EnCana generates second quarter cash flow of US$2.2 billion,or $2.87 per share – down 25 percent

CALGARY, Alberta--()--EnCana Corporation (TSX & NYSE: ECA) continued to deliver strong financial and operating performance in the second quarter of 2009 – a period of very low natural gas prices. Cash flow was $2.2 billion, or $2.87 per share, and operating earnings were $917 million, or $1.22 per share – down 25 and 38 percent respectively on a per share basis compared to the second quarter of 2008. EnCana’s financial performance was greatly enhanced by its commodity price hedges, which contributed a $900 million after-tax gain, or $1.20 per share, to cash flow in the second quarter. Second quarter natural gas and oil production remained flat at 4.6 billion cubic feet equivalent per day (Bcfe/d) compared to the second quarter of 2008.

 

“Note Regarding Reserves Data and Other Oil and Gas Information”

“EnCana’s continued strong financial and operating performance during this period of weak natural gas prices provides clear evidence of how our risk management measures reduce volatility in our business and help us continue to enhance long-term value creation. In the past year, natural gas prices dropped close to 70 percent, yet we have continued to meet or exceed our 2009 financial and operating objectives. Our natural gas price hedges provide an increased level of certainty to our cash flows so that we can most effectively manage our capital programs. Operationally, our production is on track for the year and we have additional natural gas productive capacity that we are not bringing on due to the prevailing weak prices. In our oil activities, we’ve seen a promising price recovery from the first quarter of 2009 and our newly expanded oil projects at Foster Creek and Christina Lake are ramping up production, up about 65 percent in the past year,” said Randy Eresman, EnCana’s President & Chief Executive Officer.

“Through 2009, EnCana will remain focused on directing our capital investment to our lowest cost, highest return projects and on maintaining our financial strength and flexibility. We are taking advantage of cost deflation and reduced industry activity by renegotiating supply and services contracts and by improving efficiencies. EnCana’s cost reduction initiatives, announced in February, have already exceeded our savings target of $900 million for the year. Some of those savings, achieved primarily through capital reductions, have been redeployed to other parts of our portfolio, largely to shale gas plays,” Eresman said.

“Our financial position remains strong. In the past few months, we have secured additional support for our financial future by hedging more than 45 percent of our expected natural gas production during the 2010 gas year at a price averaging $6.09 per thousand cubic feet (Mcf). During all periods in the economic cycle, we strive to be the leading North American resource play company developing unconventional natural gas and enhanced oil,” Eresman said.

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.

Second Quarter 2009 Highlights

(all year-over-year comparisons are to the second quarter of 2008)

Financial

  • Cash flow decreased 25 percent per share to $2.87, or $2.2 billion
  • Operating earnings were down 38 percent per share to $1.22, or $917 million
  • Net earnings decreased 80 percent to 32 cents per share, or $239 million
  • Capital investment, excluding acquisitions and divestitures, was down 37 percent to $1.1 billion, primarily due to lower drilling and completion costs as a result of fewer wells drilled, cost deflation, a weaker Canadian dollar and lower long-term incentive costs as a result of a decline in share price
  • Free cash flow was $1.1 billion, down 8 percent (Free cash flow is defined in Note 1 on page 8)
  • EnCana’s integrated oil business venture with ConocoPhillips generated $293 million in operating cash flow, comprised of $139 million from the company’s Foster Creek and Christina Lake upstream projects, and $154 million from the downstream business. Operating cash flow was down $174 million largely due to lower crack spreads and capacity utilization in the downstream business
  • Realized natural gas prices were down 18 percent to $6.99 per Mcf and realized liquids prices decreased 44 percent to $50.23 per barrel (bbl). These prices include financial hedges
  • At the end of the quarter, debt to capitalization was 27 percent and debt to adjusted EBITDA was 0.7 times
  • Paid dividend of 40 cents per share
  • Completed public offering in the United States of notes totalling $500 million at 6.5 percent

Operating – Upstream

  • Key resource play production was up 1 percent, with a 27 percent increase in oil production and a 1 percent decrease in natural gas production
  • Total natural gas production decreased 1 percent to 3.79 billion cubic feet per day (Bcf/d), down 1 percent per share
  • Total oil and natural gas liquids (NGLs) production increased 6 percent to almost 136,000 barrels per day (bbls/d), up 6 percent per share
  • Foster Creek and Christina Lake oil production grew 65 percent to approximately 40,700 bbls/d net to EnCana
  • Operating and administrative costs of $1.15 per thousand cubic feet equivalent (Mcfe) decreased from $1.71 per Mcfe in the second quarter of 2008, primarily due to lower long-term incentive costs as a result of a decline in share price, a weaker Canadian dollar, and lower repairs, maintenance and workover costs

Operating – Downstream

  • Refined products averaged 428,000 bbls/d (214,000 bbls/d net to EnCana), down 8 percent
  • Refinery crude utilization of 89 percent or 404,000 bbls/d crude throughput (202,000 bbls/d net to EnCana), down 8 percent.

