontal wells with two currently drilling and five more scheduled to be
drilled in the first quarter. Six vertical wells have been drilled with two
currently drilling and seven additional wells planned in the first quarter. Two
service wells have been drilled and one is currently drilling to complete the
first quarter drilling program at Princess. Crew has tied in two wells thus far
in the quarter that are currently averaging 290 boe per day.
Montney Play, Septimus, British Columbia
In the Montney play at Septimus, Crew's 2010 drilling program was very
successful increasing reserves by 19% over 2009 to 25.7 million boe. Reserves
per well also increased to 2.9 bcf representing a 7% increase. The Company
believes this area holds significant upside as the reserves currently assigned
represent an estimated 14% recovery factor.
Crew has drilled two (1.33 net) wells and is currently drilling one well with a
fourth well scheduled to be drilled in the first quarter. The first well of this
program is currently being completed with one additional well expected to be
completed by spring breakup. Of the wells expected to be drilled in the area in
the first quarter, there are three (3.0 net) targeting liquids rich natural gas
and one (0.33 net) targeting the oil window in the upper Montney zone. Plans for
2011 are to drill 6 (5.33 net) wells at Septimus.
In early February, Crew completed the expansion of the Septimus gas processing
facility doubling its capacity to approximately 50 mmcf per day. Upon completion
of the expansion, the Company completed a previously arranged transaction
recovering the $16.9 million cost of the expansion from Aux Sable Canada ("ASC")
who now owns 100% of the expanded facility. Under the terms of the arrangement,
Crew will remain operator of the facility and has retained the option to
re-purchase a 50% interest in the facility, at Crew's option, on or before
January 1, 2014.
EXPANDED DRILLING PROGRAM
The previously announced expansion of the capital program as a result of the
Company's recent equity financing will allow Crew to test a number of resource
exploration concepts on its land base. The Company has also identified
additional opportunities for resource capture that it plans to pursue over the
balance of the year.
In West Central Alberta, the Company plans to drill two wells targeting light
oil in the Cardium formation where the Company owns 40 net sections of
prospective land and three wells targeting liquids rich gas in the Mannville
group where Crew owns 30 net sections of land.
At Provost, Alberta, Crew plans to drill two to three wells targeting light oil
from the Viking formation where the Company owns 16 net sections of prospective
land.
At Kobes, British Columbia, Crew plans to drill its first horizontal well
targeting the lower Montney offsetting a vertical well that tested 2.5 mmcf per
day and 125 bbls per day of condensate. The Company believes there is
potentially 1,000 feet of gas saturated rock on 23 net sections at Kobes that,
if successful, may ultimately require eight to twelve wells per section to
adequately deplete the resource.
OUTLOOK
The Board of Directors of Crew has approved an increase in the 2011 capital
expenditure budget to $260 million which is expected to include the drilling of
a record 130 net wells. Over 90% of this drilling program is dedicated to the
Company's Princess oil play. This program is expected to be adequately financed
through the recently closed $100 million bought deal financing, cash flow and
the Company's recently expanded $240 million bank facility. With an emphasis on
oil drilling, the Company is expecting the liquids component of its production
to increase to approximately 55% to 60% of total oil and natural gas production
by year end resulting in average production of between 18,300 and 19,300 boe per
day and exit production of 21,000 to 22,000 boe per day.
We are confident in the quality of our assets and the opportunities they provide
our shareholders. The Company will continue to strive to improve operating
metrics and the efficient execution of our very active capital program. We are
well positioned to deliver sustainable reserve and production growth in 2011 and
beyond and look forward to reporting our progress in the first quarter 2011
report.
Management's Discussion and Analysis
ADVISORIES
Management's discussion and analysis ("MD&A") is the Company's explanation of
its financial performance for the period covered by the financial statements
along with an analysis of the Company's financial position. Comments relate to
and should be read in conjunction with the unaudited consolidated financial
statements of the Company for the three month periods and years ended December
31, 2010 and 2009 and the audited consolidated financial statements and
Management Discussion and Analysis for the year ended December 31, 2009. The
consolidated financial statements have been prepared in accordance with
generally accepted accounting principles ("GAAP") in Canada and all figures
provided herein and in the December 31, 2010 and 2009 consolidated financial
statements are reported in Canadian dollars.
Forward Looking Statements
This MD&A contains forward-looking statements. Management's assessment of future
plans and operations, drilling plans and the timing thereof, plans for the
tie-in and completion of wells and the timing thereof, capital expenditures,
timing of capital expenditures and methods of financing capital expenditures and
the ability to fund financial liabilities, production estimates, expected
commodity mix and prices and the impact on Crew, future operating costs, future
transportation costs, expected royalty rates, future general and administrative
expenses, interest rates, debt levels, funds from operations, the timing of and
impact of adoption of IFRS, policy choices to be made under 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 and partner 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, regulatory and partner approvals, equipment
and services in a timely and cost efficient manner; drilling results; the
ability of the operator of the projects which the Company has an interest in to
operate the field in a safe, efficient and effective manner; Crew's ability to
obtain financing on acceptable terms; field production rates and decline rates;
the ability to reduce operating costs; the ability to replace and expand oil and
natural gas reserves through acquisition, development or exploration; the timing
and costs of pipeline, storage and facility construction and expansion; the
ability of the Company to secure adequate product transportation; future
petroleum and natural gas prices; currency, exchange and interest rates; the
regulatory framework regarding royalties, taxes and environmental matters in the
jurisdictions in which the Company operates; and Crew's ability to successfully
market its petroleum and natural gas products. Readers are cautioned that the
foregoing list of factors is not exhaustive. Additional information on these and
other factors that could affect the Company's operations and financial results
are included in reports on file with Canadian securities regulatory authorities
and may be accessed through the SEDAR website (www.sedar.com) or at the
Company's website (www.crewenergy.com). Furthermore, the forward looking
statements contained in this document are made as at the date of this document
and the Company does not undertake any obligation to update publicly or to
revise any of the included forward looking statements, whether as a result of
new information, future events or otherwise, except as may be required by
applicable securities laws.
Conversions
The oil and gas industry commonly expresses production volumes and reserves on a
"barrel of oil equivalent" basis ("boe") whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved analysis of results and comparisons with other industry participants.
Throughout this MD&A, Crew has used the 6:1 boe measure which is the approximate
energy equivalency of the two commodities at the burner tip. Boe does not
represent a value equivalency at the wellhead nor at the plant gate which is
where Crew sells its production volumes and therefore may be a misleading
measure, particularly if used in isolation.
Non-GAAP Measures
One of the benchmarks Crew uses to evaluate its performance is funds from
operations. Funds from operations is a measure not defined in GAAP that is
commonly used in the oil and gas industry. It represents cash provided by
operating activities before changes in non-cash working capital, asset
retirement expenditures and the transportation liability charge. The Company
considers it a key measure as it demonstrates the ability of the business to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Funds from operations should not be considered as
an alternative to or more meaningful than cash provided by operating activities,
as determined in accordance with GAAP, as an indicator of the Company's
performance. Crew's determination of funds from operations may not be comparable
to that reported by other companies. Crew also presents funds from operations
per share whereby per share amounts are calculated using weighted average shares
outstanding consistent with the calculation of income per share. The following
table reconciles Crew's cash provided by operating activities to funds from
operations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
($ thousands) 31, 2010 31, 2009 31, 2010 31, 2009
----------------------------------------------------------------------------
Cash provided by operating
activities 21,212 16,734 97,170 82,659
Asset retirement expenditures 606 111 1,512 589
Transportation liability charge
(note 1) 120 329 758 1,314
Change in non-cash working capital 6,498 10,082 2,010 (1,109)
----------------------------------------------------------------------------
Funds from operations 28,436 27,256 101,450 83,453
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes:
(1) The amount for the year ended December 31, 2010 does not include the
transportation liability write-down of $344,000 as described in the
Transportation Costs section.
Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore, may not be
comparable with the calculation of similar measures for other entities.
Operating netback equals total petroleum and natural gas sales including
realized gains and losses on commodity related contracts less royalties,
operating costs and transportation costs calculated on a boe basis. Management
considers operating netback an important measure to evaluate its operational
performance as it demonstrates its field level profitability relative to current
commodity prices.
RESULTS OF OPERATIONS
Production
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended Three months ended
December 31, 2010 December 31, 2009
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta 5,172 393 23,358 9,458 4,256 828 30,844 10,224
British
Columbia 149 756 25,746 5,196 157 584 21,027 4,246
----------------------------------------------------------------------------
Total 5,321 1,149 49,104 14,654 4,413 1,412 51,871 14,470
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production for the fourth quarter of 2010 was slightly higher than the same
period in 2009 due to a successful drilling program at Princess, Alberta.
Natural gas and associated liquids production decreased in the fourth quarter
compared with the fourth quarter of 2009 due to the disposition of approximately
2,300 boe per day of primarily natural gas production from two separate
dispositions at Ferrier and Edson, Alberta which closed in late 2009 and at the
end of the first quarter of 2010, respectively. These dispositions were
partially offset by production additions from a successful drilling program
which added liquids rich natural gas production in the Septimus, British
Columbia area. Oil production increased 21% in the fourth quarter of 2010
compared to the same period in 2009 due to production additions from Princess.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, 2010 December 31, 2009
Oil Ngl Nat. gas Total Oil Ngl Nat. gas Total
(bbl/d) (bbl/d) (mcf/d) (boe/d) (bbl/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Alberta 4,043 500 24,502 8,627 3,496 893 35,373 10,285
British
Columbia 132 735 25,170 5,062 194 469 18,325 3,717
----------------------------------------------------------------------------
Total 4,175 1,235 49,672 13,689 3,690 1,362 53,698 14,002
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Production for 2010 decreased over 2009 due to the previously mentioned asset
dispositions but was partially offset by production additions from a successful
drilling program as described above. Weather related delays hampered activity in
the second and third quarter of 2010 in southern Alberta which created delays in
bringing on new oil production; consequently, the Company's annual oil
production for 2010 was below its original expectations.
