Connacher poised for great leap forward; Algar nearing completion; Bitumen
production to double in next two years; Pod One increasingly reliable;
Reserve and resource values rising; Core hole drilling at Great Divide in
2010 expected to expand volumes and values in mid year 2010 evaluation, based
on results in hand
CALGARY, March 18 /CNW/ - Connacher Oil and Gas Limited is poised for significant production growth over the next two years, with the impending completion of Algar, the company's second 10,000 bbl/d steam assisted gravity drainage ("SAGD") plant at its Great Divide oil sands project in northeastern Alberta. The project is on time and on budget and commissioning is anticipated to commence in mid-April 2010, with first bitumen production anticipated around mid-August 2010. Thereafter, production volumes will gradually be ramped up towards the plant's productive capacity. This is anticipated to result in Connacher's total bitumen production at Great Divide reaching 18,000 to 20,000 bbl/d by mid-2011.
We are experiencing increasingly reliable production from our first oil sands plant at Great Divide Pod One. Our Pod One nameplate steam generating capacity is slightly in excess of 27,000 bbl/d. With the installation of nine additional downhole pumps scheduled for April and September and with continued steam injection optimization, we are targeting an average steam/oil ratio ("SOR") of 3.2 in 2010. Accordingly, this should result in Pod One bitumen production averaging in excess of 8,500 bbl/d in 2010.
Our reserve values increased by over 40 percent during 2009. We anticipate further volume and value increases will occur with the release of our independently prepared mid-year evaluation, which will take into account the completion of Algar, core hole drilling during the first quarter of 2010 and the formal submission of our Environmental Impact Assessment ("EIA") application to further expand Great Divide bitumen production to an interim target of 44,000 bbl/d. We also anticipate additional resource recognition arising from our successful core hole drilling program at Halfway Creek. Connacher is one of the few independent public companies active in the oil sands with recognized proved producing bitumen reserves. Our goal remains to surpass 50,000 bbl/d of bitumen production by 2015.
The past year was a challenging year for all companies in our business. Crude oil prices collapsed in late 2008. This disrupted our ramp up activity at Pod One and adversely impacted on our overall operations and scheduling throughout much of the year. We suspended Algar construction for approximately six months, while we recapitalized the company to deal with the new financial realities arising from the collapse of capital and credit markets. During 2009, we raised over $400 million of new cash by accessing both equity and debt markets. As a result, we were able to enhance corporate liquidity and reinstate the Algar construction program by July 2009. Although our equity financing temporarily diluted our underlying net asset value ("NAV") per share, this proved to be temporary in nature and our enhanced year end 2009 reserve valuation restored a significant portion of our underlying NAV.
Our equity issue also enabled us to access the long term debt market on much more favorable terms than otherwise would have been available to us, if at all. The new high yield debt financing provided us with immediate incremental liquidity, without the burden of onerous financial maintenance covenants. This gave us the confidence to restore Algar construction, with the knowledge that we could meet our capital and financial obligations, without further external funding requirements and without the risk of funding being withdrawn due to any further credit market deterioration.
Later in the year, we also reestablished a revolving bank credit facility in the amount of US$50 million to secure added financial flexibility which will assist us in the conduct of our business. With Algar now anticipated to come onstream later this year, we will see a reduction in financial charges on a unit of production basis, as our production volumes expand. Having prefunded Algar, we are now scheduled to grow our production and sales into alignment with our balance sheet.
Our Q4 2009 and Year End 2009 results will be the subject of a Conference Call scheduled for 9:00 AM MT on March 19, 2010. To listen to or participate in the live Conference Call please dial either 1-647-427-7450 or 1-888-231- 8191. A replay of the event will be available from March 19, 2010 at 12:00 MT until March 26, 2010 at 9:59 MT. To listen to the replay please dial either 1- 416-849-0833 or 1-800-642-1687 and enter the passcode 59445038. You can also listen to the conference call online, through the following webcast link: http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=2981880
HIGHLIGHTS OF 2009:
- Algar construction reactivated; nearing completion, on time and on
budget
- Pod One production performance increasingly reliable with target of
8,555 bbl/d in 2010, as additional electric submersible pumps ("ESP"
or "ESPs") and progressing cavity pumps are installed and SORs
decline
- Balance sheet reconstituted to overcome the impact of the 2008-2009
collapse of commodity prices and capital and credit markets; over
$450 million of cash and credit raised or arranged to ensure
completion of Algar while meeting all financial obligations
- All outstanding debt is long-term, with no financial maintenance
covenants: no maturities until 2012 ($100 million), balance in 2014
and 2015, with no intervening principal repayments
- Company positioned to experience great leap forward in 2010 and
beyond, with long term goal to surpass 50,000 bbl/d by 2015
SUMMARY RESULTS
FINANCIAL HIGHLIGHTS
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Three months ended December 31
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($000 except per share amounts) 2009 2008 % Change
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FINANCIAL
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Revenues, net of royalties $108,354 $102,109 6
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Cash flow(1) $(2,766) $(4,688) (41)
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Per share, basic(1) $(0.01) $(0.02) 50
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Per share, diluted(1) $(0.01) $(0.02) 50
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Net earnings (loss) $(14,731) $(43,592) 66
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Per share, basic $(0.03) $(0.21) 86
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Per share, diluted $(0.03) $(0.21) 86
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Property and equipment additions $116,846 $86,174 36
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Cash on hand $256,787 $223,663 15
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Working capital $245,067 $197,914 24
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Long-term debt $876,181 $778,732 13
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Shareholders equity $671,588 $469,087 43
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Total assets $1,739,518 $1,431,675 22
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COMMON SHARE INFORMATION
-------------------------------------------------------------------------
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Shares outstanding at end
of period (000) 427,031 211,182 102
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Weighted average shares outstanding
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Basic (000) 421,804 211,182 100
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Diluted (000) 422,344 211,575 100
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Common shares traded during
the year (000) 207,978 110,244 89
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Common share price ($)
High $1.33 $2.95 (55)
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Low $0.94 $0.60 57
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Close, end of year $1.28 $0.74 73
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Twelve months ended December 31
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($000 except per share amounts) 2009 2008 % Change
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FINANCIAL
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Revenues, net of royalties $421,690 $629,339 (33)
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Cash flow(1) $12,522 $54,817 (77)
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Per share, basic(1) $0.04 $0.26 (85)
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Per share, diluted(1) $0.04 $0.26 (85)
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Net earnings (loss) $26,158 $(26,603) 200
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Per share, basic $0.08 $(0.13) 162
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Per share, diluted $0.08 $(0.13) 162
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Property and equipment additions $322,064 $351,736 (8)
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Cash on hand $256,787 $223,663 15
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Working capital $245,067 $197,914 24
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Long-term debt $876,181 $778,732 13
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Shareholders equity $671,588 $469,087 43
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Total assets $1,739,518 $1,431,675 22
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COMMON SHARE INFORMATION
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Shares outstanding at end
of period (000) 427,031 211,182 102
-------------------------------------------------------------------------
Weighted average shares outstanding
-------------------------------------------------------------------------
Basic (000) 326,560 210,794 55
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Diluted (000) 327,067 210,794 55
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Common shares traded during
the year (000) 654,270 393,365 66
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Common share price ($)
High $1.66 $5.26 (68)
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Low $0.61 $0.60 2
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Close, end of year $1.28 $0.74 73
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OPERATING HIGHLIGHTS
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Three months ended December 31
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2009 2008 % Change
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UPSTREAM RESULTS
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Daily production/sales volumes
-------------------------------------------------------------------------
Bitumen (bbl/d)(3) 6,090 7,086 (14)
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Crude oil (bbl/d) 880 1,187 (26)
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Natural gas (Mcf/d) 10,319 12,405 (17)
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Equivalent (boe/d)(4) 8,690 10,341 (16)
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Pricing(5)
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Bitumen ($/bbl) $48.23 $12.06 300
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Crude oil ($/bbl) $67.24 $48.13 40
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Natural gas ($/Mcf) $4.34 $6.61 (34)
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Barrels of oil equivalent ($/boe)(4) $45.76 $21.73 111
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RESERVES
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Reserves (mboe)(6)(7)
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Proved (1P) reserves 180,158 182,839 (1)
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Proved plus probable (2P) reserves 388,914 379,474 3
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Proved plus probable plus possible
(3P) reserves 471,406 452,294 4
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Reserve values ($million)(8)
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1P reserves $1,491 $1,026 45
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2P reserves $2,155 $1,543 40
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3P reserves $3,310 $2,274 46
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DOWNSTREAM RESULTS
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Refining throughput
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Crude charged (bbl/d) 8,188 8,333 (2)
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Refinery utilization (%) 86 88 (2)
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Margins ($000) $(4,050) $(10,161) 60
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Margins (%) (7) (18) 61
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-------------------------------------------------------------------------
Twelve months ended December 31
-------------------------------------------------------------------------
2009 2008 % Change
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UPSTREAM RESULTS
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Daily production/sales volumes
-------------------------------------------------------------------------
Bitumen (bbl/d)(3) 6,274 5,456 15
-------------------------------------------------------------------------
Crude oil (bbl/d) 1,041 1,029 1
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Natural gas (Mcf/d) 11,407 12,570 (9)
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Equivalent (boe/d)(4) 9,216 8,581 7
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Pricing(5)
-------------------------------------------------------------------------
Bitumen ($/bbl) $39.39 $45.74 (14)
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Crude oil ($/bbl) $54.61 $82.01 (33)
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Natural gas ($/Mcf) $3.90 $8.08 (52)
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Barrels of oil equivalent ($/boe)(4) $37.81 $50.76 (26)
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RESERVES
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Reserves (mboe)(6)(7)
-------------------------------------------------------------------------
Proved (1P) reserves 180,158 182,839 (1)
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Proved plus probable (2P) reserves 388,914 379,474 2
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Proved plus probable plus possible
(3P) reserves 471,406 452,294 4
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Reserve values ($million)(8)
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1P reserves $1,491 $1,026 45
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2P reserves $2,155 $1,543 40
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3P reserves $3,310 $2,274 46
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DOWNSTREAM RESULTS
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Refining throughput
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Crude charged (bbl/d) 7,820 9,194 (15)
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Refinery utilization (%) 82 97 (15)
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Margins ($000) $9,564 $(7,490) 228
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Margins (%) 4 (2) 300
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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, 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) Product pricing excludes realized and unrealized hedging
gains/losses.
(6) The reserve and resource estimates for 2009 and 2008 were prepared by
GLJ Petroleum Consultants Ltd. 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
quantities recovered 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
quantities recovered will be greater or less than the sum of the
estimated proved plus probable reserves. Possible reserves are those
additional reserves that are less certain to be recovered than
probable 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. As at December 31, 2009,
possible reserves were 82 million bbls valued at $1.155 billion (2008
- 73 million bbls valued at $731 million) based on a 10 percent value
of future pre-tax net revenues.
(7) After production of 3.4 million boe in 2009.
(8) 10 percent present value of future net revenue before taxes. Future
net revenues associated with reserves and resources do not
necessarily represent fair market value.
As suggested in our lead-in to this press release, we are pleased that the challenges of 2009 are behind us and look forward with great enthusiasm to 2010 and beyond for our company. Connacher is poised to deliver significantly higher operating and financial results, as a consequence of the steps we took in 2009 to improve corporate liquidity, which in turn facilitated the reactivation of our Algar oil sands project at Great Divide in northeastern Alberta. This will establish the productive capacity to be realized in 2010, 2011 and beyond.
During 2009, we raised or arranged over $450 million of cash and available credit to position the company to reactivate Algar and to meet its financial obligations, without fear of funding being rescinded in the middle of the project. Our equity raise positioned us to secure better terms without onerous maintenance covenants to increase our financial risk if another downturn in commodity prices occurred than would otherwise have been available to us in the long term US debt market. As a consequence of this strengthened liquidity, in July 2009 we reactivated construction at Algar and are now nearing completion of this project, on time and on budget.
Our 17 SAGD well pairs at Algar were drilled without complication in record time and will be tied in to the Algar plant to start receiving steam, as soon as commissioning is completed around mid-May 2010. As we did at Pod One, we will steam our well pairs for approximately 90 days during the circulation phase, before converting them over to production, likely in mid- August 2010. Thereafter, our goal will be to ramp up production in a systematic and reliable fashion towards the rated plant capacity of approximately 10,000 bbl/d of bitumen production. With a nameplate steam generating capacity at Algar of 30,000 bbl/d and with the presence of thicker, higher quality, although slightly more variable, reservoir at Algar compared to Pod One, we are hopeful to achieve or surpass the rated bitumen production capacity at Algar, once stabilized conditions are established after startup. We forecast that in 2010 Algar will produce at an average annualized daily rate of 1,685 bbl/d of bitumen. Assuming commerciality is declared approximately three months after first production, similar to our experience at Pod One, most of this production will be recorded in the fourth quarter 2010 with average ramp up rates estimated at 6,740 bbl/d during this period. We will capitalize all costs related to Algar until reliable production levels are achieved and commerciality is declared. Thereafter, related costs, including financial charges, will be expensed in the company's accounts.
We are pleased with the recent increased reliability of our operations at Pod One, despite having encountered a variety of challenges in our second year of operation. We had curtailed our production and steam injection in late 2008 and into early 2009 to reduce short term losses and to maintain liquidity when crude oil prices collapsed. At that time, we were experiencing higher operating costs, wide price differentials for heavy oil and resultant extremely low bitumen prices. Unfortunately, this also occurred at a time when we were rapidly approaching a high level of plant utilization. Subsequently, as prices improved, we were able to reinstate our Pod One ramp up, enter into risk management contracts to mitigate the downside risk of prices collapsing and gradually restored acceptable production levels with positive cash operating netbacks. Netbacks are a non-GAAP term; see attached Management's Discussion and Analysis ("MD&A").
Throughout 2009, we experienced a variety of small and manageable challenges at Pod One, while also conducting certain activities designed to optimize production and lower operating costs in the longer run. As at December 31, 2009, we had installed ESPs in eight wells and plan to have downhole pumps installed in all of our Pod One wells by the end of 2010. This has led to and may result in periodic production fluctuations during the process, but is anticipated to result in more efficient steam distribution, lower SORs, lower operating costs and increasingly reliable production levels. Our goal for 2010 is to average 8,555 bbl/d of bitumen production at Pod One with an SOR approximating 3.2 times. This would represent a 36 percent improvement over average 2009 bitumen production from this plant. Overall, we forecast total 2010 bitumen production to average 10,240 bbl/d for an increase exceeding 60 percent over 2009 levels with a considerably higher exit rate. A similar scale of increase can be anticipated for 2011, when Algar production will contribute for the full year.
During 2009, our second year of operations at Pod One, we lowered our unit operating costs to $18.77 per barrel of bitumen from year one 2008 levels of $26.42 per barrel of bitumen produced. Lower natural gas prices contributed to this performance, as did our commitment to optimization, as other costs were also reduced. During the year, we did experience unit operating costs at lower levels than the reported full year average and we are optimistic lower levels can be achieved on a sustainable basis, especially as synergies with Algar contribute to a more efficient overall oilsands operation.
The value of our company's asset base continued to escalate during 2009. As reported, the value of our reserve and resource base increased significantly, reflecting better prices, completion of capital programs and lower anticipated operating costs for our projects. The 10 percent pre-tax present value ("10% PV") of our proved and probable ("2P") reserves, totaling 389 million boe, was estimated by our independent engineers, GLJ Petroleum Consultants of Calgary, Alberta ("GLJ") to be $2.2 billion, an annual increase of 40 percent. The 10% PV of our 3P reserves, totaling 471 million boe, was estimated to exceed $3.3 billion. Our 3P reserves include 82 million barrels of possible bitumen reserves. Additionally, GLJ recognized best estimate contingent bitumen resources of 135 million barrels with an estimated 10% PV of $384 million and best estimate prospective bitumen resources of 97 million barrels with an estimated 10% PV of $236 million. As a consequence, the company's net asset value per share increased to offset the dilutive impact of the company's equity financing during the year. Further increases in reserve and resource volumes and values are anticipated when the results of the company's extensive core hole drilling program at Great Divide and Halfway Creek, the completion of Algar and the impact of the submission of our EIA application to expand Algar to an intermediate target of 34,000 bbl/d of bitumen (enroute to our stated goal of 50,000 bbl/d by 2015) are factored into our valuations. We expect to report the results of GLJ's updated reserve and resource evaluation, which is anticipated for July 2010. Barrels of oil equivalent ("boe" or "boes") 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.
Our refinery ("Refinery") in Great Falls, Montana earned a respectable four percent margin in 2009. This exceeded the performance of most refineries in the United States as industry and economic conditions were weak throughout the year. Abnormally strong asphalt markets contributed to results in 2009 and similar or possibly better market conditions are expected in 2010. We have either presold, or have commitments for, significant volumes of asphalt at very attractive prices for 2010. We also anticipate improved operating costs and efficiencies at our Refinery during 2010, even though narrow heavy oil differentials are prevalent. For Connacher, the good news is that these narrow differentials simultaneously make for improved upstream netbacks at our oil sands operations and furthermore, we are soon to be "long bitumen" with Algar coming onstream, which is positive for our overall corporate results.
Our full year operating and financial results in 2009 were adversely affected by the impact of hedging programs, adopted early in the year. These were put in place to insure and protect the company's ability to survive the possible continuation of much lower crude oil prices and widened differentials for a protracted period as we restructured our balance sheet, including the arrangement of funding to replace credit facilities which we had cancelled. These facilities were to have provided supplemental funding for Algar's completion, but were no longer viable in the credit conditions of the day. The $21 million opportunity cost of our crude oil price hedging program was reduced by $12 million arising from foreign exchange gains realized on US denominated interest obligations and from realized foreign currency collar gains on a portion of our crude oil revenue stream. Accordingly, our net "insurance premium" was only $9 million. All of our lower priced commodity hedges have now expired and we have now secured price protection at much higher levels. We can now complete Algar and the related capital programs, while having more confidence in achieving minimum levels of earnings before interest, taxes, depletion, depreciation and accretion ("EBITDA") to meet both financial obligations and capital spending requirements for the year. Our 2010 capital budget has been reset at $256 million, as certain capital programs originally contemplated for this year were completed in late 2009. We forecast our full year 2010 EBITDA will surpass $130 million and this together with our cash balances and available credit, should allow us to again meet our obligations under normal pricing and operating conditions. EBITDA is a non- GAAP term; see attached Management's Discussion and Analysis ("MD&A").
Current bitumen prices are strong at levels in excess of $50.00 per barrel. Heavy oil differentials have recently narrowed and crude oil prices have strengthened and remain in the general US$70/bbl-US$80/bbl range for WTI. As a consequence, cash operating netbacks for bitumen production are improving and with growing production volumes we have more confidence in our ability to internally generate funds for capital programs and working capital purposes, accompanied by better overall financial results in 2010.
There has been a recent resurgence in investor and industry interest in the oil sands and in the companies active in the space. We have had numerous discussions with various parties over the years about prospective or potential joint venture arrangements. To date, we have not found a suitable or preferable arrangement to supplant our ability to maintain 100 percent ownership by accessing North American capital markets for the long term funding requirements of our oil sands operations. We continue to have an open mind about such possibilities. While on occasion we have felt the market does not necessarily give full and fair recognition to the value and quality of our assets and operations, when compared with the more tenuous undeveloped resource base of our competitors, we intend to stay the course with our approach as it allows for on-time performance and maximum benefit to our shareholders.
Our goal remains to achieve 50,000 bbl/d of bitumen production by 2015. We will be commissioning the preparation of an updated reserve report in the summer of 2010, which will incorporate and reflect our successful core hole drilling program during the first quarter of this year. In a low priced environment for natural gas, we are currently comfortable with not having to be 100 percent natural gas self-sufficient, as adequate low priced supplies remain available to us to make steam at both Pod One and Algar. We may strategically expand our natural gas productive capacity when the timing is more appropriate. Similarly, with narrow current heavy crude oil price differentials likely to prevail for some time, given current worldwide and North American crude oil market fundamentals, we are content with our current refining capacity within our overall upstream to downstream balance, which currently emphasizes upstream production growth.
We made tough decisions, as we encountered tough circumstances in 2009. We believe we are uniquely positioned to now deliver much improved operating and financial results than those obtained in 2009. As we strive for excellence in all of our operations, our goal is to optimize production, to minimize costs and to achieve a high return on capital accompanied by an increasing ability to internally fund our expansion and growth.
Full details of our fourth quarter 2009 results and our full year 2009 results are contained in the attached MD&A and Financial Statements.
Connacher Oil and Gas Limited is a Calgary-based crude oil, natural gas liquids, natural gas and bitumen production company. Our principal asset is our interest in the Great Divide oil sands project in northeastern Alberta. We are nearing completion of our second 10,000 bbl/d SAGD oil sands plant at Algar to complement our operations at Great Divide Pod One. We also own a 9,500 bbl/d heavy oil refinery located in Great Falls, Montana and conventional crude oil and natural gas properties held in Western Canada. Connacher owns a 22 percent equity interest in Petrolfiera Petroleum Limited, a Calgary-based public oil company active in South America.
