EnCana Corporation (TSX & NYSE: ECA) continued to deliver strong operating and financial results in the third quarter of 2009, despite low natural gas prices. EnCana generated third quarter cash flow of US$2.1 billion, or $2.77 per share, and operating earnings of $775 million, or $1.03 per share – down 26 and 46 percent respectively compared to the third quarter of 2008. EnCana’s financial performance was significantly enhanced by commodity price hedges, which contributed $913 million in realized after-tax gains, or $1.22 per share, to cash flow in the third quarter.
Shut-in and curtailed gas coming back on this winter
To help preserve shareholder value on the expectation that natural gas prices would rise to more economic levels, EnCana curtailed or shut in about 500 million cubic feet per day (MMcf/d) of natural gas production in the third quarter. These shut-in and curtailed volumes are expected to be brought back on stream during the winter of 2009/10. Total third quarter production was about 4.4 billion cubic feet equivalent per day (Bcfe/d), down 7 percent compared to one year earlier. While natural gas production was down about 9 percent to 3.6 billion cubic feet per day (Bcf/d), oil and natural gas liquids (NGLs) production increased about 4 percent to 139,000 barrels per day (bbls/d), led by a 44 percent production increase from the Foster Creek enhanced oil project. Natural gas production in the first nine months of 2009 was 3.7 Bcf/d, which is higher than the company’s 2009 guidance of 3.6 Bcf/d. This reflects EnCana’s operational success even during a period when it chose to curtail production due to low prices.
“Our company’s solid operational and financial performance during a period of weak prices is evidence that EnCana’s strategy is working. We remain focused on being the lowest cost producer by applying advanced technologies and by pursuing operational efficiencies across all resource plays. In addition, our successful hedging program has helped us sustain strong cash flow. To help preserve the value of our resource base, we have curtailed significant natural gas production in many of our operating areas and have significant productive capacity available to bring to market as prices recover,” said Randy Eresman, EnCana’s President & Chief Executive Officer.
IMPORTANT NOTE: EnCana reports in U.S. dollars unless otherwise noted and follows U.S. protocols, which report gas and oil production, sales and reserves on an after-royalties basis. The company’s financial statements are prepared in accordance with Canadian generally accepted accounting principles (GAAP). Per share amounts for cash flow and earnings are on a diluted basis.
EnCana Third Quarter 2009 Highlights
(all year-over-year comparisons are to the third quarter of 2008)
Financial
- Cash flow was $2.1 billion or $2.77 per share, a decrease of 26 percent
- Operating earnings were $775 million or $1.03 per share, down 46 percent
- Net earnings were $25 million or 3 cents per share
- Capital investment, excluding acquisitions and divestitures, was $1.3 billion, down 16 percent, primarily due to lower drilling and completion expenditures as a result of fewer wells drilled and cost deflation
- Free cash flow was $741 million, down 39 percent (Free cash flow is defined in Note 1 on page 9)
- Realized natural gas prices were $7.31 per thousand cubic feet (Mcf), down 8 percent, and realized liquids prices were $57.39 per barrel (bbl), down 37 percent. These prices include financial hedges
- At the end of the quarter, debt to capitalization was 25 percent and debt to adjusted EBITDA was 1.1 times. These ratios do not include the $3.5 billion of debt securities intended for use by Cenovus, the proceeds of which have been placed in escrow pending the completion of the split transaction
- Paid a dividend of 40 cents per share
- EnCana’s integrated oil business venture with ConocoPhillips generated $266 million in operating cash flow, including $180 million from the Foster Creek and Christina Lake upstream projects, and $86 million from the downstream business
Operating – Upstream
- Total natural gas production was 3.6 Bcf/d, down 9 percent, primarily due to a decision to shut in or curtail about 500 MMcf/d of production because of the low price environment and natural declines in conventional properties. This reduced production was partially offset by lower royalty volumes in Alberta due to price sensitive royalty rates
- Total oil and NGLs production was more than 139,000 bbls/d, an increase of 4 percent
- Foster Creek and Christina Lake oil production grew 43 percent to approximately 45,000 bbls/d net to EnCana
- Operating and administrative costs were $1.26 per thousand cubic feet equivalent (Mcfe), which is up from 79 cents per Mcfe in the third quarter of 2008, a period when there was a large recovery of long-term incentive costs as a result of a significant decline in the EnCana share price. These higher 2009 costs were offset primarily by a weaker Canadian dollar and lower purchased fuel and workover costs
Operating – Downstream
- Refined products averaged 451,000 bbls/d (225,500 bbls/d net to EnCana), up 3 percent
- Refinery crude utilization was 94 percent or 425,000 bbls/d crude throughput (212,500 bbls/d net to EnCana), up 3 percent
- The Wood River coker and refinery expansion (CORE) project was approximately 62 percent complete at the end of September.
Financial Summary – Total Consolidated | |||||||||||||||
(for the period ended September 30)
($ millions, except per share amounts) | Q3 2009 |
Q3
2008 | % ∆ | 9 months 2009 |
9 months
2008 | % ∆ | |||||||||
Cash flow1 | 2,079 | 2,809 | -26 | 6,176 | 8,087 | -24 | |||||||||
Per share diluted | 2.77 | 3.74 | -26 | 8.22 | 10.75 | -24 | |||||||||
Operating earnings1 | 775 | 1,442 | -46 | 2,640 | 3,956 | -33 | |||||||||
Per share diluted | 1.03 | 1.92 | -46 | 3.51 | 5.26 | -33 | |||||||||
Net earnings | 25 | 3,553 | 1,226 | 4,867 | |||||||||||
Per share diluted | 0.03 | 4.73 | 1.63 | 6.47 | |||||||||||
Capital investment | 1,338 | 1,588 | -16 | 3,924 | 5,155 | -24 | |||||||||
Earnings Reconciliation Summary – Total Consolidated | |||||||||||||||
Net earnings | 25 | 3,553 | 1,226 | 4,867 | |||||||||||
Add back (losses) & deduct gains | |||||||||||||||
Unrealized mark-to-market accounting gain (loss), after-tax | (931) | 2,043 | (1,592) | 1,071 | |||||||||||
Non-operating foreign exchange gain (loss), after-tax | 181 | (31) | 178 | (259) | |||||||||||
Gain (loss) on discontinuance, after-tax | - | 99 | - | 99 | |||||||||||
Operating earnings1 | 775 | 1,442 | -46 | 2,640 | 3,956 | -33 | |||||||||
Per share diluted | 1.03 | 1.92 | -46 | 3.51 | 5.26 | -33 | |||||||||
1 Cash flow and operating earnings are non-GAAP measures as defined in Note 1 on page 9. | |||||||||||||||
Price risk management affects net earnings
Operating earnings include the realized hedging gains and losses which reflect the actual value of the hedging contracts when settled. Management believes operating earnings are a better measure of performance because they remove the variability associated with unrealized mark-to-market accounting accruals. Net earnings include both realized hedging gains/losses and unrealized mark-to-market accounting gains/losses.
Net earnings in the third quarter of 2009 were affected by the combined impact of realized and unrealized hedging gains/losses which resulted in an $18 million after-tax decrease to net earnings in 2009 compared to a $1.8 billion after-tax increase to net earnings in the third quarter of 2008.
Production & Drilling Summary | |||||||||||||||||||||
Total Consolidated | |||||||||||||||||||||
(for the period ended September 30)
(After royalties) | Q3 2009 |
Q3
2008 | % ∆ | 9 months 2009 |
9 months
2008 | % ∆ | |||||||||||||||
Natural Gas (MMcf/d) | 3,551 | 3,917 | -9 | 3,735 | 3,830 | -2 | |||||||||||||||
Oil and NGLs (Mbbls/d) | 139 | 134 | 4 | 136 | 133 | 2 | |||||||||||||||
Total Production (MMcfe/d) | 4,387 | 4,718 | -7 | 4,554 | 4,627 | -2 | |||||||||||||||
Total net wells drilled | 292 | 730 | -60 | 1,391 | 2,282 | -39 | |||||||||||||||
Key resource play production
Third quarter oil and natural gas production from key resource plays decreased 7 percent to 3.4 Bcfe/d compared to 3.6 Bcfe/d in the third quarter of 2008. Key resource play oil production was up 20 percent from the third quarter of 2008 to about 81,000 bbls/d led by Foster Creek and Christina Lake. Natural gas key resource play production was down by 10 percent, to 2.9 Bcf/d, due to a decision to shut in some wells, restrict productive capacity and delay some well completions or tie-ins to sales pipelines because of lower natural gas prices. These company-wide initiatives resulted in production restrictions of about 500 MMcf/d in the quarter.
Horn River and Haynesville shale plays continue to deliver strong drilling results
Results from drilling and completion work at EnCana’s Horn River play in northeast British Columbia continue to build the company’s confidence in the long term potential of this emerging shale gas play, where 47 gross wells have been drilled to date (23.5 net to EnCana). Performance from the first 13 gross wells completed by EnCana and its partner are very positive. Initial 30-day production rates have been between 8 million and 10 million cubic feet of gas per day. At the Haynesville play in northern Louisiana and East Texas, EnCana drilled 12 net wells and production during the quarter averaged about 80 MMcf/d. Well costs have dropped about 40 percent with EnCana’s three best wells averaging below $8 million per well.
Integrated oil business production increases
EnCana’s integrated oil business with ConocoPhillips achieved a successful third quarter generating operating cash flow of $266 million. Production at Foster Creek and Christina Lake was up 43 percent. Despite the strong production growth, upstream operating cash flow was down 2 percent to $180 million due to a 37 percent decrease in crude oil prices. The Borger and Wood River refineries generated operating cash flow of $86 million compared to a loss of $96 million in the third quarter of 2008. Higher capacity utilization and lower purchased-product and operating costs contributed to the improvement.
Expansion of oil production capacity at Foster Creek and Christina Lake on track
At Foster Creek, oil production from the phase D and E expansions continues to ramp up and the operation is on target to exit 2009 producing between 90,000 and 100,000 bbls/d (45,000 to 50,000 bbls/d net to EnCana). At Christina Lake, construction of phase C continues and current production is about 15,000 bbls/d (7,500 bbls/d net to EnCana).
Production from key North American resource plays | |||||||||||||||||||||||||||
Resource Play (After royalties) | Daily Production | ||||||||||||||||||||||||||
2009 | 2008 | 2007 | |||||||||||||||||||||||||
YTD | Q3 | Q2 | Q1 | Full Year | Q4 | Q3 | Q2 | Q1 | Full Year | ||||||||||||||||||
Natural Gas (MMcf/d) | |||||||||||||||||||||||||||
Jonah | 573 | 521 | 576 | 623 | 603 | 573 | 615 | 630 | 595 | 557 | |||||||||||||||||
Piceance | 358 | 334 | 355 | 386 | 385 | 377 | 407 | 383 | 372 | 348 | |||||||||||||||||
East Texas | 339 | 305 | 304 | 409 | 334 | 408 | 339 | 316 | 273 | 143 | |||||||||||||||||
Fort Worth | 141 | 135 | 138 | 149 | 142 | 143 | 148 | 137 | 140 | 124 | |||||||||||||||||
Greater Sierra | 206 | 189 | 216 | 215 | 220 | 228 | 228 | 219 | 205 | 211 | |||||||||||||||||
Cutbank Ridge | 328 | 322 | 340 | 323 | 296 | 311 | 322 | 280 | 271 | 258 | |||||||||||||||||
Bighorn | 165 | 154 | 186 | 156 | 167 | 165 | 185 | 170 | 146 | 126 | |||||||||||||||||
CBM | 319 | 318 | 330 | 309 | 304 | 308 | 309 | 303 | 298 | 259 | |||||||||||||||||
Shallow Gas | 661 | 649 | 661 | 673 | 700 | 683 | 691 | 712 | 715 | 726 | |||||||||||||||||
Total natural gas (MMcf/d) | 3,090 | 2,927 | 3,106 | 3,243 | 3,151 | 3,196 | 3,244 | 3,150 | 3,015 | 2,752 | |||||||||||||||||
Oil (Mbbls/d) | |||||||||||||||||||||||||||
Foster Creek | 34 | 39 | 34 | 28 | 26 | 29 | 27 | 21 | 27 | 24 | |||||||||||||||||
Christina Lake | 6 | 6 | 6 | 7 | 4 | 6 | 5 | 4 | 2 | 3 | |||||||||||||||||
Pelican Lake | 20 | 21 | 19 | 21 | 22 | 20 | 22 | 21 | 24 | 23 | |||||||||||||||||
Weyburn | 15 | 15 | 15 | 16 | 14 | 15 | 14 | 13 | 14 | 15 | |||||||||||||||||
Total oil (Mbbls/d)1 | 76 | 81 | 75 | 72 | 66 | 71 | 67 | 59 | 67 | 65 | |||||||||||||||||
Total (MMcfe/d) 1 | 3,546 | 3,410 | 3,557 | 3,676 | 3,548 | 3,621 | 3,648 | 3,506 | 3,417 | 3,141 | |||||||||||||||||
% change from prior period | +0.7 | -4.1 | -3.2 | +1.5 | +13.0 | -0.7 | +4.1 | +2.6 | +2.7 | +12.9 | |||||||||||||||||
1 Totals may not add due to rounding. | |||||||||||||||||||||||||||
Drilling activity in key North American resource plays | ||||||||||||||||||||||||||||||
Resource Play | Net Wells Drilled | |||||||||||||||||||||||||||||
2009 | 2008 | 2007 | ||||||||||||||||||||||||||||
YTD | Q3 | Q2 | Q1 | Full Year | Q4 | Q3 | Q2 | Q1 | Full Year | |||||||||||||||||||||
Natural Gas | ||||||||||||||||||||||||||||||
Jonah | 85 | 20 | 30 | 35 | 175 | 40 | 43 | 49 | 43 | 135 | ||||||||||||||||||||
Piceance | 113 | 25 | 35 | 53 | 328 | 70 | 94 | 81 | 83 | 286 | ||||||||||||||||||||
East Texas | 30 | 4 | 11 | 15 | 78 | 23 | 22 | 22 | 11 | 35 | ||||||||||||||||||||
Fort Worth | 23 | 1 | 6 | 16 | 83 | 21 | 21 | 20 | 21 | 75 | ||||||||||||||||||||
Greater Sierra | 42 | 17 | 10 | 15 | 106 | 14 | 29 | 27 | 36 | 109 | ||||||||||||||||||||
Cutbank Ridge | 56 | 18 | 18 | 20 | 82 | 17 | 17 | 24 | 24 | 93 | ||||||||||||||||||||
Bighorn | 52 | 17 | 14 | 21 | 64 | 5 | 11 | 18 | 30 | 62 | ||||||||||||||||||||
CBM | 316 | 37 | 1 | 278 | 698 | 359 | 78 | 10 | 251 | 1,079 | ||||||||||||||||||||
Shallow Gas | 436 | 55 | 45 | 336 | 1,195 | 383 | 233 | 83 | 496 | 1,914 | ||||||||||||||||||||
Total gas wells | 1,153 | 194 | 170 | 789 | 2,809 | 932 | 548 | 334 | 995 | 3,788 | ||||||||||||||||||||
Oil | ||||||||||||||||||||||||||||||
Foster Creek | 18 | 2 | 10 | 6 | 20 | 1 | 6 | 1 | 12 | 23 | ||||||||||||||||||||
Christina Lake | - | - | - | - | - | - | - | - | - | 3 | ||||||||||||||||||||
Pelican Lake | 5 | - | 1 | 4 | - | - | - | - | - | - | ||||||||||||||||||||
Weyburn | - | - | - | - | 21 | 3 | 4 | 5 | 9 | 37 | ||||||||||||||||||||
Total oil wells | 23 | 2 | 11 | 10 | 41 | 4 | 10 | 6 | 21 | 63 | ||||||||||||||||||||
Total | 1,176 | 196 | 181 | 799 | 2,850 | 936 | 558 | 340 | 1,016 | 3,851 | ||||||||||||||||||||
Natural gas and oil prices | ||||||||||||||||||||
Q3 2009 |
Q3
2008 | % ∆ | 9 months 2009 |
9 months
2008 | % ∆ | |||||||||||||||
Natural gas ($/MMBtu) | ||||||||||||||||||||
NYMEX | 3.39 | 10.24 | -67 | 3.92 | 9.73 | -60 | ||||||||||||||
EnCana Realized Gas Price1 ($/Mcf) | 7.31 | 7.94 | -8 | 7.18 | 8.17 | -12 | ||||||||||||||
Oil and NGLs ($/bbl) | ||||||||||||||||||||
WTI | 68.24 | 118.22 | -42 | 57.32 | 113.52 | -50 | ||||||||||||||
Western Canadian Select (WCS) | 58.06 | 100.22 | -42 | 48.47 | 93.16 | -48 | ||||||||||||||
Differential WTI/WCS | 10.18 | 18.00 | -43 | 8.85 | 20.36 | -57 | ||||||||||||||
EnCana Realized Liquids Price1 | 57.39 | 90.88 | -37 | 47.64 | 83.49 | -43 | ||||||||||||||
Chicago 3-2-1 Crack Spread ($/bbl) | 8.48 | 17.29 | -51 | 9.72 | 12.86 | -24 | ||||||||||||||
1 Realized prices include the impact of financial hedging. | ||||||||||||||||||||
Price risk management
Risk management positions at September 30, 2009 are presented in Note 17 to the unaudited Interim Consolidated Financial Statements. In the third quarter of 2009, EnCana’s commodity price risk management measures resulted in realized gains of approximately $913 million after tax, including a $916 million after-tax gain on natural gas and basis hedges and a $3 million after-tax loss on other hedges.
