Crew Energy Inc. (TSX:CR) of Calgary, Alberta is pleased to present its
operating and financial results for the three and six month periods ended June
30, 2010.
Highlights
- Second quarter funds from operations of $20.7 million was 3% higher than the
second quarter of 2009;
- On April 1, 2010, Crew closed a strategic farmout and property disposition of
1,700 boe per day reducing corporate debt by 44% from the first quarter of 2010;
- Crew spent $26.5 million on Crown land acquisitions in the quarter adding 47
net sections at Princess, Alberta to increase the Company's Princess land base
to over 500 sections;
- Crew tested three oil wells at Princess in the quarter at 242, 345 and 362
bbls of oil per day with ten additional wells awaiting completion;
- A recent Crew Montney well at Septimus, British Columbia tested at 12 mmcf per
day and 360 bbl per day of condensate at a flowing casing pressure of 1,670 psi
after seven days of production;
- Crew has added seven net sections of land through Crown land sales in
northeastern British Columbia to increase the Company's Montney land base to
over 220 net sections.
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Financial Three months Three months Six months Six months
($thousands, except ended ended ended ended
per share amounts) June 30, 2010 June 30, 2009 June 30, 2010 June 30, 2009
----------------------------------------------------------------------------
Petroleum and natural
gas sales 43,027 39,331 104,799 85,673
Funds from operations
(note 1) 20,693 20,036 48,910 36,557
Per share - basic 0.26 0.27 0.62 0.51
- diluted 0.25 0.27 0.60 0.51
Net income (loss) (2,691) (12,267) (249) (21,285)
Per share - basic (0.03) (0.17) (0.00) (0.29)
- diluted (0.03) (0.17) (0.00) (0.29)
Exploration and
development investment 63,309 14,187 122,384 37,865
Property acquisitions
(net of dispositions) (121,724) (23,688) (132,640) (34,378)
Net capital expenditures (58,415) (9,501) (10,256) 3,487
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Capital Structure As at As at
($ thousands) June 30, 2010 Dec. 31, 2009
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Working capital deficiency (note 2) 34,886 46,654
Bank loan 71,845 135,601
Net debt 106,731 182,255
Bank facility 210,000 250,000
Common Shares Outstanding (thousands) 80,096 78,152
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Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital, asset
retirement expenditures and the transportation liability charge. Funds
from operations is used to analyze the Company's operating performance
and leverage. Funds from operations does not have a standardized measure
prescribed by Canadian Generally Accepted Accounting Principles and
therefore may not be comparable with the calculations of similar
measures for other companies.
(2) Working capital deficiency includes only accounts receivable less
accounts payable and accrued liabilities.
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Three months Three months Six months Six months
ended ended ended ended
Operations June 30, 2010 June 30, 2009 June 30, 2010 June 30, 2009
----------------------------------------------------------------------------
Daily production
Natural gas (mcf/d) 45,753 54,036 50,715 56,773
Oil (bbl/d) 3,305 3,254 3,780 3,483
Natural gas liquids
(bbl/d) 1,117 1,206 1,284 1,295
Oil equivalent
(boe/d @ 6:1) 12,048 13,466 13,517 14,240
Average prices (note 1)
Natural gas ($/mcf) 4.31 3.66 4.89 4.41
Oil ($/bbl) 65.86 60.75 69.36 51.52
Natural gas liquids
($/bbl) 52.01 30.46 53.50 33.42
Oil equivalent ($/boe) 39.25 32.10 42.83 33.24
Netback
Operating netback ($/boe)
(note 2) 21.33 17.89 22.55 16.16
Realized gain on financial
instruments (note 3) (0.17) (0.56) (0.09) (0.20)
G&A ($/boe) 1.50 1.15 1.35 1.14
Interest and other ($/boe) 1.12 0.95 1.30 1.03
Funds from operations
($/boe) 18.88 16.35 19.99 14.19
Drilling Activity
Gross wells 11 1 33 8
Working interest wells 10.3 1.0 30.5 2.8
Success rate, net wells 100% 100% 100% 94%
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Notes:
(1) Average prices are before deduction of transportation costs and do not
include realized gains and losses on financial instruments.
(2) Operating netback equals petroleum and natural gas sales including
realized hedging gains and losses on commodity contracts less royalties,
operating costs and transportation costs calculated on a boe basis.
Operating netback and funds from operations netback do not have a
standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
(3) Amount includes realized gains and losses on non-commodity financial
instruments.
OVERVIEW
Operations during the second quarter of 2010 were highlighted by the drilling of
11 (10.3 net) wells with 100% success. The Company drilled six (6.0 net) oil
wells at Princess, Alberta, three (3.0 net) liquids rich natural gas wells in
northeast British Columbia and one (1.0 net) water disposal well at Princess. In
addition, a third party drilled one (0.33 net) well on the previously announced
Edson Cardium farmout.
Production in the second quarter was 12,048 boe per day, down from the first
quarter of 2010 as a result of asset sales of 1,700 boe per day as well as
production declines and curtailments. An early spring breakup, late season
winter storms and extreme wet weather at Princess during the quarter severely
hampered drilling, completion, pipelining and workover activity resulting in a
drop in production from the area. Currently, activity at Princess is ramping up
with four drilling rigs working and 14 wells to be placed on production.
In the second quarter, Crew continued to expand its land base in the Company's
main oil property at Princess. The Company purchased 47 net sections of land for
$25 million. In addition, Crew acquired seven net sections of land offsetting
its Montney discovery well at Portage, British Columbia in the second and early
third quarter. Crew added to its oil resource base in the second quarter by
acquiring the remaining 52 percent working interest in nine sections of land and
35 boe per day of oil production in the Viking oil play at Provost, Alberta for
$1.4 million. Crew has identified over 30 drilling locations on this light oil
play.
OPERATIONS UPDATE
Pekisko Play, Princess, Alberta
During the second quarter, Crew drilled six (6.0 net) oil wells and one (1.0
net) salt water disposal well at Princess. Due to an early spring break up, late
season winter storms and extreme wet weather, only one of these wells was
brought on production in the second quarter. The unprecedented weather
conditions severely hampered all drilling, completion, pipelining and workover
activity in the area, resulting in a reduction of production. Crew has four
drilling rigs currently active at Princess and has an inventory of 14 wells to
place on production which is expected to increase area production to 5,500 to
6,000 boe per day.
Crew's Tilley waterflood is proceeding as planned. Current primary recoveries
are estimated at 13% from the pool with waterflood modelling suggesting
potential recoveries to increase to approximately 30%. The Company believes
widespread application of secondary recovery schemes could be applied to other
Pekisko reservoirs in the Princess area once pools have been delineated.
Crew fracture stimulated two older vertical low productivity wells in the first
quarter with the first well's production improving from 18 boe per day to a
current 45 boe per day. The second well's production improved from one boe per
day to a current 12 boe per day. Wet weather delayed the planned fracture
stimulation of five additional wells which are now expected to be completed
later in the third quarter.
Crew expanded its land base at Princess in the second quarter by adding 47 (47.0
net) Crown sections primarily in the Tide Lake area. With the addition of these
lands, the Company now plans to drill 60 to 70 wells in 2010 out of a current
inventory of over 600 locations on 102 sections, with a targeted 2010 exit rate
from the area in excess of 8,000 boe per day.
Montney Play, Northeast British Columbia
Crew drilled three (3.0 net) gas wells in the Montney formation at Septimus in
the second quarter of 2010. One of these wells has been recently completed and
has a production rate of 12 mmcf per day at a flowing casing pressure of 1,670
psi after seven days of in line production testing. In addition, the well was
flowing 40 bbls per mmcf per day of natural gas liquids during the test, of
which over 30 bbls per mmcf was condensate. This region of Septimus appears to
be more liquids rich than the main core area which customarily yields 24 bbls of
natural gas liquids per mmcf of natural gas. The other two wells off the same
drilling pad are currently being tested.
The planned expansion of the Septimus gas processing facility to 50 mmcf per day
from its current capacity of 25 mmcf per day is underway. The expansion is
expected to be completed in the fourth quarter, and upon equalization with the
current owner, Aux Sable Canada ("ASC"), Crew will become a 50% owner and will
remain operator of the facility. ASC expects to complete the installation of a
20 inch pipeline from the Septimus gas facility to the Alliance pipeline in the
third quarter of 2010 which is expected to be capable of transporting over 350
mmcf per day of gas and associated liquids.
Crew completed and tested its Portage exploration well in the second quarter.
The Portage well (0.5 net) had a final test rate of 1.7 mmcf per day at 580 psi
flowing casing pressure. This well had a short lateral of 900 meters, and
compares very favourably to competitor wells drilled immediately north at
Farrell Creek on a gas flow rate per frac basis. These competitor wells are
currently producing at a restricted rate of over 5 mmcf per day. Crew controls
69 (34.5 net) sections of land at Portage.
Crew currently plans to drill four (4.0 net) additional wells at Septimus over
the remainder of 2010. These wells are expected to be completed and brought on
production in the fourth quarter timed to the Septimus gas plant expansion. In
addition, the Company has drilled a horizontal exploration well on a large 100
percent working interest land block in the Goose area which is 20 miles
northwest of Septimus and Crew has begun drilling a second horizontal earning
well at Portage following up on its recent gas discovery and Crown land
purchases.
Cardium Play, West Central Alberta
In the Edson-Pine Creek, Alberta area, Crew owns 60 net sections of oil prone
Cardium rights. The Company is in the process of licensing three Cardium wells
at Pine Creek in 2010 where the Company has identified 80 net drilling
locations. Crew owns pipeline infrastructure and an underutilized gas processing
facility in the area to accommodate future production volume growth.
