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, 2008.
Highlights
- Second quarter production of 9,445 boe per day yielded record funds from
operations of $34.1 million, a 63% increase over the second quarter of 2007 and
funds from operations per share was up 30% to $0.60 per share;
- Maintained a strong balance sheet reducing net debt by $13.4 million from the
end of the first quarter of 2008 to $125 million on a current bank facility of
$210 million;
- Continued an aggressive land acquisition strategy on key resource plays in
northeast British Columbia as well as initiating drilling operations on the
Company's Septimus, British Columbia property;
- Completed a $66.75 million bought deal equity financing on May 1, 2008;
- On May 12, 2008, closed the acquisition of 102 net sections of Montney
formation mineral rights in the Company's core area in northeast British
Columbia for $63.1 million;
- On June 23, 2008, announced an arrangement agreement to acquire all of the
issued and outstanding shares of Gentry Resources Ltd.
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Three Three Six Six
months months months months
Financial ended ended ended ended
($ thousands, except per share June 30, June 30, June 30, June 30,
amounts) 2008 2007 2008 2007
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Petroleum and natural gas sales 60,316 38,703 111,705 68,134
Funds from operations (note 1) 34,102 20,885 63,140 37,872
Per share - basic 0.60 0.46 1.14 0.87
- diluted 0.58 0.46 1.12 0.87
Net income 5,415 1,351 6,356 2,670
Per share - basic 0.09 0.03 0.11 0.06
- diluted 0.09 0.03 0.11 0.06
Exploration and development
expenditures 22,564 11,355 71,666 45,674
Property acquisitions (net of
dispositions) 63,110 (59) 71,756 2
Business acquisition - 137,456 - 137,456
Total capital investment 85,674 148,752 143,422 183,132
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Capital Structure As at As at
June 30, Dec. 31,
($ thousands) 2008 2007
----------------------------------------------------------------------------
Working capital deficiency (note 2) 5,652 14,643
Bank loan 119,348 95,028
Net debt 125,000 109,671
Bank facility 210,000 180,000
Common Shares Outstanding
(thousands) 58,910 53,577
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Notes:
(1) Funds from operations is calculated as cash provided by operating
activities, adding the change in non-cash working capital, asset
retirement expenditures and the transportation liability charge. Funds
from operations is used to analyze the Company's operating performance
and leverage. Funds from operations does not have a standardized measure
prescribed by Canadian Generally Accepted Accounting Principles and
therefore may not be comparable with the calculations of similar
measures for other companies.
(2) Working capital deficiency includes only accounts receivable less
accounts payable and accrued liabilities.
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
Operations 2008 2007 2008 2007
----------------------------------------------------------------------------
Daily production
Light oil and ngl (bbl/d) 1,845 1,446 1,921 1,457
Natural gas (mcf/d) 45,599 45,128 48,653 38,803
Oil equivalent (boe/d @ 6:1) 9,445 8,967 10,030 7,924
Average prices (note 1)
Light oil and ngl ($/bbl) 90.01 58.96 79.98 55.40
Natural gas ($/mcf) 10.60 7.54 9.32 7.62
Oil equivalent ($/boe) 70.18 47.43 61.19 47.51
Operating expenses
Light oil and ngl ($/bbl) 7.59 6.29 6.89 5.93
Natural gas ($/mcf) 1.27 1.02 1.22 1.03
Oil equivalent ($/boe @ 6:1) 7.60 6.16 7.23 6.11
Netbacks
Operating netback ($/boe) (note 2) 45.05 29.12 38.75 29.39
Realized loss on financial
instruments 2.61 0.09 1.28 0.05
G&A ($/boe) 1.14 1.09 1.11 1.08
Interest and other ($/boe) 1.61 2.35 1.78 1.85
Funds from operations ($/boe) 39.69 25.59 34.58 26.41
Drilling Activity
Gross wells 7 1 19 11
Working interest wells 7.0 1 16.8 10.5
Success rate, net wells 86% 100% 94% 100%
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Notes:
(1) Average prices are before deduction of transportation costs.
(2) Operating netback equals petroleum and natural gas sales less royalties,
operating costs and transportation costs calculated on a boe basis.
Operating netback and funds from operations netback do not have a
standardized measure prescribed by Canadian Generally Accepted
Accounting Principles and therefore may not be comparable with the
calculations of similar measures for other companies.
OVERVIEW
The second quarter of 2008 was highlighted by record funds from operations of
$34.1 million and funds from operations per share of $0.60. Crew's production of
9,445 boe per day was reduced by wet weather, a number of facilities, including
the McMahon gas plant, experiencing scheduled and unscheduled downtime and a
higher decline rate from the Company's (42.5% WI) Hanlan gas well. The Company
drilled seven (7.0 net) wells with an 86% success rate. Crew closed the
acquisition of 102 net sections of Montney rights in northeast British Columbia
and completed a $66.75 million bought deal equity financing to fund the
acquisition. On June 23, 2008, Crew and Gentry Resources Ltd. ("Gentry") jointly
announced an arrangement agreement whereby Crew would acquire all of the issued
and outstanding shares of Gentry. Closing of the arrangement agreement is
anticipated in late August and is expected to add approximately 12.5 million boe
of proved and probable reserves.
OPERATIONAL UPDATE
ALBERTA
Edson
Crew did not drill any wells at Edson in the second quarter due to wet surface
conditions. Crew plans to drill a minimum of two horizontal wells at Edson
during the remainder of the year, one of which has been drilled in the third
quarter and awaits completion and the second is currently drilling. These wells
at Edson are Crew's first to be completed using multiple fracture stimulations
and if successful could lead to broad application on Crew's 27 sections of land
which are all in close proximity to Company owned infrastructure. Crew was
recently informed that the Suncor operated gas facility in which Crew owns a 15%
working interest will undergo a 14 day turnaround in September. Crew currently
has approximately 1,700 boe per day of production processed through this
facility. The Company is working on re-routing approximately 1,400 boe per day
of production through a third party facility during this turnaround to minimize
the impact on Crew's third quarter production.
Pine Creek
Crew did not drill any wells in the second quarter at Pine Creek. Like Edson,
Pine Creek was subject to wet ground conditions which prevented the Company from
conducting field operations. Crew is currently completing one well and is
drilling its first long reach horizontal well in the area. The Company is well
positioned to add production in this area with the first quarter expansion of
its 100% owned gas facility to 15 mmcf per day of capacity. The Company has
discovered an eight kilometer long gas charged channel over its lands which it
plans on developing in 2009. Crew has also discovered an oil pool in the first
quarter. The discovery well is currently producing approximately 90 boe per day
after five months of production. Based on pressure data and three-dimensional
seismic mapping, the pool could be approximately 960 acres in size, resulting in
up to 12 drilling locations on 80 acre spacing. The Company plans to drill one
to two wells on this play before year end.
Viking-Kinsella
Crew drilled two net gas wells and one dry and abandoned well in this area in
the second quarter. The two gas wells are currently producing approximately 2.1
mmcf per day. Crew is currently tying in solution gas from its first quarter oil
discoveries which is expected to increase production by 40 to 50 boe per day and
allow for future wells to produce without restrictions. The Company has
constructed an oil battery and expects to drill five to six horizontal
development wells by year end with anticipated production rates of 60 to 100 boe
per well.
Hanlan
Crew's (WI - 42.5%) fourth quarter 2007 gas discovery has declined to 1.5 to 3
mmcf per day with reservoir flow characteristics exhibiting a high permeability
zone in close proximity to the well bore and low permeability at greater
distances from the well bore. Crew's initial 14-35 discovery continues to
produce at approximately 6 mmcf per day and has cumulative production of 4.2 bcf
since it started production in January 2007. Crew has two further recompletion
opportunities in the area with interests of 42.5% and 50%, one of which is
expected to be recompleted in the fourth quarter of 2008.
Carrot Creek
This is a full cycle exploration area that the Company has taken from an
exploration concept to a new core area with a 34 section land position in one
year. Current production is estimated to be 500 boe per day from four (4.0 net)
wells. Based on drilling success Crew has an inventory in excess of 21 drilling
locations identified on this liquids rich natural gas play. In the first quarter
of 2008, Crew purchased a 100% interest in a 5.5 mmcf per day gas plant,
associated pipeline infrastructure and approximately 100 boe per day of
production. The acquisition of this facility is expected to reduce area
operating costs to approximately $4.00 per boe. Crew drilled two wells in the
second quarter. The first has production tested at approximately 110 boe per day
and the second is currently being completed. Crew plans on drilling two to three
additional wells in 2008 at Carrot Creek.
BRITISH COLUMBIA
Inga
Crew (WI - 100%) drilled a horizontal well at Inga in the first quarter. The
tie-in of this well was delayed by wet weather and regulatory approvals and is
expected to be on production by the end of August at three to four mmcf per day.
As a result of this success, Crew has identified eight drilling locations in the
area, three of which are expected to be drilled in the third quarter with the
first currently drilling. The Company's goal is to have seven to eight mmcf per
day producing from this area through Crew owned facilities by year end.
Yoyo
Crew has six drilling locations identified in this area. The Company (WI - 75%)
has recently drilled a horizontal gas well that tested at a rate of 2.5 to 3.5
mmcf per day. The well is close to Company owned infrastructure and is expected
to be tied in early in the fourth quarter.
