EnCana generates 2009 cash flow of US$5.0 billion, or $6.68 per share, on a pro forma basis

CALGARY, Alberta-- EnCana Corporation (TSX, NYSE: ECA) achieved strong 2009 financial and operating performance during a major economic downturn and a year when benchmark natural gas prices averaged about US$4.00 per thousand cubic feet (Mcf), the lowest level in seven years. On a pro forma basis, which reflects EnCana as if it had completed its recent split transaction prior to 2009, the company generated cash flow of $5.0 billion, or $6.68 per share and operating earnings were $1.8 billion, or $2.35 per share. Fourth quarter pro forma cash flow was $930 million, or $1.24 per share. Pro forma operating earnings were $373 million, or $0.50 per share. Fourth quarter production on a pro forma basis was 2.8 billion cubic feet equivalent per day (Bcfe/d). Pro forma financial results in 2009 were enhanced by EnCana’s favourable commodity price hedges, which resulted in realized hedging gains during the year of about $2.3 billion after-tax. Total production in 2009 was 3.0 Bcfe/d, on a pro forma basis.

 

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

Consolidated operating earnings in 2009 were $4.65 per share, $1.14 per share in the fourth quarter
EnCana’s cash flow for 2009 was $6.8 billion, or $9.02 per share, on a consolidated basis, which includes the financial and operating results of the Cenovus Energy Inc. assets for the first 11 months of 2009. Operating earnings were $3.5 billion, or $4.65 per share and net earnings were $1.9 billion, or $2.48 per share. On a consolidated basis, total production in 2009 was 4.4 Bcfe/d, while natural gas production was 3.6 billion cubic feet per day (Bcf/d). In the fourth quarter of 2009, on a consolidated basis, cash flow was $603 million, or $0.80 per share. Consolidated operating earnings for the quarter were $855 million, or $1.14 per share and net earnings were $636 million, or $0.85 per share. On a consolidated basis, total production for the fourth quarter of 2009 was 3.8 Bcfe/d.

Pro forma proved reserves additions replaced 169 percent of 2009 production
On a pro forma basis, EnCana replaced 169 percent of its 2009 production at an average finding and development cost of $1.62 per thousand cubic feet of gas equivalent (Mcfe), while total reserves increased 3 percent to 12.8 trillion cubic feet of gas equivalent (Tcfe). These pro forma reserves metrics are “before SEC price revisions” and the methodology employed is comparable with that of several of EnCana’s U.S. natural gas peer companies. For information on reserves reporting protocols see Note 2 on page 9.

Strong performance in a challenging year of transformative change
“In a year of significant and widespread economic crisis, our company thrived at the same time that it completed a major corporate transformation into two highly-focused energy producers – North America’s newest and highly promising integrated oil producer Cenovus Energy Inc. and EnCana, a pure-play natural gas company. The new EnCana is now very well positioned to achieve even greater success through significant, low-cost organic natural gas production growth for many years ahead,” said Randy Eresman, President & Chief Executive Officer.

“In 2009, we met our pro forma cash flow and operating cost expectations. During a year of substantially reduced drilling activity, we grew our total proved reserves by 3 percent at an attractive finding and development cost. We delivered on our key business objectives while maintaining financial strength, expanding our portfolio of unconventional natural gas opportunities, divesting of non-core properties and continuing to pay a stable dividend to shareholders. EnCana’s 2009 performance again validated the strength of our resource play business model,” Eresman said.

Well positioned to thrive by achieving strong growth and attractive margins in a competitive price world
“As we look ahead, we remain highly focused on achieving production growth that targets an average of 10 per cent a year over the long term, and at a cost that is among the lowest in industry. While we recognize that the abundance of North American natural gas likely heralds a future of lower and less volatile natural gas prices, our operating practices, leading technologies and increasing efficiencies position us very well to continue to capture strong margins and thrive in a competitive price environment,” Eresman said.

Large and diverse natural gas plays
“We are a leading North American producer of unconventional natural gas with a huge land position in four of the continent’s six major natural gas shale plays. We have a strong balance sheet and are extremely well positioned financially to capitalize on attractive investment opportunities that may emerge. Our commodity price risk management program is aimed at continuing to underpin our capital investments and we are maintaining our focus on applying advanced technology to increase operational efficiencies across all of our projects. Our 2009 performance demonstrated our ability to create value for shareholders throughout the economic cycle and the resilience of EnCana’s long-term strategy – a historically successful approach that we plan to apply as we move forward,” Eresman said.

IMPORTANT NOTE: Consolidated results and pro forma results defined
On November 30, 2009, EnCana completed a major corporate reorganization – a split transaction that resulted in the company’s transition into a pure-play natural gas company and the spin off of its Integrated Oil and Canadian Plains assets into Cenovus Energy Inc., an independent, publicly-traded energy company. EnCana’s consolidated results include the financial and operating performance of the Cenovus assets for the first 11 months of 2009 and are reflected in EnCana’s consolidated fourth quarter and 2009 financial statements, beginning on page 15 of this news release. To give investors a clear understanding of post-split EnCana, fourth quarter and 2009 financial and operating results in this news release highlight EnCana’s results on a pro forma basis, which reflect the company as if the split transaction had been completed for all of 2009 and the previous years presented. In this pro forma presentation, the results associated with the assets and operations transferred to Cenovus are eliminated from EnCana’s consolidated results, and adjustments specific to the split transaction are reflected. Additional financial information that reconciles the consolidated and pro forma financial information is included in this news release beginning on page 12.

Per share amounts for pro forma and consolidated cash flow and earnings are on a diluted basis. EnCana reports in U.S. dollars unless otherwise noted and follows U.S. protocols, which report 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).

EnCana 2009 Highlights - Pro forma

Financial

  • Cash flow of $5.0 billion, or $6.68 per share
  • Operating earnings of $1.8 billion, or $2.35 per share
  • Capital investment, excluding acquisitions and divestitures, of $3.8 billion
  • Free cash flow of $1.3 billion

Operating

  • Total production of 3.0 Bcfe/d
  • Total natural gas production of 2.8 Bcf/d
  • Oil and natural gas liquids (NGLs) production of about 27,000 barrels per day (bbls/d)
  • Operating and administrative costs of $1.11 per Mcfe

Reserves (before SEC price revisions)

  • Proved reserves of 12.8 Tcfe
  • Added 1.9 Tcfe of proved reserves, compared to production of 1.1 Tcfe, for a production replacement of 169 percent
  • Finding and development (F&D) costs were $1.62 per Mcfe
  • Three-year (2007-2009) F&D costs averaged $1.92 per Mcfe
  • Proved reserves life index of approximately 12 years

Strategic developments

  • Completed corporate reorganization to split into two independent publicly traded energy companies: EnCana Corporation, a pure play natural gas company and Cenovus Energy Inc., an integrated oil company
  • Divested non-core conventional oil and natural gas assets in North America for approximately $1.1 billion on a pro forma basis, $1.0 billion of which was in the Canadian Division (formerly the Canadian Foothills Division); acquired about $260 million of assets for net divestitures of about $815 million
 
Financial Summary – Pro forma

(for the period ended December 31)
($ millions, except per share amounts)

 

Q4
2009

 

Q4
2008

  2009  

2008

Cash flow1   930   1,502   5,021  

6,354

Per share diluted   1.24   2.00   6.68  

8.45

Operating earnings1   373   546   1,767  

2,605

Per share diluted   0.50   0.73   2.35  

3.47

Capital investment   1,127   1,388   3,755  

5,255

1 Cash flow and operating earnings are non-GAAP measures as defined in Note 1 on page 9.

 

Production & Drilling Summary – Pro forma

(for the period ended December 31)
(After royalties)

 

Q4
2009

 

Q4
2008

 

2009

 

2008

Natural Gas (MMcf/d)   2,687   2,979   2,840   2,933
Oil and NGLs (Mbbls/d)   24   33   27   33
Total Production (MMcfe/d)   2,831   3,174   3,003   3,132
Total net wells drilled   295   602   1,089   1,815

Shut-in natural gas production brought back on stream
In 2009, natural gas production, on a pro forma basis, was 2.8 Bcf/d, slightly ahead of guidance, but impacted by a decision to shut in some natural gas 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 approximately 300 million cubic feet per day (MMcf/d) pro forma for 2009. Most of this production is expected to be back on stream by the end of the first quarter of 2010. Total 2009 production was also lower due to about $815 million of net divestitures of non-core assets which were producing about 2 percent of EnCana’s daily production last year. EnCana exited January 2010 with natural gas production approaching 3.1 Bcf/d. As of January 31, 2010, about 125 MMcf/d remains shut-in in the Canadian Division.

