Connacher Oil and Gas Limited reports year end 2008 results; Higher downstream crude oil costs and higher non-cash charges result in loss for fourth quarter and full year; Record production, revenue and cash flow achieved; Significant reserves growth reco
CALGARY, March 19 /CNW/ - Connacher Oil and Gas Limited today released
its operating and audited financial results for the year ended December 31,
2008. Connacher made significant progress as a company during 2008. We
achieved record production which averaged 8,581 barrels of oil equivalent
("boe") per day ("boe/d") for the full year 2008, an increase over full year
2007 of 270 percent and 10,341 boe/d in the fourth quarter 2008, an increase
of 363 percent over fourth quarter 2007 results. The company's proved reserves
("1P") of crude oil, natural gas, natural gas liquids and bitumen, expressed
on a boe basis, more than tripled; proved and probable reserves (2P) more than
doubled. Our reserve replacement ratio, which is calculated by dividing
reserves added in 2008 (grossed up for 2008 production) by record 2008
production, was 38 times for 1P reserves and over 60 times for 2P reserves. We
achieved record revenue and cash flow from operations, before changes in
non-cash working capital and other items ("cash flow") from our integrated
operation. We recorded a fourth quarter 2008 and full year loss, primarily
arising from higher downstream crude oil costs and increased provisions for
non-cash charges, including depletion due to record production levels and also
including those associated with foreign exchange losses on translation of our
U.S. dollar-denominated debt.
Our year-end liquidity remained strong, with $224 million of cash and
$198 million of working capital. Perhaps more importantly, we sense recovery
in the air.
These year-end 2008 and fourth quarter 2008 results will be the subject
of a Conference Call at 9:00 a.m. MDT on March 20, 2009. To listen to or
participate in the live conference call please dial either (416) 644-3414 or
(800) 733-7560. A replay of the event will be available from Friday, March 20,
2009 at 11:00 a.m. MDT until 21:59 (9:59 p.m.) MDT on Friday, March 27, 2009.
To listen to the replay please dial either (416) 640-1917 or Toll Free at
(877) 289-8525 and enter the passcode 2129403 followed by the number sign.Key operational achievements of 2008 were as follows:
- We commenced full-scale production at Great Divide Pod One ("Pod
One"), our first 10,000 bbl/d steam assisted gravity drainage
("SAGD") oil sands project. Commerciality was declared on March 1,
2008, only two months after production commenced in December 2007;
all 15 SAGD well pairs are now onstream.
- We experienced a solid ramp up of bitumen production at Pod One,
reaching a peak of 9,870 bbl/d in September 2008, against a rated
capacity of 10,000 bbl/d.
- We lowered Pod One steam-to-oil-ratios (SOR's) to less than three
times for the project with instantaneous SOR's for better wells in
the low twos.
- We produced over 3.1 million boe in 2008, including over 2.1 million
barrels of bitumen from Pod One. Daily production increased 270
percent to 8,581 boe/d, with a fourth quarter 2008 average rate of
10,341 boe/d.
- Our conventional oil and natural gas production rate averaged over
3,100 boe/d in 2008, an increase of 35% over 2007.
- We secured approval of Algar, our second 10,000 bbl/d SAGD oil sands
project, completed and paid for many long-lead equipment items and
completed civil work in early 2009.
- We significantly expanded our conventional oil, natural gas and
bitumen reserve base through successful drilling programs and the
impact of the Algar approval, which moved probable reserves to proved
reserves.
- At our refinery in Great Falls, Montana, during 2008 we substantially
completed the ultra low sulphur diesel project, on time and on
budget.
Summary financial and operating highlights were as follows:
Financial Highlights
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2008 2007 % Change
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FINANCIAL
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($000 except per share amounts)
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Revenues, net of royalties 629,339 344,520 83
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Cash flow(1) 54,817 44,965 22
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Basic, per share(1) 0.26 0.22 18
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Diluted, per share(1) 0.26 0.22 18
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Net earnings (loss) (26,603) 40,961 (165)
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Basic and diluted, per share (0.13) 0.20 (165)
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Property and equipment additions 351,736 322,962 9
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Cash on hand, end of period 223,663 392,271 (43)
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Working capital, end of period 197,914 389,789 (49)
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Term debt, end of period 778,732 664,462 17
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Shareholders' equity, end of period 469,087 480,439 (2)
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Total assets, end of period 1,431,675 1,258,828 14
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COMMON SHARE INFORMATION
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Shares outstanding,
end of period (000) 211,182 209,971 1
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Weighted average shares outstanding
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Basic (000) 210,794 200,092 5
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Diluted (000) 214,647 202,766 6
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Common shares traded
during the year (000) 393,365 239,590 64
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Common share price ($)
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High 5.26 4.43 19
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Low 0.60 3.07 (80)
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Close, end of year 0.74 3.79 (80)
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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 site restoration
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's Discussion & Analysis ("MD&A"). Commonly
used in the oil and gas industry, 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) No dividends have been declared by the company since its
incorporation.
(3) The recognition of bitumen sales from the company's first oil sands
project, Great Divide Pod One, commenced March 1, 2008, when it was
declared "commercial". Prior thereto, no production was reported and
all operating costs, net of revenues were capitalized. The 2008 daily
production average is based on a full calendar year.
(4) All references to barrels of oil equivalent (boe) are calculated on
the basis of 6 Mcf : 1 bbl. 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. Boes may
be misleading, particularly if used in isolation.
(5) Netback is a non-GAAP measure used by management as a measure of
operating efficiency and profitability. It is calculated as petroleum
and natural gas revenue less royalties and operating costs. The most
comparable measure calculated in accordance with GAAP would be net
earnings. Netback is reconciled with net earnings in the accompanying
MD&A.
(6) The reserve and resource estimates for 2008 and 2007 were prepared by
GLJ Petroleum Consultants Ltd ("GLJ"), an independent professional
petroleum engineering firm, in accordance with Canadian Securities
Administrators' National Instrument 51-101 (NI 51-101) and the
Canadian Oil and Gas Evaluation Handbook. Under NI 51-101, proved
reserves are those reserves which can be estimated with a high degree
of certainty to be recoverable. It is 90 percent likely that actual
remaining quantities will exceed estimated proved reserves. Probable
reserves are those additional reserves that are less certain to be
recovered than proved reserves. It is equally likely that the actual
remaining quantities recovered will be greater or less than the sum
of proved plus probable reserves. Possible reserves are those
additional reserves that are less certain to be recovered than
probable reserves.
Operating Highlights
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2008 2007 % Change
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OPERATING
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Production
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Bitumen (bbl/d)(3) 5,456 - -
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Crude oil (bbl/d) 1,029 792 30
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Natural Gas (mcf/d) 12,570 9,172 37
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Equivalent (boe/d)(4) 8,581 2,320 270
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Pricing
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Bitumen ($/bbl) 45.74 - -
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Crude oil ($/bbl) 82.01 52.80 55
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Natural gas ($/mcf) 7.90 6.38 24
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Selected highlights ($/boe)(4)
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Weighted average sales price 50.49 43.22 17
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Royalties 5.00 6.93 (28)
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Operating and transportation costs 20.38 11.06 84
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Operating Netback(5) 25.11 25.23 -
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RESERVES AND RESOURCES
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Reserves volumes (mboe)(6, 7)
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Proved (1P) reserves 182,840 59,857 205
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Proved plus probable (2P) reserves 379,476 187,250 103
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Proved plus probable plus possible
(3P) reserves(9) 452,295 251,468 80
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Reserves values ($million)(8)
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1P reserves 1,026 603 70
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2P reserves 1,543 1,194 29
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3P reserves 2,274 1,308 74
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REFINERY
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Refining throughput
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Crude charged (bbl/d) 9,184 9,485 (3)
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Refinery utilization (%) 97 100 (3)
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Margins (%) (2.0) 15.4 (113)
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Notes (1) to (6) on previous page
(7) After production of 3.1 million boe in 2008.
(8) 10 percent present value of future net revenue before taxes.
(9) Possible reserves account for 73 mmboe of the estimated total 3P
reserves.
There is only a 10 percent probability that the quantities actually
recovered will equal or exceed the sum of proved plus probable plus
possible reserves.
Year in ReviewConnacher had an excellent year of execution and achievement in 2008,
reporting record production, revenue and cash flow. Events near year end,
including the meltdown of commodity, stock and credit markets impacted
adversely on our fourth quarter 2008 and thus on our full year 2008 financial
and operating results. Nevertheless, we view our operational accomplishments
for the year as considerable.
The collapse of crude oil prices and economic downturn occurred quickly
and on a global basis. As a producer of bitumen in Alberta's oil sands, we
reacted quickly to weaker crude oil prices, widened heavy oil differentials
and challenging operating costs by curtailing production at Pod One in
December 2008. Subsequently, within about one month of this curtailment, we
were able to restore our operations to full capacity due to steps we took to
capitalize on contango in the crude oil price and on other factors which
improve our selling price at Pod One. Accordingly, we are now in the midst of
ramping volumes up to pre-shutdown levels, which were approaching 10,000
bbl/d. At those production levels, our steam/oil ratios ("SOR's") were
favorable, at around three times overall and approaching two times at some of
our better wells, before the curtailment. We anticipate again achieving these
metrics in 2009.
We have since drilled two new SAGD well pairs in proximity to our best
well at Pod One and following completion, tie-in and steaming, will place
these wells onstream around mid-year 2009. We also intend to install four of
nine electrical submersible pumps we have in inventory during the next several
months. This should contribute to improvements in both reliability and
productivity with lower SOR's from the wells into which this artificial lift
will be installed. This is in keeping with our emphasis on production
optimization and cost control in a lower crude oil price environment.
Our current production at Pod One is approximately 8,000 bbl/d. We are
ramping up at a measured pace towards 10,000 bbl/d to ensure our cost control
goals can be achieved. Our facility operated well throughout 2008 and we
overcame minor operational challenges throughout the year. We have recently
been successful in reducing operating costs, assisted by higher production
volumes. We are targeting to have our operating costs at Pod One in the
$17-$20 bbl range for full year 2009, depending on the cost of natural gas,
which we believe would make Connacher among the lowest if not the lowest cost
operator in the oil sands at this time.
Consistent with our commitment to an integrated strategy comprised of
repeatability, long-term sustainability and expandability of our production
base in the oil sands, we applied for regulatory approval to construct our
second 10,000 SAGD project at Algar in the latter half of 2007. In November
2008, we received the requisite approvals for this project and immediately
commenced civil work on the access road, plant site and three well pads. We
had previously ordered numerous long-lead equipment items to maintain our
execution record for timely project completion. Market conditions deteriorated
to such an extent that in mid-December, we decided to suspend construction of
Algar, once we completed the civil work on the access road, plant site and
three well pads. To date, we have invested approximately $150 million in
Algar, the total cost of which had been financed in late 2007 and was
estimated at $345 million, excluding approximately $14 million related to the
decision to suspend construction. We appreciate this is a long term
investment, but liquidity remains the priority for most oil companies at this
time. We will reinstate construction, plant assembly and drilling of the
proposed 15 SAGD well pairs for Algar at the earliest opportune time, upon
indication of improved capital markets and with satisfactory evidence of a
sustainable recovery in crude oil prices, thus providing a reasonable prospect
of an adequate rate of return on our investment.
Our 9,500 bbl/d heavy oil refinery, located in Great Falls, Montana made
respectable progress through a challenging economic period in 2008.
Profitability was adversely impacted by the rapid escalation in crude oil
prices that occurred in the first half of 2008, coupled with the inability of
the refinery to pass on its higher input costs in the prices received for its
refined products, especially asphalt. A deteriorating U.S. economy put
downward pressure on gasoline prices in the latter part of 2008, which also
negatively impacted the refinery's results for the year. The refinery was able
to offset these poor conditions somewhat by expanding its middle distillate
and asphalt product markets. We also capitalized on our small refiner niche to
secure an important U.S. government jet fuel contract. The refinery has
substantially completed construction of its ultralow sulphur diesel ("ULSD")
project, on time and on budget. The refinery did experience some throughput
reduction in December 2008 and during the first quarter 2009, associated with
the tie-in of the ULSD facility and also because of extreme cold weather.
Regardless, we have commenced the production of ULSD in March 2009.
In the first quarter of 2009, we continued a modest exploration program
at Great Divide, with a total of 24 core holes being drilled. We are pleased
with the overall results of this program, which enhances our overall
understanding of the reserve potential of our main lease block.
On March 9, 2009 we submitted a Terms of Reference for a proposal to
expand our Great Divide Pod One and Algar SAGD facilities ("Great Divide SAGD
Expansion Project") from a current authorized level of 20,000 bbl/d of bitumen
to approximately 44,000 bbl/d of bitumen. The Terms of Reference is the first
step in the process of preparing an Environmental Impact Assessment ("EIA")
for the Great Divide SAGD Expansion Project, as directed by Alberta
Environment.
Fourth Quarter 2008 and Full Year 2008
The fourth quarter 2008 was a difficult period for Connacher. Revenues
fell from the prior quarter and we experienced modest negative cash flow,
primarily due to the dramatic drop in crude oil prices and the widening of
heavy crude oil price differentials, which particularly affected bitumen
producers. This detracted from our record performance during the first three
quarters of 2008. Additionally, the fourth quarter of any year is normally the
period when we start to build our asphalt inventories at our refinery. As a
result of lower crude oil prices and refined product pricing, we recorded a
downward valuation adjustment of $9 million in this reporting period, for all
refined products we carry in inventory, including our expanding asphalt
inventory. We charged this amount as an expense in our Statement of
Operations. As a result, our refining division reported an operating loss for
the period. These adverse factors were offset by a provision for a significant
cash tax recovery, for both the fourth quarter 2008 and for the full year
reporting period. This more than offset the inventory valuation adjustment and
resulted in positive after-tax operating income in both reporting periods for
our refining division.
For the fourth quarter 2008, upstream production was 10,341 boe/d
compared to 2,233 boe/d in the fourth quarter of 2007, an increase of 363
percent. This was achieved despite the short-term curtailment of bitumen
production at Pod One in mid-December 2008. Revenue was $102 million compared
to $225 million in the third quarter of 2008 and $83 million in the fourth
quarter of 2007, reflecting crude oil price volatility. Our cash flow
deficiency was $4.7 million in the fourth quarter of 2008. Please refer to the
MD&A below for reconciliation of cash flow to net loss. A loss of $43.6
million was recorded, primarily due to non-cash charges. These included an
increased provision for depletion due to higher upstream production, a
provision for a foreign exchange loss on the translation of our U.S. dollar
denominated debt, higher future taxes and the write-off of certain costs,
including those related to the original arrangement of the company's
terminated credit facilities and for front end engineering and design studies
related to the deferral of refinery expansion plans.
For the full year 2008, cash flow was a record $55 million, an increase
of 22 percent compared to $45 million in 2007. On a weighted average
outstanding basis of 211 million shares in 2008 (200 million in 2007), cash
flow per share was $0.26 compared to $0.22 in 2007. Please refer to the MD&A
below for reconciliation of cash flow to net loss.
A net loss of $26.6 million ($0.13 per share) was recorded in fiscal
2008, after a provision for non-cash charges totaling $80 million, compared to
net earnings in 2007 of $41 million ($0.20 per share). Connacher ended the
year with $224 million of cash, working capital of $198 million and $779
million of long term debt. None of the company's debt is repayable until 2012
and most of it is not repayable until 2015. A significant portion ($89
million) of the company's year end cash balances was derived from the
successful monetization of the currency and interest rate swaps associated
with the company's outstanding U.S. dollar-denominated Second Lien Note issue.
This significant contribution to corporate liquidity was achieved without
share dilution or the incurrence of additional indebtedness.
Subsequent to year end 2008, Connacher elected to cancel its undrawn $150
million and US$50 million credit facilities. We had attempted to renegotiate
certain key terms of the facilities, but we were unsuccessful in securing
acceptable revisions from our banking syndicate. In order to further enhance
our financial flexibility and liquidity, as we now have considerable unused
credit capacity following the cancellation of our former facilities, we are
investigating alternative credit sources. We have already arranged a
cash-collateralized letter of credit facility in the amount of $20 million to
facilitate our normal business transactions requiring letters of credit. New
funding would supplement our strong year end 2008 cash balances and working
capital. We also intend to examine other opportunities to restructure
components of our balance sheet, in the context of lower commodity prices.
While we sense recovery, we also expect the early part of 2009 will be
challenging. We have already experienced difficult conditions during the first
few months of 2009, although we are currently experiencing improved market
conditions. Nevertheless, in response to these circumstances, we have
curtailed our anticipated capital spending for 2009 to approximately $123
million, down from previous levels approximating $373 million. Most of these
expenditures will occur in the first quarter 2009, primarily related to Algar.
Details of our continuing program are provided in greater detail herein.
We anticipate a much improved full year contribution from our refining
operations, primarily due to healthy asphalt markets. Newly-announced U.S.
government infrastructure projects are anticipated to result in an
unprecedented demand for asphalt. This product is currently in short supply in
the United States. This improvement should start to be apparent in the second
quarter of 2009. We also anticipate positive net operating income from our
upstream operations. With our significant cash balances and our operating cash
flow, we anticipate being able to fund all of our capital spending activities
and meet all financial obligations throughout 2009, even if crude oil prices
stay at WTI US$45.00/bbl for the balance of this year, without having to raise
any additional capital.
We continue to believe preserving our liquidity and protecting our assets
are the priority responsibilities for 2009. We have ample identified reserves
and resources to remain confident of our long-term growth prospects and we
believe energy prices will improve as the year unfolds. To stabilize our
outlook in a volatile period and protect against the possibility of renewed
crude oil price weakness, we have arranged WTI hedges at prices of
US$46.00/bbl and US$49.50/bbl, on approximately one half of our anticipated
bitumen production for much of 2009. We have a built-in physical hedge with
our own natural gas production at Marten Creek, Randall, Latornell, Seal and
other areas. We believe that this minimizes the impact of volatility in
natural gas prices on our overall operations.Revised Capital Budget
In view of changed capital market conditions, we have elected to preserve
liquidity and reduce our 2009 capital expenditures to $123 million as follows:
($million) New Original
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Upstream
Conventional $13 $15
Pod One 18 20
Algar 29 208
Algar capitalized items 30 69
Cogeneration 4 22
Exploration 9 10
EIA and other 3 3
Downstream
Refining 17 26
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Total $123 $373
-------------------------------------------------------------------------Connacher Oil and Gas Limited is a Calgary based crude oil, natural gas
and bitumen producer. Our principal asset is our interest in the Great Divide
oil sands project in northeastern Alberta. We also own a 9,500 bbl/d heavy oil
refinery in Great Falls, Montana and a 24 percent equity stake in Petrolifera
Petroleum Limited, a public company listed for trading on the Toronto Stock
Exchange, with assets in South America.
Forward-Looking Information
This press release contains forward-looking information including
estimations of reserves and resources and future net revenue associated
therewith, expectations of future production and SORs at Pod One, timing for
two new SAGD wells to commence production, planned installation of electrical
submersible pumps, anticipated improvements in reliability and productivity of
SAGD wells with artificial lift installed, anticipated reductions in operating
costs, timing and future considerations for reactivation of construction of
Algar, timing for initiating ULSD production, future expansion plans at Great
Divide, anticipated capital spending for 2009 and sources of funding thereof,
anticipated improvement in financial results of the refining operation and
anticipated improvements in commodity prices, investigation of financing
alternatives to restructure balance sheet components and efforts to secure
new, acceptable sources of credit to replace facilities cancelled by the
company. Forward looking information is based on management's expectations
regarding future growth, results of operations, 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 risks of
commodity price and foreign exchange rate fluctuation, and risk and
uncertainties associated with maintaining necessary regulatory approvals. In
addition, the current financial crisis has resulted in severe economic
uncertainty and resulting illiquidity in credit and capital markets which
increases the risk that actual results will vary from forward looking
expectations in this press release and these variations may be material. In
particular, there can be no assurance that the company will be able to secure
new sources of credit on terms and conditions acceptable to the company or at
all or that the company will be successful in its efforts to restructure
certain components of its balance sheet. These risk and uncertainties are
described in details in Connacher's Annual Information Form for the year ended
December 31, 2008, which is available at www.sedar.com.