Forward Looking Information
This press release contains forward-looking information including but not limited to estimations of reserves and future net revenue associated therewith, anticipated future operating and financial results, forecast netbacks, future corporate general and administration expenses, forecast adjusted EBITDA, future profitability, expectations of future production, anticipated sales volumes, anticipated capital expenditures, further anticipated reductions in operating costs as a result of continued operational optimization, development of additional oil sands resources (including Algar and the timeline for construction, commissioning and steam circulation prior to commercial production at Algar, the capital costs for construction of Algar and the potential timing of achieving commerciality at Algar), expansion of current conventional oil and gas and oil sands operations including the expected timing of an EIA in respect of the Great Divide Development Program, anticipated sources of funding for capital expenditures and current financial obligations, the timing of application for the Corporation's first reclamation certificate associated with the construction of Pod One, future development and exploration activities, future heavy oil differentials, expectations regarding the fulfillment of forward sales contracts of asphalt in 2010, planned installation of ESPs at Pod One, potential future steam generation levels at Pod One, anticipated use of the Revolving Credit Facility, utilization of alternative financial derivative strategies to protect the company's cash flow, corporate acquisitions or business combinations and joint venture arrangements. 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, future economic conditions and the plans and expected impacts of adopting International Financial Reporting Standards. 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 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; and 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 recent financial crisis has resulted in economic uncertainty and 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. The 2010 financial outlook contained in the MD&A is based on certain assumptions regarding revenue (including production levels, refinery throughput, commodity prices, differentials, quality of bitumen produced, foreign exchange rates and transportation costs), operating and other costs, royalties and general and administrative costs which are detailed in the notes to the tables contained in the MD&A. Actual netbacks and adjusted EBITDA realized by Connacher in 2010 could differ materially from the estimates contained in the 2010 financial outlook. Material risks and uncertainties that may impact achievement of the 2010 netbacks and adjusted EBITDA are described in this MD&A. These and other risks and uncertainties are described in further detail in Connacher's Annual Information Form for the year ended December 31, 2009 ("AIF"), which is available at www.sedar.com. Information relating to "reserves" 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 associated future net revenues reported herein are contained in the report of GLJ Petroleum Consultants Ltd. dated February 12, 2010 on the reserves, resources and future net revenue of the Corporation as at December 31, 2009 (the "GLJ 2009 Report") and are summarized in Connacher's AIF. Future net revenues associated with reserves do not necessarily represent fair market value.
Information contained herein relating to Petrolifera, including information relating to Petrolifera's future exploration and development plans constitute forward looking information that has been publicly released by Petrolifera. This information is subject to change at the discretion of the Board of Directors of Petrolifera. Connacher does not control the decisions 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 press release are expressly qualified in their entirety by this cautionary statement, The forward-looking information included in this press release is made as of March 18, 2010 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.
Management's 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 expanding conventional production base and operating the Montana refinery, through the company's wholly owned subsidiary, Montana Refinery Company Inc. ("MRCI").
The Management's Discussion and Analysis (MD&A") is dated as of March 18, 2010 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, 2009 and 2008. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") and are presented in Canadian dollars. MD&A provides management's view of the financial condition of the company and the results of its operations for the reporting periods.
Non-GAAP Measurements
The MD&A contains terms commonly used in the oil and gas industry, such as cash flow, cash flow per share, cash operating netback, bitumen netback, conventional netback, refinery margins, corporate netback and adjusted earnings before interest, taxes, depreciation and amortization ("EBITDA"). These terms are not defined by GAAP and should not be considered an alternative to, or more meaningful than, cash provided by operating activities or net earnings as determined in accordance with GAAP as an indicator of Connacher's performance. Management believes that in addition to net earnings, cash flow, netbacks and adjusted EBITDA are useful financial measurements which assist in demonstrating the company's ability to fund capital expenditures necessary for future growth or to repay debt. Connacher's determination of cash flow, netbacks and adjusted EBITDA may not be comparable to that reported by other companies. All references to cash flow throughout this report are based on cash flow from operating activities before changes in non-cash working capital, pension funding and asset retirement expenditures. The company calculates cash flow per share by dividing cash flow by the weighted average number of common shares outstanding. Netbacks, including by product, are calculated by deducting the related diluent, transportation, field operating costs and royalties from revenues. Adjusted EBITDA is calculated as net earnings before finance charges, taxes, depreciation, amortization and accretion, stock based compensation, foreign exchange gains/losses, interest/other income, equity earnings/losses and dilution gains/losses. Cash flow and netbacks are reconciled to net earnings within this MD&A. Future anticipated netbacks and adjusted EBITDA will be reconciled to net earnings in the applicable MD&A on a quarterly basis throughout 2010.
Forward-looking Information
This report, including the Letter to Shareholders and the updated 2010 financial outlook contained in the MD&A, contains forward-looking information including but not limited to estimations of reserves and future net revenue associated therewith, anticipated future operating and financial results, forecast netbacks, future corporate general and administration expenses, forecast adjusted EBITDA, future profitability, expectations of future production, anticipated sales volumes, anticipated capital expenditures, further anticipated reductions in operating costs as a result of continued operational optimization, development of additional oil sands resources (including Algar and the timeline for construction, commissioning and steam circulation prior to commercial production at Algar, the capital costs for construction of Algar and the potential timing of achieving commerciality at Algar), expansion of current conventional oil and gas and oil sands operations including the expected timing of an EIA in respect of the Great Divide Development Program, anticipated sources of funding for capital expenditures and current financial obligations, the timing of application for the Corporation's first reclamation certificate associated with the construction of Pod One, future development and exploration activities, future heavy oil differentials, expectations regarding the fulfillment of forward sales contracts of asphalt in 2010, planned installation of ESPs at Pod One, potential future steam generation levels at Pod One, anticipated use of the Revolving Credit Facility, utilization of alternative financial derivative strategies to protect the company's cash flow, corporate acquisitions or business combinations and joint venture arrangements. 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, future economic conditions and the plans and expected impacts of adopting International Financial Reporting Standards. 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 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; and 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 recent financial crisis has resulted in economic uncertainty and 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. The 2010 financial outlook contained in the MD&A is based on certain assumptions regarding revenue (including production levels, refinery throughput, commodity prices, differentials, quality of bitumen produced, foreign exchange rates and transportation costs), operating and other costs, royalties and general and administrative costs which are detailed in the notes to the tables contained in the MD&A. Actual netbacks and adjusted EBITDA realized by Connacher in 2010 could differ materially from the estimates contained in the 2010 financial outlook. Material risks and uncertainties that may impact achievement of the 2010 netbacks and adjusted EBITDA are described in this MD&A. These and other risks and uncertainties are described in further detail in Connacher's Annual Information Form for the year ended December 31, 2009 ("AIF"), which is available at www.sedar.com. Information relating to "reserves" 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 associated future net revenues reported herein are contained in the report of GLJ Petroleum Consultants Ltd. dated February 12, 2010 on the reserves, resources and future net revenue of the Corporation as at December 31, 2009 (the "GLJ 2009 Report") and are summarized in Connacher's AIF. Future net revenues associated with reserves do not necessarily represent fair market value.
Information contained herein relating to Petrolifera, including information relating to Petrolifera's future exploration and development plans constitute forward looking information that has been publicly released by Petrolifera. This information is subject to change at the discretion of the Board of Directors of Petrolifera. Connacher does not control the decisions 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 18, 2010 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 2009
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Maximize shareholder value through Tripled market capitalization.
the ownership and operatorship of Retained 100 percent working
large focused working interests interest in Great Divide Oil Sands
Project.
Maintained high working interests in
conventional crude oil and natural
gas assets.
Continued to own and operate the
Montana Refinery.
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Focus on projects with Produced 4.5 million barrels of
characteristics of expandability, bitumen from our first oil sands
repeatability and sustainability project (Pod One) since start-up.
Initiated construction of our second
oil sands project, Algar.
Bitumen reserve values increased.
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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
Montana Refinery allowed the company
to capture much of the heavy oil
differentials.
Modular approach permitted on time
facilities construction and cost
control at Algar.
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Operate with financial discipline Fully funded Algar prior to
commencing construction.
Recapitalized the company in 2009
with additional equity.
Reduced capital spending on
conventional programs.
Replaced cancelled Revolving Credit
Facility with new US$50 million
facility.
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Three Years Summary Information
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($000 except per share amounts) 2009 2008 2007
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Total revenues, net of royalties $421,690 $629,339 $344,520
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Net earnings (loss) 26,158 (26,603) 40,961
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Per share, basic 0.08 (0.13) 0.20
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Per share, diluted 0.08 (0.13) 0.20
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Total assets 1,739,518 1,431,675 1,258,828
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Long-term debt $876,181 $778,732 $664,462
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Connacher has experienced substantial growth during the last three years. The revenue increase from 2007 to 2008 was due to increased upstream production volumes from the company's first oil sands project, Pod One, which achieved commerciality on March 1, 2008 and 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). In relative terms, higher commodity prices played a lesser role in this revenue growth in 2008. Although production volumes increased again in 2009, the impact of substantially lower commodity prices and reduced demand for refined petroleum products resulted in lower revenues. The company's long-term plans anticipate continued increases in upstream production and sales volumes through the continued development of additional oil sands and conventional oil and gas projects. In 2010 and beyond, we anticipate our second SAGD oil sands project, Algar, will add significant additional production and sales volumes.
Although changes to production and sales volumes and 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 2007 and 2009 have been non-cash charges and gains. These include foreign exchange gains and losses (2007 - $27 million gain; 2008 - $12 million loss; 2009 - $106 million gain) 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. Additionally, depletion, depreciation and accretion expense increased 81 percent in 2008 (to $56 million) from lower amounts reported in 2007 ($31 million), the primary driver of which was the 270 percent increase in upstream production volumes noted above. Depletion, depreciation and accretion expense was $67 million in 2009, primarily due to higher production.
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, so long as the debt remains outstanding. Connacher did maintain a currency and interest rate hedge on a portion of this debt until November 2008, when management decided to realize the benefit of a weak Canadian dollar and unwound the hedge for net cash proceeds of $89 million. This improved liquidity was achieved without any equity dilution or additional borrowings. Similar hedges may be re-instated in the future under appropriate conditions and circumstances.
Since 2007, total long-term debt increased, as it has been an important source of funding for expanding the company's asset base. The majority of this asset growth has been in the oil sands of Northern Alberta, where Pod One was completed in 2007 at a cost of $272 million and commenced commercial production in early 2008. Construction of the company's second 10,000 bbl/d SAGD oil sands project, Algar, at a total estimated cost of $375 million, was approximately 80 percent complete at December 31, 2009 and is anticipated to be commissioned into operation in May 2010.
Marketing - Upstream
Diluted bitumen ("dilbit"), crude oil and natural gas are generally sold on month-to-month sales contracts negotiated with major Canadian or U.S. marketers, refiners, regional upgraders or other end users, at either spot reference prices or at prices subject to commodity contracts based on WTI market prices for crude oil and AECO market prices for natural gas. As a means of managing the risk of commodity price volatility, Connacher enters into financial derivative commodity price-hedging contracts from time to time.
During 2009, Connacher fulfilled a variety of short-term supply contracts for the sale of dilbit to a variety of purchasers in central and northern Alberta. Our selling prices received for dilbit sales were also influenced by the following WTI crude oil price hedging contracts:
- February 1, 2009 to August 31, 2009 - 2,500 bbl/d at WTI
US$46.00/bbl;
- April 1, 2009 to December 31, 2009 - 2,500 bbl/day at WTI
US$49.50/bbl; and
- September 1, 2009 - December 31, 2009 - 2,500 bbl/d at a minimum of
WTI US$60.00/bbl and a maximum of WTI US$84.00/bbl.
In 2009, the opportunity cost, or realized losses, on these contracts totaled $21 million. These losses are deducted from reported upstream revenues.
The February and April 2009 WTI hedges were contracted early in the year, when WTI was trading in the low US$40/bbl range, to capitalize on the contango in the crude oil futures markets. This provided the price security that allowed Connacher to restore the bitumen ramp-up process at Pod One after having to scale back operations in December 2008 when crude oil prices collapsed.
In order to mitigate foreign exchange exposure to commodity pricing, Connacher also entered into a foreign exchange revenue collar which throughout 2009 set a floor of CAD$11.925 million and a ceiling of CAD$13 million on a notional amount of US$10 million of monthly production revenue. In 2009, this contract resulted in a realized hedging gain (for which we received cash) in the amount of $8 million. Connacher realized an additional $4 million in foreign exchange gains in 2009 primarily from the impact of the appreciation of the Canadian dollar on the payment of U.S. dollar denominated interest obligations. In aggregate, Connacher's realized commodity and foreign exchange risk management programs resulted in a net realized loss of $9 million in 2009. In 2008, Connacher realized foreign exchange gains of $106 million, $98 million of which cash was received on the monetization of a cross-currency swap on a portion of the company's long-term debt.
At March 18, 2010, Connacher had the following WTI crude oil price hedging contracts in place:
- Calendar year 2010 - 2,500 bbl/d at WTI US$78.00/bbl;
- February 1, 2010 - April 30, 2010 at 2,500 bbl/d at WTI US$79.02/bbl;
and
- May 1, 2010 - December 31, 2010 - 2,500 bbl/d at a minimum of WTI
US$75.00/bbl and a maximum of WTI US$95.00/bbl.
In addition to our financial contracts and in order to manage our physical upstream production in the North American oil markets, Connacher has entered into various contracts for the supply of dilbit to a variety of heavy oil purchasers in central and northern Alberta. In order to secure preferred diluent supplies, Connacher has also entered into several diluent purchase contracts.
Marketing - Downstream
Sales of refined petroleum products are generally made on monthly sales contracts negotiated with wholesalers, retailers and large end-users for gasoline, jet fuel and diesel and with construction contractors and road builders for asphalt. Occasionally, sales contracts are for periods in excess of one month. To date, Connacher has not hedged these revenue streams as the "island" market we operate in makes it difficult to enter into effective hedge programs without incurring significant basis risk.
Pricing
General economic conditions and international and local supplies, together with many other uncontrollable variables, influence the price for WTI light gravity crude oil. Weather, domestic supplies, restricted continental markets and other variables influence the market price for natural gas.
Our revenues, cash flow and earnings are significantly influenced by the volatility of crude oil and natural gas prices. In 2009, WTI crude oil traded between US$33.98/bbl and US$81.04/bbl (2008 - between US$31.41/bbl and US$145.29/bbl) and on a yearly average basis was 38 percent lower in 2009 (US$61.99/bbl) than in 2008 (US$99.92). In 2009, AECO natural gas traded in a range of $1.96/Mcf to $6.61/Mcf (2008 - $5.80/Mcf to $11.85/Mcf), averaging $3.99/Mcf in 2009 compared to $8.20/Mcf in 2008, a decrease of 51 percent. (Source: Bloomberg)
Connacher's crude oil and bitumen production slate is generally heavier gravity than the referenced WTI. Consequently, the market price realized by the company is typically lower than WTI. This difference is commonly referred to as the "heavy oil differential".
Before hedging gains and losses, Connacher realized the following commodity selling prices:
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2009 2008
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Bitumen - $/bbl $ 39.39 $ 45.74
Crude oil - $/bbl $ 54.61 $ 82.01
Natural gas - $/Mcf $ 3.90 $ 8.08
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MRCI Realized Selling Price (US$/bbl) 2009 2008
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Gasoline $ 69.16 $ 106.91
Diesel $ 71.42 $ 125.05
Jet fuel $ 82.29 $ 142.80
Asphalt $ 67.76 $ 60.69
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Lower refined petroleum product prices in 2009 were consistent with lower yearly average WTI prices and reflected the impact of an economic recession in the U.S. for much of 2009, reduced demand for petroleum products and the impact of surplus gasoline imported to the U.S. from Europe and Asia. The niche market of MRCI provided a buffer to some of these factors, but our refinery was not immune to the general deterioration in the refining industry in 2009.
The exception was for asphalt, prices for which were higher in 2009 due to a reduction in supply of asphalt as many refiners replaced asphalt production with higher coking capacity and to a lesser extent, increased asphalt product demand. During the summer of 2009, MRCI sold asphalt at higher prices than ever before, contributing to higher downstream profit margins. MRCI currently has contracted asphalt sales of approximately 470,000 bbls at average prices approximating US$100/bbl for 2010.
Selling prices of refined petroleum products are also influenced by general economic conditions and local and international supply and demand factors. Average prices realized by the company in 2009 were much lower than pricing realized in 2008.
Financial and Operating Review
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Upstream Netbacks ($000)
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For the three months Oil Crude Natural
ended December 31, 2009 Sands(1) Oil Gas Total
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Gross revenues(2) $ 47,733 $ 5,502 $ 4,120 $ 57,355
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Diluent purchased(3) (17,055) - - (17,055)
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Transportation costs (3,657) (58) (3) (3,718)
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Production revenue 27,021 5,444 4,117 36,582
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Realized financial
derivative gains
(losses)(4) (6,537) - - (6,537)
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Unrealized mark-to-market
accounting gains
(losses)(5) (2,763) - - (2,763)
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Royalties (1,065) (980) 87 (1,958)
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Operating costs (12,995) (1,351) (2,129) (16,475)
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Calculated netback $ 3,661 $ 3,113 $ 2,075 $ 8,849
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Cash operating netback,
excluding hedging gains
and losses(6) $ 12,961 $ 3,113 $ 2,075 $ 18,149
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For the three months Oil Crude Natural
ended December 31, 2008 Sands(1) Oil Gas Total
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Gross revenues(2) $ 32,188 $ 5,259 $ 7,547 $ 44,994
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Diluent purchased(3) (19,507) - - (19,507)
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Transportation costs (4,719) (96) - (4,815)
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Production revenue 7,962 5,163 7,547 20,672
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Realized financial
derivative gains
(losses)(4) - - - -
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Unrealized mark-to-market
accounting gains
(losses)(5) - - - -
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Royalties (74) (1,282) (1,681) (3,037)
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Operating costs (17,292) (780) (1,679) (19,751)
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Calculated netback $ (9,404) $ 3,101 $ 4,187 $ (2,116)
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Cash operating netback,
excluding hedging gains
and losses(6) $ (9,404) $ 3,101 $ 4,187 $ (2,116)
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For the year ended Oil Crude Natural
December 31, 2009 Sands(1) Oil Gas Total
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Gross revenues(2) $ 162,640 $ 21,070 $ 16,232 $ 199,942
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Diluent purchased(3) (60,407) - - (60,407)
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Transportation costs (12,031) (321) (3) (12,355)
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Production revenue 90,202 20,749 16,229 127,180
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Realized financial
derivative gains
(losses)(4) (20,605) - - (20,605)
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Unrealized mark-to-market
accounting gains
(losses)(5) (4,520) - - (4,520)
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Royalties (2,370) (4,990) (623) (7,983)
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Operating costs (42,980) (4,380) (9,407) (56,767)
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Calculated netback $ 19,727 $ 11,379 $ 6,199 $ 37,305
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Cash operating netback,
excluding hedging gains
and losses(6) $ 44,852 $ 11,379 $ 6,199 $ 62,430
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For the year ended Oil Crude Natural
December 31, 2008 Sands(1) Oil Gas Total
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Gross revenues(2) $ 198,031 $ 30,982 $ 37,187 $ 266,200
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Diluent purchased(3) (92,291) - - (92,291)
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Transportation costs (14,403) (96) - (14,499)
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Production revenue 91,337 30,886 37,187 159,410
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Realized financial
derivative gains
(losses)(4) - - (831) (831)
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Unrealized mark-to-market
accounting gains
(losses)(5) - - - -
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Royalties (948) (7,229) (7,535) (15,712)
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Operating costs (52,758) (4,525) (6,710) (63,993)
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Calculated netback $ 37,631 $ 19,132 $ 22,111 $ 78,874
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Cash operating netback,
excluding hedging gains
and losses(6) $ 37,631 $ 19,132 $ 22,942 $ 79,705
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(1) In the first quarter of 2008, Connacher completed the conversion of a
majority of its fifteen horizontal well pairs to production status at
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.
In the financial statements Upstream Revenues represent sales of
dilbit, crude oil and natural gas, net of royalties and Upstream
Operating Costs include the cost of purchased diluent.
(3) Diluent volumes purchased and blended into dilbit sales have been
deducted in calculating production revenue and production volumes
sold.
(4) Realized financial derivative gains/losses reflect cash
receipts/disbursements in respect of financial derivative commodity
price-hedging contracts.
(5) Unrealized mark-to-market ("MTM") accounting gains/losses reflect
changes in the market value of unsettled commodity price derivative
contracts. From period to period the market value of these contracts
change due to the volatility of the commodity's forward pricing curve
and the reducing period to maturity of these contracts.
(6) Cash operating netbacks are calculated before adding/deducting
hedging accounting gains/losses. Netbacks on a per-unit basis are
calculated by dividing cash 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 widely used in the oil and
gas industry as a supplemental measure of the company's efficiency
and its ability to fund future growth through capital expenditures.
Netbacks are reconciled to net earnings below.