Production from key North American resource plays

Resource Play

(After royalties)

    Daily Production – Pro forma
    2009     2008     2007
Natural Gas (MMcf/d)    

Full
Year

 

Q4

 

Q3

  Q2   Q1    

Full
Year

  Q4   Q3   Q2   Q1    

Full
Year

USA Division                                                  
Jonah     571   566   521   576   623     603   573   615   630   595     557
Piceance     362   375   334   355   386     385   377   407   383   372     348
East Texas     324   281   305   304   409     334   408   339   316   273     143
Fort Worth     136   124   135   138   149     142   143   148   137   140     124
Canadian Division                                                  
Greater Sierra     199   178   189   216   215     220   228   228   219   205     211
Cutbank Ridge     310   254   322   340   323     296   311   322   280   271     258
Bighorn     159   142   154   186   156     167   165   185   170   146     126
CBM     316   306   318   330   309     304   308   309   303   298     259
Total natural gas (MMcf/d)     2,377   2,226   2,278   2,445   2,570     2,451   2,513   2,553   2,438   2,300     2,026

Other production1 (MMcfe/d)

    626   605   605   655   633     681   661   674   682   708     769
Total production2 (MMcfe/d)     3,003   2,831   2,883   3,100   3,203     3,132   3,174   3,227   3,120   3,008     2,795

1 Other – includes natural gas and oil production outside of Key Resource Plays

2 Excludes production from oil and gas assets transferred to Cenovus under the split transaction

 

Emerging plays continue to deliver strong performance
EnCana continues to increase efficiencies and well performance and reduce costs on a per unit basis in its emerging plays. In 2009 at EnCana’s Cutbank Ridge resource play in northeast B.C., drilling, completion and tie-in costs for each well in the Montney formation were down 11 percent year-over-year to $5.8 million despite an increase in fracs per well from eight to nine. At the Horn River play in northeast B.C., EnCana is targeting drilling, completion and tie-in costs of approximately $500,000 to $600,000 per completed fracture interval for an average cost of $10 to $12 million per well. In 2009 average per well costs were reduced about 25 percent due to improvements in technology, economies of scale and cost deflation. In the Haynesville play in northern Louisiana and East Texas, drilling, completion and tie-in costs were down approximately 40 percent per well compared to the fourth quarter of 2008. EnCana is targeting total well costs of $9 million per well in 2010. EnCana’s focus in the Haynesville continues to be on land retention and completion optimization.

Drilling activity in key North American resource plays

Resource Play     Net Wells Drilled
    2009     2008     2007
     

Full
Year

 

Q4

 

Q3

  Q2   Q1     Full

Year

  Q4   Q3   Q2   Q1    

Full
Year

USA Division                                                  
Jonah     108   23   20   30   35     175   40   43   49   43     135
Piceance     129   16   25   35   53     328   70   94   81   83     286
East Texas     38   8   4   11   15     78   23   22   22   11     35
Fort Worth     26   3   1   6   16     83   21   21   20   21     75
Canadian Division                                                  
Greater Sierra     57   15   17   10   15     106   14   29   27   36     109
Cutbank Ridge     71   15   18   18   20     82   17   17   24   24     93
Bighorn     69   17   17   14   21     64   5   11   18   30     62
CBM     490   174   37   1   278     698   359   78   10   251     1,079
Total1     988   271   139   125   453     1,614   549   315   251   499     1,874

1 Excludes net wells drilled on oil and gas assets transferred to Cenovus under the split transaction

 
 

2009 Proved Reserves – Pro forma

EnCana replaces 169 percent of 2009 production
In 2009, EnCana’s total proved reserves additions replaced 169 percent of its production at an average finding and development cost of $1.62 per Mcfe. Total proved reserves increased 3 percent to 12.8 Tcfe compared to 2008. These estimates are on a pro forma basis, which reflects EnCana as if it had existed as a pure-play natural gas company for all of 2009 and previous years and are before any SEC price revisions. See page 9, Note 2: Reserves reporting protocols, in this news release for further information relating to proved reserves pricing methods.

 

2009 Proved Reserves Reconciliation – Pro forma

      Natural gas & liquids (Bcfe)
     

Canadian
Division

 

USA
Division

  Total
Start of 2009     6,261   6,141   12,402
Extensions & discoveries     715   1,597   2,312
Technical Revisions     (303)   (152)   (455)
Acquisitions     34   0   34
Divestitures     (327)   (96)   (423)
Production     (481)   (615)   (1,096)
End of Year     5,899   6,875   12,774
% Change     - 6   12   3

Price Revisions (SEC)1

    (337)   (914)   (1,251)
End of Year, (SEC)     5,562   5,961   11,523

1 The impact of significantly lower natural gas prices for U.S. Securities and Exchange Commission (SEC) reporting purposes (Henry Hub price of $3.87 per MMbtu in 2009 versus $5.71 per MMbtu in 2008) is reflected in the SEC price revisions. For additional information on reserves reporting protocols see Note 2 on page 9.

At December 31, 2009, pro forma proved undeveloped reserves as a percentage of total proved reserves were 44 percent before SEC price revisions and 41 percent after SEC price revisions. In both cases, all proved undeveloped reserves are scheduled to be converted to proved developed reserves within the next five years.

 
Proved Reserves Costs – Pro forma
      2009   2008   2007   3 Years
F&D Capital investment1 ($ millions)     3,016   4,029   3,669   10,714
Reserves additions (Bcfe)     1,857   1,848   1,889   5,594
Finding and Development cost ($/Mcfe)     1.62   2.18   1.94   1.92

1 F&D Capital investment excludes most land, central facility and gathering system capital in an effort to be more consistent with US reporting entities.

All of EnCana’s proved reserves are evaluated by independent qualified reserves evaluators.

Revised reserve reporting rules under the SEC
Under the amended SEC rules, EnCana’s 2009 reserves have been determined based on 12-month average prices. EnCana’s 2009 net proved reserves information as defined under SEC disclosure protocols will be disclosed in the company’s Annual Information Form later this month. This disclosure will reflect the SEC average price and changes due to the split transaction. EnCana does not use prices derived for SEC reporting purposes in the day-to-day operation of its business or for planning purposes. For information on reserves reporting protocols see Note 2 on page 9.

