CALGARY, Alberta--()--Cenovus Energy Inc. (TSX, NYSE: CVE):
“We have top quality reservoirs, experienced and knowledgeable staff, a track record of being a low cost operator and a commitment to continuously advance our technologies and reduce our environmental impact”
- Production from the Foster Creek and Christina Lake oil sands projects increased 42% in the second quarter of 2010 compared with the same period in 2009.
- Cenovus’s established conventional oil and gas properties generated about $400 million of operating cash flow in excess of capital expenditures in the second quarter.
- Second quarter cash flow remained strong and in line with company guidance, despite weaker realized natural gas prices and lower downstream operating cash flow.
- The Board approved a 10 year business plan detailing how the company expects to achieve oil sands production of 300,000 barrels per day (bbls/d) by the end of 2019, a five-fold increase from current production.
- An application was submitted to Alberta Environment and the Energy Resources Conservation Board (ERCB) for the Narrows Lake oil sands project. The ERCB approved a Grand Rapids pilot in the Greater Pelican Region.
“Our second quarter has delivered strong operational and financial results,” said Brian Ferguson, President & Chief Executive Officer of Cenovus. “We are on track to meet guidance targets we’ve established for production and cash flow for the year. We continue to take steps that are expected to lead to a doubling of the company’s net asset value within the next five years.
“We have top quality reservoirs, experienced and knowledgeable staff, a track record of being a low cost operator and a commitment to continuously advance our technologies and reduce our environmental impact,” Ferguson said. “These elements, combined with reliable cash flow from our conventional oil and gas assets and a solid dividend, are expected to deliver strong total shareholder return over the long term.”
| Financial & Production Summary1 | |||||||||||||||
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(for the period ended June 30) (C$ millions, except per share amounts) |
2010
Q2 |
2009
Q2 |
% change |
2010
6 months |
2009
6 months |
% change | |||||||||
|
Cash flow2 |
537 | 945 |
-43 |
1,258 | 1,686 |
-25 |
|||||||||
| Per share diluted | 0.71 | 1.26 |
|
1.67 | 2.25 |
|
|||||||||
|
Operating earnings2 |
142 | 512 |
-72 |
495 | 926 |
-47 |
|||||||||
| Per share diluted | 0.19 | 0.68 |
|
0.66 | 1.23 |
|
|||||||||
| Capital investment | 430 | 488 | -12 | 923 | 1,140 | -19 | |||||||||
| Production (before royalties) | |||||||||||||||
| Foster Creek (bbls/d) | 51,010 | 34,729 | 47 | 51,067 | 31,658 | 61 | |||||||||
| Christina Lake (bbls/d) | 7,716 | 6,530 | 18 | 7,569 | 6,582 | 15 | |||||||||
| Foster Creek & Christina Lake Total (bbls/d) | 58,726 | 41,259 | 42 | 58,636 | 38,240 | 53 | |||||||||
| Other Oil and NGLs (bbls/d) | 69,840 | 76,010 | -8 | 70,915 | 77,434 | -8 | |||||||||
| Natural gas (MMcf/d) | 751 | 856 | -12 | 762 | 861 | -11 | |||||||||
1 Effective Jan. 1, 2010, Cenovus changed its reporting currency to Canadian dollars and started presenting production volumes on a before royalties basis.
2 Cash flow and operating earnings are non-GAAP measures as defined in the Advisory. See also the Earnings Reconciliation Summary on page 9.
Cenovus Energy Inc. (TSX, NYSE: CVE) continued to deliver strong production growth from its oil sands operations with a 42% production increase at Foster Creek and Christina Lake in the second quarter of 2010 compared with the same period last year. Operating performance exceeded the company’s expectations with production ahead of guidance and the company’s operating and capital expenditures below what was anticipated for half way through the year.
Cenovus’s conventional oil and natural gas properties remain a reliable source of cash flow with solid returns from modest capital expenditures. In the second quarter, these established assets delivered about $400 million of operating cash flow above the capital invested in them.
Overall cash flow for the second quarter was $537 million, in line with the company’s guidance although $408 million less compared with the same period last year. This 43% decrease was due to weaker realized natural gas prices, higher oil sands royalties and lower downstream operating cash flow.
Cenovus's realized natural gas price in the second quarter of 2010 was $5.00 per thousand cubic feet (Mcf) compared with $8.13/Mcf in the second quarter of 2009. That resulted from a $182 million lower realized after-tax hedging gain in the second quarter of 2010 compared to the same period in 2009. Expected declines in natural gas production also had an impact on cash flow, as did higher royalty payments at Foster Creek due to the operation reaching payout in February. In the second quarter of 2010, Foster Creek royalties, net to Cenovus, were $45 million compared with $2 million in the same period of 2009.
Downstream operating cash flow was $202 million lower in the second quarter of 2010 compared with the same period of 2009. Approximately $180 million of that decrease is attributed to additional crude costs determined using first in, first out inventory valuation method. The refineries also experienced lower crude utilization in the second quarter of 2010 due to planned turnarounds and refinery optimization, which resulted in an estimated $25 million of reduced cash flow compared to the same period of 2009.
Cenovus is already one of the lowest cost oil sands producers and the company further improved in the second quarter of 2010 with non-fuel operating costs for Foster Creek and Christina Lake decreasing 14% to less than $9.00/bbl compared with the same period last year. The company’s focus on innovation is expected to reduce those costs even more over time as new technologies lead to improved efficiency and reduced expenses.
“Our focus at Cenovus is on developing the tremendous oil resource in our portfolio,” Ferguson said. “This was an exciting second quarter as we announced our 10 year business plan and set measurable goals to achieve it. We’re now taking action with regulatory applications for emerging projects, increased assessment drilling on undeveloped lands and efforts to advance timelines for expansions of existing oil operations. These steps are expected to help us achieve oil sands production of 300,000 barrels per day net to Cenovus by the end of 2019.”
Next major project submitted for regulatory approval
An application for Cenovus’s Narrows Lake project was submitted to the ERCB and Alberta Environment at the end of the second quarter. Narrows Lake is near the company’s Christina Lake operation, about 160 kilometres southeast of Fort McMurray. It is jointly owned with ConocoPhillips and is expected to be developed in two or three phases with a gross production capacity of 130,000 bbls/d and an anticipated project life of 30 years.
Narrows Lake is the first commercial oil sands project application that includes the potential to use solvent aided process (SAP) along with steam assisted gravity drainage (SAGD). SAP involves the injection into the reservoir of a solvent, such as butane, along with the steam. This process increases production, improves ultimate recovery potential and lowers operating costs by reducing the amount of steam needed for each barrel of oil produced. Less steam means less natural gas is needed, which results in fewer emissions per barrel of oil as well as reduced water and land use. If the approval process proceeds as anticipated, Narrows Lake could begin producing oil in 2016.
Plans to expand production in the Greater Pelican Region
Cenovus is taking steps to increase production from its 100% owned property in the Greater Pelican Region, about 300 kilometres north of Edmonton. The company is anticipating eventual production from three separate geological formations in the region.