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Upstream Sales and Production Volumes
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For the three months ended December 31 2009 2008 % Change
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Dilbit sales - bbl/d 8,261 9,747 (15)
Diluent purchased - bbl/d (2,171) (2,661) (18)
Bitumen produced and sold - bbl/d 6,090 7,086 (14)
Crude oil produced and sold - bbl/d 880 1,187 (26)
Natural gas produced and sold - Mcf/d 10,319 12,405 (17)
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Total - boe/d 8,690 10,341 (16)
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For the years ended December 31 2009 2008 % Change
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Dilbit sales - bbl/d(1) 8,493 7,533 13
Diluent purchased - bbl/d(1) (2,219) (2,077) 7
Bitumen produced and sold - bbl/d(1) 6,274 5,456 15
Crude oil produced and sold -bbl/d 1,041 1,029 1
Natural gas produced and sold - Mcf/d 11,407 12,570 (9)
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Total - boe/d 9,216 8,581 7
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(1) Since declaring Pod One "commercial" effective March 1, 2008. Daily
averages are based on total calendar days during the year 2008.
Upstream Netbacks per Unit of Production
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Crude Natural
For the three months Bitumen Oil Gas Total
ended December 31, 2009 ($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
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Production revenue $ 48.23 $ 67.24 $ 4.34 $ 45.76
Realized financial
derivative gains
(losses) (11.67) - - (8.18)
Unrealized mark-to-market
accounting gains (losses) (4.93) - - (3.46)
Royalties (1.90) (12.10) 0.09 (2.45)
Operating costs (23.19) (16.69) (2.24) (20.61)
Calculated netback $ 6.54 $ 38.45 $ 2.19 $ 11.06
Cash operating netback,
excluding hedging gains
and losses $ 23.14 $ 38.45 $ 2.19 $ 22.70
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For the three months
ended December 31, 2008
-------------------------------------------------------------------------
Production revenue $ 12.06 $ 48.13 $ 6.61 $ 21.73
Realized financial
derivative gains (losses) - - - -
Unrealized mark-to-market
accounting gains (losses) - - - -
Royalties (0.11) (11.74) (1.47) (3.19)
Operating costs (26.53) (7.14) (1.47) (20.76)
Calculated netback $ (14.58) $ 29.25 $ 3.67 $ (2.22)
Cash operating netback,
excluding hedging gains
and losses $ (14.58) $ 29.25 $ 3.67 $ (2.22)
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Crude Natural
For the year ended Bitumen Oil Gas Total
December 31, 2009 ($ per bbl) ($ per bbl) ($ per Mcf) ($ per boe)
-------------------------------------------------------------------------
Production revenue $ 39.39 $ 54.61 $ 3.90 $ 37.81
Realized financial
derivative gains (losses) (9.00) - - (6.13)
Unrealized mark-to-market
accounting gains (losses) (1.97) - - (1.34)
Royalties (1.03) (13.13) (0.15) (2.37)
Operating costs (18.77) (11.53) (2.26) (16.88)
Calculated netback $ 8.62 $ 29.95 $ 1.49 $ 11.09
Cash operating netback,
excluding hedging gains
and losses $ 19.59 $ 29.95 $ 1.49 $ 18.56
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For the year ended
December 31, 2008
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Production revenue $ 45.74 $ 82.01 $ 8.08 $ 50.76
Realized financial
derivative gains (losses) - - (0.18) (0.27)
Unrealized mark-to-market
accounting gains (losses) - - - -
Royalties (0.47) (19.19) (1.64) (5.00)
Operating costs (26.42) (12.01) (1.46) (20.38)
Calculated netback $ 18.85 $ 50.81 $ 4.80 $ 25.11
Cash operating netback,
excluding hedging gains
and losses $ 18.85 $ 50.81 $ 4.98 $ 25.38
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Fourth quarter 2009 ("Q4 2009") gross upstream production revenues were $57 million, compared to $45 million in the fourth quarter of 2008 ("Q4 2008"). This increase was primarily attributable to higher crude oil pricing, which was offset by lower natural gas selling prices and lower overall production and sales volumes in Q4 2009. Lower production and sales volumes in Q4 2009 were the result of treating issues and evaporator clean-outs at Pod One and operational upsets and natural declines in our conventional operations.
Although annual production and sales volumes were seven percent higher for 2009 than they were in 2008, crude oil and natural gas selling prices were substantially lower in 2009. WTI averaged US$61.99/bbl in the current year compared to US$99.92/bbl in 2008, a 38 percent drop; and AECO natural gas prices averaged $3.99/Mcf in 2009 compared to $8.20/Mcf in 2008, a 51 percent reduction. Consequently, gross upstream production revenues were down 25 percent to $200 million in 2009. Additionally, our 2009 upstream revenues were adversely impacted by realized financial derivative commodity price-hedging contract losses of $21 million and unrealized mark-to-market non-cash accounting losses of $4.5 million on commodity hedges in place at December 31, 2009. Details of these contracts are addressed in "Marketing-Upstream", herein.
Royalties represent charges against production or revenue by governments and landowners. Royalties in Q4 2009 were $2 million compared to $3 million in Q4 2008 and for 2009 were $8 million compared to $15.7 million in 2008. 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 are applied on a sliding scale to commodity prices. The most notable change in royalties this year came as a result of lower commodity prices and natural gas cost allowance recoveries received from the Alberta Government, stemming from a reduction of Connacher's 2008 effective Alberta Crown royalty rate. Oil sands royalties increased in 2009 due to increased oil sands royalty rates.
In Q4 2009, upstream diluent purchases of $17 million (Q4 2008 $20 million) and for the 2009 year of $60 million (2008 - $92 million) were required for our oil sands operations. These purchases include $1.4 million of diluent purchased at market prices directly from our subsidiary, Montana Refining Company, Inc. in Q4 2009 and $7 million for the 2009 year. Although these intercompany costs were included in our netback calculations above to accurately present bitumen netbacks, for consolidated financial statement presentation purposes, these intercompany purchases were eliminated. There were no intercompany purchases of diluent from MRCI in 2008.
Bitumen produced at Great Divide is mixed with purchased diluent and sold as "dilbit." Diluent is a light liquid hydrocarbon used in our oil sands treating processes and enables the marketing and transportation of bitumen. For volumes in 2009, diluent purchased represented approximately 26 percent of the dilbit barrel sold, with bitumen the remaining 74 percent; in 2008 these splits were 28 percent and 72 percent, respectively. The price of diluent closely tracks crude oil prices. Consequently, diluent costs were lower in 2009 relative to the comparative 2008 periods, while comparative volumes changed only slightly.
Operating costs in Q4 2009 of $16.5 million were 17 percent lower than the $19.8 million in Q4 2008; and for 2009, operating costs of $56.8 million were 11 percent lower than $64 million incurred in 2008. This year-over-year ("YOY") reduction is more significant when considering the 2008 comparative figure includes less than a full year of operating costs for our Pod One oil sands operation (which was declared "commercial" in March 2008).
Bitumen operating costs were $43 million in 2009 ($18.77 per barrel of bitumen) compared to $53 million ($26.42 per barrel of bitumen) in 2008, a YOY reduction of 19 percent. Natural gas costs comprised $13.5 million, or 31 percent, of 2009 oil sands operating costs (2008 - $21.4 million, or 40 percent); and personnel, power, chemicals, facility and evaporator waste disposal costs comprised $29.5 million, or 69 percent (2008 - $31.6 million, or 60 percent). At our Pod One facility, in 2009 we used 9.3 MMcf/d of natural gas at an average cost of $3.95 per Mcf (2008 - 8.5 MMcf/d at $8.25 per Mcf). This equates to 1.47 Mcf of natural gas consumed to produce 1 bbl of bitumen in 2009 compared to 1.56 Mcf of natural gas consumed to produce 1 bbl of bitumen in 2008. Our focus is to reduce natural gas consumption in our oil sands operations which we anticipate will be accomplished through the introduction of downhole pumps in all our Pod One SAGD wells in 2010 plus through improved management of stream injected into our bitumen reservoir. Although lower natural gas costs in 2009 contributed to lower oil sands operating costs, our optimization strategy is contributing other cost savings. We expect per unit oil sands operating costs can be further reduced with more bitumen production at Pod One. A significant amount of non-natural gas oil sands operating costs are fixed in nature and we also anticipate some cost synergies between the two facilities over time.
Conventional crude oil YOY operating costs were down slightly on an absolute basis ($4.4 million compared to $4.5 million) and on a per unit basis ($11.53 per bbl compared to $12.01 per bbl), while production volumes increased marginally (1,041 bbl/d in 2009 compared to 1,029 bbl/d in 2008). The majority of this crude oil production is from the Battrum area of south west Saskatchewan, which has been the object of a water-flood recovery scheme for a number of years.
Natural gas operating costs of $9.4 million ($2.26 per Mcf) were higher in 2009 than in 2008 when they were $6.7 million ($1.46 per Mcf). Connacher did not drill any natural gas wells in 2009 because of low natural gas selling prices; consequently, we invested more monies in operational optimization activities in efforts to offset the natural decline ratio of 20 percent. In that regard, we were successful.
On a per unit basis, total upstream operating costs were down 17 percent to $16.88 per boe in 2009, compared to $20.38 per boe in 2008.
Transportation costs represent costs to transport dilbit, crude oil and natural gas to customers. Transportation costs, primarily trucking dilbit, were lower in Q4 2009 than Q4 2008 ($3.7 million compared to $4.8 million) and lower in 2009 than in 2008 ($12.4 million compared to $14.5 million), due to successful marketing arrangements in selling higher volumes to closer markets in the current year. These costs are reported as an expense, in our consolidated statement of operations but have been deducted in calculating reported product selling prices.
Netbacks are a widely used industry measure of a company's efficiency and its ability to internally fund its growth. Significantly higher upstream commodity selling prices in Q4 2009, compared to Q4 2008, resulted in substantially improved YOY netbacks. Cash operating netbacks, excluding hedges, were $18 million in Q4 2009 ($22.70 per boe) compared to a loss of $2.1 million in Q4 2008 (loss of $2.22 per boe). It was in response to a collapse in crude oil prices and a widening of heavy oil differentials in the latter part of 2008, that Connacher announced it would temporarily curtail production at Pod One from levels that exceeded 9,000 bbl/d. In late January 2009, the company announced the resumption of full production ramp-up at Pod One, in anticipation of reinstated profitability at Pod One, as a result of improved product prices, in response to narrower heavy oil differentials, reduced diluent blending ratios due to increased dilbit sales to upgraders and due to WTI crude oil hedges entered into that provided some protection against further weakness in selling prices.
Commodity selling prices in 2009 were lower than they were in 2008. Our realized bitumen price was 14 percent lower; our realized crude oil selling price was 33 percent lower and natural gas price was down 52 percent. Consequently, YOY cash operating netbacks were 27 percent lower in 2009, notwithstanding our successful efforts in reducing diluent, transportation, and operating costs. The company's overall 2009 upstream cash operating netback, excluding hedging gains and losses was $62.4 million ($18.56/boe) compared to $79.7 million ($25.38/boe) in 2008.
Reconciliation of Upstream Operating Netback to Net Earnings
-------------------------------------------------------------------------
For the three months
ended December 31 2009 2008
-------------------------------------------------------------------------
($000, except per unit
amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Upstream netback,
as above $ 8,849 $ 11.06 $ (2,116) $ (2.22)
Interest and other income 187 0.23 3,349 3.52
Downstream margin - net (4,050) (5.07) (10,161) (10.68)
General and administrative (3,710) (4.64) (3,063) (3.22)
Stock-based compensation (2,118) (2.65) (1,088) (1.14)
Finance charges (13,190) (16.50) (12,138) (12.76)
Foreign exchange
(loss) gain 12,275 15.35 (5,643) (5.93)
Depletion, depreciation
and accretion (16,884) (21.12) (20,191) (21.23)
Income tax recovery 7,139 8.93 6,618 6.96
Equity interest in
Petrolifera earnings and
dilution gains (losses) (3,229) (4.02) 841 0.88
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Net loss $ (14,731) $ (18.43) $ (43,592) $ (45.82)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
($000, except per unit
amounts) Total Per boe Total Per boe
-------------------------------------------------------------------------
Upstream netback,
as above $ 37,305 $ 11.09 $ 78,874 $ 25.11
Interest and other income 3,550 1.06 5,434 1.73
Downstream margin - net 9,564 2.84 (7,490) (2.38)
General and administrative (14,772) (4.39) (11,814) (3.76)
Stock-based compensation (4,562) (1.36) (4,575) (1.46)
Finance charges (44,354) (13.19) (34,653) (11.03)
Foreign exchange
gain (loss) 106,164 31.56 (12,291) (3.91)
Depletion, depreciation
and accretion (66,562) (19.79) (56,448) (17.97)
Income tax recovery 7,305 2.17 5,311 1.69
Equity interest in
Petrolifera earnings and
dilution gains (losses) (7,480) (2.21) 11,049 3.52
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Net earnings (loss) $ 26,158 $ 7.78 $ (26,603) $ (8.46)
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Downstream Revenues and Margins
Connacher's 9,500 bbl/d heavy oil 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, into a range of higher value refined petroleum products, including regular and premium gasoline, jet fuel, diesel and asphalt. The Refinery, accordingly, provides a physical hedge for our bitumen revenues by recovering a portion of the heavy oil differential under normal operating conditions.
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 delivers products in Montana and neighboring regions by truck and rail transport.
The Refinery is subject to a number of seasonal factors which 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 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.
The Refinery operates in a "niche" market that incorporates Great Falls and surrounding area, Western Montana, Northern Idaho, Eastern Washington and Southern Alberta. While the "niche" market provided some insulation to a very challenging refining market in 2009, MRCI margins were impacted by narrower heavy oil differentials, reduced product demand and lower product prices because of competing gasoline imports from Europe and Asia.
Downstream revenues of $63.4 million in Q4 2009 were 12 percent higher than $56.8 million of refined products sold in Q4 2008. This was attributable to increased sales volumes (an additional 224,000 bbls, or 38 percent), offset by lower average product selling prices at $71.73 per barrel in Q4 2009, compared to $81.62 in Q4 2008. Leading this increase product sales volume was asphalt, which atypically continued into Q4 2009, when we sold almost 400,000 bbls of asphalt, compared to 110,000 bbls in Q4 2008. The higher volumes of asphalt sold in Q4 2009 stemmed from efforts to reduce inventory volumes prior to the winter build up period. Notwithstanding higher crude oil input costs and narrow heavy oil differentials in Q4 2009 compared to Q4 2008, margins on downstream refined product sales improved due to improved selling margins on asphalt.
For 2009, downstream revenues were $258 million, compared to $374 million in 2008, when average refined product selling prices were 28 percent higher (see "Pricing") and total refined product sales volumes were 370,000 bbls, or 11 percent higher. The Refinery was effectively shut-down for approximately one month during parts of September and October of 2009 as part of its planned turnaround, which is conducted roughly every three years. Crude charged and refinery production was also impacted by downtime related to the tie-in of a new hydrogen plant in Q1 2009. The recent economic downturn has had a dramatic effect on refined product demand, sales volumes and refined product pricing. Notwithstanding the positive impact that lower crude oil prices had on profit margins in 2009 (WTI crude oil was approximately 38 percent lower in 2009 than in 2008), heavy oil differentials, typically captured by the refining industry, narrowed to unprecedented lower levels in 2009, minimizing the benefit of lower crude oil costs. The reduction in 2009 sales volumes was primarily due to lower demand for gasoline and diesel in a weak economy. Asphalt sales volumes were five percent higher in 2009 than in 2008, but their selling margins were much higher in 2009. Lucrative asphalt sales contracts continue into 2010, buoyed by federal government infrastructure projects creating demand for our specialty asphalt products.
Downstream revenues and refining margins include the benefit of diluent sales revenue of $7.1 million in 2009 directly attributable to our oil sands operation. These sales were transacted at prevailing fair market prices. These transactions were eliminated on consolidation for financial statement presentation purposes. There were no intercompany sales in prior years.
General economic conditions affect refined product demand and pricing. We anticipate they will continue to influence our downstream financial results in future.
The operating results of our Refinery for 2009 and 2008 are summarized below.
Refinery Throughput
-------------------------------------------------------------------------
Yearly
2009 Mar 31 June 30 Sept 30 Dec 31 Average
-------------------------------------------------------------------------
Crude charged - bbl/d(1) 6,867 9,145 7,076 8,188 7,820
Refinery production
- bbl/d(2) 7,946 10,438 8,131 8,674 8,797
Sales of produced refined
products - bbl/d 5,290 9,222 10,596 8,841 8,502
Sales of refined products
(includes purchased
products) - bbl/d(3) 5,890 9,451 11,697 9,646 9,188
-------------------------------------------------------------------------
Refinery utilization(4) 72% 96% 75% 86% 82%
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Yearly
2008 Mar 31 June 30 Sept 30 Dec 31 Average
-------------------------------------------------------------------------
Crude charged - bbl/d(1) 9,830 9,329 9,239 8,333 9,194
Refinery production
- bbl/d(2) 11,081 10,290 10,284 9,075 10,180
Sales of produced refined
products - bbl/d 7,408 12,274 11,891 6,404 9,492
Sales of refined products
(includes purchased
products) - bbl/d(3) 7,902 12,878 12,385 7,564 10,181
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Refinery utilization(4) 104% 98% 97% 88% 97%
-------------------------------------------------------------------------
(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 feedstock.
(3) Includes refined products purchased for resale.
(4) Represents crude charged divided by total crude capacity of the
Refinery.
Feedstocks
-------------------------------------------------------------------------
Yearly
2009 Mar 31 June 30 Sept 30 Dec 31 Average
-------------------------------------------------------------------------
Sour crude oil 91% 91% 91% 97% 92%
Other feedstocks & blends 9% 9% 9% 3% 8%
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
Sour crude oil 93% 93% 93% 94% 93%
Other feedstocks & blends 7% 7% 7% 6% 7%
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Revenues and Margins ($000)
-------------------------------------------------------------------------
2009 Mar 31 June 30 Sept 30 Dec 31 Total
-------------------------------------------------------------------------
Refining sales revenue $33,152 $69,094 $92,714 $63,440 $258,400
Refining - crude oil
and operating costs 30,720 65,611 85,015 67,491 248,836
Refining margin $2,432 $3,483 $7,699 $(4,051) $9,564
-------------------------------------------------------------------------
Refining margin (%) 7% 5% 8% (7%) 4%
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
Refining sales revenue $71,899 $117,820 $127,726 $56,803 $374,248
Refining - crude oil
purchases and
operating costs 71,393 117,926 125,455 66,964 381,738
Refining margin $506 $(106) $2,271 $(10,161) $(7,490)
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Refining margin (%) 1% - 2% (18%) (2%)
-------------------------------------------------------------------------
Per Barrel of Refined Product Sold
-------------------------------------------------------------------------
Yearly
2009 Mar 31 June 30 Sept 30 Dec 31 Average
-------------------------------------------------------------------------
Refining sales revenue $62.54 $80.34 $86.16 $71.73 $77.05
Refining - crude oil
and operating costs 57.95 76.29 79.00 76.36 74.20
Refining margin $4.59 $4.05 $7.16 $(4.63) $2.85
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
Refining sales revenue $99.99 100.54 112.10 $81.62 100.44
Refining - crude oil
and operating costs 99.28 100.63 110.10 96.23 102.44
Refining margin $0.71 $(0.09) $2.00 (14.61) $(2.00)
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Sales of Refined Products (Volume %)
-------------------------------------------------------------------------
Yearly
2009 Mar 31 June 30 Sept 30 Dec 31 Average
-------------------------------------------------------------------------
Gasolines 58% 48% 36% 39% 43%
Diesel fuels 22% 11% 10% 10% 12%
Jet fuels 6% 6% 6% 4% 6%
Asphalt 11% 31% 46% 45% 36%
Other 3% 4% 2% 2% 3%
-------------------------------------------------------------------------
Total 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
Gasolines 49% 33% 37% 47% 40%
Diesel fuels 27% 13% 19% 25% 19%
Jet fuels 7% 5% 4% 6% 6%
Asphalt 12% 45% 37% 18% 33%
Other 5% 4% 3% 4% 4%
-------------------------------------------------------------------------
Total 100% 100% 100% 100% 100%
-------------------------------------------------------------------------
Interest and Other Income
In the fourth quarter of 2009, the company earned interest and other income of $0.2 million (2008 - $3.3 million) primarily from investing surplus funds in secure short-term investments.
For 2009, the company earned interest of $1.3 million (2008 - $2.7 million) on surplus funds invested in secure short-term investments and ethanol rebates. Additionally, a gain of $2.3 million was realized on the repurchase of a portion of the Second Lien Senior Notes in 2009 (2008 - $2.7 million).
Surplus cash balances are invested in safe, secure and interest bearing deposit accounts. A portion of the interest earned was recognized as income and a portion (in respect of cash balances on hand from pre-funding oil sands projects under development) was credited to capitalized costs.
General and Administrative Expenses
In 2009, general and administrative ("G&A") expenses were $14.8 million, compared to $11.8 million in 2008, an increase of 25 percent, reflecting increased staffing to support the operation of Pod One and Algar. G&A of $5.0 million was also capitalized in 2009 (2008 - $5.2 million).
Finance Charges
Finance charges include interest expense relating to the Convertible Debentures, standby fees associated with the company's undrawn Revolving Credit Facility, fees on letters of credit issued and a portion of the First and Second Lien Senior Notes interest not attributable to major development/capital projects. Finance charges also include non-cash accretion charges with respect to the Convertible Debentures and a portion of the First and Second Lien Senior Notes. The company continues to capitalize interest on a portion of its long-term debt raised to finance oil sands projects.