EXPLORATION
Strachan, Alberta
At Strachan, Alberta Crew (WI - 15% bpo, 46.5% apo) plans to drill a 3,700 meter
Leduc prospect. After a lengthy delay, this well is scheduled to be drilled in
the first quarter of 2009 and is currently awaiting licensing which is expected
shortly as all surface and regulatory issues have been resolved. Successful
wells in the area have produced ten to several hundred bcf of gas with high
daily production rates. Crew has also purchased land on another Leduc reef
prospect and is in the process of obtaining a drilling license.
West Brazeau, Alberta
Crew (WI - 37.5% to 100%) is targeting thrusted Belly River sandstone reservoirs
on 34 sections of land the Company has accumulated at West Brazeau. Crew (WI -
37.5%) has drilled its first well on this prospect that is now on production at
2.4 to 3.3 mmcf per day. Crew has identified up to 14 net drilling locations on
this play and expects to drill up to five wells in 2008.
Colt, British Columbia
Crew (WI - 100%) has assembled by way of Crown land acquisitions a five section
block of land over a large foothills structure. This 3D seismically defined
feature has been interpreted to have 125 to 200 meters of structural closure
over an area encompassing 2,200 acres. An offsetting well on a similar structure
is currently producing 21 to 25 mmcf per day. Crew has identified three
locations on this play with conventional natural gas resource potential of over
120 bcf mapped with the primary target being the Mississippian Debolt formation.
EMERGING RESOURCE PLAYS
Triassic Montney Play
As a result of its extensive land holdings controlling 158 sections of land,
Crew has had an active second and third quarter program. The results to date
included:
1) The first horizontal well which was drilled to an 867 meter horizontal length
and subsequently completed. This well is currently testing into a sales pipeline
at initial rates of 600 mcf per day and has since been producing at 600 to 850
mcf per day. This well continues to cleanup with over 1,200 bbls of completion
fluid left to recover.
2) The second horizontal well at Septimus has been cased to a horizontal length
of 1,250 meters and is waiting on the commencement of completion operations.
3) The third horizontal well is currently drilling.
4) Crew, as operator, has drilled or tested three other Montney wells. These
wells are in areas where there are additional land acquisition opportunities and
the Company is expected to be in a position to discuss the results of some of
these operations later in 2008.
The upper Montney in the wells drilled to date has a thickness of 145 to 770
feet while the lower Montney has encountered a thickness of 330 to 630 feet.
Crew will continue to evaluate its Montney land holdings with up to 16 wells and
a large 30 square-mile three-dimensional seismic program planned through spring
breakup 2009.
Horn River Basin/Cordova Embayment
Muskwa Devonian Shale Gas Play
Crew has 16 net sections of land on this shale gas play. The Muskwa Shale is
approximately 500 feet thick and has gained a significant amount of attention
since announcements by industry participants of their successful drilling and
testing of the Muskwa Shale in the Horn River Basin. It was noted in one of
those announcements that they attribute a resource of 265 to 318 bcf of natural
gas per section on their lands in a specific geographic area. Their resource
estimates were based on well test and petrophysical data derived from a drilling
program targeting the Devonian aged Muskwa Shales in the area. A recent
announcement by an industry participant of production rates of five to eight
mmcf per day from three horizontal wells, two of which directly offset Crew's
lands, lends further support for the prospectivity of Crew's land base. Vertical
wells in area have tested at rates of 0.75 to 2.5 mmcf per day. This play is in
its infancy but does appear to be prospective over a large area in a relatively
homogeneous geologic environment.
OUTLOOK
Business Environment
Natural gas prices were very strong in the second quarter of 2008 and have since
declined over 30%. Natural gas prices currently trade at levels much higher than
the same period of 2007 with longer term fundamentals remaining strong. North
American LNG imports have declined from 2007 levels as strong growth in
continental United States gas well drilling and production have created an
environment where LNG shipments have been directed to higher priced markets in
Europe and Asia. Our view remains that natural gas will continue to have an
increasingly important role in supplying North American energy needs as
industrial demand grows, the world concentrates on cleaner burning energy
sources and the continuing globalization of the commodity. These factors
combined with the ever increasing proportion of natural gas produced from tight
gas reservoirs which are generally characterized by very high initial decline
rates suggest our industry should be busy for the foreseeable future.
In our first quarter report, we highlighted the industry rush into resource
style plays and the impending scarcity of available acreage. This was recently
supported by British Columbia's recent Crown land sales in May, June and July,
where land prices on the Triassic Montney play have increased to over $13,000
per acre. Crew is very well positioned in this play with over 100,000 acres of
land under control.
Balance Sheet is Strengthened and Production Growth Continues
During the second quarter, Crew reduced its net debt by $13.4 million to $125
million on a credit facility of $210 million. This represents a 0.9 times
annualized second quarter funds from operations to net debt ratio, which allows
ample room to increase its capital expenditure program. Crew currently has a
$150 million exploration and development capital budget and has spent
approximately $72 million on acquisitions in 2008.
On June 23, 2008, Crew announced an arrangement agreement to acquire all of the
outstanding shares of Gentry Resources Ltd. The meeting of Gentry's shareholders
to vote on the plan of arrangement is scheduled for August 21, 2008 and if
approved the acquisition is expected to close by the end of August. The
acquisition of Gentry is expected to increase the Company's acquisition total to
approximately $369 million for 2008. With the successful completion of the
Gentry transaction, Crew's average production for 2008 is expected to be 12,400
to 13,400 boe per day with a planned exit rate of 17,000 to 18,000 boe per day
which at its midpoint would constitute a 65% increase in production over the
first quarter of 2008.
Active Drilling Program
Crew expects to have a very active third and fourth quarter with five drilling
rigs and six service rigs currently at work and up to 45 wells scheduled. The
Company continues to test its resource plays in northeast British Columbia and
develop its properties in Alberta which will provide attractive economic returns
under Alberta's New Royalty Framework. With Crew now exposed to over 9 tcf of
resource potential on its lands, the focus will be to unlock this value. We look
forward to reporting our progress on a number of these initiatives in the third
quarter report.
Cautionary Statement - The information provided above includes references to
discovered and undiscovered natural gas resources. There is no certainty that
any portion of the resources will be discovered. If discovered, there is no
certainty that it will be commercially viable to produce any portion of the
resource.
Management's Discussion and Analysis
ADVISORIES
Management's discussion and analysis ("MD&A") is the Company's explanation of
its financial performance for the period covered by the financial statements
along with an analysis of the Company's financial position. Comments relate to
and should be read in conjunction with the consolidated financial statements of
the Company for the three and six month periods ended June 30, 2008 and 2007 and
the audited consolidated financial statements and MD&A for the year ended
December 31, 2007. The consolidated financial statements have been prepared in
accordance with generally accepted accounting principles ("GAAP") in Canada.
Forward Looking Statements
This MD&A contains forward-looking statements. Management's assessment of future
plans and operations, capital expenditures, the timing of those expenditures and
the method of funding thereof, available bank lines, production estimates, wells
to be drilled, timing of drilling, tie-in and completion of wells and the
production resulting therefrom, expected royalty rates, transportation costs and
operating costs, and the taxability of the Company, may constitute
forward-looking statements under applicable securities laws and necessarily
involve risks including, without limitation, risks associated with oil and gas
exploration, development, exploration, 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, the timing and
length of plant turnarounds and the impact of such turnarounds and the timing
thereof, delays resulting from or inability to obtain required regulatory
approvals and the ability to access sufficient capital from internal and
external sources. As a consequence, the Company's actual results could differ
materially from those expressed in, or implied by, the forward-looking
statements. 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 MD&A are made as
of the date of this MD&A and the Company does not undertake any obligation to
update publicly or to revise any of the included forward-looking statements,
whether as a result of new information, future events or otherwise, except as
may be required by applicable securities laws.
Conversions
The oil and gas industry commonly expresses production volumes and reserves on a
"barrel of oil equivalent" basis ("boe") whereby natural gas volumes are
converted at the ratio of six thousand cubic feet to one barrel of oil. The
intention is to sum oil and natural gas measurement units into one basis for
improved analysis of results and comparisons with other industry participants.
Throughout this MD&A, Crew has used the 6:1 boe measure which is the approximate
energy equivalency of the two commodities at the burner tip. Boe does not
represent a value equivalency at the plant gate which is where Crew sells its
production volumes and therefore may be a misleading measure if used in
isolation.
Non-GAAP Measures
Crew evaluates performance based on net income and funds from operations. Funds
from operations is a measure not based on GAAP that is commonly used in the oil
and gas industry. It represents cash provided by operating activities before
changes in non-cash working capital, asset retirement expenditures and the
transportation liability charge. The Company considers it a key measure as it
demonstrates the ability of the business to generate the cash flow necessary to
fund future growth through capital investment and to repay debt. Funds from
operations should not be considered as an alternative to, or more meaningful
than cash flow provided by operating activities as determined in accordance with
GAAP as an indicator of the Company's performance. Crew's determination of funds
from operations may not be comparable to that reported by other companies. Crew
also presents funds from operations per share whereby per share amounts are
calculated using weighted average shares outstanding consistent with the
calculation of income per share.