The existing polymer flood operation is producing more than 23,000 bbls/d of oil from the Wabiskaw formation, which is at depths of between 300 and 400 metres. Cenovus expects to increase production from this formation to 35,000 bbls/d by 2014 with moderate capital investment for additional in-fill wells and expansion of the polymer flood.
Cenovus is evaluating the best method to access oil from the Grand Rapids formation, located above the Wabiskaw formation at depths of between 220 and 270 metres. During the second quarter, ERCB approval was received to proceed with a single well pair SAGD pilot in the Grand Rapids. The test is expected to begin by the end of 2010, pending approval from Alberta Environment. A regulatory application for a commercial SAGD operation is expected to be filed by the end of 2011. The Grand Rapids project has a potential production capacity of 180,000 bbls/d. If the test and regulatory process proceed as planned, the Grand Rapids project could begin production in 2017.
A third formation, the Grosmont, is located below the Grand Rapids and Wabiskaw at depths ranging from 300 to 600 metres below ground. The Grosmont is a carbonate formation and Cenovus is assessing which production method would best enable development of this large resource before initiating a pilot.
Assessment work moving ahead on undeveloped lands
Cenovus is following through with its plan to further assess the company’s undeveloped oil sands assets with a stratigraphic well drilling program of 400 to 500 wells in each of the next five years. These assessment wells will provide reservoir data to support the next phases of development at the current operations and contribute to the regulatory review process for emerging projects. So far in 2010, Cenovus has drilled more than 200 stratigraphic wells, including those on land jointly held with ConocoPhillips. About 40 more stratigraphic wells are planned for later this year. Continued assessment work will help move a greater percentage of Cenovus’s 137 billion barrels of total bitumen initially-in-place into the discovered sub-category. An independent assessment of the company’s oil sands assets during the second quarter showed 56 billion barrels of discovered bitumen initially-in-place at the end of 2009.
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IMPORTANT NOTE: Effective Jan. 1, 2010, Cenovus changed its reporting currency to Canadian dollars and started presenting production volumes on a before royalties basis, to better reflect its business and to enhance comparability to its peers. All numbers are net to Cenovus unless otherwise stated. See the Advisory for a description of the non-GAAP measures and oil and gas definitions used in this news release. |
Oil Sands Operations
|
(Before royalties) (Mbbls/d) |
Daily Production | ||||||||||||||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||||
| YTD | Q2 | Q1 | Full Year | Q4 | Q3 | Q2 | Q1 | Full Year | |||||||||||||||||||||||||||||||
| Foster Creek | 51 | 51 |
51 |
38 | 47 | 40 | 35 | 29 | 26 | ||||||||||||||||||||||||||||||
| Christina Lake | 8 | 8 | 7 | 7 | 7 | 6 | 7 | 7 | 4 | ||||||||||||||||||||||||||||||
| Total1 | 59 | 59 | 59 | 44 | 54 | 47 | 41 | 35 | 30 | ||||||||||||||||||||||||||||||
1 Totals may not add due to rounding.
Foster Creek and Christina Lake
Cenovus’s oil sands properties in northern Alberta represent the company’s most significant opportunity for substantial near term growth. Cenovus’s producing oil sands projects, Foster Creek and Christina Lake, use specialized methods, such as SAGD, to drill and pump the oil to the surface. The projects are operated by Cenovus and jointly owned with ConocoPhillips. Cenovus continues to advance technologies in its oil sands operations that reduce the amount of water, natural gas and electricity used and minimize land disturbance.
Production
- Foster Creek produced more than 51,000 bbls/d in the second quarter of 2010, up from nearly 35,000 bbls/d during the same period last year – a 47% increase. The production growth is mainly attributed to the continued ramp up of phases D and E, which began production late in the first quarter of 2009, combined with increased production from wedge wells and well optimization. About 14% of current production at Foster Creek comes from wedge wells. These horizontal wells are drilled between existing SAGD well pairs. They reach oil that would have otherwise been stranded, which improves recovery rates by about 10% with minimal or no additional steam required. Thirteen new wedge wells are planned for Foster Creek in the second half of 2010, in addition to the 36 drilled to date, of which 31 are producing. One wedge well is now operating at Christina Lake and two more are planned for 2010.
- Production at Christina Lake increased by 18% to nearly 8,000 bbls/d in the second quarter compared with the same period in 2009. This is primarily a result of the ramp up of production from the phase B expansion in addition to well and operations optimization.
Expansions
- Construction is progressing as planned on Christina Lake phases C and D, which will each add 40,000 bbls/d of gross production capacity.
- The regulatory process is underway for Christina Lake phases E, F and G with approval anticipated in 2011.
- Phases F, G and H at Foster Creek continue to move through the regulatory process and approval is anticipated later this year.
- The next expansions at Foster Creek (phase F) and Christina Lake (phase E) are expected to proceed by as much as a year earlier than initially planned pending timely regulatory and partner approvals. First production at both phases is now anticipated in 2014.
Costs
- Operating costs at Foster Creek and Christina Lake averaged $11.17/bbl in the second quarter of 2010, an 8% decline from $12.11/bbl in the second quarter of 2009, mainly due to higher production volumes and lower workovers, repairs and maintenance.
- Non-fuel operating costs for Foster Creek and Christina Lake were $8.98/bbl in the second quarter of 2010 compared with $10.48/bbl in the second quarter of 2009, a 14% decrease.
- As a result of Foster Creek reaching payout for royalty purposes in February, its average royalty rate increased to 19% in the second quarter of 2010 compared with 1.5% in the second quarter of 2009. This meant that second quarter royalties, net to Cenovus, were $45 million in 2010 compared with $2 million in 2009.
- Cenovus continues to achieve one of the best steam to oil ratios (SOR) in the industry with a combined SOR of less than 2.3 at Christina Lake and Foster Creek in the second quarter. This means 2.3 barrels of steam are needed for every barrel of oil produced. A lower SOR means less natural gas is burned to create the steam, which results in fewer emissions, lower water usage and reduced costs.
Future Projects
- A joint regulatory application for the Narrows Lake project, co-owned with ConocoPhillips, was filed with the ERCB and Alberta Environment at the end of the second quarter. The application is the first to include the option of using a combination of SAGD and SAP for oil production. Narrows Lake is expected to have gross production capacity of 130,000 bbls/d. The target date for first production is 2016.
- Cenovus received ERCB approval in June for a pilot to determine whether the Grand Rapids formation can be commercially produced using SAGD. This pilot falls under the company’s existing Pelican Lake operating license and is 100% owned by Cenovus. The company anticipates Alberta Environment approval of the pilot this summer.
- Additional information is being collected to support the regulatory application that was previously filed for the Telephone Lake project in the Borealis Region.