Current year finance charges of $44.3 million were $9.7 million higher than 2008, primarily as a result of higher debt levels since issuing the First Lien Senior Notes in mid-June 2009. In 2009, Connacher capitalized interest costs of $52.4 million (2008 - $47.1 million) in respect of oil sands activities.
Stock Based Compensation
The company recorded non-cash stock-based compensation charges in the respective periods as follows:
-------------------------------------------------------------------------
Three months ended Twelve months ended
December 31 December 31
-------------------------------------------------------------------------
($000) 2009 2008 2009 2008
-------------------------------------------------------------------------
Charged to expense $ 2,118 $ 1,088 $ 4,562 $ 4,575
Capitalized to property
and equipment 427 429 1,096 1,471
-------------------------------------------------------------------------
$ 2,545 $ 1,517 $ 5,658 $ 6,046
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The reduction from the prior period is due to a lower fair market value for options granted during 2009.
Foreign Exchange Gains and Losses
Throughout 2009, the value of the Canadian dollar strengthened relative to the U.S. dollar. This had a significant impact on Connacher upon translating its U.S. dollar denominated long-term debt and U.S. dollar cash balances into Canadian dollars for financial reporting purposes.
In 2009, we had unrealized foreign exchange translation gains of $94.5 million (2008 - $122 million loss). We also realized foreign exchange gains of $11.7 million in 2009 from monthly cash settlement receipts in respect of a foreign exchange revenue collar and upon the settlement of U.S. dollar denominated obligations.
Throughout most of 2008, we had a cross-currency swap in place to hedge one-half of the foreign exchange exposure on our U.S. dollar indebtedness. This insulated us from some foreign currency volatility and reduced the impact of a weaker Canadian dollar, which resulted in the foreign exchange translation losses reported in 2008.
Having unwound the cross-currency swap in the Q4 2008 for proceeds of $98 million, Connacher became more exposed to changes in the U.S./Canadian dollar exchange rate when translating its U.S. dollar debt to Canadian dollars, for financial reporting purposes, for purposes of paying U.S. denominated interest and for repaying its U.S. denominated indebtedness. To mitigate some of this exposure, the company maintains U.S. cash balances and may secure another cross-currency swap, if economically available at some future date.
Depletion, Depreciation and Accretion ("DD&A")
Depletion expense is calculated using the unit-of-production method based on total estimated proved reserves. Downstream refining properties and other assets are depreciated over their estimated useful lives. Effective March 1, 2008, Pod One's accumulated capital costs were added to the depletion pool and have been depleted from that date. DD&A in 2009 was $66.6 million, 18 percent higher than in 2008, reflecting a full year's depletion of Pod One capital costs. Depletion equated to $16.51 per boe of production in 2009, compared to $14.33 per boe in 2008.
Future development costs of $1.4 billion (2008 - $1.3 billion) were included in the depletion calculation and capital costs of $555 million (2008 - $297 million) related to oil sands projects currently in the pre-production stage were excluded from the depletion calculation.
Included in DD&A was MRCI refinery depreciation of $7.4 million (2008 - $8.1 million), depreciation of furniture, equipment and leaseholds of $1.4 million (2008 - $1.5 million) and an accretion charge of $2.2 million (2008 - $1.7 million) in respect of the company's estimated asset retirement obligations ("ARO"). These ARO charges will continue in future years in order to accrete the currently booked discounted liability of $32.8 million to the estimated total undiscounted liability of $72 million over the remaining economic life of the company's oil sands, crude oil and natural gas properties.
At December 31, 2009, the recoverable value of the company's upstream and downstream assets and its major development projects exceeded their carrying values.
Income Taxes
The total income tax recovery of $7.3 million in 2009 included a current income tax recovery of $1.6 million, principally related to Refinery operations. A future income tax recovery of $5.7 million reflected the change in tax pools during the year.
The total income tax recovery of $5.3 million in 2008 included a current income tax recovery of $12.9 million, principally related to the Refinery and a future income tax provision of $7.6 million, reflecting the change in tax pools during 2008.
The approximate amount of total income tax pools available as at December 31, 2009 were $1,075 million in Canada and $53 million in the USA (2008 - $750 million in Canada and $39 million in the USA), including non-capital losses of approximately $327 million which expire over time to 2028 and $34 million of net capital losses which are available to reduce taxable 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, 2009.
Equity Interest in Petrolifera Petroleum Limited ("Petrolifera") Earnings and Dilution Gains/Losses
In Q3 2009, Petrolifera issued 66.5 million units ("Units") to raise $58 million. Each Unit was comprised of one Petrolifera common share and one-half Petrolifera share purchase warrant ("Share Purchase Warrant"). Each full Petrolifera Share Purchase Warrant is exercisable to purchase one Petrolifera common share at $1.20 per common share for a period of two years from issuance. Connacher subscribed for 13,556,000 Units. On September 1, 2009, Connacher also exercised options to purchase an additional 200,000 Petrolifera common shares at $0.50 per common share. The company recorded a dilution loss of $5.0 million in 2009.
In 2008, Petrolifera issued 4.4 million common shares to raise $40 million. Connacher did not subscribe for any of these shares. A dilution gain of $8 million was recorded in 2008.
Connacher now owns 26.9 million Petrolifera common shares, representing 22 percent of Petrolifera's issued and outstanding common shares and 6.8 million Share Purchase Warrants.
Connacher accounts for its equity investment in Petrolifera under the equity method of accounting. Connacher's share of Petrolifera's loss in 2009 was $2.5 million (2008 - $3.1 million earnings).
Net Earnings
In Q4 2009, the company incurred a loss of $14.7 million ($0.03 per basic and diluted shares outstanding) compared to a loss of $43.6 million ($0.21 per basic and diluted shares outstanding) in Q4 2008. For 2009, the company reported earnings of $26.2 million ($0.08 per basic and diluted shares outstanding) compared to a loss of $26.6 million ($0.13 per basic and diluted shares outstanding) for 2008. The primary reasons for these period to period variations are noted herein.
Shares Outstanding
In 2009, Connacher issued 214.9 million common shares from treasury to financially strengthen the company and to provide funding for growth, primarily at Algar.
For 2009, the weighted average number of common shares outstanding was 326.6 million (2008 - 210.8 million) and the weighted average number of diluted shares outstanding, as calculated by the treasury stock method, was 327.1 million (2008 - 210.8 million).
As at March 18, 2010, the company had the following securities issued and outstanding:
- 427,937,086 common shares;
- 22,956,835 share purchase options; and
- 10,420 share units under the share awards plan.
Additionally, the company's $100 million of outstanding Convertible Debentures are convertible into 20,002,800 common shares of the company.
Property and Equipment Expenditures
Property and equipment additions totaled $322 million in 2009 and $352 million in 2008. A breakdown of the expenditures is as follows.
-------------------------------------------------------------------------
Three months ended Twelve months ended
December 31 December 31
-------------------------------------------------------------------------
($000) 2009 2008 2009 2008
-------------------------------------------------------------------------
Crude oil, natural gas and
oil sands expenditures $111,314 $76,761 $301,244 $327,452
Refinery expenditures 5,532 9,412 20,820 24,284
-------------------------------------------------------------------------
$116,846 $86,173 $322,064 $351,736
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In 2009, expenditures of $168 million were incurred on the Algar project plant and drilling 17 SAGD well pairs; $30 million was incurred at Pod One to drill and complete two additional SAGD well pairs and to install seven ESPs, for the regularly scheduled plant turnaround and for other facility enhancement expenditures including $3 million on projects originally announced and budgeted as 2010 expenditures; $13 million was incurred on drilling 23 exploratory core holes including $3 million related to the winter 2010 exploration program; $15 million for co-generation, pipeline facilities and the Great Divide expansion project; and $61 million for capitalized interest amounts and capitalized G&A costs. Additionally, $14 million was incurred on conventional drilling (two wells), land acquisitions, seismic, well workovers and facilities.
Refinery capital expenditures in 2009 were primarily directed to the completion and tie-in of our new hydrogen plant, as part of the completion of the ultra-low sulphur diesel project, the regularly scheduled turnaround and the scheduled replacement of the fluid catalytic cracker reactor.
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, core hole exploratory drilling, seismic and other expenditures totaled $113 million.
In 2008, $14 million was incurred on the ultra low sulphur diesel conversion project at the refinery. The balance of $10 million was incurred for additional tankage, maintenance, environmental enhancements and expansion study projects.
Included in 2009 capital expenditures is $8 million of non-cash charges related to asset retirement obligations, capitalized stock-based compensation and accretion charges related to our long-term debt (2008 - $0.4 million).
Recent Financings
Common Share Issuance
On June 5, 2009 Connacher issued 191,762,500 common shares, from treasury, at a price of $0.90 per common share for gross proceeds of $173 million. The proceeds were raised for working capital to fund the company's capital expenditures, including Algar and for general corporate purposes.
To December 31, 2009, the proceeds were utilized to fund $89 million of capital expenditures including oil sands capital costs and the balance remains available for working capital purposes.
First Lien Senior Secured Notes
On June 16, 2009, the company issued US$200 million first lien five-year secured notes ("First Lien Senior Notes") at an issue price of 93.678 percent for gross proceeds of $212 million in equivalent Canadian funds. These financing proceeds were raised for working capital and general corporate purposes, including funding a portion of the remaining expenditures associated with the construction and drilling costs of Algar.
To December 31, 2009, proceeds of $88 million have been utilized to fund capital expenditures primarily relating to Algar and the balance remains available for working capital and general corporate purposes.
Flow-Through Shares
In October 2009, the company issued 23,172,500 common shares on a flow- through basis at $1.30 per common share for gross proceeds of $30.1 million to fund the company's 2010 exploration program. To December 31, 2009, proceeds of $1.4 million of the flow-through financing were utilized for the winter exploration program and the balance of the proceeds was included in year cash balances. The company renounced the income tax benefits of these expenditures ($30.1 million) to the subscribing investors effective December 31, 2009.
Revolving Credit Facilities
Throughout 2008 and for most of the first quarter of 2009, the company had 5-year term revolving banking lines of credit totaling approximately $200 million. Significantly lower crude oil prices in late 2008 and early 2009 created the prospect of the company potentially defaulting on an interest coverage covenant, notwithstanding the fact that the company had not drawn on the facilities except for a minor amount in letters of credit other than for letters of credit. Credit market conditions frustrated management's efforts to successfully re-negotiate the covenant terms and, in late March 2009, the company cancelled these credit facilities. Throughout most of 2009 the company maintained a cash-collateralized banking facility (the "L/C facility") to facilitate the issuance of letters of credit in the normal course of the business.
In November 2009, the company successfully secured a US$50 million Revolving Credit Facility. The two year facility is available for general corporate purposes and was provided by a syndicate of Canadian and international banks. In conjunction with the closing of this new facility, Connacher cancelled the L/C facility. Collateralized cash in the amount of $10 million plus interest, accordingly became available for general corporate purposes.
The new US$50 million Revolving Credit Facility provides Connacher additional liquidity and financial flexibility. It facilitates the issuance of letters of credit and the conduct of hedging activities. The Revolving Credit Facility is secured by a first priority security interest in all present and after-acquired assets of Connacher, except Connacher's investment in Petrolifera and the pipeline assets of an inactive subsidiary. The Revolving Credit Facility ranks senior to all of Connacher's indebtedness, as arranged when Connacher issued its First Lien Senior Notes earlier in 2009.
The Revolving Credit Facility has certain financial covenants, as is customary for this type of credit. The financial covenants, which must be met on a fiscal quarterly basis, are:
1) the ratio of the sum of cash, the undrawn amount of the Revolving Credit Facility and EBITDA (calculated as net earnings adjusted for interest expenses, taxes, depreciation, depletion and amortization, unusual or non-recurring items, gains/losses on asset sales, Petrolifera gains/losses and other non-cash gains/losses) to interest payable on the debt of the company, excluding the interest on the company's outstanding Convertible Debentures, shall not be less than 1.5:1, calculated on a rolling four fiscal quarterly basis;
2) excluding the company's outstanding Convertible Debentures from consolidated total debt, consolidated total debt to total capitalization (defined to include all debt, Convertible Debentures and equity) shall not be greater than 70 percent, dropping to 65 percent when production from Algar exceeds 8,000 bbl/d for a period of 30 consecutive days; and
3) debt outstanding under the Revolving Credit Facility to adjusted EBITDA shall not be greater than 2.0:1.
As at December 31, 2009, Connacher was in compliance with all its debt covenants.
As forecast for 2010, Connacher anticipates limited use of the Revolving Credit Facility other than for letters of credit, as the company has surplus cash and available funds from operations to meet its anticipated capital expenditures and financial requirements. Nevertheless, the Revolving Credit Facility was secured to strengthen liquidity and provides financial flexibility. At December 31, 2009, $7.6 million of letters of credit were issued in the course of normal business activities pursuant to the Revolving Credit Facility.
Liquidity and Capital Resources
Given the nature of our business involving long lead times for regulatory approvals, plant construction and ramp-up of ensuing bitumen production, we are mindful of the need to retain a high level of liquidity and a strong balance sheet. For this reason, we issued a substantial amount of new equity in 2009. This added financial strength enabling the company to access new borrowings to replace the cancelled credit facilities on better terms than otherwise available and it allowed the company to proceed with its growth strategy and re-commence construction at Algar.
Total gross proceeds of approximately $415 million were raised in 2009 from the two equity financings (common and flow-through share offering) and the First Lien Senior Note financing for working capital and general corporate purposes, including to fund the remaining budgeted costs (approximately $200 million) of Algar, the company's second 10,000 bbl/d SAGD oil sands project, and to fund other capital expenditures, including the company's $30 million 2010 winter exploration program.
At December 31, 2009, the company had working capital of $245 million (December 31, 2008 - $198 million), including $257 million of cash (December 31, 2008 - $224 million). As all of the company's indebtedness is long-term in nature, with no principal repayment obligation until June 2012, management believes that the company presently has sufficient liquidity and financial capacity to complete the Algar project, to fund its ongoing capital program and to satisfy its financial obligations.
The recent financial crisis of 2008 and 2009 has severely reduced liquidity in capital and bank markets. Economic uncertainty and significant volatility in commodity and stock markets have also occurred around the world. 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, the impact of an improvement in commodity prices and our overall financial liquidity, will allow us to continue expanding our operations.
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 constantly assesses alternative hedging strategies to protect the company's cash flow from the risk of potentially lower crude oil and refined product pricing and adverse foreign exchange rate fluctuations. Although the company's integrated business model provides some risk mitigation, it does not provide a perfect hedge, particularly against commodity price volatility. The purpose of any hedging activity we undertake is to ensure more predictable cash flow availability to supplement cash balances. This allows us to continue to service indebtedness, complete capital projects and protect the credit capacity of Connacher's oil and gas reserves in an uncertain and volatile commodity price environment.
In order to mitigate foreign exchange exposure to commodity pricing, the company entered into a foreign exchange revenue collar, which throughout 2009 set a floor of CAD$1.1925 per US$1.00 and a ceiling of CAD$1.30 per US$1.00, on a notional amount of US$10 million of production revenue per month. Additionally, in 2009 the company entered into WTI derivatives on a portion of its crude oil production with staggered maturities at increasing selling prices as the year progressed.
For 2010, the company has entered into WTI hedges to secure crude oil prices of US$78/bbl on a notional volume of 2,500 barrels of oil per day for all of 2010, secured US$79.02/bbl on a notional volume of 2,500 barrels of oil per day from February 1 to April 30, 2010 and entered into a pricing collar contract for 2,500 bbl/d from May 1 to December 31, 2010, with a minimum of WTI US$75.00/bbl and a maximum of WTI US$95.00/bbl.
In 2009, Connacher generated cash flow of $12.5 million ($0.04 per basic and diluted share outstanding), 77 percent lower than in 2008 primarily due to reduced commodity prices in 2009.
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 is reconciled with cash flow below.
Reconciliation of net earnings to cash flow from operations before working capital and other changes:
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Three months ended Twelve months ended
December 31 December 31
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($000) 2009 2008 2009 2008
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Net earnings (loss) $(14,731) $(43,592) $26,158 $(26,603)
Items not involving cash:
Depletion, depreciation
and accretion 16,884 20,191 66,562 56,448
Stock-based compensation 2,118 1,088 4,562 4,575
Non-cash financing charges 1,448 2,389 5,061 8,934
Future income tax
provision (recovery) (7,341) 8,180 (5,704) 7,623
Employee future benefits 287 386 651 730
Unrealized loss on risk
management contracts 2,763 - 4,520 -
Unrealized foreign
exchange loss (gain) (7,423) 115,694 (94,497) 122,342
Gain on repurchase of
Second Lien Senior Notes - (2,769) (2,271) (2,769)
Dilution (gain) loss 2,419 - 5,012 (7,964)
Equity interest in
Petrolifera loss
(earnings) 810 (841) 2,468 (3,085)
Realized foreign
exchange gains - (105,414) - (105,414)
Cash flow from operations
before working capital
and other changes $(2,766) $(4,688) $12,522 $54,817
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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.
Connacher's objectives in managing its cash, debt and equity 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 and to ensure continued compliance with debt covenants.
Connacher's capital structure is composed of:
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As at December 31 ($000) 2009 2008
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Long term debt(1) $876,181 $778,732
Shareholders' equity
Share capital, contributed surplus
and equity component 638,222 437,899
Accumulated other comprehensive income (loss) (16,178) 7,802
Retained earnings 49,544 23,386
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Total book capitalization $1,547,769 $1,247,819
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Debt to book capitalization(2) 57% 62%
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Debt to market capitalization(3) 62% 81%
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(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 year end market value of
shareholders' equity plus long-term debt.
Connacher had a high calculated ratio of debt to capitalization at December 31, 2009. This is due to pre-funding the full cost of Algar. As at December 31, 2009, the company's net debt (long-term debt, net of cash on hand) was $619 million, its net debt to book capitalization was 40 percent and its net debt to market capitalization was 44 percent.
As at December 31 the company reported the following debt outstanding:
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($000) 2009 2008
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First Lien Senior Notes, 11 3/4%,
due July 15, 2014 $191,509 $-
Second Lien Senior Notes, 10 1/4%,
due December 15, 2015 596,184 694,086
Convertible Debentures, 4 3/4%,
due June 30, 2012 88,488 84,646
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Total - no current maturities $876,181 $778,732
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Commitments, Contingencies, 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:
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Contractual obligations Within
($000) one year 1-3 years 4-5 years Thereafter
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Long-term debt at face
value (including future
interest payments) $92,722 $371,054 $964,582 $-
Asset retirement
obligations - 565 - 32,739
Operating leases and
other commitments 6,427 14,244 9,228 42,501
Employee future benefits 675 - - -
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Total $99,824 $385,863 $973,810 $75,240
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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.
The company has not entered into any off-balance sheet arrangements.
Outlook
We expect stronger financial results in 2010 compared to 2009, due to anticipated improved operating performance at Pod One; higher and more stabilized commodity prices (supported by our hedging program), the anticipation of increased production and sales volumes as Algar comes on stream in the latter part of 2010, and due to increased contributions from our refining operations, which anticipates healthy asphalt markets as government infrastructure projects continue strong demand for asphalt. MRCI currently has contracted asphalt sales of approximately 470,000 bbls at prices approximating US$100/bbl for 2010.
Current cash balances, together with available unused revolving lines of banking credit and positive upstream netbacks and downstream margins, are anticipated to be sufficient to meet all our budgeted capital expenditures and ongoing financial obligations throughout 2010. We have identified reserves and resources to support our confidence in our future growth prospects. To stabilize our outlook in a volatile period and protect against the possibility of renewed crude oil weakness, we have arranged favourable WTI derivative hedges on approximately one half of our bitumen production throughout 2010. Relative to our consumption of natural gas at Pod One and the Refinery, we have a built-in physical hedge with our own natural gas production in northern Alberta. This minimizes the impact of volatility to natural gas prices on our overall operations.
To the end of December 2009, we have invested approximately $297 million in the Algar project. We expect to complete its construction in April 2010, then commission the plant, steam the reservoir and commence production in the latter part of 2010.
The company's revised 2010 capital budget is as follows:
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($millions)
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Complete Algar $78
Algar capitalized interest, G&A and pre-commercial operations 52
Algar ESP pre-work and facility optimization 8
Cogeneration and sales transfer lines 22
Pod One, including two new SAGD wells, 9 high temperature
ESPs/PC pumps and facility optimization 27
EIA application 2
Expand Pod One trucking terminal 4
Exploration program 28
Conventional and head office capital 17
Refinery, including benzene removal project and
steam boiler replacement 18
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$256
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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 completing the Algar project and the continued expansion of all aspects of our business.
Future cash flows will be sheltered from current cash taxes by the company's tax pools, which currently exceed $1 billion and which will be augmented by future capital expenditures.
In our third quarter MD&A filed on SEDAR on November 11, 2009, we disclosed our then current 2010 financial outlook (the "2010 outlook") which contained an estimate of 2010 bitumen netback and 2010 adjusted earnings before interest, taxes, depreciation and amortization ("EBITDA"). The 2010 outlook is intended to provide investors with a measure of the ability of our Pod One and Algar projects and integrated business model to generate positive netbacks assuming close to full production from Pod One and initial production from Algar following a declaration of commerciality.