Information relating to "reserves" and "resources" and "future net
revenues" associated therewith are deemed to be forward-looking information,
as they involve the implied assessment, based on certain estimates and
assumptions, that the reserves and resources, as the case may be, described
exist in the quantities predicted or estimated, and can be profitably produced
in the future to achieve the future net revenue calculated in accordance with
certain assumptions. The assumptions relating to the reserves and resources of
the Corporation and associated future net revenues are contained in the 2008
GLJ Report and are summarized in Connacher's Annual Information Form for the
year ended December 31, 2008. Future net revenues associated with reserves and
resources do not necessarily represent fair market value. Connacher assumes no
obligation to update or revise the forward-looking information to reflect new
events or circumstances, except as required by law.
Management Discussion and Analysis
The company's long-term business plan anticipates continued substantial
growth. Emphasis will be on developing the Great Divide Oil Sands Project in
Alberta, while continuing to develop the company's recently-expanded
conventional production base and operating the Montana refinery.
The following is dated as of March 19, 2009 and should be read in
conjunction with the consolidated financial statements of Connacher Oil and
Gas Limited ("Connacher" or the "company") for the years ended December 31,
2008 and 2007 as contained in this annual report. The 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.
Forward-looking Information
This report, including the Letter to Shareholders, contains
forward-looking information including but not limited to estimations of
reserves and resources and future net revenue associated therewith,
expectations of future production, net operating income, 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 Algar and the timeline and capital
costs for construction of Algar), expansion of current conventional oil and
gas and oil sands operations, and timely expansion or downstream refining and
marketing opportunities, initiation of ultra low sulphur diesel production,
planned construction of a cogeneration facility and anticipated sources of
funding for capital expenditures and plans for improving liquidity which may
include securing a new credit facility, accessing new equity, corporate
acquisitions or business combinations, joint venture arrangements and
restructuring components of the balance sheet. Forward looking information is
based on management's expectations regarding future growth, results of
operations, production, future commodity prices and foreign exchange rates,
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 and future
economic conditions. 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 associated with the impact
of general economic conditions, risks and uncertainties associated with
securing and maintaining the necessary regulatory approvals and financing to
proceed with the continued expansion of the Great Divide Oil Sands Project. In
addition, the current financial crisis has resulted in severe economic
uncertainty and resulting illiquidity in credit and capital markets which
increases the risk that actual results will vary from forward looking
expectations in this report and these variations may be material. These and
other risks and uncertainties are described in further detail in Connacher's
Annual Information Form for the year ended December 31, 2008, which is
available at www.sedar.com. Information relating to "reserves", "resources"
and "future net revenues" associated therewith are deemed to be
forward-looking information, as they involve the implied assessment, based on
certain estimates and assumptions, that the reserves described exist in the
quantities predicted or estimated, and can be profitably produced in the
future to achieve the future net revenue calculated in accordance with certain
assumptions. The assumptions relating to the reserves and resources and
associated future net revenues reported herein are contained in the GLJ 2008
Report and are summarized in Connacher's Annual Information Form for the year
ended December 31, 2008. Future net revenues associated with reserves and
resources do not necessarily represent fair market value. Additionally,
certain information relating to Petrolifera's future exploration and
development plans, capital expenditures and proposed sale of its Argentinean
oil and gas interests represent forward-looking information that has been
publicly released by Petrolifera. This information is subject to change in the
discretion of the Board of Directors of Petrolifera. 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 report are expressly
qualified in their entirety by this cautionary statement, The forward-looking
information included in this report is made as of March 19, 2009 and Connacher
assumes no obligation to update or revise any forward-looking information to
reflect new events or circumstances, except as required by law.
Throughout the MD&A, per barrel of oil equivalent (boe) amounts have been
calculated using a conversion rate of six thousand cubic feet of natural gas
to one barrel of crude oil (6:1). The conversion is based on an energy
equivalency conversion method primarily applicable to the burner tip and does
not represent a value equivalency at the wellhead. Boes may be misleading,
particularly if used in isolation.Business Strategy and Report Card
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Strategic Priorities Progress through 2008
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Own and operate large focused Retained 100 percent working in
working interests Great Divide Oil Sands Project.
Maintained very high working
interests in our conventional crude
oil and natural gas assets.
Own and operated the Montana
Refinery.
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Focus on projects with Commenced commercial production at
characteristics of expandability, our first 10,000 bbl/d oil sands
repeatability and sustainability project (Pod One).
Initiated construction of next
phase, Algar.
Expanded conventional natural gas
production, gathering and
processing facilities at Randall,
Alberta.
Tripled proved bitumen reserves and
doubled proved and probable bitumen
reserves.
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Mitigate and manage risks of a Natural gas production exceeded
smaller company in the oil sands usage at Pod One.
with an integrated approach Natural hedge provided by Montana
refinery allowed the company to
capture heavy oil differentials.
Modular approach permitted on time
facilities construction,
cost control and ramp up.
Pre-funded capital programs.
-------------------------------------------------------------------------
Operate with financial discipline Fully funded Algar in advance of
the current financial crisis and
prior to commencing construction.
Applied discipline to our
operations.
Planned 2009 optimization programs.
-------------------------------------------------------------------------
Three Year Summary Information
-------------------------------------------------------------------------
($000 except per share amounts) 2008 2007 2006
-------------------------------------------------------------------------
Total revenues, net of royalties $629,339 $344,520 $244,684
-------------------------------------------------------------------------
Net earnings (loss) (26,603) 40,961 6,953
-------------------------------------------------------------------------
Basic and diluted, per share (0.13) 0.20 0.04
-------------------------------------------------------------------------
Total assets 1,431,675 1,258,828 712,930
-------------------------------------------------------------------------
Longterm financial liabilities 778,732 664,462 209,754
-------------------------------------------------------------------------
Dividends declared/paid - - -
-------------------------------------------------------------------------Connacher has experienced substantial growth since 2006. The main driver
for the increase in revenue from 2006 to 2007 was the full year of revenue
recognized from refinery sales in 2007, compared to nine months' revenue from
sales in 2006, since its acquisition in March that year. The revenue increase
from 2007 to 2008 was primarily attributed to increased upstream production
volumes, resulting from the company's first oil sands project (Pod One)
achieving commerciality on March 1, 2008 together with increased conventional
crude oil and natural gas production. These factors resulted in a 270 percent
increase in year over year average daily production (8,581 boe/d vs. 2,320
boe/d). The company's long-term intentions anticipate continued increases in
upstream production and sales volumes through the continued development of
additional oil sands and conventional oil and gas projects.
Although changes to commodity prices for its upstream and refining
product sales have resulted in year-to-year changes in net earnings the most
significant factors causing fluctuations between 2006 and 2008 have been
non-cash charges and gains. These include foreign exchange (2006 - $4 million
loss; 2007 - $27 million gain; 2008 - $12 million loss) attributable to the
fluctuations in the rate of exchange between the Canadian and U.S. dollar in
translating the company's U.S. dollar-denominated debt and depletion and
depreciation expense, as it increased 81 percent in 2008 (to $56 million) from
lower amounts reported in 2006 ($33 million) and 2007 ($31 million). The
primary driver for the increase in depletion and depreciation in 2008 was the
270 percent increase in upstream production volumes, as noted above.
The company's earnings will continue to be subject to the volatility of
foreign exchange rates upon the translation of its U.S. dollar-denominated
debt, which comprises the majority of its long-term debt. Connacher did
maintain a currency and interest rate hedge on a portion of this debt, but
decided to realize the benefit of a weak Canadian dollar in November 2008 and
unwound the hedge for net cash proceeds of $89 million. Similar hedges may be
re-instated in the future under appropriate conditions and circumstances.
Since 2006, total long-term debt has increased, as it has been one source
of funding for expanding the company's asset base. The majority of this growth
has been in the oil sands, as Pod One was completed in 2007 at a cost of $272
million and commenced commercial production in early 2008. The company's
second 10,000 bbl/d SAGD oil sands project, Algar, was partially constructed
at December 31, 2008 with approximately $150 million of costs incurred to
date.Financial and Operating Review
Upstream Netbacks ($000)
For the year ended December 31
-------------------------------------------------------------------------
Oil Crude Natural
2008 Sands(1) Oil Gas Total
Gross revenues(2) $198,031 $30,982 $36,356 $265,369
Diluent purchased(3) (92,291) - - (92,291)
Transportation costs (14,403) (96) - (14,499)
Production revenue 91,337 30,886 36,356 158,579
Royalties (948) (7,229) (7,535) (15,712)
Operating costs (52,758) (4,525) (6,710) (63,993)
Operating netback(4) $37,631 $19,132 $22,111 $78,874
Operating netback as a
percentage of production
revenue
(%) 41.2 61.9 60.8 49.7
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2007
-------------------------------------------------------------------------
Gross revenues/production
revenue $15,257 $21,332 $36,589
Royalties (3,632) (2,235) (5,867)
Operating costs (3,193) (6,171) (9,364)
-------------------------------------------------------------------------
Operating netback(4) $8,432 $12,926 $21,358
-------------------------------------------------------------------------
Operating netback as a percentage
of production revenue
(%) 55 61 58
-------------------------------------------------------------------------
(1) In the first quarter of 2008, Connacher completed the conversion of a
majority of its fifteen horizontal well pairs to production status at
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 segment. The above
tables, therefore, do not include operating results prior to March 1,
2008.
(2) Bitumen produced at 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 above tables,
gross revenues represent sales of dilbit, crude oil and natural gas.
(3) Diluent volumes purchased and blended into dilbit sales have been
deducted in calculating netbacks.
(4) Operating netbacks, by product, are calculated by deducting, as
applicable, the related diluent, transportation, field operating
costs and royalties from revenues. Netbacks on a per-unit basis are
calculated by dividing operating netbacks 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 year ended December 31 2008 2007 % Change
-------------------------------------------------------------------------
Dilbit sales - bbl/d(1) 7,533 - -
-------------------------------------------------------------------------
Diluent purchased - bbl/d(1) (2,077) - -
-------------------------------------------------------------------------
Bitumen produced and sold - bbl/d(1) 5,456 - -
Crude oil produced and sold -bbl/d 1,029 792 30
Natural gas produced and sold - mcf/d 12,570 9,172 37
-------------------------------------------------------------------------
Total - boe/d 8,581 2,320 270
-------------------------------------------------------------------------
(1) Since declaring Pod One "commercial" effective March 1, 2008. Daily
averages are based on total calendar days during the year.
Upstream Netbacks Per Unit Of Production
For the year ended December 31
-------------------------------------------------------------------------
Bitumen Crude Oil Natural Gas Total
($ per bbl) ($ per bbl) ($ per mcf) ($ per boe)
-------------------------------------------------------------------------
2008
Production revenue $45.74 $82.01 $7.90 $50.49
Royalties (0.47) (19.19) (1.64) (5.00)
Operating costs (26.42) (12.01) (1.46) (20.38)
Operating netback $18.85 $50.81 $4.80 $25.11
-------------------------------------------------------------------------
2007
-------------------------------------------------------------------------
Production revenue - $52.80 $6.38 $43.22
Royalties - (12.57) (0.67) (6.93)
Operating cost - (11.05) (1.84) (11.06)
-------------------------------------------------------------------------
Operating netback - $29.18 $3.87 $25.23
-------------------------------------------------------------------------In 2008, upstream revenues were $265 million, compared to $37 million in
2007, an increase of $228 million. Contributions to this significant revenue
gain were new oil sands revenues (since declaring Pod One commercial effective
March 1, 2008) of $198 million, higher crude oil revenues ($16 million) and
natural gas revenues ($15 million higher), arising from increased production
and higher selling prices. In the first quarter of 2008, we entered into a
''costless collar'' natural gas 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 intended to speculate on
future natural gas prices, but rather to protect the downside risk to our cash
flow and the lending value of our assets. The impact of the hedge in 2008 had
the effect of reducing natural gas revenues by $831,000 or $0.18 per Mcf.
Royalties for 2008 were $15.7 million compared to $5.9 million in 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 year came as a result of additional
conventional crude oil and natural gas production volumes and increased
product pricing. Additionally, oil sands production royalties payable at the
rate of one percent of the bitumen selling price also contributed to increased
royalties in 2008.
On October 25, 2007, the Government of Alberta unveiled a new royalty
regime. The new regime was introduced for conventional oil, natural gas and
bitumen effective January 1, 2009 and is linked to price and production
levels. It applies to both new and existing oil sands projects and
conventional oil and gas activities. The impact of the new royalty regime on
Connacher will be dependent on, among other things, commodity prices, bitumen
valuation, specified allowed costs that are recoverable in the pre-payout
period for oil sands projects and production volumes.
Field operating costs of $64 million for 2008 were substantially higher
than in 2007 ($9.4 million). Most of the increase ($52.8 million) relates to
new oil sands production since March 1, 2008. Incremental crude oil and
natural gas production volumes also caused field operating costs to increase
by $1.4 million over the prior year, but on a per unit basis, operating costs
for conventional production were in line with the prior year.
Oil sands field operating costs of $52.8 million since March 1, 2008
averaged $26.42 per barrel of bitumen produced. Approximately 40 percent of
this cost was for natural gas required in the SAGD steaming process. While the
production company's production and sale of natural gas ultimately offsets
this cost, the cost is required to be reported separately as part of the cost
of producing bitumen. Oil sands field operating costs were impacted by a minor
turnaround to clean out vessels at Pod One, by a debottlenecking to manage
vapours produced by the treating process, downtime to activate a new trucking
terminal and downtime for our mandated turnaround to inspect boilers and
pressure safety valves. As a significant portion of other field operating cost
components (such as personnel and electricity) are fixed in nature, a
reduction in per unit field operating costs is anticipated to be achievable
with increases in bitumen production volumes.
The overall upstream operating netback for 2008 of $25.11 per produced
boe was significantly influenced by our bitumen production, which is heavy oil
and had a lower netback of $18.85 per bitumen barrel produced, offset by
increases in commodity selling prices.Reconciliation of Upstream Operating Netback to Net Earnings
-------------------------------------------------------------------------
For the year ended December 31 2008 2007
-------------------------------------------------------------------------
($000, except per unit amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Upstream operating netback,
as above $78,874 $25.11 $21,358 $25.23
Interest and other income 5,434 1.73 748 0.88
Downstream margin - net (7,490) (2.38) 48,202 56.92
General and administrative (11,814) (3.76) (8,543) (10.09)
Stock-based compensation (4,575) (1.46) (5,650) (6.67)
Finance charges (34,653) (11.03) (6,858) (8.10)
Foreign exchange (loss) gain (12,291) (3.91) 26,900 31.77
Depletion, depreciation
and accretion (56,448) (17.97) (31,061) (36.68)
Income taxes 5,311 1.69 (13,005) (15.36)
Equity interest in Petrolifera
earnings and dilution gain 11,049 3.52 8,870 10.47
-------------------------------------------------------------------------
Net earnings (loss) $(26,603) $(8.46) $40,961 $48.37
-------------------------------------------------------------------------
Downstream Revenues and MarginsConnacher's refinery, located in Great Falls, Montana (the "Refinery"),
is a strategic fit with our oil sands development. It is the closest U.S.
refinery to Alberta's oil sands and processes Canadian heavy crude oil,
similar to Great Divide dilbit (diluent mixed with bitumen), into a range of
higher value products, including regular and premium gasoline, jet fuel and
diesel as well as home heating oil and asphalt. The Refinery provides a
physical hedge for our bitumen revenues by recovering a portion of the
differntial between West Texas Intermediate (WTI) and heavy crude oil price.
The Refinery is a complex operation and includes reforming, isomerization
and alkylation processes for formulation of gasoline blends, hydro-treating
for sulphur removal and fluid catalytic cracking for conversion of heavy gas
oils to gasoline and distillate products. It also is a major supplier of
paving grade asphalt, polymer modified grades and asphalt emulsions for road
construction. The Refinery markets products in Montana and neighboring regions
by truck and rail transport.
The Refinery is subject to a number of seasonal factors which may cause
product sales revenues to vary throughout the year. The Refinery's primary
asphalt market is paving for road construction, which is in greater demand
during the summer. Consequently, prices and 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. Seasonal factors also affect the production and sale of
gasoline, which has a higher demand in summer months and the production and
sale of distillate and diesel, which has a higher winter demand. As a result,
inventory levels, sales volumes and prices can be expected to fluctuate on a
seasonal basis.
In 2008, refining revenues were $374 million compared to $313 million in
2007 because of higher refined product prices. In addition, costs of sales for
2008 were $382 million compared to $265 million in 2007 due to higher crude
costs.
Our refining margins fell markedly in 2008, as the selling prices of
refined products did not keep pace with rising crude and other feedstock
costs. Our heavy oil refining margins also typically capture a portion of the
difference between heavy and light crude oil costs. As this differential
narrowed in 2008, so did refining margins.The operating results of our Refinery for 2008 and 2007 are summarized
below.
Refinery Throughput
-------------------------------------------------------------------------
Year ended December 31 2008 2007
-------------------------------------------------------------------------
Crude charged - bbl/d(1) 9,194 9,485
-------------------------------------------------------------------------
Refinery production - bbl/d(2) 10,180 10,444
-------------------------------------------------------------------------
Sales of produced refined products - bbl/d 9,492 10,282
-------------------------------------------------------------------------
Sales of refined products (includes
purchased products) - bbl/d(3) 10,181 10,877
-------------------------------------------------------------------------
Refinery utilization(4) 97% 99.8%
-------------------------------------------------------------------------
(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
-------------------------------------------------------------------------
Sour crude oil 93% 92%
Other feedstocks & blend 7% 8%
-------------------------------------------------------------------------
Revenues and Margins ($000)
-------------------------------------------------------------------------
Refining sales revenue $374,248 $313,050
Refining - crude oil and operating costs 381,738 264,848
-------------------------------------------------------------------------
Refining margin $(7,490) $48,202
-------------------------------------------------------------------------
Refining margin (%) (2.0)% 15.4%
-------------------------------------------------------------------------
Sales of Produced Refined Products (Volume %)
-------------------------------------------------------------------------
Gasolines 38% 38%
Diesel fuels 19% 17%
Jet fuels 6% 6%
Asphalt 33% 35%
LPG and other 4% 4%
-------------------------------------------------------------------------
Total 100% 100%
-------------------------------------------------------------------------
Per Barrel of Refined Product Sold
-------------------------------------------------------------------------
Refining sales revenue $100.44 $78.85
Less: Refining - crude oil and operating costs $102.44 $66.71
-------------------------------------------------------------------------
Refining margin $(2.00) $12.14
-------------------------------------------------------------------------During the fourth quarter of 2008 the Refinery ran at reduced rates in
order to allow completion and tie-in of a new hydrogen plant and upgraded
hydrotreating facilities. Crude throughput for 2008 averaged 9,194 bbl/day or
97% of capacity.
By year end 2008, construction of the Ultralow Sulphur Diesel (ULSD)
project was substantially completed with commissioning of a new hydrogen plant
and production of ULSD scheduled for the first quarter of 2009. This project
was designed and completed over a period of two years at an estimated cost of
US $20.5 million. Facilities were also completed to allow ethanol blending and
marketing of ethanol blends in local markets. A new asphalt tank and rail
loading facilities were also constructed in 2008.
An assessment and preliminary design study for a potential expansion of
the Refinery to a capacity of 35,000 bbl/day was also undertaken. Due to
market conditions, this project was deferred after the completion of initial
designs.
Interest and Other Income
In 2008, the company earned interest of $2.7 million (2007 - $748,000) on
excess funds invested in secure short-term investments. Additionally, a gain
of $2.8 million was realized on the repurchase of a portion of the Second Lien
Senior Notes in the fourth quarter of 2008.
