Connacher reports First Quarter 2008 results; Great Divide Pod One production continues to rise, ranging between 7,000 and 8,500 bbl/d; Total production has exceeded 11,000 bbl/d; March 2008 cash flow, if annualized, would exceed $125 million as integrate
CALGARY, May 13 /CNW/ - Connacher Oil and Gas Limited today reported
first quarter 2008 results. Of particular consequence in the reporting period
was the achievement of commerciality at Great Divide Pod One, only two months
after the startup of production at this oil sands steam assisted gravity
drainage ("SAGD") project. Accordingly, commencing March 1, 2008, Connacher is
now booking reserves, production, sales and costs in its operating results and
financial statements. Previously, all revenues and expenses related to Pod One
were being capitalized. As a result, March 2008 results are the first
indication of the impact which our oil sands operation, our expanded
conventional production base and our integrated approach will have on our
operations and financial results.
Revenue for March 2008 was $50 million and monthly cash flow from
operations before non-cash working capital adjustments ("cash flow") exceeded
$10.6 million. This level of revenue and cash flow generation was accomplished
despite Pod One bitumen production averaging only 5,205 bbl/d, below our
ultimate design capacity of 10,000 bbl/d and below current levels ranging
between 7,000 bbl/d and 8,500 bbl/d. Total upstream sales were 8,508 boe/d,
well below current levels.
March 2008 results provide the first concrete evidence of the
effectiveness of our integrated strategy. Results signal our anticipated cash
generating capacity as our production volumes at Pod One ramp up to 10,000
barrels per day. Since commerciality was achieved, our daily Pod One bitumen
production has reached as high as 9,000 bbl/d. More recently, on occasion
production has been constrained as we adapt our treatment systems to higher
utilization levels.
Recently, we converted two more well pairs to full SAGD production,
bringing to fourteen the number of wells contributing to our current
production levels. One well pair remains to be converted. While each of the
converted well pairs have been on full SAGD for different periods, our wells
have performed at or above our expectations and those of our third party
reservoir evaluator. We have had some individual wells yield daily production
in excess of 1,000 bbl/d of bitumen and we are seeing immediate daily
steam/oil ratios ("SOR's") decline to between two and three, consistent with
the high quality reservoir which characterizes the Pod One accumulation. As a
consequence, cumulative SOR's are also declining by well and overall.
Overall Q1 2008 results were constrained by narrow heavy oil
differentials, which have adversely affected refining margins throughout the
fourth quarter of 2007 and the first quarter of 2008. During the current
reporting period, the narrowing of heavy oil differentials in a rapidly rising
crude oil price environment made it difficult for this division to recover
rising crude oil costs from product sales. This is particularly true for our
asphalt production, which is held for sale until the paving season, when
warmer weather conditions prevail. Weak refining results were offset by the
positive impact of our new oil sands production and by much improved
conventional production levels. At Marten Creek, Alberta, sales which came
onstream in March 2008 approached 14 mmcf/d, which considerably exceeded our
natural gas requirements to make steam at Great Divide Pod One. Futhermore,
the recognition of bitumen sales commenced in March 2008 and served to offset
the impact of narrow differentials and the previously discussed weak refining
margins. Similar offsets were not available earlier in the year as bitumen
production, sales and related costs were capitalized.
We are confident of our future and believe that with continued high
prices, results during the balance of the year will substantially exceed those
achieved in the first quarter 2008. We anticipate full year profitability will
be achieved and that full year results will be more aligned with or better
than annualized March 2008 results. This should occur as our integrated
business model will further benefit from higher production levels throughout
the remainder of 2008. Our March bitumen sales provided an acceptable netback
exceeding $30 per barrel from bitumen wellhead prices exceeding $50 per
barrel. We also anticipate that these metrics will improve as crude oil prices
have risen recently and as our unit operating costs decline with higher
production at Pod One.
Connacher has increased its firm and contingent 2008 capital budget from
$373 million to $391 million. The increase is to provide additional
conventional expenditures following Q1 2008 drilling success, an increase in
expenditures for terminal and other facilities at Great Divide and offset by a
reduction in the provision for certain 2008 outlays at our Montana refinery,
which have been deferred until 2009.
We continue to anticipate receiving regulatory approval for our Algar
10,000 bbl/d SAGD project in the Great Divide region of Alberta; we have
preordered certain long-lead items which will assist in cost control for this
project.
These Q1 2008 results will be subject to a Conference Call event at 9:00
a.m. MT May 14, 2008. To listen to or participate in the live conference call
please dial either (416) 644-3422 or (800) 591-7539. A replay of the event
will be available from May 14, 2008 at 11:00 a.m. MT until May 21, 2008 at
11:59 p.m. MT. To listen to the replay please dial either (416) 640-1917 or
(800) 594-3615 and enter the passcode 21270829 followed by the pound sign.HIGHLIGHTS
- Great Divide Pod One achieves commerciality March 1, 2008
- Significant cash generating capacity starting to be realized
- Production has exceeds 11,000 boe/d, including 7,500 bbl/d of
bitumen, with more growth anticipated as Pod One reaches design
capacity of 10,000 bbl/d
- Refining margins show improvement in March 2008 after difficult Q4
2007 and January-February 2008
- Successful winter 2008 capital program -121 core holes and 3D seismic
at Great Divide and encouraging conventional drilling results
Summary Results
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Three months ended March 31 2008 2007 % Change
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FINANCIAL ($000 except per share amounts)
Revenues, net of royalties $100,656 $65,923 53
Cash flow(1) 7,825 10,980 (29)
Per share, basic(1) 0.04 0.06 (33)
Per share, diluted(1) 0.03 0.05 (40)
Net earnings (loss) (1,833) 4,984 (137)
Per share, basic and diluted (0.01) 0.03 -
Property and equipment additions 115,984 109,881 6
Cash on hand 323,423 66,209 388
Working capital 287,105 24,027 1,094
Term debt 671,014 207,828 223
Shareholders' equity 471,559 384,593 23
Total assets 1,348,098 757,205 78
OPERATING
Daily production / sales volumes
Crude oil - bbl/d 996 905 10
Bitumen - bbl/d(2) 1,773 - -
Natural gas - mcf/d 10,493 9,665 9
Barrels of oil equivalent - boe/d(3) 4,518 2,515 80
Product pricing
Crude oil - $/bbl 79.50 49.09 62
Bitumen - $/bbl(2) 53.01 - -
Natural gas - $/mcf 6.94 7.76 (11)
Barrels of oil equivalent - $/boe(3) 54.46 47.48 15
COMMON SHARES OUTSTANDING (000)
Weighted average
Basic 210,234 198,119 6
Diluted 231,510 200,008 16
End of period
Issued 210,277 198,218 6
Fully diluted 250,166 216,606 15
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(1) Cash flow and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures used
by other companies. Cash flow is calculated before changes in non-
cash working capital, pension funding and asset retirement
expenditures. The most comparable measure calculated in accordance
with GAAP would be net earnings. Cash flow, commonly used in the oil
and gas industry, is reconciled with net earnings on the Consolidated
Statements of Cash Flows and in the accompanying Management's
Discussion & Analysis. Management uses these non-GAAP measurements
for its own performance measures and to provide its shareholders and
investors with a measurement of the company's efficiency and its
ability to internally fund future growth expenditures.
(2) The recognition of bitumen sales from Great Divide Pod One commenced
March 1, 2008, when it was declared "commercial". Prior thereto, all
operating costs, net of revenues, were capitalized. Daily
production/sales volumes for the month of March averaged 5,205 bbl
which equates to 1,773 bbl/d for the first quarter of 2008.
(3) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 mcf:1 bbl. Boes may be misleading, particularly if
used in isolation. This conversion is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.LETTER TO SHAREHOLDERS
Overview
Connacher achieved improved operational results during the first quarter
of 2008. The highlight was the ramp-up of bitumen production from our steam
assisted gravity drainage or SAGD operation at Pod One of our Great Divide oil
sands project. During the quarter, 12 out of 15 well pairs were converted over
at different times to full SAGD injection and production. This followed a
pre-heat and semi-SAGD phase during the latter part of 2007 and into the
immediate pre-production phase. Commerciality was achieved effective March 1,
2008. As a result, revenues and associated costs for Pod One are now being
recorded in the company's financial accounts.
Our cash flow in March 2008 exceeded $10 million, or $125 million if
annualized, indicating the tremendous cash generating capacity which the
company now possesses, even though Pod One was only operating at around 50
percent of capacity. In March 2008, daily bitumen production averaged 5,205
bbl/d as volumes were being ramped up towards the plant's rated capacity of
10,000 bbl/d. Production ramp-up throughout the quarter exceeded internal
estimates. If current prices are maintained it is evident that further growth
in revenue, cash flow and profitability is anticipated and should be more
readily apparent in the remaining quarters of 2008.
We also note the company was also able to achieve significant growth of
its conventional production with new gas production and sales at Randall. This
followed a well organized and efficient facilities construction program in the
region during January and February 2008. Conventional production in March 2008
averaged 3,303 boe/d, including approximately 14 mmcf/d of natural gas with
new Randall volumes coming onstream. Total sales were 8,508 boe/d in March
2008 and averaged 4,518 boe/d for the quarter.
On April 4, 2008, Connacher announced its production had surpassed 10,600
boe/d as bitumen sales exceeded 7,000 bbl/d and conventional volumes reached
3,600 boe/d, both record levels of production. Subsequently, bitumen sales
have surpassed this level and further increases will accompany the conversion
of the remaining three SAGD well pairs. Further identifiable gains at Great
Divide Pod One are anticipated to result in sales approaching 14,000 boe/d by
year end 2008.
These operational advances were masked to some extent in the quarter by a
difficult start to the year for our refining and marketing activity in
Montana. High oil prices during a low margin season coupled with narrowing
heavy crude oil differentials to WTI impaired results during January and
February 2008 in this division, although a marked turnaround was in evidence
by March 2008.
We had an active capital program during the first quarter of 2008, with
outlays exceeding $114 million. Emphasis was placed on core hole drilling and
3D seismic at Great Divide and core hole drilling and 2D seismic at Halfway
Creek on our oil sands leases. We also experienced considerable drilling
success in our conventional program. We are excited about the indicated
results, which will be more fully evaluated in our mid-year reserve report
update.
Overall we anticipate 2008 will be a record year for Connacher as its
reported financial and operating results benefit from higher volumes and high
prices, as well as improved returns in our refining division throughout the
summer. We also anticipate mid-year approval of our second 10,000 bbl/d Algar
Project at Great Divide so we can proceed with our already-financed
construction program.
Great Divide
We had a very productive first quarter 2008 at Great Divide Pod One. We
commenced the conversion of our 15 SAGD well pairs to full injection and
production early in the year, overcoming extremely cold weather during the
early stages of this conversion process, which was conducted in a systematic
manner to yield efficient results. Our ramp up proceeded at unprecedented
rates, ahead of anticipated levels. We were able to report improved production
on a regular basis. Most recently production has ranged between 7,000 bbl/d
and 8,500 bbl/d of bitumen. Well productivity and steam oil ratios have been
improving on a consistent basis, with individual wells exceeding 1,000 bbl/d
on occasion and steam oil ratios ("SORs") below 3:1 early in well lives. We
are optimistic we can achieve targeted design volumes or higher on a near term
basis with project SORs approaching 2.6 or better.
We have encountered some start up issues as is customary for a project of
this type, but it is a credit to our operating staff that issues have been
identified and resolved fairly quickly. Our economics were respectable in this
startup phase when operating costs are spread over smaller volumes and diluent
costs were high. In March 2008, we received an average dilbit sales price of
$77.24/bbl, which after deduction of the cost of diluent, operating costs and
transportation charges, translates into a calculated wellhead netback for
bitumen of approximately $53.01 per barrel. We anticipate this can further
improve as economies of full scale operation at design capacity are achieved,
with fixed costs spread over a broader production base. Even with these costs,
volumes of 10,000 bbl/d, if and when achieved, would translate into annualized
net operating income exceeding $100 million for Pod One alone. This would be
supplemented by our anticipated conventional and refining operating income.