We have updated our 2010 outlook to incorporate actual results for January 2010 and reflect the following material changes in the 2010 outlook assumptions: lower Pod One production reflecting actual unplanned operational upsets in early 2010 and a delay in obtaining downhole pumps, which are now anticipated to be installed in April and September of this year; a lower heavy/light crude oil price differential; higher costs for diluent, electricity, chemicals and well workovers at Pod One; higher natural gas usage at Pod One due to the delay in installing pumps; lower gasoline and diesel prices; higher asphalt selling prices; and higher corporate G&A. We have also included estimated incremental production for our Algar project, which is presently under construction and anticipated to achieve commerciality in the latter part of 2010. Our planned 2010 capital budget is $256 million. This capital budget includes maintenance and replacement capital, in addition to capital requirements for production growth and regulatory compliance. The updated 2010 outlook is as at March 18, 2010. This outlook will be reviewed on a quarterly basis. The 2010 outlook will be updated on a quarterly basis to include 2010 actual results and the underlying assumptions for the balance of 2010 may be revised as required.
The calculations of netback and adjusted EBITDA are non-GAAP measures. The closest GAAP measure to the netback calculations and adjusted EBITDA calculation is net earnings. The updated 2010 outlook will be reconciled to net earnings in the applicable MD&A on a quarterly and annual basis in 2010.
Actual netbacks and adjusted EBITDA achieved during 2010 could differ materially from the estimates contained in our 2010 outlook. The material risk factors that we have identified toward achieving these future netbacks and adjusted EBITDA are outlined in the "Risk Factors" and "Forward-Looking Information" sections of this MD&A and in our Annual Information Form for the year ended December 31, 2009 ("AIF") and include, without limitation, difficulties or interruptions and additional costs during the production of bitumen, crude oil and natural gas; we may encounter timing difficulties or delays and additional costs relating to the construction, commissioning, steaming or start-up of the Algar project; we may experience difficulties in delivering diluent to our oil sands projects and dilbit to commercial markets; the performance and availability of facilities owned by third parties may adversely affect our operations; crude oil and natural gas prices may fluctuate from current estimates; there may be changes in refining spreads to WTI and changes in the differential pricing between heavy and light crude oil prices; there may be adverse currency fluctuations; general economic conditions may remain uncertain thus affecting demand for our products and/or the costs for labour, equipment and services and changes in, or the introduction of new, government regulations relating to our business may increase operating costs.
The following tables are calculated on an annualized basis and may not reflect actual quarterly netbacks or adjusted EBITDA. Volatility in quarterly netbacks and adjusted EBITDA will occur due to, among other things, seasonality factors affecting our operations, especially in our refining operations. Estimated 2010 bitumen netbacks and 2010 adjusted EBITDA constitute forward-looking information. See "Forward-Looking Information" and "Risk Factors" sections in this MD&A and in our AIF. The key assumptions relating to the 2010 outlook are set out in the notes following the tables below.
ESTIMATED 2010 BITUMEN NETBACK(1)
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Total $/bbl
US$75.40/bbl Average WTI Price of bitumen
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Bitumen price at wellhead(2)(3) $ 47.58
Financial Derivative Gain(4) 0.89
Royalties(5) (1.61)
Operating costs
Natural gas(6) (6.23)
Other operating costs(7) (8.68)
Bitumen netback $ 31.94
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(1) Assumes estimated total average daily bitumen production of
10,240 bbl/d in 2010; 8,555 bbl/d from Pod One and 1,685 bbl/d from
Algar and has not been adjusted for inflation. See "Forward-Looking
Information" and "Risk Factors" sections of our AIF. Production from
Algar assumes commerciality is declared effective October 1, 2010 and
has been annualized for calendar 2010.
(2) Based on average WTI price of US$75.40/bbl, a light/heavy
differential of US$10.90/bbl (average of 14.5 percent) and a quality
charge of $5.00/bbl, resulting in a dilbit price of $62.70/bbl. Also
assumes a foreign exchange rate of $1.05 =US$1.00.
(3) The bitumen price at the wellhead of $46.97/bbl for Pod One and
$45.24/bbl for Algar is net of dilbit transportation costs of
$6.00/bbl of bitumen and a diluent blending cost of $29.51/bbl of
bitumen ($22.12/bbl of dilbit), including $1.67/bbl of bitumen of
diluent transportation costs ($5.00/bbl of diluent), a six percent
average diluent premium to WTI and a blending ratio of 25 percent for
Pod One and a diluent blending cost of $37.24/bbl of bitumen
($26.07/bbl of dilbit), including $2.14/bbl of bitumen of diluent
transportation costs, ($5.00/bbl of diluent) a four percent average
diluent premium to WTI and a blending ratio of 30 percent for Algar.
(4) Anticipated benefit from a US$78.00/bbl WTI swap on 2,500 bbl/d of
bitumen production for calendar 2010 and a US$79.02/bbl WTI swap on
2,500 bbl/d of bitumen production from February to April, 2010.
(5) Royalties are calculated on a pre-payout basis and are estimated to
be $1.62/bbl for Pod One and $1.57/bbl for Algar.
(6) Based on an average SOR of 3.2 for Pod One and 3.4 for Algar and a
natural gas price of US$4.76/Mcf which equates to $6.19/bbl or
approximately 10,590 Mcf/d of natural gas burned to produce
8,555 bbl/d of bitumen at Pod One and equates to $6.47/bbl or
approximately 2,180 Mcf/d of natural gas burned to produce
1,685 bbl/d of bitumen at Algar. The SORs for Pod One are a
conservative estimate reflecting the impact of higher SORs
experienced to date in the five north wells of Pad 101 and the impact
of steaming the two new SAGD well pairs planned in 2010. The SORs
from Algar reflect the relative infancy of the SAGD well pairs and
are expected to trend down as the wells are optimized and as ESPs are
added.
(7) Assumes $8.41/bbl of other operating costs for Pod One and $10.07/bbl
of other operating costs at Algar.
ESTIMATED 2010 ADJUSTED EBITDA(1)
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Total $/bbl Total
US$75.40/bbl Average WTI Price of bitumen ($millions)
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Corporate netback contribution
-------------------------------------------------------------------------
Bitumen netback(2) $31.94 $120
Conventional netback(3) 4.94 18
Refinery netback(4) 3.19 12
Corporate netback 40.07 150
Corporate G&A(5) (5.14) (19)
Adjusted EBITDA $34.93 $131
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(1) Assumes estimated total average daily bitumen production of
10,240 bb/d in 2010; 8,555 bbl/d from Pod One and 1,685 bbl/d from
Algar and has not been adjusted for inflation. Also assumes a foreign
exchange rate of $1.05=US$1.00.
(2) See the table above for assumptions.
(3) Represents a blended conventional oil and natural gas netback per
barrel of bitumen. Assumes estimated production of 946 bbl/d of
conventional crude oil and 8,867 Mcf/d of natural gas production.
Conventional oil assets anticipated revenue based on average realized
oil price of US$65.56/bbl and natural gas assets revenue based on
average realized natural gas price of US$4.76/Mcf. Conventional asset
netback is based on 26 percent average royalty rate and average
operating costs of $12.87/boe.
(4) Assumes estimated refinery crude charged of 9,867 bbl/d, feedstock
purchased at US$68.73/bbl, refined products sold with a spread to WTI
of US$4.80/bbl and operating costs of US$8.32/bbl, implying a
refining margin of US$3.15/bbl of crude charged.
(5) Excludes capitalized G&A of $1.45/bbl of bitumen.
Sensitivity Analysis
The following table shows sensitivities to adjusted EBITDA for changes to oil prices, production volumes and foreign exchange rates. The analysis is based on recent prices and production volumes.
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Change $ million $/share(1)
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WTI price US$5.00/bbl 8 $0.02
Bitumen production 500 bbl/d 6 $0.01
Exchange rate (U.S./Canadian) $0.05 13 $0.03
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(1) Based on 427 million shares outstanding at December 31, 2009.
Information relating to Connacher, including Connacher's Annual Information Form is on SEDAR at www.sedar.com. See also the company's website at www.connacheroil.com.
Related Party Transactions
In 2009 the company paid professional legal fees of $1.3 million (2008 - $1.1 million) to a law firm in which the company's Corporate Secretary and a member of our Board of Directors are partners. 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, was conducted in an industry-standard joint venture arrangement with a company, a former officer of which is also a director of Connacher. Transactions with the joint venture partner company 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. The capital expenditures incurred to date are not considered material to the company's overall capital expenditure program. In March 2010 this director resigned from the joint venture partner company but remains a director of Connacher.
Significant Accounting Policies and Application of Critical Accounting Estimates
The significant accounting policies used by the company are described below. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Changes in these estimates and assumptions may have a material impact on the company's financial results and condition. The following discusses such accounting policies and is included herein to aid the reader in assessing the critical accounting policies and practices of the company and the likelihood of materially different results being reported. Management reviews its estimates and assumptions regularly 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
The reserve estimates for 2009 and 2008 were prepared by GLJ Petroleum Consultants Ltd. 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 quantities recovered 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 quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable 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. As at December 31, 2009, possible reserves were 82 million bbls valued at $1.155 billion (2008 - 73 million bbls valued at $731 million) based on a 10 percent value of future pre-tax net revenues.
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 subjective.
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 Canadian generally accepted accounting standards. 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.
Maintenance Costs
The Refinery units require regular major maintenance and repairs, which are commonly referred to as "turnarounds". The required frequency of the maintenance varies by unit, but generally is every three to four years. Turnaround costs which meet the definition of property, plant and equipment are capitalized and amortized over the period to the next scheduled turnaround. 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 regulatory requirements. Benefits are based on employees' 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 a corporate acquisition 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
Effective January 1, 2009, the company adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (CICA).
Goodwill and Intangible Assets, CICA Section 3064
The standard replaces the previous goodwill and intangible asset standard and revises the requirements for recognition, measurement, presentation and disclosure of intangible assets. The adoption of the standard has had no material impact on the company's consolidated financial statements.
Emerging Issues Committee (EIC) - 173, Credit Risk and the Fair Value of Financial Assets and Financial Liabilities
The EIC requires that the company's own credit risk and the credit risk of its counterparties be taken into account in determining the fair value of a financial instrument. The EIC is to be applied retrospectively without restatement of prior periods to periods ending on or after January 20, 2009. The adoption of the standard has had no material impact on the company's consolidated financial statements.
Financial Instruments - Disclosures, CICA Section 3862
In June 2009, the existing section 3862 was amended to include additional disclosure requirements about the fair value measurement of financial instruments and to enhance liquidity risk disclosures. The standard establishes a hierarchal disclosure framework associated with the level of pricing observability utilized in measuring fair value. This framework defines three levels of inputs to the fair value measurement process and requires that each fair value measurement be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the CICA 3862 hierarchy are as follows:
- Level 1 Inputs - quoted prices (unadjusted) in active markets for
identical assets or liabilities that the reporting entity has the
ability to access at the measurement date;
- Level 2 Inputs - inputs other than quoted prices included within
Level 1 that are observable for the asset or liability, either
directly (i.e. as prices) or indirectly (i.e. derived from prices);
and
- Level 3 Inputs - inputs for the asset or liability that are not based
on observable market data (unobservable inputs). These unobservable
inputs reflect the entity's own assumptions about the assumptions
that market participants would use in pricing the asset or liability,
and are developed based on the best information available in the
circumstances (which might include the reporting entity's own data).
The standard allows these disclosures to be provided on a prospective basis.
Business Combinations, CICA Section 1582, Consolidated Financial Statements, CICA Section 1601 and Non-Controlling Interests, CICA Section 1602:
These new standards were issued in January 2009 to be effective for fiscal years beginning on or after January 1, 2011 with early adoption permitted. Under Section 1582, changes in the determination of the fair value of the assets and liabilities of the acquiree will result in a different calculation of goodwill. Such changes include the expensing of acquisition-related costs incurred during a business combination, as opposed to capitalizing these costs as a part of the cost of the acquisition. Additionally, under the new standard, accruals for restructuring charges may not be recorded. This new standard will be applied prospectively to business combinations for acquisitions on or after January 1, 2011. Section 1601 establishes standards for the preparation of consolidated financial statements. Section 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. Under Sections 1601 and 1602, non-controlling interests will be presented as a component of equity, rather than as a liability on the consolidated balance sheet. Also, net income and components of other comprehensive income attributable to the owners of the parent and to the non-controlling interests are required to be separately disclosed on the income statement. The company is currently assessing the impact of the adoption of section 1582. The adoption of Sections 1601 and 1602 are not expected to have a material impact on the company's consolidated financial statements.
International Financial Reporting Standards
In early 2008, the Canadian Accounting Standards Board confirmed that publicly accountable enterprises (which would include Connacher) will be required to adopt international financial reporting standards ("IFRS") in place of Canadian Generally Accepted Accounting Principles ("Canadian GAAP") for interim and annual reporting purposes for fiscal years beginning on January 1, 2011. The impact of this change in accounting principles on our future financial position and results of operations is not 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 progress reporting is provided to our Audit Committee and 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 property, plant and equipment and goodwill, and asset retirement obligations. There will also be impacts on the future income tax balances associated with balance sheet items affected by the transition to IFRS.
We have also completed the design and planning and solution development phases, including testing of modifications made to our accounting and financial reporting systems to deal with the requirements of IFRS for the purpose of running in parallel during 2010 so as to generate IFRS comparative figures for reporting in 2011. During these phases, we have also been providing training to staff, management and Directors on international accounting and financial reporting standards and the impact they are having on our accounting processes and procedures.
Recently, we commenced the implementation phase and have engaged in ongoing discussions with our auditors and Audit Committee regarding revisions to our accounting policies to conform to IFRS. During this phase we will evaluate alternatives to the IFRS 1 transitional exemptions available for use in preparing our opening IFRS balance sheet. One such exemption we expect to utilize is the amendment issued by the International Accounting Standards Board (IASB) in July 2009 respecting the determination of opening balances of property, plant and equipment. That amendment permits oil and gas companies currently using the full cost method of accounting 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. During this phase we will also evaluate the impact system and procedural changes will have on our disclosure controls and procedures and on our internal controls over financial reporting.
We continue to actively monitor changes to international accounting and reporting standards and have provided comments to the IASB on some of their recently proposed changes. In addition, we continue to follow the efforts of, and participate with, some peer companies in the IFRS transition process to coordinate our efforts with them and to ensure that our policies will be consistent with IFRSs adopted by other companies in our industry.
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.
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 continued into 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 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, liquidity and general economic 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 2009, the monthly average price for benchmark WTI crude oil ranged from a low of US$34.00/bbl to a high of US$145.00/bbl. During the same period, the natural gas AECO benchmark monthly average price ranged from a low of $1.96/Mcf to a high of $12.11/Mcf and the 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 U.S.:Canadian dollar exchange rate, thereby creating another element of uncertainty. Should the Canadian dollar strengthen compared to the U.S dollar, the resulting negative effect on revenue would be partially offset with exchange gains on translating our U.S. dollar denominated debt, associated interest payments thereon and translation of 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" above.
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 and our refinery is important to meet production targets.
We implemented planned maintenance shutdowns in 2008 and 2009 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 recent 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. We attempt to mitigate this 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, production/sales volumes and foreign exchange rates relative to U.S. dollar denominated debt. Significant volatility and declining commodity prices, together with severe economic uncertainty in the fourth quarter of 2008 and the first quarter of 2009 are the primary factors affecting financial results during those quarters. The magnitude of the changes in commodity prices during these periods was unprecedented.
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2008 2008 2008 2008
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Three Months Ended Mar 31 Jun 30 Sept 30 Dec 31
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($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 per share (0.01) 0.03 0.06 (0.21)
Diluted per share - - - -
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 287,105 234,110 200,177 197,914
Long-term debt 671,014 684,705 689,673 778,732
Shareholders' equity 471,559 479,477 496,509 469,087
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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 sales prices(4)
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 7.79 8.77 8.92 6.61
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Selected highlights - $/boe(3)
-------------------------------------------------------------------------
Weighted average sales price 56.44 65.25 66.41 21.73
Royalties 7.45 6.21 4.65 3.19
Operating costs 14.32 22.78 20.41 20.76
Cash operating netback(5) 34.67 36.26 41.35 (2.22)
Downstream: Refining
Crude charged - bbl/d 9,830 9,329 9,239 8,333
Refining utilization - % 104 98 97 88
Margins - % 1 (0.1) 2 (18)
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Common Share Information
-------------------------------------------------------------------------
Shares outstanding end
of period (000) 210,277 211,027 211,182 211,182
Weighted average shares
outstanding for the period
Basic (000) 210,234 210,658 211,093 211,182
Diluted (000) 210,234 214,530 213,174 211,575
Volume traded (000) 63,718 107,001 112,401 110,244
Common share price ($)
High 3.94 5.26 4.65 2.95
Low 2.59 3.10 2.63 0.60
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Close (end of period) 3.13 4.30 2.75 0.74
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2009 2009 2009 2009
-------------------------------------------------------------------------
Three Months Ended Mar 31 June 30 Sept 30 Dec 31
-------------------------------------------------------------------------
($000 except per share amounts)
-------------------------------------------------------------------------
Revenues, net of royalties 61,757 100,219 151,360 108,354
Cash flow(1) (4,692) 9,570 10,410 (2,766)
Basic, per share(1) (0.02) 0.04 0.03 (0.07)
Diluted, per share(1) (0.02) 0.03 0.03 (0.06)
Net earnings (loss) (46,844) 39,966 47,767 (14,731)
Basic per share (0.22) 0.15 0.12 (0.03)
Diluted per share - 0.14 0.11 -
Property and equipment additions 64,255 40,236 100,727 116,846
Cash on hand 96,220 401,160 333,634 256,787
Working capital surplus 120,035 455,001 347,139 245,067
Long-term debt 803,915 960,593 889,113 876,181
Shareholders' equity 428,276 622,235 658,336 671,588
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Operating Highlights
-------------------------------------------------------------------------
Upstream: Daily production/sales
volumes
Bitumen - bbl/d(2) 6,170 6,284 6,551 6,090
Crude oil - bbl/d 1,180 1,114 993 880
Natural gas - Mcf/d 12,828 12,144 10,377 10,319
Equivalent - boe/d(3) 9,488 9,421 9,274 8,690
Product sales prices(4)
Bitumen - $/bbl(2) 22.45 40.95 45.30 48.23
Crude oil - $/bbl 39.63 54.87 60.58 67.24
Natural gas - $/Mcf 4.89 3.35 2.91 4.34
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Selected highlights - $/boe(3)
-------------------------------------------------------------------------
Weighted average sales price 26.13 38.11 41.74 45.76
Royalties 3.02 1.90 2.13 2.45
Operating costs 17.73 13.98 15.43 20.61
Cash operating netback(5) 5.38 22.23 24.18 22.70
Downstream: Refining
Crude charged - bbl/d 6,867 9,145 7,076 8,188
Refining utilization - % 72 96 75 86
Margins - % 7 5 8 (7)
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Common Share Information
-------------------------------------------------------------------------
Shares outstanding end
of period (000) 211,291 403,546 403,567 427,031
Weighted average shares
outstanding for the period
Basic (000) 211,286 266,425 403,565 421,804
Diluted (000) 211,286 286,985 424,058 422,344
Volume traded (000) 67,387 249,700 129,206 207,978
Common share price ($)
High 1.00 1.66 1.15 1.33
Low 0.61 0.74 0.76 0.94
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Close (end of period) 0.74 0.92 1.10 1.28
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(1) Cash flow and cash flow per share do not have standardized meanings
prescribed by Canadian generally accepted accounting principles
("GAAP") and therefore may not be comparable to similar measures used
by other companies. Cash flow is calculated before changes in non-
cash working capital, pension funding and asset retirement
expenditures. The most comparable measure calculated in accordance
with GAAP would be net earnings. Cash flow is reconciled with net
earnings on the Consolidated Statement of Cash Flows and in the
applicable Management Discussion & Analysis ("MD&A") for the periods
referenced. 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) Product pricing excludes realized hedging gains/losses and excludes
unrealized mark-to-market non-cash accounting gains/losses.
(5) Netback is a non-GAAP measure used by management as a measure of
operating efficiency and profitability. Cash operating netback per
boe is calculated as bitumen, crude oil and natural gas revenue
before consideration of hedging gains/losses, less royalties and
operating costs divided by related production/sales volume. Netbacks
have been reconciled to net earnings in the applicable MD&A for the
periods referenced.