In the second quarter, the first of two Cardium horizontal wells was drilled by
a third party as part of the previously announced Edson farmout. The well (0.33
net) was completed with a multi-stage oil frac, and had a final test rate of 1.4
mmcf per day of natural gas and 150 bbls per day of oil (53 percent frac oil
recovered). The well will be tied in and is expected to begin production in the
third quarter. A second farmout well is licensed and is planned to be drilled in
the third quarter.
RISK MANAGEMENT ACTIVITY
Crew remains well protected against commodity price fluctuations for the
remainder of 2010. For the second half of 2010, the Company has an average of 20
mmcf per day of natural gas hedged at an average fixed price of $6.22 per mcf
and 3,000 bbl per day of oil hedged at a minimum floor price of Canadian dollar
WTI $81.24 per bbl. These hedges are in place to protect the Company's capital
program and balance sheet against the commodity price volatility that we have
experienced over the past two years.
The Company has also established commodity hedges to secure cash flow for 2011.
Crew has entered into Canadian dollar WTI oil price swaps and floors on an
average of 2,000 bbl per day for 2011. These transactions averaged a minimum
price floor of approximately CDN $86.50 per bbl for WTI oil. A detailed list of
the Company's hedge positions is included in the attached management's
discussion and analysis.
OUTLOOK
Business Environment
Oil prices have remained strong as world economies continue to recover from
recession resulting in increasing demand for most commodities. Natural gas
prices, on the other hand, continue to be depressed as aggressive development of
unconventional resources continues unabated across North America leading to an
over supplied market. Costs, particularly hydraulic fracturing costs, continue
to escalate as a result of increased activity levels which, in the current
pricing environment, can, in our opinion, only lead to reduced natural gas
activity. Crew has the ability to direct its capital and intellectual resources
to both oil and liquids rich natural gas plays which both provide superior
economics in the current environment. The Company will continue to focus its
efforts on the liquids rich Montney play at Septimus in British Columbia and,
more heavily, weight its capital program on the Princess Pekisko oil play in
Alberta.
Active Drilling Program
Crew continues to build upon its experience at Septimus and Princess. Drilling
and completion programs continue to be refined in an effort to reduce costs and
improve well results. A number of initiatives are planned to be tested in the
last half of the year in both of these areas. Drilling costs at Septimus have
declined as a result of reducing the drilling time from 37 days to 17 days for
the latest well representing a 55% reduction taking drill and case costs down to
approximately $1.4 million. Crew has a $225 million capital expenditure budget
for 2010, the majority of which will be directed to oil related drilling and
land acquisitions at Princess. As a result of weather related delays in
southeast Alberta over the last four months, Crew is now forecasting its average
production in 2010 to be 14,500 to 15,000 boe per day. Exit production is
forecasted to be 18,000 boe per day with an increased weighting on liquids
production.
Crew is in an enviable position possessing a number of resource plays that offer
our shareholders significant upside with scale, repeatability and very
attractive investment metrics. The Company is well financed to execute a very
active second half 2010 program which is expected to result in Crew exiting the
year at record production levels while continuing to de-risk its resource plays
for years of future growth. We are excited about our recent well results and the
potential of our asset base and look forward to reporting our third quarter
results in November.
Management's Discussion and Analysis
ADVISORIES
Management's discussion and analysis ("MD&A") is the Company's explanation of
its financial performance for the period covered by the financial statements
along with an analysis of the Company's financial position. Comments relate to
and should be read in conjunction with the unaudited consolidated financial
statements of the Company for the three and six month periods ended June 30,
2010 and 2009 and the audited consolidated financial statements and Management's
Discussion and Analysis for the year ended December 31, 2009. The consolidated
financial statements have been prepared in accordance with generally accepted
accounting principles ("GAAP") in Canada and all figures provided herein and in
the December 31, 2009 consolidated financial statements are reported in Canadian
dollars.
Forward Looking Statements
This MD&A contains forward-looking statements. Management's assessment of future
plans and operations, drilling plans and the timing thereof, plans for the
tie-in and completion of wells and the timing thereof, capital expenditures,
timing of capital expenditures and methods of financing capital expenditures and
the ability to fund financial liabilities, production estimates, expected
commodity mix and prices and the impact on Crew, future operating costs, future
transportation costs, expected royalty rates, general and administrative
expenses, interest rates, debt levels, funds from operations and the timing of
and impact of adoption of IFRS and other accounting policies may constitute
forward-looking statements under applicable securities laws and necessarily
involve risks including, without limitation, risks associated with oil and gas
exploration, development, exploitation, production, marketing and
transportation, loss of markets, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks, competition
from other producers, inability to retain drilling rigs and other services,
incorrect assessment of the value of acquisitions, failure to realize the
anticipated benefits of acquisitions, the inability to fully realize the
benefits of acquisitions, delays resulting from or inability to obtain required
regulatory approvals and ability to access sufficient capital from internal and
external sources. As a consequence, the Company's actual results may differ
materially from those expressed in, or implied by, the forward looking
statements.
Forward looking statements or information are based on a number of factors and
assumptions which have been used to develop such statements and information but
which may prove to be incorrect. Although Crew believes that the expectations
reflected in such forward-looking statements or information are reasonable,
undue reliance should not be placed on forward looking statements because the
Company can give no assurance that such expectations will prove to be correct.
In addition to other factors and assumptions which may be identified in this
document and other documents filed by the Company, assumptions have been made
regarding, among other things: the impact of increasing competition; the general
stability of the economic and political environment in which Crew operates; the
ability of the Company to obtain qualified staff, equipment and services in a
timely and cost efficient manner; drilling results; the ability of the operator
of the projects which the Company has an interest in to operate the field in a
safe, efficient and effective manner; Crew's ability to obtain financing on
acceptable terms; field production rates and decline rates; the ability to
reduce operating costs; the ability to replace and expand oil and natural gas
reserves through acquisition, development or exploration; the timing and costs
of pipeline, storage and facility construction and expansion; the ability of the
Company to secure adequate product transportation; future petroleum and natural
gas prices; currency, exchange and interest rates; the regulatory framework
regarding royalties, taxes and environmental matters in the jurisdictions in
which the Company operates; and Crew's ability to successfully market its
petroleum and natural gas products. Readers are cautioned that the foregoing
list of factors is not exhaustive. Additional information on these and other
factors that could affect the Company's operations and financial results are
included in reports on file with Canadian securities regulatory authorities and
may be accessed through the SEDAR website (www.sedar.com) or at the Company's
website (www.crewenergy.com). Furthermore, the forward looking statements
contained in this document are made as at the date of this document and the
Company does not undertake any obligation to update publicly or to revise any of
the included forward looking statements, whether as a result of new information,
future events or otherwise, except as may be required by applicable securities
laws.
Conversions
The oil and gas industry commonly expresses production volumes and reserves on a
"barrel of oil equivalent" basis ("boe") whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved analysis of results and comparisons with other industry participants.
Throughout this MD&A, Crew has used the 6:1 boe measure which is the approximate
energy equivalency of the two commodities at the burner tip. Boe does not
represent a value equivalency at the wellhead nor at the plant gate which is
where Crew sells its production volumes and therefore may be a misleading
measure, particularly if used in isolation.
Non-GAAP Measures
One of the benchmarks Crew uses to evaluate its performance is funds from
operations. Funds from operations is a measure not defined in GAAP that is
commonly used in the oil and gas industry. It represents cash provided by
operating activities before changes in non-cash working capital, asset
retirement expenditures and the transportation liability charge. The Company
considers it a key measure as it demonstrates the ability of the business to
generate the cash flow necessary to fund future growth through capital
investment and to repay debt. Funds from operations should not be considered as
an alternative to, or more meaningful than cash provided by operating activities
as determined in accordance with GAAP as an indicator of the Company's
performance. Crew's determination of funds from operations may not be comparable
to that reported by other companies. Crew also presents funds from operations
per share whereby per share amounts are calculated using weighted average shares
outstanding consistent with the calculation of income per share. The following
table reconciles Crew's cash provided by operating activities to funds from
operations:
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Three months Three months Six months Six months
ended ended ended ended
($ thousands) June 30, 2010 June 30, 2009 June 30, 2010 June 30, 2009
----------------------------------------------------------------------------
Cash provided by
operating activities 24,149 21,517 56,362 41,023
Asset retirement
expenditures 129 181 705 282
Transportation
liability charge
(note 1) 154 329 482 657
Change in non-cash
working capital (3,739) (1,991) (8,639) (5,405)
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Funds from operations 20,693 20,036 48,910 36,557
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Notes:
(1) The amount for the three and six months ended June 30, 2010 does not
include the transportation liability write-down of $344,000 as shown
in the transportation costs section.
Management uses certain industry benchmarks such as operating netback to analyze
financial and operating performance. This benchmark as presented does not have
any standardized meaning prescribed by Canadian GAAP and therefore may not be
comparable with the calculation of similar measures for other entities.
Operating netback equals total petroleum and natural gas sales including
realized gains and losses on commodity contracts less royalties, operating costs
and transportation costs calculated on a boe basis. Management considers
operating netback an important measure to evaluate its operational performance
as it demonstrates its field level profitability relative to current commodity
prices.
RESULTS OF OPERATIONS
Production
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Three months ended Three months ended
June 30, 2010 June 30, 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 3,184 420 21,633 7,210 3,042 898 37,065 10,117
British
Columbia 121 697 24,120 4,838 212 308 16,971 3,349
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Total 3,305 1,117 45,753 12,048 3,254 1,206 54,036 13,466
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Second quarter 2010 production decreased compared with the second quarter of
2009 as a result of the sale of approximately 2,300 boe per day of primarily
natural gas production from two separate dispositions in Ferrier, Alberta 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 and oil production in the
Princess, Alberta area. However, in the second quarter of 2010, the Company's
oil production was below the Company's expectations as poor weather throughout
southern Alberta during the second quarter hampered activity in the Princess
area.