Surplus cash balances are invested in safe, secure interest bearing
deposit accounts. A portion (30 percent) of the interest earned is recognized
as income and a portion (70 percent) of it is credited to capitalized costs,
consistent with the way interest costs are accounted for on the Second Lien
Senior Notes. The company expenses 30 percent of interest costs in respect of
borrowings attributed to Pod One and together with other directly related
costs attributable to the Algar project, 70 percent of interest paid on the
Second Lien Senior Notes has been capitalized.
General and Administrative Expenses
In 2008, general and administrative ("G&A") expenses were $11.8 million
compared to $8.5 million in 2007, an increase of 38 percent, reflecting
increased staffing to support the operation of Great Divide and Pod One. G&A
of $5.2 million was also capitalized in 2008 (2007 - $3.4 million).
Stock Based Compensation
The company recorded non-cash stock-based compensation charges in the
respective periods as follows:-------------------------------------------------------------------------
Years Ended December 31
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Charged to G&A expense $4,575 $5,650
-------------------------------------------------------------------------
Capitalized to property and equipment $1,471 $2,220
-------------------------------------------------------------------------
$6,046 $7,870
-------------------------------------------------------------------------The reduction from the prior period is due to fewer options being
granted.
The significant deterioration in equity markets, attributed to
uncertainties arising from unprecedented financial and economic conditions,
adversely impacted the stock market value of the company's equity in the
fourth quarter of 2008. In turn, this had a negative consequence to
motivational and retention value of the company's option plan for its
employees. Concerned about the possible loss of quality staff during a period
of substantial planned growth, the company offered its employees (excluding
directors and officers) the opportunity to exchange significant "out of the
money" options for a reduced number of new options based on the fair market
value of the options. In the fourth quarter of 2008, stock-based compensation
of $675,000 was recognized (ie. expensed or capitalized) related to the
exchange of options.
Finance Charges
Financing charges were $34.7 million in 2008 compared to $6.9 million
reported in 2007. The increase resulted from interest and accretion expense
related to the Second Lien Senior Notes issued in late 2007, financing costs
related to the company's decision to terminate the Revolving Credit Facilities
and a full year of interest and accretion expense on the Convertible
Debentures.
Foreign Exchange Gains and Losses
As the value of the Canadian dollar weakened in the latter part of 2008,
the company recorded an unrealized foreign exchange loss of $131 million with
respect to the translation of its U.S. dollar denominated Second Lien Senior
Notes. This loss was partially offset by a gain of $98 million realized in
November 2008 when the company monetized its cross-currency and interest rate
swaps, the reversal of a $9 million mark to market loss reported at December
31, 2007 and by unrealized gains of $12 million on translating U.S.
dollar-denominated cash balances.
In 2007, the company repaid another U.S. dollar-denominated loan when the
Canadian dollar was stronger and realized a foreign exchange gain of $30
million, which gain then was partially offset by an unrealized loss of $3
million on translating US dollar denominated cash balances.
Depletion, Depreciation and Accretion ("DD&A")
Depletion expense is calculated using the unit-of-production method based
on total estimated proved reserves. DD&A in 2008 was $45 million, a 96 percent
increase from last year (2007 - $23 million) primarily due to significant
increases in production, depletion of Pod One capitalized costs commencing on
March 1, 2008 and to the significant additions made to capital assets in 2008.
This equates to $14.33 per boe of production compared to $27.16 per boe last
year.
Capital costs of $297 million (2007 - $413 million) related to oil sands
projects in the pre-production stage and undeveloped land acquisition costs of
$14.2 million (2007 - $14.7 million), were excluded from the depletion
calculation. However, future development costs of $1.3 billion (2007 - $14.3
million) for proved undeveloped reserves were included in the depletion
calculation. Costs excluded from the depletion pool have been separately
tested for impairment.
Included in DD&A is MRCI refinery depreciation of $8.2 million (2007 -
$5.3 million), depreciation of furniture, equipment and leaseholds of $1.5
million (2007 - $1.2 million) and a charge of $1.7 million (2007 - $1.6
million) in respect of the company's estimated asset retirement obligations
("ARO"). The ARO charges will continue to be necessary in the future to
accrete the currently booked discounted liability of $26.4 million to the
estimated total undiscounted liability of $47.3 million over the remaining
economic life of the company's oil and gas properties.
Ceiling Test
Oil and gas companies are required to compare the recoverable value of
their oil and gas assets to their recorded carrying value at the end of each
reporting period. Excess carrying values over ceiling value are to be written
off against earnings. No write-down was required for any reporting period in
2008 or 2007.
Income Taxes
The income tax recovery of $5.3 million in 2008 includes a current tax
recovery of $12.9 million, principally related to US refinery operations and a
future income tax provision of $7.6 million reflecting the change in tax pools
during the year.
At December 31, 2008 the company had approximately $89 million of
non-capital losses which expire over time to 2028, $551 million of deductible
resource pools and $26 million of deductible financing costs. The future
income tax benefit of these have been recognized at December 31, 2008.
Additionally, the company had $167 million of capital losses available to
reduce capital gains in future. These capital losses have no expiry and their
future income tax benefit has not been recognized due to uncertainty of their
realization at December 31, 2008.
The income tax provision of $13 million in 2007 includes a provision for
current income taxes of $11 million related to the Refinery and $2 million
related to Canadian capital and other taxes.
Equity Interest In Petrolifera Petroleum Limited ("Petrolifera") Earnings
Connacher accounts for its 24 percent equity investment in Petrolifera
using the equity method of accounting. Connacher's equity interest share of
Petrolifera's earnings in 2008 was $3.1 million (2007 - $7.0 million).
Dilution Gain
In April 2007, Connacher exercised warrants to purchase 1.7 million
common shares in Petrolifera for total consideration of $5.1 million. As a
result, the company maintained its then 26 percent equity interest as other
Petrolifera shareholders similarly exercised warrants on identical terms.
Connacher booked a dilution gain of $1.9 million as a consequence of these
transactions.
In June 2008, Petrolifera issued an additional 4.4 million common shares
to raise $40 million. Connacher did not subscribe for any of these shares.
Consequently, Connacher's equity interest in Petrolifera was reduced from 26
percent to 24 percent. This change resulted in a dilution gain of $8 million,
recognized by Connacher in 2008.
Net Earnings
For 2008 the company reported a loss of $26.6 million ($0.13 per basic
and diluted share outstanding). This compares to earnings of $41.0 million or
$0.20 per basic and diluted share for 2007. The change year over year is
explained in the income and expense components herein. Included in the year's
loss were non-cash charges totaling $80 million. These included DD&A, foreign
exchange, future taxes, finance charges, stock-based compensation and the
write-offs of deferred financing charges and front end engineering design
studies related to the deferral of refinery expansion plans.
Shares Outstanding
For 2008, the weighted average number of common shares outstanding was
210,793,657 (2007 - 200,092,469) and the weighted average number of diluted
shares outstanding, as calculated by the treasury stock method, was
214,647,452 (2007 - 202,766,939).
As at March 19, 2009, the company had the following securities issued and
outstanding:211,290,790 common shares;
16,025,620 share purchase options;
387,495 share units under the share awards plan; and
20,010,000 common shares issuable upon conversion of the $100,050,000
convertible debentures.Liquidity and Capital Resources
The current financial crisis has severely reduced liquidity in capital
markets. Economic uncertainty and significant volatility in commodity markets
and stock markets have also occurred around the world. Connacher's share price
and the trading value of its Second Lien Senior Notes and Convertible
Debentures have been adversely affected by the uncertainty of future crude oil
and natural gas prices, as well as by the impact of anticipated new
environmental regulations, which could affect the economics of our business.
Notwithstanding the challenges imposed by this crisis and current economic
conditions, management believes that the company has attractive
internally-generated growth prospects which, with our cash balances and the
impact of an improvement in commodity prices, will allow us to expand our
operations. In the interim, however, lower world oil prices are expected to
result in lower per unit revenues, netbacks, cash flow and earnings. We
anticipate increasing production and sales volumes in 2009 which could
partially offset the impact of lower world commodity prices.
In response to these economic and market conditions, the company has
reduced its capital expenditure budget for the 2009 winter exploration and oil
sands delineation program and curtailed some capital projects (notably, the
expansion of our downstream refining capacity and the construction of an oil
sands sales and diluent pipeline) and we suspended the construction of Algar
until there is more visibility of improved industry conditions. We anticipate
this will be evidenced by improved commodity pricing, improved credit and
capital markets and improved general economic conditions.
To date approximately $150 million has been invested in Algar. The
majority of the long-lead equipment items have been built. The road to the
plant site and well pads have also been constructed. The site is considered
ready for resumption of civil construction at a later date. We estimate that
it will require approximately 275 days and approximately $209 million of
capital to complete the project once a decision to resume construction is
made.
At December 31, 2008, the company had working capital of $198 million
(December 31, 2007 - $390 million), including $224 million of cash on hand
(December 31, 2007 - $392 million).
In light of the volatility of current commodity prices and the
U.S.:Canadian dollar exchange rate and their significance to the company's
operating performance, management continues to assess alternative hedging
strategies to protect the company's cash flow from the risk of potentially
lower crude oil and refined product pricing and adverse exchange rate
fluctuations. Although the company's integrated business model provides some
protection, it does not provide a perfect hedge. The purpose of any such
hedge(s) would be to ensure sufficient cash flow to continue to service
indebtedness, complete capital projects and protect the credit capacity of its
oil and gas reserves in a volatile and weak commodity price and weakened
economic environment.
In order to mitigate commodity price exposure, in November 2008 the
company entered into a foreign exchange collar which throughout 2009 sets a
floor of CAD $1.1925 per US $1.00 and a ceiling of CAD $1.3000 per US $1.00 on
a notional amount of US $10,000,000 of production revenue per month.
Additionally, in early 2009 the company entered into WTI hedges at crude
oil prices of US $46.00/bbl and US $49.50/bbl on a notional volume of 5,000
barrels of oil per day for a significant portion of 2009.
For 2008, cash flow was $55 million ($0.26 per basic and fully diluted
share outstanding), 22 percent higher than in 2007.
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. Net earnings are
reconciled with cash flow on the Consolidated Statement of Cash Flows and
below.
Reconciliation of net earnings to cash flow from operations before
working capital and other changes:-------------------------------------------------------------------------
Twelve months ended December 31
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Net earnings (loss) $(26,603) $40,961
-------------------------------------------------------------------------
Items not involving cash:
-------------------------------------------------------------------------
Depletion, depreciation and accretion 56,448 31,061
-------------------------------------------------------------------------
Stock-based compensation 4,575 6,071
-------------------------------------------------------------------------
Non-cash financing charges 8,934 2,168
-------------------------------------------------------------------------
Future income tax provision 7,623 27
-------------------------------------------------------------------------
Employee future benefits 730 447
-------------------------------------------------------------------------
Realized foreign exchange transactions (105,414) (29,754)
-------------------------------------------------------------------------
Unrealized foreign exchange loss 122,342 2,854
-------------------------------------------------------------------------
Gain on repurchase of Second Lien Senior Notes (2,769) -
-------------------------------------------------------------------------
Dilution gain (7,964) (1,917)
-------------------------------------------------------------------------
Equity interest in Petrolifera loss (earnings) (3,085) (6,953)
-------------------------------------------------------------------------
Cash flow from operations before
working capital and other charges $54,817 $44,965
-------------------------------------------------------------------------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 Convertible
Debentures and the Second Lien Senior Notes. The company maintains no
off-balance sheet financial instruments, other than the hedges noted above.
As the Second Lien Senior Notes are denominated in US dollars, there is a
foreign exchange risk associated with their semi-annual interest payments and
the repayment of principal in 2015 using Canadian currency to acquire US
currency.
Connacher's objectives in managing its cash, debt and equity, 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 and 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 structure using a number of financial
ratios and industry metrics to ensure its objectives are being met.-------------------------------------------------------------------------
As at December 31
-------------------------------------------------------------------------
Connacher's capital structure
is composed of: ($000) 2008 2007
-------------------------------------------------------------------------
Long term debt(1) $778,732 $664,462
-------------------------------------------------------------------------
Shareholders' equity
-------------------------------------------------------------------------
Share capital, contributed surplus
and equity component 437,899 444,086
-------------------------------------------------------------------------
Accumulated other comprehensive income (loss) 7,802 (13,636)
-------------------------------------------------------------------------
Retained earnings 23,386 49,989
-------------------------------------------------------------------------
Total $1,247,819 $1,144,901
-------------------------------------------------------------------------
Debt to book capitalization(2) 62% 58%
-------------------------------------------------------------------------
Debt to market capitalization(3) 81% 44%
-------------------------------------------------------------------------
(1) Long-term debt is stated at its carrying value, which is net of
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 year end market value of
shareholders' equity plus long-term debt.Connacher had a high calculated ratio of debt to capitalization at
December 31, 2008. This is due to pre-funding the full cost of Algar in 2007
through the issuance of US $600 million of Second Lien Senior Notes, a portion
of the proceeds of which was used to repay indebtedness incurred previously
for Pod One. As at December 31, 2008, the company's net debt (long-term debt,
net of cash on hand) was $555 million, its net debt to book capitalization was
44 percent and its net debt to market capitalization was 57 percent.
The company had the following long-term debt outstanding, as at December
31-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Second Lien Senior Notes, 10 1/4%,
due December 15, 2015 $694,086 $570,594
-------------------------------------------------------------------------
Convertible Debentures, 4 3/4%,
due June 30, 2012 84,646 81,133
-------------------------------------------------------------------------
Cross-currency interest rate swap - 12,735
-------------------------------------------------------------------------
Total 778,732 664,462
-------------------------------------------------------------------------
Less current portion of long-term debt - -
-------------------------------------------------------------------------
Long-term portion $778,732 $664,462
-------------------------------------------------------------------------
Sensitivity Analysis
The following table shows sensitivities to cash flow as a result of
changes to oil prices, production volumes and foreign exchange rates. The
analysis is based on recent prices and production volumes.
-------------------------------------------------------------------------
Change $ million $/share(1)
-------------------------------------------------------------------------
WTI price(2) 5.00/bbl 6 0.03
Bitumen production 500 bbl/d 3 0.01
Exchange rate (US/Canadian) $0.05 6 0.03
-------------------------------------------------------------------------
(1) Based on 211 million shares outstanding at December 31, 2008
(2) After royalties
Recent Financings
Second Lien Senior NotesIn December 2007 the company issued US $600 million Second Lien 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 were targeted to fund the construction of Algar, the company's
second 10,000 bbl/d SAGD oil sands project. The Second Lien Senior Notes bear
interest at a rate of 10.25%, payable semi-annually on June 15 and December
15. No principal payments are due until the maturity date of December 15,
2015. The Second Lien Senior Notes are secured by a second lien covering
substantially all of the company's assets with the exception of its investment
in Petrolifera.
To December 31, 2008, the proceeds of the Second Lien Senior Note
financing have been utilized as follows:-------------------------------------------------------------------------
($000s) As stated at As
the time of actually
financing(1) applied(1)
-------------------------------------------------------------------------
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 US:CAD exchange rates in late 2007.
(2) Net proceeds are available for funding capital expenditures relating
to Algar. As at December 31, 2008, approximately $81 million of cash
had been used to fund the Algar expenditures incurred, another $48
million of incurred expenditures is included in accounts payable and
a further $21 million of costs (primarily long-lead equipment items)
has been requisitioned.In order to partially mitigate the foreign currency translation exposure
on its U.S. dollar denominated Second Lien Senior Notes, the company entered
into cross currency and interest rate swaps on a notional US $300 million
amount. To capitalize on a weak Canadian dollar and for the prospect of adding
significant additional cash to its treasury at no cost or shareholder
dilution, the cross-currency and interest rate swaps were terminated in
November 2008 and the company realized cash proceeds of $89.1 million. The
company will again consider hedging this U.S.-dollar denominated debt in
future, again, if appropriate circumstances warrant.
In the fourth quarter of 2008, the company repurchased US $8 million face
value of Second Lien Senior Notes in the market at a discount, cancelled the
notes and realized a gain of $2.7 million.
Flow-through Shares
In November 2007, the company issued 10,450,000 common shares on a
flow-through basis at $5.00 per share for gross proceeds of $52.25 million.
Proceeds from this financing were used in December 2007 and in the first
quarter of 2008 to drill exploratory core holes and to shoot 3D seismic in
order to further delineate the company's oil sands reserves and resources. The
company renounced the income tax benefits of these expenditures ($52.25
million) to the subscribing investors effective December 31, 2007.
Proceeds of the flow-through share financing were utilized as follows:-------------------------------------------------------------------------
($000s) As stated at As
the time of actually
financing applied
-------------------------------------------------------------------------
Gross proceeds $52,250 $52,250
-------------------------------------------------------------------------
Underwriters' commissions and issue costs (2,913)(1) (2,748)(1)
-------------------------------------------------------------------------
Exploration expenditures (52,250) (52,250)
-------------------------------------------------------------------------
$ - $ -
-------------------------------------------------------------------------
(1) Paid from general funds of the company.Revolving Credit Facilities
At December 31, 2008 the company had available revolving lines of credit
in the amounts of CAD $150 million and US $40 million. No amounts were drawn
under the revolving credit facilities at December 31, 2008 other than as
security for letters of credit in the amount of $5 million. Subsequent to
December 31, 2008, the company terminated the Revolving Credit Facilities. The
unamortized costs of establishing this facility ($3.75 million) were expensed
in 2008.
Subsequent to year end Connacher put in place $20 million demand
operating facility for the purpose of issuing letters of credit. The facility
is secure by cash and a first lien claim on certain assets of the company.
Convertible Debentures
On May 25, 2007 Connacher issued senior unsecured subordinated
convertible debentures ("Convertible Debentures") with a face value of
$100,050,000. The Convertible Debentures mature June 30, 2012, unless
converted prior to that date and bear interest at an annual rate of 4.75
percent, payable semiannually on June 30 and December 31. The Convertible
Debentures are convertible at any time into common shares at the option of the
holder at a conversion price of $5.00 per share.
Proceeds of the Convertible Debenture financing were utilized as follows:-------------------------------------------------------------------------
($000s) As stated at As
the time of actually
financing applied
-------------------------------------------------------------------------
Gross proceeds $100,050 $100,050
-------------------------------------------------------------------------
Underwriters' commissions and issue costs (3,252) (4,040)
-------------------------------------------------------------------------
Net proceeds 96,798 96,010
-------------------------------------------------------------------------
Repay short-term debt (52,500) (52,500)
-------------------------------------------------------------------------
Fund Pod One and other oil sands projects (35,000) (37,500)
-------------------------------------------------------------------------
Fund conventional capital program (8,298) (4,810)
-------------------------------------------------------------------------
Fund operating expenses (1,000) (1,200)
-------------------------------------------------------------------------
Balance - -
-------------------------------------------------------------------------The Convertible Debentures are redeemable in whole or in part by the
company, on or after June 30, 2010, at a redemption price equal to 100 percent
of the principal amount of the Convertible Debentures to be redeemed, plus
accrued and unpaid interest, provided that the market price of the company's
common shares is at least 120 percent of the conversion price of the
Convertible Debentures.
The conversion feature of the Convertible Debentures has been accounted
for as a separate component of equity in the amount of $16,823,000. The
remainder of the net proceeds of the Convertible Debentures of $79,243,000 has
been recorded as long-term debt, which will be accreted up to the face value
of $100,050,000 over the five-year term of the Convertible Debentures.
Accretion and interest paid are recorded as finance charges on the
Consolidated Statement of Operations and Retained Earnings. If the Convertible
Debentures are converted to common shares, the value of the conversion feature
will be reclassified to share capital along with the principal amounts
converted.Commitments, Contingencies, Guarantees, Contractual Obligations and Off
Balance Sheet Arrangements
The company's annual commitments under leases for office premises and
operating costs, software license agreements, other equipment and long term
debt are as follows:
-------------------------------------------------------------------------
Contractual obligations 2010- 2013- Subsequent
($000) 2009 2012 2014 to 2014 Total
-------------------------------------------------------------------------
Long-term debt - 100,050 - 721,056 821,106
-------------------------------------------------------------------------
Asset retirement
obligations - 413 - 25,983 26,396
-------------------------------------------------------------------------
Operating leases 3,739 8,083 5,259 6,574 23,655
-------------------------------------------------------------------------
Employee future benefits 676 - - - 676
-------------------------------------------------------------------------
Total 4,415 108,546 5,259 753,613 871,833
-------------------------------------------------------------------------The above table excludes ongoing crude oil and refined product purchase
commitments of the Refinery, which are in the normal course of business and
are contracted at market prices, where the products are for resale into the
market.