Consolidated Balance Sheets
As at December 31
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
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ASSETS
-------------------------------------------------------------------------
CURRENT
-------------------------------------------------------------------------
Cash $256,787 $223,663
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Accounts receivable 43,038 20,492
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Inventories (Note 5) 36,871 35,993
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Due from Petrolifera Petroleum Limited 29 42
-------------------------------------------------------------------------
Prepaid expenses 15,874 2,221
-------------------------------------------------------------------------
Income taxes recoverable 2,608 13,875
-------------------------------------------------------------------------
355,207 296,286
-------------------------------------------------------------------------
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Property, plant and equipment (Note 6) 1,230,256 985,054
-------------------------------------------------------------------------
Goodwill 103,676 103,676
-------------------------------------------------------------------------
Investment in Petrolifera Petroleum Limited
(Note 7) 50,379 46,659
-------------------------------------------------------------------------
$1,739,518 $1,431,675
-------------------------------------------------------------------------
-------------------------------------------------------------------------
-------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
-------------------------------------------------------------------------
CURRENT LIABILITIES
-------------------------------------------------------------------------
Accounts payable and accrued liabilities $105,620 $98,372
-------------------------------------------------------------------------
Risk management contracts (Note 14) 4,520 -
-------------------------------------------------------------------------
110,140 98,372
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Long term debt (Note 8) 876,181 778,732
-------------------------------------------------------------------------
Future income taxes (Note 9) 47,695 58,296
-------------------------------------------------------------------------
Asset retirement obligations (Note 10) 32,848 26,396
-------------------------------------------------------------------------
Employee future benefits (Note 11) 1,066 792
-------------------------------------------------------------------------
1,067,930 962,588
-------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Share capital (Note 12) 590,845 395,023
-------------------------------------------------------------------------
Equity component of convertible debentures (Note 8) 16,817 16,823
-------------------------------------------------------------------------
Contributed surplus (Note 13) 30,560 26,053
-------------------------------------------------------------------------
Retained earnings 49,544 23,386
-------------------------------------------------------------------------
Accumulated other comprehensive (loss) income (16,178) 7,802
-------------------------------------------------------------------------
671,588 469,087
-------------------------------------------------------------------------
$1,739,518 $1,431,675
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Commitments and contingencies (Note 19)
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The accompanying notes to the consolidated financial statements are an
integral part of these statements.
Approved by the Board:
Signed, Signed,
"C.M. Evans", Director "K.J. Ogle", Director
Consolidated Statements of Operations and Retained Earnings
Years Ended December 31
-------------------------------------------------------------------------
(Canadian dollar in thousands,
except per share amounts) 2009 2008
-------------------------------------------------------------------------
-------------------------------------------------------------------------
REVENUE
-------------------------------------------------------------------------
Upstream, net of royalties and crude oil
risk management contracts $166,834 $249,657
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Downstream 251,306 374,248
-------------------------------------------------------------------------
Interest and other income 3,550 5,434
-------------------------------------------------------------------------
421,690 629,339
-------------------------------------------------------------------------
EXPENSES
-------------------------------------------------------------------------
Upstream - diluent purchases and operating costs 110,079 156,284
-------------------------------------------------------------------------
Upstream transportation costs 12,355 14,499
-------------------------------------------------------------------------
Downstream - crude oil purchases and
operating costs (Note 5) 248,837 381,738
-------------------------------------------------------------------------
General and administrative 14,772 11,814
-------------------------------------------------------------------------
Finance charges (Note 8.4) 44,354 34,653
-------------------------------------------------------------------------
Stock-based compensation (Note 13) 4,562 4,575
-------------------------------------------------------------------------
Foreign exchange (gain) loss (106,164) 12,291
-------------------------------------------------------------------------
Depletion, depreciation and accretion 66,562 56,448
-------------------------------------------------------------------------
395,357 672,302
-------------------------------------------------------------------------
Earnings (loss) before income taxes and other items 26,333 (42,963)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Current income tax recovery (Note 9) 1,601 12,934
-------------------------------------------------------------------------
Future income tax (provision) recovery (Note 9) 5,704 (7,623)
-------------------------------------------------------------------------
7,305 5,311
-------------------------------------------------------------------------
Earnings (loss) before other items 33,638 (37,652)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Equity interest in Petrolifera Petroleum
Limited's (loss) earnings (Note 7) (2,468) 3,085
-------------------------------------------------------------------------
Dilution (loss) gain on Petrolifera
Petroleum Limited investment (Note 7) (5,012) 7,964
-------------------------------------------------------------------------
NET EARNINGS (LOSS) 26,158 (26,603)
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Retained earnings, beginning of year 23,386 49,989
-------------------------------------------------------------------------
Retained earnings, end of year $49,544 $23,386
-------------------------------------------------------------------------
-------------------------------------------------------------------------
EARNINGS (LOSS) PER SHARE (Note 18.1)
-------------------------------------------------------------------------
Basic and Diluted $0.08 $(0.13)
-------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.
Consolidated Statements of Comprehensive Income (Loss)
Years Ended December 31
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Net earnings (loss) $ 26,158 $(26,603)
-------------------------------------------------------------------------
Foreign currency translation adjustment (23,980) 21,438
-------------------------------------------------------------------------
Comprehensive income (loss) $ 2,178 $ (5,165)
-------------------------------------------------------------------------
Consolidated Statements of Accumulated Other Comprehensive Income (Loss)
Years Ended December 31
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Balance, beginning of year $ 7,802 $(13,636)
-------------------------------------------------------------------------
Foreign currency translation adjustment (23,980) 21,438
-------------------------------------------------------------------------
Balance, end of year $(16,178) $ 7,802
-------------------------------------------------------------------------
The accompanying notes to the consolidated financial statements are an
integral part of these statements.
Consolidated Statements of Cash Flow
Years Ended December 31
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Cash provided by (used in) the following activities:
-------------------------------------------------------------------------
OPERATING
-------------------------------------------------------------------------
Net earnings (loss) $ 26,158 $(26,603)
-------------------------------------------------------------------------
Items not involving cash:
-------------------------------------------------------------------------
Depletion, depreciation and accretion 66,562 56,448
-------------------------------------------------------------------------
Stock-based compensation (Note 13) 4,562 4,575
-------------------------------------------------------------------------
Financing charges 5,061 8,934
-------------------------------------------------------------------------
Defined benefit plan expense (Note 11) 651 730
-------------------------------------------------------------------------
Future income tax provision (recovery) (Note 9) (5,704) 7,623
-------------------------------------------------------------------------
Unrealized loss on risk management contracts 4,520 -
-------------------------------------------------------------------------
Gain on repurchase of Second Lien Senior Notes (2,271) (2,769)
-------------------------------------------------------------------------
Equity interest in Petrolifera
Petroleum Limited's loss (earnings) 2,468 (3,085)
-------------------------------------------------------------------------
Dilution (gain) loss on Petrolifera
Petroleum Limited investment 5,012 (7,964)
-------------------------------------------------------------------------
Unrealized foreign exchange (gain) loss (94,497) 122,342
-------------------------------------------------------------------------
Realized foreign exchange gains - (105,414)
-------------------------------------------------------------------------
Cash flow from operations before working
capital and other changes 12,522 54,817
-------------------------------------------------------------------------
Changes in non-cash working capital (Note 18) (17,300) (27,583)
-------------------------------------------------------------------------
Asset retirement expenditures (Note 10) (142) (209)
-------------------------------------------------------------------------
Contribution to defined benefit plan (Note 11) (234) -
-------------------------------------------------------------------------
(5,154) 27,025
-------------------------------------------------------------------------
FINANCING
-------------------------------------------------------------------------
Issue of common shares (Note 12) 203,098 761
-------------------------------------------------------------------------
Share issue costs (Note 12) (10,560) -
-------------------------------------------------------------------------
Issuance of First Lien Senior Notes (Note 8.1) 212,218 -
-------------------------------------------------------------------------
Issue costs of First Lien Senior Notes (Note 8.1) (7,503)
-------------------------------------------------------------------------
Repurchase of Second Lien Senior Notes (Note 8.2) (2,901) (6,262)
-------------------------------------------------------------------------
Deferred financing costs - (77)
-------------------------------------------------------------------------
Proceeds on unwinding of cross currency swap
(Note 14.2.3) - 97,600
-------------------------------------------------------------------------
394,352 92,022
-------------------------------------------------------------------------
INVESTING
-------------------------------------------------------------------------
Acquisition and development of property,
plant and equipment (313,894) (351,320)
-------------------------------------------------------------------------
Decrease in restricted cash - 72,113
-------------------------------------------------------------------------
Investment in Petrolifera Petroleum Limited
(Note 7) (12,029) -
-------------------------------------------------------------------------
Changes in non-cash working capital (Note 18) (14,948) 50,789
-------------------------------------------------------------------------
(340,871) (228,418)
-------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH 48,327 (109,371)
-------------------------------------------------------------------------
Foreign exchange (loss) gain on cash balances
held in foreign currency (15,203) 3,924
-------------------------------------------------------------------------
CASH, BEGINNING OF YEAR 223,663 329,110
-------------------------------------------------------------------------
CASH, END OF YEAR $256,787 $223,663
-------------------------------------------------------------------------
Supplementary information - Note 18
The accompanying notes to the consolidated financial statements are an
integral part of these statements.
Notes to the consolidated financial statements
Years ended December 31, 2009 and 2008
1. Nature of operations and organization
Connacher Oil and Gas Limited ("Connacher" or "the company") is a
publicly traded and integrated energy company headquartered in Calgary,
Alberta, Canada.
Management has segmented the company's business based on differences in
products and services and management responsibility. The company's
business is conducted predominantly through two major business segments -
upstream in Canada and downstream in USA, through its wholly owned
subsidiary, Montana Refining Company, Inc. ("MRCI").
Upstream includes exploration for, development and production of crude
oil, natural gas and bitumen. Downstream includes refining of primarily
crude oil to produce and market gasoline, jet fuel, diesel fuels, asphalt
and ancillary products.
The company also has an investment in Petrolifera Petroleum Limited
("Petrolifera") which has been accounted for on the equity basis.
Petrolifera is engaged in petroleum and natural gas exploration,
development and production activities in South America.
2. Significant Accounting Policies
2.1 Principles of consolidation and preparation of financial
statements
The consolidated financial statements are prepared in accordance with
Canadian generally accepted accounting principles ("Canadian GAAP") and
include the accounts of the company and its subsidiaries after the
elimination of intercompany balances and transactions. Some of the
company's upstream activities are conducted jointly with third parties
and accordingly these consolidated financial statements reflect the
company's proportionate share of these activities. All amounts are
presented in Canadian dollars unless otherwise specified.
2.2 Cash and cash equivalents
Cash and cash equivalents consist of cash on hand and short term deposits
with initial maturities of equal to or less than three months. There were
no short term deposits as at December 31, 2009 and 2008.
2.3 Inventories
Crude oil and refined product inventories are stated at the lower of cost
or net realizable value. Cost is determined following the weighted
average cost method. Net realizable value is determined using current
estimated selling prices. Cost consists of raw materials, labour, direct
overhead and transportation. Previous impairment write-downs are reversed
when there is a change in the situation that caused the impairment.
2.4 Property, plant and equipment
Oil sands, crude oil and natural gas properties, plant and equipment
("upstream")
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. Such costs include land acquisition, geological and geophysical
activity, drilling of productive and non-productive wells, carrying costs
directly related to unproved properties and administrative and interest
costs directly related to exploration and development activities.
Capitalized costs of oil sands, crude oil and natural gas properties,
plant 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). Costs subject to depletion and
depreciation include the estimated costs required to develop proved
reserves. Gains or losses on the disposition of oil and gas properties
are not recognized, unless the gain or loss changes the depletion rate by
20 percent or more.
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 the
property is determined to be impaired. Costs associated with major
development projects are excluded from costs subject to depletion and
depreciation until proved developed reserves have been attributed to a
portion of the property and commercial operations have commenced, or the
property is determined to be impaired.
Impairment losses are recognized when the carrying amount of a cost
centre exceeds the sum of:
- the undiscounted cash flow expected to result from production from
proved reserves based on forecast oil and gas prices and costs;
- the costs of unproved properties, less impairment; and
- the costs of major development projects, less impairment.
The amount of impairment loss is determined to be the amount by which the
carrying amount of the cost centre exceeds the sum of:
- the fair value of proved and probable reserves, calculated using a
present value technique that uses the cash flows expected to result
from production of the proved reserves and a portion of the probable
reserves, discounted using a risk free rate; and
- the cost, less impairment, of unproved properties and major
development projects that do not have reserves attributed to them.
During 2008, Pod One, the company's first oil sands project commenced
commercial production. From March 1, 2008, the company commenced
recognizing revenues and operating costs in the statement of operations
and the capitalized costs relating to Pod One were subject to depletion
and depreciation.
To date, all costs, including financing costs, incurred in relation to
the company's second oil sands project, Algar, 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 commence. Once
it is determined that commercial operations have been achieved, revenue
will be recognized and operating costs will be charged to the statement
of operations and the capitalized costs of the project will be added to
the full cost pool for depletion and ceiling test calculations.
Incidental revenues received prior to attaining commercial operations
were credited to the capitalized costs of the property, plant and
equipment.
Refining properties, plant and equipment ("downstream")
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.
Depreciation is provided using the straight-line method, based on
estimated useful lives of assets which range from three to sixteen years.
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". The required frequency of the
maintenance varies by asset type, but generally is every three to four
years. The costs of turnarounds are recorded as capital costs if they
meet the definition of a capital asset and are amortized on a straight-
line method over the period of the life of that capital asset. Normal
repairs and maintenance costs that do not meet the criteria for
recognition of an asset are charged to income when they arise.
Furniture, equipment and leaseholds
Furniture and equipment are recorded at cost and are depreciated on a
declining balance basis at rates of 20 percent to 30 percent per year.
Leaseholds are amortized over the lease term.
2.5 Investment in Petrolifera Petroleum Limited ("Petrolifera")
The investment in Petrolifera is accounted for on the equity basis,
whereby the carrying value reflects the company's initial cost of its
investment, the company's equity interest share of its accumulated income
and other comprehensive income and the dilution gains and losses
resulting from the issuance of additional shares by the investee. Any
permanent impairment in value would be charged to earnings.
2.6 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 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
is not more likely than not that the asset will be recovered.
2.7 Goodwill
Goodwill is the excess of purchase price over fair value of net assets
acquired in a business combination and is subject to impairment at least
on an annual basis, or more frequently, if there are indicators of
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 carrying value of the reporting unit. If the fair
value of the reporting unit is less than the carrying 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 carrying value of the reporting unit's
goodwill. Any excess of the carrying value of goodwill over the implied
fair value of goodwill is the impairment amount.
2.8 Asset retirement obligations
The company recognizes an asset retirement obligation for abandoning
petroleum, natural gas and bitumen wells, related facilities,
compressors and gas plants, removal of equipment from leased acreage and
for 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, depreciation and accretion 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 abandonment and reclamation expenditures are charged to the
accumulated obligation as incurred and costs for properties disposed are
removed.
2.9 Employee future benefits
MRCI has a defined benefit pension plan. 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.
2.10 Convertible debentures
On initial recognition, the convertible debentures were classified into
debt and equity components at fair value. The fair value of the liability
component was determined as the present value of the principal and
interest payments, discounted using the company's incremental borrowing
rate for debt with similar terms but without a conversion feature. 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 debentures. Subsequent to the initial recognition, the liability
component is remeasured at amortized cost using the effective interest
rate method. The equity component is not remeasured subsequent to initial
recognition.
2.11 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.
2.12 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 previously credited to contributed surplus, are
credited to share capital. Accrued compensation for an option that is
forfeited or expired unvested is adjusted to earnings by decreasing the
compensation cost in the period of forfeiture or expiry.
2.13 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.
2.14 Foreign currency translation
Monetary assets and liabilities denominated in foreign currency are
translated at the rate of exchange prevailing on the balance sheet date
and non-monetary assets and liabilities are translated using historical
rates of exchange. Gains or losses resulting from these translation
adjustments are included in statement of operations.
The accounts of self-sustaining foreign operations are translated to
Canadian dollars using the current rate method. Assets and liabilities
are translated at the period-end exchange rate and revenues and expenses
are translated at the average exchange rate for the period. Gains and
losses on the translation of self-sustaining foreign operations are
included in other comprehensive income (loss). MRCI's operations are
considered self-sustaining for the purposes of these consolidated
financial statements.
2.15 Financial instruments
Non-derivative financial instruments
Non-derivative financial instruments comprise cash, accounts receivable,
amount due from Petrolifera, accounts payable and accrued liabilities and
long-term debt. Non-derivative financial instruments are recognized
initially at fair value plus any directly attributable costs. Subsequent
to initial recognition, non-derivative financial instruments are
classified as follows with their respective subsequent measurement basis:
-------------------------------------------------------------------------
Subsequent
measurement
Non-derivative financial instrument Classification basis
-------------------------------------------------------------------------
Cash Held for trading Fair value
Accounts receivable Held for trading Fair value
Due from Petrolifera Held for trading Fair value
Accounts payable and
accrued liabilities Held for trading Fair value
Revolving credit facility Other liabilities Amortized cost.
Transaction costs
are amortized
over the term of
the facility.
Long-term debt (Convertible Other liabilities Amortized cost.
Debentures and First and Second Transaction
Lien Senior Notes) costs are
amortized using
the effective
interest rate
method.
-------------------------------------------------------------------------
Derivative financial instruments
The company enters into certain financial derivative contracts in order
to reduce its exposure to market risks from fluctuations in commodity
prices, foreign currency and interest rates. These instruments are not
used for speculative purposes. The company has not designated its
financial derivative contracts as effective accounting hedges and thus
has not applied hedge accounting. As a result, all financial derivative
contracts are classified as "held for trading" and recorded on the
balance sheet at fair value at each reporting date. Realized and
unrealized gains and losses on these contracts are recorded as a part of
revenue. Attributable transaction costs are recorded in the statement of
operations.
The company has accounted for its forward physical delivery sales
contracts, which were entered into and continued to be held for the
purpose of receipt or delivery of non-financial items in accordance with
its expected purchase, sale or usage requirements, as executory
contracts. As such, these contracts are not considered derivative
financial instruments and thus have not been recorded at fair value on
the consolidated balance sheet. Settlements of these physical sales
contracts are recognized in related revenues.
2.16 Joint interest activities
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.
2.17 Revenue recognition
Revenues from the sale of crude oil, natural gas, natural gas liquids,
bitumen, purchased commodities and refined petroleum products are
recorded when title passes to an external party and payment has either
been received or collection is reasonably certain. Sales between the
business segments of the company are eliminated from sales and operating
revenues and cost of sales.
Incidental revenues received prior to attaining commercial operations
were credited to the capitalized costs of the property, plant and
equipment.
2.18 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.
Specifically, amounts recorded for depletion, depreciation, amortization
of accretion expense, asset retirement obligations, fair value
measurements, employee future benefits, income taxes and amounts used in
impairment tests for goodwill, inventory and property, plant and
equipment are based on estimates. These estimates include petroleum and
natural gas reserves, future petroleum and natural gas prices, future
interest rates and future costs required to develop those reserves as
well as other fair value assumptions. By their nature, these estimates
are subject to measurement uncertainty and changes in such estimates in
future years could be material.
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 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.
2.19 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. Changes in Accounting Polices and Practices
Effective January 1, 2009, the company adopted the following new
accounting standards issued by the Canadian Institute of Chartered
Accountants (CICA).
3.1 Goodwill and intangible assets, CICA section 3064
The standard replaces the previous goodwill and intangible asset standard
and revises the requirements for recognition, measurement, presentation
and disclosure of intangible assets. The adoption of the standard has had
no material impact on the company's consolidated financial statements.
3.2 Emerging Issues Committee (EIC) - 173, Credit risk and the fair
value of financial assets and financial liabilities
The EIC requires that the company's own credit risk and the credit risk
of its counterparties be taken into account in determining the fair value
of a financial instrument. The EIC is to be applied retrospectively
without restatement of prior periods, to periods ending on or after
January 20, 2009. The adoption of the standard has had no material impact
on the company's consolidated financial statements.
3.3 Financial instruments - Disclosures, CICA section 3862
In June 2009, the existing section 3862 was amended to include additional
disclosure requirements about the fair value measurement of financial
instruments and to enhance liquidity risk disclosures. The standard
establishes a hierarchal disclosure framework associated with the level
of pricing observability utilized in measuring fair value. This framework
defines three levels of inputs to the fair value measurement process and
requires that each fair value measurement be assigned to a level
corresponding to the lowest level input that is significant to the fair
value measurement in its entirety. The three broad levels of inputs
defined by the CICA 3862 hierarchy are as follows:
- Level 1 Inputs - quoted prices (unadjusted) in active markets for
identical assets or liabilities that the reporting entity has the
ability to access at the measurement date;
- Level 2 Inputs - inputs other than quoted prices included within
Level 1 that are observable for the asset or liability, either
directly (i.e. as prices) or indirectly (i.e. derived from prices);
and
- Level 3 Inputs - inputs for the asset or liability that are not based
on observable market data (unobservable inputs). These unobservable
inputs reflect the entity's own assumptions about the assumptions
that market participants would use in pricing the asset or liability
and are developed based on the best information available in the
circumstances (which might include the reporting entity's own data).
The standard allows these disclosures to be provided on a prospective
basis. The company has provided the additional disclosures in note 14 to
these consolidated financial statements.
4. Recent Accounting Pronouncements
4.1 Business combinations, CICA section 1582, consolidated
financial statements, CICA section 1601 and non-controlling
Interests, CICA section 1602:
These new standards were issued in January 2009 to be effective for
fiscal years beginning on or after January 1, 2011 with early adoption
permitted. Under Section 1582, changes in the determination of the fair
value of the assets and liabilities of the acquiree will result in a
different calculation of goodwill. Such changes include the expensing of
acquisition-related costs incurred during a business combination, as
opposed to capitalizing these costs as a part of the cost of the
acquisition. Additionally, under the new standard, accruals for
restructuring charges may not be recorded. This new standard will be
applied prospectively to business combinations for acquisitions on or
after January 1, 2011. Section 1601 establishes standards for the
preparation of consolidated financial statements. Section 1602
establishes standards for accounting for a non-controlling interest in a
subsidiary in consolidated financial statements subsequent to a business
combination. Under Sections 1601 and 1602, non-controlling interests will
be presented as a component of equity, rather than as a liability on the
consolidated balance sheet. Also, net income and components of other
comprehensive income attributable to the owners of the parent and to the
non-controlling interests are required to be separately disclosed on the
income statement. The company is currently assessing the impact of the
adoption of section 1582. The adoption of Sections 1601 and 1602 are not
expected to have a material impact on the company's consolidated
financial statements.