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Three months ended Three months ended
June 30, 2010 June 30, 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 3,659 612 26,232 8,643 3,264 932 38,574 10,625
British
Columbia 121 672 24,483 4,874 219 363 18,199 3,615
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Total 3,780 1,284 50,715 13,517 3,483 1,295 56,773 14,240
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Production for the first six months of 2010 decreased due to the previously
mentioned asset dispositions but was partially offset due to production
additions from a successful drilling program.
Revenue
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Three months Three months Six months Six months
ended ended ended ended
June 30, 2010 June 30, 2009 June 30, 2010 June 30, 2009
----------------------------------------------------------------------------
Revenue ($ thousands)
Natural gas 17,929 17,998 44,913 45,268
Oil 19,809 17,988 47,457 32,473
Natural gas liquids 5,289 3,345 12,429 7,834
Sulphur - - - 98
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Total 43,027 39,331 104,799 85,673
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Crew average prices
Natural gas ($/mcf) 4.31 3.66 4.89 4.41
Oil ($/bbl) 65.86 60.75 69.36 51.52
Natural gas liquids
($/bbl) 52.01 30.46 53.50 33.42
Oil equivalent ($/boe) 39.25 32.10 42.83 33.24
Benchmark pricing
Natural Gas - AECO C daily
index (Cdn $/mcf) 3.94 3.43 4.49 4.21
Oil - Bow River Crude Oil
(Cdn $/bbl) 75.24 70.73 77.75 62.10
Oil and ngl - CDN$ West
Texas Int. (Cdn $/bbl) 80.12 69.27 81.01 61.48
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Crew's second quarter 2010 revenue increased 9% from the second quarter of 2009
due to the 22% increase in average commodity prices partially offset by an 11%
decrease in the Company's production.
Crew's second quarter 2010 average natural gas price increased 18% which was
comparable to a 15% increase in its benchmark index. In the second quarter of
2010, the Company's oil price increased 8% as compared with a 7% increase in the
Company's comparable benchmark Bow River Crude. The price received for the
Company's ngl production increased 71% as compared to a 16% increase in the
Company's benchmark CDN$ West Texas Intermediate pricing. This was due to the
sale of the assets in the Ferrier area in 2009 which included lower valued
ethane production. In addition, the Company increased production of higher
valued condensate from the Septimus area.
For the six months ended June 30, 2010, Crew's gas price increased 11% as
compared with a 7% increase in the benchmark. Decreased production of lower
valued natural gas production in the Sierra, British Columbia area replaced by
higher valued natural gas from the Septimus area accounts for Crew's increased
pricing as compared to the benchmark. The Company's realized oil price increased
35% as compared with a 25% increase in the benchmark Bow River Crude primarily
due to higher 2010 Bow River Oil pricing combined with Crew receiving a similar
fixed price quality differential off of the Bow River price for oil volumes in
the Princess area. The Company's ngl price increased 60% as compared with a 32%
increase in the benchmark due to the sale of Ferrier, Alberta assets as
mentioned above which included lower valued ethane production combined with
increased higher valued condensate production from Septimus.
Royalties
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Three months Three months Six months Six months
($ thousands, ended ended ended ended
except per boe) June 30, 2010 June 30, 2009 June 30, 2010 June 30, 2009
----------------------------------------------------------------------------
Royalties 8,419 5,512 21,568 16,192
Per boe 7.68 4.50 8.82 6.28
Percentage of revenue 19.6% 14.0% 20.6% 18.9%
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Royalties as a percentage of revenue increased in the second quarter and first
half of 2010 compared to the same periods of 2009 due to increased oil
production from Princess which currently attracts a higher royalty rate and the
sale of the properties in the Ferrier and Edson areas which attracted a lower
royalty rate. Corporately, with an increase in forecasted second half oil sales
from production in the Princess area, Crew forecasts annual royalties as a
percentage of revenue to average 21% to 23% for 2010.
Financial Instruments
Commodities
The Company enters into derivative and physical risk management contracts in
order to reduce volatility in financial results, to protect acquisition
economics and to ensure a certain level of cash flow to fund planned capital
projects. Crew's strategy focuses on the use of puts, costless collars, swaps
and fixed price contracts to 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:
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Three months Three months Six months Six months
ended ended ended ended
($ thousands) June 30, 2010 June 30, 2009 June 30, 2010 June 30, 2009
----------------------------------------------------------------------------
Realized gain on
financial instruments 3,756 5,643 4,684 6,196
Unrealized gain (loss)
on financial instruments 2,334 (3,816) 10,532 1,054
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As at June 30, 2010, the Company held derivative commodity contracts as
follows:
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
Natural 2,500 November 1, 2009 - AECO C $6.00/gj Swap 894
Gas gj/day December 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO C $8.00/gj Call (5)
Gas gj/day December 31, 2010 Monthly
Index
Natural 10,000 January 1, 2010 - AECO C $7.75/gj Call (12)
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $6.20/gj Swap 986
Gas gj/day December 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO C $6.08/gj Swap 2,217
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $5.25/gj Swap 550
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 January 1, 2010 - AECO C $5.55/gj Swap 688
Gas gj/day December 31, 2010 Monthly
Index
Natural 2,500 April 1, 2010 - AECO C $5.30/gj Swap 471
Gas gj/day October 31, 2010 Monthly
Index
Natural 5,000 January 1, 2010 - AECO/NYMEX US$($0.55) Swap 250
Gas mmbtu/day December 31, 2010 Basis diff
Oil 250 January 1, 2010 - CDN$ WTI $78.50/bbl Swap (159)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - CDN$ WTI $72.00 - Collar (75)
bbl/day December 31, 2010 $88.00/bbl
Oil 250 January 1, 2010 - CDN$ WTI $82.50/bbl Swap 25
bbl/day December 31, 2010
Oil 500 January 1, 2010 - CDN$ WTI $80.50/bbl Swap (117)
bbl/day December 31, 2010
Oil 500 January 1, 2010 - US$ WTI US$81.00/bbl Swap 387
bbl/day December 31, 2010
Oil 250 January 1, 2010 - CDN$ WTI $80.00 - Collar 136
bbl/day December 31, 2010 $95.02/bbl
Oil 250 March 1, 2010 - CDN$ WTI $84.00/bbl Swap 136
bbl/day December 31, 2010
Oil 250 July 1, 2010 - CDN$ WTI $88.10 Swap 281
bbl/day December 31, 2010
Oil 250 July 1, 2010 - CDN$ WTI $91.50 Swap 438
bbl/day December 31, 2010
Oil 250 January 1, 2011 - CDN$ WTI $86.00/bbl Swap 79
bbl/day December 31, 2011
Oil 250 January 1, 2011 - CDN$ WTI $90.00 Swap 441
bbl/day December 31, 2011
Oil 500 January 1, 2011 - CDN$ WTI $90.20 Swap 914
bbl/day December 31, 2011
Oil 250 January 1, 2011 - CDN$ WTI $82.00 - Collar 216
bbl/day December 31, 2011 $94.62
Oil 250 January 1, 2011 - CDN$ WTI $80.00 - Collar 167
bbl/day December 31, 2011 $95.45
Oil 250 January 1, 2011 - CDN$ WTI $85.00 - Collar 533
bbl/day December 31, 2011 $100.50
----------------------------------------------------------------------------
Total 9,441
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Foreign currency
Although all of the Company's petroleum and natural gas sales are conducted in
Canada and are denominated in Canadian dollars, Canadian commodity prices are
influenced by fluctuations in the Canadian to U.S. dollar exchange rate.
At June 30, 2010, the Company held the following derivative foreign currency
contracts:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
USD / CAD $ US $2M/ January 1, 2010 -
exchange Month December 31, 2010 CAD/USD 1.094 Swap 342
----------------------------------------------------------------------------
Total 342
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 June 30, 2010, Crew had
contracts in place fixing the interest rate on $150 million of bankers'
acceptances at rates of 1.10% to 1.12%. The Company pays additional stamping
fees and margins on bankers' acceptances as outlined in note 3 of the financial
statements.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair
Subject of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
BA Rate $50M/year February 10, 2009 - BA - CDOR 1.10% Swap (58)
February 10, 2011
BA Rate $50M/year February 12, 2009 - BA - CDOR 1.10% Swap (39)
February 12, 2011
BA Rate $50M/year May 28, 2009 - BA - CDOR 1.12% Swap 12
May 28, 2011
----------------------------------------------------------------------------
Total (85)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subsequent to June 30, 2010, the Company unwound the $50 million per year 1.12%
swaps maturing on May 28, 2011 for net proceeds to the Company of $12,000.
Subsequent to June 30, 2010, the Company entered into the following
financial instrument contract:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Strike
Subject of Price Option
Contract Volume Term Reference (per bbl) Traded
----------------------------------------------------------------------------
Oil 250 bbl/day January 1, 2011 - CDN$ WTI $88.50 Swap
December 31, 2011
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands, except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Operating costs 12,663 14,448 27,649 28,258
Per boe 11.55 11.79 11.30 10.96
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the second quarter of 2010, the Company's operating costs per unit slightly
decreased over the same period in 2009 due to additional production from the
Septimus area where operating costs per boe are lower than the Company's total
corporate average. This was partially offset by the sale of lower cost
production in the Edson area and the impact of poor weather at Princess which
inhibited production and increased costs for the period. For the first six
months of 2010, operating costs per boe were slightly higher than the same
period in 2009 due to the aforementioned sale of lower cost production in the
Edson area and decreased production from the Sierra area where the operating
costs have a high fixed cost component and the impact of poor weather at
Princess which inhibited production and increased costs for the period. With
additional forecasted production to offset fixed costs in the Princess and
Septimus areas and cost cutting measures associated with water handling at
Princess, the Company forecasts total operating costs to decrease from the
current level to average between $10.00 and $10.75 per boe for 2010.