 
2009 Natural Gas and Oil Prices – Pro forma
     

Q4
2009

 

Q4
2008

  2009   2008
Natural gas                  
NYMEX     4.17   6.94   3.99   9.04
EnCana realized gas price1     6.44   7.33   7.03   8.06
Oil and NGLs                  
WTI     76.13   59.08   62.09   99.75
EnCana realized liquids price1     62.31   45.92   48.14   80.73

1 Realized prices include the impact of financial hedging.

Price risk management
Risk management positions at December 31, 2009 are presented in Note 17 to the unaudited Interim Consolidated Financial Statements for the fourth quarter of 2009. In 2009, on a pro forma basis, EnCana’s commodity price risk management measures resulted in realized gains of approximately $2.3 billion after tax.

About 60 percent of 2010 natural gas production hedged; additional hedges in place for 2011 and 2012
EnCana has hedged approximately 2 Bcf/d of expected 2010 natural gas production at an average NYMEX price of $6.04 per Mcf. In addition, as of January 31, 2010, EnCana has hedged approximately 935 MMcf/d of expected 2011 gas production at an average price of $6.52 per Mcf, and about 870 MMcf/d of expected 2012 production at an average price of $6.47 per Mcf.

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.

EnCana 2009 Highlights - Consolidated

Financial

  • Cash flow of $6.8 billion, or $9.02 per share
  • Operating earnings of $3.5 billion, or $4.65 per share
  • Net earnings of $1.9 billion, or $2.48 per share
  • Capital investment, excluding acquisitions and divestitures, of $5.5 billion
  • Free cash flow of $1.3 billion
 
Financial Summary – Consolidated
(for the period ended December 31)

($ millions, except per share amounts)

 

Q4
2009

 

Q4
2008

 

2009

  2008
Cash flow1   603   1,299   6,779   9,386
Per share diluted   0.80   1.73   9.02   12.48
Operating earnings1   855   449   3,495   4,405
Per share diluted   1.14   0.60   4.65   5.86
Net earnings   636   1,077   1,862   5,944
Per share diluted   0.85   1.43   2.48   7.91
Capital investment   1,409   2,014   5,454   7,301
Earnings Reconciliation Summary – Total Consolidated
Net earnings                

Add back (losses) & deduct gains:

  636   1,077   1,862   5,944

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

  (200)   747   (1,792)   1,818

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

  (19)   (119)   159   (378)

Gain (loss) on discontinuance, after-tax

  -   -   -   99

Operating earnings1

  855   449   3,495   4,405

Per share diluted

  1.14   0.60   4.65   5.86

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 2009 were affected by the combined impact of realized and unrealized hedging gains/losses, resulting in an after-tax gain of $1,143 million.

Corporate developments

Split transaction completed
On November 30, 2009, EnCana completed a corporate reorganization to split EnCana into two independent publicly traded energy companies: EnCana Corporation, a pure-play natural gas company, and Cenovus Energy Inc., an integrated oil company.

Non-binding advisory vote on executive compensation for 2011
As part of EnCana’s ongoing commitment to strong corporate governance practices, on February 10, 2010 EnCana’s Board of Directors approved a plan to include a non-binding advisory vote by shareholders on executive compensation (say on pay) at its annual general meeting planned for April 2011. This vote will give EnCana shareholders an opportunity to provide feedback to the Board of Directors on the company’s approach to executive compensation.

Quarterly dividend of 20 cents per share declared
On February 10, 2010 EnCana's Board of Directors declared a quarterly dividend of US$0.20 per share payable on March 31, 2010 to common shareholders of record as of March 15, 2010.

EnCana sells non-core properties for approximately $1.1 billion
In 2009, EnCana had divestitures of approximately $1.1 billion, resulting in about $815 million of divestitures net of acquisitions, on a pro forma basis. In the Canadian Division, EnCana divested about $1.0 billion of non-core conventional oil and natural gas assets, including the August 2009 sale to Bonavista Energy Trust of about 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. EnCana’s USA Division divested about $73 million of non-core assets, while another $103 million in divestitures were related to the former Canadian Plains and Integrated Oil divisions. Included in those divestitures is EnCana’s sale on November 3, 2009 of the shares of Senlac Oil Ltd., which owned west-central Saskatchewan heavy oil operations, for approximately $83 million.

Normal Course Issuer Bid renewed
On December 9, 2009 EnCana announced it had received approval for renewal of the company's Normal Course Issuer Bid (NCIB) from the Toronto Stock Exchange (TSX). Under the renewed bid, EnCana may purchase for cancellation up to 37.5 million of its common shares, representing about 5 percent of the approximately 751 million common shares issued and outstanding as at November 30, 2009.

EnCana 2010 guidance
EnCana’s 2010 guidance documents are posted on the company’s website at www.encana.com.

Financial strength

EnCana has a strong balance sheet, with 100 percent of outstanding debt composed of long-term, fixed-rate debt with an average remaining term of more than 13 years. The company has upcoming debt maturities of $200 million in 2010 and $500 million in 2011. At December 31, 2009, EnCana had $4.9 billion in unused committed credit facilities. With EnCana’s bank facilities undrawn and $4.3 billion of cash on the balance sheet at year-end 2009, the company’s liquidity position is extremely strong. EnCana manages its financial strategy to achieve a strong investment grade credit rating. At December 31, 2009 on a pro forma basis, the company’s debt to capitalization ratio was 32 percent and debt to adjusted EBITDA, on a trailing 12-month basis, was 2.1 times.

In 2009, EnCana invested $3.8 billion in capital, on a pro forma basis, primarily focused on continued development of EnCana’s North American key resource plays.

CONFERENCE CALL TODAY
11 a.m. Mountain Time (1 p.m. Eastern Time)

 

EnCana will host a conference call today Thursday, February 11, 2010 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 4:00 p.m. ET on February 11 until midnight February 18, 2010 by dialing (800) 642-1687 or (416) 849-0833 and entering passcode 48166324.

 

A live audio webcast of the conference call will also be available via EnCana’s website, www.encana.com, under Investors/Presentations & events. 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, net change in non-cash working capital from continuing operations and net change in non-cash working capital from discontinued operations, 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.

NOTE 2: Reserves reporting protocols
Under the amended SEC rules, EnCana’s 2009 proved reserves have been determined based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. For 2009, this resulted in a Henry Hub natural gas price of $3.87 per MMbtu, compared to a December 31st single-day price of $5.71 per MMbtu for 2008 reporting purposes. Because EnCana does not use prices derived for SEC reporting purposes in the day-to-day operation of its business or for planning purposes, it has highlighted 2009 reserves information in this news release as “before SEC price revisions” attributable to the changes in natural gas pricing assumptions, which EnCana believes is a better reflection of its annual reserves additions performance. For all “before SEC price revisions” reserves estimates highlighted in this news release, EnCana has used Henry Hub forecast prices of $5.50 per MMbtu for 2010 and $6.50 per MMbtu for 2011 and beyond. EnCana’s 2009 net proved reserves information as defined under SEC disclosure protocols will be disclosed in the company’s Annual Information Form later this month. This disclosure will reflect the SEC average price and changes due to the company’s split transaction.

EnCana Corporation
EnCana is a leading North American natural gas producer that is focused on growing its strong portfolio of prolific shale and other unconventional natural gas developments, called resource plays, in key basins from northeast British Columbia to east Texas and Louisiana. 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.

RESERVES METRICS DEFINITIONS
Production replacement is calculated by dividing reserves additions by production in the same period. Reserves additions over a given period, in this case 2009, are calculated by summing extensions and discoveries and technical revisions. Reserves additions exclude acquisitions and divestitures. Finding and development cost before price revisions is calculated by dividing total capital invested in finding and development activities by additions to proved reserves, before acquisitions and divestitures, which is the sum of extensions and discoveries and technical revisions. Proved reserves added in 2009 included both developed and undeveloped quantities. Additions to EnCana’s proved undeveloped reserves were consistent with EnCana’s resource play focus. The company estimates that 100 percent of its proved undeveloped reserves will be developed within the next five years. 2009 finding and development capital includes investment in long lead time projects but excludes most land, central facility and gathering system capital in an effort to be more consistent with US reporting entities. EnCana uses the aforementioned metrics as indicators of relative performance, along with a number of other measures. Many performance measures exist, all measures have limitations and historical measures are not necessarily indicative of future performance.