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash provided by operating
activities 31,908 24,467 61,448 39,483
Asset retirement expenditures 323 4 631 14
Transportation liability charge 328 188 657 188
Change in non-cash working capital 1,543 (3,774) 404 (1,813)
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Funds from operations 34,102 20,885 63,140 37,872
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Management also uses netback, a non-GAAP term, to analyze operating performance.
Netback equals total petroleum and natural gas sales less royalties, operating
costs and transportation calculated on a boe basis.
RESULTS OF OPERATIONS
Production
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Three months ended Three months ended
June 30, 2008 June 30, 2007
Oil and ngl Nat. gas Total Oil and ngl Nat. gas Total
(bbl/d) (mcf/d) (boe/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Plains Core 1,280 29,965 6,274 1,218 32,760 6,678
North Core 565 15,634 3,171 228 12,368 2,289
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Total 1,845 45,599 9,445 1,446 45,128 8,967
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Second quarter 2008 production increased over the second quarter of 2007 as a
result of a successful drilling program that added new natural gas liquid
("ngl") rich natural gas production in the Edson, Pine Creek, Carrot Creek and
Hanlan areas and the closing of a private company acquisition in May 2007. The
acquisition added mainly natural gas production in the Company's northeastern
British Columbia operating area. These additions were partially offset by
decreased production due to scheduled third party facility downtime in
northeastern British Columbia and unscheduled facility downtime in six other
facilities in Alberta and British Columbia during the quarter.
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Six months ended Six months ended
June 30, 2008 June 30, 2007
Oil and ngl Nat. gas Total Oil and ngl Nat. gas Total
(bbl/d) (mcf/d) (boe/d) (bbl/d) (mcf/d) (boe/d)
----------------------------------------------------------------------------
Plains Core 1,362 34,255 7,071 1,265 31,867 6,576
North Core 559 14,398 2,959 192 6,936 1,348
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Total 1,921 48,653 10,030 1,457 38,803 7,924
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Production for the first six months of 2008 increased as a result of the
previously mentioned successful drilling program and the private company
acquisition in northeastern British Columbia.
Revenue
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Revenue ($ thousands)
Natural gas 43,999 30,944 82,542 53,525
Light oil and ngl 15,110 7,759 27,956 14,609
Sulphur 1,207 - 1,207 -
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Total 60,316 38,703 111,705 68,134
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Crew average prices
Natural gas ($/mcf) 10.60 7.54 9.32 7.62
Light oil and ngl ($/bbl) 90.01 58.96 79.98 55.40
Oil equivalent ($/boe) 70.18 47.43 61.19 47.51
Benchmark pricing
Natural Gas - AECO C daily index
(Cdn $/mcf) 10.35 7.35 9.22 7.57
Oil and ngl - Light Sweet @
Edmonton (Cdn $/bbl) 126.12 71.09 111.87 69.08
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Crew's second quarter 2008 revenue increased by 56% over the second quarter of
2007 due to a 48% increase in the Company's commodity pricing and a 5% increase
in volumes. In the second quarter of 2008, the Company's average natural gas
price increased 41% consistent with the increase in the Company's benchmark
price. The sales price for the Company's light oil and ngl increased 53% in the
second quarter of 2008 as compared to the benchmark increase of 77%. The
discrepancy was a result of additional lower value ethane production in the
second quarter of 2008 in the Company's Ferrier, Alberta and northeastern
British Columbia areas. Ethane prices do not increase proportionately with the
Company's benchmark prices.
For the first six months of 2008, revenue increased 64% over the same period in
2007 due to increased production and commodity pricing. The Company's natural
gas price and the benchmark price both increased 22% over 2007 while the price
received for the Company's light oil and ngl increased 44% compared with a 62%
increase in the benchmark pricing in the same period in 2007 as a result of the
increased ethane production as described earlier.
Royalties
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Royalties 13,148 8,040 23,769 14,811
Per boe 15.30 9.85 13.02 10.33
Percentage of revenue 21.8% 20.8% 21.3% 21.8%
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Royalties as a percentage of revenue increased in the second quarter of 2008
compared to the second quarter of 2007 due to higher royalties from new
production in the Company's Ferrier area. In the first six months of 2008,
royalties as a percentage of revenue are slightly lower compared to the same
period in 2007 due to lower royalty rates on the assets acquired in the May,
2007 corporate acquisition.
Financial Instruments
On occasion, the Company will enter into commodity price 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 natural gas price "puts"
and costless "collars" to limit exposure to downturns in commodity prices, while
allowing for participation in commodity price increases. The Company's financial
derivative trading activities are conducted pursuant to the Company's Risk
Management Policy approved by the Board of Directors.
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Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Realized loss on financial
instruments (2,242) (68) (2,330) (68)
Unrealized gain (loss) on
financial instruments (5,260) 959 (10,426) 959
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(7,502) (891) (12,756) (891)
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As at June 30, 2008, the Company had entered into direct sales agreements to
sell natural gas as follows:
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Fair
Floor Ceiling Value
Volume Price (Cdn (Cdn ($
(gj/day) Term (Cdn $/gj) $/gj) $/gj) thousands)
----------------------------------------------------------------------------
AECO C -
AECO April 1, 2008 - Monthly
10,000 October 31, 2008 Index $7.00 $8.00 (4,180)
AECO C -
AECO April 1, 2008 - Daily
10,000 October 31, 2008 Average $7.00 $8.30 (3,882)
AECO C -
AECO 10,000 April 1, 2008 - Monthly
October 31, 2008 Index $7.50 $9.25 (2,576)
AECO C -
AECO/Station Daily
2 Average
Differential November 1, 2007 less
Swap 10,000 October 31, 2008 $0.16 - - (211)
----------
(10,849)
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Operating Costs
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Operating costs 6,532 5,024 13,205 8,768
Per boe 7.60 6.16 7.23 6.11
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----------------------------------------------------------------------------
In the second quarter and first half of 2008, the Company's operating costs per
unit increased 23% and 18%, respectively over the second quarter and first half
of 2007 as a result of continued inflationary pressures and the facility outages
in the Company's lower cost areas. With the facility outages, fixed costs
continued to be incurred thus increasing Crew's costs per boe. In addition,
increased fuel costs predominantly in the Sierra area in northeastern British
Columbia negatively affected operating costs. The Company has also experienced
an increase in third party processing fees in the Viking and Plain Lake areas.
Second quarter and year to date operating costs were higher than the expected
2008 annual range of $6.50 to $6.90 as a result of the unscheduled facility
outages, the higher than expected third party processing fees and increased fuel
costs. As a result of the higher costs experienced in the first half of 2008,
the Company has increased its estimate of second half operating costs to between
$7.00 and $7.25 per boe.
Transportation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Transportation costs 1,921 1,878 3,992 2,411
Per boe 2.23 2.30 2.19 1.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's second quarter 2008 decrease in transportation costs per boe is a
result of a decrease in the Company's firm transportation commitments in
northeastern British Columbia. The Company has transferred some of its
unutilized firm transportation commitments that were acquired in its May 2007
corporate acquisition, to a third party. In the first six months of 2008, the
increase in transportation costs per boe is the result of the Company's May,
2007 acquisition of a private company with natural gas production mainly in
northeast British Columbia which has a higher transportation cost. In northeast
British Columbia, natural gas is produced into a third party owned gathering and
processing infrastructure that enables producers to avoid facility construction.
The all-in regulated fees charged for gathering, processing and transmission of
the Company's natural gas through this system is included in transportation
expense.
Operating Netbacks
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three months Three months
ended June 30, 2008 ended June 30, 2007
Oil and Natural Oil and Natural
ngl gas Total ngl gas Total
($/bbl) ($/mcf) ($/boe) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 90.01 10.60 70.18 58.96 7.54 47.43
Royalties (21.59) (2.24) (15.30) (12.24) (1.57) (9.85)
Operating costs (7.59) (1.27) (7.60) (6.29) (1.02) (6.16)
Transportation costs (0.81) (0.43) (2.23) (0.85) (0.43) (2.30)
----------------------------------------------------------------------------
Operating netbacks 60.02 6.66 45.05 39.58 4.52 29.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months Six months
ended June 30, 2008 ended June 30, 2007
Oil and Natural Oil and Natural
ngl gas Total ngl gas Total
($/bbl) ($/mcf) ($/boe) ($/bbl) ($/mcf) ($/boe)
----------------------------------------------------------------------------
Revenue 79.98 9.32 61.19 55.40 7.62 47.51
Royalties (19.10) (1.91) (13.02) (12.28) (1.65) (10.33)
Operating costs (6.89) (1.22) (7.23) (5.93) (1.03) (6.11)
Transportation costs (0.71) (0.42) (2.19) (1.01) (0.31) (1.68)
----------------------------------------------------------------------------
Operating netbacks 53.28 5.77 38.75 36.18 4.63 29.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------
General and Administrative
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross costs 2,454 1,938 5,088 3,829
Operator's recoveries (486) (157) (1,034) (732)
Capitalized costs (984) (890) (2,027) (1,548)
----------------------------------------------------------------------------
General and administrative expenses 984 890 2,027 1,549
Per boe 1.14 1.09 1.11 1.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Increased general and administrative costs before recoveries and capitalization
was the result of increased staff levels and inflationary pressures on salaries
as well as increased rent costs for the Company's additional office space in the
second quarter and first half of 2008 compared to the same periods in 2007. The
Company's net general and administrative costs in the second quarter and first
half of 2008 were reduced by increased operator's recoveries which is a function
of increased exploration and development expenditures. The Company continues to
forecast annual general and administrative costs per unit at between $1.00 and
$1.05 per boe. General and administrative costs per unit are expected to be
lower in the second half of 2008 due to forecasted increased production,
increased operator's recoveries and lower net costs as most of the Company's
annual regulatory and filing costs have now been incurred.