Transportation Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
($ thousands, June 30, June 30, June 30, June 30,
except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Transportation costs including
liability write-down 2,143 2,397 4,520 5,265
Transportation liability write-down - - 344 -
----------------------------------------------------------------------------
Transportation costs 2,143 2,397 4,864 5,265
Per boe 1.95 1.96 1.99 2.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In the second quarter of 2010, the Company's transportation costs per unit were
at the same levels as the same period in 2009. The disposition of lower
transportation cost production in Edson and Ferrier was offset by the Company
permanently assigning its unutilized firm transportation commitment in
northeastern British Columbia in March 2010. For the first six months of 2010,
the Company's transportation costs per unit have decreased as compared with the
same period in 2009 due to the assignment of the firm transportation commitment
and increased natural gas production in Septimus and oil production in Princess
which both currently attract a lower transportation costs per boe. The Company
continues to expect transportation costs to range between $1.50 and $2.00 for
2010.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
June 30, 2010
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 65.86 52.01 4.31 39.25
Realized commodity hedging gain 1.02 - 0.07 3.26
Royalties (18.30) (10.69) (0.44) (7.68)
Operating costs (15.69) (9.89) (1.69) (11.55)
Transportation costs (1.94) (1.08) (0.35) (1.95)
----------------------------------------------------------------------------
Operating netbacks 30.95 30.35 1.90 21.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months ended
June 30, 2009
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 60.75 30.46 3.66 32.10
Realized commodity hedging gain - - 1.01 4.04
Royalties (16.45) (9.48) (0.08) (4.50)
Operating costs (13.44) (9.81) (1.91) (11.79)
Transportation costs (1.28) - (0.41) (1.96)
----------------------------------------------------------------------------
Operating netbacks 29.58 11.17 2.27 17.89
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended
June 30, 2010
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 69.36 53.50 4.89 42.83
Realized commodity hedging gain 0.42 - 0.03 1.83
Royalties (19.84) (12.28) (0.56) (8.82)
Operating costs (14.15) (9.44) (1.72) (11.30)
Transportation costs (1.38) (1.26) (0.36) (1.99)
----------------------------------------------------------------------------
Operating netbacks 34.41 30.52 2.28 22.55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended
June 30, 2009
Natural
Oil Ngl gas Total
($/bbl) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 51.52 33.42 4.41 33.24
Realized commodity hedging gain - - 0.55 2.20
Royalties (13.35) (10.91) (0.50) (6.28)
Operating costs (11.98) (9.17) (1.81) (10.96)
Transportation costs (1.43) - (0.42) (2.04)
----------------------------------------------------------------------------
Operating netbacks 24.76 13.34 2.23 16.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
($ thousands, June 30, June 30, June 30, June 30,
except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Gross costs 3,875 3,219 8,047 6,699
Operator's recoveries (596) (388) (1,427) (812)
Capitalized costs (1,639) (1,416) (3,310) (2,944)
----------------------------------------------------------------------------
General and administrative expenses 1,640 1,415 3,310 2,943
Per boe 1.50 1.15 1.35 1.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increased general and administrative costs before recoveries and capitalization
were mainly the result of increased staff levels to accommodate the Company's
larger operations at Septimus and Princess in the second quarter and first half
of 2010 compared to 2009. In the second quarter and first half of 2010, net
general and administrative costs per boe have increased over the same period of
2009. This is primarily due to increased gross costs and decreased production
due to the sale of the Ferrier and Edson production for these periods as
compared with the same periods in 2009. The Company expects general and
administrative expenses to average between $1.00 and $1.25 per boe for the year
as forecasted production increases in the last half of 2010 and second half
costs historically decline as annual reporting costs are now complete.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
($ thousands, June 30, June 30, June 30, June 30,
except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Interest expense 1,225 1,166 3,182 2,654
Average debt level 50,446 223,864 92,908 225,754
Effective interest rate 9.7% 2.1% 6.9% 2.4%
Per boe 1.12 0.95 1.30 1.03
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's 2010 second quarter and first half interest expense increased over the
same periods in 2009 despite a significant decrease in outstanding average debt
levels. This increase resulted from an increase in the stamping fees charged on
the Company's outstanding banker's acceptances from 1.1% in 2009 to 3.5% in 2010
and a significant increase in the standby fees charged on the unutilized portion
of the Company's bank facility. The effective interest rate increased for both
the three and six month periods as a result of the higher margins charged on the
Company's drawn facility. In addition, effective interest rates were impacted by
higher standby fees charged on the unutilized facility and the amortization of
annual renewal fees against the significantly decreased drawn facility as a
denominator.
With the Company's recently renegotiated bank facility and decreased average
debt to EBITDA ratios, the stamping fees and margins applied to its facility are
expected to decrease in the latter half of 2010.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Gross costs 2,139 1,663 4,779 3,421
Capitalized costs (1,069) (832) (2,389) (1,711)
----------------------------------------------------------------------------
Total stock-based compensation 1,070 831 2,390 1,710
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has increased in the second
quarter and first half of 2010 compared with 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 due to the Company's share price increasing.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
($ thousands, June 30, June 30, June 30, June 30,
except per boe) 2010 2009 2010 2009
----------------------------------------------------------------------------
Depletion, depreciation
and accretion 25,647 32,823 57,767 67,794
Per boe 23.39 26.79 23.61 26.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per unit depletion has decreased in the second quarter and first half of 2010
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 than the Company's corporate depletion rate.
Future Income Taxes
The provision for future income taxes was a recovery of $1.0 million in the
second quarter of 2010 compared to a recovery of $5.2 million in the same period
of 2009. The decrease in the future tax recovery was a result of a larger
pre-tax loss in 2009. For the first six months of 2010, the Company had a future
tax recovery of $0.1 million as compared with a recovery of $10.6 million for
the same period of 2009. The larger recovery in 2009 was a result of a greater
pre-tax loss in 2009 and a corporate rate reduction in British Columbia from 11
percent to 10.5 percent in 2010 and a further reduction to 10 percent in 2011.
Cash and Funds from Operations and Net Loss
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
($ thousands, except June 30, June 30, June 30, June 30,
per share amounts) 2010 2009 2010 2009
----------------------------------------------------------------------------
Cash provided by operating activities 24,149 21,517 56,362 41,023
Funds from operations 20,693 20,036 48,910 36,557
Per share - basic 0.26 0.27 0.62 0.51
- diluted 0.25 0.27 0.60 0.51
Net loss (2,691) (12,267) (249) (21,285)
Per share - basic (0.03) (0.17) 0.00 (0.29)
- diluted (0.03) (0.17) 0.00 (0.29)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The second quarter and first half of 2010 increase in cash provided by
operations and funds from operations was the result of increased commodity
pricing but was partially offset by the lower production due to the asset sales
completed in late 2009 and early 2010 and the poor weather at Princess. The
second quarter and first half of 2010 net loss was lower than the same periods
in 2009 due to increased commodity pricing, increased unrealized gains on
financial instruments and decreased depletion costs.
Capital Expenditures, Acquisitions and Dispositions
During the second quarter of 2010, the Company drilled 11 (10.3 net) wells
resulting in seven (6.3 net) oil wells, three (3.0 net) gas wells and one (1.0
net) water disposal wells. In addition, the Company also completed eight (7.5
net) wells in the Princess and Septimus areas. Crew continued to add to its
infrastructure spending $7.5 million primarily on infrastructure improvements at
Princess and the gas plant expansion at Septimus. In the second quarter of 2010,
the Company continued to add to its undeveloped land base spending $26.5 million
on crown land in southern Alberta and northeastern British Columbia. The Company
also closed its previously announced disposition of approximately 1,700 boe per
day of mainly natural gas production in the Edson area for net proceeds of
$123.3 million.
Total exploration and development capital expenditures for the second quarter
and first half of 2010 were $63.3 million and $122.4 million, respectively
compared to $14.2 million and $37.9 million for the same periods in 2009. The
expenditures are detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2010 2009 2010 2009
----------------------------------------------------------------------------
Land 27,155 716 34,872 3,868
Seismic 164 322 5,095 2,095
Drilling and completions 26,561 4,745 66,891 10,400
Facilities, equipment and pipelines 7,490 6,889 11,770 18,345
Other 1,939 1,515 3,756 3,157
----------------------------------------------------------------------------
Total exploration and development 63,309 14,187 122,384 37,865
Property dispositions (121,724) (23,688) (132,640) (34,378)
----------------------------------------------------------------------------
Total (58,415) (9,501) (10,256) 3,487
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2010, budgeted exploration and development expenditures for 2010
are estimated at $225 million.
Liquidity and Capital Resources
Capital Funding
During the second quarter of 2010, the Company completed the extension of its
credit facility with a syndicate of banks (the "Syndicate"). The credit facility
was amended to a revolving line of credit of $190 million and an operating line
of credit of $20 million for a total borrowing facility of $210 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 review 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 October 31, 2010. At June 30, 2010, the Company had drawings of $71.8
million on the Facility and had issued letters of credit totaling $3.6 million.
During the first half of 2010, the Company has received proceeds of $17.6
million due to the exercise of 1,943,300 employee stock options.
The Company will continue to fund its on-going operations from a combination of
cash flow, debt, asset dispositions and equity financings as needed. As the
majority of our on-going capital expenditure program is directed to the further
growth of reserves and production volumes, Crew is readily able to adjust its
budgeted capital expenditures should the need arise.
Working Capital
The capital intensive nature of Crew's activities generally results in the
Company carrying a working capital deficit. The working capital deficiency
includes only accounts receivable less accounts payable and accrued liabilities.