As of September 30, EnCana had hedged about 2 Bcf/d, of expected natural gas production for the 2010 gas year, which runs from November 1, 2009 to October 31, 2010, at an average NYMEX equivalent price of $6.08 per Mcf. EnCana also had 27,000 bbls/d of expected 2010 oil production hedged at an average fixed price of WTI $76.89 per bbl. This price hedging strategy increases certainty in cash flow to help EnCana meet its anticipated capital requirements and projected dividends. EnCana continually assesses its hedging needs and the opportunities available prior to establishing its capital program for the upcoming year.
Corporate developments
Split transaction preparation proceeding
Planning is on track to split EnCana into two independent companies: a pure-play natural gas company, EnCana, and an integrated oil company, Cenovus Energy Inc. A shareholders’ meeting to vote on the proposed transaction is set for November 25, 2009. Subject to the required shareholder and court approvals being obtained and the satisfaction of conditions, the company expects to complete the transaction on November 30, 2009.
The Arrangement Circular for the shareholders’ meeting has been mailed and is available on SEDAR’s website, www.sedar.com, on EDGAR’s website, www.sec.gov/edgar.shtml and on EnCana’s website, www.encana.com.
Fourth Quarter Dividends
EnCana intends that the initial combined dividends of EnCana and Cenovus for the fourth quarter of 2009, after the Arrangement becomes effective, will be equal to EnCana's current quarterly dividend of US$0.40 per share, to be equally apportioned between EnCana and Cenovus. It is anticipated that such dividends will be payable on December 31, 2009 to common shareholders of record, for each respective company, as of December 21, 2009. Following completion of the Arrangement, the declaration of dividends will be at the sole discretion of the EnCana Board and the Cenovus Board and no dividend policy has been adopted by either company.
EnCana completes more than $900 million of net divestitures to date in 2009
In August of 2009, EnCana completed the sale to Bonavista Energy Trust of approximately 409,000 net acres of non-core natural gas and oil producing properties for approximately $632 million. The transaction included property known as the Hoadley trend, which covers an expansive area in west-central Alberta. In early November, EnCana completed the sale of its Senlac heavy oil operation in west-central Saskatchewan, for about $83 million. In the first nine months of 2009, EnCana had net divestitures of approximately $902 million, which is in line with targeted 2009 divestitures of between $500 million and $1 billion.
EnCana 2009 guidance and guidance for post-split companies posted on encana.com
EnCana’s 2009 guidance, which does not account for the proposed split, has been updated and the company has posted individual 2010 guidance for the post-split EnCana and Cenovus. Guidance documents are posted on the company’s website at www.encana.com.
Financial strength
EnCana has a strong balance sheet, with 95 percent of outstanding debt composed of long-term, fixed-rate debt with an average remaining term of more than 13 years. The company has an upcoming debt maturity in 2010 of $200 million. At September 30, 2009, EnCana had available $4.3 billion in unused committed bank credit facilities. EnCana manages its financial strategy to achieve a strong investment grade credit rating. EnCana targets a debt to capitalization ratio of less than 40 percent and a debt to adjusted EBITDA ratio of less than 2.0 times. At September 30, 2009, the company’s debt to capitalization ratio was 25 percent and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.1 times. None of these EnCana debt measures include the debt securities arranged for Cenovus.
Cenovus Energy financing
On September 18, 2009, in preparation for the anticipated split transaction, Cenovus Energy Inc., currently a wholly owned subsidiary of EnCana, completed a private offering of debt securities for an aggregate principal amount of $3.5 billion in three tranches, which are exempt from registration requirements of the U.S. Securities Act of 1933 under Rule 144A and Regulation S. The net proceeds of the private offering were placed into an escrow account pending the completion of the split transaction. In addition, Cenovus has obtained commitments from a syndicate of banks to make available, pending the completion of the split transaction, a C$2 billion 3-year revolving credit facility and a C$500 million 364-day revolving credit facility, both for general corporate purposes. The use of these credit facilities by Cenovus is subject to customary conditions for credit facilities of this type.
2010 Preliminary Budgets
2010 post-split EnCana and Cenovus Energy budgets designed with flexibility
For 2010, EnCana and Cenovus have developed preliminary capital investment budgets aimed at maintaining financial strength and balance sheet flexibility through disciplined management of capital investment and operating expenses.
“The budgets for the two independent companies are designed to follow EnCana’s traditional investment principles. We employ a conservative and prudent approach and continually seek ways to reduce risk as we focus on our highest return opportunities in pursuit of enhancing the long-term value of every share,” Eresman said.
“While there are definite signs of a worldwide economic recovery, the commodity and financial markets continue to experience some degree of uncertainty. In order to make it easier for the individual executive teams to respond quickly to changing economic and investment circumstances, a high level of flexibility has been built into each company’s budget,” said Eresman.
It is expected that these preliminary budgets will be updated once the respective executive teams and boards of directors have had a better chance to refine individual strategies following the completion of the planned split transaction. The preliminary budgets are presented using EnCana’s current expectations and projections. The 2009 financial information for both Cenovus and post-split EnCana represents carved out data from EnCana projections including the operations, assets, liabilities and cash flows of the assets proposed for separation as well as a portion of the marketing and corporate functions of EnCana, which include some one-time transaction related costs for each company. The 2010 preliminary budget information in this news release also refers to the assets that are proposed for separation and the estimated revenues and costs associated with operating those assets.
Post-split EnCana – preliminary budget forecast summary
Post-split EnCana 2010 Preliminary Budget Forecast1 | ||||||
(US$ billions, excluding per share amounts) | 2010 Forecast | |||||
Cash flow | 4.0 – 4.6 | |||||
Cash flow per share ($ per share diluted) | 5.40 – 6.00 | |||||
Capital investment | 3.6 – 3.9 | |||||
Total production (Bcfe/d) after royalties | 3.2 – 3.3 | |||||
1 2010 based on NYMEX gas of $5.50 to $6.15 per Mcf and WTI oil of $65.00 to $85.00 per bbl and the US$/C$ at $0.85 to $0.96. Cash flow and free cash flow are non-GAAP measures. See Note 1 on page 9. | ||||||
EnCana – a leading unconventional natural gas company
“EnCana will continue to target being the best North American unconventional natural gas company. Our focus remains steadfast on being the lowest cost producer in all the fields where we operate as we employ a disciplined and methodical approach to unconventional natural gas development. We hold leading positions in key unconventional natural gas basins stretching from northeast British Columbia to east Texas and Louisiana,” Eresman said.
“In 2010, we plan to invest between $3.6 and $3.9 billion in capital and target natural gas production growth of about 10 percent. Major investments are aimed at the company’s large, early-stage opportunities in Haynesville and Horn River, as well as completion of the Deep Panuke project. Our budget is designed with the flexibility to adapt to changing economic conditions. Beyond what is currently planned, we have additional attractive investment opportunities that we may pursue if prices improve and market conditions warrant,” Eresman said.
Investment in the USA Division is expected to be about $1.9 billion, with natural gas production expected to grow about 16 percent to about 1.8 Bcf/d. Close to 40 percent of the USA budget is planned for continued production growth and land retention in the emerging Haynesville opportunity. Average 2010 production from the play is expected to be about 240 MMcf/d net to EnCana.
About $1.6 billion of investment is planned for the Canadian Division (currently the Canadian Foothills Division) and is focused on expanding the production infrastructure for longer-term growth in the Horn River basin, continued Deep Basin developments in the Cutbank Ridge (including the Montney formation) and Bighorn resource plays, the coalbed methane (CBM) resource play, plus completion of the Deep Panuke project. With sizable investments directed to longer-term projects such as Horn River and Deep Panuke, production in Canada is expected to remain steady in 2010. The lack of production growth, despite those investments, can be attributed in part to dispositions in 2009 of non-core assets in the Canadian Division and price sensitive royalty rates in Alberta.
Cenovus Energy – preliminary budget forecast summary
Cenovus Energy 2010 Preliminary Budget Forecast1 | ||||||
(US$ billions, excluding per share amounts) | 2010 Forecast | |||||
Cash flow | 2.3 – 2.6 | |||||
Cash flow per share ($ per share diluted) | 3.10 – 3.50 | |||||
Capital investment | 2.0 – 2.3 | |||||
Foster Creek & Christina Lake oil production (bbls/d) after royalties | 49,000 – 51,500 | |||||
1 2010 based on WTI oil of $65.00 to $85.00 per bbl, a Chicago 3-2-1 crack spread of $7.50 to $9.50 per bbl, NYMEX gas of $5.50 to $6.15 per Mcf and the US$/C$ at $0.85 to $0.96. Cash flow and free cash flow are non-GAAP measures. See Note 1 on page 9. | ||||||
“Cenovus Energy’s expansive, high-quality bitumen reservoirs and cost-efficient refineries offer significant opportunities for our integrated oil company to deliver long-term shareholder value for years ahead. Cenovus has 1.4 million acres of existing, high-quality leases, which the company estimates contain approximately 40 billion barrels of original bitumen in place. In 2010, we plan a year of substantial investment both upstream and downstream as we set the stage for significant future growth. About 40 percent of our capital in 2010 is directed to building productive capacity that will provide growth beyond 2010,” said Brian Ferguson, EnCana’s Chief Financial Officer and designated President & Chief Executive Officer of Cenovus.
Cenovus’s $2.0 to $2.3 billion of capital investment in 2010 is focused on increased development of the Foster Creek and Christina Lake enhanced oil operations, where 2010 production is expected to increase by 15 to 20 percent, and continued construction of the CORE project at Wood River.
Major capital investment in Cenovus’s upstream operations in 2010 will help set the stage for future phases of significant production growth. Cenovus plans to invest about $550 million in upstream production capacity expansions, largely at Christina Lake. Construction of Christina Lake’s phase C is on schedule and on budget and is expected to add about 40,000 bbls/d (20,000 bbls/d net to Cenovus) of capacity, with first production forecast in late 2011. The integrated oil business partners have sanctioned Christina Lake’s phase D and construction on this 40,000 bbls/d (20,000 bbls/d net to Cenovus) expansion is expected to begin in 2010, with first production expected in 2013. Regulatory applications for Christina Lake phases E, F and G have also been filed, with each expansion designed to add approximately 40,000 bbls/d (20,000 bbls/d net to Cenovus) of productive capacity. Ultimately, Christina Lake is expected to have productive capacity in excess of 200,000 bbls/d (100,000 bbls/d net to Cenovus).
At Foster Creek, regulatory applications have been filed for phases F, G and H, which would each add 30,000 bbls/d of capacity, taking total expected capacity to 210,000 bbls/d (105,000 bbls/d net to Cenovus). Foster Creek and Christina Lake combined are expected to have the potential to produce more than 400,000 bbls/d (200,000 bbls/d net to Cenovus) when fully developed.
Close to one-quarter of the 2010 Cenovus capital investment, about $500 million, will be directed to the final stages of construction of the CORE project at the Wood River refinery. The CORE project is more than 65 percent complete as of the end of October and is expected to come on stream in 2011. The project is expected to increase refining capacity by 50,000 bbls/d to 356,000 bbls/d (178,000 bbls/d net to Cenovus), and more than double heavy crude oil refining capacity to 240,000 bbls/d (120,000 bbls/d net to Cenovus). Each of these enhancements is expected to increase Wood River’s operating cash flow and improve refining margins.