Downstream
Cenovus’s downstream operations include the Wood River refinery in Illinois and the Borger refinery in Texas, which are jointly owned with the operator, ConocoPhillips. In addition to the 25,000 bbls/d gross coking capacity at Borger, 65,000 bbls/d gross coking capacity is being added at Wood River with the coker and refinery expansion (CORE) project to increase the total gross coking capacity at Wood River to 83,000 bbls/d. The CORE project was about 82% complete at the end of the second quarter and the total cost is expected to be within 10% of the US$3.6 billion budget (US$1.8 billion net to Cenovus). The project remains on track for a mid-2011 start up. It is anticipated this project will improve operating cash flow at Wood River by about US$200 million a year (net to Cenovus). With completion of the CORE project, Cenovus’s two refineries will have an increased ability to process a variety of crude feedstocks and produce a larger percentage of high value clean products. These refineries will have a combined capacity to process as much as 275,000 bbls/d of heavy crude oil.
- In the second quarter of 2010, the two refineries produced 398,000 bbls/d of refined products, down about 7% compared with the second quarter of 2009.
- Refinery crude utilization averaged 84% or 379,000 bbls/d of crude throughput, about 6% lower than in the same period a year ago, due to scheduled turnaround activity and refinery optimization.
- Operating cash flow for downstream operations in the second quarter of 2010 was a deficiency of $24 million, which was $202 million lower than the second quarter of 2009 mainly due to higher purchased product costs for crude oil using first in, first out inventory valuation method, as well as lower crude utilization.
- The Keystone pipeline began deliveries from Alberta to Illinois at the end of the second quarter, allowing the Wood River refinery to source significant additional volumes of Canadian heavy crude oil.
Conventional Oil, Natural Gas Liquids (NGLs) and Natural Gas
|
(Before royalties) |
Daily Production | ||||||||||||||||||||||||||||||||||||||
| 2010 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||||
| YTD | Q2 | Q1 | Full Year | Q4 | Q3 | Q2 | Q1 | Full Year | |||||||||||||||||||||||||||||||
|
Conventional Oil & NGLs1 (Mbbls/d) |
71 | 70 | 72 | 77 | 75 | 80 | 76 | 79 | 82 | ||||||||||||||||||||||||||||||
| Natural Gas (MMcf/d) | 762 | 751 | 775 | 837 | 797 | 830 | 856 | 866 | 954 | ||||||||||||||||||||||||||||||
1 Includes production from Cenovus’s Senlac asset, sold in the fourth quarter of 2009, and other non-core assets, sold in the second quarter of 2010.
Cenovus has a large base of conventional oil and natural gas properties across Alberta and Saskatchewan. The oil operations include Pelican Lake (Wabiskaw formation) and Weyburn as well as production in southern Alberta and Saskatchewan. Cenovus’s natural gas properties in Alberta are established, reliable fields with efficient operations. The conventional assets are an important component of the company’s financial foundation, generating operating cash flow well in excess of their ongoing capital investment requirements. The natural gas business also acts as a hedge against price fluctuations, because natural gas fuels the company’s oil sands and refining operations.
- Conventional oil production was about 70,000 bbls/d in the second quarter of 2010, in line with the company’s guidance. This was an 8% decrease compared with the same period last year, primarily as a result of expected natural declines and the sale of some properties, partially offset by new production in southern Alberta and southwestern Saskatchewan.
- The Lower Shaunavon oil asset in Saskatchewan is an early stage development opportunity for Cenovus. Production averaged about 460 bbls/d from nine wells during the second quarter, which was lower than expected due to weather related production restrictions. The company has commenced an additional 21 well drilling program in this area.
- The company has close to 200 prospective sections in the Bakken region of southern Saskatchewan. Development is in the early stages and Cenovus is currently evaluating the performance of a number of horizontal wells and expects to make decisions about drilling plans in the next few months.
- Operating costs for Cenovus’s conventional oil and liquids operations increased 30% to $12.80/bbl in the second quarter of 2010 compared with the same period last year, mainly due to a higher level of workover, repair and maintenance activity deferred from 2009 due to the economic uncertainty last year, increased chemical usage, higher electricity rates, as well as lower oil production. These operating costs remain within the company’s guidance range.
- Natural gas production was in line with guidance at 751 MMcf/d, a 12% decrease in the second quarter of 2010 compared with the same period in 2009. This is due to expected natural declines, weather delays and decreased production as Cenovus chose to postpone some drilling and tie-in work in 2009 in response to lower prices.
- Cenovus plans to manage declines in natural gas production, targeting a long term production level of between 400 and 500 MMcf/d to match our anticipated internal usage.
Financial
Dividend
The Cenovus Board of Directors declared a third quarter dividend of $0.20 per share, payable on September 30, 2010, to common shareholders of record as of September 15, 2010. Based on the July 28, 2010, closing share price on the Toronto Stock Exchange of $29.97, this represents an annualized yield of about 2.7%. Declaration of dividends is at the sole discretion of the Board. Earlier this year, the Board approved a dividend reinvestment plan, which was made available to shareholders for the second quarter 2010 dividend. More information is available at www.cenovus.com.
Hedging Strategy
The risk management strategy helps Cenovus to achieve more predictability around cash flow and safeguard its capital program. The strategy allows Cenovus to hedge up to 75% of the next year’s expected natural gas production, net of internal fuel use, and up to 50% and 25%, respectively, in the following two years. The strategy allows for fixed price hedges of as much as 50% of net liquids production in the next year and 25% of net liquids production for each of the following two years.
Cenovus’s hedging position at June 30, 2010, comprises:
- 444 MMcf/d, or approximately 68% of expected 2010 net gas production, hedged at an average NYMEX price of US$6.12/Mcf
- 29,100 bbls/d, or approximately 23% of expected 2010 oil production, hedged at an average WTI price of US$78.91/bbl and an additional 5,000 bbls/d, or approximately 4% of expected 2010 oil production, hedged at an average WTI price of C$89.65/bbl
- 5,000 bbls/d of 2011 oil production hedged at an average WTI price of US$90.98/bbl and an additional 6,000 bbls/d hedged at an average WTI price of C$92.77/bbl
- 351 MMcf/d of natural gas hedged for 2011 at an average NYMEX price of US$5.82/Mcf
- 60 MMcf/d of natural gas hedged for 2012 at an average NYMEX price of US$6.49/Mcf
Cenovus’s realized after-tax hedging gains for the second quarter of 2010 were $64 million, down from $250 million in the second quarter of 2009, due to weaker 2010 natural gas average hedge prices.
In addition to financial hedges, Cenovus benefits from a natural hedge with its gas production. About 100 MMcf/d of natural gas is consumed at the company’s SAGD and refinery operations, which is offset by the natural gas Cenovus produces. This natural hedge is considered when determining the company’s financial hedging limits.
Financial Highlights
- Cash flow for the second quarter of 2010 was $537 million, down 43% from the same period in 2009, largely due to lower realized hedging gains and decreased downstream operating cash flow.
- Free cash flow was $107 million for the second quarter of 2010, $350 million lower than in the second quarter of 2009.