The Company maintains sufficient unused bank credit lines to satisfy such
working capital deficiencies. At June 30, 2010, the Company's working capital
deficiency totaled $34.9 million which, when combined with the drawings on its
bank line, represented 51% of its current bank facility.
Share Capital
As at August 9, 2010, Crew had 80,112,401 Common Shares and 5,662,867 options to
acquire Common Shares of the Company issued and outstanding.
Capital Structure
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes adjustments
on an on-going basis in order to maintain the flexibility needed to achieve the
Company's long-term objectives. To manage the capital structure the Company may
adjust capital spending, hedge future revenue and some costs, issue new equity,
issue new debt or repay existing debt through asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1. This ratio may increase at certain times as a result of acquisitions or low
commodity prices. As shown below, as at June 30, 2010, the Company's ratio of
net debt to annualized funds from operations was 1.29 to 1 (December 31, 2009 -
1.67 to 1).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands, except ratio) June 30, 2010 Dec. 31, 2009
----------------------------------------------------------------------------
Accounts receivable 29,634 37,574
Accounts payable and accrued liabilities (64,520) (84,228)
----------------------------------------------------------------------------
Working capital deficiency (34,886) (46,654)
Bank loan (71,845) (135,601)
----------------------------------------------------------------------------
Net debt (106,731) (182,255)
Funds from operations 20,693 27,256
Annualized 82,772 109,024
Net debt to annualized funds
from operations ratio 1.29 1.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Contractual Obligations
Throughout the course of its ongoing business, the Company enters into various
contractual obligations such as credit agreements, purchase of services, royalty
agreements, operating agreements, processing agreements, right of way agreements
and lease obligations for office space and automotive equipment. All such
contractual obligations reflect market conditions prevailing at the time of
contract and none are with related parties. The Company believes it has adequate
sources of capital to fund all contractual obligations as they come due. The
following table lists the Company's obligations with a fixed term.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands) Total 2010 2011 2012 2013 2014 Thereafter
----------------------------------------------------------------------------
Bank Loan (note 1) 71,845 - - 71,845 - - -
Operating Leases 3,930 872 1,743 1,315 - - -
Capital commitments 8,000 4,000 4,000 - - - -
Transportation
agreements 4,918 1,853 3,065 - - - -
Processing agreement 28,967 1,525 3,049 3,049 3,049 3,049 15,246
----------------------------------------------------------------------------
Total 117,660 8,250 11,857 76,209 3,049 3,049 15,246
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2012. However, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.
The firm transportation commitments were acquired as part of the Company's May
2007 private company acquisition and represent firm service commitments for
transportation and processing of natural gas in British Columbia. In 2010, the
Company permanently assigned approximately $6.2 million of its firm
transportation commitments to third parties. The amount shown represents the
remaining contractual obligation.
During 2009, Crew entered into the firm processing agreement to process natural
gas through a third party owned gas processing facility in the Septimus area of
northeast British Columbia. Under the terms of the agreement Crew has committed
to process a minimum monthly volume of gas through the facility commencing on
December 1, 2009 and continuing through November 30, 2019. The commitment is
included in the above table.
The agreement additionally provides Crew the option to participate in an
expansion of the facility at a cost of 50% of the total expanded facility
construction costs and subsequently become a 50% owner in the facility. If the
facility is not expanded prior to January 1, 2013, the current owner of the
facility can require Crew to purchase the existing facility for the total
construction costs of $19.1 million plus $0.7 million or alter the fees
associated with Crew's commitment in order to recover the amount of Crew's full
commitment prior to January 1, 2016.
Guidance
Crew continues to build upon its experience at Septimus and Princess. Drilling
and completion programs continue to be refined in an effort to reduce costs and
improve well results. A number of initiatives are planned to be tested in the
last half of the year in both of these areas. Crew has a $225 million capital
expenditure budget for 2010, the majority of which will be directed to oil
related drilling and land acquisitions at Princess, Alberta. As a result of
weather related delays in southeast Alberta over the last four months, Crew is
now forecasting its average production in 2010 to be 14,500 to 15,000 boe per
day. Exit production is forecasted to be 18,000 boe per day with an increased
weighting on liquids production.
Additional Disclosures
Quarterly Analysis
The following table summarizes Crew's key quarterly financial results for the
past eight financial quarters:
($ thousands, except per
share amounts) June 30 Mar. 31 Dec. 31 Sept. 30
2010 2010 2009 2009
----------------------------------------------------------------------------
Total daily production (boe/d) 12,048 15,001 14,470 13,065
Average wellhead price ($/boe) 39.25 45.75 43.30 32.04
Petroleum and natural gas sales 43,027 61,772 57,646 38,510
Cash provided by operations 24,149 32,213 16,734 24,902
Funds from operations 20,693 28,217 27,256 19,640
Per share - basic 0.26 0.36 0.35 0.25
- diluted 0.25 0.35 0.35 0.25
Net income (loss) (2,691) 2,442 (9,154) (7,376)
Per share - basic (0.03) 0.03 (0.12) (0.10)
- diluted (0.03) 0.03 (0.12) (0.10)
($ thousands, except per
share amounts) June 30 Mar. 31 Dec. 31 Sept. 30
2009 2009 2008 2008
----------------------------------------------------------------------------
Total daily production (boe/d) 13,466 15,022 14,869 11,505
Average wellhead price ($/boe) 32.10 34.28 42.99 61.74
Petroleum and natural gas sales 39,331 46,342 58,806 65,345
Cash provided by operations 21,517 19,506 25,700 36,208
Funds from operations 20,036 16,521 29,646 35,004
Per share - basic 0.27 0.23 0.42 0.54
- diluted 0.27 0.23 0.42 0.54
Net income (loss) (12,267) (9,018)(74,853) 15,178
Per share - basic (0.17) (0.13) (1.05) 0.24
- diluted (0.17) (0.13) (1.05) 0.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 2008 to 2010, these performance measures have fluctuated as a result of
volatile oil and natural gas prices resulting from the current unstable global
economy.
Significant factors and trends that have impacted the Company's results during
the above periods include:
- Revenue is directly impacted by the Company's ability to replace existing
declining production and add incremental production through its on-going capital
expenditure program.
- Production in the second quarter of 2009 and 2010 was negatively impacted by
scheduled and unscheduled third party facility shutdowns and poor weather
experienced in southern Alberta in 2010.
- In August 2008, the Company acquired Gentry Resources Ltd. with approximately
4,000 boe per day of production at closing.
- Revenue and royalties are significantly impacted by underlying commodity
prices. The Company utilizes derivative contracts and forward sales contracts to
reduce the exposure to commodity price fluctuations 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 the fourth quarter of 2008, Crew performed an impairment test on its
goodwill and determined that its carrying value exceeded its fair value and
therefore an impairment charge of $69.1 million was required.
- In 2009 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
New Accounting Pronouncements
International Financial Reporting Standards
Effective January 1, 2011, Canadian public companies are required to adopt
International Financial Reporting Standards ("IFRS") which will include
comparatives for 2010. Crew's financial statements up to and including the
December 31, 2010 financial statements will continue to be reported in
accordance with Canadian GAAP as it exists on each reporting date. Financial
statements for the quarter ended March 31, 2011, including comparative amounts,
will be prepared on an IFRS basis.
In order to transition to IFRS, management has established a project team and
formed an executive steering committee. A transition plan has been developed to
convert the financial statements to IFRS. External advisors have been retained
and will assist management with the project on an as needed basis. Staff
training programs will continue throughout 2010. The Company continues to assess
the effect of the transition on information systems, internal controls over
financial reporting and disclosure controls and procedures. The project team and
steering committee continue to provide updates to senior management and the
Audit Committee. The Company's auditors are involved throughout the process to
ensure the Company's policies are in accordance with the new standards.
Analysis of differences between IFRS and Canadian GAAP is continuing. There are
significant accounting policy changes anticipated on adoption of IFRS which are
described in more detail in the Company's December 31, 2009 MD&A. Management is
continuing to finalize its accounting policies and as such is unable to quantify
the impact on the financial statements at this time. In addition, anticipated
changes to IFRS and International Accounting Standards prior to adoption could
cause changes to certain items based on new facts and circumstances.
In accordance with its plan, Crew has analyzed accounting policy alternatives
and drafted its IFRS position papers. Crew is in the process of completing its
January 1, 2010 IFRS opening balance sheet and having its external auditors
review the Company's draft IFRS balance sheet impacts.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
The Company's Chief Executive Officer ("CEO") and Chief Financial Officer
("CFO") have designed, or caused to be designed under their supervision,
disclosure controls and procedures to provide reasonable assurance that: (i)
material information relating to the Company is made known to the Company's CEO
and CFO by others, particularly during the period in which the annual and
interim filings are being prepared; and (ii) information required to be
disclosed by the Company in its annual filings, interim filings or other reports
filed or submitted by it under securities legislation is recorded, processed,
summarized and reported within the time period specified in securities
legislation.
Crew's CEO and CFO have designed, or caused to be designed under their
supervision, internal controls over financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with generally
accepted accounting principles. The Company is required to disclose herein any
change in the Company's internal control over financial reporting that occurred
during the period beginning on April 1, 2010 and ended on June 30, 2010 that has
materially affected, or is reasonably likely to materially affect, the Company's
internal control over financial reporting. No material changes in the Company's
internal control over financial reporting were identified during such period
that have materially affected, or are reasonably likely to materially affect,
the Company's internal control over financial reporting.
It should be noted that a control system, including the Company's disclosure and
internal controls and procedures, no matter how well conceived, can provide only
reasonable, but not absolute assurance that the objectives of the control system
will be met and it should not be expected that the disclosure and internal
controls and procedures will prevent all errors or fraud.