Interest
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Interest expense 1,655 1,917 3,510 2,655
Average debt level 113,558 117,720 109,534 83,467
Effective interest rate 5.1% 6.5% 6.0% 6.4%
Per boe 1.93 2.35 1.92 1.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Crew's effective interest rate decreased in the second quarter and for the first
six months of 2008 compared to 2007 due to the deferred financing costs,
incurred in connection with the new credit facility in May 2007, being fully
amortized into interest expense by May 2008 as well as lower interest rates.
Stock-Based Compensation
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Gross costs 1,864 1,298 3,572 2,264
Capitalized costs (932) (649) (1,786) (1,132)
----------------------------------------------------------------------------
Total stock-based compensation 932 649 1,786 1,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock-based compensation expense has increased in 2008 as a result
of an increase in stock options issued due to increased staff levels over the
same period in 2007.
Depletion, Depreciation and Accretion
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands except per boe) 2008 2007 2008 2007
----------------------------------------------------------------------------
Depletion, depreciation and
accretion 20,650 19,523 43,290 34,373
Per boe 24.03 23.93 23.71 23.97
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Per unit depletion, depreciation and accretion has increased in the second
quarter of 2008 due to an increase in accretion expense from the asset
retirement obligation acquired in the May 2007 corporate acquisition. For the
six months ended June 30, 2008, per unit depletion has decreased due to the
Company's successful drilling program in the first half of 2008.
Future Income Taxes
The provision for future income taxes was $1.8 million in the second quarter of
2008 compared to $0.3 million in the same period of 2007. For the first six
months of 2008, the future tax expense was $1.3 million compared with $0.7
million for the same period in 2007. The increase in future taxes was a result
of higher pre-tax earnings but was partially offset with a corporate rate
reduction in British Columbia from 12 percent to 11.5 percent in 2008 and a
further reduction to 11 percent in 2009.
Cash and Funds from Operations and Net Income
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Cash provided by operating
activities 31,908 24,467 61,448 39,483
Funds from operations 34,102 20,885 63,140 37,872
Per share - basic 0.60 0.46 1.14 0.87
- diluted 0.58 0.46 1.12 0.87
Net income 5,415 1,351 6,356 2,670
Per share - basic 0.09 0.03 0.11 0.06
- diluted 0.09 0.03 0.11 0.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's increase in cash provided by operating activities and funds from
operations for the second quarter of 2008 and the first half of 2008 was the
result of the increased production levels and increased commodity pricing. The
corresponding increase in net income was limited by unrealized losses on
financial instruments from the Company's Risk Management program.
Capital Expenditures and Acquisitions
During the second quarter, the Company drilled seven (7.0 net) wells resulting
in five successful natural gas wells, one light oil well and one dry and
abandoned well. In addition, the Company also closed an acquisition of 102.2 net
sections of Montney formation rights in northeastern British Columbia for $63.1
million adding to its inventory of undeveloped land in northeastern British
Columbia.
Total exploration and development expenditures for the second quarter of 2008
were $22.6 million compared to $11.4 million for the same period in 2007. The
expenditures are detailed below:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
($ thousands) 2008 2007 2008 2007
----------------------------------------------------------------------------
Land 2,201 1,114 20,065 4,269
Seismic 355 960 1,477 1,652
Drilling and completions 13,501 4,950 36,157 27,788
Facilities, equipment and pipelines 5,048 3,303 11,395 10,212
Other 1,459 1,028 2,572 1,753
----------------------------------------------------------------------------
Total exploration and development 22,564 11,355 71,666 45,674
Property acquisitions (dispositions) 63,110 (59) 71,756 2
Business acquisition - 137,456 - 137,456
----------------------------------------------------------------------------
Total 85,674 148,752 143,422 183,132
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company has budgeted exploration and development expenditures for 2008 of
$150 million and combined with the Company's 2008 property acquisitions, total
capital expenditures are expected to be approximately $222 million. This does
not include an amount for the proposed Gentry acquisition which is scheduled to
close later in August.
Liquidity and Capital Resources
Capital Funding
Funding for the Company's second quarter 2008 capital expenditure program came
from a combination of bank debt, cash flow from on-going operations and the
closing of an equity issue in May, 2008.
On May 1, 2008, Crew issued 5,000,000 Common shares at an issue price of $13.35
per share for total net proceeds of approximately $63.2 million. The proceeds
were used to acquire 102.2 net sections of Montney rights in northeastern
British Columbia for $63.1 million.
The Company currently has a credit facility with a syndicate of banks. The
Company's bank facility consists of a revolving line of credit of $195 million
and an operating line of credit of $15 million (the "Facility"). The Facility
revolves for a 364 day period and will be subject to its next 364 day extension
by June 15, 2009. If not extended, the Facility will cease to revolve, and all
outstanding balances under the Facility will become payable within one year. At
June 30, 2008, the Company had drawings of $119.3 million on the Facility.
The Company will continue to fund its on-going operations from a combination of
cash flow, debt, and equity financings as needed. As the majority of our
on-going capital expenditure program is directed to the further growth of
reserves and production volumes, Crew is readily able to adjust its budgeted
capital expenditures should the need arise.
Working Capital
The capital intensive nature of Crew's activities generally results in the
Company carrying a working capital deficit. However, the Company maintains
sufficient unused bank credit lines to satisfy such working capital
deficiencies. At June 30, 2008, the Company's working capital deficiency
including only accounts receivable and accounts payable and accrued liabilities
totaled $5.7 million which, when combined with the drawings on its bank line,
represented 60% of its available bank facility at that time.
Share Capital
On May 1, 2008, Crew issued 5,000,000 Common shares at an issue price of $13.35
per share for total net proceeds of approximately $63.2 million.
On October 25, 2007, the Company closed a public offering resulting in the
issuance of 6,042,360 shares for aggregate proceeds of $54.5 million ($51.5
million net of issue costs). Of the shares issued, 1,860,500 shares were issued
on a flow through basis in which the Company committed to renounce to the
purchasers certain Canadian income tax deductions totalling $20.0 million. At
June 30, 2008, the Company had renounced all required income tax deductions and
had incurred $16.1 million of qualifying expenditures under this flow through
offering with $3.9 million to be incurred before December 31, 2008.
On June 23, 2008, Crew and Gentry Resources Ltd. ("Gentry") jointly announced
that they have entered into an Arrangement Agreement whereby, subject to certain
conditions, Crew will acquire all of the issued and outstanding shares of Gentry
(the "Transaction"). Under the terms of the agreement, Gentry shareholders will
receive 0.22 of a Crew common share for each Gentry common share held or an
aggregate of approximately 12.4 million shares. Upon completion of the
Transaction, Gentry will become a wholly owned subsidiary of Crew and current
Gentry shareholders and option holders will own approximately 17% of the
combined entity. A special meeting of the Gentry shareholders is scheduled for
August 21, 2008 at which time the Gentry shareholders will be asked to approve
the Transaction. If approved, and regulatory approval is received, closing of
the Transaction is expected on or about August 22, 2008.
As at August 11, 2008, Crew had 58,916,919 Common Shares and 4,123,200 options
to acquire Common Shares of the Company issued and outstanding.
Capital Structure
The Company considers its capital structure to include working capital,
including accounts receivable and accounts payable and accrued liabilities, bank
debt, and shareholders' equity. The Company monitors capital based on the ratio
of net debt to annualized funds from operations. The ratio represents the time
period it would take to pay off the debt if no further capital expenditures were
incurred and if funds from operations remained constant. This ratio is
calculated as net debt, defined as outstanding bank debt plus or minus net
working capital, divided by funds from operations for the most recent calendar
quarter, annualized (multiplied by four). The Company's strategy is to maintain
a ratio of no more than 2 to 1.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
($ thousands, except ratio) 2008 2007
----------------------------------------------------------------------------
Accounts receivable (34,768) (28,588)
Accounts payable and accrued liabilities 40,420 43,231
----------------------------------------------------------------------------
Working capital deficiency 5,652 14,643
Bank loan 119,348 95,028
----------------------------------------------------------------------------
Net debt 125,000 109,671
Funds from operations 34,102 22,390
Annualized 136,408 89,560
Net debt to annualized funds from operations ratio 0.92 1.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 2008 2009 2010 2011
----------------------------------------------------------------------------
Bank Loan (note 1) 119,348 - - 119,348 -
Operating leases 3,217 495 990 990 742
Capital commitments 14,150 9,400 4,750 - -
Exploration and
development 3,900 3,900 - - -
Firm transportation
agreements 24,251 3,404 7,026 7,243 6,578
----------------------------------------------------------------------------
Total 164,866 17,199 12,766 127,581 7,320
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Note 1 - Based on the existing terms of the Company's bank facility the
first possible repayment date may come in 2010. However, it is
expected that the revolving bank facility will be extended and no
repayment will be required in the near term.