We are confident our high quality reservoir and our operating strategy in
the oil sands will afford us the opportunity to plan continued expansion in
the oil sands with growing confidence. We were most encouraged by the
indicated results of our 2008 winter core hole program and believe they will
expand and upgrade our reserve and resource base when we receive our reserve
report update later in the year. We also await regulatory approval of our
Algar project, which, based on previous experience, is anticipated prior to
mid-year. Financing for this project is in place and we have preordered and
acquired considerable equipment in anticipation of commencement of
construction this summer.
Our longer term objective or vision is to systematically develop our
productive capacity in the oil sands to 50,000 bbl/d by 2015. Employing our
integrated strategy, we also anticipate increasing our upstream natural gas
productive capacity to 50 mmcf/d within this timeframe, to continue to hedge
our significant operating cost component and thus keep our integrated netbacks
at higher levels than if we were solely a bitumen producer. Also, we are
actively examining the merits of expanding our refining capacity, initially to
approximately 35,000 bbl/d and ultimately in lockstep with our upstream
bitumen production growth to 50,000 bbl/d. In management's opinion, our
50-50-50 goal by 2015 is achievable at minimal dilution and we are pursuing
this vision with all available energy and commitment.
Conventional and Refining
We continued to grow our conventional natural gas production and are now
producing about 150 percent of our Pod One requirements, so we have a solid
head start on Algar requirements. This added production is derived from
exploratory and development drilling success achieved during 2007 and in 2008.
We also completed facilities at Randall under budget and ahead of schedule,
thus bringing these volumes onstream with attendant earlier revenue and cash
flow. Facilities at Three Hills were also completed and our core area in this
region was expanded with successful new drilling.
As indicated, our Montana Refining division encountered economic
challenges during January and February 2008 before conditions improved in
March. This reflected the rapid and considerable increase in crude purchase
costs due to rising crude oil prices and a narrowing of the heavy crude oil
differential to WTI in a weak season for refined products, particularly
asphalt. This division was a major cash flow contributor in 2007 and we
anticipate market conditions will improve as the year progresses. Our capital
program at our Great Falls refinery is currently focused on production of
ultra low sulphur diesel ("ULSD") to meet regulatory requirements. Serious
evaluation of the merits of a 25,000 bbl/d expansion is also under review,
including an examination of financing alternatives. A decision to proceed on
this expansion project will be made at a later date.
Other
Our property and equipment additions in the first quarter 2008 totaled
$116 million, including $83 million on our overall oil sands operations - core
holes, facilities, seismic, preordering items for Algar and capitalized costs.
Approximately $30 million was invested in our conventional crude oil and
natural gas properties and the balance was invested in our refinery. While in
excess of cash flow, our cash balances to fund Algar remain strong and we also
have a significant unutilized credit facility available for our operations.
While we have considerable capital expenditures ahead of us, especially with
possible refinery expansion and pipeline construction to consider, we will
pursue these objectives, if finalized, in a manner that maximizes shareholder
returns.
We are gratified by the recent stock market recognition of our improving
fundamentals and financial results and cash generating capacity, as manifested
in an improved price for our common shares. We have a solid institutional and
retail shareholder base and management and directors remain significant
stakeholders of the company, with a solid commitment to its growth and
well-financed expansion. We have put together a solid, experienced and
qualified management group in recent years and we believe our technical
expertise, especially in respect of SAGD operations, is unparalleled for a
company of our size.
We operate with a small compact group of professionals who should be
proud of their collective accomplishments. We look forward to reporting our
progress to you, our shareholders, as the ensuing quarters of 2008 unfold.
Forward Looking Information
This press release contains forward-looking information including
anticipated increases in reserves and resources as a result of the 2008 winter
core drilling program, expectations of future production, revenues, cash flow,
profitability and capital expenditures, anticipated reductions in operating
costs as a result of optimization of certain operations, development of
additional oil sands resources (including receipt of regulatory approvals in
respect of Algar and the timeline for construction of Algar), expansion of
current conventional oil and gas and refining operations and evaluation of
future transportation alternatives and implementation thereof and anticipated
sources of funding for capital expenditures. Forward looking information is
based on management's expectations regarding future growth, results of
operation, production, future capital and other expenditures (including the
amount, nature and sources of funding thereof), plans for and results of
drilling activity, environmental matters, business prospects and
opportunities. Forward-looking information involves significant known and
unknown risks and uncertainties, which could cause actual results to differ
materially from those anticipated. These risks include, but are not limited
to: the risks associated with the oil and gas industry (e.g., operational
risks in development, exploration and production; delays or changes in plans
with respect to exploration or development projects or capital expenditures;
the uncertainty of reserve and resource estimates; the uncertainty of
estimates and projections relating to production, costs and expenses, and
health, safety and environmental risks), and the risk of commodity price and
foreign exchange rate fluctuations, and risks and uncertainties associated
with securing the necessary regulatory approvals and financing to proceed with
the continued expansion of the Great Divide Project at Algar and other regions
and expansion of the company's refinery in Great Falls, Montana. These risks
and uncertainties are described in detail in Connacher's Annual Information
Form for the year ended December 31, 2007, which is available at
www.sedar.com. Annualized cash flow and net operating income based on March
financial results is provided for illustrative purposes to show the effect of
the Corporation's integrated model following the achievement of commerciality
at Great Divide Pod One. Actual annual cash flow and net operating revenue
will vary from the annualized estimate provided and such variations may be
material. Although Connacher believes that the expectations in such
forward-looking information are reasonable, there can be no assurance that
such expectations shall prove to be correct. The Corporation assumes no
obligation to update or revise the forward-looking information to reflect new
events or circumstances, except as required by law.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following is dated as of May 13, 2008 and should be read in
conjunction with the unaudited consolidated financial statements of Connacher
Oil and Gas Limited ("Connacher" or the "company") for the three months ended
March 31, 2008 and 2007 as contained in this interim report and the MD&A, and
audited consolidated financial statements for the years ended December 31,
2007 and 2006 as contained in the company's 2007 annual report. All of these
consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles ("GAAP") and are presented
in Canadian dollars. This MD&A provides management's view of the financial
condition of the company and the results of its operations for the reporting
periods.
Additional information relating to Connacher, including Connacher's
Annual Information Form is on SEDAR at www.sedar.com.
FORWARD-LOOKING INFORMATION
This quarterly report, including the Letter to Shareholders, contains
forward-looking information including but not limited to anticipated increases
in reserves and resources as a result of the 2008 winter core hole drilling
program, expectations of future production, revenues, cash flow, profitability
and capital expenditures, anticipated reductions in operating costs as a
result of optimization of certain operations, development of additional oil
sands resources (including receipt of regulatory approvals in respect of Algar
and timeline for construction of Algar), expansion of current conventional oil
and gas and refining operations, evaluation of future transportation
alternatives and implementation thereof and anticipated sources of funding for
capital expenditures. Forward looking information is based on management's
expectations regarding future growth, results of operation, production, future
capital and other expenditures (including the amount, nature and sources of
funding thereof), plans for and results of drilling activity, environmental
matters, business prospects and opportunities. Forward-looking information
involves significant known and unknown risks and uncertainties, which could
cause actual results to differ materially from those anticipated. These risks
include, but are not limited to: the risks associated with the oil and gas
industry (e.g., operational risks in development, exploration and production;
delays or changes in plans with respect to exploration or development projects
or capital expenditures; the uncertainty of reserve and resource estimates;
the uncertainty of estimates and projections relating to production, costs and
expenses, and health, safety and environmental risks), the risk of commodity
price and foreign exchange rate fluctuations, risks and uncertainties
associated with securing and maintaining the necessary regulatory approvals
and financing to proceed with the continued expansion of the Great Divide
Project and of the company's refinery in Great Falls, Montana. These risks and
uncertainties are described in detail in Connacher's Annual Information Form
for the year ended December 31, 2007, which is available at www.sedar.com.
Annualized cash flow and net operating income based on March financial results
is provided for illustrative purposes to show the effect of the Corporation's
integrated model following the achievement of commerciality at Great Divide
Pod One. Actual annual cash flow and net operating revenue will vary from the
annualized estimate provided and such variations may be material. Although
Connacher believes that the expectations in such forward-looking information
are reasonable, there can be no assurance that such expectations shall prove
to be correct. The forward-looking information included in this quarterly
report are expressly qualified in their entirety by this cautionary statement.
The forward-looking information included in this quarterly report is made as
of May 13, 2008 and Connacher assumes no obligation to update or revise any
forward-looking information to reflect new events or circumstances, except as
required by law.FINANCIAL AND OPERATING REVIEW
UPSTREAM NETBACKS ($000)
For the three months
ended March 31
2008 Oil Sands(1) Crude Oil Natural Gas Total
-------------------------------------------------------------------------
Gross revenues(2) $17,150 $7,206 $6,633 $30,989
Diluent purchased(3) (8,103) (8,103)
-------------------------------------------------------------------------
Transportation costs (494) - - (494)
-------------------------------------------------------------------------
Production revenue 8,553 7,206 6,633 22,392
Royalties (86) (1,815) (1,162) (3,063)
Operating costs (3,403) (1,060) (1,426) (5,889)
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Total netback(4) $5,064 $4,331 $4,045 $13,440
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2007
-------------------------------------------------------------------------
Gross revenues $3,997 $6,750 $10,747
Diluent purchased - - -
-------------------------------------------------------------------------
Production revenue 3,997 6,750 10,747
Royalties (939) (1,601) (2,540)
Operating costs (876) (1,056) (1,932)
-------------------------------------------------------------------------
Total netback $2,182 $4,093 $6,275
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(1) In the first quarter of 2008, Connacher completed the conversion of a
majority of its fifteen horizontal well pairs to production status at
Great Divide Pod One and processed increasing levels of bitumen
through its facility. This provided the company with the necessary
confidence that this first oil sands project could economically
produce, process and sell bitumen on a continuous basis. Therefore,
effective March 1, 2008 Connacher declared it to be "commercial". As
a result, the company discontinued the capitalization of all pre-
operating costs, moved accumulated capital costs into the full cost
pool, commenced the depletion of these costs, and began reporting Pod
One production and operating results as part of the oil and gas
reporting segment.
(2) Bitumen produced at Great Divide Pod One is mixed with purchased
diluent and sold as "dilbit". Diluent is a light hydrocarbon that
improves the marketing and transportation quality of bitumen. In the
financial statements Upstream Revenues represent sales of dilbit,
crude oil and natural gas, net of royalties; and Upstream Operating
Costs include the cost of purchased diluent.
(3) Diluent volumes purchased and sold have been deducted in calculating
production revenue and production volumes sold.
(4) Total netbacks, by product, are calculated by deducting the related
diluent, transportation, field operating costs and royalties from
revenues. Netbacks on a per-unit basis are calculated by dividing
related production revenue, costs and royalties by production
volumes. Netbacks do not have a standardized meaning prescribed by
GAAP and, therefore, may not be comparable to similar measures used
by other companies. This non-GAAP measurement is a useful and widely
used supplemental measure of the company's efficiency and its ability
to fund future growth through capital expenditures. Netbacks are
reconciled to net earnings below.
UPSTREAM SALES AND PRODUCTION VOLUMES
For the three months ended March 31
2008 2007 % Change
-------------------------------------------------------------------------
Dibit sales(1) 2,440 bbl/d - -
Diluent purchased(1) (667) bbl/d - -
-------------------------------------------------------------------------
Bitumen produced and sold(1) 1,773 bbl/d - -
Crude oil produced and sold 996 bbl/d 905 bbl/d 10
Natural gas produced and sold 10,493 mcf/d 9,665 mcf/d 9
-------------------------------------------------------------------------
Total 4,518 boe/d 2,515 boe/d 80
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(1) Since declaring Great Divide Pod One "commercial" effective March 1,
2008, dilbit sales averaged 7,164 bbl/d in March, or 2,440 bbl/d in
the first quarter of 2008; diluent purchases averaged 1,959 bbl/d in
March, or 667 bbl/d for the quarter; and bitumen production and sales
volumes averaged 5,205 bbl/d in March, or 1,773 bbl/d for the first
quarter of 2008.