Dated as of August 9, 2010
Cautionary Statements
Forward-looking information and statements
This news release contains certain forward-looking information and statements
within the meaning of applicable securities laws. The use of any of the words
"expect", "anticipate", "continue", "estimate", "may", "will", "project",
"should", "believe", "plans", "intends" and similar expressions are intended to
identify forward-looking information or statements. In particular, but without
limiting the foregoing, this news release contains forward-looking information
and statements pertaining to the following: the volume and product mix of Crew's
oil and gas production; production estimates; anticipated disposal rates on
water disposal wells; future oil and natural gas prices and Crew's commodity
risk management programs; future liquidity and financial capacity; future
results from operations and operating metrics; anticipated reductions in
operating costs; future costs, expenses and royalty rates; future interest
costs; the exchange rate between the $US and $Cdn; future development,
exploration, acquisition and development activities and related capital
expenditures and the timing thereof; the number of wells to be drilled,
completed and tied-in and the timing thereof; the amount and timing of capital
projects; the anticipated recoveries from Crew's waterflood program at Tilley;
planned expansion of the Septimus gas processing facility; ASC completion of the
Septimus pipeline, the timing and delivery capability thereof; operating costs;
the total future capital associated with development of reserves and resources;
forecast reductions in operating expenses.
Forward-looking statements or information are based on a number of material
factors, expectations or assumptions of Crew which have been used to develop
such statements and information but which may prove to be incorrect. Although
Crew believes that the expectations reflected in such forward-looking statements
or information are reasonable, undue reliance should not be placed on
forward-looking statements because Crew can give no assurance that such
expectations will prove to be correct. In addition to other factors and
assumptions which may be identified herein, assumptions have been made
regarding, among other things: the impact of increasing competition; the general
stability of the economic and political environment in which Crew operates; the
timely receipt of any required regulatory approvals; the ability of Crew to
obtain qualified staff, equipment and services in a timely and cost efficient
manner; drilling results; the ability of the operator of the projects in which
Crew has an interest in to operate the field in a safe, efficient and effective
manner; the ability of Crew to obtain financing on acceptable terms; field
production rates and decline rates; the ability to replace and expand oil and
natural gas reserves through acquisition, development and exploration; the
timing and cost of pipeline, storage and facility construction and expansion and
the ability of Crew to secure adequate product transportation; future commodity
prices; currency, exchange and interest rates; regulatory framework regarding
royalties, taxes and environmental matters in the jurisdictions in which Crew
operates; and the ability of Crew to successfully market its oil and natural gas
products.
The forward-looking information and statements included in this news release are
not guarantees of future performance and should not be unduly relied upon. Such
information and statements, including the assumptions made in respect thereof,
involve known and unknown risks, uncertainties and other factors that may cause
actual results or events to defer materially from those anticipated in such
forward-looking information or statements including, without limitation: changes
in commodity prices; changes in the demand for or supply of Crew's products;
unanticipated operating results or production declines; changes in tax or
environmental laws, royalty rates or other regulatory matters; changes in
development plans of Crew or by third party operators of Crew's properties,
increased debt levels or debt service requirements; inaccurate estimation of
Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack
of access to capital markets; increased costs; a lack of adequate insurance
coverage; the impact of competitors; and certain other risks detailed from
time-to-time in Crew's public disclosure documents (including, without
limitation, those risks identified in this news release and Crew's Annual
Information Form).
The forward-looking information and statements contained in this news release
speak only as of the date of this news release, and Crew does not assume any
obligation to publicly update or revise any of the included forward-looking
statements or information, whether as a result of new information, future events
or otherwise, except as may be required by applicable securities laws.
BOE equivalent
Barrel of oil equivalents or BOEs may be misleading, particularly if used in
isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy
equivalency conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead.
Crew is an oil and gas exploration and production company whose shares are
traded on The Toronto Stock Exchange under the trading symbol "CR".
Financial statements for the three and six month periods ended June 30, 2010 and
2009 are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
2010 2009
----------------------------------------------------------------------------
Assets
Current Assets:
Accounts receivable $ 29,634 $ 37,574
Fair value of financial instruments (note 7) 9,698 -
Future income taxes - 542
----------------------------------------------------------------------------
39,332 38,116
Property, plant and equipment (note 2) 859,248 925,132
----------------------------------------------------------------------------
$ 898,580 $ 963,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable and accrued liabilities $ 64,520 $ 84,228
Fair value of financial instruments (note 7) - 834
Future income taxes 2,306 -
Current portion of other long-term obligations
(note 4) 619 1,313
----------------------------------------------------------------------------
67,445 86,375
Bank loan (note 3) 71,845 135,601
Other long-term obligations (note 4) - 132
Asset retirement obligations (note 5) 33,582 35,341
Future income taxes 99,341 101,519
Shareholders' Equity
Share capital (note 6) 642,208 617,605
Contributed surplus (note 6 (c)) 20,502 22,769
Deficit (36,343) (36,094)
----------------------------------------------------------------------------
626,367 604,280
Commitments (note 10)
----------------------------------------------------------------------------
$ 898,580 $ 963,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Operations, Comprehensive Loss and Retained
Earnings (Deficit)
(unaudited)
(thousands, except per share amounts)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas
sales $ 43,027 $ 39,331 $ 104,799 $ 85,673
Royalties (8,419) (5,512) (21,568) (16,192)
Realized gain on financial
instruments (note 7) 3,756 5,643 4,684 6,196
Unrealized gain (loss) on
financial instruments (note 7) 2,334 (3,816) 10,532 1,054
----------------------------------------------------------------------------
40,698 35,646 98,447 76,731
Expenses
Operating 12,663 14,448 27,649 28,258
Transportation (note 4) 2,143 2,397 4,520 5,265
General and administrative 1,640 1,415 3,310 2,943
Interest 1,225 1,166 3,182 2,654
Stock-based compensation
(note 6(d)) 1,070 831 2,390 1,710
Depletion, depreciation and
accretion 25,647 32,823 57,767 67,794
----------------------------------------------------------------------------
44,388 53,080 98,818 108,624
----------------------------------------------------------------------------
Loss before income taxes (3,690) (17,434) (371) (31,893)
Future income tax reduction (999) (5,167) (122) (10,608)
----------------------------------------------------------------------------
Loss and comprehensive loss (2,691) (12,267) (249) (21,285)
Retained earnings (deficit),
beginning of period (33,652) (7,297) (36,094) 1,721
----------------------------------------------------------------------------
Deficit, end of period $ (36,343) $ (19,564) $ (36,343) $ (19,564)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Loss per share (note 6(e))
Basic $ (0.03) $ (0.17) $ (0.00) $ (0.29)
Diluted $ (0.03) $ (0.17) $ (0.00) $ (0.29)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Cash Flows
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Loss $ (2,691) $ (12,267) $ (249) $ (21,285)
Items not involving cash:
Depletion, depreciation and
accretion 25,647 32,823 57,767 67,794
Stock-based compensation 1,070 831 2,390 1,710
Future income tax reduction (999) (5,167) (122) (10,608)
Unrealized (gain) loss on
financial instruments (2,334) 3,816 (10,532) (1,054)
Transportation liability
charge (note 4) (154) (329) (826) (657)
Asset retirement
expenditures (129) (181) (705) (282)
Change in non-cash working
capital (note 9) 3,739 1,991 8,639 5,405
----------------------------------------------------------------------------
24,149 21,517 56,362 41,023
Financing activities:
Decrease in bank loan (81,756) (64,762) (63,756) (48,700)
Issue of common shares 6,356 43,400 17,593 43,400
Share issue costs (48) (2,439) (48) (2,439)
----------------------------------------------------------------------------
(75,448) (23,801) (46,211) (7,739)
Investing activities:
Exploration and development (63,309) (14,187) (122,384) (37,865)
Property dispositions 121,724 23,688 132,640 34,378
Change in non-cash working
capital (note 9) (7,116) (7,217) (20,407) (29,797)
----------------------------------------------------------------------------
51,299 2,284 (10,151) (33,284)
----------------------------------------------------------------------------
Change in cash and cash
equivalents - - - -
Cash and cash equivalents,
beginning of period - - - -
----------------------------------------------------------------------------
Cash and cash equivalents,
end of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Notes to Consolidated Financial Statements
For the three and six months ended June 30, 2010 and 2009
(Unaudited)
(Tabular amounts in thousands)
CREW ENERGY INC.
Notes to Consolidated Financial Statements
For the three and six months ended June 30, 2010 and 2009
(Unaudited)
(Tabular amounts in thousands)
1. Significant accounting policies:
The interim consolidated financial statements of Crew Energy Inc. ("Crew" or the
"Company") have been prepared by management in accordance with accounting
principles generally accepted in Canada. The interim consolidated financial
statements have been prepared following the same accounting policies and methods
of computation as the consolidated financial statements for the year ended
December 31, 2009. The disclosure which follows is incremental to the disclosure
included with the December 31, 2009 consolidated financial statements. These
interim consolidated financial statements should be read in conjunction with the
audited consolidated financial statements and notes thereto for the year ended
December 31, 2009.
Certain comparative amounts have been reclassified to conform to current period
presentation.
2. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and Net book
June 30, 2010 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $ 1,292,920 $ 433,672 $ 859,248
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and Net book
December 31, 2009 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $ 1,302,399 $ 377,267 $ 925,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The cost of unproved properties at June 30, 2010 of $177,193,000 (2009 -
$163,820,000) was excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $150,055,000 (2009 - $106,968,000) have been included in the
depletion calculation and estimated salvage values of $33,323,000 (2009 -
$38,246,000) have been excluded from the depletion calculation.
During the quarter, the Company closed the disposition of oil and gas assets in
the Edson, Alberta area for gross proceeds of $126 million, before closing
adjustments.