- Operating earnings were $142 million, or $0.19 per share, down 72% from the same period a year ago, reflecting the effects of decreased realized hedging gains and lower natural gas production, as well as increased crude oil purchased product costs, turnarounds and optimizations at the refineries. Cenovus’s management views operating earnings, a non-GAAP measure defined in the Advisory, as a better measure of performance than net earnings because non-operating unrealized gains and losses are removed from operating earnings.
- Cenovus’s net earnings in the second quarter were $172 million, slightly higher than the same quarter in 2009. Net earnings were impacted by an unrealized mark-to-market after-tax gain of $16 million, compared with an after-tax loss of $214 million in the second quarter of 2009, and an unrealized after-tax foreign exchange gain of $14 million, compared with an after-tax loss of $138 million in the second quarter of last year.
- Cenovus received an average realized price, including hedging, of $59.11/bbl for its oil, almost the same price as during the second quarter of last year. The average realized price, including hedging, for natural gas was $5.00/Mcf, 38% less than the second quarter of 2009, which had substantially higher hedging gains.
- Capital investment during the quarter was $430 million, a decrease of 12% compared with the second quarter of 2009, primarily due to poor weather that restricted access to Cenovus's lands in southern Alberta and reduced downstream capital spending related to the CORE project. The downstream decrease was partially offset by increased spending on the Christina Lake expansion.
- Cenovus sold assets for proceeds of $72 million in the second quarter for a year-to-date divestiture total of $144 million. The company maintains a royalty interest in some of those properties. In addition, Cenovus recently signed a purchase and sale agreement providing for the disposition of certain non-core assets in southeastern Alberta and southwestern Saskatchewan that are currently producing approximately 37 MMcf/d of natural gas, for proceeds of $165 million before any closing adjustments. The transaction is subject to normal closing conditions and regulatory approvals and is expected to be completed in the third quarter of this year. Several other asset packages are currently being marketed and the company continues to assess its portfolio and may consider selling other non-core assets if market conditions are favourable. Small acquisitions of property were made in the second quarter to add to the company’s Narrows Lake and Wainwright oil assets.
- In June, 2010, Cenovus filed a Canadian base shelf prospectus for unsecured medium term notes in the amount of $1.5 billion. A U.S. base shelf prospectus for unsecured notes in the amount of US$1.5 billion was filed in July. Each prospectus allows for the issuance, dependent on market conditions, of debt securities from time to time over a 25 month period.
- Cenovus targets a debt to capitalization ratio of between 30% and 40% and a debt to adjusted EBITDA ratio of between 1.0 and 2.0 times. At June 30, 2010, the company’s debt to capitalization ratio was 28% and debt to adjusted EBITDA, on a trailing 12 month basis, was 1.2 times. Both debt to capitalization and debt to adjusted EBITDA are non-GAAP measures as defined in the Advisory.
| Earnings Reconciliation Summary | |||||||||||||||||||||||
|
(for the period ended June 30)
($ millions, except per share amounts) |
2010
Q2 |
2009
Q2 |
6 months 2010 |
6 months
2009 |
|||||||||||||||||||
|
Net earnings
Add back (losses) & deduct gains: |
172 | 160 | 697 | 675 | |||||||||||||||||||
| Unrealized mark-to-market hedging gain (loss), after-tax | 16 | -214 | 186 | -150 | |||||||||||||||||||
| Non-operating foreign exchange gain (loss), after-tax | 14 | -138 | 16 | -101 | |||||||||||||||||||
| Operating earnings1 | 142 | 512 | 495 | 926 | |||||||||||||||||||
| Per share diluted | 0.19 | 0.68 | 0.66 | 1.23 | |||||||||||||||||||
1Operating earnings is a non-GAAP measure as defined in the Advisory.
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Conference Call Today |
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9:00 a.m. Mountain Time (11:00 a.m. Eastern Time) |
| Cenovus will host a conference call today, July 29, 2010, starting at 9:00 a.m. MT (11:00 a.m. ET). To |
| participate, please dial 888-231-8191 (toll-free in North America) or 647-427-7450 approximately 10 |
| minutes prior to the conference call. An archived recording of the call will be available from |
| approximately 2:00 p.m. MT on July 29, 2010, until midnight August 5, 2010, by dialing |
| 800-642-1687 or 416-849-0833 and entering conference passcode 81235259. A live audio webcast of |
|
the conference call will also be available via www.cenovus.com. The webcast will be archived for |
| approximately 90 days. |
ADVISORY
NON-GAAP MEASURES
This news release contains references to non-GAAP measures as follows:
- Operating cash flow is defined as net revenues, less production and mineral taxes, transportation and selling, operating and purchased product expenses and is used to provide a consistent measure of the cash generating performance of our assets and improves the comparability of our underlying financial performance between periods.
- Cash flow is defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital from continuing operations, both of which are defined on the Consolidated Statement of Cash Flows, in Cenovus’s interim consolidated financial statements.
- Operating earnings show net earnings excluding non-operating items such as the after-tax impacts of a gain/loss on discontinuance, the after-tax gain/loss of unrealized mark-to-market accounting for derivative instruments, the after-tax gain/loss on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, the after-tax foreign exchange gain/loss on settlement of intercompany transactions, future income tax on foreign exchange related to U.S. dollar intercompany debt recognized for tax purposes only and the effect of changes in statutory income tax rates. Management views operating earnings as a better measure of performance than net earnings because the excluded items reduce the comparability of the company’s underlying financial performance between periods. The majority of the U.S. dollar debt issued from Canada has maturity dates in excess of five years.
- Free cash flow is defined as cash flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing and/or financing activities.
- Debt to capitalization and debt to adjusted EBITDA are two ratios that management uses to steward the company’s overall debt position as measures of the company’s overall financial strength. Capitalization is a measure defined as debt plus shareholders’ equity. Adjusted EBITDA is defined as net earnings from continuing operations before gains or losses on divestitures, income taxes, foreign exchange gains or losses, interest net, accretion of asset retirement obligation, and depreciation, depletion and amortization. Debt is defined as the current and long term portions of long term debt.
These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding Cenovus’s liquidity and its ability to generate funds to finance its operations. For further information, refer to Cenovus’s most recent Management’s Discussion and Analysis (MD&A) available at www.cenovus.com.