Cenovus plans to invest about $700 million in Canadian Plains natural gas and oil production which is expected to generate strong operating cash flow, estimated in the range of $1.9 to $2.3 billion in 2010. These assets are a reliable source of free cash flow that will help fund future growth of enhanced oil production. Cenovus’s extensive, low-cost shallow gas production also provides a natural price hedge for the natural gas volumes consumed at the company’s enhanced oil projects and refineries.
Cenovus expected to use Canadian reporting protocols
For purposes of consistency, and in keeping with EnCana’s historical reporting, all information is stated in U.S. dollars unless otherwise noted and follows U.S. protocols, which report natural gas and oil production, sales and reserves on an after-royalty basis. EnCana will continue to report using these protocols. Following the completion of the split transaction, Cenovus expects to report its results in Canadian dollars and its volumes on a before-royalty basis. This change in reporting is expected to commence with the first quarter of 2010. Each company has chosen its reporting protocols to facilitate an easier comparison with its respective industry peers.
CONFERENCE CALL TODAY |
11 a.m. Mountain Time (1 p.m. Eastern Time) |
EnCana will host a conference call today Thursday, November 12, 2009 starting at 11:00 a.m. MT (1:00 p.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 1:00 p.m. MT on November 12 until midnight November 19, 2009 by dialing (800) 695-9469 or (402) 220-0618 and entering passcode 26580754. |
A live audio webcast of the conference call will also be available via EnCana’s website, www.encana.com, under Investor Relations. The webcast will be archived for approximately 90 days. |
NOTE 1: Non-GAAP measures
This news release contains references to non-GAAP measures as follows:
- Cash flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows, in this news release and interim financial statements.
- Free cash flow is a non-GAAP measure that EnCana defines 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.
- Operating earnings is a non-GAAP measure that shows 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 recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates. Management believes that these 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.
- Capitalization is a non-GAAP measure defined as debt plus shareholders’ equity. Debt to capitalization and debt to adjusted EBITDA are two ratios which management uses to steward the company’s overall debt position as measures of the company’s overall financial strength.
- Adjusted EBITDA is a non-GAAP measure defined as net earnings 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.
These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding EnCana’s liquidity and its ability to generate funds to finance its operations.
EnCana Corporation
With an enterprise value of approximately $50 billion, EnCana is a leading North American unconventional natural gas and integrated oil company. By partnering with employees, community organizations and other businesses, EnCana contributes to the strength and sustainability of the communities where it operates. EnCana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.
ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION – EnCana's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to EnCana by Canadian securities regulatory authorities which permits it to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by EnCana may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). EnCana’s reserves quantities represent net proved reserves calculated using the standards contained in Regulation S-X of the U.S. Securities and Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading "Note Regarding Reserves Data and Other Oil and Gas Information" in EnCana's Annual Information Form.
In this news release, certain crude oil and NGLs volumes have been converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). Also, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head.
ADVISORY REGARDING FORWARD-LOOKING STATEMENTS – In the interests of providing EnCana shareholders and potential investors with information regarding EnCana, including management’s assessment of EnCana’s and its subsidiaries’ future plans and operations, certain statements contained in this news release are forward-looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as “forward-looking statements.” Forward-looking statements in this news release include, but are not limited to: future economic and operating performance (including per share growth, debt to capitalization ratio, debt to adjusted EBITDA ratio, sustainable growth and returns, free cash flow, cash flow, cash flow per share, operating earnings and increases in net asset value); projections contained in the company’s and Cenovus’s guidance forecasts and the anticipated ability to meet the company’s and Cenovus’s guidance forecasts; anticipated life of proved reserves; anticipated growth and success of resource plays and the expected characteristics of resource plays; anticipated production and drilling in the Horn River and Haynesville areas; anticipated 2010 budgets for EnCana and Cenovus (including cash flow, cash flow per share, free cash flow, capital investment, divestitures and total production); anticipated allocation of capital for EnCana and Cenovus in 2010, including among various projects; the potential success of such projects as Deep Panuke, Cutbank Ridge, Bighorn and CORE at Wood River; the ability of enhancements at Wood River to increase cash flow and improve refining margins; anticipated capacities at Foster Creek and Christina Lake; planned expansion of in-situ oil production; anticipated crude oil and natural gas prices, including basis differentials for various regions; anticipated expansion and production for various phases at Foster Creek and Christina Lake; anticipated divestitures; potential dividends; anticipated success of EnCana’s price risk management strategy; anticipated hedging gains; potential demand for natural gas; anticipated drilling; estimates of original bitumen in place; potential capital expenditures and investment; potential oil, natural gas and NGLs production in 2009 and beyond; anticipated plans to bring production back on in the event of the recovery of natural gas prices; anticipated costs and cost reductions; the company’s plans for splitting into two independent companies and the conditions which may be required therefor; and references to potential exploration. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the company’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These assumptions, risks and uncertainties include, among other things: risks associated with the ability to obtain any necessary approvals, waivers, consents, court orders and other requirements necessary or desirable to permit or facilitate the planned split transaction (including regulatory and shareholder approvals); the risk that any applicable conditions of the planned split transaction may not be satisfied; volatility of and assumptions regarding oil and gas prices; assumptions based upon the company’s current guidance, as well as assumptions based upon 2010 EnCana and Cenovus guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the company’s marketing operations, including credit risks; imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved reserves; the ability of the company and ConocoPhillips to successfully manage and operate the integrated North American oil business and the ability of the parties to obtain necessary regulatory approvals; 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 crude oil; risks associated with technology; the company’s ability to replace and expand oil and gas reserves; its ability to generate sufficient cash flow from operations to meet its current and future obligations; its ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the company’s ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which the company operates; the risk of war, hostilities, civil insurrection and instability affecting countries in which the company operates and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the company; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. Although EnCana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive.
Forward-looking information respecting anticipated 2009 cash flow for EnCana is based upon achieving average production of oil and gas for 2009 of approximately 4.4 to 4.8 Bcfe/d, year-to-date actuals and forward curve estimates for commodity prices and U.S./Canadian dollar foreign exchange rate as of September 30, 2009 and an average number of outstanding shares for EnCana of approximately 750 million. Forward-looking information respecting anticipated 2010 cash flow for EnCana is based upon achieving average production of oil and gas for 2010 of approximately 3.2 to 3.3 Bcfe/d, forward curve estimates for commodity prices and an estimated U.S./Canadian dollar foreign exchange rate of $0.85 to $0.96 and an average number of outstanding shares for EnCana of approximately 750 million. Forward-looking information respecting anticipated 2010 cash flow for Cenovus is based upon achieving average production of oil and NGLs for 2010 of approximately 105,000 to 111,500 bbls/d and average production of natural gas for 2010 of approximately 720 to 740 MMcf/d, forward curve estimates for commodity prices and an estimated U.S./Canadian dollar foreign exchange rate of $0.85 to $0.96 and an average number of outstanding shares for Cenovus of approximately 750 million. Assumptions relating to forward-looking statements generally include EnCana’s current expectations and projections made by the company in light of, and generally consistent with, its historical experience and its perception of historical trends, as well as expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this news release.
Furthermore, the forward-looking statements contained in this news release are made as of the date of this news release, and, except as required by law, EnCana does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.
Further information on EnCana Corporation is available on the company’s website, www.encana.com, or by contacting:
FOR FURTHER INFORMATION: | ||
Investor contact: | Media contact: | |
EnCana Corporate Communications | ||
Paul Gagne | Alan Boras | |
Vice-President, Investor Relations | Manager, Media Relations | |
(403) 645-4737 | (403) 645-4747 | |
Ryder McRitchie | ||
Manager, Investor Relations | ||
(403) 645-2007 | ||
Susan Grey | ||
Manager, Investor Relations | ||
(403) 645-4751 | ||
EnCana Corporation
Interim Consolidated Financial Statements
(unaudited)
For the period ended September 30, 2009
(U.S. Dollars)
Consolidated Statement of Earnings (unaudited) | |||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||||||||||
($ millions, except per share amounts) | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||
Revenues, Net of Royalties | (Note 5) | $ | 3,881 | $ | 10,849 | $ | 12,251 | $ | 23,705 | ||||||||||||||||||||
Expenses | (Note 5) | ||||||||||||||||||||||||||||
Production and mineral taxes | 29 | 138 | 122 | 406 | |||||||||||||||||||||||||
Transportation and selling | 355 | 443 | 969 | 1,282 | |||||||||||||||||||||||||
Operating | 510 | 521 | 1,575 | 1,926 | |||||||||||||||||||||||||
Purchased product | 1,747 | 3,445 | 4,341 | 8,720 | |||||||||||||||||||||||||
Depreciation, depletion and amortization | 992 | 1,095 | 2,955 | 3,227 | |||||||||||||||||||||||||
Administrative | 145 | 18 | 350 | 399 | |||||||||||||||||||||||||
Interest, net | (Note 7) | 155 | 147 | 388 | 428 | ||||||||||||||||||||||||
Accretion of asset retirement obligation | (Note 12) | 20 | 20 | 56 | 61 | ||||||||||||||||||||||||
Foreign exchange (gain) loss, net | (Note 8) | (114 | ) | 110 | (116 | ) | 170 | ||||||||||||||||||||||
(Gain) loss on divestitures | (Note 6) | (1 | ) | (124 | ) | 1 | (141 | ) | |||||||||||||||||||||
3,838 | 5,813 | 10,641 | 16,478 | ||||||||||||||||||||||||||
Net Earnings Before Income Tax | 43 | 5,036 | 1,610 | 7,227 | |||||||||||||||||||||||||
Income tax expense | (Note 9) | 18 | 1,483 | 384 | 2,360 | ||||||||||||||||||||||||
Net Earnings | $ | 25 | $ | 3,553 | $ | 1,226 | $ | 4,867 | |||||||||||||||||||||
Net Earnings per Common Share | (Note 16) | ||||||||||||||||||||||||||||
Basic | $ | 0.03 | $ | 4.74 | $ | 1.63 | $ | 6.49 | |||||||||||||||||||||
Diluted | $ | 0.03 | $ | 4.73 | $ | 1.63 | $ | 6.47 | |||||||||||||||||||||
See accompanying Notes to Consolidated Financial Statements. | |||||||||||||||||||||||||||||
Consolidated Statement of Retained Earnings (unaudited) | |||||||||||||||||||||||||
Nine Months Ended | |||||||||||||||||||||||||
September 30, | |||||||||||||||||||||||||
($ millions) | 2009 | 2008 | |||||||||||||||||||||||
Retained Earnings, Beginning of Year | $ | 17,584 | $ | 13,082 | |||||||||||||||||||||
Net Earnings | 1,226 | 4,867 | |||||||||||||||||||||||
Dividends on Common Shares | (901 | ) | (899 | ) | |||||||||||||||||||||
Charges for Normal Course Issuer Bid | (Note 13) | - | (243 | ) | |||||||||||||||||||||
Retained Earnings, End of Period | $ | 17,909 | $ | 16,807 | |||||||||||||||||||||
Consolidated Statement of Comprehensive Income (unaudited) | |||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||||||
($ millions) | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||
Net Earnings | $ | 25 | $ | 3,553 | $ | 1,226 | $ | 4,867 | |||||||||||||||||
Other Comprehensive Income, Net of Tax | |||||||||||||||||||||||||
Foreign Currency Translation Adjustment | 985 | (430 | ) | 1,630 | (782 | ) | |||||||||||||||||||
Comprehensive Income | $ | 1,010 | $ | 3,123 | $ | 2,856 | $ | 4,085 | |||||||||||||||||
Consolidated Statement of Accumulated Other Comprehensive Income (unaudited) | |||||||||||||||||||||||||
Nine Months Ended | |||||||||||||||||||||||||
September 30, | |||||||||||||||||||||||||
($ millions) | 2009 | 2008 | |||||||||||||||||||||||
Accumulated Other Comprehensive Income, Beginning of Year | $ | 833 | $ | 3,063 | |||||||||||||||||||||
Foreign Currency Translation Adjustment | 1,630 | (782 | ) | ||||||||||||||||||||||
Accumulated Other Comprehensive Income, End of Period | $ | 2,463 | $ | 2,281 | |||||||||||||||||||||
See accompanying Notes to Consolidated Financial Statements. | |||||||||||||||||||||||||
Consolidated Balance Sheet (unaudited) | ||||||||||||||||
As at | As at | |||||||||||||||
September 30, | December 31, | |||||||||||||||
($ millions) | 2009 | 2008 | ||||||||||||||
Assets | ||||||||||||||||
Current Assets | ||||||||||||||||
Cash and cash equivalents | $ | 1,376 | $ | 383 | ||||||||||||
Accounts receivable and accrued revenues | 1,596 | 1,568 | ||||||||||||||
Current portion of partnership contribution receivable | 325 | 313 | ||||||||||||||
Risk management | (Note 17) | 586 | 2,818 | |||||||||||||
Inventories | (Note 10) | 727 | 520 | |||||||||||||