UPSTREAM NETBACKS PER UNIT OF PRODUCTION
For the three months ended March 31
2008 Bitumen Crude Oil Natural Gas Total
($ per bbl) ($ per bbl) ($ per mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $53.01 $79.50 $6.94 $54.46
Royalties (0.53) (20.03) (1.22) (7.45)
Operating costs (21.09) (11.69) (1.49) (14.32)
-------------------------------------------------------------------------
Upstream netback $31.39 $47.78 $4.23 $32.69
-------------------------------------------------------------------------
2007 Bitumen Crude Oil Natural Gas Total
($ per bbl) ($ per bbl) ($ per mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue - $49.09 $7.76 $47.48
Royalties - (11.53) (1.84) (11.22)
Operating costs - (10.76) (1.21) (8.54)
-------------------------------------------------------------------------
Upstream netback - $26.80 $4.71 $27.72
-------------------------------------------------------------------------In the first quarter of 2008, bitumen, crude oil, and natural gas
revenues were up 188 percent to $31 million from $10.7 million in the first
quarter of 2007. This was primarily due to increased production and sales
volumes in 2008. Dilbit sales of $17.2 million for the month of March, since
declaring Pod One "commercial", contributed most of the $20 million increase.
A 10 percent increase in crude oil production and a 62 percent increase in
crude oil pricing contributed the balance of the increase in revenues.
Although natural gas production and sales volumes increased nine percent over
the prior year period, natural gas selling prices were lower this year
($6.94/mcf) than last year ($7.76/mcf), primarily due to the $816,000
unrealized mark-to-market loss on the gas collar sustained in 2008.
In the first quarter of 2008, the company entered into a "costless
collar" contract with a third party to receive a minimum of US $7.50 per mmbtu
and a maximum of US $10.05 per mmbtu on a notional quantity of 5,000 mmbtu per
day of natural gas sold between April 1, 2008 and October 31, 2008. This
transaction was not meant to speculate on future natural gas prices, but
rather to protect the downside risk to the company's cash flow and the lending
value of its assets, which is considered very important during a period of
rapid growth with significant capital expenditures.
Royalties represent charges against production or revenue by governments
and landowners. Royalties in the first quarter of 2008 were $3.1 million
compared to $2.5 million in the first quarter of 2007. From year to year,
royalties can change based on changes in the product mix, the components of
which are subject to different royalty rates. Additionally, royalty rates
typically escalate with increased product prices. The most notable change in
royalties this period came as a result of new bitumen production and sales
volumes reported from March 1, 2008. In 2008, royalties on bitumen production
are payable at the rate of one percent of the bitumen selling price. As a
result of this new bitumen production and increased crude oil revenue,
royalties increased by $523,000. However, the low bitumen royalty rate reduced
the company's average royalty rate from 24 percent to 14 percent of production
revenues, or from $11.22 per boe to $7.45 per boe.
In the first quarter of 2008 upstream diluent purchases and operating
costs of $14 million were $12.1 million (624 percent) higher than in the same
prior year period, primarily due to diluent purchases of $8.1 million in 2008
related to the commencement of oil sands bitumen production and dilbit sales,
effective from March 1, 2008. Bitumen produced at Great Divide Pod One is
mixed with purchased diluent and sold as "dilbit." Diluent is a light
hydrocarbon that improves the marketing and transportation quality of bitumen.
For the reported volumes, diluent purchased represented approximately
27 percent of the dilbit barrel sold; bitumen the remaining 73 percent. It is
anticipated that less diluent will be necessary when oil sands production and
handling operations are optimized and higher volumes are processed. The price
of diluent is influenced by supply and demand and in the current period, they
were at historic high levels.
Excluding diluent purchases, upstream field operating costs averaged
$14.32 per boe produced and sold in the first quarter of 2008, compared to
$8.54 per boe produced and sold in the same prior year period. The increase
primarily reflects costs associated with new bitumen production. Bitumen field
operating costs of $3.4 million for March 2008 comprise natural gas
($1.9 million for 7.2 mmcf/d, averaging $8.65/mcf), personnel, power,
chemicals and other costs, averaging $21.09 per bbl of bitumen produced and
sold. As a significant portion of these costs are fixed, it is anticipated
that this per unit operating cost will decline as the company increases
bitumen production to its design capacity of 10,000 bbl/d in 2008.
Transportation costs of $494,000 represent the cost of trucking a small
portion of the company's oil sands sales to market, as a majority of its sales
were priced "net of transportation."
Netbacks are a widely used industry measure of a company's efficiency and
its ability to internally fund its growth. The company's overall upstream
netback of $32.69 per produced boe (an 18 percent increase over the same 2007
period) is significantly affected by its oil sands production, which had a
netback of $31.39 per bitumen barrel produced. Given its early stage of
development and anticipating more operating efficiencies will be realized,
particularly with expected higher production volumes, the company is satisfied
with its oil sands results at this time.Reconciliation of Netback to Net Earnings
-------------------------------------------------------------------------
For the three months
ended March 31 2008 2007
-------------------------------------------------------------------------
($000, except per
unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Upstream netback as above $13,440 $32.69 $6,275 $27.72
Interest income 831 2.02 120 0.53
Refining margin - net 506 1.23 11,198 49.47
General and administrative (3,066) (7.46) (3,584) (15.83)
Stock-based compensation (1,516) (3.69) (2,946) (13.02)
Finance charges (4,431) (10.78) (446) (1.97)
Foreign exchange (loss) gain (1,892) (4.60) 1,702 7.52
Depletion, depreciation
and accretion (7,464) (18.15) (7,357) (32.50)
Income taxes 1,346 3.27 (3,878) (17.13)
Equity interest in
Petrolifera earnings and
dilution gain 413 1.00 3,900 17.23
-------------------------------------------------------------------------
Net earnings (loss) $(1,833) $(4.47) $4,984 $22.02
-------------------------------------------------------------------------DOWNSTREAM REVENUES AND MARGINS
The Montana refinery is subject to a number of seasonal factors which
typically cause product sales revenues to vary throughout the year. The
refinery's primary asphalt market is for paving roads which is predominantly a
summer demand. Consequently, prices and sales volumes for our asphalt tend to
be higher in the summer and lower in the colder seasons. During the winter,
most of the refinery's asphalt production is stored in tankage for sale in the
subsequent summer months. Seasonal factors also affect sales revenues for
gasoline (higher demand in summer months) as well as distillate and diesel
fuels (higher winter demand). As a result, inventory levels, sales volumes and
prices can be expected to fluctuate on a seasonal basis.
In the first quarter of 2008, refining industry margins narrowed further
than was experienced in the fourth quarter of 2007. This has been mainly
attributed to crude oil costs rising faster than the selling prices of refined
products and by a narrowing of the heavy : light oil pricing differential
which also influences heavy refining profit margins.
In the first quarter of 2008, the company's refining revenues
($71.9 million) were lower than in the fourth quarter of 2007 ($75.7 million)
due to restricted asphalt sales, but were higher than the first quarter of
2007 ($57.6 million) due to generally higher refined product prices. Refining
costs of sales in the first quarter of 2008 ($71.4 million) were higher than
in the fourth quarter of 2007 ($70.9 million) and in the first quarter of 2007
($46.4 million) due to higher crude oil costs.Refinery throughput -
three months ended Mar 31, June 30, Sept 30, Dec 31, Mar 31,
2007 2007 2007 2007 2008
-------------------------------------------------------------------------
Crude charged (bbl/d)(1) 9,621 9,248 9,400 9,610 9,830
Refinery production
(bbl/d)(2) 10,634 10,085 10,478 10,578 11,081
Sales of produced
refined products (bbl/d) 7,777 9,753 12,906 10,629 7,408
Sales of refined
products (bbl/d)(3) 8,254 10,735 13,447 11,014 7,902
Refinery utilization(4) 101% 97% 100% 101% 104%
-------------------------------------------------------------------------
(1) Crude charged represents the barrels per day of crude oil processed
at the refinery.
(2) Refinery production represents the barrels per day of refined
products yielded from processing crude and other refinery feedstocks.
(3) Includes refined products purchased for resale.
(4) Represents crude charged divided by total crude capacity of the
refinery.
Feedstocks -
three months ended Mar 31, June 30, Sept 30, Dec 31, Mar 31,
2007 2007 2007 2007 2008
-------------------------------------------------------------------------
Sour crude oil 92% 93% 91% 93% 92%
Other feedstocks and
blends 8% 7% 9% 7% 8%
-------------------------------------------------------------------------
Total 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
Revenues and Margins ($000)
-------------------------------------------------------------------------
Refining sales revenue $57,596 $84,628 $95,093 $75,733 $71,899
Refining - crude oil
and operating costs 46,398 66,480 81,107 70,863 71,393
-------------------------------------------------------------------------
Refining margin $11,198 $18,148 $13,986 $4,870 $506
-------------------------------------------------------------------------
Refining margin 19.4% 21.4% 14.7% 6.4% 0.7%
-------------------------------------------------------------------------
Sales of Produced Refined
Products (Volume %)
-------------------------------------------------------------------------
Gasolines 52% 40% 31% 35.3% 47.2%
Diesel fuels 27% 18% 12% 15.8% 26.6%
Jet fuels 6% 5% 6% 6.2% 8.1%
Asphalt 11% 33% 48% 38.9% 12.7%
LPG and other 4% 4% 3% 3.8% 5.4%
-------------------------------------------------------------------------
Total 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
Per Barrel of Produced
Refined Product Sold
-------------------------------------------------------------------------
Refining sales revenue $77.53 $86.63 $76.87 $74.74 $99.99
Less: refining - crude
oil purchases and
operating costs 62.46 68.05 65.56 69.93 99.28
-------------------------------------------------------------------------
Refining margin $15.07 $18.58 $11.31 $4.81 $0.71
-------------------------------------------------------------------------INTEREST AND OTHER INCOME
In the first quarter of 2008, the company earned interest of $831,000
(March 31, 2007 - $120,000) on excess funds invested in secure short-term
investments. The company has not invested in asset-based commercial paper
investments.
GENERAL AND ADMINISTRATIVE EXPENSES
In the first quarter of 2008, general and administrative ("G&A") expenses
were $3.1 million compared to $3.6 million in the first quarter of 2007, a
decrease of 14 percent, as the company capitalized more costs in the current
period ($1.9 million) than in the first quarter of 2007 ($290,000) due to more
of these expenses for personnel engaged in this expanded capital program.
STOCK BASED COMPENSATION
The company recorded non-cash stock-based compensation charges in the
respective periods as follows:Three months
ended March 31
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Charged to G&A expense $1,516 $2,946
Capitalized to property and equipment 798 546
-------------------------------------------------------------------------
$2,314 $3,492
-------------------------------------------------------------------------The reduction from the prior is due to fewer options being granted and a
lower share price.
FINANCE CHARGES
Finance charges include interest expensed relating to the Convertible
Debentures and amounts drawn on revolving lines of credit, standby fees
associated with the company's undrawn lines of credit, fees on letters of
credit issued, and a portion of the Senior Notes interest expense attributable
to Great Divide Pod One since it was declared commercial, effective March 1,
2008. Finance charges also include non-cash accretion charges with respect to
the Convertible Debentures and a portion to the Senior Notes.
Expensed finance charges of $4.4 million in the first quarter of 2008
compared to $446,000 reported in the first of quarter of 2007. These charges
increased primarily due to the issuance of the Convertible Debentures and
Senior Notes in 2007.
FOREIGN EXCHANGE GAINS AND LOSSES
In the first quarter of 2008, the company recorded a foreign exchange
loss of $1.9 million with respect to the translation of its US dollar
denominated indebtness and its currency swap. An unrealized foreign exchange
gain of $1.7 million was recorded in the first quarter of 2007 upon
translating it US dollar denominated indebtness.