OIL AND GAS INFORMATION
The following estimates were prepared effective December 31, 2009 by McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator (IQRE) and are based on definitions contained in the Canadian Oil and Gas Evaluation Handbook (COGEH). For further discussion regarding our economic contingent resources and our total bitumen initially-in-place and all subcategories thereof, see our April 22, 2010, news release and our June 16, 2010, news release, respectively, available at www.cenovus.com. Actual resources may be greater than or less than the estimates provided. All quantities expressed are best estimate. Total Bitumen Initially-In-Place (BIIP) (137 Bbbls) (equivalent to “total resources”) is that quantity of bitumen that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. BIIP estimates include unrecoverable volumes and are not an estimate of the volume of the substances that will ultimately be recovered. Discovered Bitumen Initially-In-Place (56 Bbbls) (equivalent to “discovered resources”) is that quantity of bitumen that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered bitumen initially-in-place includes production, reserves, and contingent resources; the remainder is categorized as unrecoverable. There is no certainty that it will be commercially viable to produce any portion of the estimate. Undiscovered Bitumen Initially-In-Place (82 Bbbls) (equivalent to “undiscovered resources”) is that quantity of bitumen that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered bitumen initially-in-place is referred to as “prospective resources,” the remainder as “unrecoverable”. There is no certainty that any portion of the estimate will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Contingent resources are quantities of bitumen estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. For Cenovus, the contingencies which must be overcome to enable the classification of bitumen contingent resources as reserves include regulatory application submission with no major issues raised, access to markets and intent to proceed by the operator and partners as evidenced by major capital expenditures planned within five years. Economic contingent resources (5.4 Bbbls) are those contingent resources that are currently economically recoverable based on specific forecasts of commodity prices and costs. The IQRE used the same commodity price assumptions that were used for the 2009 reserves evaluation, which were determined in accordance with U.S. Securities and Exchange Commission requirements. The estimate of economic contingent resources has not been adjusted for risk based on the chance of development. There is no certainty that it will be commercially viable to produce any portion of the resources. Prospective resources (12.6 Bbbls) are those quantities of bitumen estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity. Unrecoverable (49 Bbbls discovered; 69 Bbbls undiscovered) is that portion of discovered or undiscovered BIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Best estimate, when used in reference to contingent resources, is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Those resources that fall within the best estimate have a 50% confidence level that the actual quantities recovered will equal or exceed the estimate. The term “best estimate”, when used in reference to an “in-place” estimate, is not defined in COGEH; however, it was determined by the IQRE to the same 50% confidence level as was applied to previously disclosed estimates of 2P reserves and best estimate economic contingent resources.
FORWARD-LOOKING INFORMATION
This news release contains certain forward-looking statements and information about our current expectations, estimates and projections about the future, based on certain assumptions made by the Company in light of its experience and perception of historical trends. Although we believe that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct.
Forward-looking statements and information are typically identified by words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “forecast”, “target”, “project”, “objective”, “could”, “focus”, “vision”, “goal”, “proposed”, “scheduled”, “outlook” or similar expressions suggesting future outcomes or statements regarding an outlook, including statements about our strategy, our projected future value or net asset value, operating and financial results, schedules, land positions, production, including, without limitation, the stability or growth thereof, reserves and resources, material properties, uses and development of our technology, risk mitigation efforts, commodity prices, shareholder value, cash flow, funding alternatives, costs and expected impact of future commitments in respect of our ongoing operations generally and with respect to certain properties and interests held by Cenovus. Readers are cautioned not to place undue reliance on forward-looking statements and information as our actual results may differ materially from those expressed or implied.
Our forward-looking information respecting anticipated 2010 cash flow and operating cash flow is based on the following assumptions: achieving average 2010 production of approximately 120,200 bbls/d to 129,700 bbls/d of crude oil and liquids and 740 MMcf/d to 760 MMcf/d of natural gas; average commodity prices for 2010 of a WTI price of US$65 per bbl to US$85 per bbl and a WCS price of US$54 per bbl to US$71 per bbl for oil, a NYMEX price of US$5.50 per Mcf to US$6.15 per Mcf and AECO price of $5.15 per GJ to $5.70 per GJ for natural gas; an average U.S./Canadian dollar foreign exchange rate of $0.85 to $0.96 US$/CDN$; an average Chicago 3-2-1 crack spread for 2010 of US$7.50 per bbl to US$9.50 per bbl for refining margins; and an average number of outstanding shares of approximately 752 million.
Forward-looking statements involve a number of assumptions, risks and uncertainties, some of which are specific to Cenovus and others that apply to the industry generally. The risk factors and uncertainties that could cause actual results to differ materially, and the factors or assumptions on which the forward-looking information is based, include, among other things: volatility of and assumptions regarding oil and gas prices; assumptions inherent in our current guidance; our projected capital investment levels, the flexibility of capital spending plans and the associated source of funding; the effect of our risk management program, including the impact of derivative financial instruments and our access to various sources of capital; accuracy of cost estimates; fluctuations in commodity, currency and interest rates; fluctuations in product supply and demand; market competition, including from alternative energy sources; risks inherent in our marketing operations, including credit risks; success of hedging strategies; maintaining a desirable debt to cash flow ratio; accuracy of our reserves, resources and future production estimates; estimates of quantities of oil, bitumen, natural gas and liquids from properties and other sources not currently classified as proved; our ability to replace and expand oil and gas reserves; the ability of us and ConocoPhillips to maintain our relationship and to successfully manage and operate the North American integrated heavy oil business and to obtain necessary regulatory approvals; the successful and timely implementation of capital projects; reliability of our assets; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; risks associated with technology and its application to our business; our ability to generate sufficient cash flow from operations to meet our current and future obligations; our ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; our ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon and other laws or regulations, or the interpretations of such laws or regulations, as adopted or proposed, the impact thereof and the costs associated with compliance; the expected impact and timing of various accounting pronouncements, rule changes and standards on us, our financial results and our consolidated financial statements; changes in the general economic, market and business conditions; the political and economic conditions in the countries in which we operate; the occurrence of unexpected events such as war, terrorist threats, hostilities, civil insurrection and instability affecting countries in which we operate; risks associated with existing and potential future lawsuits and regulatory actions made against us; our financing plans and initiatives; the expected impacts of the plan of arrangement with Encana Corporation (“Arrangement”) on our employees, operations, suppliers, business partners and stakeholders and our ability to realize the expected benefits of the Arrangement; our ability to obtain financing in the future on a stand alone basis; the historical financial information pertaining to our assets as operated by Encana Corporation prior to November 30, 2009 may not be representative of our results as an independent entity; our limited operating history as a separate entity and other risks and uncertainties described from time to time in the filings we make with securities regulatory authorities. Readers are cautioned that the foregoing list is not exhaustive.
Many of these risk factors are discussed in further detail in our Annual Information Form/Form 40-F and our annual and interim MD&A as filed with Canadian securities regulatory authorities at www.sedar.com and the U.S. Securities and Exchange Commission at www.sec.gov, and available at www.cenovus.com.
The forward-looking statements and information contained in this document, including the assumptions, risks and uncertainties underlying such statements, are made as of the date of this document and, except as required by law, we do not undertake any obligation to update publicly or to revise any of such information, whether as a result of new information, future events or otherwise. The forward-looking statements and information contained in this document are expressly qualified by this cautionary statement.
Cenovus Energy Inc.
Cenovus Energy Inc. is a Canadian, integrated oil company. It is committed to applying fresh, progressive thinking to safely and responsibly unlock energy resources the world needs. Operations include oil sands projects in northern Alberta, which use specialized methods to drill and pump the oil to the surface, and established natural gas and oil production in Alberta and Saskatchewan. The company also has 50% ownership in two U.S. refineries. Cenovus shares trade under the symbol CVE, and are listed on the Toronto and New York stock exchanges. Its enterprise value is approximately $26 billion. For more information, visit www.cenovus.com.