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 the relevant legal requirements of the U.S. Securities and Exchange Commission. 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). 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). 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 2010 budgets for EnCana (including cash flow, cash flow per share, free cash flow, capital investment, divestitures and total production); anticipated allocation of capital for EnCana in 2010, including among various projects; the potential success of such projects as Deep Panuke, Cutbank Ridge and Bighorn anticipated crude oil and natural gas prices, including basis differentials for various regions; 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 2010 and beyond; anticipated plans to bring production back on in the event of the recovery of natural gas prices; anticipated costs and cost reductions; expectations to convert proved undeveloped reserves to proved developed within the next five years; references to potential exploration; expected number of future drilling locations in Cutbank Ridge; estimated drilling, completion and tie-in costs per completed interval, including total cost per well, in Horn River; expected number of fracture simulations in 2010 in Horn River; expected completion of first phase and capacity of Cabin Gas Plant project; expected number of wells to be drilled and target exit rate in Haynesville; estimated reserve life index; expected downtrend in finding and development costs over the next couple of years; expected percentage increase in production in 2010; expectation to add to current hedging positions; expectation for 2010 that inflationary pressures will remain flat; estimate that for 2010 and beyond North American natural gas prices will on average be lower than historical prices; expectation to deliver double digit growth for the long term. 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, as well as assumptions based upon 2010 EnCana 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; 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 processing facilities; risks associated with technology; the company’s ability to replace and expand 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 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. 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.

FOR FURTHER INFORMATION:

EnCana Corporate Communications
Investor contact:     Media contact:
Ryder McRitchie     Alan Boras
Vice-President, Investor Relations     Vice-President, Media Relations
(403) 645-2007     (403) 645-4747
EnCana Corporation
 
 
Interim Supplemental Information - Selected Excerpts
(unaudited)
 
For the period ended December 31, 2009
 
U.S. Dollars / U.S. Protocol
Supplemental Financial Information
 
The following Supplemental Information presents selected historical pro forma financial and operating information related to the ongoing operations of EnCana Corporation ("EnCana"). The information excludes the results of operations from assets distributed to Cenovus Energy Inc. as part of the Split Transaction; See Note 4 to the December 31, 2009 Interim Consolidated Financial Statements.
 
For background on the pro forma information please refer to Note 1 - Basis of Presentation in the Notes to EnCana Pro Forma Consolidated Statements of Earnings and Cash from Operating Activities.
 
Pro Forma Consolidated Statement of Earnings (unaudited)
 
For the Year Ended December 31,  

 

             

2009

  2008
        Deduct   Add/(Deduct)            
    EnCana   Cenovus   Pro Forma       EnCana   EnCana
($ millions, except per share amounts)   Consolidated   Carve-out   Adjustments   Note 2   Pro Forma   Pro Forma
                         
Revenues, Net of Royalties   $ 11,114     $ 4,382    

$

 

        $ 6,732     $ 13,505  
                         
Expenses                        
Production and mineral taxes     171       39               132       403  
Transportation and selling     1,280       596               684       741  
Operating     1,627       619               1,008       1,252  
Purchased product     1,460       640               820       1,476  
Depreciation, depletion and amortization     3,704       1,052       118     (A)     2,770       3,096  
Administrative     477       108       41     (B)     359       329  
              (51 )   ©        
Interest, net     405       34               371       368  
Accretion of asset retirement obligation     71       34               37       40  
Foreign exchange (gain) loss, net     (22 )     290               (312 )     673  
(Gain) loss on divestitures     2       -               2       (143 )
Net Earnings Before Income Tax     1,939       970       (108 )         861       5,270  
Income tax expense     109       393       396     (D i,ii,iii,iv)     112       1,865  
Net Earnings from Continuing Operations     1,830       577       (504 )         749       3,405  
Net Earnings from Discontinued Operations     32       32       -           -       -  
Net Earnings   $ 1,862     $ 609     $ (504 )       $ 749     $ 3,405  
                         
Net Earnings from Continuing Operations per Common Share               (E)        
Basic   $ 2.44                 $ 1.00     $ 4.54  
Diluted   $ 2.44                 $ 1.00     $ 4.53  
                         
Net Earnings per Common Share               (E)        
Basic   $ 2.48                 $ 1.00     $ 4.54  
Diluted   $ 2.48                 $ 1.00     $ 4.53  
 
Pro Forma Consolidated Statement of Cash from Operating Activities (unaudited)
                         
For the Year Ended December 31,  

 

             

2009

  2008
        Deduct   Add/(Deduct)            
    EnCana   Cenovus   Pro Forma       EnCana   EnCana
($ millions)   Consolidated   Carve-out   Adjustments   Note 2   Pro Forma   Pro Forma
                         
Operating Activities                        
Net earnings from continuing operations   $ 1,830     $ 577     $ (504 )       $ 749     $ 3,405  
Depreciation, depletion and amortization     3,704       1,052       118     (A)     2,770       3,096  
Future income taxes     (1,799 )     (501 )     860     (D i,ii,iii,iv)     (438 )     1,297  
Cash tax on sale of assets     -       -               -       25  
Unrealized (gain) loss on risk management     2,680       614               2,066       (1,995 )
Unrealized foreign exchange (gain) loss     (231 )     277               (508 )     676  
Accretion of asset retirement obligation     71       34               37       40  
(Gain) loss on divestitures     2       -               2       (143 )
Other     373       30               343       (47 )
Cash flow from discontinued operations     149       149               -       -  
Net change in other assets and liabilities     23       (15 )             38       (173 )
Net change in non-cash working capital from continuing operations     (29 )     (11 )             (18 )     43  
Net change in non-cash working capital from discontinued operations     1,100       1,100               -       -  
Cash From Operating Activities   $ 7,873     $ 3,306     $ 474         $ 5,041     $ 6,224  
 
Notes to Pro Forma Consolidated Statements of Earnings and
Cash from Operating Activities (unaudited)
 
1. Basis of Presentation
 
On November 30, 2009, EnCana completed a corporate reorganization (the “Split Transaction”) involving the division of EnCana into two independent publicly traded energy companies – EnCana and Cenovus Energy Inc. The unaudited Pro Forma Consolidated Statement of Earnings and Pro Forma Consolidated Statement of Cash from Operating Activities have been prepared for information purposes and assumes the Split Transaction occurred on January 1, 2008. Pro forma adjustments are detailed in Note 2.
 
The unaudited Pro Forma Consolidated Statement of Earnings and Pro Forma Consolidated Statement of Cash from Operating Activities are expressed in United States dollars and have been prepared for information purposes using information contained in the following:
a)   EnCana's audited Consolidated Financial Statements for the years ended December 31, 2009 and 2008.
b)   Cenovus Energy unaudited Carve-out Consolidated Financial Statements for the 11 months ended November 30, 2009 and the Cenovus Energy unaudited Carve-out Consolidated Financial Statements for the year ended December 31, 2008. The Cenovus unaudited Carve-out Consolidated Financial Statements were derived from the accounting records of EnCana on a carve-out basis.
c)   EnCana's unaudited Pro Forma Consolidated Financial Statements for the year ended December 31, 2008.
 
In the opinion of Management of EnCana, the unaudited Pro Forma Consolidated Financial Statements include all the adjustments necessary for fair presentation in accordance with Canadian generally accepted accounting principles.
 