Additionally, the company has various guarantees and indemnifications in
place in the ordinary course of business, none of which are expected to have a
significant impact on the company's financial statements or operations.
The company has not entered into any off-balance sheet arrangements,
other than the hedging arrangements addressed herein.Property and Equipment Additions
Property and equipment additions totaled $352 million in 2008 and $323
million in 2007. A breakdown of the expenditures follows:
-------------------------------------------------------------------------
Twelve months ended December 31
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Crude oil, natural gas and
oil sands expenditures $327,452 $307,047
-------------------------------------------------------------------------
Refinery expenditures 24,284 15,915
-------------------------------------------------------------------------
$351,736 $322,962
-------------------------------------------------------------------------For 2008, conventional and oil sands exploration expenditures totaled
$327 million; Algar facility and equipment expenditures totaled $128 million;
conventional oil and natural gas facilities and drilling programs totaled $56
million; Pod One turnaround costs, a horizontal well re-drill, truck loading
facilities and capitalized pre-operating costs totaled $30 million; and
capitalized interest, G&A, lease acquisitions, corehold exploratory drilling
seismic and other expenditures totaled $113 million. The capital program added
significant additional natural gas production and significant additions to
proved, probable and possible reserves and to contingent and prospective
resources, as reported in the company's Annual Information Form for the year
ended December 31, 2008.
At our refinery, $14 million was incurred on the ultra low sulphur diesel
conversion project in 2008. Total 2008 capital expenditures tracked closely to
our 2008 capital budget. The balance of $10 million was incurred for
additional tankage, maintenance, environmental enhancements and expansion
study projects.
In 2007, capital costs were primarily focused on the construction of the
Great Divide Pod One facility, core hole exploratory drilling, SAGD well pairs
and the upstream drilling program.Fourth Quarter
-------------------------------------------------------------------------
For the three months ended
-------------------------------------------------------------------------
December September December
($000) 31, 2008 30, 2008 31, 2007
-------------------------------------------------------------------------
REVENUE
-------------------------------------------------------------------------
Upstream, net of royalties $41,957 $96,291 $7,376
-------------------------------------------------------------------------
Downstream 56,803 127,726 75,733
-------------------------------------------------------------------------
Interest and other income 3,349 541 231
-------------------------------------------------------------------------
102,109 224,558 83,340
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EXPENSES
-------------------------------------------------------------------------
Upstream - diluent purchases
and operating costs 39,258 52,125 2,826
-------------------------------------------------------------------------
Upstream transportation costs 4,815 6,256 -
-------------------------------------------------------------------------
Downstream - crude oil purchases
and operating costs 66,964 125,455 70,638
-------------------------------------------------------------------------
General and administrative 3,063 2,774 1,711
-------------------------------------------------------------------------
Stock-based compensation 1,088 790 1,213
-------------------------------------------------------------------------
Finance charges 12,138 7,786 2,603
-------------------------------------------------------------------------
Foreign exchange loss (gain) 5,643 1,439 2,555
-------------------------------------------------------------------------
Depletion, depreciation and accretion 20,191 14,968 8,658
-------------------------------------------------------------------------
153,160 211,593 90,204
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings (loss) before
income taxes and other items (51,051) 12,965 (6,864)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current income tax provision (recovery) (14,798) 387 (313)
-------------------------------------------------------------------------
Future income tax provision (recovery) 8,180 1,233 (4,878)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Earnings (loss) before other items (44,433) 11,345 (1,673)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Equity interest in Petrolifera earnings 841 854 812
-------------------------------------------------------------------------
Dilution gain (loss) - (60) 21
-------------------------------------------------------------------------
-------------------------------------------------------------------------
NET EARNINGS (LOSS) $(43,592) $12,139 $(840)
-------------------------------------------------------------------------
Reconciliation of net earnings (loss) to cash flow from operations before
working capital and other changes
-------------------------------------------------------------------------
For the three months ended
-------------------------------------------------------------------------
December September December
($000) 31, 2008 30, 2008 31, 2007
-------------------------------------------------------------------------
Net earnings (loss) $(43,592) $12,139 $(840)
-------------------------------------------------------------------------
Items not involving cash:
-------------------------------------------------------------------------
Depletion, depreciation and accretion 20,191 14,968 8,658
-------------------------------------------------------------------------
Stock based compensation 1,088 790 1,299
-------------------------------------------------------------------------
Non-cash financing costs 2,389 1,238 1,034
-------------------------------------------------------------------------
Employee future benefits 386 117 88
-------------------------------------------------------------------------
Future income tax provision
(recovery) 8,180 1,233 (4,878)
-------------------------------------------------------------------------
Unrealized foreign exchange loss 115,694 1,439 32,309
-------------------------------------------------------------------------
Realized foreign exchange
transactions (105,414) - (29,754)
-------------------------------------------------------------------------
Gain on repurchase of
Second Lien Senior Notes (2,769) - -
-------------------------------------------------------------------------
Dilution (gain) loss - 60 (21)
-------------------------------------------------------------------------
Equity interest in Petrolifera
earnings (841) (854) (812)
-------------------------------------------------------------------------
Cash flow from operations before
working capital and other changes $(4,688) $31,130 $7,083
-------------------------------------------------------------------------For the fourth quarter 2008, upstream production was 10,341 boe/d
compared to 2,233 boe/d in the fourth quarter of 2007 and 9,966 boe/d in the
third quarter of 2008. This was achieved despite the curtailment of bitumen
production at Pod One in mid-December 2008. Revenue was $102 million compared
to $83 million in the fourth quarter of 2007 and $225 million in the third
quarter of 2008.
The collapse of crude oil prices late in 2008 had a significant adverse
impact on oil sands economics. As a producer of bitumen in Alberta, we reacted
quickly to weaker crude oil prices, widened heavy oil differentials and
challenging operating costs by curtailing production at Pod One in December
2008. Subsequently, within about one month of this curtailment, we were
fortunately able to restore our operations to full capacity, because of steps
we took to capitalize on contango in the crude oil price futures market and
other factors, which improved our selling price at Pod One. Accordingly, we
are now in the midst of ramping volumes up to pre-shutdown levels, which were
approaching 10,000 bbl/d in December, 2008. At those production levels, our
steam/oil ratios ("SOR's") were favorable, at around three times overall and
approaching two times at some of our better wells, before the curtailment. We
anticipate again achieving these metrics in 2009.
Refining revenues and margins in the fourth quarter were impacted by
lower commodity prices, reduced product demand for gasoline and diesel due to
economic circumstances and for asphalt due to seasonality demands and reduced
processing volumes to allow completion and tie-in of our new hydrogen and
upgraded hydro treating facilities.
In the fourth quarter of 2008, interest and other income included a gain
of $2.8 million realized upon the re-purchase and cancellation of US $8
million face value of Second Lien Notes, as the notes were purchased at a
discount in the open market.
In the fourth quarter of 2008, the company also monetized the
cross-currency and interest rate swaps by unwinding them and realized net cash
proceeds of $89.1 million, of which $97.6 million was recorded as a realized
foreign exchange gain, $2.6 million was recorded as a finance charge and $5.9
million was capitalized to property and equipment.
For the three months ended December 31, 2008, the company sustained a
loss of $43.6 million ($0.21 per share) compared to a loss of $840,000 (nil
per share) in the fourth quarter of 2007 and net earnings of $12.1 million
($0.06 per share) in the third quarter of 2008. This loss was primarily due to
non-cash charges totaling $39 million. These charges included foreign
exchange, future taxes and writeoffs of deferred financing costs and front end
engineering and design studies related to the deferral of refinery expansion
plans. Operating cash flow was negative $4.7 million in the fourth quarter of
2008 ($0.02 per share) compared to positive cash flow of $7.1 million ($0.03
per share) in the fourth quarter of 2007 and cash flow of $31.1 million ($0.15
per share) in the third quarter of 2008. The primary reasons for these period
to period variations are noted above.
Outlook
We expect 2009 will continue to be challenging. We have already
experienced challenges during the first few months of the year. However, we
anticipate a much improved full year contribution from our refining operations
primarily due to anticipated healthy asphalt markets, with wider margins, as
newly-announced U.S. government infrastructure projects are anticipated to
result in an unprecedented demand for asphalt. This product is currently in
short supply in the United States. This improvement should start to be
apparent in the second quarter of 2009. We also anticipate positive net
operating income from our upstream operations during 2009 as a result of
hedging and marketing activities and anticipated reductions in transportation
and operating costs.
We have significant cash balances and together with anticipated positive
operating income in 2009, we anticipate being able to meet all our financial
obligations throughout 2009, even if crude oil prices stay at WTI US$45.00/bbl
for the balance of this year. We continue to believe preserving our liquidity
and protecting our assets are the priority responsibilities for 2009. We have
ample identified reserves and resources to remain confident of our future
growth prospects and we believe energy prices will improve as the year
unfolds. To stabilize our outlook in a volatile period and protect against the
possibility of renewed crude oil weakness, we have arranged WTI hedges at
prices of US$46/bbl and US$49.50/bbl on approximately one half of our bitumen
production for most of 2009. Relative to our consumption of natural gas at Pod
One we have a built-in physical hedge with our own natural gas production at
Marten Creek, Latornell, Seal and other areas. This minimizes the impact of
volatility in natural gas prices on our overall operations.
The company's business plan anticipates long-term growth, with continued
increases in revenue and cash flow from Pod One, conventional crude oil and
natural gas production, while in due course completing the Algar project and
subsequently expanding all aspects of our business. A more cautious short-term
approach has recently been adopted in light of existing adverse capital and
commodity market conditions.
In response to the current conditions, the company reduced its capital
expenditure budget for the 2009 winter exploration and oil sands delineation
program and curtailed some capital projects (notably, the expansion of our
downstream refining capacity and the construction of an oil sands sales and
diluent pipeline). Construction of Algar was suspended until we see more
visibility in improved industry conditions which we anticipate will be
evidenced by improved commodity pricing, improved capital markets and improved
general economic conditions.
To date we have invested approximately $150 million in Algar, having
built the majority of the long-lead equipment items, constructed the road to
the site and prepared the site for resumption of civil construction at a later
date. Approximately 275 days and, based on current estimates, approximately
$209 million, will be required to complete the project.
In view of changed capital market conditions, we have elected to preserve
liquidity by reducing our 2009 capital expenditures to $123 million from $373
million as follows:($million) New Original
-------------------------------------------------------------------------
Upstream
Conventional $13 $15
Pod One 18 20
Algar 29 208
Algar capitalized items 30 69
Cogeneration 4 22
Exploration 9 10
EIA and other 3 3
Downstream
Refining 17 26
-------------------------------------------------------------------------
Total $123 $373
-------------------------------------------------------------------------Related Party Transactions
In 2008 the company paid professional legal fees of $1.1 million (2007 -
$667,000) to a law firm in which the company's Corporate Secretary is a
partner. Transactions with the foregoing related parties occurred within the
normal course of business and have been measured at their exchange amount on
normal business terms. The exchange amount is the amount of consideration
established and agreed to by the related parties.
A portion of the company's conventional crude oil and natural gas
exploration and drilling activities, which activities are anticipated to
continue in the future, was conducted in an industry-standard joint venture
arrangement with a company, an officer of which is also a director of
Connacher. Transactions with the joint venture partner occurred within the
normal course of business and have been measured at their exchange amount on
normal business terms. The exchange amount is the amount of consideration
established and agreed to by the company and the joint venture partner. These
capital expenditures incurred to date are not considered material to the
company's overall capital expenditure program.Significant Accounting Policies and Application of Critical Accounting
EstimatesThe 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 in light of changing circumstances,
economic and otherwise. 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 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 equal or 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 proved oil and gas reserves on the
financial results and 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 oil and gas 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
production. 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 oil and
gas assets 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 for changes in
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 management 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 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
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 a timing difference reverses are impacted by future income and
capital expenditures. Rates are also affected by legislation 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.
These estimates by their nature are subject to measurement uncertainty.
Convertible Debentures
The Convertible Debentures have been recorded as a compound financial
instrument in accordance with Section 3863 of the Canadian Institute of
Chartered Accountants, or CICA, Handbook. The fair value of the liability
component was determined at the date of issue based on our incremental
borrowing rate for debt with similar terms. The amount of the equity component
was determined as a residual after deducting the amount of the liability
component from the face value of the issue.
Share Award Plan
Obligations for payments in cash or common shares under our share award
plan for non-employee directors are accrued as compensation expense over the
vesting period. Fluctuations in the price of our common shares change the
accrued compensation expense and are recognized when they occur.
Refinery Accounting
Since its acquisition in March 2006, the Refinery's financial results are
reported in accordance with Canadian GAAP and have been consolidated with our
other business units. The preparation of the Refinery's financial results
require certain estimates and judgments that affect the reported amounts of
assets, liabilities, revenues and expenses, and related disclosure of
contingent assets and liabilities as of the date of the financial statements.
Actual results may differ from those estimates under different assumptions or
conditions. Our management considers the following new accounting policies to
be the most critical to understanding the judgments that are involved and the
uncertainties that could impact on our results of operations, financial
condition and cash flow.
Inventory Valuation
Crude oil and refined product inventories are stated at the lower of cost
or net realizable value.
Since acquiring the refining assets in March 2006, management
re-evaluated the inventory costing method and has chosen the average cost
method in order to conform to (then) impending (now mandated) Canadian GAAP
changes. The effect of this change was to decrease inventory by $2.5 million
at December 31, 2006. Net realizable value is determined using current
estimated selling prices.
Maintenance Costs
The Refinery units require regular major maintenance and repairs, which
are commonly referred to as "turnarounds." Catalysts used in certain refinery
processes also require routine "change-outs." The required frequency of the
maintenance varies by unit and by catalyst, but generally is every two to five
years. Turnaround costs which meet the definition of property, plant and
equipment are capitalized and amortized over the period to the next scheduled
turnaround or change-out. In order to minimize downtime during turnarounds,
contract labor as well as maintenance personnel are utilized on a continuous
24 hour basis. Whenever possible, turnarounds are scheduled so that some units
continue to operate while others are down for maintenance.
Employee Future Benefits
As a consequence of the Refinery acquisition and related employment of
Refinery personnel, our U.S. subsidiary, MRCI, adopted employee future benefit
plans with effect from March 31, 2006. A non-contributory defined benefit
retirement plan covers only the Refinery's employees from March 31, 2006.
MRCI's policy is to make regular contributions in accordance with the funding
requirements of ERISA. Benefits are to be based on the employee's years of
service and compensation. We also established defined contribution (U.S. tax
code "401(k)") plans that cover all Refinery employees from March 31, 2006.
MRCI's contributions are based on employees' compensation and partially match
employee contributions.
Long-lived Refining Assets
Depreciation and amortization is calculated based on estimated useful
lives and salvage values. When assets are placed into service, estimates are
made with respect to their useful lives that are believed to be reasonable.
However, factors such as new technologies, competition, regulation or
environmental matters could cause changes to estimates, thus impacting the
future calculation of depreciation and amortization. Long-lived assets are
also evaluated for potential impairment by identifying whether indicators of
impairment exist and, if so, assessing whether the long-lived assets are
recoverable from estimated future undiscounted cash flow. The actual amount of
impairment loss, if any, to be recorded is equal to the amount by which a
long-lived asset's carrying value exceeds its fair value. Estimates of future
discontinued cash flow and fair values of assets require subjective
assumptions with regard to future operating results and actual results could
differ from those estimates.
Goodwill
Goodwill arose on the acquisition of Luke in 2006. Goodwill, which
represents the excess of purchase price over fair value of net assets
acquired, is assessed for impairment annually. Goodwill and all other assets
and liabilities have been allocated to our segments, referred to as reporting
units. To assess impairment, the fair value of each reporting unit is
determined and compared to the book value of the reporting unit. If the fair
value of the reporting unit is less than the book value, then a second test is
performed to determine the amount of the impairment. The amount of the
impairment is determined by deducting the fair value of the reporting unit's
assets and liabilities from the fair value of the reporting unit to determine
the implied fair value of goodwill and comparing that amount to the book value
of the reporting unit's goodwill. Any excess of the book value of goodwill
over the implied fair value of goodwill is the impairment amount.
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
On February 13, 2008, the Canadian Accounting Standards Board confirmed
that publicly accountable enterprises will be required to adopt IFRS in place
of Canadian GAAP for interim and annual reporting purposes for fiscal years
beginning on or after January 1, 2011. The impact of the change in accounting
principles on our future financial position and results of operations is not
determinable or quantifiable at the present time.
We have commenced our IFRS conversion project which consists of four
phases: diagnostic; design and planning; solution development; and
implementation. Regular reporting is provided to management and to the Audit
Committee of the Board of Directors.
We have completed the diagnostic phase, which involved a review of the
differences between current Canadian GAAP and IFRS. During this phase we
determined that the differences which will have the greatest impact on
Connacher's consolidated financial statements relate to accounting for
exploration and development activities and property, plant and equipment
impairments of capital assets, asset retirement obligations and the reporting
of employee future benefits. Their financial impacts have yet to be
quantified. We are currently engaged in the design and planning and the
solution development phases of our project. We have identified and documented
the high impact areas, including an analysis of financial system impacts and
have engaged in ongoing discussions with our external auditors. The impact on
our disclosure controls, internal controls over financial reporting and the
impact on contracts and lending agreements will also be determined.
In September 2008 the International Accounting Standards Board issued an
exposure draft to amend IFRS accounting standards in respect of property,
plant and equipment as at the date of the initial transition to IFRS. That
exposure draft, if adopted, would permit issuers currently using the full cost
method of accounting, (as described in the CICA Handbook - Accounting
Guideline 16 Oil and Gas accounting - Full Cost), to allocate the balance of
property, plant and equipment as determined under Canadian GAAP to the IFRS
categories of exploration and evaluation assets and development and producing
properties without requiring full retroactive restatement of historic balances
to the IFRS basis of accounting. If the exposure draft is adopted we
anticipate using the exemption. We are also monitoring the development of
guidance being prepared by a committee of the Canadian Association of
Petroleum Producers on how to apply IFRS to oil and gas exploration and
development activities. This is expected to be finalized in March 2009. We
continue to monitor the IFRS adoption efforts of our peers and to participate
in the process for a smooth transition to IFRS in advance of the deadline.
Risk Factors and Risk Management
General
Connacher is engaged in the oil and gas exploration, development,
production, and refining industry. This business is inherently risky and there
is no assurance that hydrocarbon reserves will be discovered and economically
produced. Operational risks include competition, reservoir performance
uncertainties, environmental factors, and regulatory and safety concerns.
Financial risks associated with the petroleum industry include fluctuations in
commodity prices, interest rates, currency exchange rates and the cost of
goods and services.
Connacher's financial and operating performance is potentially affected
by a number of factors including, but not limited to, risks associated with
the oil and gas, commodity prices and exchange rates, environmental
legislation, changes to royalty and income tax legislation, credit and capital
market conditions, credit risk for failure of performance of third parties and
other risks and uncertainties described in more detail in Connacher's Annual
Information Form filed with securities regulatory authorities.
Certain key risk factor some disclosed below. Reference should be made to
Connacher's most recent Annual Information Form for a description of
additional risk factors.
Connacher employs highly qualified people, uses sound operating and
business practices and evaluates all potential and existing wells using the
latest applicable technology. The company complies with government regulations
and has in place an up-to-date emergency response program. Connacher adheres
to environment and safety policies and standards. Asset retirement obligations
are recognized upon acquisition, construction and development of the assets.
Connacher maintains property and liability insurance coverage. The coverage
provides a reasonable amount of protection from risk of loss; however, not all
risks are foreseeable or insurable.