DEPLETION, DEPRECIATION AND ACCRETION ("DD&A")
Depletion expense is calculated using the unit-of-production method based
on total estimated proved reserves. Refining properties and other assets are
depreciated over their estimated useful lives. Effective March 1, 2008 Pod
One's accumulated capital costs were added to the depletion pool and are being
depleted from that date. DD&A in the first quarter of 2008 was $7.5 million, a
one percent increase from last year due to higher production volumes and
increased capital costs, offset somewhat by the benefit of a longer oil sands
reserve life related to Pod One. Depletion equates to $13.31 per boe of
production compared to $25.12 per boe last year, reflecting the benefit of
adding substantial Pod One proved reserves to the depletion calculation.
Capital costs of $125.3 million (March 31, 2007 - $239 million) related
to oil sands projects currently in the pre-production stage, and undeveloped
land acquisition costs of $14.9 million (2007 - $16.3 million) were excluded
from the depletion calculation. Future development costs of $253.1 million
(2007 - $3.2 million) for proved undeveloped reserves were included in the
depletion calculation.
Included in DD&A is an accretion charge of $422,000 (March 31, 2007 -
$191,000) in respect of the company's estimated asset retirement obligations.
These charges will continue in future years in order to accrete the currently
booked discounted liability of $24 million to the estimated total undiscounted
liability of $44.3 million over the remaining economic life of the company's
oil sands, crude oil and natural gas properties.
At March 31, 2008, the recoverable value of the company's productive
crude oil, oil sands and natural gas assets exceeded its carrying value and,
therefore, no ceiling test writedown was required.
INCOME TAXES
The income tax recovery of $1.3 million in the first three months of 2008
includes a current income tax provision of $817,000, principally related to
Canadian capital and other taxes and a future income tax recovery of
$2.1 million reflecting the benefit of increased tax pools during the period.
At March 31, 2008 the company had approximately $79 million of
non-capital losses which do not expire before 2028, $191 million of capital
losses which do not have an expiry date, $480 million of deductible resource
pools and $34 million of deductible financing costs.
EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED ("PETROLIFERA")
Connacher accounts for its 26 percent equity investment in Petrolifera on
the equity method basis of accounting. Connacher's equity interest share of
Petrolifera's earnings in the first three months of 2008 was $413,000 (March
31, 2007 - $3.9 million).
NET EARNINGS
In the first three months of 2008 the company reported a loss of
$1,833,000 ($0.01 loss per basic and diluted share outstanding) compared to
earnings of $5.0 million or $0.03 per basic and diluted share for the first
three months of 2007.
SHARES OUTSTANDING
For the first three months of 2008, the weighted average number of common
shares outstanding was 210,234,346 (2007 - 198,119,130) and the weighted
average number of diluted shares outstanding, as calculated by the treasury
stock method, was 210,234,346 (2007 - 200,007,743).
As at May 12, 2008, the company had the following equity securities
issued and outstanding:- 210,525,166 common shares;
- 19,471,893 share purchase options; and
- 392,705 share units ("SUs") under the non-employee director share
awards planAdditionally, 20,010,000 common shares are issuable upon conversion of
the Convertible Debentures. Details of the exercise provisions and terms of
the outstanding options are noted in the consolidated financial statements,
included in this interim report.
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 2008, the company had working capital of $287.1 million,
including $323.4 million of cash on hand. Of this amount $66 million was
restricted in an interest reserve account related to the Senior Notes.
At March 31, 2008 the company also had approximately $181 million
available to be drawn on its five-year term Revolving Credit Facilities, as
approximately $19 million was used to secure letters of credit primarily for
its crude oil purchase activity associated with the refining business.
Available cash, cash flow and funds available under its Revolving Credit
Facilities are anticipated to be sufficient to fully fund the company's
capital program in 2008 and to complete Algar in 2009. A significant part of
the company's capital program is discretionary and may be expanded or
curtailed based on drilling results and the availability of capital. This is
reinforced by the fact that Connacher operates most of its wells and holds a
very high working interest in all its properties, providing the company with
operational and timing controls.
Cash flow and cash flow per share do not have standardized meanings
prescribed by GAAP and therefore may not be comparable to similar measures
used by other companies. Cash flow includes all cash flow from operating
activities and is calculated before changes in non-cash working capital,
pension funding and asset retirement expenditures. The most comparable measure
calculated in accordance with GAAP is net earnings. Cash flow is reconciled
with net earnings on the Consolidated Statement of Cash Flows and below.
Cash flow per share is calculated by dividing cash flow by the calculated
weighted average number of shares outstanding. Management uses this non-GAAP
measurement (which is a common industry parameter) for its own performance
measure and to provide its shareholders and investors with a measurement of
the company's efficiency and its ability to fund future growth expenditures.
The company's only financial instruments are cash, restricted cash,
accounts receivable and payable, amounts due from Petrolifera, the Revolving
Credit Facilities, the Convertible Debentures, the Senior Notes and the
cross-currency swap. The company maintains no off-balance sheet financial
instruments.
As the Senior Notes are denominated in US dollars, there is a foreign
exchange risk associated with their repayment using Canadian currency. This
risk is partially mitigated by the cross currency swap.
The natural gas costless collar is intended to mitigate some downside
natural gas pricing risk and, therefore, protect the risk of reduced cash flow
and the risk of reductions to the lending value of its banking facilities,
which is considered particularly important in a time of rapid growth with
significant capital expenditure.Connacher's capital structure is composed of:
As at As at
March 31, 2008 December 31, 2007
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Long term debt(1) $671,014 $664,462
Shareholders' equity
Share capital, contributed surplus
and equity component 433,530 444,086
Accumulated other comprehensive loss (10,127) (13,636)
Retained earnings 48,156 49,989
-------------------------------------------------------------------------
Total $1,142,573 $1,144,901
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Debt to book capitalization(2) 59% 58%
Debt to market capitalization(3) 49% 44%
-------------------------------------------------------------------------
(1) Long-term debt is stated at its carrying value, which is net of fair
value adjustments, original issue discounts, transaction costs and
the Convertible Debentures' equity component value.
(2) Calculated as long-term debt divided by the book value of
shareholders' equity plus long-term debt.
(3) Calculated as long-term debt divided by the period end market value
of shareholders' equity plus long-term debt.Connacher had a high calculated ratio of debt to capitalization at March
31, 2008. This is due to pre-funding the full cost of Algar in 2007, through
the issuance of US $600 million of Senior Notes. As at March 31, 2008, the
company's calculated ratio of net debt (long-term debt, net of cash on hand)
to book capitalization was 30 percent and the percentage of net debt to market
capitalization was 25 percent.
In the first quarter of 2008, Pod One, the company's first oil sands
facility, had commenced commercial operations. It is anticipated that Pod One
will attain its design capacity of 10,000 bbl/d of bitumen production during
2008. This is expected to result in substantially higher levels of revenue and
cash flow for the company. This cash flow, together with cash deposited in a
debt service account, are anticipated to be more than sufficient to fund the
company's interest costs in 2008.Reconciliation of net earnings to cash flow from operations before working
capital and other changes:
Three months ended March 31
2008 2007
-------------------------------------------------------------------------
($000s)
-------------------------------------------------------------------------
Net earnings (loss) $(1,833) $4,984
Items not involving cash:
Depletion, depreciation and accretion 7,464 7,357
Stock-based compensation 1,516 2,946
Finance charges - non-cash portion 1,249 -
Future employee benefits 113 130
Future income tax provision (recovery) (2,163) 1,165
Foreign exchange (gain) loss 1,892 (1,702)
-------------------------------------------------------------------------
Equity interest in Petrolifera earnings (413) (3,900)
-------------------------------------------------------------------------
Cash flow from operations before working
capital and other changes $7,825 $10,980
-------------------------------------------------------------------------In the first quarter of 2008, cash flow was $7.8 million ($0.04 per basic
and $0.03 per diluted share), 29 percent lower than the $11 million reported
($0.06 per basic and $0.05 per diluted share) for the first three months of
2007, primarily due to lower refining margins compared to the first quarter
last year.
Senior Notes
In December 2007 the company issued US $600 million second lien
eight-year notes ("Senior Notes") at an issue price of 98.657 for net proceeds
of US $575 million after fees and expenses. A portion of the proceeds was used
to repay the US $180 million Oil Sands Term Loan, to fully repay drawn amounts
and then cancel the company's conventional oil and gas line of credit and to
fund a one-year interest reserve account in the amount of US $63.6 million.
The remainder of the proceeds are targeted to partially fund the construction
of Algar.To March 31, 2008, the proceeds of the Senior Note financing have been
utilized as follows:
As stated at As actually
the time of financing(1) applied(1)
-------------------------------------------------------------------------
($000s)
-------------------------------------------------------------------------
Gross proceeds $576,380 $591,942
Underwriters commissions
and issue costs (13,380) (16,493)
-------------------------------------------------------------------------
Repayment of Oil Sands Term Loan (186,000) (180,000)
-------------------------------------------------------------------------
Funding interest reserve account (66,000) (63,600)
-------------------------------------------------------------------------
Repay the conventional line of credit - (2,500)
-------------------------------------------------------------------------
Net proceeds for the
construction of Algar(2) $311,000 $329,349
-------------------------------------------------------------------------
(1) The Canadian dollar equivalent changed between the dates of
announcing and closing the financing due to significant changes in
the CDN/US exchange rates in late 2007.
(2) Net proceeds are available for funding capital expenditures relating
to Algar. As at March 31, 2008, approximately $14 million had been
spent in respect of these expenditures.
PROPERTY AND EQUIPMENT ADDITIONS
Property and equipment additions totaled $116 million in the first quarter
of 2008 (first quarter 2007 - $110 million). A breakdown of these additions
follows:
Three months ended March 31
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Crude oil, natural gas and oil sands $112,957 $106,794
Refinery expenditures 3,027 3,117
-------------------------------------------------------------------------
$115,984 $109,881
-------------------------------------------------------------------------Oil sands expenditures of $83 million were incurred in the first quarter
of 2008 for exploratory core hole drilling, seismic shooting and processing,
some preliminary facility expenditures for Algar and Pod One pre-operating
costs in excess of bitumen revenues which were capitalized. In the first three
months of 2008, 128 exploratory core holes were drilled. In the first quarter
of 2007, $86 million was spent to drill 75 exploratory core holes and to shoot
and process seismic data.
Conventional oil and gas expenditures of $30 million in the first quarter
of 2008 include costs of drilling, completing, equipping and working over
conventional oil and gas wells, undeveloped land acquisition, seismic
expenditures and facility expenditures. In the first quarter of 2008, the
company drilled 20 (16.5 net) crude oil and natural gas wells, resulting in 13
(10.5 net) gas wells; one (one net) suspended gas well, three (two net) oil
wells; and three (three net) abandoned wells. In the first quarter of 2007,
$20 million was incurred to drill 19 (18 net) oil and gas wells.
OUTLOOK
The company's business plan anticipates continued growth, with stronger
production revenue and cash flow as Pod One achieved commerciality effective
March 1, 2008. Emphasis will continue to be placed on delineating and
developing more production projects at Great Divide, while developing the
company's recently-expanded conventional production base and profitably
operating the Montana refinery. Additional financing may be required for
future projects at Great Divide, development of conventional petroleum and
natural gas assets and for the Montana refinery, especially if a decision is
made to expand simultaneously and not sequentially.
The company's first 10,000 bbl/d oil sands project, Pod One, was
completed on schedule in 2007. Fourteen of the fifteen horizontal well pairs
are presently producing in excess of 7,000 bbl/d. It is anticipated that the
targeted bitumen production volume of 10,000 bbl/d will be achieved in 2008.
The company's second project, Algar, is expected to commence a 10-month
period of construction in the second half of 2008, following receipt of the
necessary governmental regulatory approvals. Algar's design is similar to that
of Pod One and its construction timetable is expected to be comparable.
Production from Algar is anticipated to commence in late 2009 or early 2010
and, following ramp up, to add an additional 10,000 bbl/d to Connacher's
growing production base. The cost of Algar is budgeted at $326 million, as it
incorporates scope changes and increased infrastructure costs relative to Pod
One. The cost of the Algar project was fully funded in December 2007.