The unaudited Pro Forma Statement of Earnings and Pro Forma Consolidated Statement of Cash from Operating Activities are for illustrative purposes only and may not be indicative of the results that actually would have occurred if the Split Transaction had been in effect on the dates indicated or of the results that may be obtained in the future. In addition to the pro forma adjustments to the historical carve-out financial statements, various other factors will have an effect on the results of operations.
 
2. Pro Forma Assumptions and Adjustments
 
The following adjustments reflect expected changes to EnCana’s historical results which would arise from the Split Transaction.
 
A.   Reflects the expected difference in depreciation, depletion and amortization expense arising from a change in the depletion rate calculated for EnCana’s Canadian cost centre.
 
B.   Increases administrative expense for additional compensation costs arising from the separation of compensation plans and the estimated increase in the number of employees required to operate EnCana as a separate entity, after removing those costs associated with Cenovus’s employees.
 
C.   Reduces administrative expense to remove EnCana’s share of the transaction costs incurred related to the Split Transaction.
 
D.   Pro forma adjustments to income tax expense,
 
   

i. adjustments for the tax effect of items A, B and C above;

   

ii. adjustments for the effect of the loss of tax deferrals resulting from the wind up of EnCana’s Canadian upstream oil and gas partnership;

   

iii. acceleration of the intangible drilling costs deduction in the U.S. as a result of a change in the status of EnCana being considered an independent producer; and

   

iv. remove tax benefits solely resulting from the Split Transaction.

 
E.   The Pro Forma Net Earnings per Common Share is calculated using the same weighted average number of pre-Arrangement EnCana Corporation Common Shares outstanding as at December 31, 2009.
 
    For the year ended December 31,
    (millions)   2009   2008
 
    Weighted Average Common Shares Outstanding - Basic   751.0   750.1
    Effects of Stock Options and Other Dilutive Securities   0.4   1.7
    Weighted Average Common Shares Outstanding - Diluted   751.4   751.8
 
 
Financial Statistics
 
($ millions, except per share amounts)   2009       2008
    Year   Q4   Q3   Q2   Q1       Year   Q4   Q3   Q2   Q1
 
Pro Forma Reconciliation
 
Cash Flow (1)
EnCana Corporation, Consolidated   6,779     603     2,079     2,153   1,944    

 

  9,386     1,299     2,809     2,889     2,389  
     
Less: Cenovus Carve-out (2)   2,232     (15 )   841     811   595         3,088     (174 )   1,123     1,228     911  
Add/(Deduct) Pro Forma adjustments   474     312     36     88   38    

 

  56     29     48     -     (21 )
                                             
EnCana Pro Forma   5,021     930     1,274     1,430   1,387    

 

  6,354     1,502     1,734     1,661     1,457  
Per share amounts                                            
EnCana Corporation, Consolidated   - Basic   9.03     0.80     2.77     2.87   2.59         12.51     1.73     3.74     3.85     3.19  
    - Diluted   9.02     0.80     2.77     2.87   2.59         12.48     1.73     3.74     3.85     3.17  
                                                 
EnCana Pro Forma   - Basic   6.69     1.24     1.70     1.90   1.85         8.47     2.00     2.31     2.21     1.94  
    - Diluted   6.68     1.24     1.70     1.90   1.85         8.45     2.00     2.31     2.21     1.93  
 
Net Earnings
EnCana Corporation, Consolidated   1,862     636     25     239   962    

 

  5,944     1,077     3,553     1,221     93  
 
Less: Cenovus Carve-out (2)   609     (15 )   63     149   412         2,368     380     1,299     522     167  
Add/(Deduct) Pro Forma adjustments   (504 )   (418 )   (15 )   2   (73 )       (171 )   (26 )   (26 )   (56 )   (63 )
 
EnCana Pro Forma   749     233     (53 )   92   477    

 

  3,405     671     2,228     643     (137 )
Per share amounts                                            
EnCana Corporation, Consolidated   - Basic   2.48     0.85     0.03     0.32   1.28         7.92     1.44     4.74     1.63     0.12  
    - Diluted   2.48     0.85     0.03     0.32   1.28         7.91     1.43     4.73     1.63     0.12  
 
EnCana Pro Forma   - Basic   1.00     0.31     (0.07 )   0.12   0.64         4.54     0.89     2.97     0.86     (0.18 )
    - Diluted   1.00     0.31     (0.07 )   0.12   0.63         4.53     0.89     2.97     0.86     (0.18 )
 
Operating Earnings (3)
EnCana Corporation, Consolidated   3,495     855     775     917   948    

 

  4,405     449     1,442     1,469     1,045  
 
Less: Cenovus Carve-out (2)   1,224     64     382     447   331         1,629     (123 )   611     710     431  
Add/(Deduct) Pro Forma adjustments   (504 )   (418 )   (15 )   2   (73 )  

 

  (171 )   (26 )   (26 )   (56 )   (63 )
 
EnCana Pro Forma   1,767     373     378     472   544    

 

  2,605     546     805     703     551  
Per share amounts
EnCana Corporation, Consolidated   - Diluted   4.65     1.14     1.03     1.22   1.26         5.86     0.60     1.92     1.96     1.39  
 
EnCana Pro Forma   - Diluted   2.35     0.50     0.50     0.63   0.72         3.47     0.73     1.07     0.94     0.73  

(1)

Cash Flow is a non-GAAP measure defined as Cash from Operating Activities excluding net change in other assets and liabilities, net change in non-cash working capital and net change in non-cash working capital from discontinued operations, which are defined on the Consolidated Statement of Cash Flows.
   

(2)

Cenovus Energy was spun-off on November 30, 2009. As a result, carve-out information for the fourth quarter is for the two months ended November 30, 2009 and the Year-to-date information is for the 11 months ended November 30, 2009.
   

(3)

Operating Earnings is a non-GAAP measure defined as Net Earnings excluding the after-tax gain/loss on discontinuance, after-tax effect of unrealized mark-to-market accounting gains/losses on derivative instruments, after-tax gains/losses on translation of U.S. dollar denominated debt issued from Canada, after-tax foreign exchange gains/losses 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.
 
EnCana Corporation
 
 
Interim Consolidated Financial Statements
(unaudited)
 
For the period ended December 31, 2009
 
(U.S. Dollars)
   
Consolidated Statement of Earnings (unaudited)
   
    Three Months Ended   Twelve Months Ended
    December 31,   December 31,
($ millions, except per share amounts)   2009   2008   2009   2008
 
Revenues, Net of Royalties   (Note 5)   $ 2,712     $ 4,862     $ 11,114     $ 21,053  
 
Expenses   (Note 5)                
Production and mineral taxes         49       72       171       478  
Transportation and selling         311       422       1,280       1,704  
Operating         381       432       1,627       1,983  
Purchased product         340       506       1,460       2,426  
Depreciation, depletion and amortization         895       946       3,704       4,035  
Administrative         145       67       477       447  
Interest, net   (Note 8)     153       113       405       402  
Accretion of asset retirement obligation   (Note 13)     16       17       71       77  
Foreign exchange (gain) loss, net   (Note 9)     95       253       (22 )     423  
(Gain) loss on divestitures   (Note 7)     1       -       2       (141 )
          2,386       2,828       9,175       11,834  
Net Earnings Before Income Tax         326       2,034       1,939       9,219  
Income tax expense (recovery)   (Note 10)     (263 )     565       109       2,720  
Net Earnings From Continuing Operations         589       1,469       1,830       6,499  
Net Earnings (Loss) From Discontinued Operations   (Note 6)     47       (392 )     32       (555 )
Net Earnings       $ 636     $ 1,077     $ 1,862     $ 5,944  
 