Net earnings positively impacted by hedging program

EnCana’s net earnings were impacted by mark-to-market accounting for hedging contracts. EnCana’s second quarter net earnings of $239 million were down $982 million from the second quarter of 2008. Net earnings in the second quarter of 2009 included a $900 million after-tax, realized gain on hedging, primarily offset by a $750 million after-tax, unrealized loss that was previously included in net earnings as unrealized gains due to mark-to-market accounting. It is because of these dramatic mark-to-market accounting swings in net earnings that EnCana focuses on operating earnings as a better measure of quarter-over-quarter earnings performance.

Realized after-tax hedging gains for the first eight months of the 2008-2009 natural gas year, which runs from November 1, 2008 to October 31, 2009, were $1.9 billion and, as of June 30, 2009, unrealized after-tax gains for the remainder of the gas year were about $1.1 billion, for a total of approximately $3.0 billion, after tax.

 

Financial Summary – Total Consolidated

(for the period ended June 30)

($ millions, except per share amounts)

  Q2

2009

  Q2

2008

  % ∆  

6

months

2009

 

6

months

2008

  % ∆
Cash flow1   2,153   2,889   -25   4,097   5,278   -22
Per share diluted   2.87   3.85   -25   5.45   7.02   -22
Operating earnings1   917   1,469   -38   1,865   2,514   -26
Per share diluted   1.22   1.96   -38   2.48   3.34   -26
Net earnings   239   1,221   -80   1,201   1,314   -9
Per share diluted   0.32   1.63   -80   1.60   1.75   -9
Earnings Reconciliation Summary – Total Consolidated
Net earnings   239   1,221       1,201   1,314    

Add back (losses) & deduct gains

                       

Unrealized mark-to-market gain (loss), after tax

  (750)   (235)       (661)   (972)    

Non-operating foreign exchange gain (loss), after tax

  72   (13)       (3)   (228)    

Operating earnings1

  917   1,469   -38   1,865   2,514   -26

Per share diluted

  1.22   1.96   -38   2.48   3.34   -26
                         

1 Cash flow and operating earnings are non-GAAP measures as defined in Note 1 on Page 8.

 
Production & Drilling Summary
Total Consolidated

 (for the period ended June 30)

 (After royalties)

 

Q2

2009

 

Q2

2008

 

 

% ∆

 

6

months

2009

 

6

months

2008

 

 

% ∆

Natural Gas (MMcf/d)   3,788   3,841   -1   3,828   3,787   +1
Natural gas production per 1,000 shares (Mcf/d)   5.04   5.12   -1   5.10   5.05   +1
Oil and NGLs (Mbbls/d)   136   128   +6   135   132   +2
Oil and NGLs production per 1,000 shares (Mcfe/d)   1.09   1.02   +6   1.08   1.06   +2
Total Production (MMcfe/d)   4,602   4,607   -   4,638   4,582   +1
Total production per 1,000 shares (Mcfe/d)   6.13   6.14   -   6.18   6.11   +1
Net wells drilled   216   409   -47   1,099   1,552   -29
                         

Key resource play oil production grows 27 percent; key resource play natural gas production steady

Oil and natural gas production from key resource plays increased 1 percent to 3.56 Bcfe/d compared to 3.51 Bcfe/d in the second quarter of 2008. Oil production was up 27 percent from the second quarter of 2008 to about 75,000 bbls/d led by Foster Creek and Christina Lake. Natural gas resource play production was down slightly, by 1 percent, to 3.1 Bcf/d, with lower volumes offset by Cutbank Ridge, which saw strong performance from the company’s Montney developments in British Columbia. Production volumes benefited from lower royalties in Alberta, which were offset by a decision, due to lower prices and netbacks in certain areas, to shut in some wells, restrict some wells’ productive capacity and delay some well completions or tie-ins to sales pipelines. These company-wide initiatives resulted in between 300 million and 400 million cubic feet per day (MMcf/d) being kept off line.

Integrated oil business contributes solid second quarter performance

EnCana’s integrated oil business continued its strong performance with Foster Creek and Christina Lake production increasing 65 percent to about 40,700 bbls/d compared to the same quarter in 2008. Year-over-year oil prices fell dramatically from the record highs seen one year ago, but prices recovered significantly, up close to 40 percent, from the low levels experienced in the first quarter of 2009. Operating cash flow for Foster Creek and Christina Lake was up 11 percent to $139 million in 2009 compared to $125 million in 2008. The downstream operations reported a 55 percent decrease in operating cash flow to $154 million from $342 million mainly due to lower crack spreads and capacity utilization.