4.2 International Financial Reporting Standards ("IFRS"):
In October 2009, CICA confirmed that publicly accountable enterprises in
Canada will be required to apply IFRS beginning January 1, 2011. The
company's expected IFRS transition date of January 1, 2011 will require
the restatement, for comparative purposes, of amounts reported by the
company for its year ended December 31, 2010 and of the opening balance
sheet as at January 1, 2010. In July 2009, CICA Handbook Section 1506,
Accounting Changes, was modified such that it does not apply to changes
in accounting policies upon the complete replacement of an entity's
primary basis of accounting. The requirement for all publicly accountable
enterprises in Canada to apply IFRS beginning January 1, 2011 represents
a complete replacement of the company's primary basis of accounting and
accordingly, Section 1506 does not apply to the adoption of IFRS. The
company is continuing to assess the financial reporting impacts of
adopting IFRS. The impact of adopting IFRS on the company's consolidated
financial statements is not determinable at this time.
5. Inventories
Inventories at December 31 consisted of the following:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Crude oil $ 9,613 $ 3,433
Other raw materials and unfinished products
(Note 5.1) 3,843 1,762
Refined products (Note 5.2) 18,185 18,901
Process chemicals (Note 5.3) 1,606 8,110
Repairs and maintenance supplies and other
(Note 5.4) 3,624 3,787
-------------------------------------------------------------------------
$ 36,871 $ 35,993
-------------------------------------------------------------------------
5.1
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.
5.2
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.
5.3
Process chemicals include catalysts, additives and other chemicals. The
inventory carrying value includes the cost of the purchased chemicals and
related freight.
5.4
Repair and maintenance supplies are for refining and oil sands
operations.
Inventory valuation impairment previously recorded was reversed in the
amount of $9 million in 2009 and credited to "Downstream-Crude Oil
Purchases and Operating Costs" in the Consolidated Statement of
Operations; in 2008, an impairment charge of $9 million was recorded, as
net realizable values were lower than cost. Included in statement of
operations under "Downstream-Crude Oil Purchases and Operating Costs" in
2009 was $216 million of inventory costs. (2008 - $350 million).
6. Property, Plant and Equipment
-------------------------------------------------------------------------
Accumulated
Depletion,
Depreciation
and Amorti- Net Book
(Canadian dollar in thousands) Cost zation Value
-------------------------------------------------------------------------
2009
-------------------------------------------------------------------------
Oil sands, crude oil and natural
gas properties, plant and equipment $1,303,276 $167,538 $1,135,738
Refining property, plant and equipment 105,789 18,075 87,714
Furniture, equipment and leaseholds 12,272 5,468 6,804
-------------------------------------------------------------------------
$1,421,337 $191,081 $1,230,256
-------------------------------------------------------------------------
-------------------------------------------------------------------------
Accumulated
Depletion,
Depreciation
and Amorti- Net Book
(Canadian dollar in thousands) Cost zation Value
-------------------------------------------------------------------------
2008
-------------------------------------------------------------------------
Oil sands, crude oil and natural gas
properties, plant and equipment $1,004,891 $112,013 $892,878
Refining property, plant and equipment 99,823 13,620 86,203
Furniture, equipment and leaseholds 9,999 4,026 5,973
-------------------------------------------------------------------------
$1,114,713 $129,659 $985,054
-------------------------------------------------------------------------
In 2009, the company capitalized $5.0 million (2008 - $5.2 million) of
general and administrative expenses, $1.1 million (2008 - $1.5 million)
of stock-based compensation costs and $52.4 million (2008 -
$47.1 million) of interest and financing costs related to oil sands and
conventional petroleum and natural gas activities.
Costs relating to unproved properties totaling $12.6 million (2008 -
$14.2 million) and major project development totaling $554.6 million
(2008 - $297.0 million) were excluded from costs subject to depletion and
depreciation. Future development costs of approximately $1.4 billion
(2008 - $1.3 billion) were included in costs subject to depletion.
Connacher's oil sands, crude and natural gas reserves were evaluated by
qualified independent evaluators as at December 31, 2009 using the
following base price assumptions. Based on these assumptions, the company
completed a ceiling test of its oil sands, crude oil and natural gas
properties and equipment and determined no impairment was required for
the fiscal year 2009 and 2008.
-------------------------------------------------------------------------
Bitumen Alberta
Wellhead WTI @ Spot
Current Cushing (CDN$/
(CDN$/bbl) (US$/bbl) mmbtu)
-------------------------------------------------------------------------
2010 $ 51.50 $ 80.00 $ 5.96
2011 53.01 83.00 6.79
2012 54.36 86.00 6.89
2013 57.03 89.00 6.95
2014 60.77 92.00 7.05
2015 62.14 93.84 7.16
2016 63.53 95.72 7.42
2017 64.96 97.64 7.95
2018 66.41 99.59 8.52
2019 67.89 101.58 8.69
2020+ +2.0%/yr +2.0%/yr +2.0%/yr
-------------------------------------------------------------------------
7. Investment in Petrolifera Petroleum Limited ("Petrolifera")
Changes to the investment in Petrolifera are as follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Balance, beginning of year $ 46,659 $ 35,610
Acquisition of units 12,029 -
Equity interest in earnings (loss) and other
comprehensive income (loss) (3,297) 3,085
Dilution (loss) gain on additional issue of shares (5,012) 7,964
-------------------------------------------------------------------------
Balance, end of year $ 50,379 $ 46,659
-------------------------------------------------------------------------
In 2009, Petrolifera issued 66.5 million units from treasury to raise
$58 million. Each unit was comprised of one Petrolifera common share and
one-half Petrolifera share purchase warrant. Each full Petrolifera share
purchase warrant entitles the holder to purchase one Petrolifera common
share at a price of $1.20 per common share for a period of two years from
issuance. Connacher subscribed for 13,556,000 units. In addition, in
2009, Connacher exercised its options to purchase an additional 200,000
Petrolifera common shares at $0.50 per common share.
In 2008, Petrolifera issued 4.4 million common shares to raise
$40 million. Connacher did not subscribe for any of these shares.
The above transactions resulted in a dilution loss of $5.0 million in
2009 and a dilution gain of $8 million in 2008.
As at December 31, 2009, Connacher owned 26.9 million Petrolifera common
shares, representing 22 percent of Petrolifera's issued and outstanding
common shares and 6.8 million Petrolifera share purchase warrants.
In consideration for the assistance provided in 2005 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, 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 company'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 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 2009 (2008 - $180,000) under the Administrative Services
Agreement.
8. Long-Term Debt
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
First Lien Senior Notes (Note 8.1) $191,509 $ -
Second Lien Senior Notes (Note 8.2) 596,184 694,086
Convertible Debentures (Note 8.3) 88,488 84,646
-------------------------------------------------------------------------
Long-term debt $876,181 $778,732
-------------------------------------------------------------------------
8.1 First Lien Senior Notes
On June 16, 2009, the company issued US$200 million of First Lien Senior
Notes at an issue price of 93.678 percent for net proceeds of
US$187.4 million (CAD $212.2 million). Transaction costs of approximately
$7.5 million were capitalized within the long-term loan and are being
accreted up to the face value using the effective interest rate method.
The First Lien Senior Notes bear interest at 11.75 percent payable semi-
annually on January 15 and July 15. No principal payments are due until
the maturity date of July 15, 2014. The First Lien Senior Notes are
secured on a first priority basis (subject to specific liens up to
US$50 million for the Revolving Credit Facility) by liens on all of the
company's assets, excluding certain pipeline assets in the USA and the
company's investment in Petrolifera.
The company may redeem some or all of the First Lien Senior Notes at
their principal amount, plus a make whole premium, if such redemption
occurs prior to July 15, 2011. The company may redeem up to 35 percent of
the First Lien Senior Notes prior to July 15, 2011 at a redemption price
of 111.75 percent of the principal amount, plus accrued interest, with
the proceeds of certain equity offerings, provided that at least 65
percent of the aggregate principal amount of the First Lien Senior Notes
remains outstanding on existing terms. After July 15, 2011, the First
Lien Senior Notes may be redeemed at redemption prices ranging from
105.875 percent, reducing to 100 percent on July 15, 2013 and thereafter.
Upon a change of control of the company, the holders of the First Lien
Senior Notes may require Connacher to purchase the First Lien Senior
Notes at redemption prices noted above, with a minimum price of 101
percent of the principal amount to be repurchased.
Interest on the First Lien Senior Notes is being capitalized to the Algar
project during its construction.
8.2 Second Lien Senior Notes
On December 3, 2007, the company issued US$600 million of Second Lien
Senior Notes at an issue price of 98.657 percent, for gross proceeds of
US$591.9 million. The Second Lien Senior Notes bear interest at a rate of
10.25 percent percent, 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
all of the company's assets, with the exception of certain pipeline
assets in the USA and the company's 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. The company may redeem up to 35
percent 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 percent of the aggregate principal amount of the Second Lien
Senior Notes remains outstanding on existing terms. 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. During 2009, the company repurchased a total of
US $4.7 million (CAD $5.1 million) (2008 - US$8 million; CAD $9 million)
face value of Second Lien Senior Notes in the market at a discount and
cancelled the notes.
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.
A portion of the interest on the Second Lien Senior Notes attributed to
Pod One, has been expensed since the commencement of its commercial
operations (March 1, 2008). Interest on that portion of the Second Lien
Senior Notes which was used to fund the construction of Algar continues
to be capitalized during its construction phase.
8.3 Convertible Debentures
On May 25, 2007 Connacher issued subordinated unsecured Convertible
Debentures with a face value of $100,050,000. The Convertible Debentures
mature on June 30, 2012, unless converted prior to that date and bear
interest at an annual rate of 4.75 percent, payable semi-annually on
June 30 and December 31 while outstanding. 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 on 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.
As at the date of issuance, 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 is accreted up to the face value over the five-year term of the
Convertible Debentures. Accretion and interest expense are recorded as
finance charges in the consolidated statement of operations. Upon
conversion, the value of the conversion feature will be reclassified to
share capital, along with the principal amounts converted.
In June 2009, $36,000 principal amount of Convertible Debentures were
converted into 7,200 common shares and no gain or loss was recorded. A
portion of each of the liability and equity components of the debentures,
together with the principal amount, were transferred to share capital as
follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands)
-------------------------------------------------------------------------
Balance, December 31, 2007 and 2008 $ 16,823
-------------------------------------------------------------------------
Conversion of Debentures (6)
-------------------------------------------------------------------------
Equity Component, December 31, 2009 $ 16,817
-------------------------------------------------------------------------
8.4 Revolving Credit Facility
In November 2009, the company secured a US$50 million revolving credit
facility (the "Facility") from a syndicate of Canadian and international
banks. The facility has a two year tenure and ranks ahead of the
company's First and Second Lien Senior Notes. It is secured by a first
lien charge on all of the company's assets, excluding certain pipeline
assets in the USA and the company's investment holdings in Petrolifera.
The Facility bears interest at the lenders' Canadian prime rate, a U.S.
base rate, a Bankers' Acceptances rate, or at a LIBOR rate plus
applicable margins. Transaction costs amounting to $1.7 million were
recorded as a part of prepaid expenses and are being amortized to expense
over the term of the Facility. The Facility contains certain covenants
that if not met, give the lender the ability to cancel the Facility. As
of December 31, 2009, the company was in compliance with these covenants.
At December 31, 2009, $7.6 million of letters of credit were issued
pursuant to the Facility.
Finance charges include interest and other costs of $2.2 million (2008 -
$6.8 million) representing standby fees, bank charges and amortization of
transaction costs relating to the Facility.
8.5 Principal Repayments Due
Principal repayments for all the aforementioned loans are due as follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
2010 - 2011 $ - $ -
2012 100,014 100,050
2013 - -
2014 210,200 -
2015 617,294 721,056
-------------------------------------------------------------------------
Total $927,508 $821,106
-------------------------------------------------------------------------
9. Income Taxes
The provision for income taxes in the consolidated statement of
operations reflects an effective tax rate which differs from the expected
statutory tax rate. Differences for the years ended December 31 were
accounted for as follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Earnings (loss) before income taxes and after equity
interest $ 18,853 $(31,914)
-------------------------------------------------------------------------
Canadian statutory rate 29.1% 29.8%
-------------------------------------------------------------------------
Expected income tax (expense) recovery (5,486) 9,510
-------------------------------------------------------------------------
Impact of reduction in Canadian tax rates and other (1,329) (1,846)
-------------------------------------------------------------------------
Foreign taxes 756 2,130
-------------------------------------------------------------------------
Capital taxes (402) (1,535)
-------------------------------------------------------------------------
Non taxable portion of foreign exchange losses
(gains) 16,302 (3,233)
-------------------------------------------------------------------------
Equity interest in Petrolifera earnings (loss) and
dilution gain (loss) (1,210) 1,644
-------------------------------------------------------------------------
Non deductible stock-based compensation costs (1,326) (1,359)
-------------------------------------------------------------------------
Recovery of income taxes $ 7,305 $ 5,311
-------------------------------------------------------------------------
The future income tax assets and liabilities as at December 31 comprised
the tax effect to the temporary differences as follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Future income tax liabilities (asset)
-------------------------------------------------------------------------
Property, plant and equipment $129,201 $101,008
-------------------------------------------------------------------------
Deferred capital costs 2,340 231
-------------------------------------------------------------------------
Investment in Petrolifera 3,109 4,153
-------------------------------------------------------------------------
Non-capital losses carried forward (87,976) (23,055)
-------------------------------------------------------------------------
Foreign exchange loss (gain) on debt 3,472 (11,224)
-------------------------------------------------------------------------
Financing and share issue costs (7,871) (7,125)
-------------------------------------------------------------------------
Asset retirement obligation (8,238) (6,620)
-------------------------------------------------------------------------
Capital losses carried forward (8,560) (10,482)
-------------------------------------------------------------------------
Other (1,935) (617)
-------------------------------------------------------------------------
Valuation allowance 24,153 12,027
-------------------------------------------------------------------------
Net future income tax liability $ 47,695 $ 58,296
-------------------------------------------------------------------------
The approximate amount of total income tax pools available as at
December 31, 2009 were $1,075 million in Canada and $53 million in the
USA (2008 - $750 million in Canada and $39 million in the USA), including
non-capital losses of approximately $327 million which expire over time
to 2028 and $34 million of net capital losses which are available to
reduce taxable 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, 2009.
10. 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:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Balance, beginning of year $ 26,396 $ 24,365
-------------------------------------------------------------------------
Liabilities incurred 6,194 1,496
Liabilities settled (142) (209)
Change in estimated future cash flows (1,803) (960)
Accretion expense 2,203 1,704
-------------------------------------------------------------------------
Balance, end of year $ 32,848 $ 26,396
-------------------------------------------------------------------------
At December 31, 2009, the estimated total undiscounted amount required to
settle the asset retirement obligations was $72.0 million (2008 -
$47.3 million). These obligations are expected to be settled over the
period of 20 to 25 years into the future. This amount has been discounted
using credit-adjusted risk-free rates of interest ranging between 6
percent to 10 percent, depending on year the obligation was incurred, and
after provision for inflation at 2 percent per annum.
The company has not recorded an asset retirement obligation for the
Refining property, plant and equipment 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.
11. 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 USA based employees and a defined contribution
savings plan for its Canadian employees.
11.1 Defined benefit pension plan for USA employees
The company's USA 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 defined benefit 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.
The status of the Defined Benefit Obligation at December 31 was as
follows:
Defined Benefit Plan Obligation
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Defined benefit plan obligation, beginning of year $ 1,470 $ 617
Current service cost 623 723
Interest cost 97 62
Actuarial gain (755) (52)
Benefits paid (13) (63)
Foreign exchange (gain) loss (197) 183
-------------------------------------------------------------------------
Defined benefit plan obligation, end of year $ 1,225 $ 1,470
-------------------------------------------------------------------------
Defined Benefit Plan Assets
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Fair value of defined benefit plan assets, beginning
of year $ 640 $ 757
Actual return on plan assets 141 (192)
Employer contributions 234 -
Benefits paid (13) (63)
Foreign exchange gain (loss) (121) 138
-------------------------------------------------------------------------
Fair value of defined benefit plan assets, end of
year $ 881 $ 640
-------------------------------------------------------------------------
Funded Status of the Defined Benefit Plan
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Defined benefit plan obligation, end of year $ 1,225 $ 1,470
Fair value of defined benefit plan assets, end
of year (881) (640)
Excess defined benefit obligation 344 830
Unamortized net actuarial gain (loss) 722 (38)
-------------------------------------------------------------------------
Accrued defined benefit obligation $ 1,066 $ 792
-------------------------------------------------------------------------
The weighted average assumptions used to determine benefit
obligations and periodic expense are as follows:
-------------------------------------------------------------------------
(percent) 2009 2008
-------------------------------------------------------------------------
Discount rate 7.9 5.7
-------------------------------------------------------------------------
Expected long-term rate of return on plan assets 9.8 7.0
-------------------------------------------------------------------------
Long-term rate of increase in compensation level 3.0 3.0
-------------------------------------------------------------------------
The expense for the years ended December 31 were as follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Current service cost $ 623 $ 723
-------------------------------------------------------------------------
Interest cost 97 62
-------------------------------------------------------------------------
Actual return on defined benefit plan assets (141) 192
-------------------------------------------------------------------------
Difference between expected and actual return 72 (247)
-------------------------------------------------------------------------
Net defined benefit plan expense $ 651 $ 730
-------------------------------------------------------------------------
The company amortizes the portion of the unrecognized actuarial gains or
losses that exceed 10 percent of the greater of the accrued benefit
obligation or fair value of benefit plan assets. The gains or losses that
are in excess of 10 percent are amortized over the expected future years
of service which was 15.6 years as at December 31, 2009 (December 31,
2008 - 14.5 years).
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. 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 the plan's 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
investments, credit rating categories and foreign currency exposures. The
composition of the Defined Benefit Plan was as follows:
-------------------------------------------------------------------------
(percent) 2009 2008
-------------------------------------------------------------------------
Equity securities 58 59
Debt securities 38 37
Cash 4 4
Total 100 100
-------------------------------------------------------------------------
11.2 Defined contribution savings plan for USA 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
2009, MRCI contributed $400,000 which was recorded to "Downstream - crude
oil purchases and operating costs" (2008 - $343,000) to this plan to
satisfy, in full, its obligation under this plan.
11.3 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 2009, the
company contributed $839,000, which was recorded to general and
administrative expenses (2008 - $739,000) to this plan to satisfy, in
full, its obligation under this plan.
12. Share Capital
Authorized Unlimited number of common voting shares
Unlimited number of first preferred shares of which none were outstanding
Unlimited number of second preferred shares of which none were
outstanding
12.1 Issued and outstanding common share capital
-------------------------------------------------------------------------
Amount
(Canadian
Number of dollar in
shares thousands)
-------------------------------------------------------------------------
Balance, December 31, 2007 209,971,257 $406,881
-------------------------------------------------------------------------
Shares issued upon exercise of stock options
(Note 13) 1,101,583 893
-------------------------------------------------------------------------
Shares issued to directors as compensation
(Note 13.3) 108,975 381
-------------------------------------------------------------------------
Assigned value of stock options exercised
(Note 13.1) 250
-------------------------------------------------------------------------
Tax effect of flow-through shares (Note 12.4) (13,250)
-------------------------------------------------------------------------
Share issue costs, net of future income tax (132)
-------------------------------------------------------------------------
Balance, December 31, 2008 211,181,815 395,023
-------------------------------------------------------------------------
Issued for cash (Note 12.2) 191,762,500 172,586
-------------------------------------------------------------------------
Issued for cash on flow-through basis
(Note 12.3) 23,172,500 30,124
-------------------------------------------------------------------------
Shares issued upon exercise of stock options
(Note 13) 579,724 388
-------------------------------------------------------------------------
Shares issued to directors as compensation
(Note 13.3) 327,623 302
-------------------------------------------------------------------------
Assigned value of stock options exercised
(Note 13.1) 183
-------------------------------------------------------------------------
Conversion of debentures (Note 8.3) 7,200 36
-------------------------------------------------------------------------
Share issue costs, net of future income tax (7,797)
-------------------------------------------------------------------------
Balance, December 31, 2009 427,031,362 $590,845
-------------------------------------------------------------------------
12.2
In June 2009, the company issued 191,762,500 common shares at $0.90 per
common share for gross proceeds of $172.6 million.
12.3
In October 2009, the company issued 23,172,500 common shares on a flow-
through basis at $1.30 per common share for gross proceeds of
$30.1 million and renounced the qualifying expenditures to investors
effective December 31, 2009. The related future income tax liability will
be recorded in fiscal 2010.
12.4
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 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.