Net Earnings From Continuing Operations per Common Share   (Note 14)              
Basic       $ 0.78     $ 1.96     $ 2.44     $ 8.66  
Diluted       $ 0.78     $ 1.96     $ 2.44     $ 8.64  
                     
Net Earnings per Common Share   (Note 14)              
Basic       $ 0.85     $ 1.44     $ 2.48     $ 7.92  
Diluted       $ 0.85     $ 1.43     $ 2.48     $ 7.91  
   
   
Consolidated Statement of Comprehensive Income (unaudited)
   
    Three Months Ended   Twelve Months Ended
    December 31,   December 31,
($ millions)   2009   2008   2009   2008
                 
Net Earnings   $ 636     $ 1,077     $ 1,862     $ 5,944  
Other Comprehensive Income, Net of Tax                
Foreign Currency Translation Adjustment     388       (1,448 )     2,018       (2,230 )
Comprehensive Income   $ 1,024     $ (371 )   $ 3,880     $ 3,714  
 

See accompanying Notes to Consolidated Financial Statements.

 
Consolidated Balance Sheet (unaudited)
 
        As at   As at
        December 31,   December 31,
($ millions)       2009   2008
             
Assets            
Current Assets            
Cash and cash equivalents       $ 4,275   $ 354
Accounts receivable and accrued revenues         1,180     1,436
Current portion of partnership contribution receivable   (Note 4)     -     313
Risk management   (Note 17)     328     2,818
Inventories   (Note 11)     12     184
Assets of discontinued operations   (Note 6)     -     497
          5,795     5,602
Property, Plant and Equipment, net   (Note 5)     26,173     31,910
Investments and Other Assets         164     72
Partnership Contribution Receivable   (Note 4)     -     2,834
Risk Management   (Note 17)     32     234
Goodwill         1,663     2,426
Assets of Discontinued Operations   (Note 6)     -     4,169
    (Note 5)   $ 33,827   $ 47,247
             
Liabilities and Shareholders' Equity            
Current Liabilities            
Accounts payable and accrued liabilities       $ 2,143   $ 2,448
Income tax payable         1,776     500
Risk management   (Note 17)     126     43
Current portion of long-term debt   (Note 12)     200     250
Liabilities of discontinued operations   (Note 6)     -     653
          4,245     3,894
Long-Term Debt   (Note 12)     7,568     8,755
Other Liabilities         1,185     576
Risk Management   (Note 17)     42     7
Asset Retirement Obligation   (Note 13)     787     1,230
Future Income Taxes         3,386     6,917
Liabilities of Discontinued Operations   (Note 6)     -     2,894
          17,213     24,273
Shareholders' Equity            
Share capital   (Note 14)     2,360     4,557
Paid in surplus   (Note 14)     6     -
Retained earnings         13,493     17,584
Accumulated other comprehensive income         755     833
Total Shareholders' Equity         16,614     22,974
        $ 33,827   $ 47,247
 

See accompanying Notes to Consolidated Financial Statements.

 
Consolidated Statement of Shareholders' Equity (unaudited)
             
        Twelve Months Ended
        December 31,
($ millions)       2009   2008
             
Share Capital            
Balance, Beginning of Year       $ 4,557     $ 4,479  
Common Shares Issued under Option Plans   (Note 14)     5       80  
Common Shares Issued from PSU Trust   (Note 14)     19       -  
Stock-Based Compensation   (Note 14)     1       11  
Common Shares Purchased   (Note 14)     -       (13 )
Common Shares Cancelled   (Note 4)     (4,582 )     -  
New EnCana Common Shares Issued   (Note 4)     2,360       -  
EnCana Special Shares Issued   (Note 4)     2,222       -  
EnCana Special Shares Cancelled   (Note 4)     (2,222 )     -  
Balance, End of Year       $ 2,360     $ 4,557  
             
Paid in Surplus            
Balance, Beginning of Year       $ -     $ 80  
Common Shares Issued from PSU Trust   (Note 14)     6       -  
Stock-Based Compensation         -       1  
Common Shares Distributed under Incentive Compensation Plans         -       (81 )
Balance, End of Year       $ 6     $ -  
             
Retained Earnings            
Balance, Beginning of Year       $ 17,584     $ 13,082  
Net Earnings         1,862       5,944  
Dividends on Common Shares         (1,051 )     (1,199 )
Charges for Normal Course Issuer Bid   (Note 14)     -       (243 )
Net Distribution to Cenovus Energy   (Note 4)     (4,902 )     -  
Balance, End of Year       $ 13,493     $ 17,584  
             
Accumulated Other Comprehensive Income            
Balance, Beginning of Year       $ 833     $ 3,063  
Foreign Currency Translation Adjustment         2,018       (2,230 )
Transferred to Cenovus Energy   (Note 4)     (2,096 )     -  
Balance, End of Year       $ 755     $ 833  
Total Shareholders' Equity       $ 16,614     $ 22,974  
 

See accompanying Notes to Consolidated Financial Statements.

 
Consolidated Statement of Cash Flows (unaudited)
 
        Three Months Ended   Twelve Months Ended
        December 31,   December 31,
($ millions)       2009   2008   2009   2008
                     
Operating Activities                    
Net earnings from continuing operations       $ 589     $ 1,469     $ 1,830     $ 6,499  
Depreciation, depletion and amortization         895       946       3,704       4,035  
Future income taxes   (Note 10)     (1,281 )     409       (1,799 )     1,723  
Cash tax on sale of assets   (Note 7)     -       -       -       25  
Unrealized (gain) loss on risk management   (Note 17)     289       (1,090 )     2,680       (2,729 )
Unrealized foreign exchange (gain) loss         (82 )     268       (231 )     417  
Accretion of asset retirement obligation   (Note 13)     16       17       71       77  
(Gain) loss on divestitures   (Note 7)     1       -       2       (141 )
Other         189       (127 )     373       (79 )
Cash flow from discontinued operations         (13 )     (593 )     149       (441 )
Net change in other assets and liabilities         (13 )     22       23       (257 )
Net change in non-cash working capital from continuing operations         528       29       (29 )     (1,353 )
Net change in non-cash working capital from discontinued operations         353       802       1,100       1,210  
Cash From Operating Activities         1,471       2,152       7,873       8,986  
                     
Investing Activities                    
Capital expenditures   (Note 5)     (1,410 )     (1,806 )     (4,864 )     (7,997 )
Proceeds from divestitures   (Note 7)     148       311       1,178       904  
Cash tax on sale of assets   (Note 7)     -       -       -       (25 )
Corporate acquisitions   (Note 7)     -       -       (24 )     -  
Cash transferred on Split Transaction   (Note 4)     (3,996 )     -       (3,996 )     -  
Proceeds from notes receivable from Cenovus   (Note 4)     3,750       -       3,750       -  
Restricted cash         3,619       -       -       -  
Net change in investments and other         105       74       337       311  
Net change in non-cash working capital from continuing operations         166       (17 )     (50 )     34  
Discontinued operations         (227 )     (209 )     (1,137 )     (769 )
Cash From (Used in) Investing Activities         2,155       (1,647 )     (4,806 )     (7,542 )
                     
Financing Activities                    
Net issuance (repayment) of revolving long-term debt         (461 )     (304 )     (1,852 )     (53 )
Issuance of long-term debt   (Note 12)     -       -       496       723  
Issuance of Cenovus Notes   (Note 4)     -       -       3,468       -  
Repayment of long-term debt         -       -       (250 )     (664 )
Issuance of common shares   (Note 14)     1       2       24       80  
Purchase of common shares   (Note 14)     -       -       -       (326 )
Dividends on common shares         (150 )     (300 )     (1,051 )     (1,199 )
Cash From (Used in) Financing Activities         (610 )     (602 )     835       (1,439 )
                     
Foreign Exchange Gain (Loss) on Cash and Cash                    
Equivalents Held in Foreign Currency         8       (23 )     19       (33 )
                     
Increase (Decrease) in Cash and Cash Equivalents         3,024       (120 )     3,921       (28 )
Cash and Cash Equivalents, Beginning of Period         1,251       474       354       382  
Cash and Cash Equivalents, End of Period       $ 4,275     $ 354     $ 4,275     $ 354  
                     
Cash, End of Period         218       13       218       13  
Cash Equivalents, End of Period         4,057       341       4,057       341  
Cash and Cash Equivalents, End of Period       $ 4,275     $ 354     $ 4,275     $ 354  
 
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 and crude oil and natural gas liquids ("NGLs").
 