Revenue
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 2010 31, 2009 31, 2010 31, 2009
----------------------------------------------------------------------------
Revenue ($ thousands)
Natural gas 17,691 23,746 80,656 83,699
Oil 33,373 27,674 102,824 79,997
Natural gas liquids 5,556 6,226 22,863 18,035
Sulphur - - - 98
----------------------------------------------------------------------------
Total 56,620 57,646 206,343 181,829
----------------------------------------------------------------------------
Crew average prices
Natural gas ($/mcf) 3.92 4.98 4.45 4.27
Oil ($/bbl) 68.17 68.16 67.48 59.39
Natural gas liquids ($/bbl) 52.57 47.91 50.70 36.28
Oil equivalent ($/boe) 42.00 43.30 41.30 35.58
Benchmark pricing
Natural Gas - AECO C daily index
(Cdn $/mcf) 3.68 4.61 4.06 4.03
Oil - Bow River Crude Oil (Cdn $/bbl) 78.25 77.45 77.22 68.71
Oil and ngl - Cdn$ West Texas Int.
(Cdn $/bbl) 86.25 80.48 81.86 69.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's fourth quarter 2010 revenue decreased 2% over the same period in 2009
primarily due to a 21% decrease in its natural gas price partially offset by a
21% increase in oil production. Crew's average price received for natural gas
production decreased 21% which was comparable to the decrease in the Company's
AECO C benchmark price. The Company's oil price was consistent from the fourth
quarter of 2010 to the same period in 2009 which was in line with a minor change
in the Company's benchmark Bow River Crude price. The price received for the
Company's natural gas liquids ("ngl") production increased 10% in the fourth
quarter of 2010 as compared to the same period in 2009 which was comparable to
the increase in the Company's Cdn$ West Texas Intermediate benchmark.
For 2010, Crew's natural gas price increased 4% compared to a minor increase in
the Company's benchmark. Decreased production of lower valued Sierra, British
Columbia natural gas production that was replaced by higher valued Septimus
natural gas production accounts for the disproportionate increase in pricing.
Crew's oil price increased proportionately with the Bow River Crude Oil
benchmark for the year ended December 31, 2010. The Company's ngl price
increased disproportionately as compared to the Company's Cdn$ West Texas
Intermediate benchmark due to the disposition of lower valued ethane production
in the Ferrier area in late 2009 and increased sales of higher valued condensate
production in the Septimus area.
Royalties
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
Dec. 31, Dec. 31, Dec. 31, Dec. 31,
($ thousands, except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Royalties 11,311 13,167 41,799 36,027
Per boe $ 8.39 $ 9.89 $ 8.37 $ 7.05
Percentage of revenue 20.0% 22.8% 20.3% 19.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Royalties as a percentage of revenue decreased in the fourth quarter of 2010 as
compared with the same period in 2009 due to new natural gas production at
Septimus which currently attracts a lower royalty rate and due to a lower
natural gas price which decreases the natural gas royalty rates in Alberta. This
was partially offset by new oil production in the Princess area which attracts a
higher royalty rate than the Company's existing production.
For the year ended December 31, 2010, royalties as a percentage of revenue
slightly increased over the same period in 2009 due to additional higher royalty
rate production from the Princess area combined with the disposition of lower
royalty rate natural gas production from the Edson properties in early 2010.
Corporately, with an increase in forecasted Princess area production, Crew
expects annual royalties as a percentage of revenue to average approximately 25%
for 2011.
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 primarily on the use of puts, costless
collars, swaps and fixed price contracts to reduce exposure to fluctuations in
commodity prices, interest rates and foreign exchange rates while allowing for
participation in commodity price increases. The Company's financial derivative
trading activities are conducted pursuant to the Company's Risk Management
Policy approved by the Board of Directors. In 2010, these contracts had the
following impact on the consolidated statement of operations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Realized gain on financial
instruments 3,284 4,471 13,082 18,461
Unrealized loss on financial
instruments (12,586) (6,225) (7,380) (2,089)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at December 31, 2010, the Company held derivative commodity contracts as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
AECO C
Natural January 1, 2011 - Monthly
Gas 2,500 gj/day December 31, 2011 Index $ 4.85 Swap(1) 961
AECO C
Natural January 1, 2011 - Monthly
Gas 2,500 gj/day December 31, 2011 Index $ 4.90 Swap(1) 1,001
AECO C
Natural January 1, 2011 - Monthly
Gas 2,500 gj/day December 31, 2011 Index $ 4.95 Swap(1) 1,046
AECO C
Natural January 1, 2011 - Monthly
Gas 2,500 gj/day December 31, 2011 Index $ 4.965 Swap(1) 1,058
AECO C
Natural January 1, 2011 - Monthly
Gas 7,500 gj/day December 31, 2011 Index $ 5.00 Swap(1) 3,276
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 US$ WTI US$80.15 Swap (2,478)
January 1, 2011 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 86.00 Swap (723)
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 CDN$ WTI $ 88.00 Swap (1,031)
January 1, 2011 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 88.50 Swap (474)
January 1, 2011 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 90.00 Swap (332)
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 CDN$ WTI $ 90.20 Swap (641)
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 CDN$ WTI $ 93.00 Swap 15
January 1, 2011 - $80.00 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 95.45 Collar (307)
January 1, 2011 - $82.00 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 94.62 Collar (340)
January 1, 2011 - $85.00 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 100.50 Collar (24)
January 1, 2011 - CDN$ WCS -
Oil 500 bbl/day June 30, 2011 WTI diff ($18.00) Swap (46)
January 1, 2012 -
Oil 500 bbl/day December 31, 2012 CDN$ WTI $ 85.00 Call(1) (3,081)
January 1, 2012 -
Oil 750 bbl/day December 31, 2012 CDN$ WTI $ 90.00 Call(1) (3,548)
January 1, 2012 -
Oil 500 bbl/day December 31, 2012 US$ WTI US$90.00 Call(1) (2,566)
----------------------------------------------------------------------------
Total (8,234)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Derivative contracts are part of a paired transaction in which the
proceeds from the sale of 2012 oil calls were used to fund the 2011
natural gas swaps at the prices indicated.
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, 2010, Crew
had contracts in place fixing the interest rate on $100 million of bankers'
acceptances at a rate of 1.10%. The Company pays additional stamping fees and
margins on bankers' acceptances as outlined in note 4 of the financial
statements.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
February 10, 2009 -
BA Rate $50M / year February 10, 2011 BA - CDOR 1.10% Swap 8
February 12, 2009 -
BA Rate $50M / year February 12, 2011 BA - CDOR 1.10% Swap 12
----------------------------------------------------------------------------
Total 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subsequent to December 31, 2010, the Company entered into the following
derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Strike Price Option
Contract Volume Term Reference (per bbl) Traded
----------------------------------------------------------------------------
January 1, 2012 -
Oil 500 bbl/day December 31, 2012 CDN $WTI $ 101.00/bbl Swap
January 1, 2012 -
Oil 250 bbl/day December 31, 2012 CDN $WTI $ 100.45/bbl Swap
January 1, 2012 -
Oil 250 bbl/day December 31, 2012 CDN $WTI $ 100.50/bbl Swap
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended ended Year ended Year ended
($ thousands, December 31, December 31, December 31, December 31,
except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Operating costs 14,009 15,084 53,976 57,342
Per boe $ 10.39 $ 11.33 $ 10.80 $ 11.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the fourth quarter of 2010, the Company's operating costs and costs per unit
decreased over the same period in 2009 due to the addition of lower cost natural
gas and associated liquids production in the Septimus area. This was partially
offset by the addition of higher cost production from the Princess area and the
disposition of lower cost production in the Ferrier and Edson areas in late 2009
and early 2010.
For 2010, additional oil production at Princess with higher costs was more than
offset by lower cost natural gas and associated liquids production additions in
the Septimus area thus decreasing overall corporate operating costs. In 2010,
although additional production partially offset fixed costs, Crew continued to
contend with fluid handling in the Princess area. Delays in regulatory approval
of water injection wells hampered the timing of activating these wells thus
increasing oil operating costs for the year. The Company continues to research
and identify cost cutting measures in order to be proactive in water handling
and lowering oil operating costs in the area. With increased forecasted
production in the Princess area, the Company forecasts corporate operating costs
to average between $10.50 and $11.00 per boe for 2011.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
($ thousands, ended ended Year ended Year ended
except per boe) December 31, December 31, December 31, December 31,
2010 2009 2010 2009
----------------------------------------------------------------------------
Transportation costs 2,819 3,134 9,582 11,229
Transportation
liability write-down - - 344 -
----------------------------------------------------------------------------
Transportation costs
excluding liability
write-down 2,819 3,134 9,926 11,229
Per boe $ 2.09 $ 2.35 $ 1.99 $ 2.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the fourth quarter of 2010, the Company's transportation costs and
transportation costs per unit decreased over the same period in 2009 due to the
Company permanently assigning a significant portion of its unutilized firm
transportation commitment in northeastern British Columbia in March 2010.