Expansion of enhanced oil production capacity at Foster Creek and Christina Lake remains on track

At Foster Creek, phases D and E were commissioned in the second quarter, each adding 30,000 bbls/d of productive capacity. Production continues to ramp up and is on target to exit 2009 exceeding 90,000 bbls/d (45,000 bbls/d net to EnCana). In the second quarter, a regulatory application was initiated for Foster Creek’s phases F, G, and H with each phase expected to add about 30,000 bbls/d of productive capacity. At Christina Lake, construction of phase C continues to proceed on schedule and on budget. Phase C is expected to add about 40,000 bbls/d of capacity, with first production forecast in late 2011. Phase D of the Christina Lake project is targeted to be sanctioned by EnCana and ConocoPhillips in the fourth quarter of 2009. Regulatory applications for phases E, F and G at Christina Lake are expected to be filed in the third quarter of 2009 with each of these new phases designed to add approximately 40,000 bbls/d of productive capacity. EnCana continues to proceed through the regulatory application process for future expansion phases at Foster Creek and Christina Lake although exact timing of construction and initial production from these phases is subject to receipt of regulatory approvals and partnership sanction.

Haynesville and Horn River shale plays continue to show very strong results

EnCana continues to see improved operational performance and strong initial production rates from its Haynesville shale gas play. To date, EnCana has drilled 25 gross horizontal wells in the play. EnCana has increased fracture stimulations in each horizontal well from eight to as many as 14. This efficiency initiative has helped increase initial production rates and reduce well costs by about 35 percent from prior wells to an estimated $9 million per well. The strongest well performance continues to be in the northern portion of the company’s Red River Parish leases where EnCana has a joint venture with Shell. EnCana exited the second quarter with gross production from North Louisiana of about 100 MMcf/d. EnCana is currently operating 10 rigs in the Haynesville Shale, up from five at the start of 2009, and is participating in another four rigs operated by Shell.

At Horn River, the joint drilling program by EnCana and Apache Corporation at Two Island Lake continues to meet or exceed expectations for both initial well production and expected size of the resource. As a result of the joint venture’s combined activities, to date 32 gross wells have been drilled to evaluate the basin and 10 gross horizontal wells placed on production. Similar to activity at the Haynesville, fracture stimulations at Horn River have increased to up to 14 stages per horizontal section. The first wells completed in 2009 were placed on production towards the end of the quarter. The wells have shown strong results with flow rates of 9.5 MMcf/d to 11 MMcf/d after 15 days of initial flow. EnCana also commissioned a new compression and dehydration facility as well as a gas gathering pipeline that connects the Two Island Lake area with the Spectra pipeline system near the proposed EnCana operated Cabin gas plant.

Large opportunity ahead for abundant, affordable, cleaner-burning natural gas

“Looking ahead, we strongly believe there are tremendous opportunities for expanding the use of clean-burning natural gas to help solve some of our continent’s most pressing energy, environmental and economic challenges. A number of respected geological authorities have recently confirmed the abundant nature of North American natural gas. This abundance will help ensure an affordable future for expanding natural gas in our economy, primarily by displacing foreign oil in transportation and by fuelling electricity generation. While the use of natural gas as a convenient and economic transportation fuel for trucks and cars is not common in North America, it is in wide use on other continents. As a step in that direction, EnCana has started to convert a portion of its vehicle fleet to run on natural gas in select Canadian and U.S. operating locations,” Eresman said.

 

Growth from key North American resource plays

     

   Resource Play

 

 (After royalties)

  Daily Production
  2009   2008   2007
  YTD   Q2   Q1  

Full

Year

  Q4   Q3   Q2   Q1  

Full

Year

Natural Gas

                                   

(MMcf/d)

                                   

Jonah

  600   576   623   603   573   615   630   595   557
Piceance   371   355   386   385   377   407   383   372   348
East Texas   356   304   409   334   408   339   316   273   143
Fort Worth   144   138   149   142   143   148   137   140   124
Greater Sierra   215   216   215   220   228   228   219   205   211
Cutbank Ridge   332   340   323   296   311   322   280   271   258
Bighorn   171   186   156   167   165   185   170   146   126
CBM   319   330   309   304   308   309   303   298   259
Shallow Gas   667   661   673   700   683   691   712   715   726

Total natural gas

                                   

(MMcf/d)

  3,175   3,106   3,243   3,151   3,196   3,244   3,150   3,015   2,752
Oil (Mbbls/d)                                    
Foster Creek   31   34   28   26   29   27   21   27   24
Christina Lake   6   6   7   4   6   5   4   2   3
Pelican Lake   20   19   21   22   20   22   21   24   23
Weyburn   16   15   16   14   15   14   13   14   15
Total oil (Mbbls/d)1   74   75   72   66   71   67   59   67   65
Total (MMcfe/d)1   3,617   3,557   3,676   3,548   3,621   3,648   3,506   3,417   3,141
% change from prior period   +4.6   -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   Q2   Q1  

Full

Year

  Q4   Q3   Q2   Q1  

Full

Year

  Natural Gas                                    
  Jonah   65   30   35   175   40   43   49   43   135
  Piceance   88   35   53   328   70   94   81   83   286
  East Texas   26   11   15   78   23   22   22   11   35
  Fort Worth   22   6   16   83   21   21   20   21   75
  Greater Sierra   25   10   15   106   14   29   27   36   109
  Cutbank Ridge   38   18   20   82   17   17   24   24   93
  Bighorn   35   14   21   64   5   11   18   30   62
  CBM   279   1   278   698   359   78   10   251   1,079
  Shallow Gas   381   45   336   1,195   383   233   83   496   1,914
  Total gas wells   959   170   789   2,809   932   548   334   995   3,788
  Oil                                    
  Foster Creek   16   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   21   11   10   41   4   10   6   21   63
  Total  