The following directly attributable general and administrative and stock-based
compensation expenses related to exploration and development activities were
capitalized.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months Year ended
ended December 31,
June 30, 2010 2009
----------------------------------------------------------------------------
General and administrative expense $ 3,310 $ 5,736
Stock-based compensation expense, including
future income taxes 3,193 4,442
----------------------------------------------------------------------------
$ 6,503 $ 10,178
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. Bank loan:
The Company's bank facility consists of a revolving line of credit of $190
million and an operating line of credit of $20 million (the "Facility"). The
Facility revolves for a 364 day period and will be subject to its next 364 day
extension by June 13, 2011. If not extended, the Facility will cease to revolve,
the margins thereunder will increase by 0.50 percent and all outstanding
advances thereunder will become repayable in one year. The available lending
limits of the Facility are reviewed semi-annually and are based on the bank
syndicate's interpretation of the Company's reserves and future commodity
prices. There can be no assurance that the amount of the available Facility will
not be adjusted at the next scheduled borrowing base review on or before October
31, 2010.
Advances under the Facility are available by way of prime rate loans with
interest rates of between 1.25 percent and 2.75 percent over the bank's prime
lending rate and bankers' acceptances and LIBOR loans, which are subject to
stamping fees and margins ranging from 2.25 percent to 3.75 percent depending
upon the debt to EBITDA ratio of the Company calculated at the Company's
previous quarter end. Standby fees are charged on the undrawn facility at rates
ranging from 0.56 percent to 0.94 percent depending upon the same debt to EBITDA
ratio.
As at June 30, 2010, the Company's applicable pricing included a 2.50 percent
margin on prime lending and a 3.50 percent stamping fee and margin on bankers'
acceptances and LIBOR loans along with a 0.875 percent per annum standby fee on
the portion of the Facility that is not drawn. Borrowing margins and fees are
reviewed annually as part of the bank syndicate's annual renewal. At June 30,
2010, the Company had issued letters of credit totaling $3.6 million. The
effective interest rate on the Company's borrowings under its bank Facility for
the three months ended June 30, 2010 was 9.7% (2009 - 2.4%).
4. Other long-term obligations:
As part of the May, 2007 private company acquisition, the Company acquired
several firm transportation agreements. These agreements had a fair value at the
time of the acquisition of a $4.9 million liability. This amount was accounted
for as part of the acquisition cost and will be charged as a reduction to
transportation expenses over the life of the contracts as they are incurred. The
charge for the three and six months ended June 30, 2010 was $0.2 million and
$0.5 million, respectively (2009 - $0.3 million and $0.7 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.
5. Asset retirement obligations:
Total future asset retirement obligations were determined by management and were
based on Crew's net ownership interest, the estimated future costs to reclaim
and abandon the wells and facilities and the estimated timing of when the costs
will be incurred. Crew estimated the net present value of its total asset
retirement obligation as at June 30, 2010 to be $33,582,000 (December 31, 2009 -
$35,341,000) based on a total future liability of $60,094,000 (December 31, 2009
- $64,030,000). These payments are expected to be made over the next 30 years.
An 8% to 10% (2009 - 8% to 10%) credit adjusted risk free discount rate and 2%
(2009 - 2%) inflation rate were used to calculate the present value of the asset
retirement obligation.
The following table reconciles Crew's asset retirement obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months ended Year ended
June 30, 2010 December 31, 2009
----------------------------------------------------------------------------
Carrying amount, beginning of period $ 35,341 $ 34,941
Liabilities incurred 424 385
Liabilities disposed (2,840) (2,161)
Accretion expense 1,362 2,765
Liabilities settled (705) (589)
----------------------------------------------------------------------------
Carrying amount, end of period $ 33,582 $ 35,341
----------------------------------------------------------------------------
----------------------------------------------------------------------------
6. Share capital:
(a) Authorized:
Unlimited number of Common Shares
(b) Common Shares issued:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
shares Amount
----------------------------------------------------------------------------
Common shares, December 31, 2009 78,152 $ 617,605
Exercise of stock options 1,944 17,593
Stock-based compensation - 7,046
Share issue costs, net of income taxes of $12 - (36)
----------------------------------------------------------------------------
Common shares, June 30, 2010 80,096 $ 642,208
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(c) Contributed Surplus:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Contributed surplus, December 31, 2009 $ 22,769
Exercise of options (7,046)
Stock-based compensation 4,779
----------------------------------------------------------------------------
Contributed surplus, June 30, 2010 $ 20,502
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(d) Stock-based compensation:
The Company measures compensation costs associated with stock-based compensation
using the fair market value method under which the cost is recognized over the
vesting period of the underlying security. The fair value of each stock option
is determined at each grant date using the Black-Scholes model with the
following weighted average assumptions used for options granted during the three
month period ended June 30, 2010: risk free interest rate 2.46% (2009 - 1.55%),
expected life 4 years (2009 - 4 years), volatility 61% (2009 - 52%), and an
expected dividend of nil (2009 - nil). The Company has not incorporated an
estimated forfeiture rate for stock options that will not vest rather the
Company accounts for actual forfeitures as they occur.
During the first six months of 2010, the Company recorded $4,779,000, (2009 -
$3,421,000) of stock-based compensation expense related to the stock options, of
which $2,389,000 (2009 - $1,711,000) 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
$804,000 (2009 - $579,000) associated with the current year's capitalized
stock-based compensation has been recorded.
The average fair value of the stock options granted during the six months ended
June 30, 2010, as calculated by the Black-Scholes method, was $8.09 per option
(2009 - $2.03).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Number of Price average
Options Range exercise price
----------------------------------------------------------------------------
Balance December 31, 2009 5,751 $ 2.78 to $18.70 $ 8.33
Granted 2,165 $ 13.36 to $18.36 $ 15.13
Exercised (1,944) $ 2.78 to $16.60 $ 9.05
Forfeited (294) $ 2.78 to $14.68 $ 7.75
----------------------------------------------------------------------------
Balance June 30, 2010 5,678 $ 3.43 to $18.70 $ 10.70
Exercisable 1,657 $ 3.43 to $18.70 $ 8.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(e) Per share amounts:
Per share amounts have been calculated on the weighted average number of shares
outstanding. The weighted average shares outstanding for the three month period
ended June 30, 2010 was 79,888,000 (June 30, 2009 - 73,622,000) and for the six
month period ended June 30, 2010 the weighted average number of shares
outstanding was 79,272,000 (June 30, 2009 - 72,360,000).
In computing diluted per share amounts for the three month period ended June 30,
2010, no shares (June 30, 2009 - nil) were added to the weighted average number
of Common Shares outstanding for the dilution added by the stock options and for
the six month period ended June 30, 2010, no shares (June 30, 2009 - nil) were
added to the weighted average number of common shares for the dilution. There
were 5,678,000 (June 30, 2009 - 5,780,000) stock options that were not included
in the diluted earnings per share calculation because they were anti-dilutive.
7. Financial Instruments:
Overview
The Company has exposure to credit, liquidity and market risks from its use of
financial instruments. This note provides information about the Company's
exposure to each of these risks, the Company's objectives, policies and
processes for measuring and managing risk. Further quantitative disclosures are
included throughout these financial statements.
The Board of Directors has overall responsibility for the establishment and
oversight of the Company's risk management framework. The Board has implemented
and monitors compliance with risk management policies. The Company's risk
management policies are established to identify and analyze the risks faced by
the Company, to set appropriate risk limits and controls, and to monitor risks
and adherence to market conditions and the Company's activities.
(a) Credit risk:
Credit risk is the risk of financial loss to the Company if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Company's receivables from
petroleum and natural gas marketers and joint venture partners and the fair
value of derivative instruments.
The carrying amount of accounts receivable and derivative assets, when
outstanding, represents the maximum credit exposure. As at June 30, 2010 the
Company's receivables consisted of $15.8 (2009 - $17.2) million of receivables
from petroleum and natural gas marketers which has subsequently been collected,
$8.1 (2009 - $9.2) million from joint venture partners of which $0.5 million has
been subsequently collected, and $5.7 (2009 - $11.2) million of Crown deposits,
prepaids and other accounts receivable. The Company does not consider any
receivables to be past due.
(b) Liquidity risk:
Accounts payable and financial instruments have contractual maturities of less
than one year. The Company maintains a revolving credit facility, as outlined in
note 3, that is subject to renewal annually by the lenders and has a contractual
maturity in 2012. The Company also maintains and monitors a certain level of
cash flow which is used to partially finance all operating and capital
expenditures as the Company does not pay dividends.
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity
prices, interest rates, and foreign exchange rates will affect the Company's net
income or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
limits, while maximizing the Company's returns.
The Company utilizes both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with the Company's risk management policy that has been approved by
the Board of Directors.
(i) Commodity price risk
The Company has attempted to mitigate a portion of the commodity price risk
through the use of various financial derivative and physical delivery sales
contracts as outlined below. The Company's Board of Directors approved policy is
to enter into commodity price contracts when considered appropriate to a maximum
of 50% of forecasted production volumes for a period of not more than two years.
Derivatives are recorded on the balance sheet at fair value at each reporting
period with the change in fair value being recognized as an unrealized gain or
loss on the consolidated statement of operations.
(ii) Foreign currency exchange rate risk
The Company has attempted to mitigate a portion of its foreign exchange
fluctuation risk through the use of financial derivatives as outlined below.
(iii) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result
of changes in market interest rates. The Company is exposed to interest rate
fluctuations on its bank loan which bears a floating rate of interest. For the
three and six months ended June 30, 2010, a 1.0 percent change to the effective
interest rate would have a $0.1 million and $0.3 million impact on net income
(2009 - $0.4 and $0.9 million).
The Company has attempted to mitigate the impact of future fluctuations in
interest rates on its outstanding debt by entering into contracts fixing the
base interest rate on $150 million of banker's acceptance borrowings as outlined
below. These rates are, under the Company's bank Facility, subject to an
additional stamping fee of 3.50 percent as of June 30, 2010.