Transportation costs increased in the fourth quarter of 2010 compared to the
2010 annual average due to the increased costs per unit of transporting Septimus
natural gas volumes to the Alliance pipeline system, additional condensate
production at Septimus, which attracts a higher trucking cost, and added clean
oil trucking costs at Princess for delivering a portion of the area's volumes to
an alternative terminal in order to receive enhanced pricing.
For 2010, the Company's transportation costs and transportation costs per unit
decreased over 2009 due to the previously mentioned assignment of the unutilized
firm transportation commitment as well as additional oil production from the
Princess area which currently attracts a lower clean oil trucking cost than the
corporate average transportation cost per boe. The Company forecasts
transportation costs to range between $1.90 and $2.15 per boe for 2011.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
December 31, 2010
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 68.17 52.57 3.92 42.00
Realized commodity hedging
gain (loss) (1.37) - 0.87 2.42
Royalties (19.28) (11.89) (0.14) (8.39)
Operating costs (13.31) (7.84) (1.47) (10.39)
Transportation costs (1.56) (1.94) (0.41) (2.09)
----------------------------------------------------------------------------
Operating netbacks 32.65 30.90 2.77 23.55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
December 31, 2009
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 68.16 47.91 4.98 43.30
Realized commodity hedging
gain (loss) (0.61) - 1.06 3.56
Royalties (21.07) (10.51) (0.68) (9.89)
Operating costs (10.30) (9.64) (2.02) (11.33)
Transportation costs (1.45) (0.89) (0.51) (2.35)
----------------------------------------------------------------------------
Operating netbacks 34.73 26.87 2.83 23.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended
December 31, 2010
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 67.48 50.70 4.45 41.30
Realized commodity hedging
gain (loss) 0.45 - 0.71 2.72
Royalties (19.41) (10.88) (0.40) (8.37)
Operating costs (13.85) (8.31) (1.61) (10.80)
Transportation costs (1.46) (1.42) (0.37) (1.99)
----------------------------------------------------------------------------
Operating netbacks 33.21 30.09 2.78 22.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended
December 31, 2009
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 59.39 36.28 4.27 35.58
Realized commodity hedging
gain (loss) (0.01) - 0.98 3.76
Royalties (16.66) (10.09) (0.43) (7.05)
Operating costs (11.30) (9.40) (1.91) (11.22)
Transportation costs (1.59) (0.29) (0.46) (2.20)
----------------------------------------------------------------------------
Operating netbacks 29.83 16.50 2.45 18.87
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands, except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Gross costs 4,698 4,026 16,420 14,160
Operator's recoveries (890) (1,080) (3,463) (2,689)
Capitalized costs (1,904) (1,473) (6,478) (5,735)
----------------------------------------------------------------------------
General and administrative expenses 1,904 1,473 6,479 5,736
Per boe $ 1.41 $ 1.11 $ 1.30 $ 1.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increased fourth quarter 2010 general and administrative costs before recoveries
and capitalization were mainly due to increased staff levels, increased salary
levels and the cost of additional office space added in 2010 in order to
accommodate the Company's growth. In the fourth quarter of 2010, recoveries
slightly decreased over the same period in 2009 due to the Company contract
operating fewer wells, while capitalized costs increased over the same period of
2009 due to increased capital related activities during the fourth quarter of
2010.
For 2010, gross costs before recoveries and capitalization as well as net
general and administrative costs have increased as a result of increased staff
levels and increased office rent costs to accommodate the Company's larger
operations in Princess and Septimus. As the Company continues to expand,
combined with International Financial Reporting Standards being introduced in
2011 altering capitalization of general and administrative expenses, Crew
expects general and administrative expenses to average between $1.50 and $1.75
per boe for 2011.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands, except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Interest expense 1,425 2,003 5,795 6,503
Average debt level 120,596 158,937 96,538 194,818
Effective interest rate 4.7% 5.1% 6.0% 3.3%
Per boe $ 1.06 $ 1.50 $ 1.16 $ 1.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's fourth quarter 2010 interest expense has decreased over the same period
in 2009 due to a decrease in outstanding average debt levels. During the fourth
quarter, the margin charged on the Company's borrowings under its prime loans
and the stamping fees charged on its outstanding bankers' acceptances have
decreased but this has been partially offset by increased prime interest rates
and interest rates charged on bankers' acceptances.
Total interest expense for 2010 has decreased compared to 2009 due to a
significant decrease in outstanding average debt levels. Effective interest
rates increased in 2010 due to increased standby fees charged on the unutilized
bank facility and the amortization of annual renewal fees against the
significantly decreased drawn facility as the denominator. Crew's effective
interest rate is expected to average approximately 5.00% in 2011.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Gross costs 2,186 1,586 9,034 6,642
Capitalized costs (1,093) (793) (4,517) (3,321)
----------------------------------------------------------------------------
Total stock-based compensation 1,093 793 4,517 3,321
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has increased in the fourth
quarter and for 2010 over the same periods in 2009 due to an increase in the
fair value of stock options that were issued to Crew employees and service
providers, resulting from the Company's increased share price.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
($ thousands, except per boe) 31, 2010 31, 2009 31, 2010 31, 2009
----------------------------------------------------------------------------
Depletion, depreciation and accretion 27,736 31,677 113,214 131,613
Per boe 20.57 23.80 22.66 25.75
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Depletion, depreciation and accretion costs and per unit costs have decreased in
the fourth quarter of 2010 compared with the same period in 2009 due to low cost
reserve additions from a successful drilling program in the Company's Septimus
and Princess areas as well as the sale of the Edson assets which received a
greater price per unit than the Company's corporate depletion rate.
In 2010, per unit depletion rates decreased 12% over 2009. The Company's
successful drilling program in Septimus and Princess continued to add low cost
proven reserves. During 2010, the Company was also successful in reducing its
infrastructure costs by taking advantage of government incentive programs in
British Columbia. The disposition of the Edson assets in March 2010 also
received a greater price per unit than the Company's corporate depletion rate
thus lowering the corporate depletion rate.
Crew performed a ceiling test as at December 31, 2010. 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 carrying value of the Company's property plant and equipment was
considered recoverable.
Future Income Taxes
The provision for future income taxes was a recovery of $3.5 million in the
fourth quarter of 2010 and a recovery of $6.2 million for 2010 compared to
recoveries of $2.3 million and $15.8 million, respectively, for the same periods
of 2009. In the fourth quarter of 2010, the increased recovery was a result of a
greater pre-tax loss. For 2009, the Company had a greater pre-tax loss for the
year as compared with 2010 and therefore had an increased future tax recovery.
A summary of the Company's estimated income tax pools at December 31, 2010 is
outlined below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Dec. 31, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
Cumulative Canadian Exploration Expense 120,600 108,900
Cumulative Canadian Development Expense 223,800 132,200
Cumulative Canadian Oil and Gas Property Expense 23,000 110,000
Undepreciated Capital Cost 109,700 103,800
Share issue costs 1,300 5,000
Non-capital loss 31,400 32,000
----------------------------------------------------------------------------
509,800 491,900
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The estimated income tax pools for 2010 have been reduced by the estimated
deferred partnership income for 2010. The Company did not pay cash taxes in 2010
and estimates it has sufficient tax pools to shelter estimated income until 2012
or beyond.
Cash and Funds from Operations and Net Loss
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
($ thousands, except per share 31 , 31, 31, 31,
amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash provided by operating
activities 21,212 16,734 97,170 82,659
Funds from operations 28,436 27,256 101,450 83,453
Per share - basic 0.35 0.35 1.27 1.11
- diluted 0.35 0.35 1.24 1.11
Net loss (9,525) (9,154) (17,161) (37,815)
Per share - basic (0.12) (0.12) (0.22) (0.50)
- diluted (0.12) (0.12) (0.22) (0.50)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the fourth quarter and year ended December 31, 2010, an increase in cash
provided by operating activities and funds from operations was the result of an
increase in oil production which attracted a higher price than natural gas
production as well as reduced operating and transportation costs. For the fourth
quarter of 2010, the net loss was consistent with the same period in 2009 as
reduced depletion costs were offset by a net unrealized loss on financial
instruments. The net loss for 2010 was less than the net loss for the same
period in 2009 due to significantly reduced depletion, depreciation and
accretion costs which was partially offset by an increase in the unrealized loss
on financial instruments in 2010.
Capital Expenditures, Acquisitions and Dispositions
During the fourth quarter of 2010, the Company drilled 21 (19.8 net) wells,
resulting in 19 (18.5 net) oil wells, one (0.25 net) gas well and one (1.0 net)
dry & abandoned well. The Company completed 23 (21.8 net) wells during the
quarter, consisting of 18 (18.0 net) oil wells at Princess, one (0.25 net) gas
well at Kakwa, Alberta, three (3.0 net) gas wells at Septimus and one (0.5 net)
gas well at Portage, British Columbia. The Company brought a total of three
Septimus gas wells and 18 Princess oil wells on production throughout the
quarter. The Company continued adding fluid handling capacity to its three main
oil treating and water disposal facilities at Princess.
In 2010, the Company drilled 80 (75.2 net) wells resulting in 56 (54.8 net) oil
wells, 15 (11.3 net) gas wells, eight (8.0 net) water disposal wells and one
(1.0 net) dry and abandoned well. During 2010, the Company continued to add to
its undeveloped land base acquiring over 50,000 net undeveloped acres of land at
crown land sales primarily within its core area of Princess. Crew continued to
add to its infrastructure in Princess expanding its batteries and significantly
increasing its pipeline capabilities. Late in 2010, the Company substantially
completed the expansion of the Septimus facility with final testing completed in
early 2011. At the time of construction, the Company had an agreement in place
to sell the Septimus gas plant expansion for its as built cost, which closed in
early 2011. As the facility expansion was sold in early 2011, the asset was
reclassified as an asset held for sale and therefore is not included in the
capital expenditures for the year. During the year, Crew was notified that it
was granted a $7.6 million infrastructure credit from the British Columbia
government which was applied as an offset to capital expenditures in the year.