Additional 10,000 bbl/d oil sands projects (Pods) are anticipated,
subject to confirmation of definitive additional reserves and resources. The
timing of additional Pods is dependent on a number of factors which are
outside of the control of the company, including the regulatory process.
Connacher has increased its 2008 firm and contingent capital expenditure
budget to $391 million from $373 million to provide for increased capital
outlays on conventional assets, following a successful winter 2008 drilling
program, and for oil terminal and related facilities at Great Divide, with
these increases offset by the deferral of some anticipated expenditures at the
Montana refinery.
Information relating to Connacher, including Connacher's Annual
Information Form is on SEDAR at www.sedar.com. See also the company's website
at www.connacheroil.com.
SIGNIFICANT ACCOUNTING POLICIES AND APPLICATION OF CRITICAL ACCOUNTING
ESTIMATES
The significant accounting policies used by the company are described
below. Certain accounting policies require that management make appropriate
decisions with respect to the formulation of estimates and assumptions that
affect the reported amounts of assets, liabilities, revenues and expenses.
Changes in these estimates and assumptions may have a material impact on the
company's financial results and condition. The following discusses such
accounting policies and is included herein to aid the reader in assessing the
critical accounting policies and practices of the company and the likelihood
of materially different results being reported. Management reviews its
estimates and assumptions regularly. The emergence of new information and
changed circumstances may result in changes to estimates and assumptions which
could be material and the company might realize different results from the
application of new accounting standards promulgated, from time to time, by
various regulatory rule-making bodies.
The following assessment of significant accounting polices and critical
accounting estimates is not meant to be exhaustive.
Reserve Estimates
Under Canadian Securities Administrators' "National Instrument
51-101-Standards of Disclosure for Oil and Gas Activities" ("NI 51-101")
proved reserves are those reserves that can be estimated with a high degree of
certainty to be recoverable. In accordance with this definition, the level of
certainty should result in at least a 90 percent probability that the
quantities actually recovered will exceed the estimated reserves. In the case
of probable reserves, which are less certain to be recovered than proved
reserves, NI 51-101 states that it must be equally likely that the actual
remaining quantities recovered will be greater or less than the sum of the
estimated proved plus probable reserves. Possible reserves are those reserves
less certain to be recovered than probable reserves. There is at least a 10
percent probability that the quantities actually recovered will exceed the sum
of proved plus probable plus possible reserves.
The company's oil and gas reserve estimates are made by independent
reservoir engineers using all available geological and reservoir data as well
as historical production data. Estimates are reviewed and revised as
appropriate. Revisions occur as a result of changes in prices, costs, fiscal
regimes, reservoir performance or a change in the company's plans. The reserve
estimates can also be used in determining the company's borrowing base for its
credit facilities and may impact the same upon revision or changes to the
reserve estimates. The effect of changes in reserve estimates on the financial
results and financial position of the company is described below.
Full Cost Accounting for Oil and Gas Activities
The company uses the full cost method of accounting for exploration and
development activities. In accordance with this method of accounting, all
costs associated with exploration and development are capitalized whether
successful or not. The aggregate of net capitalized costs and estimated future
development costs is depleted using the unit-of-production method based on
estimated proved reserves. A change in estimated total proved reserves could
significantly affect the company's calculation of depletion.
Major Development Projects and Unproved Properties
Certain costs related to acquiring and evaluating unproved properties are
excluded from net capitalized costs subject to depletion until proved reserves
have been determined or their value is impaired. Costs associated with major
development projects are not depleted until commencement of commercial
operations. All capitalized costs are reviewed quarterly and any impairment is
transferred to the costs being depleted or, if the properties are located in a
cost centre where there is no reserve base, the impairment is charged directly
to income.
All costs related to the Great Divide oil sands project are being
capitalized to specific projects, or "Pods", pending commencement of
commercial operations from each Pod. Upon commencement of commercial
operations of a Pod, the related capital costs and estimates of future capital
requirements for such Pod will be added to the company's depletable costs and
depleted under the unit-of-production method based on the company's total
proved reserves. Effective March 1, 2008, the company's first oil sands
project, Pod One, was declared commercially operative and its related costs
were added to the company's depletable cost pool.
Ceiling Test
The company is required to review the carrying value of all property,
plant, and equipment, including the carrying value of its conventional and its
commercially operative oil sands properties, for potential impairment.
Impairment is indicated if the carrying value of the long-lived asset or oil
and gas cost centre is not recoverable by the future undiscounted cash flows.
If impairment is indicated, the amount by which the carrying value exceeds the
estimated fair value of the long-lived asset is charged to earnings.
The ceiling test is based on estimates of reserves prepared by qualified
independent evaluators, production rate, crude oil, bitumen and natural gas
prices, future costs and other relevant assumptions. By their nature, reserve
estimates are subject to measurement uncertainty and the impact of ceiling
test calculations on the consolidated financial statements of changes to
reserve estimates could be material.
Asset Retirement Obligations
The company is required to provide for future removal and site
restoration costs by estimating these costs in accordance with existing laws,
contracts or other policies. These estimated costs are charged to earnings and
the appropriate liability account over the expected service life of the asset.
When the future removal and site restoration costs cannot be reasonably
determined, a contingent liability may exist. Contingent liabilities are
charged to earnings only when management is able to determine the amount and
the likelihood of the future obligation. The company estimates future
retirement costs based on current costs as estimated by the company's
engineers, adjusted for inflation and credit risk. These estimates are subject
to measurement uncertainty.
Legal, Environmental Remediation and Other Contingent Matters
In respect of these matters, the company is required to determine whether
a loss is probable, based on judgment and interpretation of laws and
regulations and also to determine if such a loss can be estimated. When any
such loss is determined, it is charged to earnings. Management continually
monitors known and potential contingent matters and makes appropriate
provisions by charges to earnings when warranted by circumstance.
Income Taxes
The company follows the liability method of accounting for income taxes.
Under this method, tax assets are recognized when it is more than likely that
realization will occur. Tax liabilities are recognized for temporary
differences between recorded book values and underlying tax values. Rates used
to determine income tax asset and liability amounts are enacted tax rates
expected to be used in future periods, when the timing differences reverse.
The period in which timing differences reverse is impacted by future income
and capital expenditures. Rates are also affected by legislative changes.
These components can impact the charge for future income taxes.
Stock-Based Compensation
The company uses the fair value method to account for stock options. The
determination of the amounts for stock-based compensation are based on
estimates of stock volatility, interest rates and the term of the option. By
their nature, these estimates are subject to measurement uncertainty.
NEW SIGNIFICANT ACCOUNTING POLICIES
As of January 1, 2008, the company adopted new CICA Handbook, Section
3862, "Financial Instruments - Disclosures" and Section 3863, "Financial
Instruments - Presentation" which replaced former Section 3861. The new
standards require disclosure of the significance of financial instruments to
an entity's financial statements, the risks associated with the financial
instruments and how those risks are managed.
As of January 1, 2008, the company also adopted new CICA Handbook Section
1535, "Capital Disclosures" which requires entities to disclose their
objectives, policies and processes for managing capital and, in addition,
whether the entity has complied with any externally imposed capital
requirements.
In February 2008, the CICA issued Section 3064, "Goodwill and Intangible
Assets", replacing Section 3062, "Goodwill and Other Intangible Assets" and
Section 3450, "Research and Development Costs." The new Sections will be
applicable to financial statements relating to fiscal years beginning on or
after October 1, 2008. Accordingly, the company will adopt the new standards
for its fiscal year beginning January 1, 2009. Section 3064 establishes
standards for the recognition, measurement, presentation and disclosure of
goodwill subsequent to its initial recognition and of intangible assets by
profit-oriented enterprises. Standards concerning goodwill are unchanged from
the standards included in the previous Section 3062, and therefore are not
anticipated to have a significant impact on the company's financial
statements.
INTERNATIONAL FINANCIAL REPORTING STANDARDS
In January 2006, the Canadian Accounting Standards Board adopted a
strategic plan for the direction of accounting standards in Canada. As part of
the plan, Canadian GAAP for public companies will converge with International
Financial Reporting Standards ("IFRS") over the next few years. The company is
currently assessing the impact of the convergence of Canadian GAAP with IFRS
on its financial statements and expects to begin work on the conversion
process later in 2008.
RISK FACTORS AND RISK MANAGEMENT
Connacher is exposed to risks and uncertainties inherent in the oil and
gas exploration, development, production and refining industry. A detailed
summary of the company's risks and uncertainties is included in the company's
2007 Annual Information Form and in MD&A included in the company's 2007 annual
report, which are available on SEDAR at www.sedar.com and on the company's
website at www.connacheroil.com.
Some of the more significant risks affecting Connacher's operating
results and financial in the first quarter of 2008 related to changing
commodity prices, which were influenced by a weaker US dollar. The average WTI
selling price increased by approximately 68 percent to $97.90/bbl in the first
quarter of 2008. Additionally, the heavy oil : light oil pricing differential
narrowed. These two factors were the main reasons that refining margins shrank
from 19 percent in the first quarter of 2007 to one percent in the first
quarter of 2008. However, these two factors had a positive impact on pricing
the company's first quarter bitumen and crude oil revenues, reflecting the
benefit of the company's integrated business model.
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by the company is accumulated, recorded,
processed, summarized and reported to the company's management as appropriate
to allow timely decisions regarding required disclosure. The company's Chief
Executive Officer and Chief Financial Officer have concluded, based on their
evaluation as of the end of the period covered by this MD&A, that the
company's disclosure controls and procedures as of the end of such period are
effective to provide reasonable assurance that material information related to
the company, including its consolidated subsidiaries, is communicated to them
as appropriate to allow timely decisions regarding required disclosure.
INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the company is responsible for designing adequate internal
controls over the company's financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with Canadian
GAAP. There have been no changes in the company's systems of internal control
over financial reporting that would materially affect, or is reasonably likely
to materially affect, the company's internal controls over financial
reporting.
It should be noted that while the company's Chief Executive Officer and
Chief Financial Officer believe that the company's disclosure controls and
procedures provide a reasonable level of assurance that they are effective and
that the internal controls over financial reporting are adequately designed,
they do not expect that the financial disclosure controls and procedures or
internal control over financial reporting will prevent all errors and fraud. A
control system, no matter how well conceived or operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system
are met. In reaching a reasonable level of assurance, management necessarily
is required to apply its judgment in evaluating the cost-benefit relationship
of possible controls and procedures.