980

 

181

  799   2,850   936  

558

 

340

  1,016   3,851
                                       
   
   
  Second quarter natural gas and oil prices
      Q2

2009

  Q2

2008

  % ∆  

6 months

2009

 

6 months

2008

  % ∆
  Natural gas ($/MMBtu)                        
  NYMEX   3.50   10.93   -68   4.19   9.48   -56
  EnCana realized gas price1 ($/Mcf)   6.99   8.54   -18   7.11   8.29   -14
  Oil and NGLs ($/bbl)                        
  WTI   59.79   123.80   -52   51.68   111.12   -53
  Western Canadian Select (WCS)   52.37   102.18   -49   43.50   89.58   -51
  Differential WTI/WCS   7.42   21.62   -66   8.18   21.54   -62
  EnCana realized liquids price 1   50.23   90.47   -44   42.45   79.77   -47
  Chicago 3-2-1 crack spread ($/bbl)   10.95   13.60   -19   10.35   10.65   -3
                           

1 Realized prices include the impact of financial hedging.

   

Price risk management

Risk management positions at June 30, 2009 are presented in Note 16 to the unaudited Interim Consolidated Financial Statements. In the second quarter of 2009, EnCana’s commodity price risk management measures resulted in realized gains of approximately $900 million after tax, composed of an $896 million after-tax gain on gas prices and basis hedges and a $4 million after-tax gain on other hedges.

EnCana has hedged two-thirds of expected 2009 natural gas production, about 2.6 Bcf/d, through October of this year at an average NYMEX equivalent price of $9.13 per Mcf. EnCana has also extended its risk management program through 2010. As of July 21, 2009, EnCana had established fixed price hedges on more than 45 percent of the company's expected 2010 natural gas production - or about 2 Bcf/d - at an average NYMEX equivalent price of $6.09 per Mcf for the gas year, which runs from November 1, 2009 to October 31, 2010. EnCana also has 20,000 bbls/d of expected 2010 oil production hedged at an average fixed price of WTI $76.45 per bbl. This price hedging strategy increases certainty in cash flow to help ensure that EnCana can meet its capital and dividend requirements without substantially adding to debt. EnCana continually assesses its hedging needs and the opportunities available prior to establishing its capital program for the upcoming year.

Corporate developments

Quarterly dividend of 40 cents per share declared

EnCana’s Board of Directors has declared a quarterly dividend of 40 cents per share payable on September 30, 2009 to common shareholders of record as of September 15, 2009. Based on the July 22, 2009 closing share price on the New York Stock Exchange of $52.57, this represents an annualized yield of about 3 percent.

“Plans for splitting EnCana into two independent companies, creating an integrated oil company and a pure-play natural gas company, continue to be evaluated, but are currently on hold as market conditions continue to be volatile,” Eresman said.

Guidance updated

EnCana has updated its 2009 guidance for total natural gas, oil and NGLs production to a range of 4.4 to 4.8 MMcfe/d from 4.5 to 4.7 MMcfe/d. EnCana has also updated its capital investment guidance from $6.1 billion to a range of $5.5 billion to $6 billion. Total operating cost guidance has been reduced to $1.00 from $1.10 per Mcfe. Updated guidance and key resource play information is posted on the company’s website at www.encana.com.

EnCana sells non-core properties for $632 million

On July 16, 2009, EnCana announced it had reached an agreement to sell approximately 409,000 net acres of non-core natural gas and oil producing properties for approximately $632 million to Bonavista Energy Trust. Current production on these lands is approximately 60 MMcfe/d, after royalties. The transaction includes properties known as the Hoadley trend which covers an expansive area in west-central Alberta. The sale has an effective date of April 1, 2009 and is subject to typical closing conditions and regulatory approvals. It is expected to close in the third quarter of 2009.

Financial strength

EnCana has a very strong balance sheet, with 88 percent of EnCana’s outstanding debt comprised of long-term, fixed-rate debt with an average remaining term of more than 13 years. Upcoming debt maturities in 2009 are $250 million and in 2010 are $200 million. At June 30, 2009, EnCana had $3.4 billion in unused committed 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 June 30, 2009, the company’s debt to capitalization ratio was 27 percent and debt to adjusted EBITDA, on a trailing 12-month basis, was 0.7 times.

On May 4, 2009, EnCana completed a public offering in the United States of $500 million notes with an interest rate of 6.50 percent due on May 15, 2019. The net proceeds of the offering were used to repay a portion of EnCana's existing bank and commercial paper indebtedness. The offering was made in the United States under EnCana's previously filed shelf prospectus dated March 11, 2008 and a prospectus supplement dated April 29, 2009.