4,610 | 5,602 | |||||||||||||||
Property, Plant and Equipment, net | (Note 5) | 38,481 | 35,424 | |||||||||||||
Restricted Cash | (Note 4) | 3,619 | - | |||||||||||||
Investments and Other Assets | 936 | 727 | ||||||||||||||
Partnership Contribution Receivable | 2,589 | 2,834 | ||||||||||||||
Risk Management | (Note 17) | 31 | 234 | |||||||||||||
Goodwill | 2,703 | 2,426 | ||||||||||||||
(Note 5) | $ | 52,969 | $ | 47,247 | ||||||||||||
Liabilities and Shareholders' Equity | ||||||||||||||||
Current Liabilities | ||||||||||||||||
Accounts payable and accrued liabilities | $ | 2,947 | $ | 2,871 | ||||||||||||
Income tax payable | 880 | 424 | ||||||||||||||
Current portion of partnership contribution payable | 320 | 306 | ||||||||||||||
Risk management | (Note 17) | 12 | 43 | |||||||||||||
Current portion of long-term debt | (Note 11) | 200 | 250 | |||||||||||||
4,359 | 3,894 | |||||||||||||||
Long-Term Debt | (Note 11) | 7,963 | 8,755 | |||||||||||||
Cenovus Notes | (Note 4) | 3,468 | - | |||||||||||||
Other Liabilities | 1,083 | 576 | ||||||||||||||
Partnership Contribution Payable | 2,615 | 2,857 | ||||||||||||||
Risk Management | (Note 17) | 90 | 7 | |||||||||||||
Asset Retirement Obligation | (Note 12) | 1,412 | 1,265 | |||||||||||||
Future Income Taxes | 7,020 | 6,919 | ||||||||||||||
28,010 | 24,273 | |||||||||||||||
Shareholders' Equity | ||||||||||||||||
Share capital | (Note 13) | 4,581 | 4,557 | |||||||||||||
Paid in surplus | (Note 13) | 6 | - | |||||||||||||
Retained earnings | 17,909 | 17,584 | ||||||||||||||
Accumulated other comprehensive income | 2,463 | 833 | ||||||||||||||
Total Shareholders' Equity | 24,959 | 22,974 | ||||||||||||||
$ | 52,969 | $ | 47,247 | |||||||||||||
See accompanying Notes to Consolidated Financial Statements. |
Consolidated Statement of Cash Flows (unaudited) | |||||||||||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||||||||||
($ millions) | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||
Operating Activities | |||||||||||||||||||||||||||||
Net earnings | $ | 25 | $ | 3,553 | $ | 1,226 | $ | 4,867 | |||||||||||||||||||||
Depreciation, depletion and amortization | 992 | 1,095 | 2,955 | 3,227 | |||||||||||||||||||||||||
Future income taxes | (Note 9) | (294 | ) | 1,418 | (488 | ) | 1,491 | ||||||||||||||||||||||
Cash tax on sale of assets | - | 25 | - | 25 | |||||||||||||||||||||||||
Unrealized (gain) loss on risk management | (Note 17) | 1,384 | (3,050 | ) | 2,391 | (1,639 | ) | ||||||||||||||||||||||
Unrealized foreign exchange (gain) loss | (100 | ) | 84 | (149 | ) | 149 | |||||||||||||||||||||||
Accretion of asset retirement obligation | (Note 12) | 20 | 20 | 56 | 61 | ||||||||||||||||||||||||
(Gain) loss on divestitures | (Note 6) | (1 | ) | (124 | ) | 1 | (141 | ) | |||||||||||||||||||||
Other | 53 | (212 | ) | 184 | 47 | ||||||||||||||||||||||||
Net change in other assets and liabilities | 10 | (19 | ) | 33 | (283 | ) | |||||||||||||||||||||||
Net change in non-cash working capital | 608 | 268 | 274 | (992 | ) | ||||||||||||||||||||||||
Cash From Operating Activities | 2,697 | 3,058 | 6,483 | 6,812 | |||||||||||||||||||||||||
Investing Activities | |||||||||||||||||||||||||||||
Capital expenditures | (Note 5) | (1,353 | ) | (2,466 | ) | (4,028 | ) | (6,369 | ) | ||||||||||||||||||||
Proceeds from divestitures | (Note 6) | 977 | 442 | 1,030 | 593 | ||||||||||||||||||||||||
Cash tax on sale of assets | (Note 6) | - | (25 | ) | - | (25 | ) | ||||||||||||||||||||||
Corporate acquisition | (Note 6) | - | - | (24 | ) | - | |||||||||||||||||||||||
Restricted cash | (Note 4) | (3,619 | ) | - | (3,619 | ) | - | ||||||||||||||||||||||
Net change in investments and other | 80 | (157 | ) | (90 | ) | (166 | ) | ||||||||||||||||||||||
Net change in non-cash working capital | 64 | (120 | ) | (215 | ) | 71 | |||||||||||||||||||||||
Cash (Used in) Investing Activities | (3,851 | ) | (2,326 | ) | (6,946 | ) | (5,896 | ) | |||||||||||||||||||||
Financing Activities | |||||||||||||||||||||||||||||
Net issuance (repayment) of revolving long-term debt | (726 | ) | (116 | ) | (1,391 | ) | 251 | ||||||||||||||||||||||
Issuance of long-term debt | (Note 11) | - | - | 496 | 723 | ||||||||||||||||||||||||
Issuance of Cenovus Notes | (Note 4) | 3,468 | - | 3,468 | - | ||||||||||||||||||||||||
Repayment of long-term debt | (250 | ) | (468 | ) | (250 | ) | (664 | ) | |||||||||||||||||||||
Issuance of common shares | (Note 13) | 2 | 2 | 23 | 78 | ||||||||||||||||||||||||
Purchase of common shares | (Note 13) | - | - | - | (326 | ) | |||||||||||||||||||||||
Dividends on common shares | (300 | ) | (299 | ) | (901 | ) | (899 | ) | |||||||||||||||||||||
Cash From (Used in) Financing Activities | 2,194 | (881 | ) | 1,445 | (837 | ) | |||||||||||||||||||||||
Foreign Exchange Gain (Loss) on Cash and Cash | |||||||||||||||||||||||||||||
Equivalents Held in Foreign Currency | 6 | (7 | ) | 11 | (10 | ) | |||||||||||||||||||||||
Increase (Decrease) in Cash and Cash Equivalents | 1,046 | (156 | ) | 993 | 69 | ||||||||||||||||||||||||
Cash and Cash Equivalents, Beginning of Period | 330 | 778 | 383 | 553 | |||||||||||||||||||||||||
Cash and Cash Equivalents, End of Period | $ | 1,376 | $ | 622 | $ | 1,376 | $ | 622 | |||||||||||||||||||||
See accompanying Notes to Consolidated Financial Statements. | |||||||||||||||||||||||||||||
Notes to Consolidated Financial Statements (unaudited)
(All amounts in $ millions unless otherwise specified)
1. Basis of Presentation
The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries ("EnCana" or the "Company"), and are presented in accordance with Canadian generally accepted accounting principles ("GAAP"). EnCana's operations are in the business of the exploration for, the development of, and the production and marketing of natural gas, crude oil and natural gas liquids ("NGLs"), refining operations and power generation operations.
The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2008, except as noted below. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. Certain information and disclosures normally required to be included in the notes to the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, the interim Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2008.
2. Changes in Accounting Policies and Practices
On January 1, 2009, the Company adopted the following Canadian Institute of Chartered Accountants ("CICA") Handbook section:
- "Goodwill and Intangible Assets", Section 3064. The new standard replaces the previous goodwill and intangible asset standard and revises the requirement for recognition, measurement, presentation and disclosure of intangible assets. The adoption of this standard has had no material impact on EnCana's Consolidated Financial Statements.
3. Recent Accounting Pronouncements
In February 2008, the CICA's Accounting Standards Board confirmed that International Financial Reporting Standards ("IFRS") will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. EnCana will be required to report its results in accordance with IFRS beginning in 2011. The Company has developed a changeover plan to complete the transition to IFRS by January 1, 2011, including the preparation of required comparative information. EnCana's IFRS changeover plan also addresses the requirements of the entities that result from the proposed corporate reorganization (See Note 4). The impact of IFRS on the Company's Consolidated Financial Statements is not reasonably determinable at this time.
As of January 1, 2011, EnCana will be required to adopt the following CICA Handbook sections:
- "Business Combinations", Section 1582, which replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of earnings. The adoption of this standard will impact the accounting treatment of future business combinations.
- "Consolidated Financial Statements", Section 1601, which together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard should not have a material impact on EnCana's Consolidated Financial Statements.
- "Non-controlling Interests", Section 1602, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard should not have a material impact on EnCana's Consolidated Financial Statements.
4. Proposed Corporate Reorganization
In May 2008, EnCana's Board of Directors unanimously approved a proposal to split EnCana into two independent energy companies – one a natural gas company and the other an integrated oil company. The proposed corporate reorganization (the “Arrangement”) was expected to close in early January 2009.
In October 2008, EnCana announced the proposed Arrangement would be delayed until the global debt and equity markets regained stability.
On September 10, 2009, EnCana's Board of Directors unanimously approved plans to proceed with the proposed Arrangement. The proposed Arrangement is expected to be implemented through a court approved Plan of Arrangement and is subject to shareholder and regulatory approvals. The reorganization would result in two publicly traded entities with the names of Cenovus Energy Inc. and EnCana Corporation. Under the Arrangement, EnCana Shareholders will receive one New EnCana Common Share and one Cenovus Energy Inc. Common Share in exchange for each EnCana Common Share held.
Subject to court and shareholder approval, EnCana expects to complete the reorganization on November 30, 2009 following a Shareholders' meeting to vote on the proposed Plan of Arrangement to be held on November 25, 2009.
In conjunction with the proposed Arrangement, on September 18, 2009, EnCana's wholly owned subsidiary, Cenovus Energy Inc., completed a private offering of senior unsecured notes for an aggregate principal amount of $3,500 million issued in three tranches, which are exempt from the registration requirements of the U.S. Securities Act of 1933 under Rule 144A and Regulation S.
As at | |||||||||||
September 30, | |||||||||||
2009 | |||||||||||
U.S. Unsecured Notes | |||||||||||
4.5% due September 15, 2014 | $ | 800 | |||||||||
5.7% due October 15, 2019 | 1,300 | ||||||||||
6.75% due November 15, 2039 | 1,400 | ||||||||||
3,500 | |||||||||||
Debt Discounts and Financing Costs | (32 | ) | |||||||||
Cenovus Notes | 3,468 | ||||||||||
Amounts on Deposit in Escrow | 151 | ||||||||||
Restricted Cash | $ | 3,619 |
The notes are legal obligations of Cenovus Energy Inc. and have been disclosed on EnCana's Consolidated Balance Sheet as a separate long-term liability, net of financing costs. The net proceeds of the private offering were placed into an escrow account held by the escrow agent, The Bank of New York Mellon, pending the completion of the Arrangement, pursuant to the terms and conditions of an escrow and security agreement for the benefit of the note holders. The underwriters have deposited $3,468 million into the escrow account and Cenovus Energy Inc. has contributed $151 million into the escrow account so that, in aggregate, the total escrowed funds of $3,619 million will be sufficient to pay the special mandatory redemption price for the notes if the Arrangement does not proceed.
Pursuant to the terms and conditions of the escrow and security agreement, neither EnCana nor Cenovus Energy Inc., or any of their subsidiaries have any rights to, access to, control of, or dominion over, the escrowed funds before the completion of the Arrangement. All amounts in the escrow account will be released to Cenovus Energy Inc. by the escrow agent promptly after the escrow agent has been notified that the Arrangement has become effective and all of the escrow conditions have been satisfied. If the Arrangement does not proceed, the notes will be subject to a special mandatory redemption at a redemption price, payable from the amounts held in escrow, equal to 101 percent of the aggregate principal amount of the notes plus a penalty payment computed with reference to the expected accrued interest.
Additional information about the calculation of the special mandatory redemption price and other effects of the proposed Arrangement can be found in EnCana's Information Circular dated October 20, 2009. The cash in escrow has been disclosed as Restricted Cash on EnCana's Consolidated Balance Sheet and is not available for current use.
Subject to the completion of the Arrangement, Cenovus Energy Inc. has obtained commitments from a syndicate of banks to make available a C$2.0 billion three-year revolving credit facility and a C$500 million 364-day revolving credit facility.
5. Segmented Information
The Company's operating and reportable segments are as follows:
- Canada includes the Company’s exploration for, and development and production of natural gas, crude oil and NGLs and other related activities within the Canadian cost centre.
- USA includes the Company’s exploration for, and development and production of natural gas, NGLs and other related activities within the United States cost centre.
- Downstream Refining 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.
- Market Optimization is primarily responsible for the sale of the Company's proprietary production. These results are included in the Canada and USA segments. Market optimization activities include third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment.
- Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once amounts are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates.
Market Optimization sells substantially all of the Company's upstream production to third-party customers. Transactions between segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.
On December 31, 2008, EnCana updated its segmented reporting to present the upstream Canadian and United States cost centres and Downstream Refining as separate reportable segments. This resulted in EnCana presenting the Canadian portion of the Integrated Oil Division as part of the Canada segment. Previously, this was aggregated and presented in the Integrated Oil segment. Prior periods have been restated to reflect this presentation.
EnCana has a decentralized decision making and reporting structure. Accordingly, the Company is organized into Divisions as follows:
- Canadian Plains Division includes natural gas and crude oil exploration, development and production assets located in eastern Alberta and Saskatchewan.
- Canadian Foothills Division includes natural gas exploration, development and production assets located in western Alberta and British Columbia as well as the Company’s Canadian offshore assets.
- USA Division includes natural gas exploration, development and production assets located in the United States and comprises the USA segment described above.
- Integrated Oil Division is the combined total of Integrated Oil – Canada and Downstream Refining. Integrated Oil – Canada includes the Company’s exploration for, and development and production of bitumen using enhanced recovery methods. Integrated Oil – Canada is composed of EnCana’s interests in the FCCL Partnership jointly owned with ConocoPhillips, the Athabasca natural gas assets and other bitumen interests.