Global Financial Crisis
Recent market events and conditions, including disruptions in the
international credit markets and other financial systems and the deterioration
of global economic conditions, have caused significant volatility to commodity
prices. These conditions worsened in 2008 and are continuing in 2009, causing
a loss of confidence in the broader U.S. and global credit and financial
markets and resulting in the collapse of, and government intervention in,
major banks, financial institutions and insurers and creating a climate of
greater volatility, less liquidity, widening of credit spreads, a lack of
price transparency, increased credit losses and tighter credit conditions.
Notwithstanding various actions by governments, concerns about the general
condition of the capital markets, financial instruments, banks, investment
banks, insurers and other financial institutions caused the broader credit
markets to further deteriorate and stock markets to decline substantially.
These factors have negatively impacted company valuations and will impact the
performance of the global economy going forward.
Petroleum prices are expected to remain volatile for the near future as a
result of market uncertainties over the supply and demand of these commodities
due to the current state of the world economies, OPEC actions and the ongoing
global credit and liquidity concerns.
Commodity Price and Exchange Rate Risks
Connacher's future financial performance remains closely linked to crude
oil and natural gas commodity prices and foreign exchange rate changes which
may be influenced by many factors including global and regional supply and
demand, seasonality, worldwide political events and weather. These factors can
cause a high degree of price volatility. For example, from 2006 to 2008, the
monthly average price for benchmark WTI crude oil ranged from a low of
US$42.04/bbl to a high of US$134.02/bbl. During the same three-year period,
the natural gas AECO benchmark monthly average price ranged from a low of
$4.45/mcf to a high of $12.11/mcf and value of the Canadian dollar traded
between US$0.77 and US$1.09.
Crude oil and dilbit selling prices are based on U.S. dollar benchmarks
that result in our realized prices being influenced by the US$/Cdn$ currency
exchange rate, thereby creating another element of uncertainty. Should the
Canadian dollar strengthen compared to the U.S dollar, the resulting negative
effect on net earnings would be partially offset with exchange gains on
translating our U.S. dollar denominated debt, associated interest payments
thereon and U.S. refining results to Canadian dollars for financial statement
reporting purposes. The opposite would occur should the Canadian dollar weaken
compared to the U.S. dollar. Cash flow is not impacted by the effects of
currency fluctuations on translating our U.S. dollar denominated debt. We
mitigate some of the risk associated with changes in commodity prices through
the use of hedges and other derivative financial instruments. See Liquidity
and Capital Resources.
Regulatory Approval Risks
Before proceeding with most major development projects, Connacher must
obtain regulatory approvals, which approvals must be maintained in good
standing during the currency of the particular project. The regulatory
approval process involves stakeholder consultation, environmental impact
assessments and public hearings, among other factors. Failure to obtain
regulatory approvals, or failure to obtain them on a timely basis, could
result in delays, abandonment, or restructuring of projects and increased
costs, all of which could negatively impact future earnings and cash flow.
Failure to maintain approvals, licenses, permits and authorizations in good
standing could result in the imposition of fines, production limitations or
suspension orders.
Performance
Our financial and operating performance is potentially affected by a
number of factors, including, but not limited to the following.
Our ability to reliably operate our conventional and oil sands facilities
is important to meet production targets. We implemented planned maintenance
shutdowns in 2008 that are expected to improve reliability.
Operating costs could be impacted by inflationary pressures on labor,
volatile pricing for natural gas used as an energy source in oil sands
processes, and planned and unplanned maintenance. We continue to address these
risks though such strategies as application of technologies that help manage
operational workforce demand, offsetting natural gas purchases with our own
production and an increased focus on preventative maintenance.
While fiscal regimes in Alberta and Canada are generally stable relative
to many global jurisdictions, royalty and tax treatments are subject to
periodic review, the outcome of which is not predictable and could result in
changes to the company's planned investments and rates of return on existing
investments.
Management expects that fluctuations in demand and supply for refined
products, margin and price volatility, market competition and the seasonal
demand fluctuations for some of our refined products will continue to impact
our refining business.
There are certain risks associated with the execution of capital
projects, including the risk of cost overruns. Numerous risks and
uncertainties can affect construction schedules, including the availability of
labor and other impacts of competing projects drawing on the same resources
during the same time period.
Capital Requirements
The company anticipates making substantial capital expenditures for the
acquisition, exploration, development and production of bitumen, crude oil and
natural gas reserves and refining in the future. As the company's revenues may
decline as a result of decreased commodity pricing, it may be required to
reduce capital expenditures. In addition, uncertain levels of near term
industry activity coupled with the present global credit crisis exposes the
company to additional access to capital risk. There can be no assurance that
debt or equity financing, or cash generated by operations will be available or
sufficient to meet these requirements or for other corporate purposes or, if
debt or equity financing is available, that it will be on terms acceptable to
the company. The inability of the company to access sufficient capital for its
operations could have a material adverse effect on the company's business
financial condition, results of operations and prospects.
Third Party Credit Risk
An additional risk is credit risk for failure of performance by
counter-parties. This risk is controlled by an evaluation of the credit risk
before contract initiation and ensuring product sales and delivery contracts
are made with well-known and financially strong crude oil and natural gas
marketers.
The company may be exposed to third party credit risk through its
contractual arrangements with its current or future joint venture partners and
other parties. In the event such entities fail to meet their contractual
obligations to the company, such failures may have a material adverse effect
on the company's business, financial condition, results of operations and
prospects.
Environmental
All phases of the oil and gas and refining business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial, state and local laws and regulations.
Compliance with such legislation can require significant expenditures and a
breach may result in the imposition of fines and penalties, some of which may
be material. Environmental legislation is evolving in a manner expected to
result in stricter standards and enforcement, larger fines and liability and
potentially increased capital expenditures and operating costs. There has been
much public debate with respect to Canada's alternative strategies with
respect to climate change and the control of greenhouse gases. Implementation
of strategies for reducing greenhouse gases could have a material impact on
the nature of oil gas and refining operations, including those of the company.
Given the evolving nature of the issues related to climate change and the
control of greenhouse gases and resulting requirements, it is not possible to
predict either the nature of those requirements or the impact on the company
and its operations and financial condition.
Disclosure Controls and Procedures
The company's Chief Executive Officer ("CEO") and Chief Financial Officer
("CFO") have designed, or caused to be designed under their supervision,
disclosure controls and procedures to provide reasonable assurance that: (i)
material information relating to the company is made known to the company's
CEO and CFO by others, particularly during the period in which the annual
filings are being prepared; and (ii) information required to be disclosed by
the company in its annual filings, interim filings or other reports filed or
submitted by it under securities legislation is recorded, processed,
summarized and reported within the time period specified in securities
legislation. Such officers have evaluated, or caused to be evaluated under
their supervision, the effectiveness of the company's disclosure controls and
procedures at the financial year end of the company and have concluded that
the company's disclosure controls and procedures are effective at the
financial year end of the company for the foregoing purposes.
Internal Controls over Financial Reporting
The CEO and CFO have designed, or caused to be designed under their
supervision, internal controls over financial reporting to provide reasonable
assurance regarding the reliability of the company's financial reporting and
the preparation of financial statements for external purposes in accordance
with Canadian GAAP. Such officers have evaluated, or caused to be evaluated
under their supervision, the effectiveness of the company's internal controls
over financial reporting at the financial year end of the company and
concluded that the company's internal controls over financial reporting is
effective at the financial year end of the company for the foregoing purpose.
The company's CEO and CFO are required to cause the company to disclose
any change in the company's internal controls over financial reporting that
occurred during the company's most recent interim period that has materially
affected, or is reasonably likely to materially affect, the company's internal
controls over financial reporting. No material changes in the company's
internal controls over financial reporting were identified during such period
that has materially affected, or are reasonably likely to materially affect,
the company's internal controls over financial reporting.
It should be noted that a control system, including the company's
disclosure and internal controls and procedures, no matter how well conceived,
can provide only reasonable, but not absolute, assurance that the objectives
of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud. 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.
-------------------------------------------------------------------------
2007
-------------------------------------------------------------------------
Three Months Ended Mar 31 Jun 30 Sep 30 Dec 31
-------------------------------------------------------------------------
($000 except per
share amounts)
-------------------------------------------------------------------------
Revenues, net of royalties 65,923 93,266 101,991 83,340
-------------------------------------------------------------------------
Cash flow(1) 10,980 16,876 10,025 7,083
-------------------------------------------------------------------------
Basic, per share(1) 0.06 0.09 0.05 0.03
-------------------------------------------------------------------------
Diluted, per share(1) 0.05 0.08 0.05 0.03
-------------------------------------------------------------------------
Net earnings (loss) 4,984 22,228 14,589 (840)
-------------------------------------------------------------------------
Basic and diluted per
share 0.03 0.11 0.07 (0.00)
-------------------------------------------------------------------------
Property and equipment
additions 109,881 93,223 64,006 55,852
-------------------------------------------------------------------------
Cash on hand 66,209 25,375 754 392,271
-------------------------------------------------------------------------
Working capital surplus
(deficiency) 24,027 36,320 (19,853) 389,789
-------------------------------------------------------------------------
Term debt 207,828 272,559 260,606 664,462
-------------------------------------------------------------------------
Shareholders' equity 384,593 417,793 428,764 480,439
-------------------------------------------------------------------------
Operating Highlights
-------------------------------------------------------------------------
Upstream: Daily production/
sales volumes
-------------------------------------------------------------------------
Bitumen - bbl/d(2) - - - -
-------------------------------------------------------------------------
Crude oil - bbl/d 905 731 781 752
-------------------------------------------------------------------------
Natural gas - mcf/d 9,665 9,017 9,413 8,889
-------------------------------------------------------------------------
Equivalent - boe/d(3) 2,515 2,234 2,350 2,233
-------------------------------------------------------------------------
Product pricing
-------------------------------------------------------------------------
Bitumen - $/bbl(2) - - - -
-------------------------------------------------------------------------
Crude oil - $/bbl 49.09 49.79 55.98 56.79
-------------------------------------------------------------------------
Natural gas - $/mcf 7.76 7.02 4.70 5.82
-------------------------------------------------------------------------
Selected Highlights -
$/boe(3)
-------------------------------------------------------------------------
Weighted average
sales price 47.48 44.63 37.43 42.29
-------------------------------------------------------------------------
Royalties 11.22 3.23 6.32 6.34
-------------------------------------------------------------------------
Operating costs 8.54 13.08 9.00 13.77
-------------------------------------------------------------------------
Netback(4) 27.72 28.32 22.11 22.18
-------------------------------------------------------------------------
Downstream: Refining
-------------------------------------------------------------------------
Crude charged - bbl/d 9,621 9,248 9,400 9,610
-------------------------------------------------------------------------
Refining utilization - % 101 97 100 101
-------------------------------------------------------------------------
Margins - % 19 21 15 6
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
-------------------------------------------------------------------------
Shares outstanding at end
of period (000) 198,218 198,834 199,447 209,971
-------------------------------------------------------------------------
Weighted average shares
outstanding for the period
-------------------------------------------------------------------------
Basic (000) 198,119 198,360 199,167 204,701
-------------------------------------------------------------------------
Diluted (000) 200,008 209,088 221,554 220,362
-------------------------------------------------------------------------
Volume traded during
quarter (000) 55,292 61,162 70,939 52,198
-------------------------------------------------------------------------
Common share price ($)
-------------------------------------------------------------------------
High 4.13 4.43 4.40 4.08
-------------------------------------------------------------------------
Low 3.07 3.07 3.20 3.31
-------------------------------------------------------------------------
Close (end of period) 3.86 3.69 4.01 3.79
-------------------------------------------------------------------------
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
Three Months Ended Mar 31 Jun 30 Sept 30 Dec 31
----------------------------
($000 except per
share amounts)
-------------------------------------------------------------------------
Revenues, net of royalties 100,656 202,016 224,558 102,109
-------------------------------------------------------------------------
Cash flow(1) 7,825 20,550 31,130 (4,688)
-------------------------------------------------------------------------
Basic, per share(1) 0.04 0.10 0.15 (0.02)
-------------------------------------------------------------------------
Diluted, per share(1) 0.03 0.10 0.14 (0.02)
-------------------------------------------------------------------------
Net earnings (loss) (1,833) 6,683 12,139 (43,592)
-------------------------------------------------------------------------
Basic and diluted per
share (0.01) 0.03 0.06 (0.21)
-------------------------------------------------------------------------
Property and equipment
additions 115,984 80,403 69,175 86,174
-------------------------------------------------------------------------
Cash on hand 323,423 232,704 236,375 223,663
-------------------------------------------------------------------------
Working capital surplus
(deficiency) 287,105 234,110 200,177 197,914
-------------------------------------------------------------------------
Term debt 671,014 684,705 689,673 778,732
-------------------------------------------------------------------------
Shareholders' equity 471,559 479,477 496,509 469,087
-------------------------------------------------------------------------
Operating Highlights
-------------------------------------------------------------------------
Upstream: Daily production/
sales volumes
-------------------------------------------------------------------------
Bitumen - bbl/d(2) 1,773 6,123 6,810 7,086
-------------------------------------------------------------------------
Crude oil - bbl/d 996 981 957 1,187
-------------------------------------------------------------------------
Natural gas - mcf/d 10,493 14,220 13,188 12,405
-------------------------------------------------------------------------
Equivalent - boe/d(3) 4,518 9,474 9,966 10,341
-------------------------------------------------------------------------
Product pricing
-------------------------------------------------------------------------
Bitumen - $/bbl(2) 53.01 60.80 65.34 12.06
-------------------------------------------------------------------------
Crude oil - $/bbl 79.50 105.28 103.60 48.13
-------------------------------------------------------------------------
Natural gas - $/mcf 6.94 8.77 8.92 6.61
-------------------------------------------------------------------------
Selected Highlights -
$/boe(3)
-------------------------------------------------------------------------
Weighted average
sales price 54.46 63.37 66.41 21.73
-------------------------------------------------------------------------
Royalties 7.45 6.21 4.65 3.19
-------------------------------------------------------------------------
Operating costs 14.32 22.78 20.41 20.76
-------------------------------------------------------------------------
Netback(4) 32.69 34.38 41.35 (2.23)
-------------------------------------------------------------------------
Downstream: Refining
-------------------------------------------------------------------------
Crude charged - bbl/d 9,830 9,329 9,239 8,333
-------------------------------------------------------------------------
Refining utilization - % 104 98 97 88
-------------------------------------------------------------------------
Margins - % 1 (0.1) 2 (18)
-------------------------------------------------------------------------
COMMON SHARE INFORMATION
-------------------------------------------------------------------------
Shares outstanding at end
of period (000) 210,277 211,027 211,182 211,182
-------------------------------------------------------------------------
Weighted average shares
outstanding for the period
-------------------------------------------------------------------------
Basic (000) 210,234 210,658 211,093 211,182
-------------------------------------------------------------------------
Diluted (000) 210,234 214,530 213,174 211,575
-------------------------------------------------------------------------
Volume traded during
quarter (000) 63,718 107,001 112,401 110,244
-------------------------------------------------------------------------
Common share price ($)
-------------------------------------------------------------------------
High 3.94 5.26 4.65 2.95
-------------------------------------------------------------------------
Low 2.59 3.10 2.63 0.60
-------------------------------------------------------------------------
Close (end of period) 3.13 4.30 2.75 0.74
-------------------------------------------------------------------------
(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 fund its 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, no
production volumes were reported and 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. 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. Boes may
be misleading, particularly if used in isolation.
(4) Netback is a non-GAAP measure used by management as a measure of
operating efficiency and profitability. Netback per boe is calculated
as bitumen, crude oil and natural gas revenue less royalties and
operating costs divided by related production/sales volume. Netbacks
are reconciled to net earnings in the accompanying MD&A.
Connacher Oil and Gas Limited
Consolidated Balance Sheets
December 31
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
ASSETS
-------------------------------------------------------------------------
CURRENT
-------------------------------------------------------------------------
Cash and cash equivalents $223,663 $329,110
-------------------------------------------------------------------------
Restricted cash (Note 16(c)) - 63,161
-------------------------------------------------------------------------
Accounts receivable 20,492 25,084
-------------------------------------------------------------------------
Inventories (Note 5) 35,993 18,379
-------------------------------------------------------------------------
Due from Petrolifera (Note 6) 42 -
-------------------------------------------------------------------------
Prepaid expenses 2,221 2,520
-------------------------------------------------------------------------
Income taxes recoverable 13,875 4,279
-------------------------------------------------------------------------
296,286 442,533
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Property and equipment (Note 7) 985,054 671,422
-------------------------------------------------------------------------
Goodwill 103,676 103,676
-------------------------------------------------------------------------
Investment in Petrolifera (Note 6) 46,659 35,610
-------------------------------------------------------------------------
Deferred costs (Note 8) - 5,587
-------------------------------------------------------------------------
$1,431,675 $1,258,828
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES
-------------------------------------------------------------------------
CURRENT
-------------------------------------------------------------------------
Accounts payable and accrued liabilities $98,372 $52,744
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long term debt (Note 10) 778,732 664,462
-------------------------------------------------------------------------
Future income taxes (Note 9) 58,296 36,818
-------------------------------------------------------------------------
Asset retirement obligations (Note 11) 26,396 24,365
-------------------------------------------------------------------------
Employee future benefits (Note 12) 792 -
-------------------------------------------------------------------------
864,216 725,645
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Share capital, contributed surplus
and equity component (Note 13) 437,899 444,086
-------------------------------------------------------------------------
Accumulated other comprehensive income (loss) 7,802 (13,636)
-------------------------------------------------------------------------
Retained earnings 23,386 49,989
-------------------------------------------------------------------------
469,087 480,439
-------------------------------------------------------------------------
$1,431,675 $1,258,828
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Commitments, contingencies and guarantees
(Note 17)
Connacher Oil and Gas Limited
Consolidated Statements of Operations and Retained Earnings
Years Ended December 31
-------------------------------------------------------------------------
($000, except per share amounts) 2008 2007
-------------------------------------------------------------------------
REVENUE
-------------------------------------------------------------------------
Upstream, net of royalties $249,657 $30,722
-------------------------------------------------------------------------
Downstream 374,248 313,050
-------------------------------------------------------------------------
Interest and other income 5,434 748
-------------------------------------------------------------------------
629,339 344,520
-------------------------------------------------------------------------
EXPENSES
-------------------------------------------------------------------------
Upstream - diluent purchases and operating costs 156,284 9,364
-------------------------------------------------------------------------
Upstream transportation costs 14,499 -
-------------------------------------------------------------------------
Downstream - crude oil purchases and
operating costs (Note 5) 381,738 264,848
-------------------------------------------------------------------------
General and administrative 11,814 8,543
-------------------------------------------------------------------------
Stock-based compensation (Note 13) 4,575 5,650
-------------------------------------------------------------------------
Finance charges 34,653 6,858
-------------------------------------------------------------------------
Foreign exchange loss (gain) 12,291 (26,900)
-------------------------------------------------------------------------
Depletion, depreciation and accretion 56,448 31,061
-------------------------------------------------------------------------
672,302 299,424
-------------------------------------------------------------------------
Earnings (loss) before income taxes and
other items (42,963) 45,096
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current income tax provision (recovery) (Note 9) (12,934) 12,978
-------------------------------------------------------------------------
Future income tax provision (Note 9) 7,623 27
-------------------------------------------------------------------------
(5,311) 13,005
-------------------------------------------------------------------------
Earnings (loss) before other items (37,652) 32,091
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Equity interest in Petrolifera earnings (Note 6) 3,085 6,953
-------------------------------------------------------------------------
Dilution gain (Note 6) 7,964 1,917
-------------------------------------------------------------------------
NET EARNINGS (LOSS) (26,603) 40,961
-------------------------------------------------------------------------
-------------------------------------------------------------------------
RETAINED EARNINGS, BEGINNING OF YEAR 49,989 9,028
-------------------------------------------------------------------------
RETAINED EARNINGS, END OF YEAR $23,386 $49,989
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE (Note 16(a))
-------------------------------------------------------------------------
Basic $(0.13) $0.20
-------------------------------------------------------------------------
Diluted $(0.13) $0.20
-------------------------------------------------------------------------
Connacher Oil and Gas Limited Consolidated
Statements of Comprehensive Income (Loss)
Year Ended December 31
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Net earnings (loss) $(26,603) $40,961
-------------------------------------------------------------------------
Foreign currency translation adjustment 21,438 (13,506)
-------------------------------------------------------------------------
Comprehensive income (loss) $(5,165) $27,455
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Connacher Oil and Gas Limited
Consolidated Statements of Accumulated Other Comprehensive Income (Loss)
Year Ended December 31
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($000) 2008 2007
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Balance, beginning of period $(13,636) $(130)
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Foreign currency translation adjustment 21,438 (13,506)
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Balance, end of period $7,802 $(13,636)
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Connacher Oil and Gas Limited
Consolidated Statements of Cash Flow
Years Ended December 31
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($000) 2008 2007
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Cash provided by (used in) the following activities:
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OPERATING
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Net earnings (loss) $(26,603) $40,961
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Items not involving cash:
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Depletion, depreciation and accretion 56,448 31,061
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Stock-based compensation (Note 13) 4,575 6,071
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Financing charges - non-cash portion 8,934 2,168
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Employee future benefits (Note 12a) 730 447
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Future income tax provision 7,623 27
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Realized foreign exchange transactions (105,414) (29,754)
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Unrealized foreign exchange loss 122,342 2,854
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Gain on repurchase of Second Lien Senior Notes (2,769) -
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Dilution gain (7,964) (1,917)
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Equity interest in Petrolifera earnings (3,085) (6,953)
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Cash flow from operations before working
capital and other changes 54,817 44,965
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Changes in non-cash working capital (Note 16(b)) (27,583) 6,464
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Pension funding (Note 12) - (781)
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Asset retirement expenditures (209) (311)
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27,025 50,337
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FINANCING
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Repayment of oil sands term loan - (180,000)
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Issue of common shares, net of share issue costs 761 50,968
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Increase in bank debt - 135,856
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Repayment of bank debt - (154,963)
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Issuance of Convertible Debentures,
net of issue costs (Note 10) - 96,010
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Issuance of Second Lien Senior Notes,
net of issue costs (Note 10) - 575,449
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Repurchase of Second Lien Senior Notes (6,262) -
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Deferred financing costs (77) (3,848)
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Proceeds on unwinding of cross currency swap 97,600 -
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92,022 519,472
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INVESTING
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Development of upstream and
downstream properties (351,320) (301,877)
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Decrease in restricted cash (Note 16(c)) 72,113 59,627
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Exercise of Petrolifera warrants - (5,143)
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Change in non-cash working capital (Note 16(b)) 50,789 (8,669)
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(228,418) (256,062)
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NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (109,371) 313,747
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Impact of foreign exchange on foreign
currency denominated cash balances 3,924 (4,240)
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CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 329,110 19,603
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CASH AND CASH EQUIVALENTS, END OF YEAR $223,663 $329,110
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Supplementary information - Note 16
Connacher Oil and Gas Limited Notes To The Consolidated Financial
Statements
Years Ended December 31, 2008 and 2007
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 ("Canadian GAAP"). Operating in Canada and
in the U.S. through its subsidiary Montana Refining Company, Inc.