In the quarter, EnCana invested $1.1 billion in capital on continued development of the company’s long-term production and refining assets – including the coker and refinery expansion (CORE) project at the Wood River refinery in Illinois, expansion of upstream oil projects in northeast Alberta, development of the Deep Panuke natural gas project offshore Nova Scotia, and other long-term upstream projects with substantial future growth potential.

 

CONFERENCE CALL TODAY

11 a.m. Mountain Time (1 p.m. Eastern Time)

EnCana will host a conference call today Thursday, July 23, 2009 starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial (800) 733-7560 (toll-free in North America) or (416) 644-3414 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 July 23 until midnight July 30, 2009 by dialing (877) 289-8525 or (416) 640-1917 and entering passcode 21307975 followed by the pound (#) sign.

 

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 related to U.S. dollar intercompany debt recognized for tax purposes only 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 guidance forecasts and the anticipated ability to meet the company’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 cost reductions and production efficiencies from fracture stimulations; anticipated capacity and timing for the proposed Cabin Gas Plant; planned expansion of in-situ oil production; anticipated crude oil and natural gas prices, including basis differentials for various regions; anticipated expansion and production 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; potential capital expenditures and investment; potential oil, natural gas and NGLs production in 2009 and beyond; anticipated plans to ramp up production in the event of the recovery of natural gas prices; anticipated conversion of natural gas powered vehicles; anticipated costs and cost reductions; the company’s plans for splitting into two independent companies and the conditions which may be required therefore; the expected closing date for the Bonavista Energy Trust transaction; 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: volatility of and assumptions regarding oil and gas prices; assumptions based upon the company’s current 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, average commodity prices for 2009 based on year-to-date actuals, forward curve commodity prices and US/Canadian dollar foreign exchange rate estimates as of June 30, 2009, and an average number of outstanding shares for EnCana 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 June 30, 2009
 
 
(U.S. Dollars)
 
                                         
Consolidated Statement of Earnings (unaudited)                                        
                                                   
                    Three Months Ended         Six Months Ended
                    June 30,         June 30,
($ millions, except per share amounts)                 2009           2008           2009           2008  
                                                   
                                                   
Revenues, Net of Royalties       (Note 4)       $ 3,762         $ 7,422         $ 8,370         $ 12,856  
                                                   
Expenses       (Note 4)                                        
  Production and mineral taxes                 32           154           93           268  
  Transportation and selling                 321           427           614           839  
  Operating                 512           709           1,065           1,405  
  Purchased product                 1,385           2,882           2,594           5,275  
  Depreciation, depletion and amortization                 980           1,097           1,963           2,132  
  Administrative                 120           225           205           381  
  Interest, net       (Note 6)         129           147           233           281  
  Accretion of asset retirement obligation       (Note 11)         19           20           36           41  
  Foreign exchange (gain) loss, net       (Note 7)         (60 )         (35 )         (2 )         60  
  (Gain) loss on divestitures       (Note 5)         3           (17 )         2           (17 )
                    3,441           5,609           6,803           10,665  
Net Earnings Before Income Tax                 321           1,813           1,567           2,191  
  Income tax expense       (Note 8)         82           592           366           877  
Net Earnings               $ 239         $ 1,221         $ 1,201         $ 1,314  
                                                   
                                                   
                                                   
Net Earnings per Common Share       (Note 15)                                  
  Basic               $ 0.32         $ 1.63         $ 1.60         $ 1.75  
  Diluted               $ 0.32         $ 1.63         $ 1.60         $ 1.75  
                                                   
See accompanying Notes to Consolidated Financial Statements.
Consolidated Statement of Retained Earnings (unaudited)                                        
                                             
                                  Six Months Ended
                                  June 30,
($ millions)                               2009           2008  
                                             
Retained Earnings, Beginning of Year                             $ 17,584         $ 13,082  
Net Earnings                               1,201           1,314  
Dividends on Common Shares                               (601 )         (600 )
Charges for Normal Course Issuer Bid                     (Note 12)   -           (243 )
Retained Earnings, End of Period                             $ 18,184         $ 13,553  
                                             
                                             
                                             
Consolidated Statement of Comprehensive Income (unaudited)                      
                                             
              Three Months Ended         Six Months Ended
              June 30,         June 30,
($ millions)           2009         2008         2009           2008  
                                             
Net Earnings         $ 239       $ 1,221       $ 1,201         $ 1,314  
Other Comprehensive Income, Net of Tax                                          
Foreign Currency Translation Adjustment         916         48         645           (352 )
Comprehensive Income         $ 1,155       $ 1,269       $ 1,846         $ 962  
                                             
                                             
                                             
Consolidated Statement of Accumulated Other Comprehensive Income (unaudited)            
                                             
                                  Six Months Ended
                                  June 30,
($ millions)                               2009           2008  
                                             
Accumulated Other Comprehensive Income, Beginning of Year         $ 833         $ 3,063  
Foreign Currency Translation Adjustment                               645           (352 )
Accumulated Other Comprehensive Income, End of Period                 $ 1,478         $ 2,711  
                                             
See accompanying Notes to Consolidated Financial Statements.                      
Consolidated Balance Sheet (unaudited)                            
                                   