The exploration and development commitment relates to the Company's obligation
under its October 25, 2007 flow-through share issue.
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.
Guidance
We expect a very busy latter half of 2008. Crew expects to drill up to 45 wells
in the last half of 2008 and currently has five drilling rigs and six service
rigs working. Crew reduced its net debt by $13.4 million to $125 million in the
second quarter on a credit facility of $210 million. This represents a 0.9 times
annualized second quarter funds from operations to net debt ratio, which allows
ample room to increase its capital expenditure program. Crew currently has an
$150 million exploration and development capital budget and has spent
approximately $72 million on acquisitions in 2008.
On June 23, 2008, Crew announced an arrangement agreement to acquire all of the
outstanding shares of Gentry Resources Ltd. Gentry's shareholders meeting to
vote on the plan of arrangement is on August 21, 2008. The acquisition of Gentry
would increase the Company's acquisition total to approximately $369 million for
2008. With the successful completion of the Gentry transaction, Crew's average
production for 2008 is expected to increase to 12,400 to 13,400 boe per day with
a planned exit rate of 17,000 to 18,000 boe per day which at its midpoint would
constitute a 65% increase in production over the first quarter of 2008.
Additional Disclosures
Quarterly Analysis
The following table summarizes Crew's key quarterly financial results for the
past eight financial quarters:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ thousands,
except
per
share June 30 Mar. 31 Dec. 31 Sept. 30 June 30 Mar. 31 Dec. 31 Sept. 30
amounts) 2008 2008 2007 2007 2007 2007 2006 2006
----------------------------------------------------------------------------
Total
daily
production
(boe/d) 9,445 10,614 9,641 9,268 8,967 6,869 6,227 5,768
Average
wellhead
price
($/boe) 70.18 53.20 43.90 39.16 47.43 47.61 46.41 41.96
Petroleum
and
natural
gas sales 60,316 51,389 38,942 33,390 38,703 29,431 26,590 22,267
Cash
provided
by
operations 31,908 29,540 11,882 23,035 24,467 15,016 16,522 11,984
Funds from
operations 34,102 29,038 22,390 21,171 20,885 16,987 16,705 14,245
Per share
- basic 0.60 0.54 0.43 0.45 0.46 0.41 0.43 0.41
- diluted 0.58 0.54 0.43 0.44 0.46 0.41 0.43 0.40
Net income
(loss) 5,415 941 6,889 (449) 1,351 1,319 1,796 1,633
Per share
- basic 0.09 0.02 0.13 (0.01) 0.03 0.03 0.05 0.05
- diluted 0.09 0.02 0.13 (0.01) 0.03 0.03 0.05 0.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 2006 to 2008, despite increasing production, these performance measures
have fluctuated as a result of volatile natural gas prices combined with the
escalating cost of operations.
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.
- In May 2007, the Company acquired a private oil and gas company with
approximately 3,100 boe per day of production at closing, consisting mainly of
natural gas in the northeastern British Columbia area.
- In November 2006 the Company acquired a private oil and gas company with
approximately 1,000 boe per day of production at closing.
- Production was negatively impacted by scheduled and unscheduled facility
outages in Alberta and northeastern British Columbia in the second quarter of
2008 reducing volumes below the first quarter of 2008.
- Revenue and royalties are significantly impacted by underlying commodity
prices. Prior to March 31, 2008, the Company had used a limited amount of
derivative contracts or forward sales contracts to reduce the exposure to
commodity price fluctuations.
- In the first and second quarters of 2008, the Company had unrealized losses on
financial instruments of $5.2 million and $5.2 million, respectively, primarily
relating to contracts covering the period of April 1, 2008 to October 31, 2008.
- In the second quarter of 2008, the Company had a realized loss on financial
instruments of $2.2 million.
- The Company's operating costs and capital expenditures have been subject to
inflationary pressures brought on by increasing demand for services and supplies
within the Canadian oil and gas industry.
- In the fourth quarter of 2007 and the first quarter of 2008, Crew had future
tax recoveries which positively affected net income due to Canadian federal and
provincial tax rate reductions.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting
Crew's Chief Executive Officer and Chief Financial Officer are required to cause
the Company to disclose herein any change in Crew's disclosure controls and
procedures and internal controls over financial reporting that occurred during
the Company's most recent interim period that has materially affected, or is
reasonably likely to materially affect the Company's internal controls over
financial reporting. No material changes in Crew's disclosure controls and
procedures and internal controls over financial reporting were identified during
the six months ended June 30, 2008 that have materially affected, or are
reasonably likely to materially affect the Company's internal controls over
financial reporting.
New Accounting Pronouncements
Financial Instruments
On January 1, 2008, the Company adopted CICA Handbook Section 3862, "Financial
Instruments - Disclosures", and Section 3863, "Financial Instruments -
Presentation". Section 3862 and 3863 establish standards for the presentation
and disclosure of information that enable users to evaluate the significance of
financial instruments to the entity's financial position, and the nature and
extent of risks arising from financial instruments and how the entity manages
these risks. The implementation of these standards did not impact the Company's
financial results, however it did result in additional disclosure presented in
note 8 of the Company's notes to the consolidated financial statements.
Capital Disclosures
On January 1, 2008, the Company adopted CICA Handbook Section 1535 "Capital
Disclosures". Section 1535 establishes standards for disclosing information
about an entity's capital and how it is managed. This section specifies
disclosure about objectives, policies and processes for managing capital,
quantitative data about what an entity regards as capital, whether an entity has
complied with all capital requirements, and if it has not complied, the
consequences of such non-compliances. The implementation of this standard did
not impact the Company's financial results, however it did result in additional
disclosure presented in note 9 of the Company's notes to the consolidated
financial statements.
Goodwill
As of January 1, 2009, Crew will be required to adopt CICA Handbook Section 3064
"Goodwill and Intangible Assets", which defines the criteria for the recognition
of intangible assets.
Convergence with International Reporting Standards
In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the
changeover to International Financial Reporting Standards ("IFRS") from Canadian
GAAP will be required for publicly accountable enterprises interim and annual
financial statements effective for fiscal years beginning on or after January 1,
2011. The AcSB issued the "omnibus" exposure draft of IFRS with comments due by
July 31, 2008, wherein early adoption by Canadian entities is also permitted.
The Canadian Securities Administrators ("CSA") has also issued Concept Paper
52-402, which requested feedback on the early adoption of IFRS as well as the
continued use of US GAAP by domestic issuers. The eventual changeover to IFRS
represents a change due to new accounting standards. The transition from current
Canadian GAAP to IFRS is a significant undertaking that may materially affect
the Company's reported financial position and results of operations.
The IASB has stated that it plans to issue an exposure draft relating to certain
amendments and exemptions to IFRS 1. One such exemption relating to full cost
oil and gas accounting is expected to reduce the administrative burden in the
transition from the current Canadian Accounting Guideline 16 to IFRS. It is
anticipated that this exposure draft will not result in an amended IFRS 1
standard until late 2009. The amendment will potentially permit the Company to
apply IFRS prospectively to their full cost pool, rather than the retrospective
assessment of capitalized exploration and development expenses, with the proviso
that an impairment test, under IFRS standards, be conducted at the transition
date.
Although, the Company has not completed development of its IFRS changeover plan,
when finalized it will include project structure and governance, resourcing and
training, an analysis of key GAAP differences and a phased plan to assess
accounting policies under IFRS as well as potential IFRS 1 exemptions. The
Company anticipates completing its project scoping, which will include a
timetable for assessing the impact on data systems, internal controls over
financial reporting, and business activities, such as financing and compensation
arrangements, by the fourth quarter of 2008.
Dated as of August 11, 2008
Cautionary Statement
This press release contains forward-looking statements relating to Management's
approach to operations, expectations relating to the number of wells, amount and
timing of capital projects, Company production, commodity prices in Canada,
royalties, operating costs, transportation costs, general and administrative
costs and cash flow. The reader is cautioned that assumptions used in the
preparation of such information, although considered reasonable by Crew at the
time of preparation, may prove to be incorrect. Actual results achieved during
the forecast period will vary from the information provided herein as a result
of numerous known and unknown risks and uncertainties and other factors. Such
factors include, but are not limited to: general economic, market and business
conditions; industry capacity; competitive action by other companies;
fluctuations in oil and gas prices; the ability to produce and transport crude
oil and natural gas to markets; the result of exploration and development
drilling and related activities; fluctuation in foreign currency exchange rates;
the imprecision of reserve estimates; the ability of suppliers to meet
commitments; actions by governmental authorities including increases in taxes;
decisions or approvals of administrative tribunals; change in environmental and
other regulations; risks associated with oil and gas operations; the weather in
the Company's areas of operations; and other factors, many of which are beyond
the control of the Company. There is no representation by Crew that actual
results achieved during the forecast period will be the same in whole or in part
as that forecast.
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, 2008 and
2007 are attached.
CREW ENERGY INC.