Results of Operations (For the three months ended September 30)
Segment and Geographic Information
Canada | USA | Downstream Refining | ||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 2,101 | $ | 2,776 | $ | 1,161 | $ | 1,477 | $ | 1,610 | $ | 2,699 | ||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||
Production and mineral taxes | 12 | 41 | 17 | 97 | - | - | ||||||||||||||||||||||||||||
Transportation and selling | 216 | 311 | 139 | 132 | - | - | ||||||||||||||||||||||||||||
Operating | 289 | 273 | 100 | 127 | 99 | 116 | ||||||||||||||||||||||||||||
Purchased product | (41 | ) | (45 | ) | - | - | 1,425 | 2,679 | ||||||||||||||||||||||||||
1,625 | 2,196 | 905 | 1,121 | 86 | (96 | ) | ||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 537 | 578 | 373 | 435 | 49 | 50 | ||||||||||||||||||||||||||||
Segment Income (Loss) | $ | 1,088 | $ | 1,618 | $ | 532 | $ | 686 | $ | 37 | $ | (146 | ) | |||||||||||||||||||||
Market Optimization | Corporate & Other | Consolidated | ||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 381 | $ | 840 | $ | (1,372 | ) | $ | 3,057 | $ | 3,881 | $ | 10,849 | |||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||
Production and mineral taxes | - | - | - | - | 29 | 138 | ||||||||||||||||||||||||||||
Transportation and selling | - | - | - | - | 355 | 443 | ||||||||||||||||||||||||||||
Operating | 11 | 8 | 11 | (3 | ) | 510 | 521 | |||||||||||||||||||||||||||
Purchased product | 363 | 811 | - | - | 1,747 | 3,445 | ||||||||||||||||||||||||||||
7 | 21 | (1,383 | ) | 3,060 | 1,240 | 6,302 | ||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 6 | 4 | 27 | 28 | 992 | 1,095 | ||||||||||||||||||||||||||||
Segment Income (Loss) | $ | 1 | $ | 17 | $ | (1,410 | ) | $ | 3,032 | 248 | 5,207 | |||||||||||||||||||||||
Administrative | 145 | 18 | ||||||||||||||||||||||||||||||||
Interest, net | 155 | 147 | ||||||||||||||||||||||||||||||||
Accretion of asset retirement obligation | 20 | 20 | ||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss, net | (114 | ) | 110 | |||||||||||||||||||||||||||||||
(Gain) loss on divestitures | (1 | ) | (124 | ) | ||||||||||||||||||||||||||||||
205 | 171 | |||||||||||||||||||||||||||||||||
Net Earnings Before Income Tax | 43 | 5,036 | ||||||||||||||||||||||||||||||||
Income tax expense | 18 | 1,483 | ||||||||||||||||||||||||||||||||
Net Earnings | $ | 25 | $ | 3,553 |
Results of Operations (For the three months ended September 30)
Product and Divisional Information
Canada Segment | |||||||||||||||||||||||||||||||||||||||||||
Canadian Plains | Canadian Foothills | Integrated Oil - Canada | Total | ||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 875 | $ | 1,213 | $ | 849 | $ | 1,168 | $ | 377 | $ | 395 | $ | 2,101 | $ | 2,776 | |||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 9 | 27 | 2 | 14 | 1 | - | 12 | 41 | |||||||||||||||||||||||||||||||||||
Transportation and selling | 48 | 106 | 40 | 57 | 128 | 148 | 216 | 311 | |||||||||||||||||||||||||||||||||||
Operating | 111 | 96 | 126 | 120 | 52 | 57 | 289 | 273 | |||||||||||||||||||||||||||||||||||
Purchased product | - | - | - | - | (41 | ) | (45 | ) | (41 | ) | (45 | ) | |||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 707 | $ | 984 | $ | 681 | $ | 977 | $ | 237 | $ | 235 | $ | 1,625 | $ | 2,196 | |||||||||||||||||||||||||||
Canadian Plains Division | |||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 487 | $ | 576 | $ | 385 | $ | 633 | $ | 3 | $ | 4 | $ | 875 | $ | 1,213 | |||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 3 | 14 | 6 | 13 | - | - | 9 | 27 | |||||||||||||||||||||||||||||||||||
Transportation and selling | 10 | 18 | 38 | 88 | - | - | 48 | 106 | |||||||||||||||||||||||||||||||||||
Operating | 56 | 44 | 55 | 51 | - | 1 | 111 | 96 | |||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 418 | $ | 500 | $ | 286 | $ | 481 | $ | 3 | $ | 3 | $ | 707 | $ | 984 | |||||||||||||||||||||||||||
Canadian Foothills Division | |||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 761 | $ | 982 | $ | 77 | $ | 172 | $ | 11 | $ | 14 | $ | 849 | $ | 1,168 | |||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 2 | 12 | - | 2 | - | - | 2 | 14 | |||||||||||||||||||||||||||||||||||
Transportation and selling | 38 | 54 | 2 | 3 | - | - | 40 | 57 | |||||||||||||||||||||||||||||||||||
Operating | 118 | 108 | 5 | 7 | 3 | 5 | 126 | 120 | |||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 603 | $ | 808 | $ | 70 | $ | 160 | $ | 8 | $ | 9 | $ | 681 | $ | 977 | |||||||||||||||||||||||||||
USA Division | |||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | ||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 1,084 | $ | 1,263 | $ | 53 | $ | 124 | $ | 24 | $ | 90 | $ | 1,161 | $ | 1,477 | |||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 12 | 86 | 5 | 11 | - | - | 17 | 97 | |||||||||||||||||||||||||||||||||||
Transportation and selling | 139 | 132 | - | - | - | - | 139 | 132 | |||||||||||||||||||||||||||||||||||
Operating | 78 | 59 | - | - | 22 | 68 | 100 | 127 | |||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 855 | $ | 986 | $ | 48 | $ | 113 | $ | 2 | $ | 22 | $ | 905 | $ | 1,121 | |||||||||||||||||||||||||||
Integrated Oil Division | |||||||||||||||||||||||||||||||||||||||||||
Oil * | Downstream Refining | Other * | Total | ||||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 345 | $ | 362 | $ | 1,610 | $ | 2,699 | $ | 32 | $ | 33 | $ | 1,987 | $ | 3,094 | |||||||||||||||||||||||||||
Expenses | |||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | - | - | - | - | 1 | - | 1 | - | |||||||||||||||||||||||||||||||||||
Transportation and selling | 120 | 137 | - | - | 8 | 11 | 128 | 148 | |||||||||||||||||||||||||||||||||||
Operating | 45 | 42 | 99 | 116 | 7 | 15 | 151 | 173 | |||||||||||||||||||||||||||||||||||
Purchased product | - | - | 1,425 | 2,679 | (41 | ) | (45 | ) | 1,384 | 2,634 | |||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 180 | $ | 183 | $ | 86 | $ | (96 | ) | $ | 57 | $ | 52 | $ | 323 | $ | 139 | ||||||||||||||||||||||||||
* | Oil and Other are included in Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties. |
Results of Operations (For the nine months ended September 30)
Segment and Geographic Information
Canada | USA | Downstream Refining | ||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 6,054 | $ | 8,089 | $ | 3,461 | $ | 4,356 | $ | 3,849 | $ | 7,514 | ||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||
Production and mineral taxes | 44 | 95 | 78 | 311 | - | - | ||||||||||||||||||||||||||||
Transportation and selling | 582 | 915 | 387 | 367 | - | - | ||||||||||||||||||||||||||||
Operating | 866 | 1,053 | 314 | 482 | 329 | 375 | ||||||||||||||||||||||||||||
Purchased product | (72 | ) | (126 | ) | - | - | 3,221 | 6,800 | ||||||||||||||||||||||||||
4,634 | 6,152 | 2,682 | 3,196 | 299 | 339 | |||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1,544 | 1,717 | 1,168 | 1,253 | 146 | 138 | ||||||||||||||||||||||||||||
Segment Income (Loss) | $ | 3,090 | $ | 4,435 | $ | 1,514 | $ | 1,943 | $ | 153 | $ | 201 | ||||||||||||||||||||||
Market Optimization | Corporate & Other | Consolidated | ||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 1,239 | $ | 2,112 | $ | (2,352 | ) | $ | 1,634 | $ | 12,251 | $ | 23,705 | |||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||
Production and mineral taxes | - | - | - | - | 122 | 406 | ||||||||||||||||||||||||||||
Transportation and selling | - | - | - | - | 969 | 1,282 | ||||||||||||||||||||||||||||
Operating | 26 | 27 | 40 | (11 | ) | 1,575 | 1,926 | |||||||||||||||||||||||||||
Purchased product | 1,192 | 2,046 | - | - | 4,341 | 8,720 | ||||||||||||||||||||||||||||
21 | 39 | (2,392 | ) | 1,645 | 5,244 | 11,371 | ||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 15 | 12 | 82 | 107 | 2,955 | 3,227 | ||||||||||||||||||||||||||||
Segment Income (Loss) | $ | 6 | $ | 27 | $ | (2,474 | ) | $ | 1,538 | 2,289 | 8,144 | |||||||||||||||||||||||
Administrative | 350 | 399 | ||||||||||||||||||||||||||||||||
Interest, net | 388 | 428 | ||||||||||||||||||||||||||||||||
Accretion of asset retirement obligation | 56 | 61 | ||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss, net | (116 | ) | 170 | |||||||||||||||||||||||||||||||
(Gain) loss on divestitures | 1 | (141 | ) | |||||||||||||||||||||||||||||||
679 | 917 | |||||||||||||||||||||||||||||||||
Net Earnings Before Income Tax | 1,610 | 7,227 | ||||||||||||||||||||||||||||||||
Income tax expense | 384 | 2,360 | ||||||||||||||||||||||||||||||||
Net Earnings | $ | 1,226 | $ | 4,867 |
Results of Operations (For the nine months ended September 30)
Product and Divisional Information
Canada Segment | ||||||||||||||||||||||||||||||||||||||||||
Canadian Plains | Canadian Foothills | Integrated Oil - Canada | Total | |||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 2,470 | $ | 3,629 | $ | 2,671 | $ | 3,432 | $ | 913 | $ | 1,028 | $ | 6,054 | $ | 8,089 | ||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 30 | 64 | 13 | 30 | 1 | 1 | 44 | 95 | ||||||||||||||||||||||||||||||||||
Transportation and selling | 163 | 330 | 115 | 167 | 304 | 418 | 582 | 915 | ||||||||||||||||||||||||||||||||||
Operating | 322 | 385 | 389 | 478 | 155 | 190 | 866 | 1,053 | ||||||||||||||||||||||||||||||||||
Purchased product | - | - | - | - | (72 | ) | (126 | ) | (72 | ) | (126 | ) | ||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 1,955 | $ | 2,850 | $ | 2,154 | $ | 2,757 | $ | 525 | $ | 545 | $ | 4,634 | $ | 6,152 | ||||||||||||||||||||||||||
Canadian Plains Division | ||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | |||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 1,483 | $ | 1,795 | $ | 978 | $ | 1,826 | $ | 9 | $ | 8 | $ | 2,470 | $ | 3,629 | ||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 11 | 32 | 19 | 32 | - | - | 30 | 64 | ||||||||||||||||||||||||||||||||||
Transportation and selling | 31 | 55 | 132 | 275 | - | - | 163 | 330 | ||||||||||||||||||||||||||||||||||
Operating | 158 | 191 | 161 | 191 | 3 | 3 | 322 | 385 | ||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 1,283 | $ | 1,517 | $ | 666 | $ | 1,328 | $ | 6 | $ | 5 | $ | 1,955 | $ | 2,850 | ||||||||||||||||||||||||||
Canadian Foothills Division | ||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | |||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 2,432 | $ | 2,891 | $ | 208 | $ | 494 | $ | 31 | $ | 47 | $ | 2,671 | $ | 3,432 | ||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 11 | 26 | 2 | 4 | - | - | 13 | 30 | ||||||||||||||||||||||||||||||||||
Transportation and selling | 109 | 158 | 6 | 9 | - | - | 115 | 167 | ||||||||||||||||||||||||||||||||||
Operating | 362 | 432 | 17 | 30 | 10 | 16 | 389 | 478 | ||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 1,950 | $ | 2,275 | $ | 183 | $ | 451 | $ | 21 | $ | 31 | $ | 2,154 | $ | 2,757 | ||||||||||||||||||||||||||
USA Division | ||||||||||||||||||||||||||||||||||||||||||
Gas | Oil & NGLs | Other | Total | |||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 3,246 | $ | 3,754 | $ | 132 | $ | 353 | $ | 83 | $ | 249 | $ | 3,461 | $ | 4,356 | ||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | 66 | 280 | 12 | 31 | - | - | 78 | 311 | ||||||||||||||||||||||||||||||||||
Transportation and selling | 387 | 367 | - | - | - | - | 387 | 367 | ||||||||||||||||||||||||||||||||||
Operating | 237 | 266 | - | - | 77 | 216 | 314 | 482 | ||||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 2,556 | $ | 2,841 | $ | 120 | $ | 322 | $ | 6 | $ | 33 | $ | 2,682 | $ | 3,196 | ||||||||||||||||||||||||||
Integrated Oil Division | ||||||||||||||||||||||||||||||||||||||||||
Oil * | Downstream Refining | Other * | Total | |||||||||||||||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | 2009 | 2008 | |||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 785 | $ | 898 | $ | 3,849 | $ | 7,514 | $ | 128 | $ | 130 | $ | 4,762 | $ | 8,542 | ||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes | - | - | - | - | 1 | 1 | 1 | 1 | ||||||||||||||||||||||||||||||||||
Transportation and selling | 286 | 380 | - | - | 18 | 38 | 304 | 418 | ||||||||||||||||||||||||||||||||||
Operating | 123 | 133 | 329 | 375 | 32 | 57 | 484 | 565 | ||||||||||||||||||||||||||||||||||
Purchased product | - | - | 3,221 | 6,800 | (72 | ) | (126 | ) | 3,149 | 6,674 | ||||||||||||||||||||||||||||||||
Operating Cash Flow | $ | 376 | $ | 385 | $ | 299 | $ | 339 | $ | 149 | $ | 160 | $ | 824 | $ | 884 | ||||||||||||||||||||||||||
* | Oil and Other are included in Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties. |
The following tables represent EnCana's and Cenovus Energy Inc.'s divisional information, post-Arrangement (See Note 4), excluding their respective share of the Market Optimization and Corporate and Other segments.
EnCana's divisions, post-Arrangement, will include Canadian Foothills and USA. Cenovus Energy Inc.'s divisions, post-Arrangement, will include Integrated Oil and Canadian Plains.