                        As at         As at
                        June 30,         December 31,
($ millions)             2009         2008
                                   
Assets                              
  Current Assets                            
    Cash and cash equivalents               $ 330       $ 383
    Accounts receivable and accrued revenues                 1,472         1,568
    Current portion of partnership contribution receivable                 321         313
    Risk management       (Note 16)         1,927         2,818
    Inventories       (Note 9)         710         520
                        4,760         5,602
  Property, Plant and Equipment, net       (Note 4)         37,377         35,424
  Investments and Other Assets                 955         727
  Partnership Contribution Receivable                 2,672         2,834
  Risk Management       (Note 16)         44         234
  Goodwill                   2,530         2,426
              (Note 4)       $ 48,338       $ 47,247
                                   
Liabilities and Shareholders' Equity                            
  Current Liabilities                            
    Accounts payable and accrued liabilities               $ 2,401       $ 2,871
    Income tax payable                 527         424
    Current portion of partnership contribution payable                 315         306
    Risk management       (Note 16)         14         43
    Current portion of long-term debt       (Note 10)         250         250
                        3,507         3,894
  Long-Term Debt       (Note 10)         8,688         8,755
  Other Liabilities                 903         576
  Partnership Contribution Payable                 2,697         2,857
  Risk Management       (Note 16)         26         7
  Asset Retirement Obligation       (Note 11)         1,325         1,265
  Future Income Taxes                 6,945         6,919
                        24,091         24,273
  Shareholders' Equity                            
    Share capital       (Note 12)         4,579         4,557
    Paid in surplus       (Note 12)         6         -
    Retained earnings                 18,184         17,584
    Accumulated other comprehensive income                 1,478         833
  Total Shareholders' Equity                 24,247         22,974
                      $ 48,338       $ 47,247
                                   
See accompanying Notes to Consolidated Financial Statements.
Consolidated Statement of Cash Flows (unaudited)                                          
                                                   
                    Three Months Ended         Six Months Ended
                    June 30,         June 30,
($ millions)                 2009           2008           2009           2008  
                                                   
Operating Activities                                                
  Net earnings               $ 239         $ 1,221         $ 1,201         $ 1,314  
  Depreciation, depletion and amortization                 980           1,097           1,963           2,132  
  Future income taxes       (Note 8)         (231 )         152           (194 )         73  
  Unrealized (gain) loss on risk management       (Note 16)         1,118           318           1,007           1,411  
  Unrealized foreign exchange (gain) loss                 (69 )         (11 )         (49 )         65  
  Accretion of asset retirement obligation       (Note 11)         19           20           36           41  
  (Gain) loss on divestitures       (Note 5)         3           (17 )         2           (17 )
  Other                 94           109           131           259  
  Net change in other assets and liabilities                 9           (171 )         23           (264 )
  Net change in non-cash working capital                 (207 )         (722 )         (334 )         (1,260 )
  Cash From Operating Activities                 1,955           1,996           3,786           3,754  
                                                   
Investing Activities                                                
  Capital expenditures       (Note 4)         (1,088 )         (1,996 )         (2,675 )         (3,903 )
  Proceeds from divestitures       (Note 5)         20           79           53           151  
  Corporate acquisition       (Note 5)         (24 )         -           (24 )         -  
  Net change in investments and other                 (28 )         (18 )         (170 )         (9 )
  Net change in non-cash working capital                 (187 )         (101 )         (279 )         191  
  Cash (Used in) Investing Activities                 (1,307 )         (2,036 )         (3,095 )         (3,570 )
                                                   
Financing Activities                                                
  Net issuance (repayment) of revolving long-term debt           (1,170 )         426           (665 )         367  
  Issuance of long-term debt       (Note 10)         496           -           496           723  
  Repayment of long-term debt                 -           (196 )         -           (196 )
  Issuance of common shares       (Note 12)         19           13           21           76  
  Purchase of common shares       (Note 12)         -           (15 )         -           (326 )
  Dividends on common shares                 (301 )         (300 )         (601 )         (600 )
  Cash From (Used in) Financing Activities                 (956 )         (72 )         (749 )         44  
                                                   
Foreign Exchange Gain (Loss) on Cash and Cash                                          
  Equivalents Held in Foreign Currency                 9           1           5           (3 )
                                                   
Increase (Decrease) in Cash and Cash Equivalents           (299 )         (111 )         (53 )         225  
Cash and Cash Equivalents, Beginning of Period           629           889           383           553  
Cash and Cash Equivalents, End of Period               $ 330         $ 778         $ 330         $ 778  
                                                   
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. 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. 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 the new 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 June 30)

Segment and Geographic Information                                                            
                                                               
            Canada         USA         Downstream Refining
            2009           2008           2009           2008           2009           2008  
                                                               