Exploration and development capital expenditures for the fourth quarter and full
year of 2010 were $61.3 million and $248.9 million, respectively, compared to
$55.3 million and $128.6 million for the same periods in 2009. The expenditures
are detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three
months months Year Year
ended ended ended ended
December December December December
31, 31, 31, 31,
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Land 1,098 5,619 38,835 10,500
Seismic 194 2,426 5,471 4,602
Drilling and completions 47,419 37,302 163,992 65,469
Facilities, equipment and pipelines 10,605 8,371 33,679 41,755
Other 2,032 1,594 6,893 6,241
----------------------------------------------------------------------------
Exploration and development 61,348 55,312 248,870 128,567
Property acquisitions (dispositions) 620 (44,315) (132,020) (78,693)
----------------------------------------------------------------------------
Total net 61,968 10,997 116,850 49,874
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's Board of Directors has approved a $260 million exploration and
development budget for 2011.
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 $220 million and an operating line
of credit of $20 million (the "Facility"). The Facility revolves for a 364 day
period and will be subject to its next 364 day extension by June 13, 2011. If
not extended, the Facility will cease to revolve, the margins thereunder will
increase by 0.50 percent and all outstanding balances under the Facility will
become repayable in one year from the extension date. 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 13, 2011. At
December 31, 2010, the Company had committed drawings of $138.7 million on the
Facility and had issued letters of credit totaling $1.1 million.
During 2010, the Company received proceeds of $20.6 million due to the exercise
of 2,216,066 employee stock options.
On March 2, 2011, the Company closed a bought deal sale of 4,820,000 Common
Shares of the Company at a price of $20.75 per share for aggregate gross
proceeds of $100 million. Crew has also granted the Underwriters an
over-allotment option to purchase, on the same terms, up to an additional
723,000 Common Shares for additional gross proceeds of up to $15.0 million
exercisable by the Underwriters, in whole or in part, at any time up to 30 days
following closing of the offering to cover the Underwriters' over-allotments, if
any.
The Company will continue to fund its on-going operations from a combination of
cash flow, debt, the proceeds from future non-core asset dispositions and equity
financings as needed. As the majority of our on-going capital expenditure
program is directed to the further growth of reserves and production volumes,
Crew is readily able to adjust its budgeted capital expenditures should the need
arise.
Working Capital
The capital intensive nature of Crew's activities generally results in the
Company carrying a working capital deficit. However, the Company maintains
sufficient unused bank credit lines to satisfy such working capital
deficiencies. At December 31, 2010, the Company's working capital deficiency
(including accounts receivable, assets held for sale, accounts payable and
accrued liabilities) totaled $40.7 million which, when combined with the
drawings on its bank line, represented 75% of its current bank facility.
Share Capital
As at March 7, 2011, Crew had issued and outstanding 85,544,234 Common Shares
and had options to acquire 5,193,500 Common Shares outstanding.
Capital Structure
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes adjustments
on an on-going basis in order to maintain the flexibility needed to achieve the
Company's long-term objectives. To manage the capital structure the Company may
adjust capital spending, hedge future revenue and some costs, issue new equity,
issue new debt or repay existing debt through non-core asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1. This ratio may increase at certain times as a result of acquisitions or low
commodity prices. As shown below, as at December 31, 2010, the Company's ratio
of net debt to annualized funds from operations was 1.58 to 1 (December 31, 2009
- 1.67 to 1).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except ratio) Dec. 31, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
Accounts receivable (including assets
held for sale) 60,038 37,574
Accounts payable and accrued liabilities (100,745) (84,228)
----------------------------------------------------------------------------
Working capital deficiency (40,707) (46,654)
Bank loan (138,700) (135,601)
----------------------------------------------------------------------------
Net debt (179,407) (182,255)
Fourth quarter 2010 funds from operations 28,436 27,256
Annualized 113,744 109,024
Net debt to annualized funds from
operations ratio 1.58 1.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contractual Obligations
Throughout the course of its ongoing business, the Company enters into various
contractual obligations such as credit agreements, purchases of services,
royalty agreements, operating agreements, processing agreements, right of way
agreements and lease obligations for office space and automotive equipment. All
such contractual obligations reflect market conditions prevailing at the time of
the contract and none are with related parties. The Company believes it has
adequate sources of capital to fund all contractual obligations as they come
due. The following table lists the Company's obligations with a fixed term.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Total 2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
Bank Loan
(note 1) 138,700 - - 138,700 - - -
Operating
Leases 3,052 1,743 1,309 - - - -
Capital
commitments 2,000 2,000 - - - - -
Transportation
agreements 22,618 4,600 1,535 1,535 2,110 2,110 10,728
Processing
agreement 77,936 6,526 6,526 6,526 8,239 8,239 41,880
----------------------------------------------------------------------------
Total 244,306 14,869 9,370 146,761 10,349 10,349 52,608
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2013; however, it is
expected that the revolving bank facility will be extended and
no repayment will be required in the near term.
The transportation agreements include a $19.5 million commitment to a third
party to transport natural gas from the gas processing facility in the Septimus
area to the Alliance pipeline system. The remaining commitment relates to firm
transportation commitments that were acquired as part of the Company's May 2007
private company acquisition. In 2010, the Company permanently assigned
approximately $6.2 million of its firm commitments to third parties.
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.
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.
In the fourth quarter of 2010, the Company amended the agreement with the owner
of this facility. Under the terms of the amended agreement, Crew constructed a
facility expansion during the fourth quarter of 2010 and subsequently closed the
sale of the Septimus facility expansion in early 2011. Upon completion of the
expansion, Crew was reimbursed for the full cost of the facility of $16.9
million in return for an expanded processing commitment that will extend to
December 2020. As this asset was classified as an asset held for sale, the
commitment is included in the above table. As part of the amended agreement,
Crew has also retained the option to re-purchase a 50% interest in the facility
at certain dates prior to January 1, 2014, at a cost of 50% of the total
expanded facility's construction cost. If the Company re-purchases a 50%
interest on January 1, 2014 for approximately $18.0 million, the remaining
commitment would be reduced by approximately $29.0 million.
Outlook
The Board of Directors of Crew has approved an increase in the 2011 capital
expenditure budget to $260 million which is expected to include the drilling of
a record 130 net wells. Over 90% of this drilling program is dedicated to the
Company's Princess oil play. This program is expected to be adequately financed
through the recently closed $100 million bought deal financing, cash flow and
the Company's recently expanded $240 million bank facility. With an emphasis on
oil drilling, the Company is expecting the liquids component of its production
to increase to approximately 55% to 60% of total oil and natural gas production
by year end resulting in average production of between 18,300 and 19,300 boe per
day and exit production of 21,000 to 22,000 boe per day.
Additional Disclosures
Quarterly Analysis
The following table summarizes Crew's key quarterly financial results for
the past eight financial quarters:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per Dec. 31 Sept. 30 June 30 Mar. 31
share amounts) 2010 2010 2010 2010
----------------------------------------------------------------------------
Total daily production (boe/d) 14,654 13,061 12,048 15,001
Average wellhead price ($/boe) 42.00 37.39 39.25 45.75
Petroleum and natural gas sales 56,620 44,924 43,027 61,772
Cash provided by operations 21,212 19,596 24,149 32,213
Funds from operations 28,436 24,104 20,693 28,217
Per share - basic 0.35 0.30 0.26 0.36
- diluted 0.35 0.29 0.25 0.35
Net income (loss) (9,525) (7,387) (2,691) 2,442
Per share - basic (0.12) (0.09) (0.03) 0.03
- diluted (0.12) (0.09) (0.03) 0.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per Dec. 31 Sept. 30 June 30 Mar. 31
share 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)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's petroleum and natural gas sales, cash and funds from operations and net
income are all impacted by production levels and volatile commodity pricing.
From 2009 to 2010, these performance measures have fluctuated as a result of
volatile oil and natural gas prices.
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.
- Over the past two years, the price of natural gas has been negatively impacted
by an increasing supply of natural gas coming from new technology tapping into
abundant supplies of tight shale gas reservoirs in North America. With depressed
natural gas prices, Crew has focused its capital expenditures towards oil
development with higher netbacks. This has resulted in the commodity mix moving
towards more oil and the Company's overall netbacks improving revenues and funds
from operations.
- Production in the second quarter of 2009 and 2010 was negatively impacted by
scheduled and unscheduled third party facility shutdowns and poor weather
experienced in southern Alberta during the second and third quarters of 2010.
- 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 on a portion of its
production. 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.
- In 2009 and 2010, the Company sold assets with approximately 2,970 boe per day
of production for $182.9 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
-- Second quarter 2010 - 1,700 boe per day for $123.3 million
The following table summarizes Crew's key financial results over the past
three years:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except per share Year ended Year ended Year ended
amounts) Dec. 31, 2010 Dec. 31, 2009 Dec. 31, 2008
----------------------------------------------------------------------------
Petroleum and natural gas sales 206,343 181,829 235,856
Cash provided by operations 97,170 82,660 123,356
Funds from operations 101,450 83,453 127,790
Per share - basic 1.27 1.11 2.08
- diluted 1.24 1.11 2.06
Net income (loss) (17,161) (37,815) (53,319)
Per share - basic (0.22) (0.50) (0.87)
- diluted (0.22) (0.50) (0.87)
Daily production (boe/d) 13,689 14,002 11,617
Crew average sales price ($/boe) 41.30 35.58 55.47
Total assets 998,070 963,248 1,045,510
Working capital deficiency (note 1) 40,707 46,654 31,822
Bank loan 138,700 135,601 223,628
Total other long-term liabilities 132,403 136,992 152,679
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 1) Working capital includes accounts receivable, assets held for sale
and accounts payable and accrued liabilities.