Results of Operations (For the three months ended September 30)
Divisional Information
EnCana | |||||||||||||||||||||||||||||
Canadian Foothills | USA | Total | |||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 849 | $ | 1,168 | $ | 1,161 | $ | 1,477 | $ | 2,010 | $ | 2,645 | |||||||||||||||||
Expenses | |||||||||||||||||||||||||||||
Production and mineral taxes | 2 | 14 | 17 | 97 | 19 | 111 | |||||||||||||||||||||||
Transportation and selling | 40 | 57 | 139 | 132 | 179 | 189 | |||||||||||||||||||||||
Operating | 126 | 120 | 100 | 127 | 226 | 247 | |||||||||||||||||||||||
Operating Cash Flow | $ | 681 | $ | 977 | $ | 905 | $ | 1,121 | $ | 1,586 | $ | 2,098 | |||||||||||||||||
Cenovus | |||||||||||||||||||||||||||||
Integrated Oil | Canadian Plains | Total | |||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 1,987 | $ | 3,094 | $ | 875 | $ | 1,213 | $ | 2,862 | $ | 4,307 | |||||||||||||||||
Expenses | |||||||||||||||||||||||||||||
Production and mineral taxes | 1 | - | 9 | 27 | 10 | 27 | |||||||||||||||||||||||
Transportation and selling | 128 | 148 | 48 | 106 | 176 | 254 | |||||||||||||||||||||||
Operating | 151 | 173 | 111 | 96 | 262 | 269 | |||||||||||||||||||||||
Purchased product | 1,384 | 2,634 | - | - | 1,384 | 2,634 | |||||||||||||||||||||||
Operating Cash Flow | $ | 323 | $ | 139 | $ | 707 | $ | 984 | $ | 1,030 | $ | 1,123 | |||||||||||||||||
Results of Operations (For the nine months ended September 30) | |||||||||||||||||||||||||||||
Divisional Information | |||||||||||||||||||||||||||||
EnCana | |||||||||||||||||||||||||||||
Canadian Foothills | USA | Total | |||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 2,671 | $ | 3,432 | $ | 3,461 | $ | 4,356 | $ | 6,132 | $ | 7,788 | |||||||||||||||||
Expenses | |||||||||||||||||||||||||||||
Production and mineral taxes | 13 | 30 | 78 | 311 | 91 | 341 | |||||||||||||||||||||||
Transportation and selling | 115 | 167 | 387 | 367 | 502 | 534 | |||||||||||||||||||||||
Operating | 389 | 478 | 314 | 482 | 703 | 960 | |||||||||||||||||||||||
Operating Cash Flow | $ | 2,154 | $ | 2,757 | $ | 2,682 | $ | 3,196 | $ | 4,836 | $ | 5,953 | |||||||||||||||||
Cenovus | |||||||||||||||||||||||||||||
Integrated Oil | Canadian Plains | Total | |||||||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||||||
Revenues, Net of Royalties | $ | 4,762 | $ | 8,542 | $ | 2,470 | $ | 3,629 | $ | 7,232 | $ | 12,171 | |||||||||||||||||
Expenses | |||||||||||||||||||||||||||||
Production and mineral taxes | 1 | 1 | 30 | 64 | 31 | 65 | |||||||||||||||||||||||
Transportation and selling | 304 | 418 | 163 | 330 | 467 | 748 | |||||||||||||||||||||||
Operating | 484 | 565 | 322 | 385 | 806 | 950 | |||||||||||||||||||||||
Purchased product | 3,149 | 6,674 | - | - | 3,149 | 6,674 | |||||||||||||||||||||||
Operating Cash Flow | $ | 824 | $ | 884 | $ | 1,955 | $ | 2,850 | $ | 2,779 | $ | 3,734 | |||||||||||||||||
Capital Expenditures | |||||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||
Capital | |||||||||||||||||||||||
Canadian Plains | $ | 104 | $ | 173 | $ | 332 | $ | 593 | |||||||||||||||
Canadian Foothills | 505 | 473 | 1,250 | 1,836 | |||||||||||||||||||
Integrated Oil - Canada | 111 | 142 | 340 | 494 | |||||||||||||||||||
Canada | 720 | 788 | 1,922 | 2,923 | |||||||||||||||||||
USA | 346 | 621 | 1,271 | 1,800 | |||||||||||||||||||
Downstream Refining | 266 | 133 | 695 | 310 | |||||||||||||||||||
Market Optimization | 1 | 4 | (2 | ) | 11 | ||||||||||||||||||
Corporate & Other | 5 | 42 | 38 | 111 | |||||||||||||||||||
1,338 | 1,588 | 3,924 | 5,155 | ||||||||||||||||||||
Acquisition Capital | |||||||||||||||||||||||
Canadian Plains | - | - | 1 | - | |||||||||||||||||||
Canadian Foothills | 8 | 28 | 82 | 120 | |||||||||||||||||||
Canada | 8 | 28 | 83 | 120 | |||||||||||||||||||
USA | 7 | 850 | 21 | 1,094 | |||||||||||||||||||
15 | 878 | 104 | 1,214 | ||||||||||||||||||||
Total | $ | 1,353 | $ | 2,466 | $ | 4,028 | $ | 6,369 | |||||||||||||||
On September 25, 2008, EnCana acquired certain land and property in Louisiana for approximately $101 million before closing adjustments. The purchase was facilitated by an unrelated party, Brown Haynesville Leasehold LLC ("Brown Haynesville"), which held the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. The relationship with Brown Haynesville represented an interest in a Variable Interest Entity ("VIE") from September 25, 2008 to March 24, 2009. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Haynesville. On March 24, 2009, when the arrangement with Brown Haynesville was completed, the assets were transferred to EnCana.
On July 23, 2008, EnCana acquired certain land and mineral interests in Louisiana for approximately $457 million before closing adjustments. The purchase was facilitated by an unrelated party, Brown Southwest Minerals LLC ("Brown Southwest"), which held the majority of the assets in trust for the Company in anticipation of a qualifying like kind exchange for U.S. tax purposes. On November 12, 2008, an unrelated party exercised an option to purchase certain interests as part of the above acquisition for approximately $157 million, reducing the qualifying like kind exchange to approximately $300 million. The relationship with Brown Southwest represented an interest in a VIE from July 23, 2008 to January 19, 2009. During this period, EnCana was the primary beneficiary of the VIE and consolidated Brown Southwest. On January 19, 2009, when the arrangement with Brown Southwest was completed, the assets were transferred to EnCana.
Property, Plant and Equipment and Total Assets by Segment
Property, Plant and Equipment | Total Assets | |||||||||||||||||
As at | As at | |||||||||||||||||
September 30, | December 31, | September 30, | December 31, | |||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||||
Canada | $ | 19,206 | $ | 17,082 | $ | 25,829 | $ | 23,419 | ||||||||||
USA | 13,588 | 13,541 | 14,649 | 14,635 | ||||||||||||||
Downstream Refining | 4,598 | 4,032 | 5,407 | 4,637 | ||||||||||||||
Market Optimization | 140 | 140 | 445 | 429 | ||||||||||||||
Corporate & Other | 949 | 629 | 6,639 | 4,127 | ||||||||||||||
Total | $ | 38,481 | $ | 35,424 | $ | 52,969 | $ | 47,247 |
On February 9, 2007, EnCana announced that it had entered into a 25 year lease agreement with a third party developer for The Bow office project. As at September 30, 2009, Corporate and Other Property, Plant and Equipment and Total Assets includes EnCana's accrual to date of $545 million ($252 million at December 31, 2008) related to this office project as an asset under construction.
On January 4, 2008, EnCana signed the contract for the design and construction of the Production Field Centre ("PFC") for the Deep Panuke project. As at September 30, 2009, Canada Property, Plant, and Equipment and Total Assets includes EnCana's accrual to date of $377 million ($199 million at December 31, 2008) related to this offshore facility as an asset under construction.
Corresponding liabilities for these projects are included in Other Liabilities in the Consolidated Balance Sheet. There is no effect on the Company's net earnings or cash flows related to the capitalization of The Bow office project or the Deep Panuke PFC.
6. Acquisitions and Divestitures
Acquisitions
On May 5, 2009, the Company acquired the common shares of Kerogen Resources Canada, ULC for net cash consideration of $24 million. The acquisition included $37 million of property, plant and equipment and the assumption of $6 million of current liabilities and $7 million of future income taxes. The operations are included in the Canadian Foothills Division.
Divestitures
Total year-to-date proceeds received on the sale of assets were $1,030 million (2008 - $593 million). The significant items are described below:
Canada and USA
In 2009, the Company completed the divestiture of mature conventional oil and natural gas assets for proceeds of $957 million (2008 - $218 million) in Canadian Foothills and $70 million (2008 - $123 million) in the USA.
Corporate and Other
In September 2008, the Company completed the sale of its interests in Brazil for net proceeds of $164 million resulting in a gain on sale of $124 million. After recording income tax of $25 million, EnCana recorded an after-tax gain of $99 million.
7. Interest, Net
Three Months Ended | Nine Months Ended | |||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Interest Expense - Long-Term Debt | $ | 125 | $ | 142 | $ | 366 | $ | 426 | ||||||||||||||
Interest Expense - Other * | 72 | 56 | 161 | 166 | ||||||||||||||||||
Interest Income * | (42 | ) | (51 | ) | (139 | ) | (164 | ) | ||||||||||||||
$ | 155 | $ | 147 | $ | 388 | $ | 428 | |||||||||||||||
* Interest Expense - Other and Interest Income are primarily due to the Partnership Contribution Payable and Receivable, respectively. |
8. Foreign Exchange (Gain) Loss, Net | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||
Unrealized Foreign Exchange (Gain) Loss on: | |||||||||||||||||||||
Translation of U.S. dollar debt issued from Canada * | $ | (485 | ) | $ | 205 | $ | (774 | ) | $ | 370 | |||||||||||
Translation of U.S. dollar partnership contribution receivable issued from Canada * | 254 | (119 | ) | 414 | (218 | ) | |||||||||||||||
Other Foreign Exchange (Gain) Loss on: | |||||||||||||||||||||
Monetary revaluations and settlements | 117 | 24 | 244 | 18 | |||||||||||||||||
$ | (114 | ) | $ | 110 | $ | (116 | ) | $ | 170 | ||||||||||||
* Reflects the current year change in foreign exchange rates calculated on the period end balance. | |||||||||||||||||||||
9. Income Taxes | |||||||||||||||||||||
The provision for income taxes is as follows: | |||||||||||||||||||||
Three Months Ended | Nine Months Ended | ||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||
Current | |||||||||||||||||||||
Canada | $ | 238 | $ | 40 | $ | 678 | $ | 446 | |||||||||||||
United States | 75 | - | 189 | 385 | |||||||||||||||||
Other Countries | (1 | ) | 25 | 5 | 38 | ||||||||||||||||
Total Current Tax | 312 | 65 | 872 | 869 | |||||||||||||||||
Future | (294 | ) | 1,418 | (488 | ) | 1,491 | |||||||||||||||
$ | 18 | $ | 1,483 | $ | 384 | $ | 2,360 | ||||||||||||||
10. Inventories | ||||||||||||||
As at | As at | |||||||||||||
September 30, | December 31, | |||||||||||||
2009 | 2008 | |||||||||||||
Product | ||||||||||||||
Canada | $ | 68 | $ | 46 | ||||||||||
USA | 6 | 8 | ||||||||||||
Downstream Refining | 513 | 323 | ||||||||||||
Market Optimization | 126 | 127 | ||||||||||||
Parts and Supplies | 14 | 16 | ||||||||||||
$ | 727 | 520 | ||||||||||||
11. Long-Term Debt | |||||||||||||||||
As at | As at | ||||||||||||||||
September 30, | December 31, | ||||||||||||||||
2009 | 2008 | ||||||||||||||||
Canadian Dollar Denominated Debt | |||||||||||||||||
Revolving credit and term loan borrowings | $ | 221 | $ | 1,410 | |||||||||||||
Unsecured notes | 1,166 | 1,020 | |||||||||||||||
1,387 | 2,430 | ||||||||||||||||
U.S. Dollar Denominated Debt | |||||||||||||||||
Revolving credit and term loan borrowings | 202 | 247 | |||||||||||||||
Unsecured notes * | 6,600 | 6,350 | |||||||||||||||
6,802 | 6,597 | ||||||||||||||||
Increase in Value of Debt Acquired | 52 | 49 | |||||||||||||||
Debt Discounts and Financing Costs | (78 | ) | (71 | ) | |||||||||||||
Current Portion of Long-Term Debt | (200 | ) | (250 | ) | |||||||||||||
$ | 7,963 | $ | 8,755 | ||||||||||||||
* Excluding Cenovus Notes (See Note 4). |
On May 4, 2009, EnCana completed a public offering in the United States of senior unsecured notes in the aggregate principal amount of US$500 million. The notes have a coupon rate of 6.5 percent and mature on May 15, 2019. The net proceeds of the offering were used to repay a portion of EnCana's bank and commercial paper indebtedness.
12. Asset Retirement Obligation
The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas assets and refining facilities:
As at | As at | ||||||||||||||
September 30, | December 31, | ||||||||||||||
2009 | 2008 | ||||||||||||||
Asset Retirement Obligation, Beginning of Year | $ | 1,265 | $ | 1,458 | |||||||||||
Liabilities Incurred | 19 | 54 | |||||||||||||
Liabilities Settled | (44 | ) | (115 | ) | |||||||||||
Liabilities Divested | (17 | ) | (38 | ) | |||||||||||
Change in Estimated Future Cash Flows | (8 | ) | 54 | ||||||||||||
Accretion Expense | 56 | 79 | |||||||||||||
Foreign Currency Translation | 141 | (227 | ) | ||||||||||||
Asset Retirement Obligation, End of Period | $ | 1,412 | $ | 1,265 |
13. Share Capital
September 30, 2009 | December 31, 2008 | |||||||||||||||||
(millions) | Number | Amount | Number | Amount | ||||||||||||||
Common Shares Outstanding, Beginning of Year | 750.4 | $ | 4,557 | 750.2 | $ | 4,479 | ||||||||||||
Common Shares Issued under Option Plans | 0.3 | 4 | 3.0 | 80 | ||||||||||||||
Common Shares Issued from PSU Trust | 0.5 | 19 | - | - | ||||||||||||||
Stock-Based Compensation | - | 1 | - | 11 | ||||||||||||||
Common Shares Purchased | - | - | (2.8 | ) | (13 | ) | ||||||||||||
Common Shares Outstanding, End of Period | 751.2 | $ | 4,581 | 750.4 | $ | 4,557 |
Performance Share Units ("PSUs")
In April 2009, the remaining 0.5 million Common Shares held in trust relating to EnCana's PSU plan were sold for total consideration of $25 million. Of the amount received, $19 million was credited to Share capital and $6 million to Paid in surplus, representing the excess consideration received over the original price of the Common Shares acquired by the trust. Effective May 15, 2009, the trust agreement was terminated.
Normal Course Issuer Bid
EnCana has received regulatory approval each year under Canadian securities laws to purchase Common Shares under seven consecutive Normal Course Issuer Bids ("Bids"). EnCana is entitled to purchase, for cancellation, up to approximately 75.0 million Common Shares under the renewed Bid which commenced on November 13, 2008 and terminates on November 12, 2009. To September 30, 2009, there have been no purchases under the current bid (2008 - 4.8 million Common Shares for approximately $326 million).