QUARTERLY RESULTS
Fluctuations in results over the previous eight quarters are due
principally to variations in oil and gas prices and production/sales volumes.-------------------------------------------------
2006
-------------------------------------------------
Three Months Ended Jun 30 Sept 30 Dec 31
-------------------------------------------------
Financial Highlights
($000 except per
share amounts) -
Unaudited
-------------------------------------------------
Revenues 61,239 103,110 76,700
-------------------------------------------------
Cash flow(1) 9,499 14,957 14,015
-------------------------------------------------
Basic, per share(1) 0.05 0.08 0.08
-------------------------------------------------
Diluted, per
share(1) 0.05 0.08 0.07
-------------------------------------------------
Net earnings (loss) (2,419) 6,771 3,267
-------------------------------------------------
Basic and diluted
per share (0.01) 0.03 0.02
-------------------------------------------------
Property and equip-
ment additions 34,280 41,449 74,960
-------------------------------------------------
Cash on hand 7,505 14,450 142,391
-------------------------------------------------
Working capital
surplus
(deficiency) (42,483) (39,942) 118,626
-------------------------------------------------
Debt 70,365 62,380 229,254
-------------------------------------------------
Shareholders'
equity 340,639 378,730 385,398
-------------------------------------------------
Operating Highlights
-------------------------------------------------
Daily production/
sales volumes
-------------------------------------------------
Natural gas -
mcf/d 15,172 12,711 11,291
-------------------------------------------------
Bitumen - bbl/d(2) - - -
-------------------------------------------------
Crude oil - bbl/d 1,026 1,059 1,139
-------------------------------------------------
Equivalent -
boe/d(3) 3,554 3,177 3,021
-------------------------------------------------
Product pricing
-------------------------------------------------
Crude oil - $/bbl 61.45 62.53 46.65
-------------------------------------------------
Bitumen - $/bbl(2) - - -
-------------------------------------------------
Natural gas - $/mcf 5.66 5.33 6.57
-------------------------------------------------
Selected Highlights -
$/boe(3)
-------------------------------------------------
Weighted average
sales price 41.88 42.16 42.15
-------------------------------------------------
Royalties 10.43 10.72 9.00
-------------------------------------------------
Operating costs 7.63 7.99 9.27
-------------------------------------------------
Netback(4) 23.82 23.45 23.88
-------------------------------------------------
Refining throughput
-------------------------------------------------
Crude charged (bbl/d) 6,864 9,613 9,642
-------------------------------------------------
Refining
utilization (%) 83 101 102
-------------------------------------------------
Margins (%) 8 16 15
-------------------------------------------------
Common Share Information
-------------------------------------------------
Shares outstanding
at end of period
(000) 191,924 197,878 197,894
-------------------------------------------------
Weighted average
shares outstanding
for the period
-------------------------------------------------
Basic (000) 191,672 193,587 193,884
-------------------------------------------------
Diluted (000) 198,931 200,572 204,028
-------------------------------------------------
Volume traded
during quarter
(000) 80,347 48,849 46,444
-------------------------------------------------
Common share
price ($)
-------------------------------------------------
High 5.05 4.55 4.43
-------------------------------------------------
Low 3.10 3.09 3.17
-------------------------------------------------
Close (end of
period) 4.30 3.60 3.49
-------------------------------------------------
---------------------------------------------------------------------
2007 2008
---------------------------------------------------------------------
Three Months Ended Mar 31 June 30 Sept 30 Dec 31 Mar 31
---------------------------------------------------------------------
Financial Highlights
($000 except per
share amounts) -
Unaudited
---------------------------------------------------------------------
Revenues 65,923 93,266 101,991 83,340 100,656
---------------------------------------------------------------------
Cash flow(1) 10,980 16,876 10,025 7,084 7,825
---------------------------------------------------------------------
Basic, per share(1) 0.06 0.09 0.05 0.03 0.04
---------------------------------------------------------------------
Diluted, per
share(1) 0.05 0.08 0.05 0.03 0.03
---------------------------------------------------------------------
Net earnings (loss) 4,984 22,228 14,589 (840) (1,833)
---------------------------------------------------------------------
Basic and diluted
per share 0.03 0.11 0.07 0.00 (0.01)
---------------------------------------------------------------------
Property and equip-
ment additions 109,881 93,223 64,006 55,852 115,984
---------------------------------------------------------------------
Cash on hand 66,209 25,375 754 392,271 323,423
---------------------------------------------------------------------
Working capital
surplus
(deficiency) 24,027 36,320 (19,853) 389,789 287,105
---------------------------------------------------------------------
Debt 207,828 272,559 260,606 664,462 671,014
---------------------------------------------------------------------
Shareholders'
equity 384,593 417,793 428,764 480,439 471,559
---------------------------------------------------------------------
Operating Highlights
---------------------------------------------------------------------
Daily production/
sales volumes
---------------------------------------------------------------------
Natural gas -
mcf/d 9,665 9,017 9,413 8,889 10,493
---------------------------------------------------------------------
Bitumen - bbl/d(2) - - - - 1,773
---------------------------------------------------------------------
Crude oil - bbl/d 905 731 781 752 996
---------------------------------------------------------------------
Equivalent -
boe/d(3) 2,515 2,234 2,350 2,233 4,518
---------------------------------------------------------------------
Product pricing
---------------------------------------------------------------------
Crude oil - $/bbl 49.09 49.79 55.98 56.79 79.50
---------------------------------------------------------------------
Bitumen - $/bbl(2) - - - - 53.01
---------------------------------------------------------------------
Natural gas - $/mcf 7.76 7.02 4.70 5.82 6.94
---------------------------------------------------------------------
Selected Highlights -
$/boe(3)
---------------------------------------------------------------------
Weighted average
sales price 47.48 44.63 37.43 42.29 54.46
---------------------------------------------------------------------
Royalties 11.22 3.23 6.32 6.34 7.45
---------------------------------------------------------------------
Operating costs 8.54 13.08 9.00 13.77 14.32
---------------------------------------------------------------------
Netback(4) 27.72 28.32 22.11 22.18 32.69
---------------------------------------------------------------------
Refining throughput
---------------------------------------------------------------------
Crude charged (bbl/d) 9,621 9,248 9,400 9,610 9,830
---------------------------------------------------------------------
Refining
utilization (%) 101 97 100 101 104
---------------------------------------------------------------------
Margins (%) 19 21 15 6 1
---------------------------------------------------------------------
Common Share Information
---------------------------------------------------------------------
Shares outstanding
at end of period
(000) 198,218 198,834 199,447 209,971 210,277
---------------------------------------------------------------------
Weighted average
shares outstanding
for the period
---------------------------------------------------------------------
Basic (000) 198,119 198,360 198,539 204,701 210,234
---------------------------------------------------------------------
Diluted (000) 200,008 209,088 210,580 220,362 231,510
---------------------------------------------------------------------
Volume traded
during quarter
(000) 55,292 61,162 70,939 52,198 63,718
---------------------------------------------------------------------
Common share
price ($)
---------------------------------------------------------------------
High 4.13 4.43 4.40 4.08 3.94
---------------------------------------------------------------------
Low 3.07 3.07 3.20 3.31 2.59
---------------------------------------------------------------------
Close (end of
period) 3.86 3.69 4.01 3.79 3.13
---------------------------------------------------------------------
(1) Cash flow and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures used
by other companies. Cash flow is calculated before changes in non-
cash working capital, pension funding and asset retirement
expenditures. The most comparable measure calculated in accordance
with GAAP would be net earnings. Cash flow is reconciled with net
earnings on the Consolidated Statement of Cash Flows and in the
accompanying Management Discussion & Analysis. Management uses these
non-GAAP measurements for its own performance measures and to provide
its shareholders and investors with a measurement of the company's
efficiency and its ability to internally fund future growth
expenditures.
(2) The recognition of bitumen sales from Great Divide Pod One commenced
March 1, 2008, when it was declared 'commercial'. Prior thereto, all
operating costs, net of revenues, were capitalized.
(3) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 mcf : 1 bbl. Boes may be misleading, particularly if
used in isolation. This conversion is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.
(4) Netback is a non-GAAP measure used by management as a measure of
operating efficiency and profitability. It is calculated as crude
oil, bitumen and natural gas revenue less royalties and operating
costs. Netbacks are reconciled to net earnings in the accompanying
MD&A.
Connacher Oil and Gas Limited
CONSOLIDATED BALANCE SHEETS
(Unaudited)
-------------------------------------------------------------------------
($000) March 31, 2008 December 31, 2007
-------------------------------------------------------------------------
ASSETS
CURRENT
Cash $257,489 $329,110
Restricted cash (Note 9(c)) 65,934 63,161
Accounts receivable 52,581 25,084
Inventories (Note 5) 38,033 18,379
Income taxes recoverable 4,867 4,279
Prepaid expenses 1,528 2,520
Due from Petrolifera 7 -
-------------------------------------------------------------------------
420,439 442,533
Property and equipment 782,725 671,422
Goodwill 103,676 103,676
Investment in Petrolifera 36,023 35,610
Deferred costs 5,235 5,587
-------------------------------------------------------------------------
$1,348,098 $1,258,828
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
CURRENT
Accounts payable and accrued liabilities $133,334 $52,744
-------------------------------------------------------------------------
133,334 52,744
Long term debt (Note 4(e)) 671,014 664,462
Future income taxes 48,081 36,818
Asset retirement obligations (Note 6) 23,995 24,365
Employee future benefits 115 -
-------------------------------------------------------------------------
876,539 778,389
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital, contributed surplus and
equity component (Note 7) 433,530 444,086
Retained earnings 48,156 49,989
Accumulated other comprehensive loss (10,127) (13,636)
-------------------------------------------------------------------------
471,559 480,439
-------------------------------------------------------------------------
$1,348,098 $1,258,828
-------------------------------------------------------------------------
Connacher Oil and Gas Limited
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
Three Months Ended March 31
(Unaudited)
-------------------------------------------------------------------------
($000, except per share amounts) 2008 2007
-------------------------------------------------------------------------
REVENUES
Upstream, net of royalties $27,926 $8,207
Downstream 71,899 57,596
Interest and other income 831 120
-------------------------------------------------------------------------
100,656 65,923
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EXPENSES
Upstream - diluent purchases and
operating costs 13,992 1,932
Upstream transportation costs 494 -
Downstream - crude oil purchases and
operating costs (Note 5) 71,393 46,398
General and administrative 3,066 3,584
Stock-based compensation (Note 7(a)) 1,516 2,946
Finance charges 4,431 446
Foreign exchange loss (gain) 1,892 (1,702)
Depletion, depreciation and accretion 7,464 7,357
-------------------------------------------------------------------------
104,248 60,961
-------------------------------------------------------------------------
Earnings (loss) before income taxes and
other items (3,592) 4,962
Current income tax provision 817 2,713
Future income tax provision (recovery) (2,163) 1,165
-------------------------------------------------------------------------
(1,346) 3,878
-------------------------------------------------------------------------
Earnings (loss) before other items (2,246) 1,084
Equity interest in Petrolifera earnings 413 3,900
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS (LOSS) (1,833) 4,984
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RETAINED EARNINGS, BEGINNING OF PERIOD 49,989 9,028
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF PERIOD $48,156 $14,012
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EARNINGS PER SHARE (Note 9 (a))
Basic $(0.01) $0.03
Diluted $(0.01) $0.03
-------------------------------------------------------------------------
Connacher Oil and Gas Limited
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended March 31
(Unaudited)
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Net earnings (loss) $(1,833) $4,984
Foreign currency translation adjustment 3,509 (561)
-------------------------------------------------------------------------
Comprehensive income $1,676 $4,423
-------------------------------------------------------------------------
-------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE LOSS
Three Months Ended March 31
(Unaudited)
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Balance, beginning of period $(13,636) $(130)
Foreign currency translation adjustment 3,509 (561)
-------------------------------------------------------------------------
Balance, end of period $(10,127) $(691)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Connacher Oil and Gas Limited
CONSOLIDATED STATEMENTS OF CASH FLOW
Three Months Ended March 31
(Unaudited)
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Cash provided by (used in) the following
activities:
OPERATING
Net earnings (loss) $(1,833) $4,984
Items not involving cash:
Depletion, depreciation and accretion 7,464 7,357
Stock-based compensation 1,516 2,946
Finance charges - non cash portion 1,249 -
Employee future benefits 113 130
Future income tax provision (recovery) (2,163) 1,165
Foreign exchange loss (gain) 1,892 (1,702)
Equity interest in Petrolifera earnings (413) (3,900)
-------------------------------------------------------------------------
Cash flow from operations before working
capital and other changes 7,825 10,980
Asset retirement expenditures (123) -
Changes in non-cash working capital
(Note 9(b)) 21,770 6,922
-------------------------------------------------------------------------
29,472 17,902
-------------------------------------------------------------------------
FINANCING
Issue of common shares, net of share issue
costs (Note 7) 17 280
Increase in bank debt - 27,600
Repayment of bank debt - (9,000)
Deferred financing costs (82) -
-------------------------------------------------------------------------
(65) 18,880
-------------------------------------------------------------------------
INVESTING
Acquisition and development of oil and
gas properties (114,055) (105,294)
(Increase) decrease in restricted cash (2,773) 56,579
Change in non-cash working capital
(Note 9(b)) 12,400 (7,105)
-------------------------------------------------------------------------
(104,428) (55,820)
-------------------------------------------------------------------------
NET DECREASE IN CASH (75,021) (19,038)
Impact of foreign exchange on foreign
currency denominated cash balances 3,400 (565)
CASH, BEGINNING OF PERIOD 329,110 19,603
-------------------------------------------------------------------------
CASH, END OF PERIOD $257,489 $-
-------------------------------------------------------------------------
Supplementary information - Note 9
-------------------------------------------------------------------------
Connacher Oil and Gas Limited
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Period ended March 31, 2008
(Unaudited)
1. FINANCIAL STATEMENT PRESENTATION
The Consolidated Financial Statements include the accounts of Connacher
Oil and Gas Limited and its subsidiaries (collectively "Connacher" or the
"company") and are presented in accordance with Canadian generally
accepted accounting principles. Operating in Canada, and in the U.S.
through its subsidiary, Montana Refining Company, Inc. ("MRCI"), the
company is in the business of exploring, developing, producing, refining
and marketing crude oil, bitumen and natural gas.