Consolidated Balance Sheets
(unaudited)
(thousands)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Assets
Current assets:
Accounts receivable $ 34,768 $ 28,588
Future income taxes 2,763 -
----------------------------------------------------------------------------
37,531 28,588
Property, plant and equipment (note 3) 656,737 552,805
Goodwill 20,800 20,800
----------------------------------------------------------------------------
$ 715,068 $ 602,193
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accrued liabilities $ 40,420 $ 43,231
Fair value of financial instruments (note 8) 10,849 423
Current portion of other long-term obligations
(note 5) 1,313 1,313
----------------------------------------------------------------------------
52,582 44,967
Bank loan (note 4) 119,348 95,028
Other long-term obligations (note 5) 2,102 2,759
Asset retirement obligations (note 6) 19,428 18,668
Future income taxes 85,945 77,045
Shareholders' Equity
Share capital (note 7) 361,344 298,129
Contributed surplus (note 7) 12,923 10,557
Retained earnings 61,396 55,040
----------------------------------------------------------------------------
435,663 363,726
Commitments (note 11)
Subsequent event (note 12)
----------------------------------------------------------------------------
$ 715,068 $ 602,193
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the consolidated financial statements.
CREW ENERGY INC.
Consolidated Statements of Operations, Comprehensive Income and Retained
Earnings
(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,
2008 2007 2008 2007
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue
Petroleum and natural gas
sales $ 60,316 $ 38,703 $ 111,705 $ 68,134
Royalties (13,148) (8,040) (23,769) (14,811)
Gain (loss) on financial
instruments (note 8) (7,502) 891 (12,756) 891
Other income 268 - 268 -
----------------------------------------------------------------------------
39,934 31,554 75,448 54,214
Expenses
Operating 6,532 5,024 13,205 8,768
Transportation 1,921 1,878 3,992 2,411
Interest 1,655 1,917 3,510 2,655
General & administrative 984 891 2,027 1,549
Stock-based compensation 932 649 1,786 1,132
Depletion, depreciation &
accretion 20,650 19,523 43,290 34,373
----------------------------------------------------------------------------
32,674 29,882 67,810 50,888
----------------------------------------------------------------------------
Income before income taxes 7,260 1,672 7,638 3,326
Future income taxes 1,845 321 1,282 656
----------------------------------------------------------------------------
Net income and comprehensive
income 5,415 1,351 6,356 2,670
Retained earnings, beginning
of period 55,981 47,249 55,040 45,930
Retained earnings, end of
period $ 61,396 $ 48,600 $ 61,396 $ 48,600
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per share
(note 7(d))
Basic $ 0.09 $ 0.03 $ 0.11 $ 0.06
Diluted $ 0.09 $ 0.03 $ 0.11 $ 0.06
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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,
2008 2007 2008 2007
----------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Net income $ 5,415 $ 1,351 $ 6,356 $ 2,670
Items not involving cash:
Depletion, depreciation &
accretion 20,650 19,523 43,290 34,373
Stock-based compensation 932 649 1,786 1,132
Future income taxes 1,845 321 1,282 656
Unrealized loss (gain) on
financial instruments 5,260 (959) 10,426 (959)
Transportation liability
charge (note 5) (328) (188) (657) (188)
Asset retirement
expenditures (323) (4) (631) (14)
Change in non-cash working
capital (note 10) (1,543) 3,774 (404) 1,813
----------------------------------------------------------------------------
31,908 24,467 61,448 39,483
Financing activities:
Increase (decrease) in bank
loan (4,795) 71,074 24,320 99,654
Issue of common shares 69,097 59,226 69,762 59,274
Share issue costs (3,507) (3,274) (3,521) (3,274)
----------------------------------------------------------------------------
60,795 127,026 90,561 155,654
Investing activities:
Exploration and development (22,564) (11,355) (71,666) (45,674)
Property acquisitions, net
of dispositions (63,110) 59 (71,756) (2)
Business acquisition - (137,325) - (137,325)
Change in non-cash working
capital (note 10) (7,029) (2,872) (8,587) (12,136)
----------------------------------------------------------------------------
(92,703) (151,493) (152,009) (195,137)
----------------------------------------------------------------------------
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, 2008 and 2007
(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, 2007, except as disclosed below. The disclosure which follows is
incremental to the disclosure included with the December 31, 2007 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, 2007.
Certain comparative amounts have been reclassified to conform to current period
presentation.
2. Change in accounting policy:
Financial Instruments
On January 1, 2008, the Company adopted CICA Handbook Section 3862, "Financial
Instruments - Disclosures", and Section 3863, "Financial Instruments -
Presentation". Section 3862 and 3863 establish standards for the presentation
and disclosure of information that enable users to evaluate the significance of
financial instruments to the entity's financial position, and the nature and
extent of risks arising from financial instruments and how the entity manages
these risks. The implementation of these standards did not impact the Company's
financial results, however it did result in additional disclosure presented in
note 8.
Capital Disclosures
On January 1, 2008, the Company adopted CICA Handbook Section 1535 "Capital
Disclosures". Section 1535 establishes standards for disclosing information
about an entity's capital and how it is managed. This section specifies
disclosure about objectives, policies and processes for managing capital,
quantitative data about what an entity regards as capital, whether an entity has
complied with all capital requirements, and if it has not complied, the
consequences of such non-compliances. The implementation of this standard did
not impact the Company's financial results, however it did result in additional
disclosure presented in note 9.
New Accounting Pronouncements
Goodwill
As of January 1, 2009, Crew will be required to adopt CICA Handbook Section 3064
"Goodwill and Intangible Assets", which defines the criteria for the recognition
of intangible assets.
Convergence with International Reporting Standards
In February 2008, the CICA Accounting Standards Board ("AcSB") confirmed the
changeover to International Financial Reporting Standards ("IFRS') from Canadian
GAAP will be required for publicly accountable enterprises interim and annual
financial statements effective for fiscal years beginning on or after January 1,
2011. The AcSB issued the "omnibus" exposure draft of IFRS with comments due by
July 31, 2008, wherein early adoption by Canadian entities is also permitted.
The Canadian Securities Administrators ("CSA") has also issued Concept Paper
52-402, which requested feedback on the early adoption of IFRS as well as the
continued use of US GAAP by domestic issuers. The eventual changeover to IFRS
represents a change due to new accounting standards. The transition from current
Canadian GAAP to IFRS is a significant undertaking that may materially affect
the Company's reported financial position and results of operations.
The IASB has stated that it plans to issue an exposure draft relating to certain
amendments and exemptions to IFRS 1. One such exemption relating to full cost
oil and gas accounting is expected to reduce the administrative burden in the
transition from the current Canadian Accounting Guideline 16 to IFRS. It is
anticipated that this exposure draft will not result in an amended IFRS 1
standard until late 2009. The amendment will potentially permit the Company to
apply IFRS prospectively to their full cost pool, rather than the retrospective
assessment of capitalized exploration and development expenses, with the proviso
that an impairment test, under IFRS standards, be conducted at the transition
date.
Although, the Company has not completed development of its IFRS changeover plan,
when finalized it will include project structure and governance, resourcing and
training, an analysis of key GAAP differences and a phased plan to assess
accounting policies under IFRS as well as potential IFRS 1 exemptions. The
Company anticipates completing its project scoping, which will include a
timetable for assessing the impact on data systems, internal controls over
financial reporting, and business activities, such as financing and compensation
arrangements, by the fourth quarter of 2008.
3. Property, plant and equipment:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
June 30, 2008 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $ 844,726 $ 187,989 $ 656,737
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion & Net book
December 31, 2007 Cost depreciation value
----------------------------------------------------------------------------
Petroleum and natural gas properties
and equipment $ 698,251 $ 145,446 $ 552,805
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The cost of unproved properties at June 30, 2008 of $118,740,000 (2007 -
$34,065,000) was excluded from the depletion calculation. Estimated future
development costs associated with the development of the Company's proved
reserves of $28,594,000 (2007 - $31,295,000) have been included in the depletion
calculation and estimated salvage values of $25,026,000 (2007 - $20,703,000)
have been excluded from the depletion calculation.
On May 12, 2008, the Company acquired certain working interests in undeveloped
land for cash proceeds of $63.1 million.
The following corporate expenses related to exploration and development
activities were capitalized:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six months Year ended
ended June 30, December 31,
2008 2007
----------------------------------------------------------------------------
General and administrative expense $ 2,027 $ 3,331
Stock-based compensation expense, including
future income taxes 2,409 3,624
----------------------------------------------------------------------------
$ 4,436 $ 6,955
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. Bank loan:
The Company's bank facility consists of a revolving line of credit of $195
million and an operating line of credit of $15 million (the "Facility"). The
Facility revolves for a 364 day period and will be subject to its next 364 day
extension by June 15, 2009. If not extended, the Facility will cease to revolve,
the margins there under will increase by 0.25 per cent and all outstanding
advances there under will become repayable in one year.
Advances under the Facility are available by way of prime rate loans with
interest rates of up to 0.75 per cent over the bank's prime lending rate and
bankers' acceptances and LIBOR loans which are subject to stamping fees and
margins ranging from 0.95 per cent to 1.75 per cent depending upon the debt to
EBITDA ratio of the Company calculated at the Company's previous quarter end. As
at June 30, 2008, the Company's applicable pricing included a 0.10 percent
margin on prime lending and a 1.10 percent stamping fee and margin on Bankers'
Acceptances and LIBOR loans along with a 0.20 percent per annum standby fee on
the portion of the facility that is not drawn. The facility is secured by a
first floating charge debenture over the Company's consolidated assets. The
effective interest rate on the Company's borrowings under its bank facility for
the period ended June 30, 2008 was 5.9% (June 30, 2007 - 6.1%).