Stock Options
EnCana has stock-based compensation plans that allow employees to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were granted. Options granted under the plans are generally fully exercisable after three years and expire five years after the date granted. Options granted under predecessor and/or related company replacement plans expire up to 10 years from the date the options were granted.
The following tables summarize the information related to options to purchase Common Shares that do not have Tandem Share Appreciation Rights ("TSARs") attached to them at September 30, 2009. Information related to TSARs is included in Note 15.
Stock | Weighted | |||||||||||||
Outstanding, Beginning of Year | 0.5 | 11.62 | ||||||||||||
Exercised | (0.3 | ) | 11.59 | |||||||||||
Outstanding, End of Period | 0.2 | 11.84 | ||||||||||||
Exercisable, End of Period | 0.2 | 11.84 | ||||||||||||
Outstanding & Exercisable Options | ||||||||||||||
Range of Exercise Price (C$) |
Number of |
Weighted |
Weighted | |||||||||||
11.50 to 14.50 | 0.2 | 0.4 | 11.84 | |||||||||||
14. Capital Structure
The Company's capital structure consists of Shareholders' Equity plus Long-Term Debt, defined as the current and long-term portions of long-term debt. The Company's objectives when managing its capital structure are to:
i) | maintain financial flexibility to preserve EnCana's access to capital markets and its ability to meet its financial obligations; and | |||||
ii) | finance internally generated growth as well as potential acquisitions. |
The Company monitors its capital structure and short-term financing requirements using non-GAAP financial metrics consisting of Debt to Capitalization and Debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization ("EBITDA"). These metrics are used to steward the Company's overall debt position as measures of the Company's overall financial strength.
EnCana targets a Debt to Capitalization ratio of less than 40 percent. At September 30, 2009, EnCana's Debt to Capitalization ratio was 25 percent (December 31, 2008 - 28 percent) calculated as follows:
As at | ||||||||||||||||||
September 30, | December 31, | |||||||||||||||||
2009 | 2008 | |||||||||||||||||
Debt * | $ | 8,163 | $ | 9,005 | ||||||||||||||
Total Shareholders' Equity | 24,959 | 22,974 | ||||||||||||||||
Total Capitalization | $ | 33,122 | $ | 31,979 | ||||||||||||||
Debt to Capitalization ratio | 25% | 28% | ||||||||||||||||
* Excluding Cenovus Notes (See Note 4). |
EnCana targets a Debt to Adjusted EBITDA of less than 2.0 times. At September 30, 2009, Debt to Adjusted EBITDA was 1.1x (December 31, 2008 - 0.7x) calculated on a trailing twelve-month basis as follows:
As at | ||||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||
2009 | 2008 | |||||||||||||||||||
Debt * | $ | 8,163 | $ | 9,005 | ||||||||||||||||
Net Earnings | $ | 2,303 | $ | 5,944 | ||||||||||||||||
Add (deduct): | ||||||||||||||||||||
Interest, net | 546 | 586 | ||||||||||||||||||
Income tax expense | 657 | 2,633 | ||||||||||||||||||
Depreciation, depletion and amortization | 3,951 | 4,223 | ||||||||||||||||||
Accretion of asset retirement obligation | 74 | 79 | ||||||||||||||||||
Foreign exchange (gain) loss, net | 137 | 423 | ||||||||||||||||||
(Gain) loss on divestitures | 2 | (140 | ) | |||||||||||||||||
Adjusted EBITDA | $ | 7,670 | $ | 13,748 | ||||||||||||||||
Debt to Adjusted EBITDA | 1.1x | 0.7x | ||||||||||||||||||
* Excluding Cenovus Notes (See Note 4). |
EnCana has a long-standing practice of maintaining capital discipline, managing its capital structure and adjusting its capital structure according to market conditions to maintain flexibility while achieving the objectives stated above. To manage the capital structure, the Company may adjust capital spending, adjust dividends paid to shareholders, purchase shares for cancellation pursuant to normal course issuer bids, issue new shares, issue new debt or repay existing debt.
The Company's capital management objectives, evaluation measures and definitions have remained unchanged over the periods presented. EnCana is subject to certain financial covenants in its credit facility agreements and is in compliance with all financial covenants.
15. Compensation Plans
The following tables outline certain information related to EnCana's compensation plans at September 30, 2009. Additional information is contained in Note 19 of the Company's annual audited Consolidated Financial Statements for the year ended December 31, 2008.
A) Pensions
The following table summarizes the net benefit plan expense:
Three Months Ended | Nine Months Ended | ||||||||||||||||||||||
September 30, | September 30, | ||||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | ||||||||||||||||||||
Current Service Cost | $ | 4 | $ | 4 | $ | 11 | $ | 12 | |||||||||||||||
Interest Cost | 5 | 5 | 15 | 16 | |||||||||||||||||||
Expected Return on Plan Assets | (3 | ) | (4 | ) | (10 | ) | (14 | ) | |||||||||||||||
Amortization of Net Actuarial Losses | 3 | 1 | 7 | 3 | |||||||||||||||||||
Amortization of Past Service Costs | - | - | 1 | 1 | |||||||||||||||||||
Amortization of Transitional Obligation | - | - | 1 | (1 | ) | ||||||||||||||||||
Expense for Defined Contribution Plan | 11 | 10 | 33 | 30 | |||||||||||||||||||
Net Benefit Plan Expense | $ | 20 | $ | 16 | $ | 58 | $ | 47 | |||||||||||||||
For the nine months ended September 30, 2009, contributions of $6 million have been made to the defined benefit pension plans (2008 - $8 million).
B) Tandem Share Appreciation Rights ("TSARs")
The following table summarizes information related to the TSARs at September 30, 2009:
Outstanding TSARs | Weighted Average Exercise Price | |||||||||||
Canadian Dollar Denominated (C$) | ||||||||||||
Outstanding, Beginning of Year | 19,411,939 | 53.97 | ||||||||||
Granted | 3,973,660 | 55.35 | ||||||||||
Exercised - SARs | (1,802,205 | ) | 42.47 | |||||||||
Exercised - Options | (53,084 | ) | 34.41 | |||||||||
Forfeited | (373,317 | ) | 59.90 | |||||||||
Outstanding, End of Period | 21,156,993 | 55.16 | ||||||||||
Exercisable, End of Period | 12,451,333 | 51.17 | ||||||||||
For the period ended September 30, 2009, EnCana recorded compensation costs of $71 million related to the outstanding TSARs (2008 - $68 million).
C) Performance Tandem Share Appreciation Rights ("Performance TSARs")
The following table summarizes information related to the Performance TSARs at September 30, 2009:
Outstanding Performance TSARs | Weighted Average Exercise Price | |||||||||||
Canadian Dollar Denominated (C$) | ||||||||||||
Outstanding, Beginning of Year | 12,979,725 | 63.13 | ||||||||||
Granted | 7,751,720 | 55.31 | ||||||||||
Exercised - SARs | (128,300 | ) | 56.09 | |||||||||
Exercised - Options | (980 | ) | 56.09 | |||||||||
Forfeited | (1,929,541 | ) | 62.75 | |||||||||
Outstanding, End of Period | 18,672,624 | 59.97 | ||||||||||
Exercisable, End of Period | 3,793,229 | 60.46 | ||||||||||
For the period ended September 30, 2009, EnCana recorded compensation costs of $36 million related to the outstanding Performance TSARs (2008 - $42 million).
D) Share Appreciation Rights ("SARs")
The following table summarizes information related to the SARs at September 30, 2009:
Outstanding SARs | Weighted Average Exercise Price | ||||||||||||
Canadian Dollar Denominated (C$) | |||||||||||||
Outstanding, Beginning of Year | 1,285,065 | 72.13 | |||||||||||
Granted | 1,116,220 | 55.42 | |||||||||||
Forfeited | (49,975 | ) | 66.87 | ||||||||||
Outstanding, End of Period | 2,351,310 | 64.31 | |||||||||||
Exercisable, End of Period | 359,368 | 72.99 | |||||||||||
For the period ended September 30, 2009, EnCana recorded compensation costs of $3 million related to the outstanding SARs (2008 - nil).
E) Performance Share Appreciation Rights ("Performance SARs")
The following table summarizes information related to the Performance SARs at September 30, 2009:
Outstanding Performance SARs | Weighted Average Exercise Price | ||||||||||||
Canadian Dollar Denominated (C$) | |||||||||||||
Outstanding, Beginning of Year | 1,620,930 | 69.40 | |||||||||||
Granted | 2,140,440 | 55.31 | |||||||||||
Forfeited | (241,082 | ) | 67.94 | ||||||||||
Outstanding, End of Period | 3,520,288 | 60.93 | |||||||||||
Exercisable, End of Period | 297,174 | 69.40 | |||||||||||
For the period ended September 30, 2009, EnCana recorded compensation costs of $4 million related to the outstanding Performance SARs (2008 - nil).
F) Deferred Share Units ("DSUs")
The following table summarizes information related to the DSUs at September 30, 2009:
Outstanding DSUs | |||||||||||||
Canadian Dollar Denominated | |||||||||||||
Outstanding, Beginning of Year | 656,841 | ||||||||||||
Granted | 73,989 | ||||||||||||
Converted from HPR awards | 46,884 | ||||||||||||
Units, in Lieu of Dividends | 18,740 | ||||||||||||
Redeemed | (45,352 | ) | |||||||||||
Outstanding, End of Period | 751,102 | ||||||||||||
For the period ended September 30, 2009, EnCana recorded compensation costs of $8 million related to the outstanding DSUs (2008 - $7 million).
Employees have the option to convert either 25 or 50 percent of their annual High Performance Results ("HPR") award into DSUs. The number of DSUs is based on the value of the award divided by the closing value of EnCana's share price at the end of the performance period of the HPR award. DSUs vest immediately, can be redeemed in accordance with the terms of the agreement and expire on December 15 of the calendar year following the year of termination.
16. Per Share Amounts
The following table summarizes the Common Shares used in calculating Net Earnings per Common Share:
Three Months Ended | Nine Months Ended | ||||||||||||||||||
March 31, | June 30, | September 30, | September 30, | ||||||||||||||||
(millions) | 2009 | 2009 | 2009 | 2008 | 2009 | 2008 | |||||||||||||
Weighted Average Common Shares Outstanding - Basic | 750.5 | 751.0 | 751.2 | 750.3 | 750.9 | 750.0 | |||||||||||||
Effect of Dilutive Securities | 0.9 | 0.4 | 0.2 | 1.0 | 0.5 | 2.0 | |||||||||||||
Weighted Average Common Shares Outstanding - Diluted | 751.4 | 751.4 | 751.4 | 751.3 | 751.4 | 752.0 | |||||||||||||
17. Financial Instruments and Risk Management
EnCana's financial assets and liabilities include cash and cash equivalents, restricted cash, accounts receivable and accrued revenues, accounts payable and accrued liabilities, the partnership contribution receivable and payable, risk management assets and liabilities, long-term debt, and the Cenovus Notes. Risk management assets and liabilities arise from the use of derivative financial instruments. Fair values of financial assets and liabilities, summarized information related to risk management positions, and discussion of risks associated with financial assets and liabilities are presented as follows:
A) Fair Value of Financial Assets and Liabilities
The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amount due to the short-term maturity of those instruments.
The fair value of restricted cash approximates its carrying amount due the nature of the amounts held in escrow (See Note 4).
The fair values of the partnership contribution receivable and partnership contribution payable approximate their carrying amount due to the specific nature of these instruments in relation to the creation of the integrated oil joint venture. Further information about these notes is disclosed in Note 11 to the Company's annual audited Consolidated Financial Statements for the year ended December 31, 2008.
Risk management assets and liabilities are recorded at their estimated fair value based on the mark-to-market method of accounting, using quoted market prices or, in their absence, third-party market indications and forecasts.
Long-term debt is carried at amortized cost using the effective interest method of amortization. The estimated fair values of long-term borrowings have been determined based on market information where available, or by discounting future payments of interest and principal at estimated interest rates expected to be available to the Company at period end.
The Cenovus Notes are carried at amortized cost using the effective interest method of amortization. The estimated fair values of the notes have been determined based on market information where available, or by discounting future payments of interest and principal at estimated interest rates expected to be available to the Company at period end.
The fair value of financial assets and liabilities were as follows:
As at | As at | ||||||||||||||||||
September 30, 2009 | December 31, 2008 | ||||||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | ||||||||||||||||
Financial Assets | |||||||||||||||||||
Held-for-Trading: | |||||||||||||||||||
Cash and cash equivalents | $ | 1,376 | $ | 1,376 | $ | 383 | $ | 383 | |||||||||||
Restricted cash (See Note 4) | 3,619 | 3,619 | - | - | |||||||||||||||
Risk management assets * | 617 | 617 | 3,052 | 3,052 | |||||||||||||||
Loans and Receivables: | |||||||||||||||||||
Accounts receivable and accrued revenues | 1,596 | 1,596 | 1,568 | 1,568 | |||||||||||||||
Partnership contribution receivable * | 2,914 | 2,914 | 3,147 | 3,147 | |||||||||||||||
Financial Liabilities | |||||||||||||||||||
Held-for-Trading: | |||||||||||||||||||
Risk management liabilities * | $ | 102 | $ | 102 | $ | 50 | $ | 50 | |||||||||||
Other Financial Liabilities: | |||||||||||||||||||
Accounts payable and accrued liabilities | 2,947 | 2,947 | 2,871 | 2,871 | |||||||||||||||
Long-term debt * | 8,163 | 8,868 | 9,005 | 8,242 | |||||||||||||||
Cenovus notes (See Note 4) | 3,468 | 3,651 | - | - | |||||||||||||||
Partnership contribution payable * | 2,935 | 2,935 | 3,163 | 3,163 | |||||||||||||||
* Including current portion. | |||||||||||||||||||
B) Risk Management Assets and Liabilities
Net Risk Management Position | As at | As at | |||||||||||
September 30, | December 31, | ||||||||||||
2009 | 2008 | ||||||||||||
Risk Management | |||||||||||||
Current asset | $ | 586 | $ | 2,818 | |||||||||
Long-term asset | 31 | 234 | |||||||||||
617 | 3,052 | ||||||||||||
Risk Management | |||||||||||||
Current liability | 12 | 43 | |||||||||||
Long-term liability | 90 | 7 | |||||||||||
102 | 50 | ||||||||||||
Net Risk Management Asset (Liability) | $ | 515 | $ | 3,002 | |||||||||
Summary of Unrealized Risk Management Positions | |||||||||||||||||||||||||
As at September 30, 2009 | As at December 31, 2008 | ||||||||||||||||||||||||
Risk Management | Risk Management | ||||||||||||||||||||||||
Asset | Liability | Net | Asset | Liability | Net | ||||||||||||||||||||
Commodity Prices | |||||||||||||||||||||||||
Natural gas | $ | 590 | $ | 90 | $ | 500 | $ | 2,941 | $ | 10 | $ | 2,931 | |||||||||||||
Crude oil | 27 | 6 | 21 | 92 | 40 | 52 | |||||||||||||||||||
Power | - | 6 | (6 | ) | 19 | - | 19 | ||||||||||||||||||
Total Fair Value | $ | 617 | $ | 102 | $ | 515 | $ | 3,052 | $ | 50 | $ | 3,002 | |||||||||||||
Net Fair Value Methodologies Used to Calculate Unrealized Risk Management Positions | |||||||||||||
As at | As at | ||||||||||||
September 30, | December 31, | ||||||||||||
2009 | 2008 | ||||||||||||
Prices actively quoted | $ | 465 | $ | 2,055 | |||||||||
Prices sourced from observable data or market corroboration | 50 | 947 | |||||||||||
Total Fair Value | $ | 515 | $ | 3,002 | |||||||||
Prices actively quoted refers to the fair value of contracts valued using quoted prices in an active market. Prices sourced from observable data or market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data.