2. SIGNIFICANT ACCOUNTING POLICIES
The interim Consolidated Financial Statements have been prepared
following the same accounting policies and methods of computation as
indicated in the annual audited Consolidated Financial Statements for the
year ended December 31, 2007, except as described in Note 3. The
disclosures provided below do not conform in all respects to those
included with the annual audited Consolidated Financial Statements. The
interim Consolidated Financial Statements should be read in conjunction
with the annual audited Consolidated Financial Statements and the notes
thereto for the year ended December 31, 2007.
3. NEW ACCOUNTING STANDARDS
Effective January 1, 2008, the company adopted new CICA Handbook, Section
3862, "Financial Instruments - Disclosures" and Section 3863, "Financial
Instruments - Presentation" which replaced former Section 3861. The new
standards require disclosure of the significance of financial instruments
to an entity's financial statements, the risks associated with the
financial instruments and how those risks are managed.
As of January 1, 2008, the company also adopted new CICA Handbook Section
1535, "Capital Disclosures" which requires entities to disclose their
objectives, policies and processes for managing capital and, in addition,
whether the entity has complied with any externally imposed capital
requirements.
In February 2008, the CICA issued Section 3064, "Goodwill and Intangible
Assets," replacing Section 3062, "Goodwill and Other Intangible Assets"
and Section 3450, "Research and Development Costs," applicable to
financial statements relating to fiscal years beginning on or after
October 1, 2008. The company will adopt the new standards for its fiscal
year beginning January 1, 2009. Section 3064 establishes standards for
the recognition, measurement, presentation and disclosure of goodwill
subsequent to its initial recognition and of intangible assets by profit-
oriented enterprises. Standards concerning goodwill are unchanged from
the standards included in the previous Section 3062, and therefore are
not anticipated to have a significant impact on the company's financial
statements.
4. FINANCIAL INSTRUMENTS AND CAPITAL RISK MANAGEMENT
The company is exposed to financial risks on a range of financial
instruments including its cash, accounts receivable and payable, amounts
due from/to Petrolifera, its Revolving Credit Facilities, the Convertible
Debentures, the Senior Notes, the cross currency swap and the natural gas
costless collar. The company is also exposed to risks in the way it
finances its capital requirements. The company manages these financial
and capital structure risks by operating in a manner that minimizes its
exposures to volatility of the company's financial performance. These
risks affecting the company are discussed below. No significant changes
have occurred in either the company's risk exposure or its risk
management strategy in the current period.
(a) Credit risk
Credit risk is the risk that a contracting entity will not fulfill its
obligations under a financial instrument and cause a financial loss to
the company. To help manage this risk, the company has a policy for
establishing credit limits, requiring collateral before extending credit
to customers where appropriate and monitoring outstanding accounts
receivable. The majority of the company's financial assets arise from the
sale of crude oil, bitumen, natural gas and refined products to a number
of large integrated oil companies and product retailers and are subject
to normal industry credit risks. The fair value of accounts receivable
and accounts payable are represented by their carrying values due to the
relatively short periods to maturity of these instruments. The maximum
exposure to credit risk is represented by the carrying amount on the
consolidated balance sheet. The company regularly assesses its financial
assets for impairment losses. There are no material financial assets that
the company considers past due or any allowances for uncollectible
accounts.
(b) Market risk
Market risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in market prices.
The company is exposed to market risk as a result of potential changes in
the market prices of its crude oil, bitumen, natural gas and refined
product sales volumes.
A portion of this risk is mitigated by Connacher's integrated business
model. The cost of purchasing natural gas for use in its oil sands and
refinery operations is offset by the company's monthly conventional
natural gas sales; and the majority of the company's monthly bitumen
sales is offset by its monthly purchases of heavy crude oil required for
processing at its refinery. Petroleum commodity futures contracts, price
swaps and collars may be utilized to reduce exposure to price
fluctuations associated with the sales of additional natural gas and
crude oil sales volumes and for the sale of refined products.
As part of the company's risk management strategy, a natural gas costless
collar contract has been put in place effective for the period April 1 to
October 31, 2008. The collar has a floor price of US $7.50/mmbtu and a
ceiling price of US $10.05/mmbtu on a notional volume of 5,000 mmbtu per
day of natural gas sales. The intent of this natural gas pricing collar
was not to speculate on future natural gas prices, but rather to protect
the downside risk to the company's cash flow and the lending value of its
assets, which is considered very important during a period of rapid
growth with significant capital expenditures. The risk in implementing
the collar is that future natural gas prices could escalate beyond the
ceiling price, limiting the company's natural gas revenue. As at March
31, 2008 the carrying value of this contract was adjusted to its
calculated fair value and resulted in a reduction of Upstream Revenues
and an accrued liability of $816,000. A $0.50 per mcf decrease in natural
gas prices would have resulted in an increase in earnings of $200,000 and
a $0.50 per mcf increase in natural gas prices would have resulted in a
decrease in earnings of $227,000 due to the sensitivity of the natural
gas collar at March 31, 2008 as determined by an option pricing model.
(c) Interest rate risk
Interest rate risk refers to the risk that the fair value or future cash
flows of a financial instrument will fluctuate because of changes in
market interest rates. The fair values of the company's cross-currency
and interest rate swaps are influenced by changes in interest rates. A 25
basis point change in interest rates would result in approximately a $1.9
million change in the fair value of the company's cross-currency and
interest rate swaps.
(d) Currency risk
Currency risk is the risk that the fair value or future cash flows of a
financial instrument will fluctuate because of changes in foreign
exchange rates.
As Connacher incurs the majority of its expenditures in Canadian dollars,
it is exposed to the impact of fluctuations in the US/Canadian dollar
exchange rate on pricing of its sales of crude oil and bitumen (which are
generally priced by reference to US dollars but settled in Canadian
dollars) and for the translation of its US refining operating results and
its US dollar denominated Senior Notes to Canadian dollars for financial
statement reporting purposes.
In order to mitigate half of the foreign exchange exposure on the Senior
Notes, the company entered into a cross currency swap to fix one half of
the Senior Notes' principal and interest payments in Canadian dollars.
The swaps provide for a fixed payment of C$304.8 million in exchange for
receipt of US $300 million on December 15, 2015. The swaps also provide
for semi-annual interest payments commencing June 15, 2009 until December
15, 2015 at a fixed rate of 10.795 percent based on a notional C$304.8
million of debt in exchange for receipt of semi-annual interest payments
until December 15, 2015 at a fixed rate of 10.25 percent based on a
notional US $300 million of debt.
Relative to the company's crude oil revenue receivables, Senior Notes and
currency swap, a $0.01 strengthening in the Canadian dollar exchange rate
would have resulted in a $4.2 million increase in net earnings for the
first quarter of 2008, and a $0.01 weakening of the Canadian dollar would
have resulted in a $2.3 million decrease in net earnings in the first
quarter of 2008.
(e) Liquidity risk
Liquidity risk is the risk that the company will not have sufficient
funds to repay its debts and fulfill its financial obligations.
To manage this risk, the company follows a conservative financing
philosophy, pre-funds major development projects, continuously monitors
expenditures against pre-approved budgets to control costs, regularly
monitors its operating cash flow, working capital and bank balances
against its business plan, maintains accessible revolving banking lines
of credit, and maintains prudent insurance programs to minimize exposure
to insurable losses.
Additionally, the long term nature of the company's debt repayment
obligations is aligned to the long term nature of its assets. The
Convertible Debentures do not mature until June 30, 2012, unless
converted to common shares earlier, and principal repayments are not
required on the Senior Notes until their maturity date of December 15,
2015. This affords Connacher the opportunity to deploy its conventional,
oil sands, and refinery cash flow to fund the development of further
expansion projects over the next few years without having to make
principal payments or raise new capital unless expenditures exceed cash
flow and credit capacity.
The Revolving Credit Facilities (C $150 million and US $50 million)
provide liquidity as the company has the ability to draw on them when,
and if, necessary anytime over their five year term. As at March 31, 2008
they secure approximately $19 million of issued letters of credit.
Substantially, all of the company's assets (except its investment in
Petrolifera) secure the Revolving Credit Facilities and Senior Notes.
The company is subject to financial covenants with respect to its
Revolving Credit Facilities and Senior Notes. The financial covenants
applicable to the first quarter of 2008 are:
- Consolidated Total Debt to Total Capitalization Ratio shall not
exceed 65% at the end of the fiscal quarter. Consolidated Total Debt
includes all debt of the company except for the Convertible
Debentures. Total Capitalization is the sum of Consolidated Total
Debt, the principal amount of the Convertible Debentures and the book
value of Shareholders' Equity.
- Consolidated Senior Debt to EBITDA Ratio shall not exceed 3.5:1 at
the end of any fiscal quarter, as determined on a rolling four fiscal
quarter basis. Consolidated Senior Debt includes all borrowings under
the Revolving Credit Facilities. EBITDA is equal to Net Earnings plus
finance charges, taxes, depletion, depreciation, accretion, stock
based compensation expense and earnings of Petrolifera accounted for
on an equity basis, with further adjustment made for extraordinary
gains or losses and other non cash items added or deducted in
determining Net Earnings.
The company is in compliance with all of its financial covenants.
The change in carrying value of long-term debt at March 31, 2008 ($671
million) from December 31, 2007 ($664 million) is primarily due to the
change in the Canadian : US exchange rate in converting the US dollar-
denominated Senior Notes to Canadian dollars and accretion of the debt
discount of approximately $1.2 million.
At March 31, 2008 the fair values of the Convertible Debentures and
Senior Notes were $93 million and $602 million, respectively, based on
their quoted market prices. The fair value of the cross-currency and
interest rate swaps was an asset of $2.2 million, based on the present
value of future cash flows.
The company's term debt is repayable as follows:
- Convertible Debentures - June 30, 2012 in the amount of $100,050,000,
unless converted into common shares prior thereto; and
- Senior Notes - December 15, 2015 in the amount of US$600 million.
Connacher's investment in Petrolifera also provides liquidity. Trading on
the TSX, Connacher's 13.1 million shares held in Petrolifera are readily
marketable as they have not been collateralized. Although it is not
Connacher's intention to sell these shares in the foreseeable future, the
shareholding provides Connacher an additional margin of safety.
(f) Capital risks
Connacher's objectives in managing its cash, debt and equity ("capital"),
its capital structure and its future capital requirements are to
safeguard its ability to meet its financial obligations, to maintain a
flexible capital structure that allows multiple financing options when a
financing need arises and to optimize its use of short-term and long-term
debt and equity at an appropriate level of risk.
The company manages its capital structure and follows a financial
strategy that considers economic/industry conditions, the risk
characteristics of its underlying assets and its growth opportunities. It
strives to continuously improve its credit rating and reduce its cost of
capital. Connacher monitors its capital using a number of financial
ratios and industry metrics to ensure its objectives are being met and to
ensure continued compliance with its debt covenants.
Connacher's current capital structure and certain financial ratios are
noted below.
As at As at
March 31, 2008 December 31, 2007
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Long term debt(1) $671,014 $664,462
Shareholders' equity
Share capital, contributed surplus
and equity component 433,530 444,086
Accumulated other comprehensive loss (10,127) (13,636)
Retained earnings 48,156 49,989
-------------------------------------------------------------------------
Total $1,142,573 $1,144,901
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Debt to book capitalization(2) 59% 58%
Debt to market capitalization(3) 49% 44%
-------------------------------------------------------------------------
(1) Long-term debt is stated at its carrying value, which is net of fair
value adjustments, original issue discounts, transaction costs and
the Convertible Debentures' equity component value.