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. Split Transaction
 
On November 30, 2009, EnCana completed a corporate reorganization (the “Split Transaction”) involving the division of EnCana into two independent publicly traded energy companies – one, EnCana Corporation, a natural gas company, and the other, an integrated oil company, Cenovus Energy Inc. (“Cenovus”).
 
The Split Transaction was initially proposed in May 2008. In October 2008, EnCana announced the proposed reorganization would be delayed until the global debt and equity markets regained stability. In September 2009, EnCana’s Board of Directors unanimously approved plans to proceed with the split and in November 2009, shareholders approved to proceed with the Split Transaction.
 
Under the Split Transaction, EnCana shareholders received one new EnCana Common Share and one EnCana Special Share in exchange for each EnCana Common Share previously held. The book value of EnCana's outstanding Common Shares immediately prior to the Split Transaction was attributed to the new EnCana Common Shares and the EnCana Special Shares in direct proportion to the weighted average trading price of the shares on a "when issued" basis. In accordance with the calculation, the value attributed to the new EnCana Common Shares and the EnCana Special Shares was $2,360 million and $2,222 million, respectively. The EnCana Special Shares were subsequently exchanged by EnCana shareholders for Common Shares of Cenovus, thereby effecting the Split Transaction.
 
Under the Split Transaction, EnCana's downstream refining operations and certain upstream oil and gas assets were transferred to Cenovus. The historical results associated with the upstream assets transferred are reported as continuing operations in accordance with full cost accounting requirements (See Note 5). The historical results associated with the downstream refining operations have been presented as discontinued operations (See Note 6).
 
In conjunction with the proposed reorganization, on September 18, 2009, Cenovus completed a private offering of senior unsecured notes for an aggregate principal amount of $3,500 million. The unsecured notes (“Cenovus Notes”) were transferred under the Split Transaction.
 
The impact of the Split Transaction on EnCana’s Consolidated Balance Sheet is as follows. The net assets were transferred at book value.
 
Net Assets Transferred Under the Split Transaction
     
Assets    
Cash and restricted cash $ 3,996
Property, plant and equipment, net    
Oil and gas   9,329
Downstream refining (See Note 6)   4,710
Partnership contribution receivable, including current portion   2,835
Goodwill   1,083
Other current and non-current assets   2,094
    24,047
     
Liabilities    
Notes payable to EnCana   3,750
Cenovus notes   3,436
Partnership contribution payable, including current portion   2,857
Future income taxes   2,314
Other current and non-current liabilities   2,470
    14,827
Net Assets Transferred Under the Split Transaction $ 9,220
 
The Split Transaction reduced Total Shareholders’ Equity by way of a reduction in Share capital of $2,222 million, a reduction in Retained earnings of $4,902 million and a reduction in Accumulated other comprehensive income of $2,096 million.
 
Following the Split Transaction, EnCana received amounts due from Cenovus and invested the net proceeds of approximately $3.75 billion in short-term marketable securities.
 
EnCana’s continuing operations include all revenues and expenses prior to November 30, 2009 of the oil and gas assets transferred to Cenovus under the Split Transaction (See Note 5).
 
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.
  • 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.
 
In conjunction with the Split Transaction (See Note 4), the assets formerly included in EnCana’s Canadian Plains Division and Integrated Oil Division were transferred to Cenovus. As a result, EnCana has updated its segmented reporting to present the Canadian Foothills Division as the Canadian Division. The Canadian Plains Division and Integrated Oil - Canada are now presented as Canada – Other. Prior periods have been restated to reflect the new presentation.
 
EnCana has a decentralized decision-making and reporting structure. Accordingly, the Company reports its divisional results as follows:
 
  • "Canadian Division, formerly the Canadian Foothills Division, includes natural gas development and production assets located in British Columbia and Alberta, 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 forms the USA segment described above.
  • Canada - Other includes the combined results from the former Canadian Plains Division and Integrated Oil - Canada.
Operations that have been discontinued are disclosed in Note 6.
 
Results of Operations (For the three months ended December 31)
 
Segment and Geographic Information
 
    Canada   USA   Market Optimization
    2009   2008   2009   2008   2009   2008
                         
Revenues, Net of Royalties   $ 1,531     $ 1,961     $ 1,076     $ 1,273     $ 368     $ 543  
Expenses                        
Production and mineral taxes     9       13       40       59       -       -  
Transportation and selling     168       287       143       135       -       -  
Operating     252       280       120       136       -       18  
Purchased product     (13 )     (25 )     -       -       353       531  
      1,115       1,406       773       943       15       (6 )
Depreciation, depletion and amortization     436       481       393       438       5       3  
Segment Income (Loss)   $ 679     $ 925     $ 380     $ 505     $ 10     $ (9 )
                 
   

Corporate & Other

 

Consolidated

    2009   2008   2009   2008
                 
Revenues, Net of Royalties   $ (263 )   $ 1,085     $ 2,712     $ 4,862  
Expenses                
Production and mineral taxes     -       -       49       72  
Transportation and selling     -       -       311       422  
Operating     9       (2 )     381       432  
Purchased product     -       -       340       506  
      (272 )     1,087       1,631       3,430  
Depreciation, depletion and amortization     61       24       895       946  
Segment Income (Loss)   $ (333 )   $ 1,063       736       2,484  
Administrative             145       67  
Interest, net             153       113  
Accretion of asset retirement obligation             16       17  
Foreign exchange (gain) loss, net             95       253  
(Gain) loss on divestitures             1       -  
              410       450  
Net Earnings Before Income Tax             326       2,034  
Income tax expense             (263 )     565  
Net Earnings from Continuing Operations           $ 589     $ 1,469  
 
Results of Operations (For the three months ended December 31)
 
Product and Divisional Information
 
    Canada Segment
           

Canadian Division

 

Canada - Other

  Total
            2009   2008   2009   2008   2009   2008
                                 
Revenues, Net of Royalties           $ 691   $ 923   $ 840     $ 1,038     $ 1,531     $ 1,961  
Expenses                                
Production and mineral taxes             1     3     8       10       9       13  
Transportation and selling             39     72     129       215       168       287  
Operating             147     131     105       149       252       280  
Purchased product             -     -     (13 )     (25 )     (13 )     (25 )
Operating Cash Flow           $ 504   $ 717   $ 611     $ 689     $ 1,115     $ 1,406  
 
    Canadian Division *
    Gas   Oil & NGLs   Other   Total
    2009   2008   2009   2008   2009   2008   2009   2008
                                 