Crew's petroleum and natural gas sales, cash provided by operations, funds from
operations and net income are all impacted by production levels and commodity
pricing. These performance measures have all fluctuated throughout 2008 to 2010
as a result of volatile oil and natural gas prices combined with the increased
cost of the Company's operations. In addition, the Company disposed of assets
producing 1,270 boe per day for $58.5 million in 2009 and 1,700 boe per day for
$123.3 million in 2010.
New Accounting Pronouncements
International Financial Reporting Standards
Effective January 1, 2011, Canadian public companies are required to adopt
International Financial Reporting Standards ("IFRS") which will include
comparatives for 2010. Crew's financial statements up to and including December
31, 2010 will continue to be reported in accordance with Canadian GAAP as it
exists on each reporting date. Financial statements for the quarter ended March
31, 2011, including comparative amounts, will be prepared on an IFRS basis.
In order to transition to IFRS, management has established a project team and
formed an executive steering committee. A transition plan has been developed to
convert the financial statements to IFRS. External advisors have been retained
and will continue to assist management with the project on an as needed basis.
Training has been provided to key employees and staff training programs will
continue as needed. The Company continues to assess the effect of the transition
on information systems, internal controls over financial reporting and
disclosure controls and procedures. Systems and controls are being updated as
IFRS accounting processes are implemented. Significant system and control
changes are not anticipated. The project team and steering committee continue to
provide updates to senior management and the Audit Committee. Calculations of
the impact of changes in accounting policy have been prepared by management and
have been approved by the Company's Board of Directors and the Company's
auditors. The Company's auditors have been involved throughout the process to
ensure the Company's policies are in accordance with the new standards.
There are significant accounting policy changes anticipated on adoption of IFRS
which are described in more detail below. Most adjustments required on
transition to IFRS will be made retrospectively against opening retained
earnings as of the date of the first comparative balance sheet being January 1,
2010. 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
planning to adopt this exemption. Management has analyzed the various other
accounting policy choices available under IFRS 1 and has determined the
following to be most appropriate for Crew:
- Oil and gas properties will be classified as Property, Plant and Equipment
("PP&E") or Exploration and Evaluation assets ("E&E"). Upon transition to IFRS,
Crew will reclassify all E&E expenditures included in the PP&E balance under
Canadian GAAP, as a separate item under IFRS. 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. Once these E&E assets have
reached technical feasibility and commercial viability, they will be transferred
to PP&E. At the time of transfer, they will be subjected to an impairment test.
Crew's E&E assets will primarily consist of undeveloped exploration lands and at
January 1, 2010 are estimated at $35.6 million.
- Under IFRS PP&E assets are grouped into areas designated as cash generating
units ("CGU") for the purposes of impairment testing and further broken down
into components within the CGU for purposes of depletion and depreciation. IFRS
1 provides for the allocation of the Canadian GAAP net book value of PP&E
assets, excluding E&E assets, to CGUs and components on a pro rata basis using
the reserve volumes or values as at December 31, 2009. Crew has elected to
allocate the PP&E balance using reserve values and at January 1, 2010, the value
allocated to the PP&E assets is $889.5 million.
- Under Canadian GAAP, impairment testing on oil and gas properties is performed
at a cost centre level. Under IFRS, impairment testing will be performed at the
CGU level. This will result in a greater number of impairment tests. At January
1, 2010, Crew did not have any impairment on its PP&E under IFRS.
- Depletion and depreciation of PP&E will be calculated at a component level.
Depletion of resource properties within PP&E will be calculated using the
unit-of-production method under IFRS with the option to base the calculation on
proved reserves or proved plus probable reserves. Crew will use proved plus
probable reserves to calculate the depletion of resource properties.
Depreciation of office equipment will continue to be calculated using a
declining balance method.
- IFRS 1 allows Crew to use the IFRS rules for business combinations on a
prospective basis rather than restating all business combinations. Crew will
elect to use this exemption; therefore, Crew will not be recording any
adjustments to retrospectively restate any of its business combinations that
have occurred prior to January 1, 2010.
- Under Canadian GAAP, Crew's Asset Retirement Obligation is discounted over its
life based on a credit adjusted risk free rate which was 10% at December 31,
2009. Under IFRS, Crew is required to revalue its liability for asset retirement
costs at each balance sheet date using a current liability-specific discount
rate. As a result, the Company's asset retirement obligation will increase upon
transition to IFRS as the liability will be re-valued using a discount rate of
4% to reflect the Company's estimated risk-free rate of interest. The revalued
Asset Retirement Obligation at the transition date is estimated at $53.1 million
with the offsetting $17.7 million increase in the liability being charged to
retained earnings.
- Currently Crew expenses stock-based compensation on a straight-line basis.
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 as currently practiced under
Canadian GAAP. The adjustment to contributed surplus to account for the graded
vesting and forfeitures will be an increase of $2.7 million with the offset
being charged to retained earnings.
- Under Canadian GAAP, the future tax liability associated with the renouncement
of tax deductions from the issuance of flow through shares was recorded as a
reduction in share capital at the time of renouncement. Under IFRS, the
difference between the future tax liability associated with the renouncement of
the tax deductions and the premium price received on the issuance of flow
through shares over the market value of the Company's common shares at the time
of issue is recorded as a future tax expense at the time of the renouncement.
This future tax expense effectively represents the net loss on the distribution
of the tax deductions to investors. The transitional adjustment results in an
increase of $3.4 million to share capital with a resulting offset being charged
to retained earnings.
In the first quarter of 2011, the Company plans to prepare its 2010 IFRS
comparative quarterly financial statements and will assess and continue to
review the impact of the IFRS changes on disclosure controls and internal
controls, including identification of instances where controls may require
amendments or additions in order to address the accounting policy changes
required under IFRS. No material changes in control procedures are presently
expected.
Application of Critical Accounting Estimates
Crew's significant accounting policies are disclosed in note one to the December
31, 2010 consolidated financial statements. Certain accounting policies require
that management make appropriate decisions with respect to the formulation of
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. These accounting policies are discussed
below and are included to aid the reader in assessing the critical accounting
policies and practices of the Company and the likelihood of materially different
results being reported. Crew's management reviews its estimates regularly. The
emergence of new information and changed circumstances may result in actual
results or changes to estimate amounts that differ materially from current
estimates.
The following assessment of significant accounting policies and associated
estimates is not meant to be exhaustive. The Company might realize different
results from the application of new accounting standards promulgated, from time
to time, by various rule-making bodies.
Proved Oil and Gas Reserves
Proved oil and gas reserves, as defined by the Canadian Securities
Administrators in National Instrument 51-101 with reference to the Canadian Oil
and Gas Evaluation Handbook, are those reserves that can be estimated with a
high degree of certainty to be recoverable. It is likely that the actual
remaining quantities recovered will exceed the estimated proved reserves.
An independent reserve evaluator using all available geological and reservoir
data as well as historical production data has prepared Crew's oil and gas
reserve estimate. Estimates are reviewed and revised as appropriate. Revisions
occur as a result of changes in prices, costs, fiscal regimes, reservoir
performance or a change in the Company's development plans. The effect of
changes in proved oil and gas reserves on the financial results and position of
the Company is described below under the heading "Full-Cost Accounting" and
"Full-Cost Accounting Ceiling Test".
Full-Cost Accounting
The Company currently 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. The
capitalized costs are depleted and depreciated using the unit-of-production
method based on estimated proved reserves. Reserve estimates can have a
significant impact on earnings, as they are a key component in the calculation
of depletion and depreciation. A downward revision in a reserve estimate could
result in a higher depletion and depreciation charge to earnings. In addition,
if net capitalized costs are determined to be in excess of the calculated
ceiling, which is based largely on reserve estimates (see Full-Cost Accounting
Ceiling Test) the excess must be written off as an expense charged against
earnings. In the event of property disposition, proceeds are normally deducted
from the full cost pool without recognition of gain or loss unless there is a
change in the depletion rate of 20 percent or greater.
Unproved Properties
Certain costs related to unproved properties are excluded from costs subject to
depletion until proved reserves have been determined or their value is impaired.
These properties are reviewed quarterly and any impairment is transferred to the
costs being depleted.
Full Cost Accounting Ceiling Test
Petroleum and natural gas assets are evaluated in each reporting period 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. By their nature, these estimates are subject to
measurement uncertainty and the impact on the financial statements could be
material. Any impairment loss would be charged as additional depletion and
depreciation expense.
Asset Retirement Obligations
The fair value of an asset's retirement obligation must be recognized in the
period in which it is incurred if a reasonable estimate of the fair value can be
made. The present value of the estimated asset retirement cost is capitalized as
part of the carrying amount of the long-lived asset. The depletion and
depreciation of the capitalized asset retirement cost is determined on a basis
consistent with depletion and depreciation. With the passage of time, accretion
will increase the carrying amount of the asset retirement obligation. The actual
cost and timing of the Company's asset retirement expenditures may vary
significantly from management's current estimates.