5. Other long-term obligations:
As part of the May 3, 2007 private company acquisition, the Company acquired
several firm transportation agreements. These agreements had a fair value at the
time of the acquisition of a $4.9 million liability. This amount was accounted
for as part of the acquisition cost and will be charged as a reduction to
transportation expenses over the life of the contracts as they are incurred.
This charge for the three and six months ended June 30, 2008 was $0.3 million
and $0.7 million, respectively (June 30, 2007 - $0.2 million).
6. Asset retirement obligations:
Total future asset retirement obligations were determined by management and were
based on Crew's net ownership interest, the estimated future costs to reclaim
and abandon the wells and facilities and the estimated timing of when the costs
will be incurred. Crew estimated the net present value of its total asset
retirement obligation as at June 30, 2008 to be $19,428,000 (December 31, 2007 -
$18,668,000) based on a total future liability of $37,057,000 (December 31, 2007
- $35,166,000). These payments are expected to be made over the next 49 years.
An 8% (2007 - 8%) credit adjusted risk free discount rate and 2% (2007 - 2%)
inflation rate were used to calculate the present value of the asset retirement
obligation.
The following table reconciles Crew's asset retirement obligations:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year ended
Six months ended December 31,
June 30, 2008 2007
----------------------------------------------------------------------------
Carrying amount, beginning of period $ 18,668 $ 10,485
Liabilities incurred 571 845
Liabilities acquired 73 6,646
Accretion expense 747 929
Liabilities settled (631) (237)
----------------------------------------------------------------------------
Carrying amount, end of period $ 19,428 $ 18,668
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. Share capital:
(a) Common Shares
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
shares Amount
----------------------------------------------------------------------------
Common shares, December 31, 2007 53,577 $ 298,129
Public offering issued for cash 5,000 66,750
Exercise of stock options 333 3,012
Stock-based compensation - 1,206
Flow through share income tax adjustment on 2007
issuance - (5,200)
Share issue costs, net of future income taxes of
$968 - (2,553)
----------------------------------------------------------------------------
Common shares, June 30, 2008 58,910 $ 361,344
----------------------------------------------------------------------------
----------------------------------------------------------------------------
On May 1, 2008, Crew issued 5,000,000 Common Shares at $13.35 per share for
aggregate proceeds of $66.8 million ($63.2 million net of issue costs). The
proceeds were used to acquire certain working interests in undeveloped land as
presented in note 3.
On October 25, 2007, the Company closed a public offering resulting in the
issuance of 6,042,360 shares for aggregate proceeds of $54.5 million ($51.5
million net of issue costs). Of the shares issued, 1,860,500 shares were issued
on a flow through basis in which the Company committed to renounce to the
purchasers certain Canadian income tax deductions totalling $20.0 million. At
June 30, 2008, the Company had renounced all required income tax deductions and
had incurred $16.1 million of qualifying expenditures under this flow through
offering leaving $3.9 million remaining to be incurred on or before December 31,
2008.
(b) Contributed Surplus:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
Contributed surplus, December 31, 2007 $ 10,557
Stock-based compensation 3,572
Conversion of stock options (1,206)
----------------------------------------------------------------------------
Contributed surplus, June 30, 2008 $ 12,923
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(c) 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 six
month period ended June 30, 2008: risk free interest rate 4.15% (2007 - 3.95%),
expected life 4 years (2007 - 4 years), volatility 45% (2007 - 45%), and an
expected dividend of nil (2007 - nil). The Company has not incorporated an
estimated forfeiture rate for stock options that will not vest rather the
Company accounts for actual forfeitures as they occur.
During the first six months of 2008, the Company recorded $3,572,000, (2007 -
$2,264,000) of stock-based compensation expense related to the stock options, of
which $1,786,000 (2007 - $1,132,000) 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
$623,000 (2007 - $459,000) associated with the current year's capitalized
stock-based compensation has been recorded.
i) Stock options
The average fair value of the stock options granted during the six months ended
June 30, 2008, as calculated by the Black-Scholes method, was $3.34 per option
(June 30, 2007 - $4.09).
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Weighted
Number of Price average
Options Range exercise price
----------------------------------------------------------------------------
Balance December 31, 2007 3,271 $ 4.70 to $17.80 $ 11.41
Granted 2,160 $ 7.23 to $18.70 $ 8.36
Exercised (333) $ 4.70 to $12.05 $ 9.06
Forfeited (593) $ 7.23 to $17.80 $ 10.79
Cancelled (444) $17.73 to $17.80 $ 17.75
----------------------------------------------------------------------------
Balance June 30, 2008 4,061 $ 7.23 to $18.70 $ 9.38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(d) Per share amounts:
Per share amounts have been calculated on the weighted average number of shares
outstanding. The weighted average number of shares outstanding for the three
month period ended June 30, 2008 were 57,162,000 (June 30, 2007 - 45,117,000)
and for the six month period ended June 30, 2008, the weighted average number of
shares outstanding were 55,394,000 (June 30, 2007 - 43,290,000).
In computing diluted earnings per share for the three month period ended June
30, 2008, 1,212,000 (June 30, 2007 - 392,000) shares were added to the weighted
average number of common shares outstanding for the dilution added by the stock
options and for the six months ended June 30, 2008, 850,000 (June 30, 2007 -
391,000) shares were added to the weighted average number of common shares for
the dilution. There were 190,500 (June 30, 2007 - 1,489,000) stock options that
were not included in the diluted earnings per share calculation because they
were anti-dilutive.
8. Financial Instruments:
Overview
The Company has exposure to credit, liquidity and market risks from its use of
financial instruments. This note provides information about the Company's
exposure to each of these risks, the Company's objectives, policies and
processes for measuring and managing risk. Further quantitative disclosures are
included throughout these financial statements.
The Board of Directors has overall responsibility for the establishment and
oversight of the Company's risk management framework. The Board has implemented
and monitors compliance with risk management policies. The Company's risk
management policies are established to identify and analyze the risks faced by
the Company, to set appropriate risk limits and controls, and to monitor risks
and adherence to market conditions and the Company's activities.
(a) Credit risk:
Credit risk is the risk of financial loss to the Company if a customer or
counterparty to a financial instrument fails to meet its contractual
obligations, and arises principally from the Company's receivables from
petroleum and natural gas marketers and joint venture partners.
Substantially all of the Company's petroleum and natural gas production is
marketed under standard industry terms. Receivables from petroleum and natural
gas marketers are normally collected on the 25th day of the month following
production. The Company's policy to mitigate credit risk associated with these
balances is to establish marketing relationships with large credit worthy
purchasers and to sell through multiple purchasers. The Company historically has
not experienced any collection issues with its petroleum and natural gas
marketers. Joint venture receivables are typically collected within one to three
months of the joint venture bill being issued to the partner. The Company
attempts to mitigate the risk from joint venture receivables by obtaining
partner approval of significant capital expenditures prior to the expenditure.
However, the receivables are from participants in the petroleum and natural gas
sector, and collection of the outstanding balances can be impacted by industry
factors such as commodity price fluctuations, limited capital availability and
unsuccessful drilling programs. The Company does not typically obtain collateral
from petroleum and natural gas marketers or joint venture partners; however the
Company does have the ability in most cases to withhold production from joint
venture partners in the event of non-payment.
The carrying amount of accounts receivable represents the maximum credit
exposure. As at June 30, 2008 the Company's receivables consisted of $16.5
million of receivables from petroleum and natural gas marketers which has
subsequently been collected, $13.4 million from joint venture partners of which
$4.4 million has been subsequently collected, and $4.8 million of Crown deposits
and prepaids. The Company does not have an allowance for doubtful accounts as at
June 30, 2008 and did not provide for any doubtful accounts nor was it required
to write-off any receivables during the period ended June 30, 2008. The Company
does not consider any receivables to be past due.
(b) Liquidity risk:
Liquidity risk is the risk that the Company will encounter difficulty in meeting
obligations associated with the financial liabilities. The Company's financial
liabilities consist of accounts payable, financial instruments and bank debt.
Accounts payable consists of invoices payable to trade suppliers for office,
field operating activities and capital expenditures. The Company processes
invoices within a normal payment period. Accounts payable and financial
instruments have contractual maturities of less than one year. The Company
maintains a revolving credit facility, as outlined in note 4, that is reviewed
semi-annually by the lenders and has a contractual maturity in 2010. The Company
also maintains and monitors a certain level of cash flow which is used to
partially finance all operating and capital expenditures as the Company does not
pay dividends.
(c) Market risk:
Market risk is the risk that changes in market conditions, such as commodity
prices, interest rates, and foreign exchange rates, will affect the Company's
net income or the value of financial instruments. The objective of market risk
management is to manage and control market risk exposures within acceptable
limits, while maximizing the Company's returns.
The Company utilizes both financial derivatives and physical delivery sales
contracts to manage market risks. All such transactions are conducted in
accordance with the Company's risk management policy that has been approved by
the Board of Directors.