The Company's derivative contracts in place as of June 30, 2010 are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
Natural 2,500 November 1, 2009 - AECO C
Gas gj/day December 31, 2010 Monthly $6.00 Swap 894
Index
Natural 5,000 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly
Index less
$0.09 $8.00 Call (5)
Natural 10,000 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly
Index $7.75 Call (12)
Natural 2,500 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly
Index $6.20 Swap 986
Natural 5,000 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly
Index $6.08 Swap 2,217
Natural 2,500 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly
Index $5.25 Swap 550
Natural 2,500 January 1, 2010 - AECO C
Gas gj/day December 31, 2010 Monthly
Index $5.55 Swap 688
Natural 2,500 April 1, 2010 - AECO C
Gas gj/day October 31, 2010 Monthly
Index $5.30 Swap 471
Natural 5,000 January 1, 2010 - AECO/NYMEX
Gas mmbtu/ December 31, 2010 Basis diff US$(0.55) Swap 250
day
Oil 250 bbl January 1, 2010 -
/day December 31, 2010 CDN$ WTI $78.50 Swap (159)
Oil 500 bbl January 1, 2010 - $72.00 -
/day December 31, 2010 CDN$ WTI $88.00 Collar (75)
Oil 250 bbl January 1, 2010 -
/day December 31, 2010 CDN$ WTI $82.50 Swap 25
Oil 500 bbl January 1, 2010 -
/day December 31, 2010 CDN$ WTI $80.50 Swap (117)
Oil 500 bbl January 1, 2010 -
/day December 31, 2010 US$ WTI US$81.00 Swap 387
Oil 250 bbl January 1, 2010 - $80.00 -
/day December 31, 2010 CDN$ WTI $95.02 Collar 136
Oil 250 bbl March 1, 2010 -
/day December 31, 2010 CDN$ WTI $84.00 Swap 136
Oil 250 bbl July 1, 2010 -
/day December 31, 2010 CDN$ WTI $88.10 Swap 281
Oil 250 bbl July 1, 2010 -
/day December 31, 2010 CDN$ WTI $91.50 Swap 438
Oil 250 bbl January 1, 2011 -
/day December 31, 2011 CDN$ WTI $86.00 Swap 79
Oil 250 bbl January 1, 2011 - $82.00 -
/day December 31, 2011 CDN$ WTI $94.62 Collar 216
Oil 500 bbl January 1, 2011 -
/day December 31, 2011 CDN$ WTI $90.20 Swap 914
Oil 250 bbl January 1, 2011 - $80.00 -
/day December 31, 2011 CDN$ WTI $95.45 Collar 167
Oil 250 bbl January 1, 2011 -
/day December 31, 2011 CDN$ WTI $90.00 Swap 441
Oil 250 bbl January 1, 2011 - $85.00 -
/day December 31, 2011 CDN$ WTI $100.50 Collar 533
----------------------------------------------------------------------------
Total commodity contracts 9,441
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
USD / CAD US $2M / January 1, 2010 -
$ exchange Month December 31, 2010 CAD/USD 1.094 Swap 342
----------------------------------------------------------------------------
Total foreign exchange contracts 342
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject Fair
of Notional Strike Option Value
Contract Quantity Term Reference Price Traded ($000s)
----------------------------------------------------------------------------
BA Rate $50M/ February 10, 2009 -
year February 10, 2011 BA - CDOR 1.10% Swap (58)
BA Rate $50M/ February 12, 2009 -
year February 12, 2011 BA - CDOR 1.10% Swap (39)
BA Rate $50M/ May 28, 2009 -
year May 28, 2011 BA - CDOR 1.12% Swap 12
----------------------------------------------------------------------------
Total interest rate contracts (85)
----------------------------------------------------------------------------
Total financial instruments 9,698
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subsequent to June 30, 2010, the Company unwound the $50 million per year 1.12%
swap maturing on May 28, 2011 for net proceeds to the Company of $12,000.
As at June 30, 2010, a $0.10 change to the price per thousand cubic feet of
natural gas on the contracts outlined above would have a $0.5 million impact on
net income.
As at June 30, 2010, a $1.00 per barrel change to the price on the oil contract
outlined above would have a $0.9 million impact on net income.
As at June 30, 2010, a $0.01 change to the exchange rate on the foreign exchange
contracts would have a $0.1 million impact on net income.
As at June 30, 2010, a 0.1% change to the interest rate on the interest rate
contracts would have a $0.1 million impact on net income.
Subsequent to June 30, 2010, the Company entered into the following financial
derivative contract:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Subject
of Notional Strike Option
Contract Quantity Term Reference Price Traded
----------------------------------------------------------------------------
Oil 250 bbl/day January 1, 2011 -
December 31, 2011 CDN$ WTI $88.50 Swap
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Fair value of financial instruments
The Company's financial instruments as at June 30, 2010 and 2009 include
accounts receivable, derivative contracts, accounts payable and accrued
liabilities, and bank debt. The fair value of accounts receivable and accounts
payable and accrued liabilities approximate their carrying amounts due to their
short-terms to maturity.
The fair value of derivative contracts is determined by discounting the
difference between the contracted price and published forward price curves as at
the balance sheet date, using the remaining contracted notional volumes.
Bank debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.
8. Capital management:
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. Crew's primary capital management objective is
to maintain a strong balance sheet in order to continue to fund the future
growth of the Company. Crew monitors its capital structure and makes
adjustments on an on-going basis in order to maintain the flexibility needed to
achieve the Company's long-term objectives. To manage the capital structure the
Company may adjust capital spending, hedge future revenue and some costs, issue
new equity, issue new debt or repay existing debt through asset sales.
The Company monitors debt levels based on the ratio of net debt to annualized
funds from operations. The ratio represents the time period it would take to pay
off the debt if no further capital expenditures were incurred and if funds from
operations remained constant. This ratio is calculated as net debt, defined as
outstanding bank debt and net working capital, divided by annualized funds from
operations for the most recent quarter.
The Company monitors this ratio and endeavours to maintain it at or below 2.0 to
1.0 in a normalized commodity price environment. This ratio may increase at
certain times as a result of acquisitions or low commodity prices. As shown
below, as at June 30, 2010, the Company's ratio of net debt to annualized funds
from operations was 1.29 to 1 (December 31, 2009 - 1.67 to 1).
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June 30, December 31,
2010 2009
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Net debt:
Accounts receivable $ 29,634 $ 37,574
Accounts payable and accrued liabilities (64,520) (84,228)
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Working capital deficiency $ (34,886) $ (46,654)
Bank loan (71,845) (135,601)
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Net debt $ (106,731) $ (182,255)
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Annualized funds from operations:
Cash provided by operating activities $ 24,149 $ 16,734
Asset retirement expenditures 129 111
Transportation liability charge 154 329
Change in non-cash working capital (3,739) 10,082
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Funds from operations 20,693 27,256
Annualized $ 82,772 $ 109,024
Net debt to annualized funds from operations 1.29 1.67
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The Company has commodity, interest rate and foreign exchange hedging for 2010
and 2011 to provide support for its funds from operations and assist in funding
its capital expenditure program.
There has been no change in the Company's approach to capital management during
the period ended June 30, 2010.
9. Supplemental cash flow information:
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----------------------------------------------------------------------------
Three months Three months Six months Six months
ended ended ended ended
June 30, June 30, June 30, June 30,
2010 2009 2010 2009
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Changes in non-cash
working capital:
Accounts receivable $ 10,134 $ 3,335 $ 7,940 $ 14,282
Accounts payable and
accrued liabilities (13,511) (8,561) (19,708) (38,674)
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$ (3,377) $ (5,226) $ (11,768) $ (24,392)
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Operating activities $ 3,739 $ 1,991 $ 8,639 $ 5,405
Investing activities (7,116) (7,217) (20,407) (29,797)
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$ (3,377) $ (5,226) $ (11,768) $ (24,392)
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The Company made the following cash outlays in respect of interest expense:
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Three months Three months Six months Six months
ended ended ended ended
June 30, 2010 June 30, 2009 June 30, 2010 June 30, 2009
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Interest $ 1,472 $ 2,457 $ 2,562 $ 4,188
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10. Commitments:
The Company has the following fixed term commitments related to its on-going
business:
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Total 2010 2011 2012 2013 2014 Thereafter
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Operating
Leases $ 3,930 $ 872 $ 1,743 $ 1,315 - - -
Capital
commitments 8,000 4,000 4,000 - - - -
Transportation
agreements 4,918 1,853 3,065 - - - -
Processing
agreement 28,967 1,525 3,049 3,049 3,049 3,049 15,246
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Total $ 45,815 $8,250 $ 11,857 $ 4,364 $ 3,049 $ 3,049 $ 15,246
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The firm transportation commitments were acquired as part of the Company's May
2007 private company acquisition and represent firm service commitments for
transportation and processing of natural gas in British Columbia. In 2010, the
Company permanently assigned approximately $6.2 million of its firm commitments
to third parties. The amount shown represents the remaining contractual
obligations.
During 2009, Crew entered into an agreement to process natural gas through a
third party owned gas processing facility in the Septimus area of northeast
British Columbia. Under the terms of the agreement, Crew has committed to
process a minimum monthly volume of gas through the facility commencing on
December 1, 2009 and continuing through November 30, 2019. The commitment is
included in the above table.
The agreement additionally provides Crew the option to participate in an
expansion of the facility at a cost of 50% of the total expanded facility
construction costs and subsequently become a 50% owner in the facility. If the
facility is not expanded prior to January 1, 2013, the current owner of the
facility can require Crew to purchase the existing facility for the total
construction costs of $19.1 million plus $0.7 million or alter the fees
associated with Crew's commitment in order to recover the amount of Crew's full
commitment prior to January 1, 2016.
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