Income Taxes
The determination of the Company's income and other tax liabilities requires
interpretation of complex laws and regulations often involving multiple
jurisdictions. All tax filings are subject to audit and potential reassessment
after the lapse of considerable time. Accordingly, the actual income tax
liability may differ from that estimated and recorded by management.
Stock-based Compensation
Crew accounts for its stock based compensation program, which includes stock
options, using the fair value method. The determination of the fair value of
options requires management to make assumptions about risk-free interest rates,
expected option lives and expected volatility. Such assumptions may change from
time to time and the estimated fair value of options calculated at the grant
date may differ on subsequent dates. The fair value of stock options being
amortized to compensation expense is not revised for any changes in assumptions
from the grant date.
Fair Value of Financial Derivatives
Crew uses financial derivatives to manage commodity price risk, foreign currency
risk, and interest rate risk. The fair value of derivative contracts is
estimated on Crew's balance sheet with the change in fair value recognized in
net income for the period. The fair value of each derivative is based on forward
prices or rates and therefore any change in commodity prices, interest rates or
foreign currency rates will impact the fair value and net income for the period.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
The Company's Chief Executive Officer ("CEO") and Chief Financial Officer
("CFO") have designed, or caused to be designed under their supervision,
disclosure controls and procedures to provide reasonable assurance that: (i)
material information relating to the Company is made known to the Company's CEO
and CFO by others, particularly during the period in which the annual and
interim filings are being prepared; and (ii) information required to be
disclosed by the Company in its annual filings, interim filings or other reports
filed or submitted by it under securities legislation is recorded, processed,
summarized and reported within the time period specified in securities
legislation. 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.
Crew's CEO and CFO have designed, or caused to be designed under their
supervision, internal controls over financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with Canadian
generally accepted accounting principles. Such officers have evaluated, or
caused to be evaluated under their supervision, the effectiveness of the
Company's internal controls over financial reporting at the financial year end
of the Company and concluded that the Company's internal controls over financial
reporting are effective, at the financial year end of the Company, for the
foregoing purpose. The Company is required to disclose herein any change in the
Company's internal controls over financial reporting that occurred during the
period beginning on October 1, 2010 and ended on December 31, 2010 that has
materially affected, or is reasonably likely to materially affect, the Company's
internal controls over financial reporting. No material changes in the Company's
internal controls over financial reporting were identified during such period
that have materially affected, or are reasonably likely to materially affect,
the Company's internal controls over financial reporting.
It should be noted that a control system, including the Company's disclosure and
internal controls and procedures, no matter how well conceived, can provide only
reasonable, but not absolute assurance that the objectives of the control system
will be met and it should not be expected that the disclosure and internal
controls and procedures will prevent all errors or fraud.
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 7, 2011
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", "forecasts" and similar expressions are
intended to identify forward-looking information or statements. In particular,
but without limiting the foregoing, this news release contains forward-looking
information and statements pertaining to the following: the volume and product
mix of Crew's oil and gas production; production estimates including forecast
2011 average and exit rates; 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; potential prospectivity of
the Company's lands at Kobes, British Columbia, Pine Creek, Alberta and Provost,
Alberta; future general and administrative costs, royalty rates; future interest
costs; the exchange rate between the $US and $Cdn; future development,
exploration, acquisition and development activities and related capital
expenditures and the timing thereof; the number of wells to be drilled,
completed and tied-in and the timing thereof; the amount and timing of capital
projects; operating costs; transportation costs; the total future capital
associated with development of reserves and resources; forecasts in operating
expenses.
The recovery and reserve estimates of Crew's reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered. 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 and partner approvals; the ability of
Crew to obtain qualified staff, regulatory and partner approvals, 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 partners; and certain other risks
detailed from time-to-time in Crew's public disclosure documents (including,
without limitation, those risks identified in this news release and Crew's
Annual Information Form).
The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Crew does not assume any
obligation to publicly update or revise any of the included forward-looking
statements or information, whether as a result of new information, future events
or otherwise, except as may be required by applicable securities laws.
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
Crew is an oil and gas exploration and production company whose shares are
traded on The Toronto Stock Exchange under the trading symbol "CR".
Financial statements for the three month periods and years ended December 31,
2010 and 2009 are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(thousands)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2010 2009
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 44,922 $ 37,574
Fair value of financial instruments (note 8) 982 -
Future income taxes (note 10) - 542
Asset held for sale (notes 3 & 12) 15,116 -
----------------------------------------------------------------------------
61,020 38,116
Property, plant and equipment (note 3) 937,050 925,132
----------------------------------------------------------------------------
$ 998,070 $ 963,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 100,745 $ 84,228
Fair value of financial instruments (note 8) - 834
Current portion of other long-term
obligations (note 5) 343 1,313
----------------------------------------------------------------------------
101,088 86,375
Fair value of financial instruments (note 8) 9,196 -
Bank loan (note 4) 138,700 135,601
Other long-term obligations (note 5) - 132
Asset retirement obligations (note 6) 36,073 35,341
Future income taxes (note 10) 96,330 101,519
Shareholders' Equity
Share capital (note 7) 646,385 617,605
Contributed surplus (note 7(c)) 23,553 22,769
Deficit (53,255) (36,094)
----------------------------------------------------------------------------
616,683 604,280
Commitments (note 12)
Subsequent events (notes 3,8,9 & 12)
----------------------------------------------------------------------------
$ 998,070 $ 963,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Operations, Comprehensive Loss and 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,
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas sales $ 56,620 $ 57,646 $206,343 $ 181,829
Royalties (11,311) (13,167) (41,799) (36,027)
Realized gain on financial
instruments (note 8) 3,284 4,471 13,082 18,461
Unrealized loss on financial
instruments (note 8) (12,586) (6,225) (7,380) (2,089)
----------------------------------------------------------------------------
36,007 42,725 170,246 162,174
Expenses
Operating 14,009 15,084 53,976 57,342
Transportation (note 5) 2,819 3,134 9,582 11,229
General and administrative 1,904 1,473 6,479 5,736
Interest 1,425 2,003 5,795 6,503
Stock-based compensation
(note 7(d)) 1,093 793 4,517 3,321
Depletion, depreciation and
accretion 27,736 31,677 113,214 131,613
----------------------------------------------------------------------------
48,986 54,164 193,563 215,744
----------------------------------------------------------------------------
Loss before income taxes (12,979) (11,439) (23,317) (53,570)
Future income tax reduction
(note 10) (3,454) (2,285) (6,156) (15,755)
----------------------------------------------------------------------------
Loss and comprehensive loss (9,525) (9,154) (17,161) (37,815)
Retained earnings (deficit),
beginning of period (43,730) (26,940) (36,094) 1,721
----------------------------------------------------------------------------
Deficit, end of period $ (53,255) $(36,094) $(53,255) $(36,094)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Loss per share (note 7(e))
Basic $ (0.12) $ (0.12) $ (0.22) $ (0.50)
Diluted $ (0.12) $ (0.12) $ (0.22) $ (0.50)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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,
2010 2009 2010 2009
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Loss $ (9,525) $ (9,154) $(17,161) $(37,815)
Items not involving cash:
Depletion, depreciation and
accretion 27,736 31,677 113,214 131,613
Stock-based compensation 1,093 793 4,517 3,321
Future income tax reduction (3,454) (2,285) (6,156) (15,755)
Unrealized loss on financial
instruments (note 8) 12,586 6,225 7,380 2,089
Transportation liability charge
(note 5) (120) (329) (1,102) (1,314)
Asset retirement expenditures
(note 6) (606) (111) (1,512) (589)
Change in non-cash working
capital (note 11) (6,498) (10,082) (2,010) 1,109
----------------------------------------------------------------------------
21,212 16,734 97,170 82,659
Financing activities:
Increase (decrease) in bank loan 27,930 (31,167) 3,099 (88,027)
Issue of common shares 1,753 539 20,566 43,961
Share issue costs - - (48) (2,442)
----------------------------------------------------------------------------
29,683 (30,628) 23,617 (46,508)
Investing activities:
Exploration and development (61,348) (55,312) (248,870) (128,567)
Property acquisitions (446) - (446) -
Property dispositions (174) 44,315 132,466 78,693
Cost incurred on asset held for
sale (15,116) - (15,116) -
Change in non-cash working
capital (note 11) 26,189 24,891 11,179 13,723
----------------------------------------------------------------------------
(50,895) 13,894 (120,787) (36,151)
----------------------------------------------------------------------------
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, 2010 and 2009
(Tabular amounts in thousands)
(unaudited)
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, cost
less impairment 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 plus probable
reserves, cost less impairment 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) 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.
(e) 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.
(f) Revenue recognition:
Revenues from the sale of petroleum and natural gas are recorded when title
passes to a third party and collection is reasonably assured.
(g) 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 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.
(h) 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.
(i) 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.
(j) 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.
(k) Comparative amounts:
Certain comparative amounts may have been reclassified to conform with
presentation adopted in the current year.
2. Changes in accounting policy:
Future accounting pronouncements
Adoption of International Financial Reporting Standards ("IFRS")
On January 1, 2011 International Financial Reporting Standards ("IFRS"), as
issued by the Accounting Standards Board, will become the generally accepted
accounting principles in Canada. The transition from Canadian GAAP to IFRS will
result in significant differences affecting financial position and results of
operations. The Company will be reporting under IFRS for all periods beginning
after January 1, 2011.
3. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
December 31, 2010 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 1,424,892 $ 487,842 $ 937,050
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
December 31, 2009 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas
properties and equipment $ 1,302,399 $ 377,267 $ 925,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The cost of unproved properties at December 31, 2010 of $164,652,000 (2009 -
$153,674,000) were excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $176,893,000 (2009 - $173,999,000) have been included in the
depletion calculation and estimated salvage values of $35,845,000 (2009 -
$38,039,000) have been excluded from the depletion calculation.