("MRCI"), the company is in the business of exploring for and developing,
producing, refining and marketing conventional petroleum and natural gas
and the exploration, development and production of bitumen in the oil
sands of northern Alberta.
2. Significant Accounting Policies
Cash and cash equivalents
Cash and cash equivalents include short-term deposits with initial
maturities of three months or less, when purchased.
Inventory valuation
Crude oil and refined product inventories are stated at the lower of cost
or net realizable value, determined under the weighted average cost
method. Net realizable value is determined using current estimated
selling prices.
Deferred costs
These amounts include costs incurred in relation to the company's
revolving credit facilities, which have been deferred and were being
amortized over their term.
Petroleum, natural gas and bitumen ("upstream") operations
The company follows the full cost method of accounting whereby all costs
relating to the exploration for and development of crude oil, natural gas
and bitumen reserves are capitalized on a country by country cost centre
basis.
Capitalized costs of petroleum and natural gas properties and related
equipment within a cost centre are depleted and depreciated using the
unit-of-production method based on estimated proved reserves before
royalties as determined by independent consulting engineers. For the
purpose of this calculation, production and reserves of natural gas are
converted to equivalent units of crude oil based on relative energy
content (6:1).
The company applies a "ceiling test" to the net book value of petroleum
and natural gas properties to ensure that such carrying value does not
exceed the estimated fair value of the properties. The carrying value is
assessed to be recoverable when the sum of the undiscounted cash flows
expected from the production of proved reserves and the cost, less
impairment, of unproved properties exceeds the carrying value. If the
carrying value is assessed to not be recoverable, the calculation
compares the carrying value to the sum of the discounted cash flows
expected from the production of proved and probable reserves and the
cost, less impairment, of unproved properties. Should the carrying value
exceed this sum, an impairment loss is recognized. The cash flows are
estimated using projected future product prices and costs and are
discounted using the credit adjusted risk-free interest rate.
Costs of acquiring and evaluating unproved properties are excluded from
costs subject to depletion and depreciation until it is determined
whether or not proved reserves are attributable to the properties or
impairment occurs. 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
earnings.
During 2008, Pod One, the company's first oil sands project commenced
commercial production. From March 1, 2008, revenue has been recognized,
operating costs have been expensed and capitalized costs related to Pod
One have been depleted.
To date, all costs, including financing costs, incurred in relation to
the company's Algar oil sands project in Northern Alberta, have been
capitalized as the project is considered to be in the pre-production
stage. Judgment is required in order to determine when commercial
operations have commenced. Once it is determined that commercial
operations have been achieved, revenue will be recognized, operating
costs will be expensed to earnings and the capitalized costs of the
project will be added to the full cost pool for depletion and ceiling
test calculations. Revenues generated in the period prior to commencement
of commercial operations are credited against capitalized costs.
Gains or losses on sales of properties are recognized only when crediting
the proceeds to the cost pool would result in a change of 20 percent or
more in the depletion and depreciation rate.
Refining ("downstream") assets
Depreciation and amortization of refining assets is calculated based on
estimated useful lives and salvage values. When assets are placed into
service, estimates are made with respect to their useful lives that are
believed to be reasonable. However, factors such as competition,
regulation or environmental matters could cause changes to estimates,
thus impacting the future calculation of depreciation and amortization.
Long-lived refining assets are also evaluated for potential impairment by
identifying whether indicators of impairment exist and, if so, assessing
whether the long-lived assets are recoverable from estimated future
undiscounted cash flows. The actual amount of impairment loss, if any, to
be recorded is equal to the amount by which a long-lived asset's carrying
value exceeds its fair value. Estimates of future cash flows and fair
values of assets require subjective assumptions with regard to future
operating results and actual results could differ from those estimates.
The refining assets require regular major maintenance and repairs which
are commonly referred to as "turnarounds". Catalysts used in certain
refinery processes also require routine "change-outs". The required
frequency of the maintenance varies by asset type and by catalyst, but
generally is every two to five years. The costs of turnarounds and
change-outs are recorded as capital costs and are amortized over the
period to the next scheduled turnaround or change-out.
Furniture, equipment and leaseholds
Furniture and equipment are recorded at cost and are being depreciated on
a declining balance basis at rates of 20 percent to 30 percent per year.
Leaseholds are amortized over the lease term.
Investment in Petrolifera Petroleum Limited
The investment in Petrolifera Petroleum Limited ("Petrolifera") is
accounted for on an equity basis, whereby the carrying value reflects the
company's investment, at the lower of cost and fair value, and the
company's equity interest share of its accumulated income. Any permanent
decline in value would be charged to earnings.
Income taxes
The company follows the liability method of accounting for income taxes.
Under this method, income tax liabilities and assets are recognized for
the estimated tax consequences attributed to differences between the
amounts reported in the financial statements and their respective tax
bases, using substantively enacted income tax rates. The effect of a
change in income tax rates on future income tax assets and liabilities is
recognized in income in the period that the change occurs. Future tax
assets recognized are assessed by management at each balance sheet date
for impairment. An impairment is recognized when management assesses that
it's not more likely than not that the asset will be recovered.
Goodwill
Goodwill, which represents the excess of purchase price over fair value
of net assets acquired, is annually assessed for impairment. Goodwill and
all other assets and liabilities have been allocated to the company's
segments, referred to as reporting units. To assess impairment, the fair
value of each reporting unit is determined and compared to the book value
of the reporting unit. If the fair value of the reporting unit is less
than the book value, then a second test is performed to determine the
amount of the impairment. The amount of the impairment is determined by
deducting the fair value of the reporting unit's assets and liabilities
from the fair value of the reporting unit to determine the implied fair
value of goodwill and comparing that amount to the book value of the
reporting unit's goodwill. Any excess of the book value of goodwill over
the implied fair value of goodwill is the impairment amount.
Asset retirement obligations
The company recognizes an asset retirement obligation liability for
abandoning petroleum, natural gas and bitumen wells, related facilities,
compressors and gas plants, removal of equipment from leased acreage and
returning such land to its original condition by estimating and recording
the fair value of each asset retirement obligation arising in the period
a well or related asset is drilled, constructed or acquired. This fair
value is estimated using the present value of the estimated future cash
outflows to abandon the asset at the company's credit adjusted risk-free
interest rate and includes estimates for inflation. The obligation is
reviewed regularly by management based upon current regulations, costs,
technologies and industry standards. The discounted obligation is
initially capitalized as part of the carrying amount of the related
petroleum, natural gas or bitumen property and a corresponding liability
is recognized. The liability is accreted against income until it is
settled or the property is sold and is included as a component of
depletion and depreciation expense. The amount of the capitalized
retirement obligation is depleted and depreciated on the same basis as
the other capitalized petroleum or natural gas property costs. Actual
restoration expenditures are charged to the accumulated obligation as
incurred and costs for properties disposed are removed.
Employee future benefits
The costs of the defined benefit pension plan are actuarially determined
using the projected benefit method prorated on service and management's
best estimate of expected plan investment performance, salary escalation,
retirement ages of employees and expected health care costs. For the
purpose of calculating the expected return on plan assets, those assets
are valued at a market-related value. The cost of the company's portion
of the defined contribution plan is expensed as incurred.
Convertible Debentures
The Convertible Debentures have been classified as long term debt and
equity at their fair value at the date of issue. The fair value of the
liability component has been determined based on the company's
incremental borrowing rate for debt with similar terms. The amount of the
equity component has been determined as a residual after deducting the
amount of the liability component from the face value of the debentures.
Share award plan for non-employee directors
Obligations for payments in cash or common shares under the company's
share award plan for non-employee directors are accrued as stock-based
compensation expense and liabilities over the vesting period.
Fluctuations in the price of the company's common shares change the
accrued compensation expense and are recognized over the remaining
vesting period.
Flow-through shares
The resource expenditure deductions for income tax purposes related to
exploratory and development activities funded by flow-through share
arrangements are renounced to investors in accordance with tax
legislation. Accordingly, share capital is reduced and the future income
tax liability is increased by the tax benefits related to the
expenditures at the time they are renounced.
Foreign currency translation
The company has assessed the operations of MRCI to be self-sustaining.
Assets and liabilities of self-sustaining foreign operations are
translated into Canadian dollars at the rate of exchange in effect at the
balance sheet date and revenues and expenses are translated at the
average monthly rates of exchange during the periods. Gains or losses on
translation of self-sustaining foreign operations are included in
accumulated other comprehensive income (loss) in shareholders' equity.
Transaction-based foreign exchange gains and losses are included in
earnings.
Financial instruments
Financial instruments include cash and cash equivalents, restricted cash,
accounts receivable, amounts due from Petrolifera, the Revolving Credit
Facilities, accounts payable, the Convertible Debentures, the Second Lien
Senior Notes and the cross-currency and interest rate swaps. All carrying
values of financial instruments approximate fair value with the exception
of the Convertible Debentures and Second Lien Senior Notes, which are
initially recognized at fair value and are subsequently accounted for
under the amortized cost method. Accretion of the discount on the
Convertible Debentures and Second Lien Senior Notes is a finance cost.
The company has classified all of its financial instruments, with the
exception of the Second Lien Senior Notes, the Convertible Debentures and
the Revolving Credit Facilities, as Held for Trading, which requires
measurement on the balance sheet at fair value with any changes in fair
value recorded in earnings. This classification has been chosen due to
the nature of the company's financial instruments, which, except for the
Second Lien Senior Notes, the Convertible Debentures and Revolving Credit
Facilities are of a short-term nature such that there are no material
differences between the carrying values and the fair values. Transaction
costs related to financial instruments classified as Held for Trading are
recorded in earnings. Transaction costs relating to the Convertible
Debentures and Second Lien Senior Notes are amortized against earnings
over the term of the instrument using the effective interest rate method.
Any amounts that would be drawn on the Revolving Credit Facilities would
be classified as "other financial liabilities" on the consolidated
balance sheet because the fair value of such liability would closely
approximate its carrying value due to the revolving nature of such debt.
Transaction costs related to the Revolving Credit Facilities were being
amortized over their term.
Joint venture operations
A part of the company's activities is conducted with others, and these
consolidated financial statements reflect only the company's
proportionate interest in such activities.
Revenue recognition
Petroleum, natural gas and refined product sales are recognized as
revenue at the time the respective commodities are delivered to
purchasers.
Unrealized gains and losses from the company's natural gas and crude oil
commodity price risk management activities are recorded as revenue based
on mark-to-market calculations.
Prior to attaining commercial operations status, revenues on bitumen
sales from the company's oil sands projects are credited to those project
costs. Upon attaining commercial operations, oil sands revenues are
recognized as bitumen is delivered to purchasers.
Natural gas, bitumen, diluent and other products and services may be
purchased and sold between the company's subsidiaries. On consolidation,
these intercompany amounts are eliminated.
Stock-based compensation
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option pricing model. The amount is
expensed or capitalized and credited to contributed surplus over the
vesting period. Upon exercise of the options, the exercise proceeds
together with amounts credited to contributed surplus, are credited to
share capital.
Segment reporting
The company has changed its segmentation in 2008 to better reflect the
organization of its business by combining 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. Comparative figures have been
reclassified.
The above have been defined as the operating segments of the company
because they (a) produce products which are sufficiently differentiated
from each other so as to be separately identifiable; (b) are those for
which operating results are regularly reviewed by the company's chief
operating decision maker to make decisions about resources to be
allocated to each segment and to assess its performance; and (c) are
those for which discrete financial information is available.
Segment accounting policies are the same as those described in this
summary of significant accounting policies. Transfers of assets between
segments are recorded at carrying value.
Measurement uncertainty
The timely preparation of the consolidated financial statements in
conformity with Canadian GAAP requires that management make estimates and
assumptions and use judgment regarding the reported amounts of assets and
liabilities at the date of the consolidated financial statements and the
reported amounts of revenues and expenses during the period. Such
estimates primarily relate to unsettled transactions and events as of the
date of the consolidated financial statements. Accordingly, actual
results may differ from estimated amounts as future confirming events
occur. Income taxes are subject to re-assessment by tax authorities.
Estimates of the stage of completion of capital projects at the financial
statement date affect the calculation of additions to property and
equipment and the related accrued liability.
Amounts recorded for depreciation, depletion and accretion, asset
retirement costs and obligations, amounts used for ceiling test and
impairment calculations and amounts used in the determination of future
taxes are based on estimates of petroleum, natural gas and bitumen
reserves and future costs required to develop those reserves. By their
nature, these estimates of reserves, including the estimates of future
prices and costs and the related future cash flows are subject to
measurement uncertainty.
Amounts recorded for stock-based compensation expense are based on the
historical volatility of the company's share price, which may not be
indicative of future volatility. Accordingly, those amounts are subject
to measurement uncertainty.
Credit risk
The company generally extends unsecured credit to customers and
therefore, the collection of accounts receivable may be affected by
changes in economics or other conditions. Management believes this risk
is mitigated by the size and reputation of the companies to which credit
has been extended. The company has not historically experienced any
material credit loss in the collection of accounts receivable.
Commodity and financial risk management
The company periodically enters into contracts to fix the price of a
portion of its petroleum and natural gas sales to reduce the exposure to
commodity price fluctuations. Occasionally these contracts are
denominated in Canadian dollars to mitigate foreign exchange risks.
To help mitigate some of the foreign currency and interest rate risk
associated with its US-denominated Senior Notes, the company from time to
time enters into cross-currency and interest rate swaps.
Unless any of these transactions are designated as "hedges" for
accounting purposes, they would be marked to market for financial
statement reporting purposes.
Per share amounts
Basic per share amounts are calculated using the weighted average number
of common shares outstanding for the year. The company follows the
treasury stock method to calculate diluted per share amounts. The
treasury stock method assumes that any proceeds from the exercise of in-
the-money stock options and other dilutive instruments plus the amount of
stock-based compensation not yet recognized would be used to purchase
common shares at the average market price during the period.
3. New Accounting Standards
As of January 1, 2008, the company adopted two new CICA Handbook
requirements, section 3862, "Financial Instruments - Disclosures" and
section 3863, "Financial Instruments - Presentation," which replaced
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 adopted 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." Various changes have
been made to other sections of the CICA Handbook for consistency
purposes. 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.
Over the next two years the CICA will adopt its new strategic plan for
the direction of accounting standards in Canada, which was ratified in
January 2006. As part of the plan, Canadian GAAP for public companies
will converge with International Financial Reporting Standards ("IFRS")
with an effective date of January 1, 2011. The company continues to
monitor and assess the impact of the convergence of Canadian GAAP with
IFRS.
4. Financial Instruments And Capital Risk Management
Financial Instruments
The financial instruments standard (CICA Section 3855) establishes the
recognition and measurement criteria for financial assets, financial
liabilities and derivatives. All financial instruments are required to be
measured at fair value on initial recognition of the instrument, except
for certain related party transactions. Measurement in subsequent periods
depends on whether the financial instrument has been classified as "held-
for-trading," "available-for-sale," "held-to-maturity," "loans and
receivables," or "other financial liabilities" as defined by the
accounting standard.
Financial assets and financial liabilities "held-for-trading" are
measured at fair value with changes in those fair values recognized in
net earnings. Financial assets "available-for-sale" are measured at fair
value, with changes in those fair values recognized in OCI. Financial
assets "held-to-maturity," "loans and receivables" and "other financial
liabilities" are measured at amortized cost using the effective interest
rate method of amortization.
The company has classified all of its financial instruments, with the
exception of the Second Lien Senior Notes, the Convertible Debentures and
the Revolving Credit Facilities, as Held for Trading. This classification
has been chosen due to the nature of the company's financial instruments,
which, except for the Second Lien Senior Notes, the Convertible
Debentures and Revolving Credit Facilities, are of a short-term nature
such that there are no material differences between the carrying values
and the fair values.
The Second Lien Senior Notes and the Convertible Debentures have been
classified as "other financial liabilities" and are accounted for on the
amortized cost method, with transaction costs being amortized over the
life of the instrument using the effective interest rate method.
Any amounts drawn on the Revolving Credit Facilities would have been
classified as "other financial liabilities" on the consolidated balance
sheet. The fair value of any such liability would have closely
approximated carrying value due to its revolving nature. Transaction
costs related to the Revolving Credit Facilities were being amortized
over their term.
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 Petrolifera, its Revolving Credit Facilities, the Convertible
Debentures and the Second Lien Senior Notes.
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.
(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 company's financial assets subject to credit risk 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.
The majority of the company's upstream revenues are composed of bitumen
sales. Substantially all of the company's sales were made to three
customers in 2008.
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 selling price of the company's dilbit sales
largely equates to the purchase price 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 was put in place effective for the period April 1 to
October 31, 2008. The collar had 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 on a portion of natural gas sales volumes notionally in excess of
those required for consumption at Pod One. The risk in implementing the
collar was that future natural gas prices could escalate beyond the
ceiling price, limiting the company's natural gas revenue. In 2008,
reported Upstream Revenues decreased by $831,000 as a result of carrying
this contract (approximately $0.18 per mcf).