Cenovus Energy Inc.
Interim Consolidated Financial Statements (unaudited)
For the Period Ended June 30, 2010
(Canadian Dollars)
| CONSOLIDATED STATEMENT OF EARNINGS AND COMPREHENSIVE INCOME (unaudited) |
| For the period ended June 30, | Three Months Ended | Six Months Ended | ||||||||
| (C$ millions, except per share amounts) | 2010 | 2009 | 2010 | 2009 | ||||||
| Gross Revenues | (Note 1) | 3,318 | 2,871 | 6,920 | 5,607 | |||||
| Less: Royalties | 123 | 53 | 234 | 96 | ||||||
| Net Revenues | 3,195 | 2,818 | 6,686 | 5,511 | ||||||
| Expenses | (Note 1) | |||||||||
| Production and mineral taxes | 6 | 13 | 18 | 26 | ||||||
| Transportation and selling | 291 | 184 | 582 | 350 | ||||||
| Operating | 322 | 320 | 670 | 684 | ||||||
| Purchased product | 1,888 | 1,425 | 3,653 | 2,561 | ||||||
| Depreciation, depletion and amortization | 325 | 382 | 649 | 762 | ||||||
| General and administrative | 59 | 52 | 111 | 93 | ||||||
| Interest, net | (Note 7) | 66 | 57 | 131 | 102 | |||||
| Accretion of asset retirement obligation | (Note 13) | 18 | 12 | 40 | 23 | |||||
| Foreign exchange (gain) loss, net | (Note 8) | 28 | 143 | 1 | 91 | |||||
| Other (income) loss, net | 9 | - | 8 | - | ||||||
| 3,012 | 2,588 | 5,863 | 4,692 | |||||||
| Earnings Before Income Tax | 183 | 230 | 823 | 819 | ||||||
| Income tax expense | (Note 9) | 11 | 70 | 126 | 144 | |||||
| Net Earnings | 172 | 160 | 697 | 675 | ||||||
| Other Comprehensive Income, Net of Tax | ||||||||||
| Foreign Currency Translation Adjustment | 129 | (104) | 41 | (17) | ||||||
| Comprehensive Income | 301 | 56 | 738 | 658 | ||||||
| Net Earnings per Common Share |
(Note 18) |
|||||||||
| Basic | 0.23 | 0.21 | 0.93 | 0.90 | ||||||
| Diluted | 0.23 | 0.21 | 0.93 | 0.90 | ||||||
See accompanying Notes to Interim Consolidated Financial Statements (unaudited).
| CONSOLIDATED BALANCE SHEET (unaudited) |
| As at (C$ millions) | June 30, 2010 | December 31, 2009 | ||||
| Assets | ||||||
| Current Assets | ||||||
| Cash and cash equivalents | 409 | 155 | ||||
| Accounts receivable and accrued revenues | 1,063 | 978 | ||||
| Income tax receivable | 34 | 40 | ||||
| Current portion of Partnership Contribution Receivable | (Note 11) | 359 | 345 | |||
| Risk management | (Note 17) | 196 | 60 | |||
| Inventories | (Note 10) | 809 | 875 | |||
| 2,870 | 2,453 | |||||
| Property, Plant and Equipment, net | (Note 1) | 15,469 | 15,214 | |||
| Partnership Contribution Receivable | (Note 11) | 2,475 | 2,621 | |||
| Risk Management | (Note 17) | 62 | 1 | |||
| Other Assets | 427 | 320 | ||||
| Goodwill | (Note 1) | 1,146 | 1,146 | |||
| 22,449 | 21,755 | |||||
| Liabilities and Shareholders’ Equity | ||||||
| Current Liabilities | ||||||
| Accounts payable and accrued liabilities | 1,547 | 1,574 | ||||
| Income tax payable | 64 | - | ||||
| Current portion of Partnership Contribution Payable | (Note 11) | 355 | 340 | |||
| Risk management | (Note 17) | 8 | 70 | |||
| 1,974 | 1,984 | |||||
| Long-Term Debt | (Note 12) | 3,821 | 3,656 | |||
| Partnership Contribution Payable | (Note 11) | 2,506 | 2,650 | |||
| Risk Management | (Note 17) | 4 | 4 | |||
| Asset Retirement Obligation | (Note 13) | 1,175 | 1,147 | |||
| Other Liabilities | 353 | 239 | ||||
| Future Income Taxes | 2,561 | 2,467 | ||||
| 12,394 | 12,147 | |||||
| Shareholders’ Equity | 10,055 | 9,608 | ||||
| 22,449 | 21,755 |
See accompanying Notes to Interim Consolidated Financial Statements (unaudited).
| CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY (unaudited) |
| (C$ millions) |
Share Capital
(Note 14) |
Paid in Surplus |
Retained
Earnings |
AOCI* |
Owner’s
Net Investment (Note 14) |
Total | ||||||
| Balance as of December 31, 2008 | - | - | - | 224 | 9,264 | 9,488 | ||||||
| Net earnings | - | - | - | - | 675 | 675 | ||||||
| Net distribution to owner | - | - | - | - | (322) | (322) | ||||||
| Other comprehensive income (loss) | - | - | - | (17) | - | (17) | ||||||
| Balance as of June 30, 2009 | - | - | - | 207 | 9,617 | 9,824 | ||||||
| Balance as of December 31, 2009 | 3,681 | 5,896 | 45 | (14) | - | 9,608 | ||||||
| Net earnings | - | - | 697 | - | - | 697 | ||||||
| Common shares issued under option plans | 9 | - | - | - | - | 9 | ||||||
| Dividends on common shares | - | - | (300) | - | - | (300) | ||||||
| Other comprehensive income (loss) | - | - | - | 41 | - | 41 | ||||||
| Balance as of June 30, 2010 | 3,690 | 5,896 | 442 | 27 | - | 10,055 |
*Accumulated Other Comprehensive Income
See accompanying Notes to Interim Consolidated Financial Statements (unaudited).