Revenues, Net of Royalties       $ 2,070         $ 2,810         $ 1,126         $ 1,525         $ 1,313         $ 2,769  
Expenses                                                            
  Production and mineral taxes         17           36           15           118           -           -  
  Transportation and selling         196           307           125           120           -           -  
  Operating         291           396           99           186           112           127  
  Purchased product         (18 )         (46 )         -           -           1,047           2,300  
            1,584           2,117           887           1,101           154           342  
  Depreciation, depletion and amortization   523           570           379           421           46           44  
Segment Income (Loss)       $ 1,061         $ 1,547         $ 508         $ 680         $ 108         $ 298  
                                                               
            Market Optimization         Corporate & Other Consolidated
            2009           2008           2009           2008           2009           2008  
                                                               
Revenues, Net of Royalties       $ 366         $ 647         $ (1,113 )       $ (329 )       $ 3,762         $ 7,422  
Expenses                                                            
  Production and mineral taxes         -           -           -           -           32           154  
  Transportation and selling         -           -           -           -           321           427  
  Operating         7           8           3           (8 )         512           709  
  Purchased product         356           628           -           -           1,385           2,882  
            3           11           (1,116 )         (321 )         1,512           3,250  
  Depreciation, depletion and amortization   4           4           28           58           980           1,097  
Segment Income (Loss)       $ (1 )       $ 7         $ (1,144 )       $ (379 )         532           2,153  
  Administrative                                                 120           225  
  Interest, net                                                 129           147  
  Accretion of asset retirement obligation                                         19           20  
  Foreign exchange (gain) loss, net                                                 (60 )         (35 )
  (Gain) loss on divestitures                                                 3           (17 )
                                                    211           340  
Net Earnings Before Income Tax                                                 321           1,813  
  Income tax expense                                                 82           592  
Net Earnings                                               $ 239         $ 1,221  
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

      $ 820       $ 1,275       $ 907       $ 1,189       $ 343         $ 346         $ 2,070         $ 2,810  
Expenses                                                                                
  Production and mineral taxes         11         24         6         12         -           -           17           36  
  Transportation and selling         53         115         38         54         105           138           196           307  
  Operating         108         147         133         180         50           69           291           396  
  Purchased product         -         -         -         -         (18 )         (46 )         (18 )         (46 )
Operating Cash Flow       $ 648       $ 989       $ 730       $ 943       $ 206         $ 185         $ 1,584         $ 2,117  
                                                                                   
          Canadian Plains Division
            Gas         Oil & NGLs         Other         Total
            2009         2008         2009         2008         2009           2008           2009           2008  
                                                                                   
Revenues, Net of Royalties       $ 475       $ 629       $ 341       $ 644       $ 4         $ 2         $ 820         $ 1,275  
Expenses                                                                                
  Production and mineral taxes         5         13         6         11         -           -           11           24  
  Transportation and selling         10         18         43         97         -           -           53           115  
  Operating         51         74         55         72         2           1           108           147  
Operating Cash Flow       $ 409       $ 524       $ 237       $ 464       $ 2         $ 1         $ 648         $ 989  
                                                                                   
          Canadian Foothills Division
            Gas         Oil & NGLs         Other         Total
            2009         2008         2009         2008         2009           2008           2009           2008  
                                                                                   
Revenues, Net of Royalties       $ 823       $ 1,000       $ 74       $ 174       $ 10         $ 15         $ 907         $ 1,189  
Expenses                                                                                
  Production and mineral taxes         5         11         1         1         -           -           6           12  
  Transportation and selling         37         51         1         3         -           -           38           54  
  Operating         124         163         6         12         3           5           133           180  
Operating Cash Flow       $ 657       $ 775       $ 66       $ 158       $ 7         $ 10         $ 730         $ 943  
                                                                                   
          USA Division
            Gas         Oil & NGLs         Other         Total
            2009         2008         2009         2008         2009           2008           2009           2008  
                                                                                   
Revenues, Net of Royalties       $ 1,044       $ 1,308       $ 50       $ 130       $ 32         $ 87         $ 1,126         $ 1,525  
Expenses                                                                                
  Production and mineral taxes         11         107         4         11         -           -           15           118  
  Transportation and selling         125         120         -         -         -           -           125           120  
  Operating         77         106         -         -         22           80           99           186  
Operating Cash Flow       $ 831       $ 975       $ 46       $ 119       $ 10         $ 7         $ 887         $ 1,101  
                                                                                   
          Integrated Oil Division
            Oil *         Downstream Refining   Other *         Total
            2009         2008         2009         2008         2009           2008           2009           2008  
                                                                                   
Revenues, Net of Royalties       $ 277       $ 298       $ 1,313       $ 2,769       $ 66         $ 48         $ 1,656         $ 3,115  
Expenses                                                                                
  Production and mineral taxes         -         -         -         -         -           -           -           -  
  Transportation and selling         100         123         -         -         5           15           105           138  
  Operating         38         50         112         127         12           19           162           196  
  Purchased product         -         -         1,047         2,300         (18 )         (46 )         1,029           2,254  
Operating Cash Flow       $ 139       $ 125       $ 154       $ 342       $ 67         $ 60         $ 360         $ 527  
                                                                                   
* Oil and Other comprise Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties.
Segment and Geographic Information
                                                               