(2) Calculated as long-term debt divided by the book value of
shareholders' equity plus long-term debt.
(3) Calculated as long-term debt divided by the period end market value
of shareholders' equity plus long-term debt.
Connacher currently has a high ratio of debt to capitalization, and its
debt service costs are high relative to cash flow. This is due to pre-
funding the full cost of Algar, the company's second oil sands project,
in December 2007, by issuing US$600 million of Senior Notes. As at March
31, 2008, the company's net debt (long-term debt, net cash on hand) was
$347,591. Net debt to book capitalization was 30 percent and net debt to
market capitalization was 25 percent.
5. INVENTORIES
Inventories consist of the following:
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($000) March 31, 2008 December 31, 2007
-------------------------------------------------------------------------
Crude oil $3,218 $2,258
Other raw materials and unfinished
products(1) 1,385 1,501
Refined products(2) 29,785 11,183
Process chemicals(3) 789 1,036
Repairs and maintenance supplies
and other(4) 2,856 2,401
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$38,033 $18,379
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(1) Other raw materials and unfinished products include feedstocks and
blendstocks, other than crude oil. The inventory carrying value
includes the costs of the raw materials and transportation.
(2) Refined products include gasoline, jet fuels, diesels, asphalts,
liquid petroleum gases and residual fuels. The inventory carrying
value includes the cost of raw materials, transportation and direct
production costs.
(3) Process chemicals include catalysts, additives and other chemicals.
The inventory carrying value includes the cost of the purchased
chemicals and related freight.
(4) Repair and maintenance supplies in crude refining and oil sands
supplies.
In accordance with the company's accounting policies, inventories are
valued at the lower of cost and net realizable value. At each of December
31, 2007 and March 31, 2008 net realizable value was used to value
asphalt inventories as at each date net realizable value was lower than
cost. At March 31, 2008 the net realizable value of asphalt was higher
than it was at December 31, 2007, due to seasonal influences on asphalt
selling prices. As a result, asphalt inventory values at March 31, 2008
increased due to increases in market prices from December 31, 2007 by
approximately $8 million.
Included in downstream crude oil purchases and operating costs for the
three months ended March 31, 2008 was approximately $64 million of
inventory costs.
6. ASSET RETIREMENT OBLIGATIONS
The following table reconciles the beginning and ending aggregate
carrying amount of the obligation associated with the company's
retirement of its oil sands and conventional petroleum and natural gas
properties and facilities.
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($000) Three months ended Year ended
March 31, 2008 December 31, 2007
-------------------------------------------------------------------------
Asset retirement obligations,
beginning of period $24,365 $7,322
Liabilities incurred 547 8,277
Liabilities settled (123) (311)
Change in estimated future cash flows (1,216) 7,503
Accretion expense 422 1,574
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Asset retirement obligations,
end of period $23,995 $24,365
-------------------------------------------------------------------------
Liabilities incurred in 2008 have been estimated using a discount rate of
10 percent reflecting the company's credit-adjusted risk free interest
rate given its current capital structure and an inflation rate of two
percent. The company has not recorded an asset retirement obligation for
the Montana refinery as it is currently the company's intent to maintain
and upgrade the refinery so that it will be operational for the
foreseeable future. Consequently, it is not possible at the present time
to estimate a date or range of dates for settlement of any asset
retirement obligation related to the refinery.
7. SHARE CAPITAL AND CONTRIBUTED SURPLUS
Authorized
The authorized share capital comprises the following:
- Unlimited number of common voting shares
- Unlimited number of first preferred shares
- Unlimited number of second preferred shares
Issued
Only common shares have been issued by the company.
-------------------------------------------------------------------------
Number Amount
of Shares ($000)
-------------------------------------------------------------------------
Balance, Share Capital,
December 31, 2007 209,971,257 $406,881
Issued upon exercise of options in
2008(a) 197,000 95
Issued to directors under share award
plan(b) 108,975 381
Assigned value of options exercised in 2008 - 35
Share issue costs, net of income taxes (51)
Tax effect of expenditures renounced
pursuant to the issuance of flow
through common shares in 2007(c) (13,250)
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Balance, Share Capital, March 31, 2008 210,277,232 $394,091
-------------------------------------------------------------------------
Balance, Contributed Surplus,
December 31, 2007 $20,382
Stock based compensation for share
options expensed in 2008 2,269
Assigned value of options exercised in 2008 (35)
-------------------------------------------------------------------------
Balance, Contributed Surplus,
March 31, 2008 $22,616
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Equity component of Convertible
Debentures, December 31, 2007
and March 31, 2008 $16,823
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Share Capital, Contributed
Surplus and Equity Component
-------------------------------------------------------------------------
December 31, 2007 $444,086
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March 31, 2008 $433,530
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(a) Stock Options
A summary of the company's outstanding stock options, as at March 31,
2008 and 2007 and changes during those periods is presented below:
-------------------------------------------------------------------------
For the three months
ended March 31 2008 2007
-------------------------------------------------------------------------
Weighted Weighted
Number of Average Number of Average
Options Exercise Price Options Exercise Price
-------------------------------------------------------------------------
Outstanding,
beginning of
period 17,432,717 $3.60 16,212,490 $3.31
Granted 2,548,023 $3.15 2,744,833 3.88
Exercised (197,000) $0.53 (324,433) 0.89
Expired (14,000) $3.51 (213,000) 3.75
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Outstanding,
end of
period 19,769,740 $3.57 18,419,890 $3.44
-------------------------------------------------------------------------
Exercisable,
end of
period 13,693,864 $3.54 9,617,198 $3.02
-------------------------------------------------------------------------
All stock options have been granted for a period of five years. Options
granted under the plan are generally fully exercisable after either two
or three years. The table below summarizes unexercised stock options.
-------------------------------------------------------------------------
Range of Exercise Prices Number Weighted Average
Outstanding Remaining Contractual Life
at March 31, 2008
-------------------------------------------------------------------------
$0.20 - $0.99 1,800,968 1.6
$1.00 - $1.99 1,632,000 2.2
$2.00 - $3.99 9,013,239 3.9
$4.00 - $5.56 7,323,533 3.1
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19,769,740 3.3
-------------------------------------------------------------------------
During the first quarter of 2008 a non-cash charge of $1.5 million (2007
- $2.9 million) was expensed, reflecting the fair value of stock options
amortized over the vesting period. A further $798,000 (2007 - $546,000)
was capitalized to property and equipment.
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with weighted average
assumptions for grants as follows:
-------------------------------------------------------------------------
For the three months ended March 31 2008 2007
-------------------------------------------------------------------------
Risk free interest rate 3.2% 4.5%
Expected option life (years) 3 3
Expected volatility 48% 68%
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of all options
granted in the first quarter of 2008 was $1.12 per option (2007 - $1.86).
(b) Share award plan for non-employee directors
On January 16, 2008, 108,975 shares were issued to non-employee directors
under the share award plan, settling the accrued liability of $381,000
relating to this award.
On March 25, 2008 an additional 283,730 shares were awarded to non-
employee directors over a future vesting period. A total of 392,705 share
awards were outstanding at March 31, 2008 and vest on the following
dates:
-------------------------------------------------------------------------
December 31, 2008 5,210
January 1, 2009 108,975
December 31, 2009 5,210
January 1, 2010 136,655
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January 1, 2011 136,655
-------------------------------------------------------------------------
392,705
-------------------------------------------------------------------------
In the first quarter of 2008, a non-cash charge of $45,000 (2007 - nil)
was accrued as a liability and expensed in respect of shares yet to be
issued under the share award plan.
(c) Flow through shares
Effective December 31, 2007, the company renounced $52.25 million of
resource expenditures to flow-through share investors. The related tax
effect of $13.25 million of these expenditures was recorded in 2008. The
company has incurred all of the required expenditures related to these
flow-through shares in 2007 and 2008.
8. SEGMENTED INFORMATION
The company has changed its segmentation in 2008 to better reflect the
organization of its business by combing the former Canadian
administrative segment with the Canadian oil and gas segment. In Canada,
the company is in the business of exploring for and producing crude oil,
natural gas and bitumen. In the U.S., the company is in the business of
refining and marketing petroleum products. The significant aspects of
these operating segments are presented below. Comparative figures have
been reclassified.
Three months ended March 31 Canada USA
($000) Oil and Gas Refining Total
-------------------------------------------------------------------------
2008
Revenues, net of royalties $27,926 $71,899 $99,825
Equity interest in
Petrolifera earnings 413 - 413
Interest and other income 706 125 831
Crude oil purchases and
operating costs 14,486 71,393 85,879
General and administrative 3,066 - 3,066
Stock-based compensation 1,516 - 1,516
Finance charges 4,372 59 4,431
Foreign exchange (gain) 1,960 (68) 1,892
Depletion, depreciation
and accretion 6,216 1,248 7,464
Tax provision (recovery) (702) (644) (1,346)
Net earnings (loss) (1,869) 36 (1,833)
Property and equipment, net 724,575 58,150 782,725
Capital expenditures 112,957 3,027 115,984
Total assets $1,214,329 $133,769 $1,348,098
-------------------------------------------------------------------------
2007
Revenues, net of royalties $8,207 $57,596 $65,803
Equity interest in Petrolifera
earnings 3,900 - 3,900
Interest and other income 13 107 120
Crude oil purchases and
operating costs 1,932 46,398 48,330
General and administrative 3,584 - 3,584
Stock-based compensation 2,946 - 2,946
Finance charges 371 75 446
Foreign exchange (gain) (1,702) - (1,702)
Depletion, depreciation and
accretion 6,100 1,257 7,357
Tax provision 224 3,654 3,878
Net earnings (loss) (343) 5,327 4,984
Property and equipment, net 435,526 51,495 487,021
Capital expenditures 106,764 3,117 109,881
Total assets $646,870 $110,335 $757,205
-------------------------------------------------------------------------
9. SUPPLEMENTARY INFORMATION
(a) Per share amounts
The following table summarizes the common shares used in earnings per
share calculations.
For the three months ended March 31 (000) 2008 2007
-------------------------------------------------------------------------
Weighted average common shares outstanding 210,234 198,119
Dilutive effect of stock options - 1,889
-------------------------------------------------------------------------
Weighted average common shares outstanding
- diluted 210,234 200,008
-------------------------------------------------------------------------
(b) Net change in non-cash working capital
For the three months ended March 31 ($000) 2008 2007
-------------------------------------------------------------------------
Accounts receivable $(27,497) $(182)
Inventories (19,654) (14,558)
Due from Petrolifera (7) 109
Prepaid expenses 992 366
Accounts payable and accrued liabilities 80,924 14,589
Income taxes payable/recoverable (588) (507)
-------------------------------------------------------------------------
Total $34,170 $(183)
-------------------------------------------------------------------------
Summary of working capital changes:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Operations $21,770 $6,922
Investing 12,400 (7,105)
-------------------------------------------------------------------------
$34,170 $(183)
-------------------------------------------------------------------------
(c) Supplementary cash flow information
-------------------------------------------------------------------------
For the three months ended March 31 2008 2007
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Interest paid $383 $5,759
Income taxes paid 1,127 3,039
Stock-based compensation capitalized $798 $546
-------------------------------------------------------------------------
At March 31, 2008 cash of $65.9 million (December 31, 2007 -
$63.2 million) was restricted to fund the first year of interest payments
on the Senior Notes.
(d) Defined benefit pension plan
In the first quarter of 2008, $113,000 (2007 - $130,000) has been charged
to expense in relation to MRCI's defined benefit pension plan.
For further information:
For further information: Richard A. Gusella, President and Chief Executive Officer; OR Grant D. Ukrainetz, Vice President, Corporate Development, Phone: (403) 538-6201, Fax: (403) 538-6225, inquiries@connacheroil.com, Website: www.connacheroil.com