|
CONSOLIDATED STATEMENT OF CASH FLOWS (unaudited) |
| Three Months Ended | Six Months Ended | |||||||||
| For the period ended June 30, (C$ millions) | 2010 | 2009 | 2010 | 2009 | ||||||
| Operating Activities | ||||||||||
| Net earnings | 172 | 160 | 697 | 675 | ||||||
| Depreciation, depletion and amortization | 325 | 382 | 649 | 762 | ||||||
| Future income taxes | (Note 9) | (4) | (81) | 96 | (105) | |||||
| Unrealized (gain) loss on risk management | (Note 17) | (22) | 297 | (259) | 211 | |||||
| Unrealized foreign exchange (gain) loss | (Note 8) | 31 | 160 | (1) | 107 | |||||
| Accretion of asset retirement obligation | (Note 13) | 18 | 12 | 40 | 23 | |||||
| Other | 17 | 15 | 36 | 13 | ||||||
| Net change in other assets and liabilities | (13) | (6) | (28) | (9) | ||||||
| Net change in non-cash working capital | (53) | (146) | 61 | (202) | ||||||
| Cash From Operating Activities | 471 | 793 | 1,291 | 1,475 | ||||||
| Investing Activities | ||||||||||
| Capital expenditures | (Note 1) | (477) | (489) | (970) | (1,141) | |||||
| Proceeds from divestitures | (Note 6) | 72 | 3 | 144 | 3 | |||||
| Net change in investments and other | - | 13 | 2 | 14 | ||||||
| Net change in non-cash working capital | (63) | (59) | (16) | (126) | ||||||
| Cash (Used in) Investing Activities | (468) | (532) | (840) | (1,250) | ||||||
| Net Cash Provided (Used) before Financing Activities | 3 | 261 | 451 | 225 | ||||||
| Financing Activities | ||||||||||
| Net issuance (repayment) of revolving long-term debt | 164 | (403) | 106 | (163) | ||||||
| Net financing transactions with Encana | - | (193) | - | (322) | ||||||
| Issuance of long-term debt | - | 204 | - | 204 | ||||||
| Issuance of common shares | 2 | - | 7 | - | ||||||
| Dividends on common shares | (150) | - | (300) | - | ||||||
| Cash From (Used in) Financing Activities | 16 | (392) | (187) | (281) | ||||||
| Foreign Exchange Gain (Loss) on Cash and Cash Equivalents Held in Foreign Currency | (7) | (3) | (10) | (5) | ||||||
| Increase (Decrease) in Cash and Cash Equivalents | 12 | (134) | 254 | (61) | ||||||
| Cash and Cash Equivalents, Beginning of Period | 397 | 261 | 155 | 188 | ||||||
| Cash and Cash Equivalents, End of Period | 409 | 127 | 409 | 127 | ||||||
See accompanying Notes to Interim Consolidated Financial Statements (unaudited).
| NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS (unaudited) |
|
All amounts in C$ millions, unless otherwise indicated |
|
For the period ended June 30, 2010 |
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES
Cenovus Energy Inc. (“Cenovus” or the “Company”) is in the business of the development, production and marketing of crude oil, natural gas and natural gas liquids (“NGLs”) in Canada with refining operations in the United States.
The Company is headquartered in Calgary, Alberta and its common shares are listed on the Toronto and New York stock exchanges. Information on the Company’s background and the basis of presentation for these financial statements are found in Note 2.
Cenovus is organized into two operating divisions:
- Integrated Oil Division, which includes all of the assets within the upstream and downstream integrated oil business with the Company’s joint venture partner, as well as other oil sands interests and the Athabasca natural gas assets. The Integrated Oil Division has assets in both Canada and the U.S. including two major oil sands projects: (i) Foster Creek; and (ii) Christina Lake; as well as two refineries: (i) Wood River; and (ii) Borger.
- Canadian Plains Division, which contains established crude oil and natural gas development assets in Alberta and Saskatchewan and includes two major properties: (i) Weyburn; and (ii) Pelican Lake; as well as the Southern Alberta oil and gas properties. The division also markets Cenovus’s crude oil and natural gas, as well as third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification.
For financial statement reporting purposes, the Company’s operating and reportable segments are:
- Upstream Canada, which includes Cenovus’s development and production of crude oil, natural gas and natural gas liquids (“NGLs”), and other related activities in Canada. This includes the Foster Creek and Christina Lake operations which are jointly owned with ConocoPhillips, an unrelated U.S. public company, and operated by Cenovus, as well as several other emerging projects.
- Downstream Refining, which is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. The refineries are jointly owned with ConocoPhillips and operated by ConocoPhillips.
- Corporate and Eliminations, which primarily includes unrealized gains or losses recorded on derivative financial instruments as well as other Cenovus-wide costs for general and administrative and financing activities. As financial instruments are settled, realized gains and losses are recorded in the operating segment to which the derivative instrument relates. Eliminations relate to sales and operating revenues and purchased product between segments recorded at transfer prices based on current market prices and to unrealized intersegment profits in inventory.
The tabular financial information which follows presents the segmented information first by segment and geographic location, then by product and operating division. Capital expenditures and goodwill information are summarized at the end of the note.
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)
Results of Operations
Segment and Geographic Information (For the three months ended June 30)
| Upstream Canada | Downstream Refining | |||||||
| (C$ millions) | 2010 | 2009 | 2010 | 2009 | ||||
| Gross Revenues | 1,726 | 1,661 | 1,610 | 1,526 | ||||
| Less: Royalties | 123 | 53 | - | - | ||||
| Net Revenues | 1,603 | 1,608 | 1,610 | 1,526 | ||||
| Expenses | ||||||||
| Production and mineral taxes | 6 | 13 | - | - | ||||
| Transportation and selling | 291 | 184 | - | - | ||||
| Operating | 215 | 188 | 110 | 129 | ||||
| Purchased product | 402 | 228 | 1,524 | 1,219 | ||||
| Operating Cash Flow | 689 | 995 | (24) | 178 | ||||
| Depreciation, depletion and amortization | 264 | 316 | 49 | 54 | ||||
| Segment Income (Loss) | 425 | 679 | (73) | 124 | ||||
| Corporate and Eliminations | Consolidated | |||||||
|
(C$ millions) |
2010 |
2009 |
2010 |
2009 |
||||
| Gross Revenues | (18) | (316) | 3,318 | 2,871 | ||||
| Less: Royalties | - | - | 123 | 53 | ||||