In April 2010, the Company closed the disposition of oil and gas assets in the
Edson, Alberta area for gross proceeds of $126 million, before closing
adjustments. Proceeds from the sale of this disposition were applied against
capitalized petroleum and natural gas properties with no gain or loss
recognized, and also resulted in the elimination of $3.5 million of asset
retirement obligations.
During the fourth quarter of 2010, the Company entered into an agreement to sell
the Septimus facility expansion for its as built cost. The Company also
commenced construction of the Septimus facility expansion and as at December 31,
2010, the cumulative costs incurred on the expansion totaled $15.1 million with
an additional $1.8 million incurred subsequent to year end, to bring the total
cost to $16.9 million. The costs of the facility expansion have been recorded as
an asset held for sale. The sale of the asset was completed on February 14, 2011
for total proceeds equal to the facility's cost of $16.9 million.
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, December 31,
2010 2009
----------------------------------------------------------------------------
General and administrative expense $ 6,381 $ 5,736
Stock-based compensation expense, including
future income taxes 6,038 4,442
----------------------------------------------------------------------------
$ 12,419 $ 10,178
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew performed a ceiling test as at December 31, 2010. 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)
----------------------------------------------------------------------------
2011 $ 88.00 0.980 $ 75.87 $ 70.76 $ 4.16 $ 4.21
2012 $ 89.00 0.980 $ 75.89 $ 70.83 $ 4.74 $ 4.87
2013 $ 90.00 0.980 $ 75.10 $ 70.27 $ 5.31 $ 5.51
2014 $ 92.00 0.980 $ 76.23 $ 71.16 $ 5.77 $ 6.01
2015 $ 95.17 0.980 $ 78.88 $ 73.57 $ 6.22 $ 6.52
2016 $ 97.55 0.980 $ 80.87 $ 75.34 $ 6.53 $ 6.84
2017 $ 100.26 0.980 $ 83.14 $ 77.35 $ 6.76 $ 7.12
2018 $ 102.74 0.980 $ 85.21 $ 79.02 $ 6.90 $ 7.30
2019 $ 105.45 0.980 $ 87.48 $ 81.01 $ 7.06 $ 7.50
2020 $ 107.56 0.980 $ 89.25 $ 82.47 $ 7.21 $ 7.69
Annual escalation thereafter +2.0%/yr.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. Bank loan:
The Company's bank facility consists of a revolving line of credit of $220
million and an operating line of credit of $20 million (the "Facility"). The
Facility revolves for a 364 day period and will be subject to its next 364 day
extension by June 13, 2011. If not extended, the Facility will cease to revolve,
the margins thereunder will increase by 0.50 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 borrowing base review on or before June
13, 2011.
Advances under the Facility are available by way of prime rate loans with
interest rates between 1.25 percent and 2.75 percent over the bank's prime
lending rate and bankers' acceptances and LIBOR loans, which are subject to
stamping fees and margins ranging from 2.25 percent to 3.75 percent depending
upon the debt to EBITDA ratio of the Company calculated at the Company's
previous quarter end. Standby fees are charged on the undrawn facility at rates
ranging from 0.56 percent to 0.94 percent depending upon the debt to EBITDA
ratio.
As at December 31, 2010, the Company's applicable pricing included a 1.5 percent
margin on prime lending and a 2.5 percent stamping fee and margin on bankers'
acceptances and LIBOR loans along with a 0.625 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, 2010, the Company had issued letters of credit totaling $1.1 million (2009 -
$2.8 million). The effective interest rate on the Company's borrowings under its
bank facility for the year ended December 31, 2010 was 6.6% (2009 - 3.3%).
5. 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, 2010 was $0.8 million (2009 - $1.3
million).
In March 2010, the Company permanently assigned a portion of the firm
transportation agreements to third parties at no cost to Crew. As a result, the
remaining liability associated with the assigned contracts was written-off
during the first quarter of 2010 as a $0.3 million reduction of transportation
expense.
6. 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, 2010 to be $36,073,000 (2009 -
$35,341,000) based on a total future liability of $63,355,000 (2009 -
$64,030,000). These payments are expected to be made over the next 30 years. An
8% to 10% (2009 - 8% to 10%) credit adjusted risk free discount rate and 2%
(2009 - 2%) inflation rate were used to calculate the present value of the asset
retirement obligation.
The following table reconciles Crew's asset retirement obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
December 31, December 31,
2010 2009
----------------------------------------------------------------------------
Carrying amount, beginning of year $ 35,341 $ 34,941
Liabilities incurred 980 385
Liabilities disposed (3,456) (2,161)
Accretion expense 2,639 2,765
Liabilities settled (1,512) (589)
Change in estimate 2,081 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Carrying amount, end of year $ 36,073 $ 35,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. 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, 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
Exercise of stock options 2,216 20,566
Stock-based compensation - 8,250
Share issue costs, net of future income taxes of
$12 - (36)
----------------------------------------------------------------------------
Common Shares, December 31, 2010 80,368 $ 646,385
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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).
(c) Contributed Surplus:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Contributed surplus, December 31, 2008 $ 16,356
Stock-based compensation 6,642
Exercise of stock options (229)
----------------------------------------------------------------------------
Contributed surplus, December 31, 2009 $ 22,769
Stock-based compensation 9,034
Exercise of stock options (8,250)
----------------------------------------------------------------------------
Contributed surplus, December 31, 2010 $ 23,553
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 2.26% (2009 - 1.58%),
expected life 4 years (2009 - 4 years), volatility 61% (2009 - 53%), and an
expected dividend of nil (2009 - nil). The Company has not incorporated an
estimated forfeiture rate for stock options that will not vest, rather the
Company accounts for actual forfeitures as they occur.
During 2010 the Company recorded $9,034,000, (2009 - $6,642,000) of stock-based
compensation expense related to the stock options, of which $4,517,000 (2009 -
$3,321,000) 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 $1,521,000 (2009 - $1,121,000)
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 weighted
average fair value of the stock options granted during the year as calculated by
the Black-Scholes method was $7.32 per option (2009 - $2.14).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Number of average
options exercise price
----------------------------------------------------------------------------
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
Granted 2,237 $ 15.18
Exercised (2,216) $ 9.28
Forfeited (442) $ 8.50
----------------------------------------------------------------------------
Balance December 31, 2010 5,330 $ 10.79
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The following table summarizes information about the stock options
outstanding at December 31, 2010:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Outstanding average Weighted Exercisable Weighted
at Remaining average at average
Range of December 31, life exercise December 31, exercise
exercise prices 2010 (years) price 2010 price
----------------------------------------------------------------------------
$ 3.43 to $ 7.01 1,175 2.0 $ 5.14 272 $ 5.17
$ 7.02 to $ 9.94 1,284 1.1 $ 7.51 758 $ 7.47
$ 9.95 to $14.63 576 0.9 $ 11.43 464 $ 11.02
$14.64 to $18.70 2,295 2.9 $ 15.35 118 $ 16.99
----------------------------------------------------------------------------
5,330 2.1 $ 10.79 1,612 $ 8.80
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2010 was 79,747,000 (2009 - 75,252,000).
In computing diluted earnings per share for the year ended December 31, 2010,
nil (2009 - nil) shares were added to the weighted average Common Shares
outstanding to account for the dilution of stock options. There were 5,330,000
(2009 - 5,751,000) stock options that were not included in the diluted earnings
per share calculation because they were anti-dilutive.
8. 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, 2010 the
Company's receivables consisted of $22.5 (2009 - $17.2) million of receivables
from petroleum and natural gas marketers which has subsequently been collected,
$6.7 (2009 - $9.2) million from joint venture partners of which $0.3 million has
been subsequently collected, and $15.7 (2009 - $11.2) million of Crown
incentives, deposits, prepaids and other accounts receivable of which $3.0
million has subsequently been collected. 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, financial instruments and the 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 4, that is
subject to renewal annually by the lenders and has a contractual maturity in
2012. The Company also maintains and monitors a certain level of cash flow which
is used to partially finance all operating and capital expenditures as the
Company does not pay dividends.
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity
prices, interest rates, and foreign exchange rates, will affect the Company's
net income or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
limits, while maximizing the Company's returns.
The Company utilizes both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with the Company's risk management policy that has been approved by
the Board of Directors.
(i) Commodity price risk
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. Any contracts extending beyond two years require Board
approval.
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 rate risk is the risk that the fair value of future
cash flows will fluctuate as a result of changes in foreign exchange rates. All
of the Company's petroleum and natural gas sales are conducted in Canada and are
denominated in Canadian dollars. Canadian commodity prices are influenced by
fluctuations in the Canadian to U.S. dollar exchange rate.
(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
year ended December 31, 2010, a 1.0 percent change to the effective interest
rate would have a $1.1 million impact on net income (2009 - $1.5 million). The
sensitivity for 2010 is lower as compared to 2009 because of a decrease in
average outstanding bank debt in 2010 compared to 2009.