In November 2008 Connacher entered into a foreign exchange collar which
sets a floor of CAD $1.1925 per US $1.00 and a ceiling of CAD $1.3000 per
US $1.00 on a notional amount of US $10,000,000 of production revenue per
month throughout 2009. At December 31, 2008 the fair value of this
contract was an asset of $1.8 million which is recorded in accounts
receivable on the consolidated balance sheet. The corresponding gain is
included in the net foreign exchange loss in the consolidated statement
of operations. A $0.01 change on the USD/CAD exchange rate would result
in a $700,000 change in the fair value of the collar.
(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 company's Second Lien Senior Notes and
Convertible Debentures have fixed interest rate obligations and,
therefore, are not subject to changes in variable interest rates.
(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,
its exposure to fluctuations in the US/Canadian dollar exchange rate
primarily relates to pricing of its sales of crude oil and bitumen (which
are generally priced by reference to US dollars but settled in Canadian
dollars) and on the translation of its US refining operating results and
its US dollar denominated Second Lien Senior Notes to Canadian dollars
for financial statement reporting purposes.
In order to mitigate half of the foreign exchange exposure on the Second
Lien Senior Notes, the company entered into cross currency and interest
rate swaps to fix one half of the Second Lien Senior Notes' principal and
interest payments in Canadian dollars. In the fourth quarter of 2008 the
company monetized the cross-currency and interest rate swaps by unwinding
them and realized net cash proceeds of $89.1 million, of which
$97.6 million was recorded as a realized foreign exchange gain,
$2.6 million was recorded as a finance charge and $5.9 million was
capitalized to property and equipment.
Relative to the company's U.S. dollar cash balances, crude oil and
bitumen revenue receivables and Second Lien Senior Notes, a $0.01 change
in the Canadian dollar exchange rate would have resulted in a
$5.7 million change in net earnings for 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, monitors expenditures
against pre-approved budgets to control costs, regularly monitors its
operating cash flow, working capital and bank balances against its
business plan, usually 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 Second Lien 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 several years without having
to make principal payments or raise new capital unless expenditures
exceed cash flow and credit capacity.
The company was in compliance with all of its financial covenants at
December 31, 2008.
The change in carrying value of long-term debt at December 31, 2008
($779 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 Second Lien Senior Notes to Canadian dollars and accretion of
the debt discount of approximately $5.5 million.
At December 31, 2008 the fair values of the Convertible Debentures and
Second Lien Senior Notes were approximately $45 million and $287 million,
respectively, based on their quoted market prices.
The company's term debt is repayable as follows:
- Convertible Debentures - June 30, 2012 in the amount of $100 million
unless converted into common shares prior thereto; and
- Second Lien Senior Notes - December 15, 2015 in the amount of
US $592 million.
Connacher's investment in Petrolifera also provides liquidity. Trading on
the TSX, Connacher's 13.1 million shares held in Petrolifera may be sold
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 financial safety.
(f) Capital risks
Connacher's objectives in managing its cash, debt and equity, 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 and 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
December 31, December 31,
($000) 2008 2007
-------------------------------------------------------------------------
Long term debt(1) $778,732 $664,462
-------------------------------------------------------------------------
Shareholders' equity
-------------------------------------------------------------------------
Share capital, contributed surplus and
equity component 437,899 444,086
-------------------------------------------------------------------------
Accumulated other comprehensive income (loss) 7,802 (13,636)
-------------------------------------------------------------------------
Retained earnings 23,386 49,989
-------------------------------------------------------------------------
Total $1,247,819 $1,144,901
-------------------------------------------------------------------------
Debt to book capitalization(2) 62% 58%
-------------------------------------------------------------------------
Debt to market capitalization(3) 81% 44%
-------------------------------------------------------------------------
(1) Long-term debt is stated at its carrying value, which is net of
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 of the full cost of Algar, the company's second oil sands
project, in 2007, by issuing US$600 million of Second Lien Senior Notes,
a portion of which was used to repay indebtedness previously incurred for
Pod One. As at December 31, 2008, the company's net debt (long-term debt,
net of cash on hand) was $555 million, its net debt to book
capitalization was 44 percent and its net debt to market capitalization
was 57 percent.
5. Inventories
Inventories at December 31 consist of the following:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Crude oil $3,433 $2,258
-------------------------------------------------------------------------
Other raw materials and unfinished products(1) 1,762 1,501
-------------------------------------------------------------------------
Refined products(2) 18,901 11,183
-------------------------------------------------------------------------
Process chemicals(3) 8,110 1,036
-------------------------------------------------------------------------
Repairs and maintenance supplies and other(4) 3,787 2,401
-------------------------------------------------------------------------
$35,993 $18,379
-------------------------------------------------------------------------
(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 including 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 for refining and oil sands
operations.
The amount of inventory recognized in downstream-crude oil purchases
during 2008 was $349.8 million (2007 - $237.1 million).
As a consequence of decreased crude oil and asphalt prices during the
fourth quarter of 2008, the company wrote down its purchased crude oil,
asphalt and other refined products in inventories in the amount of $9
million at December 31, 2008 (2007 - $562,000), which is included in
downstream-crude oil purchases and operating costs.
6. Investment In Petrolifera Petroleum Limited ("Petrolifera")
Changes to the investment in Petrolifera are as follows:
-------------------------------------------------------------------------
($000)
-------------------------------------------------------------------------
Investment in Petrolifera, December 31, 2006 $21,597
-------------------------------------------------------------------------
Equity in Petrolifera's 2007 earnings 6,953
-------------------------------------------------------------------------
Exercise of warrants - purchase of additional common shares 5,143
-------------------------------------------------------------------------
Dilution gain resulting from issuance of Petrolifera
shares in 2007 1,917
-------------------------------------------------------------------------
Investment in Petrolifera, December 31, 2007 35,610
-------------------------------------------------------------------------
Equity in Petrolifera's 2008 earnings 3,085
-------------------------------------------------------------------------
Dilution gain resulting from issuance of Petrolifera
shares in 2008 7,964
-------------------------------------------------------------------------
Investment in Petrolifera, December 31, 2008 $46,659
-------------------------------------------------------------------------
Dilution gains have been recognized whenever changes have occurred in the
company's equity interest in Petrolifera, most notably relative to
Petrolifera's $7 million private placement financing completed in March
2005 when Connacher's equity interest holding was reduced from 61 percent
to 40 percent, resulting in a dilution gain of $3 million. Although
Connacher participated in Petrolifera's $21.3 million initial public
offering in November 2005 by investing $6 million, Connacher's equity
investment interest was reduced to 35 percent and a further dilution gain
of $1.5 million was then recognized.
In April 2007, the company exercised warrants to purchase 1.7 million
additional common shares in Petrolifera for total consideration of
$5.1 million. As a result, the company increased its equity interest.
Because other Petrolifera shareholders similarly exercised their warrants
to purchase additional common shares in Petrolifera on identical terms,
the company's interest decreased to 26 percent, resulting in a dilution
gain of $1.9 million.
In June 2008, Petrolifera issued an additional 4.4 million common shares
to raise $40 million. Connacher did not subscribe for any of these
shares. Consequently, Connacher's equity interest in Petrolifera was
reduced from 26 percent to 24 percent resulting in a dilution gain of
$8 million, which was recognized by Connacher in the second quarter of
2008.
In consideration for the assistance provided to Petrolifera in securing
two Peruvian licenses for exploratory lands and for the provision of
financial guarantees respecting Petrolifera's annual work commitments in
the two licensed blocks in 2005, Connacher was granted a five-year option
to acquire 200,000 common shares at $0.50 per share and was granted a
10 percent carried working interest ("CWI") through the drilling of the
first well on each block. Petrolifera has the right of first purchase of
this CWI should Connacher elect to sell it at some future date. The CWI
is convertible at the holder's election into a two percent gross
overriding royalty on each license after the drilling of the first well
on each block.
Under the terms of an Administrative Services Agreement dated January 1,
2008 with Petrolifera, Connacher provides certain management and general
and administrative services to Petrolifera. The fee for this service is
$15,000 per month. Connacher is also guarantor for Petrolifera in Peru
and operator of record on behalf of Petrolifera in Colombia for which
Connacher is indemnified by Petrolifera. Petrolifera paid Connacher
$180,000 in 2008 (2007 - $200,000) under the Administrative Services
Agreement.
7. Property And Equipment
-------------------------------------------------------------------------
Accumulated
Depletion,
Depreciation
and Amort- Net Book
($000) Cost ization Value
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
Oil sands, crude oil and natural
gas properties and equipment $1,004,891 $112,013 $892,878
-------------------------------------------------------------------------
Refining assets 99,823 13,620 86,203
-------------------------------------------------------------------------
Furniture, equipment and leaseholds 9,999 4,026 5,973
-------------------------------------------------------------------------
$1,114,713 $129,659 $985,054
-------------------------------------------------------------------------
2007
-------------------------------------------------------------------------
Oil sands, crude oil and natural
gas properties and equipment $678,176 $67,499 $610,677
-------------------------------------------------------------------------
Refining assets 59,192 5,182 54,010
-------------------------------------------------------------------------
Furniture, equipment and leaseholds 9,219 2,484 6,735
-------------------------------------------------------------------------
$746,587 $75,165 $671,422
-------------------------------------------------------------------------
In 2008, the company capitalized $5.2 million (2007 - $3.4 million) of
general and administrative expenses, stock-based compensation costs of
$1.5 million (2007 - $2.2 million), and $47.1 million (2007 -
$24.6 million) of interest and financing costs related to oil sands and
conventional petroleum and natural gas activities.
Depletion, depreciation and accretion expense includes a charge of
$1.7 million (2007 - $1.6 million) to accrete the company's estimated
asset retirement obligations (Note 11).
The ceiling test as at December 31, 2008 excludes $14.2 million (2007 -
$14.7 million) of undeveloped land and $297 million (2007 - $413 million)
of major development project costs, principally related to oil sands
assets in the pre-production stage, which have been separately evaluated
by management for impairment. Based on the ceiling test and other
assessments, no impairment has been recorded at December 31, 2008.
Connacher's oil sands, crude and natural gas reserves were evaluated by
qualified independent evaluators as at December 31, 2008 in a report
dated February 4, 2009. The evaluation was conducted in accordance with
the Canadian Securities Administrators' National Instrument 51-101, using
the following base price assumptions adjusted for the company's product
quality and transportation differentials:
-------------------------------------------------------------------------
Bitumen
Wellhead WTI at Alberta
Current Cushing Spot
($CDN/bbl) ($US/bbl) ($CDN/mmbtu)
-------------------------------------------------------------------------
2009 $23.10 $57.50 $7.34
-------------------------------------------------------------------------
2010 31.33 68.00 7.70
-------------------------------------------------------------------------
2011 42.25 74.00 8.10
-------------------------------------------------------------------------
2012 50.06 85.00 8.46
-------------------------------------------------------------------------
2013 54.66 92.01 8.70
-------------------------------------------------------------------------
Approximately Approximately Approximately
2% thereafter 2% thereafter 2% thereafter
-------------------------------------------------------------------------
8. Deferred Costs
Deferred costs are composed of the following:
-------------------------------------------------------------------------
December 31, December 31,
($000's) 2008 2007
-------------------------------------------------------------------------
Deferred capital costs related to refinery $ - $1,835
-------------------------------------------------------------------------
Deferred financing costs related to
Revolving Credit Facilities - 3,752
-------------------------------------------------------------------------
$ - $5,587
-------------------------------------------------------------------------
The unamortized costs of the Revolving Credit Facility were expensed in
2008. (See Note 10.)
9. Income Taxes
The income tax recovery of $5.3 million in 2008 includes a current income
tax recovery of $12.9 million, principally related to US refinery
operations and a future income tax provision of $7.6 million reflecting
the movement in tax pools during the year.
The following table reconciles income taxes calculated at the Canadian
statutory rate with recorded income taxes:
-------------------------------------------------------------------------
Years Ended December 31 ($000) 2008 2007
-------------------------------------------------------------------------
Earnings (loss) before income taxes $(31,914) $53,966
-------------------------------------------------------------------------
Canadian statutory rate 29.8% 32.7%
-------------------------------------------------------------------------
Expected income taxes (recovery) (9,510) 17,647
-------------------------------------------------------------------------
Impact of reduction in Canadian tax
rates and other 1,846 (5,385)
-------------------------------------------------------------------------
Foreign taxes (recovery) (2,130) 2,488
-------------------------------------------------------------------------
Capital taxes 1,535 1,896
-------------------------------------------------------------------------
Non taxable portion of foreign exchange
losses (gains) 3,233 (4,100)
-------------------------------------------------------------------------
Equity income and dilution gain (1,644) (1,523)
-------------------------------------------------------------------------
Non deductible stock-based compensation costs 1,359 1,982
-------------------------------------------------------------------------
Provision (recovery) for income taxes $(5,311) $13,005
-------------------------------------------------------------------------
-------------------------------------------------------------------------
The company had the following future tax assets (liabilities) relating to
temporary differences.
-------------------------------------------------------------------------
As at December 31 ($000) 2008 2007
-------------------------------------------------------------------------
Book value in excess of tax basis of
property, plant and equipment $(101,008) $(56,725)
-------------------------------------------------------------------------
Non-capital losses carried forward 23,055 18,647
-------------------------------------------------------------------------
Foreign exchange loss (gain) on debt 11,224 (532)
-------------------------------------------------------------------------
Partnership deferral - (6,360)
-------------------------------------------------------------------------
Investment in Petrolifera (4,153) (2,850)
-------------------------------------------------------------------------
Deferred capital costs (231) (723)
-------------------------------------------------------------------------
Financing and share issue costs 7,125 3,998
-------------------------------------------------------------------------
Asset retirement obligation 6,620 6,164
-------------------------------------------------------------------------
Other (928) 1,563
-------------------------------------------------------------------------
Net future income tax liability $(58,296) $(36,818)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
At December 31, 2008 the company had approximately $89 million of non-
capital losses which expire over time to 2028, $551 million of deductible
resource pools and $26 million of deductible financing costs. The future
income tax benefit of these have been recognized at December 31, 2008.
Additionally, the company had $167 million of capital losses available to
reduce capital gains in future. These capital losses have no expiry and
their future income tax benefit has not been recognized due to
uncertainty of their realization at December 31, 2008.
10. Indebtedness
The company had the following long-term debt outstanding, as at
December 31
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Second Lien Senior Notes $694,086 $570,594
-------------------------------------------------------------------------
Cross-currency and interest rate swaps
liability - 12,735
-------------------------------------------------------------------------
Convertible Debentures 84,646 81,133
-------------------------------------------------------------------------
Total 778,732 664,462
-------------------------------------------------------------------------
Less current portion of long-term debt - -
-------------------------------------------------------------------------
Long-term portion $778,732 $664,462
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Senior Notes
On December 3, 2007 the company issued US $600 million of Senior Notes
("Senior Second Lien Secured Notes") at an issue price of 98.657 for net
proceeds of US $575.4 million after fees and expenses. A portion of the
proceeds was used to repay the US $180 million Oil Sands Term Loan then
outstanding and to fund a one-year interest reserve account in the amount
of US $63.6 million. The remainder of the proceeds are to be used to fund
the construction of Algar, the company's second oil sands project. The
Second Lien Senior Notes bear interest at a rate of 10.25% payable semi-
annually on June 15 and December 15. No principal payments are due until
the maturity date of December 15, 2015. The Second Lien Senior Notes are
secured by a second lien covering substantially all of the
company's assets with the exception of its investment in Petrolifera.
The company may redeem some or all of the Second Lien Senior Notes at
their principal amount plus a make whole premium if such redemption
occurs prior to December 15, 2011. After December 15, 2011, the Second
Lien Senior Notes may be redeemed at redemption prices ranging from
105.125 percent reducing to 100 percent on December 15, 2013 and
thereafter.
The company may redeem up to 35% of the of the Second Lien Senior Notes
prior to December 15, 2010 at a redemption price of 110.25 percent of the
principal amount plus accrued interest with the proceeds of certain
equity offerings provided that at least 65% of the aggregate principal
amount of the Second Lien Senior Notes remains outstanding on existing
terms. Upon a change of control of the company, the holders of the Second
Lien Senior Notes may require Connacher to purchase the Second Lien
Senior Notes at redemption prices noted above, with a minimum price of
101 percent of the principal amount to be repurchased.
In the fourth quarter of 2008, the company repurchased US $8 million face
value of Second Lien Senior Notes in the market at a discount, cancelled
the notes, and realized a gain of $2.8 million.
A portion of the interest on the Second Lien Senior Notes attributed to
the company's first oil sands project ("Pod One"), has been expensed
since the commencement of its commercial operations (March 1, 2008).
Interest on the portion of the loan which is used to fund the
construction of Algar is being capitalized.
At December 31, 2008, the fair value of the Second Lien Senior Notes was
approximately $287 million. This amount was determined by reference to
the quoted market price for the company's Second Lien Senior Notes.
Cross-Currency and Interest Rate Swaps
To partially mitigate the foreign exchange risk associated with its
Second Lien Senior Notes in 2007, the company entered into cross currency
and interest rate swaps to fix a portion of the Second Lien Senior Notes'
US dollar denominated principal and interest payments in Canadian
dollars. At December 31, 2007, the fair value of these swaps was a
liability of $12.7 million, which was included with long-term debt in the
consolidated balance sheet. An unrealized foreign exchange loss of
$9.6 million related to the cross currency swap was recorded in income in
2007 and $3.1 million related to the interest rate swap was capitalized
to property and equipment. The unrealized 2007 foreign exchange loss was
offset by a $9.7 million unrealized gain on translating the Second Lien
Senior Notes and the interest rate swap at December 31, 2007.
In the fourth quarter of 2008 the company monetized the cross-currency
and interest rate swaps by unwinding them and realized cash proceeds of
$89.1 million, of which $97.6 million was recorded as a realized foreign
exchange gain, $2.6 million was recorded as a finance charge and
$5.9 million was capitalized to property and equipment.
Convertible Debentures
On May 25, 2007 Connacher issued senior unsecured subordinated
Convertible Debentures with a face value of $100,050,000. The Convertible
Debentures mature June 30, 2012 unless converted prior to that date and
bear interest at an annual rate of 4.75 percent payable semiannually on
June 30 and December 31. The Convertible Debentures are convertible at
any time into common shares at the option of the holder at a conversion
price of $5.00 per share.
The Convertible Debentures are redeemable or after June 30, 2010 by the
company, in whole or in part at a redemption price equal to 100 percent
of the principal amount of the Convertible Debentures to be redeemed plus
accrued and unpaid interest provided that the market price of the
company's common shares is at least 120 percent of the conversion price
of the Convertible Debentures.
The conversion feature of the Convertible Debentures has been accounted
for as a separate component of equity in the amount of $16,823,000. The
remainder of the net proceeds of the Convertible Debentures of
$79,187,000 was recorded as long-term debt, which will be accreted up to
the face value of $100,050,000 over the five-year term of the Convertible
Debentures. Accretion and interest paid are recorded as finance charges
on the consolidated statement of operations. If the Convertible
Debentures are converted to common shares, the value of the conversion
feature will be reclassified to share capital along with the principal
amounts converted.
At December 31, 2008, the fair value of the Convertible Debentures was
$45 million (December 31, 2007 - $96.5 million). This amount was
determined by reference to the quoted market price for the Convertible
Debenture.
Revolving Credit Facilities
At December 31, 2008 the company had available revolving lines of credit
in the amounts of CAD $150 million and US $50 million. No amounts were
drawn under the revolving credit facilities at December 31, 2008 other
than as security for letters of credit in the amount of $6 million.
Subsequent to December 31, 2008, the company terminated the Revolving
Credit Facilities. The unamortized costs of establishing this facility
($3.75 million) were expensed in 2008.