13. Contributed surplus, Stock options and Share award plan for
non-employee Directors
13.1 Contributed surplus
The following table shows the changes in contributed surplus during
the years ended December 31:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Balance, beginning of year $ 26,053 $ 20,382
Stock based compensation for stock options 4,690 5,921
Assigned value of stock options exercised (183) (250)
-------------------------------------------------------------------------
Balance, end of year $ 30,560 $ 26,053
-------------------------------------------------------------------------
13.2 Stock options
The company has a stock option plan permitting the issue from time to
time of options entitling the holders to acquire common shares up to an
aggregate of 10 percent of the number of common shares outstanding.
Options are granted at the discretion of the board on such terms as the
board may determine. The options have a term of five years to maturity
and vest over the period of two to three years. The following table shows
the changes in stock options during the years ended December 31, and the
related weighted average exercise price:
-------------------------------------------------------------------------
2009 2008
-------------------------------------------------------------------------
Weighted Weighted
Average Average
Number of Exercise Number of Exercise
Options Price Options Price
-------------------------------------------------------------------------
Outstanding, beginning
of year 16,383,104 $ 3.16 17,432,717 $ 3.60
Granted 12,318,375 $ 0.96 6,226,846 $ 2.29
Exercised (579,724) $ 0.67 (1,101,583) $ 0.81
Forfeited (945,710) $ 1.97 (516,129) $ 3.93
Exchanged/expired (4,597,000) $ 4.89 (5,658,747) $ 3.93
-------------------------------------------------------------------------
Outstanding, end of year 22,579,045 $ 1.72 16,383,104 $ 3.16
-------------------------------------------------------------------------
Exercisable, end of year 12,689,028 $ 2.18 12,423,317 $ 3.14
-------------------------------------------------------------------------
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
2008, stock-based compensation of $675,000 was recognized (i.e. expensed
or capitalized) in relation to the options exchanged.
The following table summarizes stock options outstanding and exercisable
under the plan at December 31:
-------------------------------------------------------------------------
2009 2008
-------------------------------------------------------------------------
Weighted Weighted
Weighted Average Weighted Average
Range of Number Average Remaining Number Average Remaining
Exercise Out- Exercise Contract- Out- Exercise Contract-
Prices standing Price ual Life standing Price ual Life
-------------------------------------------------------------------------
$0.20 -
$0.99 5,089,267 $ 0.76 3.8 997,034 $ 0.77 1.1
$1.00 -
$1.99 11,399,047 $ 1.19 4.1 4,563,623 $ 1.34 3.7
$2.00 -
$3.99 5,133,222 $ 3.30 1.9 5,377,938 $ 3.31 2.9
$4.00 -
$5.99 957,509 $ 4.68 1.5 5,444,509 $ 4.98 2.3
-------------------------------------------------------------------------
22,579,045 $ 1.72 3.4 16,383,104 $ 3.16 2.8
-------------------------------------------------------------------------
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model using the following
weighted average assumptions for grants as follows:
-------------------------------------------------------------------------
2009 2008
-------------------------------------------------------------------------
Risk free interest rate (percent) 1.3 2.5
Expected option life (years) 3.0 3.0
Expected volatility (percent) 72 54
-------------------------------------------------------------------------
The weighted average fair value was $0.46 per option for the stock
options granted in 2009 (2008 - $0.81 per option).
13.3 Share award plan for non-employee directors
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 Toronto Stock Exchange or by issuing common
shares from treasury, subject to certain limitations. The Board of
Directors may alternatively 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 common shares.
-------------------------------------------------------------------------
(Number of common shares) 2009 2008
-------------------------------------------------------------------------
Outstanding, beginning of year 392,705 217,950
Granted 638,496 283,730
Vested and Issued (327,623) (108,975)
Cancelled (54,662) -
-------------------------------------------------------------------------
Outstanding, end of year 648,916 392,705
-------------------------------------------------------------------------
Exercisable, end of year 10,420 5,210
-------------------------------------------------------------------------
Outstanding units of 648,916 under the plan as at December 31, 2009 fully
vest on January 1, 2010 and 638,496 common shares were issued in early
2010. In 2009, $967,000 (2008 - $125,000) was accrued as a liability and
expense in respect of outstanding shares under the share award plan.
14. Financial Instruments
Connacher's financial instruments include its cash, accounts receivable,
amounts due from Petrolifera, accounts payable and accrued liabilities,
risk management contracts and long-term debt (Convertible Debentures and
First and Second Lien Senior Notes).
14.1 Fair value measurements for financial instruments
Fair value estimates are made at a specific point in time, based on
relevant market information and information about the financial
instrument. These estimates cannot be determined with precision as they
are subjective in nature and involve uncertainties and matters of
judgment. The following table shows the comparison of the carrying and
fair values of the company's financial instruments as at December 31,
2009:
-------------------------------------------------------------------------
Financial instrument (Canadian dollar in
thousands) Carrying Value Fair Value
-------------------------------------------------------------------------
Held for trading
-------------------------------------------------------------------------
Cash (Note 14.1(a)) $256,787 $256,787
-------------------------------------------------------------------------
Accounts receivable (Note 14.1(a)) 43,038 43,038
-------------------------------------------------------------------------
Due from Petrolifera (Note 14.1(a)) 29 29
-------------------------------------------------------------------------
Accounts payable and accrued liabilities
(Note 14.1(a)) 105,620 105,620
-------------------------------------------------------------------------
Risk management contracts (Note 14.1(b)) 4,520 4,520
-------------------------------------------------------------------------
Other liabilities
-------------------------------------------------------------------------
First Senior Notes (Note 14.1(c)) 191,509 232,000
-------------------------------------------------------------------------
Second Senior Notes (Note 14.1(c)) 596,184 568,000
-------------------------------------------------------------------------
Convertible Debentures (Note 14.1(c)) $ 88,488 $ 92,000
-------------------------------------------------------------------------
a) Fair value of cash is determined based on transaction value and is
categorized as Level 1 measurement. Fair values of accounts
receivable, due from Petrolifera and accounts payable and accrued
liabilities are determined from transaction values which were
derived from observable market inputs. Fair values of these
financial instruments are based on LeveI 2 measurements.
b) The risk management contracts are recorded on the consolidated
balance sheet at their fair value. Accordingly, there is no
difference between fair value and carrying value. The fair values
of the risk management contracts are determined using forward
prices and incorporate adjustments for quality and location. These
values are derived in part using active quotes and in part using
observable market-corroborated data. The fair values of risk
management contracts were based on Level 2 measurements.
c) Carrying value is measured at amortized cost using the effective
interest rate method. The fair values are based on quoted market
prices as at December 31, 2009, which are categorized as a Level 1
measurement for disclosure purposes. The face value of the First
Senior Lien Notes is US$ 200 million ($210 million), Second Senior
Lien Notes is US$ 587 million ($617.3 million) and convertible
debt is $100 million (unless converted before maturity).
14.2 Risk exposure
The company is exposed to market risks related to the volatility of
commodity prices, foreign exchange rates and interest rates. In certain
instances, the company uses derivative instruments to manage the
company's exposure to these risks. The company is also exposed, to a
lesser extent, to credit risk on accounts receivable and counterparties
to price risk management contracts and to liquidity risk relating to
debt. The company employs risk management strategies and policies to
ensure that any exposures to risk are in compliance with the company's
business objectives and risk tolerance levels. Risk management is
ultimately established by the company's Board of Directors and is
implemented and monitored by senior management of the company.
14.2.1 Credit risk
Credit risk is the risk that the contracting entity will not fulfill its
obligations under a contract when they are due. The company generally
extends unsecured credit to customers and therefore, the collection of
accounts receivable may be affected by changes in economic or other
conditions. Management believes this risk is mitigated by the size and
creditworthiness 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.
Upstream and downstream accounts receivable
Accounts receivable are due from crude oil and natural gas purchasers and
joint venture partners in the petroleum and natural gas industry and are
subject to normal industry credit risks. The company periodically
assesses the financial strength of its crude oil and natural gas
purchasers and will adjust its marketing plan to mitigate credit risks.
This assessment involves a review of external credit ratings and an
internal credit review based on the purchaser's past financial
performance. Generally, the only instances of impairment are when a
purchaser or partner is facing bankruptcy or extreme financial distress.
Sales made to three upstream customers represented 90 percent of the
total upstream sales in 2009 (two customers represented 65 percent in
2008). Sales made to one downstream customer represented 10 percent of
the total downstream sales in 2009 and 2008. One upstream customer
represented 12 percent of the upstream accounts receivable as at
December 31, 2009. Three downstream customers comprised 38 percent of the
downstream account receivable balances as at December 31, 2009.
Risk Management Contract Counterparties
The company is also exposed to credit risk from the counterparties to
risk management contracts. This risk is managed by limiting
counterparties to investment grade banking institutions; there is no
history of impairment with these counterparties.
The company considers all amounts due above 90 days as past due. The
company does not have any material past due accounts as at December 31,
2009 and 2008. The maximum exposure to credit risk relating to the above
classes of financial assets at December 31, 2009 is the carrying value of
accounts receivable.
14.2.2 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,
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 First or Second Lien Senior Notes until their maturity
dates of July 15, 2014 and December 15, 2015, respectively. 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 also has a revolving credit facility of US$50 million, as
more fully described in note 8.4, which further gives Connacher
additional liquidity in providing finance for its working capital
requirements.
Connacher owns 26.9 million common shares and 6.8 million share purchase
warrants of Petrolifera. The common shares and share purchase warrants
are publicly traded on the Toronto Stock Exchange and, subject to certain
limitations, potentially provide additional liquidity as they have not
been collateralized. Although it is not Connacher's intention to sell its
investment in Petrolifera in the foreseeable future, this investment
provides Connacher a margin of financial flexibility.
The following table shows the maturities of Connacher's financial
liabilities:
-------------------------------------------------------------------------
(Canadian dollar in thousands) Within 1 year 1-3 years 4-5 years
-------------------------------------------------------------------------
Non-derivative liabilities:
-------------------------------------------------------------------------
Accounts payable and accrued
liabilities $105,620 $ - $ -
-------------------------------------------------------------------------
Long-term debt(i) 92,722 371,054 964,582
-------------------------------------------------------------------------
Derivative-based liabilities:
-------------------------------------------------------------------------
Risk management contracts $ 4,520 $ - $ -
-------------------------------------------------------------------------
i) The amounts represent face value of the principal amounts
due and are equal to the Canadian equivalent amounts as at
December 31, 2009 in the case of US$ denominated loans.
These amounts also include future interest payments.
14.2.3 Market risk and sensitivity analysis
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.
Market risk is comprised of foreign currency risk, interest rate risk and
other price risk, for example, commodity price risk. The objective of
market risk management is to manage and control market price exposures
within acceptable limits, while maximizing returns.
Commodity price risk
The company is exposed to commodity price risk as a result of potential
changes in the market prices of its crude oil, bitumen, natural gas and
refined product sales volumes and the purchase price for diluent.
A portion of this risk is mitigated by Connacher's integrated business
model. The cost of purchasing natural gas for use in its Pod One and
refinery operations is offset by the company's conventional natural gas
sales. The selling price and volume of the company's current Pod One
dilbit sales largely equates to the purchase price and volumes of heavy
crude oil required for processing at its refinery. In accordance with
policies approved by the Board of Directors, derivative financial
contracts, including petroleum commodity futures contracts, price swaps
and collars may be utilized to reduce exposure to price fluctuations
associated with a portion of the sales of natural gas, crude oil or
bitumen sales volumes and for the sale of refined products.
A summary of the risk management contracts outstanding as at December 31,
2009 are presented below: (Nil - December 31, 2008):
-------------------------------------------------------------------------
Fair value
as at
December 31,
2009
(Canadian
dollar in
Volume Term Type Price thousands)
-------------------------------------------------------------------------
2,500 bbl/d Jan 1 - Dec 31, 2010 Swap WTI U.S. $78/bbl $ 4,115
-------------------------------------------------------------------------
2,500 bbl/d Feb 1 - Apr 30, 2010 Swap WTI U.S. $79.02/bbl 405
-------------------------------------------------------------------------
Total $ 4,520
-------------------------------------------------------------------------
Subsequent to the year ended December 31, 2009, the company entered into
the following risk management contracts:
-------------------------------------------------------------------------
Volume Term Type Price
-------------------------------------------------------------------------
2,500 bbl/d May 1 - Dec 31, 2010 Call option WTI U.S. $95/bbl
-------------------------------------------------------------------------
2,500 bbl/d May 1 - Dec 31, 2010 Put option WTI U.S. $75/bbl
-------------------------------------------------------------------------
As at December 31, 2009, had the forward price been US$1/bbl lower for
WTI, the impact to earnings before tax would have been $1.1 million
higher. Had the forward price been US$1/bbl higher, the impact to
earnings before tax would have been $1.1 million lower.
Interest rate risk
Interest rate risk refers to the risk that the future cash flows of a
financial instrument will fluctuate because of changes in market interest
rates. The company's First and Second Lien Senior Notes and Convertible
Debentures have fixed interest rate obligations and, therefore, are not
subject to changes in interest rates. The Revolving Credit Facility bears
variable interest rate. Once the amounts are drawn on the Facility, the
future cash flows will fluctuate because of change in future market
interest rates.
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. The company is exposed to the risk of changes in the U.S.
dollar exchange rate on its U.S. dollar denominated revenues and for
Canadian dollar revenues that are based on a U.S. dollar commodity price.
In addition, the company's First and Second Senior Lien Notes are
denominated in U.S. dollars and interest on these notes is payable
semiannually in U.S. dollars. Accordingly, the principal and any interest
payable at the balance sheet date are also subject to currency exchange
rate risk. The company is also exposed to currency exchange rate risk on
its net investment in downstream operations, which is a self sustaining
subsidiary that uses a U.S. dollar functional currency. The company
manages these exchange rate risks by occasionally entering into fixed
rate currency exchange contracts on future U.S. dollar payments and U.S.
dollar sales receipts.
In 2008, Connacher entered into a foreign exchange revenue collar which
set a floor of CAD$1.1925 per US$1.00 and a ceiling of CAD$1.30 per US
$1.00 on a notional amount of US$10 million of production revenue per
month throughout 2009. For 2009, a realized foreign exchange gain of
$8.0 million was included in the net foreign exchange gains in the
consolidated statement of operations in respect of this contract.
In 2008, the company mitigated half of the foreign exchange exposure on
its Second Lien Senior Notes by entering 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 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.
The impact on net earnings of the translation of monetary financial
instruments denominated in U.S. dollars including the effect of the
exchange variance between U.S. dollars and Canadian dollars with respect
to oil prices would be as follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands) Impact on Net Earnings
-------------------------------------------------------------------------
Canadian Dollar weakens by $0.01 ($4,875)
-------------------------------------------------------------------------
Canadian Dollar strengthen by $0.01 $4,875
-------------------------------------------------------------------------
The company's downstream operations operate with a U.S. dollar functional
currency, which gives rise to currency exchange rate risk on translation
of MRCI's operations. The impact is recorded in other comprehensive
income. The impact on other comprehensive income due to the fluctuation
in U.S. and Canadian dollar exchange would be as follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands) Impact on Other comprehensive income
-------------------------------------------------------------------------
Canadian Dollar weakens by $0.01 $48
-------------------------------------------------------------------------
Canadian Dollar strengthen by $0.01 ($48)
-------------------------------------------------------------------------
15. Capital Risk Management
The company is exposed to financial risks on its financial instruments
and 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. Connacher continues to structure is capital in the same way
as it was last year. These risks affecting the company are discussed
below.
Connacher's objectives in managing its cash, debt and equity 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 or opportunity
arises and to optimize its use of 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 financial covenants.
Connacher's current capital structure and certain financial ratios are
noted below:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Long term debt(1) $876,181 $778,732
-------------------------------------------------------------------------
Shareholders' equity 671,588 469,087
-------------------------------------------------------------------------
Total debt plus equity ("book capitalization") $1,547,769 $1,247,819
-------------------------------------------------------------------------
Debt to book capitalization(2) 57% 62%
-------------------------------------------------------------------------
Debt to market capitalization(3) 62% 81%
-------------------------------------------------------------------------
(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 in part due to
pre-funding of the full cost of Algar, the company's second oil sands
project. As at December 31, 2009, the company's net debt (long-term debt,
net of cash on hand) was $619.4 million, its net debt to book
capitalization was 40 percent and its net debt to market capitalization
was 44 percent.
16. Related Party Transactions
In 2009 the company paid professional legal fees of $1.3 million (2008 -
$1.1 million) 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. As at December 31, 2009, accounts payable to the law firm was
approximately $71,000 (2008 - $103,000).
A portion of the company's conventional crude oil and natural gas
exploration and drilling activities, was conducted in an industry-
standard joint venture arrangement with a company, a former officer of
which is also a director of Connacher. Transactions with the joint
venture partner company 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. In March 2010 this director resigned from
the joint venture partner company but remains a director of Connacher.
17. Segmented Information
The company has two business segments. In Canada, the company is in the
business of exploring for and producing crude oil, natural gas and
bitumen. In USA, the company is in the business of refining and marketing
petroleum products. The significant information of these operating
segments are presented below:
-------------------------------------------------------------------------
(Canadian dollar in
thousands) Canada USA
-------------------------------------------------------------------------
Inter-
segment
Elimi-
2009 Oil and Gas Refining nation(1) Total
-------------------------------------------------------------------------
Net revenues $ 166,834 $ 258,400 $ 7,094 $ 418,140
-------------------------------------------------------------------------
Equity interest in
Petrolifera loss (2,468) - - (2,468)
-------------------------------------------------------------------------
Dilution loss on
investment in
Petrolifera (5,012) - - (5,012)
-------------------------------------------------------------------------
Interest and other
income 2,950 600 - 3,550
-------------------------------------------------------------------------
Finance charges 43,979 375 - 44,354
-------------------------------------------------------------------------
Depletion, depreciation
and accretion 59,171 7,391 - 66,562
-------------------------------------------------------------------------
Income tax recovery (4,062) (3,243) - (7,305)
-------------------------------------------------------------------------
Net earnings (loss) 29,406 (3,248) - 26,158
-------------------------------------------------------------------------
Property and equipment,
net 1,142,542 87,714 - 1,230,256
-------------------------------------------------------------------------
Goodwill 103,676 - - 103,676
-------------------------------------------------------------------------
Capital expenditures 301,244 20,820 - 322,064
-------------------------------------------------------------------------
Total assets $1,590,243 $ 149,275 $ - $1,739,518
-------------------------------------------------------------------------
-------------------------------------------------------------------------
(Canadian dollar in
thousands) Canada USA
-------------------------------------------------------------------------
Inter-
segment
Elimi-
2008 Oil and Gas Refining nation(1) Total
-------------------------------------------------------------------------
Net revenues $ 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
-------------------------------------------------------------------------
Income tax provision
(recovery) 1,330 (6,641) - (5,311)
-------------------------------------------------------------------------
Net 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
-------------------------------------------------------------------------
(1) Intersegment transactions are eliminated on consolidation.
18. Supplementary Information
18.1 Per share amounts
The following table summarizes the common shares used in per share
calculations for the years ended December 31:
-------------------------------------------------------------------------
(000) 2009 2008
-------------------------------------------------------------------------
Weighted average common shares outstanding 326,560 210,794
-------------------------------------------------------------------------
Dilutive effect of stock options and share units
under the non-employee Directors share award plan 507 -
-------------------------------------------------------------------------
Weighted average common shares outstanding - diluted 327,067 210,794
-------------------------------------------------------------------------
Outstanding options as at December 31, 2009 of 22.6 million (2008 -
16.3 million) and 20 million common shares as at December 31, 2009 (2008
- 20 million) issuable on conversion of convertible debentures were
excluded from the diluted earnings per share calculation as the effect of
including them would be anti-dilutive.
18.2 Net change in non-cash working capital
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Accounts receivable $(25,145) $ 4,274
Inventories (8,530) (17,614)
Due from Petrolifera 13 (42)
Prepaid expenses (16,427) 299
Accounts payable and accrued liabilities 8,644 45,885
Income taxes recoverable 9,197 (9,596)
-------------------------------------------------------------------------
Total $(32,248) $ 23,206
-------------------------------------------------------------------------
Summary of working capital changes:
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Operations $(17,300) $(27,583)
Investing (14,948) 50,789
-------------------------------------------------------------------------
Total $(32,248) $ 23,206
-------------------------------------------------------------------------
18.3 Supplementary cash flow information
-------------------------------------------------------------------------
(Canadian dollar in thousands) 2009 2008
-------------------------------------------------------------------------
Interest paid $ 71,999 $ 78,506
-------------------------------------------------------------------------
Income taxes paid $ 1,621 $ 1,650
-------------------------------------------------------------------------
19. Commitments and Contingencies
The company's annual commitments under leases for office premises and
operating costs, electrical transmission and distribution facilities for
Algar, software license agreements and other equipment are as follows:
-------------------------------------------------------------------------
(Canadian dollar in thousands)
-------------------------------------------------------------------------
2010 $ 6,427
2011 4,970
2012 4,651
2013 4,623
2014 4,617
2015 4,611
Thereafter 42,501
-------------------------------------------------------------------------
Total $ 72,400
-------------------------------------------------------------------------
For further information: R. A. Gusella, President and Chief Executive Officer, Or Grant D. Ukrainetz, Vice President, Corporate Development, Phone (403) 538-6201, Fax (403) 538-6225, [email protected], www.connacheroil.com
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