Net Fair Value of Commodity Price Positions at September 30, 2009
Notional Volumes | Term | Average Price | Fair Value | |||||||||||||||||
Natural Gas Contracts | ||||||||||||||||||||
Fixed Price Contracts | ||||||||||||||||||||
NYMEX Fixed Price | 1,983 | MMcf/d | 2009 | 7.24 | US$/Mcf | $ | 453 | |||||||||||||
NYMEX Fixed Price | 1,721 | MMcf/d | 2010 | 6.07 | US$/Mcf | (8 | ) | |||||||||||||
NYMEX Fixed Price | 108 | MMcf/d | 2011 | 6.73 | US$/Mcf | (3 | ) | |||||||||||||
Purchased Options | ||||||||||||||||||||
NYMEX Call | (61 | ) | MMcf/d | 2009 | 11.67 | US$/Mcf | (3 | ) | ||||||||||||
NYMEX Put | 209 | MMcf/d | 2009 | 9.10 | US$/Mcf | 95 | ||||||||||||||
Basis Contracts | ||||||||||||||||||||
Canada | 80 | MMcf/d | 2009 | - | ||||||||||||||||
United States | 427 | MMcf/d | 2009 | (14 | ) | |||||||||||||||
Canada and United States * | 2010-2013 | (33 | ) | |||||||||||||||||
487 | ||||||||||||||||||||
Other Financial Positions ** | 2 | |||||||||||||||||||
Total Unrealized Gain on Financial Contracts | 489 | |||||||||||||||||||
Premiums Paid on Unexpired Options | 11 | |||||||||||||||||||
Natural Gas Fair Value Position | $ | 500 | ||||||||||||||||||
* EnCana has entered into swaps to protect against widening natural gas price differentials between production areas, including Canada, the U.S. Rockies and Texas, and various sales points. These basis swaps are priced using both fixed prices and basis prices determined as a percentage of NYMEX. | ||||||||||||||||||||
** Other financial positions are part of the ongoing operations of the Company's proprietary production management. | ||||||||||||||||||||
Notional Volumes | Term | Average Price | Fair Value | |||||||||||||||||
Crude Oil Contracts | ||||||||||||||||||||
Fixed Price Contracts | ||||||||||||||||||||
WTI NYMEX Fixed Price | 27,000 | bbls/d | 2010 | 76.89 | US$/bbl | $ | 24 | |||||||||||||
Other Financial Positions * | (3 | ) | ||||||||||||||||||
Crude Oil Fair Value Position | $ | 21 | ||||||||||||||||||
* Other financial positions are part of the ongoing operations of the Company's proprietary production and condensate management and its share of downstream crude supply positions. | ||||||||||||||||||||
Fair Value | ||||||||||||||||||||
Power Purchase Contracts | ||||||||||||||||||||
Power Fair Value Position | $ | (6 | ) | |||||||||||||||||
Earnings Impact of Realized and Unrealized Gains (Losses) on Risk Management Positions
Realized Gain (Loss) | ||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Revenues, Net of Royalties | $ | 1,362 | $ | (389 | ) | $ | 3,776 | $ | (955 | ) | ||||||||||||
Operating Expenses and Other | (4 | ) | (2 | ) | (33 | ) | (2 | ) | ||||||||||||||
Gain (Loss) on Risk Management | $ | 1,358 | $ | (391 | ) | $ | 3,743 | $ | (957 | ) | ||||||||||||
Unrealized Gain (Loss) | ||||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||
2009 | 2008 | 2009 | 2008 | |||||||||||||||||||
Revenues, Net of Royalties | $ | (1,373 | ) | $ | 3,057 | $ | (2,354 | ) | $ | 1,633 | ||||||||||||
Operating Expenses and Other | (11 | ) | (7 | ) | (37 | ) | 6 | |||||||||||||||
Gain (Loss) on Risk Management | $ | (1,384 | ) | $ | 3,050 | $ | (2,391 | ) | $ | 1,639 | ||||||||||||
Reconciliation of Unrealized Risk Management Positions from January 1 to September 30, 2009 | |||||||||||||||||||
2009 | 2008 | ||||||||||||||||||
Fair Value | Total Unrealized Gain (Loss) | Total Unrealized Gain (Loss) | |||||||||||||||||
Fair Value of Contracts, Beginning of Year | $ | 2,892 | |||||||||||||||||
Change in Fair Value of Contracts in Place at Beginning of Year | |||||||||||||||||||
and Contracts Entered into During the Period | 1,352 | $ | 1,352 | $ | 682 | ||||||||||||||
Foreign Exchange Gain (Loss) on Canadian Dollar Contracts | 3 | - | - | ||||||||||||||||
Fair Value of Contracts Realized During the Period | (3,743 | ) | (3,743 | ) | 957 | ||||||||||||||
Fair Value of Contracts Outstanding | $ | 504 | $ | (2,391 | ) | $ | 1,639 | ||||||||||||
Premiums Paid on Unexpired Options | 11 | ||||||||||||||||||
Fair Value of Contracts and Premiums Paid, End of Period | $ | 515 | |||||||||||||||||
Commodity Price Sensitivities
The following table summarizes the sensitivity of the fair value of the Company's risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting net earnings as at September 30, 2009 as follows:
10% Price Increase | 10% Price Decrease | ||||||||||||||
Natural gas price | $ | (497 | ) | $ | 497 | ||||||||||
Crude oil price | (79 | ) | 79 | ||||||||||||
Power price | 10 | (10 | ) |
C) Risks Associated with Financial Assets and Liabilities
The Company is exposed to financial risks arising from its financial assets and liabilities. Financial risks include market risks (such as commodity prices, foreign exchange and interest rates), credit risk and liquidity risk. The fair value or future cash flows of financial assets or liabilities may fluctuate due to movement in market prices and the exposure to credit and liquidity risks.
Commodity Price Risk
Commodity price risk arises from the effect that fluctuations of future commodity prices may have on the fair value or future cash flows of financial assets and liabilities. To partially mitigate exposure to commodity price risk, the Company has entered into various financial derivative instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors. The Company's policy is to not use derivative financial instruments for speculative purposes.
Natural Gas - To partially mitigate the natural gas commodity price risk, the Company has entered into option contracts and swaps, which fix the NYMEX prices. To help protect against widening natural gas price differentials in various production areas, EnCana has entered into swaps to manage the price differentials between these production areas and various sales points.
Crude Oil - The Company has partially mitigated its commodity price risk on crude oil and condensate supply with swaps which fix WTI NYMEX prices.
Power - The Company has in place two Canadian dollar denominated derivative contracts, which commenced January 1, 2007 for a period of 11 years, to manage its electricity consumption costs.
Credit Risk
Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. This credit risk exposure is mitigated through the use of Board-approved credit policies governing the Company's credit portfolio and with credit practices that limit transactions according to counterparties' credit quality. Any foreign currency agreements entered into are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings. A substantial portion of the Company’s accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. As at September 30, 2009, approximately 93 percent of EnCana's accounts receivable and financial derivative credit exposures are with investment grade counterparties.
At September 30, 2009, EnCana had four counterparties whose net settlement position individually account for more than 10 percent of the fair value of the outstanding in-the-money net financial instrument contracts by counterparty. The maximum credit risk exposure associated with accounts receivable and accrued revenues, risk management assets and the partnership contribution receivable is the total carrying value.
Liquidity Risk
Liquidity risk is the risk the Company will encounter difficulties in meeting a demand to fund its financial liabilities as they come due. The Company manages its liquidity risk through cash and debt management. As disclosed in Note 14, EnCana targets a Debt to Capitalization ratio of less than 40 percent and a Debt to Adjusted EBITDA of less than 2.0 times to steward the Company's overall debt position.
In managing liquidity risk, the Company has access to a wide range of funding at competitive rates through commercial paper, capital markets and banks. As at September 30, 2009, excluding the Cenovus credit facilities as disclosed in Note 4, EnCana had available unused committed bank credit facilities in the amount of $4.3 billion and unused capacity under shelf prospectuses, the availability of which is dependent on market conditions, for $5.4 billion. The Company believes it has sufficient funding through the use of these facilities to meet foreseeable borrowing requirements.
EnCana maintains investment grade credit ratings on its senior unsecured debt. Following the proposed corporate reorganization announcement on September 10, 2009 (See Note 4), S&P maintained the rating of "A-" and placed the Company on "CreditWatch" with negative implications. Moody’s affirmed the rating of "Baa2" with a “Stable” outlook and DBRS maintained the rating of "A (low)" which is “Under Review with Developing Implications”. DBRS placed the rating "Under Review" following the May 11, 2008 announcement of the proposed Arrangement.
The timing of cash outflows relating to financial liabilities are outlined in the table below:
Less Than 1 Year | 1 - 3 Years | 4 - 5 Years | Thereafter | Total | |||||||||||||||||||
Accounts Payable and Accrued Liabilities | $ | 2,947 | $ | - | $ | - | $ | - | $ | 2,947 | |||||||||||||
Risk Management Liabilities | 12 | 89 | 1 | - | 102 | ||||||||||||||||||
Long-Term Debt * | 685 | 1,866 | 2,710 | 9,904 | 15,165 | ||||||||||||||||||
Cenovus Notes * | 141 | 409 | 1,209 | 5,517 | 7,276 | ||||||||||||||||||
Partnership Contribution Payable * | 489 | 978 | 978 | 1,222 | 3,667 | ||||||||||||||||||
* Principal and interest, including current portion. | |||||||||||||||||||||||
Included in EnCana's total long-term debt obligations of $15,165 million at September 30, 2009, excluding the Cenovus Notes, are $423 million in principal obligations related to Commercial Paper and LIBOR loans. These amounts are fully supported and Management expects that they will continue to be supported by revolving credit and term loan facilities that have no repayment requirements within the next year. The revolving credit and term loan facilities, excluding the Cenovus credit facilities as described in Note 4, are fully revolving for a period of up to five years. Based on the current maturity dates of the credit facilities, these amounts are included in cash outflows for the period disclosed as 4 - 5 Years. Further information on Long-term Debt is contained in Note 11.
Foreign Exchange Risk
Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. As EnCana operates primarily in North America, fluctuations in the exchange rate between the U.S./Canadian dollar can have a significant effect on the Company's reported results. EnCana's functional currency is Canadian dollars, however, the Company reports its results in U.S. dollars as most of its revenue is closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies. As the effects of foreign exchange fluctuations are embedded in the Company's results, the total effect of foreign exchange fluctuations are not separately identifiable.
To mitigate the exposure to the fluctuating U.S./Canadian exchange rate, EnCana maintains a mix of both U.S. dollar and Canadian dollar debt.
As disclosed in Note 8, EnCana's foreign exchange (gain) loss primarily includes unrealized foreign exchange gains and losses on the translation of U.S. dollar debt issued from Canada and the translation of the U.S. dollar partnership contribution receivable issued from Canada. At September 30, 2009, excluding the Cenovus Notes, EnCana had $5,600 million in U.S. dollar debt issued from Canada ($5,350 million at December 31, 2008) and $2,914 million related to the U.S. dollar partnership contribution receivable ($3,147 million at December 31, 2008). A $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $25 million change in foreign exchange (gain) loss at September 30, 2009 (2008 - $20 million), excluding the Cenovus Notes.
Interest Rate Risk
Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Company’s financial assets or liabilities. The Company partially mitigates its exposure to interest rate changes by maintaining a mix of both fixed and floating rate debt.
At September 30, 2009, the increase or decrease in net earnings for each one percent change in interest rates on floating rate debt amounts to approximately $3 million (2008 - $15 million).
18. Contingencies
Legal Proceedings
The Company is involved in various legal claims associated with the normal course of operations. The Company believes it has made adequate provision for such legal claims.
Discontinued Merchant Energy Operations
During the period between 2003 and 2005, EnCana and its indirect wholly owned U.S. marketing subsidiary, WD Energy Services Inc. (“WD”), along with other energy companies, were named as defendants in several lawsuits, some of which were class action lawsuits, relating to sales of natural gas from 1999 to 2002. The lawsuits allege that the defendants engaged in a conspiracy with unnamed competitors in the natural gas markets in California in violation of U.S. and California anti-trust and unfair competition laws. All but one of these lawsuits has been settled prior to 2009, without admitting any liability in the lawsuits.
The remaining lawsuit was commenced by E. & J. Gallo Winery (“Gallo”). The Company and WD have conditionally agreed to settle this lawsuit pending the successful negotiation and execution of a Settlement Agreement. Subsequent to September 30, 2009, the Settlement Agreement was fully executed, without admitting any liability in the lawsuit.
19. Reclassification
Certain information provided for prior periods has been reclassified to conform to the presentation adopted in 2009.
Contacts:
EnCana Corporate Communications
Investor
contacts:
Paul Gagne
Vice-President, Investor Relations
(403)
645-4737
Ryder McRitchie
Manager, Investor Relations
(403)
645-2007
Susan Grey
Manager, Investor Relations
(403)
645-4751
Media contact:
Alan Boras
Manager,
Media Relations
(403) 645-4747