Principal repayments due
Principal repayments for all the aforementioned loans are due as follows:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
2009 $- $-
-------------------------------------------------------------------------
2010 - -
-------------------------------------------------------------------------
2011 - -
-------------------------------------------------------------------------
2012 100,050 100,050
-------------------------------------------------------------------------
2013 - -
-------------------------------------------------------------------------
Thereafter 721,056 612,735
-------------------------------------------------------------------------
$821,106 $712,785
-------------------------------------------------------------------------
-------------------------------------------------------------------------
11. 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 upstream crude oil, natural gas and oil sands
properties and facilities.
-------------------------------------------------------------------------
Year ended December 31 ($000) 2008 2007
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset retirement obligations, beginning of year $24,365 $7,322
-------------------------------------------------------------------------
Liabilities incurred 1,496 8,277
-------------------------------------------------------------------------
Liabilities settled (209) (311)
-------------------------------------------------------------------------
Change in estimated future cash flows (960) 7,503
-------------------------------------------------------------------------
Accretion expense 1,704 1,574
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Asset retirement obligations, end of year $26,396 $24,365
-------------------------------------------------------------------------
At December 31, 2008 the estimated total undiscounted amount required to
settle the asset retirement obligations was $47.3 million (2007 -
$44.4 million). These obligations are expected to be settled over the
useful lives of the underlying assets, which currently extend up to
20 years into the future. This amount has been discounted using a credit-
adjusted risk-free rate of interest and after provision for inflation.
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.
12. Employee Future Benefits
The company maintains the following retirement/savings plans for its
employees: a defined benefit pension plan and a defined contribution
savings plan for its US-based employees and a defined contribution
savings plan for its Canadian employees.
(a) The defined benefit pension plan
The company's US subsidiary, MRCI, maintains a non-contributory defined
benefit retirement plan (the "Defined Benefit Plan") covering MRCI's
employees. MRCI's policy is to make regular contributions in accordance
with the funding requirements of the United States Employee Retirement
Income Security Act of 1974 as determined by regular actuarial
valuations. The company's pension obligation is based on the employees'
years of service and compensation, effective from, and after, March 31,
2006, the date that Connacher acquired the refining assets and hired the
refinery personnel. In 2007, MRCI fully funded the Defined Benefit Plan's
cost for 2006 and 2007.
MRCI is responsible for administering the Defined Benefit Plan and has
retained the services of an independent and professional investment
manager, as fund manager, for the related investment portfolio. Among the
factors considered in developing the investment policy are the Defined
Benefit Plan's primary investment goal, rate of return objective,
investment risk, investment time horizon, role of asset classes and asset
allocation.
Details of this Defined Benefit Plan for the years ended December 31,
2007 and 2008 are based on actuarial valuations prepared as at those
dates.
-------------------------------------------------------------------------
For the years ended December 31 ($000) 2008 2007
-------------------------------------------------------------------------
Total expense for the Plan $730 $447
-------------------------------------------------------------------------
Defined Benefit Plan Obligation
-------------------------------------------------------------------------
Accrued Defined Benefit Plan Obligation,
Beginning of the Year $617 $388
-------------------------------------------------------------------------
Current service cost 723 470
-------------------------------------------------------------------------
Interest cost 62 21
-------------------------------------------------------------------------
Actuarial (gain) loss (52) (140)
-------------------------------------------------------------------------
Benefits paid (63) (24)
-------------------------------------------------------------------------
Foreign exchange (gain) loss 183 (98)
-------------------------------------------------------------------------
Accrued Defined Benefit Plan Obligation,
End of Year $1,470 $617
-------------------------------------------------------------------------
Defined Benefit Plan Assets
-------------------------------------------------------------------------
Fair Value of Defined Benefit Plan Assets,
Beginning of Year $757 $ -
-------------------------------------------------------------------------
Actual return on plan assets (192) 43
-------------------------------------------------------------------------
Employer contributions - 781
-------------------------------------------------------------------------
Benefits paid (63) (24)
-------------------------------------------------------------------------
Foreign exchange gain (loss) 138 (43)
-------------------------------------------------------------------------
Fair Value of Defined Benefit Plan Assets,
End of Year $640 $757
-------------------------------------------------------------------------
Accrued Benefit Asset (Liability)
-------------------------------------------------------------------------
Funded Status - Defined Benefit Plan Assets
greater (less) than Defined Benefit
Plan Obligation $(830) $140
-------------------------------------------------------------------------
Unamortized net actuarial (gain) loss 38 (140)
-------------------------------------------------------------------------
Accrued Defined Benefit Plan Asset (Liability) $(792) $ -
-------------------------------------------------------------------------
The weighted average assumptions used to determine benefit obligations
and periodic expense are as follows:
-------------------------------------------------------------------------
Discount Rate 5.75% 5.75%
-------------------------------------------------------------------------
Expected Long-Term Rate of Return on Plan Assets: 7.0% 7.0%
-------------------------------------------------------------------------
Rate of compensation increase 3.0% 3.0%
-------------------------------------------------------------------------
The periodic expense for benefits is as follows:
-------------------------------------------------------------------------
Current Service Cost $723 $470
-------------------------------------------------------------------------
Interest Cost 62 21
-------------------------------------------------------------------------
Actual Return on Defined Benefit Plan Assets 192 (43)
-------------------------------------------------------------------------
Difference between actual and expected return
on plan assets (247) (1)
-------------------------------------------------------------------------
Net Defined Benefit Plan Expense $730 $447
-------------------------------------------------------------------------
The average remaining service period of the active employees covered by
the Defined Benefit Plan is 14.54 years.
The Company's pension plan asset allocation is as follows:
-------------------------------------------------------------------------
Asset Category % of Plan Assets
at December 31
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
Equity securities 59% 57%
-------------------------------------------------------------------------
Debt securities 37% 39%
-------------------------------------------------------------------------
Cash and cash equivalents 4% 4%
-------------------------------------------------------------------------
Total 100% 100%
-------------------------------------------------------------------------
The expected rate of return on plan assets is based on historical and
projected rates of return for each asset class in the plan investment
portfolio. The objective of asset allocation policy is to manage the
funded status of the plan at an appropriate level of risk, giving
consideration to the security of the assets and the potential volatility
of market returns and the resulting effect on both contribution
requirements and pension expense. The long-term return is expected to
achieve or exceed the return from a composite benchmark comprised of
passive investments in appropriate market indices.
The asset allocation structure is subject to diversification requirements
and constraints which reduce risk by limiting exposure to individual
equity investment, credit rating categories and foreign currency
exposure.
(b) The MRCI defined contribution savings plan for United States
employees
MRCI also maintains defined contribution (US tax code "401(k)"), savings
plans that cover all of its employees. MRCI's contributions are based on
employees' compensation and partially match employee contributions. In
2008, MRCI contributed $343,000 (2007 - $345,000) to this plan, to
satisfy, in full, its obligation under this plan.
(c) The defined contribution savings plan for Canadian employees
The company also maintains defined contribution savings plans for its
Canadian employees, whereby the company matches employee contributions to
a maximum of eight percent of each employee's salary. In 2008, the
company contributed $739,000 (2007 - $474,000) to this plan, to satisfy,
in full, its obligation under this plan.
13. Share Capital, Contributed Surplus And Equity Component
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 of Amount
shares ($000)
-------------------------------------------------------------------------
Balance, Share Capital, December 31, 2006 197,894,015 $363,082
-------------------------------------------------------------------------
Issued for cash in public offering (a) 10,450,000 52,250
-------------------------------------------------------------------------
Issued upon exercise of options (b) 1,518,267 1,466
-------------------------------------------------------------------------
Shares issued to directors as
compensation (c) 108,975 392
-------------------------------------------------------------------------
Assigned value of options exercised 518
-------------------------------------------------------------------------
Tax effect of expenditures renounced
pursuant to the issuance of
flow-through common shares (9,000)
-------------------------------------------------------------------------
Share issue costs, net of income taxes (1,827)
-------------------------------------------------------------------------
Balance, Share Capital, December 31, 2007 209,971,257 $406,881
-------------------------------------------------------------------------
Issued upon exercise of options (b) 1,101,583 893
-------------------------------------------------------------------------
Shares issued to directors as
compensation (c) 108,975 381
-------------------------------------------------------------------------
Assigned value of options exercised 250
-------------------------------------------------------------------------
Tax effect of expenditures renounced
pursuant to the issuance of
flow-through common shares in 2007 (a) (13,250)
-------------------------------------------------------------------------
Share issue costs, net of income taxes (132)
-------------------------------------------------------------------------
Balance, Share Capital, December 31, 2008 211,181,815 $395,023
-------------------------------------------------------------------------
Contributed Surplus:
-------------------------------------------------------------------------
Balance, Contributed Surplus,
December 31, 2006 $13,418
-------------------------------------------------------------------------
Stock - based compensation for share
options expensed in 2007 (b) 7,482
-------------------------------------------------------------------------
Assigned value of options
exercised in 2007 (518)
-------------------------------------------------------------------------
Balance, Contributed Surplus,
December 31, 2007 $20,382
-------------------------------------------------------------------------
Stock - based compensation for share
options expensed in 2008 (b) 5,921
-------------------------------------------------------------------------
Assigned value of options
exercised in 2008 (250)
-------------------------------------------------------------------------
Balance, Contributed Surplus,
December 31, 2008 $26,053
-------------------------------------------------------------------------
Equity component of Convertible Debentures,
December 31, 2007 and 2008 $16,823
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Total Share Capital, Contributed Surplus
and Equity Component:
-------------------------------------------------------------------------
December 31, 2007 $444,086
-------------------------------------------------------------------------
December 31, 2008 $437,899
-------------------------------------------------------------------------
(a) Flow-through share issue - 2007
In November 2007, the company issued from treasury 10,450,000 common
shares on a flow-through basis at $5.00 per share for gross proceeds of
$52.25 million and renounced the related resource expenditures to the
flow-through investors effective December 31, 2007. The related tax
effect of $13.25 million was recorded in 2008.
(b) Stock Options
A summary of the company's outstanding stock options, as at December 31,
2008 and 2007 and changes during those years is presented below:
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding, beginning
of year 17,432,717 $3.60 16,212,490 $3.31
-------------------------------------------------------------------------
Granted 6,226,846 $2.29 4,311,703 $3.88
-------------------------------------------------------------------------
Exercised (1,101,583) $0.81 (1,518,267) $0.97
-------------------------------------------------------------------------
Expired/exchanged (6,174,876) $3.93 (1,573,209) $4.00
-------------------------------------------------------------------------
Outstanding, end
of year 16,383,104 $3.16 17,432,717 $3.60
-------------------------------------------------------------------------
Exercisable, end
of year 12,423,317 $3.14 10,204,053 $3.18
-------------------------------------------------------------------------
All stock options have been granted for a period of five years. Options
granted under the plan are generally fully exercisable after three years.
The company offered its employees (excluding directors and officers) the
opportunity to exchange significantly "out of the money" options for a
reduced number of new options based on the fair value of the options. In
the fourth quarter of 2008 Stock-based compensation of $675,000 was
recognized (ie. expensed or capitalized) in relation to the options
exchanged.
The table below summarizes unexercised stock options.
-------------------------------------------------------------------------
Weighted
Weighted Average
Average Remaining
Number Exercise Contractual
Range of Exercise Prices Outstanding Price Life
-------------------------------------------------------------------------
At December 31 2008
-------------------------------------------------------------------------
$0.20 - $0.99 997,034 $0.77 1.1
-------------------------------------------------------------------------
$1.00 - $1.99 4,563,623 $1.34 3.7
-------------------------------------------------------------------------
$2.00 - $3.99 5,377,938 $3.31 2.9
-------------------------------------------------------------------------
$4.00 - $5.99 5,444,509 $4.98 2.3
-------------------------------------------------------------------------
16,383,104 $3.16
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Weighted
Weighted Average
Average Remaining
Number Exercise Contractual
Range of Exercise Prices Outstanding Price Life
-------------------------------------------------------------------------
At December 31 2007
-------------------------------------------------------------------------
$0.20 - $0.99 1,997,968 $0.72 1.8
-------------------------------------------------------------------------
$1.00 - $1.99 1,632,000 $1.58 2.4
-------------------------------------------------------------------------
$2.00 - $3.99 6,479,216 $3.51 3.7
-------------------------------------------------------------------------
$4.00 - $5.99 7,323,533 $4.91 3.4
-------------------------------------------------------------------------
17,432,717 $3.60
-------------------------------------------------------------------------
In 2008 a compensatory non-cash expense of $5.9 million (2007 -
$8.3 million) was recorded, reflecting the fair value of stock options
amortized over their term. Of this amount, $4.4 million (2007 -
$5.7 million) was expensed and nil (2007 - $0.4 million) was charged to
refining operating costs. A further $1.5 million (2007 - $2.2 million)
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:
-------------------------------------------------------------------------
2008 2007
-------------------------------------------------------------------------
Risk free interest rate 2.5% 4.1%
-------------------------------------------------------------------------
Expected option life (years) 3 3
-------------------------------------------------------------------------
Expected volatility 54% 52%
-------------------------------------------------------------------------
The weighted average fair value at the date of grant of all options
granted in 2008 was $0.81 per option (2007 - $1.50).
(c) Share award plan for non-employee directors
Shareholders of the company approved a share award incentive plan for
non-employee directors at the company's Annual and Special Meeting of
Shareholders on May 10, 2007. Under the plan, a total of 326,925 share
units (represented by common shares) were awarded to non-employee
directors. In June 2007, 108,975 common shares were issued to directors
as compensation under the plan; on January 1, 2008 a further 108,975
share units were vested and the equivalent number of common shares were
issued on January 16, 2008; the remaining 108,975 share units vested on
January 1, 2009 and were issued on January 5, 2009.
Under the share award plan, share units may be granted to non-employee
directors of the company in amounts determined by the Board of Directors
on the recommendation of the Governance Committee. Payment under the plan
is made by delivering common shares to non-employee directors either
through purchases on the TSX or by issuing shares from treasury, subject
to certain limitations. The Board of Directors may also elect to pay cash
equal to the fair market value of the common shares to be delivered to
non-employee directors upon vesting of such share units in lieu of
delivering shares.
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 December 31, 2008 and have vested or 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
-------------------------------------------------------------------------
January 1, 2011 136,655
-------------------------------------------------------------------------
392,705
-------------------------------------------------------------------------
In the year ended December 31, 2008, $125,000 (year ended December 31,
2007 - $810,000) was charged to expense in respect of awards granted
under the share award plan.
14. Related Party Transactions
In 2008 the company paid professional legal fees of $1.1 million (2007 -
$667,000) to a law firm in which an officer and director of the company
were partners. Transactions with the related party occurred within the
normal course of business and have been measured at their exchange amount
on normal business terms. The exchange amount is the amount of
consideration established and agreed to with the related parties.
A portion of the company's conventional crude oil and natural gas
exploration and drilling activities, which activities are anticipated to
continue in the future, was conducted in an industry-standard joint
venture arrangement with a company, an officer of which is also a
director of Connacher. Transactions with the joint venture partner
occurred within the normal course of business and have been measured at
their exchange amount on normal business terms. The exchange amount is
the amount of consideration established and agreed to by the company and
the joint venture partner.
15. Segmented Information
The company has changed its segmentation in 2008 to better reflect the
organization of its business by combining 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.
-------------------------------------------------------------------------
Year ended December 31 Canada USA
-------------------------------------------------------------------------
($000) Oil and Gas Refining Total
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
Revenues, net of royalties $249,657 $374,248 $623,905
-------------------------------------------------------------------------
Equity interest in
Petrolifera earnings 3,085 - 3,085
-------------------------------------------------------------------------
Dilution gain 7,964 - 7,964
-------------------------------------------------------------------------
Interest and other income 5,057 377 5,434
-------------------------------------------------------------------------
Finance charges 34,235 418 34,653
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 48,304 8,144 56,448
-------------------------------------------------------------------------
Taxes provision (recovery) 1,330 (6,641) (5,311)
-------------------------------------------------------------------------
Net earnings (loss) (11,128) (15,475) (26,603)
-------------------------------------------------------------------------
Property and equipment, net 898,851 86,203 985,054
-------------------------------------------------------------------------
Goodwill 103,676 - 103,676
-------------------------------------------------------------------------
Capital expenditures 327,452 24,284 351,736
-------------------------------------------------------------------------
Total assets 1,287,851 143,824 1,431,675
-------------------------------------------------------------------------
2007
-------------------------------------------------------------------------
Revenues, net of royalties $30,722 $313,050 $343,772
-------------------------------------------------------------------------
Equity interest in
Petrolifera earnings 6,953 - 6,953
-------------------------------------------------------------------------
Dilution gain 1,917 - 1,917
-------------------------------------------------------------------------
Interest and other income 232 516 748
-------------------------------------------------------------------------
Finance charges 6,858 - 6,858
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 25,887 5,174 31,061
-------------------------------------------------------------------------
Taxes provision (recovery) (1,927) 14,932 13,005
-------------------------------------------------------------------------
Net earnings 12,349 28,612 40,961
-------------------------------------------------------------------------
Property and equipment, net 617,412 54,010 671,422
-------------------------------------------------------------------------
Goodwill 103,676 - 103,676
-------------------------------------------------------------------------
Capital expenditures
and acquisitions 307,047 15,915 322,962
-------------------------------------------------------------------------
Total assets 1,150,655 108,173 1,258,828
-------------------------------------------------------------------------
16. Supplementary Information
(a) Per share amounts
The following table summarizes the common shares used in per share
calculations.
-------------------------------------------------------------------------
For the years ended December 31 (000) 2008 2007
-------------------------------------------------------------------------
Weighed average common shares outstanding 210,794 200,092
-------------------------------------------------------------------------
Dilutive effect of stock options, Convertible
Debentures and share units under the
non-employee Directors share award plan 3,853 2,674
-------------------------------------------------------------------------
Weighed average common shares
outstanding - diluted 214,647 202,766
-------------------------------------------------------------------------
(b) Net change in non-cash working capital
-------------------------------------------------------------------------
For the years ended December 31 ($000) 2008 2007
-------------------------------------------------------------------------
Accounts receivable $4,274 $5,872
-------------------------------------------------------------------------
Inventories (17,614) 6,058
-------------------------------------------------------------------------
Due from Petrolifera (42) 32
-------------------------------------------------------------------------
Prepaid expenses 299 (995)
-------------------------------------------------------------------------
Accounts payable and accrued liabilities 45,885 (5,249)
-------------------------------------------------------------------------
Income taxes payable/recoverable (9,596) (7,923)
-------------------------------------------------------------------------
Total $23,206 $(2,205)
-------------------------------------------------------------------------
Summary of working capital changes:
-------------------------------------------------------------------------
($000) 2008 2007
-------------------------------------------------------------------------
Operations $(27,583) $6,464
-------------------------------------------------------------------------
Investing 50,789 (8,669)
-------------------------------------------------------------------------
$23,206 $(2,205)
-------------------------------------------------------------------------
(c) Supplementary cash flow information
-------------------------------------------------------------------------
For the years ended December 31 ($000) 2008 2007
-------------------------------------------------------------------------
Interest paid $78,506 $24,403
-------------------------------------------------------------------------
Income taxes paid 1,650 19,001
-------------------------------------------------------------------------
At December 31, 2007, cash of $63.2 million was restricted to fund the
first year of interest payments on the Second Lien Senior Notes.
17. Commitments, Contingencies And Guarantees
The company's annual commitments under leases for office premises and
operating costs, field compression equipment, software license agreements
and other equipment are as follows:
2009 - $3.7 million; 2010 - $2.7 million; 2011 - $2.7 million; 2012 -
$2.6 million; 2013 - $2.6 million; total thereafter $9.2 million.
Additionally, the company has various guarantees and indemnifications in
place in the ordinary course of business, none of which are expected to
have a significant impact on the company's financial statements or
operations.
18. Subsequent Event
Subsequent to the year end Connacher entered into WTI crude hedges for
prices of US $46.00/bbl and US $49.50/bbl on a notional volume of
5,000 barrels of oil per day for a significant portion of 2009.
Subsequent to year end Connacher cancelled its Revolving Credit
Facilities and put in place a $20 million demand operating facility for
the purpose of issuing letters of credit. The facility is secured by cash
and a first lien claim on certain assets of the company.
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