(i) Commodity price risk
Commodity price risk is the risk that the fair value or future cash flows will
fluctuate as a result of changes in commodity prices. Commodity prices for
petroleum and natural gas are impacted by not only the relationship between the
Canadian and United States dollar, as outlined below, but also global economic
events that dictate the levels of supply and demand. The Company has attempted
to mitigate a portion of the commodity price risk through the use of various
financial derivative and physical delivery sales contracts. The Company's policy
is to enter into commodity price contracts when considered appropriate to a
maximum of 50% of forecasted production volumes. The Company's contracts in
place as of June 30, 2008 are as follows:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Floor
Volume Price (Cdn Ceiling
(gj/day) Term (Cdn $/gj) $/gj)(Cdn $/gj)
----------------------------------------------------------------------------
April 1, 2008- AECO C
AECO 10,000 October 31, 2008 Monthly Index $7.00 $8.00
April 1, 2008- AECO Daily
AECO 10,000 October 31, 2008 Average $7.00 $8.30
April 1, 2008- AECO C
AECO 10,000 October 31, 2008 Monthly Index $7.50 $9.25
AECO/
Station 2
Differential November 1, 2007- AECO C less
Swap 10,000 October 31, 2008 $ 0.16 - -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Derivatives are recorded on the balance sheet at fair value at each reporting
period with the change in fair value being recognized as an unrealized gain or
loss on the consolidated statement of operations, comprehensive income and
retained earnings. These contracts had the following reflected in the
consolidated statement of operations, comprehensive income and retained
earnings:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six Six
months months months months
ended ended ended ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Realized (loss) on financial
instruments $ (2,242) $ (68) $ (2,330) $ (68)
Unrealized (loss) gain on
financial instruments (5,260) 959 (10,426) 959
----------------------------------------------------------------------------
$ (7,502) $ 891 $ (12,756) $ 891
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at June 30, 2008, a $0.10 change to the price per thousand cubic feet of
natural gas on the costless collars would have a $0.3 million impact on net
income.
(ii) Foreign currency exchange rate risk
Foreign currency exchange rate risk is the risk that the fair value of future
cash flows will fluctuate as a result of changes in foreign exchange rates. All
of the Company's petroleum and natural gas sales are conducted in Canada and are
denominated in Canadian dollars. Canadian commodity prices are influenced by
fluctuations in the Canadian to U.S. dollar exchange rate. The Company had no
forward exchange rate contracts in place as at or during the period ended June
30, 2008.
(iii) Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result
of changes in market interest rates. The Company is exposed to interest rate
fluctuations on its bank debt which bears a floating rate of interest. For the
three and six months ended June 30, 2008, a 100 basis points change to the
effective interest rate would have a $0.2 million and $0.4 million impact on net
income, respectively (2007 - $0.2 and $0.3 million). The sensitivity for the six
months ended June 30, 2008 is higher as compared to 2007 because of an increase
in outstanding bank debt in the first half of 2008 compared to 2007. The Company
had no interest rate swap or financial contracts in place as at or during the
period ended June 30, 2008.
Fair value of financial instruments
The Company's financial instruments as at June 30, 2008 and December 31, 2007
include accounts receivable, derivative contracts, accounts payable and accrued
liabilities, and bank debt. The fair value of accounts receivable, accounts
payable and accrued liabilities approximate their carrying amounts due to their
short-terms to maturity.
The fair value of derivative contracts is determined by discounting the
difference between the contracted price and published forward price curves as at
the balance sheet date, using the remaining contracted petroleum and natural gas
volumes.
Bank debt bears interest at a floating market rate and accordingly the fair
market value approximates the carrying value.
9. Capital management:
The Company's objective when managing capital is to maintain a flexible capital
structure which will allow it to execute on its capital expenditure program,
which includes expenditures on oil and gas activities which may or may not be
successful. Therefore, the Company monitors the level of risk incurred in its
capital expenditures to balance the proportion of debt and equity in its capital
structure.
The Company considers its capital structure to include working capital, bank
debt, and shareholders' equity. The Company monitors capital based on the ratio
of net debt to annualized funds from operations. The ratio represents the time
period it would take to pay off the debt if no further capital expenditures were
incurred and if funds from operations remained constant. This ratio is
calculated as net debt, defined as outstanding bank debt plus or minus net
working capital, divided by funds from operations for the most recent calendar
quarter, annualized (multiplied by four). The Company's strategy is to maintain
a ratio of no more than 2 to 1. This ratio may increase at certain times as a
result of acquisitions or very low commodity prices. As at June 30, 2008, the
Company's ratio of net debt to annualized funds from operations was 0.92 to 1
(December 31, 2007 - 1.22 to 1), which is within the range established by the
Company.
----------------------------------------------------------------------------
----------------------------------------------------------------------------
June 30, December 31,
2008 2007
----------------------------------------------------------------------------
Net debt:
Accounts receivable $ 34,768 $ 28,588
Accounts payable and accrued liabilities (40,420) (43,231)
----------------------------------------------------------------------------
Working capital deficiency $ (5,652) $ (14,643)
Bank loan (119,348) (95,028)
----------------------------------------------------------------------------
Net debt $ (125,000) $ (109,671)
Annualized funds from operations:
Cash provided by operating activities $ 31,908 $ 11,882
Asset retirement expenditures 323 205
Transportation liability charge 328 313
Change in non-cash working capital 1,543 9,990
----------------------------------------------------------------------------
Funds from operations 34,102 22,390
Annualized $ 136,408 $ 89,560
Net debt to annualized funds from operations 0.92 1.22
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In order to facilitate the management of this ratio, the Company prepares annual
funds from operations and capital expenditure budgets, which are updated as
necessary, and are reviewed and periodically approved by the Company's Board of
Directors.
The Company manages its capital structure and makes adjustments by continually
monitoring its business conditions, including; the current economic conditions;
the risk characteristics of the Company's petroleum and natural gas assets; the
depth of its investment opportunities; current and forecasted net debt levels;
current and forecasted commodity prices; and other facts that influence
commodity prices and funds from operations, such as quality and basis
differential, royalties, operating costs and transportation costs.
In order to maintain or adjust the capital structure, the Company will consider;
its forecasted ratio of net debt to forecasted funds from operations while
attempting to finance an acceptable capital expenditure program including
acquisition opportunities; the current level of bank credit available from the
Company's lenders; the level of bank credit that may be attainable from its
lenders as a result of oil and gas reserve growth; the availability of other
sources of debt with different characteristics than the existing bank debt; the
sale of assets; limiting the size of the capital expenditure program and new
equity if available on favourable terms. The Company's share capital is not
subject to external restrictions, however the Company's bank facility is
determined by the lenders and based on the lenders' borrowing base models which
are based on the Company's petroleum and natural gas reserves.
There has been no change in the Company's approach to capital management during
the period ended June 30, 2008.
10. Supplemental cash flow information:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six
months months months Six months
ended ended ended ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Changes in non-cash working
capital:
Accounts receivable $ 154 $ 2,945 $ (6,180) $ 3,727
Accounts payable and accrued
liabilities (8,726) (2,043) (2,811) (14,050)
----------------------------------------------------------------------------
$ (8,572) $ 902 $ (8,991) $ (10,323)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities $ (1,543) $ 3,774 $ (404) $ 1,813
Investing activities (7,029) (2,872) (8,587) (12,136)
----------------------------------------------------------------------------
$ (8,572) $ 902 $ (8,991) $ (10,323)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company made the following cash outlays in respect of interest expense:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Three Six
months months months Six months
ended ended ended ended
June 30, June 30, June 30, June 30,
2008 2007 2008 2007
----------------------------------------------------------------------------
Interest $ 1,099 $ 3,125 $ 2,851 $ 4,002
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. Commitments:
The Company has the following fixed term commitments related to its on-going
business:
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total 2008 2009 2010 2011
----------------------------------------------------------------------------
Operating Leases $ 3,217 $ 495 $ 990 $ 990 $ 742
Capital commitments 14,150 9,400 4,750 - -
Exploration and development 3,900 3,900 - - -
Firm transportation agreements 24,251 3,404 7,026 7,243 6,578
----------------------------------------------------------------------------
Total $ 45,518 $ 17,199 $ 12,766 $ 8,233 $ 7,320
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The exploration and development commitment relates to the Company's obligation
under its October 25, 2007 flow through share issue as described in note 7(a).
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.
12. Subsequent event:
On June 23, 2008, Crew and Gentry Resources Ltd. ("Gentry") jointly announced
that they have entered into an Arrangement Agreement whereby, subject to certain
conditions, Crew will acquire all of the issued and outstanding shares of Gentry
(the "Transaction"). Under the terms of the agreement, Gentry shareholders will
receive 0.22 of a Crew common share for each Gentry common share held or an
aggregate of approximately 12.4 million shares. Upon completion of the
Transaction, Gentry will become a wholly owned subsidiary of Crew and current
Gentry shareholders and option holders will own approximately 17% of the
combined entity. A special meeting of the Gentry shareholders is scheduled for
August 21, 2008 at which time the Gentry shareholders will be asked to approve
the Transaction. If approved, and regulatory approval is received, closing of
the Transaction is expected on or about August 22, 2008.
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