            Canada         USA         Downstream Refining
            2009           2008           2009           2008           2009           2008  
                                                               
Revenues, Net of Royalties       $ 3,953         $ 5,313         $ 2,300         $ 2,879         $ 2,239         $ 4,815  
Expenses                                                            
  Production and mineral taxes         32           54           61           214           -           -  
  Transportation and selling         366           604           248           235           -           -  
  Operating         577           780           214           355           230           259  
  Purchased product         (31 )         (81 )         -           -           1,796           4,121  
            3,009           3,956           1,777           2,075           213           435  
  Depreciation, depletion and amortization   1,007           1,139           795           818           97           88  
Segment Income (Loss)       $ 2,002         $ 2,817         $ 982         $ 1,257         $ 116         $ 347  
                                                               
            Market Optimization         Corporate & Other   Consolidated
            2009           2008           2009           2008           2009           2008  
                                                               

Revenues, Net of Royalties

      $ 858         $ 1,272         $ (980 )       $ (1,423 )       $ 8,370         $ 12,856  
Expenses                                                            
  Production and mineral taxes         -           -           -           -           93           268  
  Transportation and selling         -           -           -           -           614           839  
  Operating         15           19           29           (8 )         1,065           1,405  
  Purchased product         829           1,235           -           -           2,594           5,275  
            14           18           (1,009 )         (1,415 )         4,004           5,069  
  Depreciation, depletion and amortization   9           8           55           79           1,963           2,132  
Segment Income (Loss)       $ 5         $ 10         $ (1,064 )       $ (1,494 )         2,041           2,937  
  Administrative                                                 205           381  
  Interest, net                                                 233           281  
  Accretion of asset retirement obligation                                         36           41  
  Foreign exchange (gain) loss, net                                                 (2 )         60  
  (Gain) loss on divestitures                                                 2           (17 )
                                                    474           746  
Net Earnings Before Income Tax                                                 1,567           2,191  
  Income tax expense                                                 366           877  
Net Earnings                                               $ 1,201         $ 1,314  
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       $ 1,595       $ 2,416       $ 1,822       $ 2,264       $ 536         $ 633         $ 3,953         $ 5,313  
Expenses                                                                                
  Production and mineral taxes         21         37         11         16         -           1           32           54  
  Transportation and selling         115         224         75         110         176           270           366           604  
  Operating         211         289         263         358         103           133           577           780  
  Purchased product         -         -         -         -         (31 )         (81 )         (31 )         (81 )
Operating Cash Flow       $ 1,248       $ 1,866       $ 1,473       $ 1,780       $ 288         $ 310         $ 3,009         $ 3,956  
                                                                                   
          Canadian Plains Division
            Gas         Oil & NGLs         Other         Total
            2009         2008         2009         2008         2009           2008           2009           2008  
                                                                                   
Revenues, Net of Royalties       $ 996       $ 1,219       $ 593       $ 1,193       $ 6         $ 4         $ 1,595         $ 2,416  
Expenses                                                                                
  Production and mineral taxes         8         18         13         19         -           -           21           37  
  Transportation and selling         21         37         94         187         -           -           115           224  
  Operating         102         147         106         140         3           2           211           289  
Operating Cash Flow       $ 865       $ 1,017       $ 380       $ 847       $ 3         $ 2         $ 1,248         $ 1,866  
                                                                                   
          Canadian Foothills Division
            Gas         Oil & NGLs         Other         Total
            2009         2008         2009         2008         2009           2008           2009           2008  
                                                                                   
Revenues, Net of Royalties       $ 1,671       $ 1,909       $ 131       $ 322       $ 20         $ 33         $ 1,822         $ 2,264  
Expenses                                                                                
  Production and mineral taxes         9         14         2         2         -           -           11           16  
  Transportation and selling         71         104         4         6         -           -           75           110  
  Operating         244         324         12         23         7           11           263           358  
Operating Cash Flow       $ 1,347       $ 1,467       $ 113       $ 291       $ 13         $ 22         $ 1,473         $ 1,780  
                                                                                   
          USA Division
            Gas         Oil & NGLs         Other         Total
            2009         2008         2009         2008         2009           2008           2009           2008  
                                                                                   
Revenues, Net of Royalties       $ 2,162       $ 2,491       $ 79       $ 229       $ 59         $ 159         $ 2,300         $ 2,879  
Expenses                                                                                
  Production and mineral taxes         54         194         7         20         -           -           61           214  
  Transportation and selling         248         235         -         -         -           -           248           235  
  Operating         159         207         -         -         55           148           214           355  
Operating Cash Flow       $ 1,701       $ 1,855       $ 72       $ 209       $ 4         $ 11         $ 1,777         $ 2,075  
                                                                                   
          Integrated Oil Division
            Oil *         Downstream Refining   Other *         Total
            2009         2008         2009         2008         2009           2008           2009           2008  
                                                                                   
Revenues, Net of Royalties       $ 440       $ 536       $ 2,239       $ 4,815       $ 96         $ 97         $ 2,775         $ 5,448  
Expenses                                                                                
  Production and mineral taxes         -         -