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 $100 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 2.25 per cent to 3.75 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, 2010 are as
follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
Commodity contracts
AECO C
Natural January 1, 2011 - Monthly
Gas 2,500 gj/day December 31, 2011 Index $ 4.85 Swap(1) 961
AECO C
Natural January 1, 2011 - Monthly
Gas 2,500 gj/day December 31, 2011 Index $ 4.90 Swap(1) 1,001
AECO C
Natural January 1, 2011 - Monthly
Gas 2,500 gj/day December 31, 2011 Index $ 4.95 Swap(1) 1,046
AECO C
Natural January 1, 2011 - Monthly
Gas 2,500 gj/day December 31, 2011 Index $ 4.965 Swap(1) 1,058
AECO C
Natural January 1, 2011 - Monthly
Gas 7,500 gj/day December 31, 2011 Index $ 5.00 Swap(1) 3,276
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 US$ WTI US$80.15 Swap (2,478)
January 1, 2011 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 86.00 Swap (723)
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 CDN$ WTI $ 88.00 Swap (1,031)
January 1, 2011 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 88.50 Swap (474)
January 1, 2011 -
Oil 250 bbl/day December 31, 2011 CDN$ WTI $ 90.00 Swap (332)
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 CDN$ WTI $ 90.20 Swap (641)
January 1, 2011 -
Oil 500 bbl/day December 31, 2011 CDN$ WTI $ 93.00 Swap 15
January 1, 2011 - $ 80.00 -
Oil 250 bbl/day December 31, 2011 $ 95.45 CDN$ WTI Collar (307)
January 1, 2011 - $ 82.00 -
Oil 250 bbl/day December 31, 2011 $ 94.62 CDN$ WTI Collar (340)
January 1, 2011 - $ 85.00 -
Oil 250 bbl/day December 31, 2011 $ 100.50 CDN$ WTI Collar (24)
January 1, 2011 - CDN$ WCS-
Oil 500 bbl/day June 30, 2011 WTI diff ($18.00) Swap (45)
January 1, 2012 -
Oil 500 bbl/day December 31, 2012 CDN$ WTI $ 85.00 Call(1) (3,082)
January 1, 2012 -
Oil 750 bbl/day December 31, 2012 CDN$ WTI $ 90.00 Call(1) (3,548)
January 1, 2012 -
Oil 500 bbl/day December 31, 2012 US$ WTI US$90.00 Call(1) (2,566)
----------------------------------------------------------------------------
Total commodity contracts (8,234)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
Interest rate contracts
$50M / February 10, 2009 - BA -
BA Rate year February 10, 2011 CDOR 1.10% Swap 8
$50M / February 12, 2009 - BA -
BA Rate year February 12, 2011 CDOR 1.10% Swap 12
----------------------------------------------------------------------------
Total interest rate contracts 20
----------------------------------------------------------------------------
Total financial instruments (8,214)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) These derivative contracts are part of a paired transaction in which the
proceeds from the sale of 2012 oil calls were used to fund the 2011
natural gas swaps at the prices indicated.
As at December 31, 2010, a $0.10 change to the price per thousand cubic feet of
natural gas on the natural gas contracts outlined above would have a $0.5
million impact on net income.
As at December 31, 2010, a $1.00 per barrel change to the price on the oil
contracts outlined above would have a $1.4 million impact on net income.
As at December 31, 2010, a 0.1% change to the interest rate on the interest rate
contracts outlined above would have less than a $0.1 million impact on net
income.
Subsequent to December 31, 2010, the Company entered into the following
financial derivative contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject of Notional Strike Option
Contract Quantity Term Reference Price traded
----------------------------------------------------------------------------
500 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN $WTI $ 101.00/bbl Swap
250 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN $WTI $ 100.45/bbl Swap
250 January 1, 2012 -
Oil bbl/day December 31, 2012 CDN $WTI $ 100.50/bbl Swap
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair value of financial instruments
The Company's financial instruments as at December 31, 2010 and 2009 include
accounts receivable, derivative contracts, accounts payable and accrued
liabilities, and bank debt. The fair value of accounts receivable and accounts
payable and accrued liabilities approximate their carrying amounts due to their
short-terms to maturity.
The fair value of derivative contracts is determined by discounting the
difference between the contracted price and interest rates and published forward
price and interest rate curves as at the balance sheet date, using the remaining
contracted petroleum and natural gas volumes and notional debt amounts.
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, 2010.
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.
9. 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, the 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 non-core 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, 2010, the Company's ratio of net debt to annualized
funds from operations was 1.58 to 1 (December 31, 2009 - 1.67 to 1). The ratio
improved over the prior year as a result of the sale of assets in 2010 and the
higher funds from operations earned in the fourth quarter of 2010.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec. 31, Dec. 31,
2010 2009
----------------------------------------------------------------------------
Net debt:
Accounts receivable (including assets held
for sale) $ 60,038 $ 37,574
Accounts payable and accrued liabilities (100,745) (84,228)
----------------------------------------------------------------------------
Working capital deficiency $ (40,707) $ (46,654)
Bank loan (138,700) (135,601)
----------------------------------------------------------------------------
Net debt $ (179,407) $ (182,255)
----------------------------------------------------------------------------
Annualized funds from operations:
Cash provided by operating activities $ 21,212 $ 16,734
Asset retirement expenditures 606 111
Transportation liability charge 120 329
Change in non-cash working capital 6,498 10,082
----------------------------------------------------------------------------
Fourth quarter funds from operations 28,436 27,256
Annualized $ 113,744 $ 109,024
----------------------------------------------------------------------------
Net debt to annualized funds from operations 1.58 1.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's capital spending program for 2011 is estimated at $260 million.
The Company has commodity and interest rate hedging for 2011 to provide support
for its funds from operations and assist in funding its capital expenditure
program.
On March 2, 2011, the Company issued 4,820,000 Common Shares at a price of
$20.75 per share for aggregate gross proceeds of $100 million. Crew has also
granted the Underwriters an over-allotment option to purchase, on the same
terms, up to an additional 723,000 Common Shares for additional gross proceeds
of up to $15.0 million exercisable by the Underwriters, in whole or in part, at
any time up to 30 days following closing of the offering, to cover the
Underwriters' over-allotments, if any.
The Company may also consider the sale of additional non-core assets and will
consider other forms of financing to improve the Company's financial position if
cash flow does not adequately fund the capital programs planned to achieve the
Company's long term objectives.
There has been no change in the Company's approach to capital management during
the year ended December 31, 2010.
10. 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:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
Dec. 31, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
Loss before income taxes $ (23,317) $ (53,570)
----------------------------------------------------------------------------
Combined federal and provincial income tax rate 28.10% 29.10%
Computed "expected" income tax reduction $ (6,552) $ (15,589)
Increase (decrease) in income taxes resulting from:
Non-deductible stock-based compensation 1,269 966
Benefits relating to change in income tax rates (925) (731)
Other 52 (401)
----------------------------------------------------------------------------
Future income tax reduction $ (6,156) $ (15,755)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(b) Future income tax liability:
The components of the Company's future income tax liability are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
December 31, December 31,
2010 2009
----------------------------------------------------------------------------
Future income tax:
Property, plant and equipment $ 117,129 $ 121,282
Asset retirement obligations (9,061) (8,953)
Share issue costs (1,325) (2,381)
Non-capital loss (8,156) (8,287)
Other (2,257) (684)
----------------------------------------------------------------------------
Future income tax liability $ 96,330 $ 100,977
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The non-capital losses expire during the years 2026 to 2028, except for $1.2
million which expires in the year 2015.
11. Supplemental cash flow information:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
Dec. 31, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
Changes in non-cash working capital:
Accounts receivable $ (7,348) $ 5,226
Accounts payable and accrued liabilities 16,517 9,606
----------------------------------------------------------------------------
$ (9,169) $ 14,832
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities $ (2,010) $ 1,109
Investing activities 11,179 13,723
----------------------------------------------------------------------------
$ (9,169) $ 14,832
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company made the following cash outlays in respect of interest expense:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended Year ended
Dec. 31, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
Interest $ 5,415 $ 6,246
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. Commitments:
The Company has the following fixed term commitments related to its on-going
business:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 2011 2012 2013 2014 2015 Thereafter
----------------------------------------------------------------------------
Operating
leases $ 3,052 $ 1,743 $ 1,309 - - - -
Capital
commitments 2,000 2,000 - - - - -
Transportation
agreements 22,618 4,600 1,535 1,535 2,110 2,110 10,728
Processing
agreement 77,936 6,526 6,526 6,526 8,239 8,239 41,880
----------------------------------------------------------------------------
Total $105,606 $ 14,869 $ 9,370 $ 8,061 $10,349 $10,349 $ 52,608
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The transportation agreements include a $19.5 million commitment to a third
party to transport natural gas from the gas processing facility in the Septimus
area to the Alliance pipeline system. The remaining commitment relates to firm
transportation commitments that were acquired as part of the Company's May 2007
private company acquisition. In 2010, the Company permanently assigned
approximately $6.2 million of its firm commitments to third parties.
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.
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.
In the fourth quarter of 2010, the Company amended the agreement with the owner
of this facility. Under the terms of the amended agreement, Crew undertook
construction of the facility expansion during the fourth quarter of 2010 and
then subsequently sold the Septimus facility expansion in February 2011. Upon
completion of the expansion, Crew was reimbursed for the full cost of the
facility of $16.9 million in return for an expanded processing commitment that
will extend to December 2020. The commitment is included in the above table.
Crew has also retained the option to re-purchase a 50% interest in the facility
at certain dates prior to January 1, 2014, at a cost of 50% of the total
expanded facility's construction cost. If the Company re-purchases a 50%
interest on January 1, 2014 for approximately $18.0 million, the remaining
commitment would be reduced by approximately $29.0 million.
Crew Energy (TSX:CR)
Historical Stock Chart
From May 2024 to Jun 2024
Crew Energy (TSX:CR)
Historical Stock Chart
From Jun 2023 to Jun 2024