| Net Revenues | (18) | (316) | 3,195 | 2,818 | ||||
| Expenses | ||||||||
| Production and mineral taxes | - | - | 6 | 13 | ||||
| Transportation and selling | - | - | 291 | 184 | ||||
| Operating | (3) | 3 | 322 | 320 | ||||
| Purchased product | (38) | (22) | 1,888 | 1,425 | ||||
| 23 | (297) | 688 | 876 | |||||
| Depreciation, depletion and amortization | 12 | 12 | 325 | 382 | ||||
| Segment Income (Loss) | 11 | (309) | 363 | 494 | ||||
| General and administrative | 59 | 52 | 59 | 52 | ||||
| Interest, net | 66 | 57 | 66 | 57 | ||||
| Accretion of asset retirement obligation | 18 | 12 | 18 | 12 | ||||
| Foreign exchange (gain) loss, net | 28 | 143 | 28 | 143 | ||||
| Other (income) loss, net | 9 | - | 9 | - | ||||
| 180 | 264 | 180 | 264 | |||||
| Earnings Before Income Tax | 183 | 230 | ||||||
| Income tax expense | 11 | 70 | ||||||
| Net Earnings | 172 | 160 | ||||||
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)
Upstream Canada Product and Divisional Information
(For the three months ended June 30)
| Crude Oil & NGLs | ||||||||||||
| Integrated Oil | Canadian Plains | Total | ||||||||||
| (C$ millions) | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | ||||||
| Gross Revenues | 507 | 325 | 452 | 445 | 959 | 770 | ||||||
| Less: Royalties | 46 | 2 | 72 | 48 | 118 | 50 | ||||||
| Net Revenues | 461 | 323 | 380 | 397 | 841 | 720 | ||||||
| Expenses | ||||||||||||
| Production and mineral taxes | - | - | 8 | 7 | 8 | 7 | ||||||
| Transportation and selling | 224 | 116 | 56 | 51 | 280 | 167 | ||||||
| Operating | 61 | 45 | 82 | 64 | 143 | 109 | ||||||
| Purchased product | - | - | - | - | - | - | ||||||
| Operating Cash Flow | 176 | 162 | 234 | 275 | 410 | 437 | ||||||
| Natural Gas | ||||||||||||
| Integrated Oil | Canadian Plains | Total | ||||||||||
| (C$ millions) | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | ||||||
| Gross Revenues | 23 | 79 | 323 | 558 | 346 | 637 | ||||||
| Less: Royalties | 2 | (4) | 3 | 3 | 5 | (1) | ||||||
| Net Revenues | 21 | 83 | 320 | 555 | 341 | 638 | ||||||
| Expenses | ||||||||||||
| Production and mineral taxes | - | - | (2) | 6 | (2) | 6 | ||||||
| Transportation and selling | 1 | - | 10 | 12 | 11 | 12 | ||||||
| Operating | 4 | 5 | 60 | 60 | 64 | 65 | ||||||
| Purchased product | - | - | - | - | - | - | ||||||
| Operating Cash Flow | 16 | 78 | 252 | 477 | 268 | 555 | ||||||
| Other | ||||||||||||
| Integrated Oil | Canadian Plains | Total | ||||||||||
| (C$ millions) | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | ||||||
| Gross Revenues | 6 | 18 | 415 | 236 | 421 | 254 | ||||||
| Less: Royalties | - | 4 | - | - | - | 4 | ||||||
| Net Revenues | 6 | 14 | 415 | 236 | 421 | 250 | ||||||
| Expenses | ||||||||||||
| Production and mineral taxes | - | - | - | - | - | - | ||||||
| Transportation and selling | - | 5 | - | - | - | 5 | ||||||
| Operating | 1 | 8 | 7 | 6 | 8 | 14 | ||||||
| Purchased product | - | - | 402 | 228 | 402 | 228 | ||||||
| Operating Cash Flow | 5 | 1 | 6 | 2 | 11 | 3 | ||||||
| Total Upstream | ||||||||||||
| Integrated Oil | Canadian Plains | Total | ||||||||||
| (C$ millions) | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | ||||||
| Gross Revenues | 536 | 422 | 1,190 | 1,239 | 1,726 | 1,661 | ||||||
| Less: Royalties | 48 | 2 | 75 | 51 | 123 | 53 | ||||||
| Net Revenues | 488 | 420 | 1,115 | 1,188 | 1,603 | 1,608 | ||||||
| Expenses | ||||||||||||
| Production and mineral taxes | - | - | 6 | 13 | 6 | 13 | ||||||
| Transportation and selling | 225 | 121 | 66 | 63 | 291 | 184 | ||||||
| Operating | 66 | 58 | 149 | 130 | 215 | 188 | ||||||
| Purchased product | - | - | 402 | 228 | 402 | 228 | ||||||
| Operating Cash Flow | 197 | 241 | 492 | 754 | 689 | 995 | ||||||
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)
Results of Operations
Segment and Geographic Information (For the six months ended June 30)
| Upstream Canada | Downstream Refining | |||||||
| (C$ millions) | 2010 | 2009 | 2010 | 2009 | ||||
| Gross Revenues | 3,593 | 3,154 | 3,128 | 2,680 | ||||
| Less: Royalties | 234 | 96 | - | - | ||||
| Net Revenues | 3,359 | 3,058 | 3,128 | 2,680 | ||||
| Expenses | ||||||||
| Production and mineral taxes | 18 | 26 | - | - | ||||
| Transportation and selling | 582 | 350 | - | - | ||||
| Operating | 420 | 386 | 249 | 276 | ||||
| Purchased product | 806 | 446 | 2,909 | 2,153 | ||||
| Operating Cash Flow | 1,533 | 1,850 | (30) | 251 | ||||
| Depreciation, depletion and amortization | 529 | 620 | 100 | 117 | ||||
| Segment Income (Loss) | 1,004 | 1,230 | (130) | 134 | ||||
| As at (C$ millions) |
June 30,
2010 |
December 31,
2009 |
June 30,
2010 |
December 31,
2009 |
||||
| Property, Plant & Equipment | 10,014 | 10,109 | 5,342 | 4,989 | ||||
| Goodwill | 1,146 | 1,146 | - | - | ||||
| Total Assets | 14,980 | 15,218 | 6,558 | 6,107 | ||||
| Corporate and Eliminations | Consolidated | |||||||
|
(C$ millions) |
2010 |
2009 |
2010 |
2009 |
||||
| Gross Revenues | 199 | (227) | 6,920 | 5,607 | ||||
| Less: Royalties | - | - | 234 | 96 | ||||
| Net Revenues | 199 | (227) | 6,686 | 5,511 | ||||
| Expenses | ||||||||
| Production and mineral taxes | - | - | 18 | 26 | ||||
| Transportation and selling | - | - | 582 | 350 | ||||
| Operating | 1 | 22 | 670 | 684 | ||||
| Purchased product | (62) | (38) | 3,653 | 2,561 | ||||
| 260 | (211) | 1,763 | 1,890 | |||||
| Depreciation, depletion and amortization | 20 | 25 | 649 | 762 | ||||
| Segment Income (Loss) | 240 | (236) | 1,114 | 1,128 | ||||
| General and administrative | 111 | 93 | 111 | 93 | ||||
| Interest, net | 131 | 102 | 131 | 102 | ||||
| Accretion of asset retirement obligation | 40 | 23 | 40 | 23 | ||||
| Foreign exchange (gain) loss, net | 1 | 91 | 1 | 91 | ||||
| Other (income) loss, net | 8 | - | 8 | - | ||||
| 291 | 309 | 291 | 309 | |||||
| Earnings Before Income Tax | 823 | 819 | ||||||
| Income tax expense | 126 | 144 | ||||||
| Net Earnings | 697 | 675 | ||||||
| As at (C$ millions) |
June 30,
2010 |
December 31,
2009 |
June 30,
2010 |
December 31,
2009 |
||||
| Property, Plant & Equipment | 113 | 116 | 15,469 | 15,214 | ||||
| Goodwill | - | - | 1,146 | 1,146 | ||||
| Total Assets | 911 | 430 | 22,449 | 21,755 | ||||
1. DESCRIPTION OF BUSINESS AND SEGMENTED DISCLOSURES (continued)
Upstream Canada Product and Divisional Information
(For the six months ended June 30)
| Crude Oil & NGLs | ||||||||||||
| Integrated Oil | Canadian Plain | |||||||||||