Revenues, Net of Royalties   $ 609   $ 829   $ 69   $ 84   $ 13     $ 10     $ 691     $ 923  
Expenses                                
Production and mineral taxes     -     2     1     1     -       -       1       3  
Transportation and selling     39     43     -     3     -       26       39       72  
Operating     139     117     4     9     4       5       147       131  
Operating Cash Flow   $ 431   $ 667   $ 64   $ 71   $ 9     $ (21 )   $ 504     $ 717  
 
    USA Division
    Gas   Oil & NGLs   Other   Total
    2009   2008   2009   2008   2009   2008   2009   2008
                                 
Revenues, Net of Royalties   $ 976   $ 1,180   $ 69   $ 54   $ 31     $ 39     $ 1,076     $ 1,273  
Expenses                                
Production and mineral taxes     34     54     6     5     -       -       40       59  
Transportation and selling     143     135     -     -     -       -       143       135  
Operating     90     86     -     -     30       50       120       136  
Operating Cash Flow   $ 709   $ 905   $ 63   $ 49   $ 1     $ (11 )   $ 773     $ 943  
 
    Canada - Other **
    Gas   Oil & NGLs   Other   Total
    2009   2008   2009   2008   2009   2008   2009   2008
                                 
Revenues, Net of Royalties   $ 298   $ 506   $ 524   $ 499   $ 18     $ 33     $ 840     $ 1,038  
Expenses                                
Production and mineral taxes     4     4     4     6     -       -       8       10  
Transportation and selling     6     16     117     192     6       7       129       215  
Operating     28     50     72     85     5       14       105       149  
Purchased product     -     -     -     -     (13 )     (25 )     (13 )     (25 )
Operating Cash Flow   $ 260   $ 436   $ 331   $ 216   $ 20     $ 37     $ 611     $ 689  
 
*Formerly known as the Canadian Foothills Division.
**Includes the operations formerly known as the Canadian Plains Division and Integrated Oil - Canada.
 
Results of Operations (For the twelve months ended December 31)
 
Segment and Geographic Information
 
    Canada   USA   Market Optimization
    2009   2008   2009   2008   2009   2008
                         
Revenues, Net of Royalties   $ 7,585     $ 10,050     $ 4,537     $ 5,629     $ 1,607     $ 2,655  
Expenses                        
Production and mineral taxes     53       108       118       370       -       -  
Transportation and selling     750       1,202       530       502       -       -  
Operating     1,118       1,333       434       618       26       45  
Purchased product     (85 )     (151 )     -       -       1,545       2,577  
      5,749       7,558       3,455       4,139       36       33  
Depreciation, depletion and amortization     1,980       2,198       1,561       1,691       20       15  
Segment Income (Loss)   $ 3,769     $ 5,360     $ 1,894     $ 2,448     $ 16     $ 18  
                 
    Corporate & Other   Consolidated
    2009   2008   2009   2008
                 
Revenues, Net of Royalties   $ (2,615 )   $ 2,719     $ 11,114     $ 21,053  
Expenses                
Production and mineral taxes     -       -       171       478  
Transportation and selling     -       -       1,280       1,704  
Operating     49       (13 )     1,627       1,983  
Purchased product     -       -       1,460       2,426  
      (2,664 )     2,732       6,576       14,462  
Depreciation, depletion and amortization     143       131       3,704       4,035  
Segment Income (Loss)   $ (2,807 )   $ 2,601       2,872       10,427  
Administrative             477       447  
Interest, net             405       402  
Accretion of asset retirement obligation             71       77  
Foreign exchange (gain) loss, net             (22 )     423  
(Gain) loss on divestitures             2       (141 )
              933       1,208  
Net Earnings Before Income Tax             1,939       9,219  
Income tax expense             109       2,720  
Net Earnings from Continuing Operations           $ 1,830     $ 6,499  
 
Results of Operations (For the twelve months ended December 31)
 
Product and Divisional Information
 
    Canada Segment
           

Canadian Division

 

Canada - Other

  Total
            2009   2008   2009   2008   2009   2008
                                 
Revenues, Net of Royalties           $ 3,362   $ 4,355   $ 4,223     $ 5,695     $ 7,585     $ 10,050  
Expenses                                
Production and mineral taxes             14     33     39       75       53       108  
Transportation and selling             154     239     596       963       750       1,202  
Operating             536     609     582       724       1,118       1,333  
Purchased product             -     -     (85 )     (151 )     (85 )     (151 )
Operating Cash Flow           $ 2,658   $ 3,474   $ 3,091     $ 4,084     $ 5,749     $ 7,558  
 
    Canadian Division *
    Gas   Oil & NGLs   Other   Total
    2009   2008   2009   2008   2009   2008   2009   2008
                                 
Revenues, Net of Royalties   $ 3,041   $ 3,720   $ 277   $ 578   $ 44     $ 57     $ 3,362     $ 4,355  
Expenses                                
Production and mineral taxes     11     28     3     5     -       -       14       33  
Transportation and selling     148     201     6     12     -       26       154       239  
Operating     501     549     21     39     14       21       536       609  
Operating Cash Flow   $ 2,381   $ 2,942   $ 247   $ 522   $ 30     $ 10     $ 2,658     $ 3,474  
 
    USA Division
    Gas   Oil & NGLs   Other   Total
    2009   2008   2009   2008   2009   2008   2009   2008
                                 
Revenues, Net of Royalties   $ 4,222   $ 4,934   $ 201   $ 407   $ 114     $ 288     $ 4,537     $ 5,629  
Expenses                                
Production and mineral taxes     100     334     18     36     -       -       118       370  
Transportation and selling     530     502     -     -     -       -       530       502  
Operating     327     352     -     -     107       266       434       618  
Operating Cash Flow   $ 3,265   $ 3,746   $ 183   $ 371   $ 7     $ 22     $ 3,455     $ 4,139  
 
    Canada - Other **
    Gas   Oil & NGLs   Other   Total
    2009   2008   2009   2008   2009   2008   2009   2008
                                 
Revenues, Net of Royalties   $ 1,781   $ 2,301   $ 2,287   $ 3,223   $ 155     $ 171     $ 4,223     $ 5,695  
Expenses                                
Production and mineral taxes     15     36     23     38     1       1       39       75  
Transportation and selling     37     71     535     847     24       45       596       963  
Operating     186     241     356     409     40       74       582       724  
Purchased product     -     -     -     -     (85 )     (151 )     (85 )     (151 )
Operating Cash Flow   $ 1,543   $ 1,953   $ 1,373   $ 1,929   $ 175     $ 202     $ 3,091     $ 4,084  
 
*Formerly known as the Canadian Foothills Division.
**Includes the operations formerly known as the Canadian Plains Division and Integrated Oil - Canada.
 
Capital Expenditures (Continuing Operations)
    Three Months Ended   Twelve Months Ended
    December 31,   December 31,
    2009   2008   2009   2008
                 
Capital                
Canadian Division   $ 575   $ 504     $ 1,869   $ 2,459
Canada - Other     134     425       848     1,500
Canada     709     929       2,717     3,959
USA     515     854       1,821     2,682
Market Optimization     4     6       2     17
Corporate & Other     47     57       85     165
      1,275     1,846       4,625     6,823
                 
Acquisition Capital                
Canadian Division     108     31       190     151
Canada - Other     2     -       3     -
Canada     110     31       193     151
USA     25     (71 )     46     1,023
      135     (40 )     239     1,174
Total   $ 1,410   $ 1,806     $ 4,864   $ 7,997
 
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
    December 31,   December 31,   December 31,   December 31,
    2009   2008   2009   2008
                 
Canada   $ 11,162     $ 17,498     $ 12,748     $ 23,419  
USA     13,929       13,643       14,962       14,635  
Market Optimization     124       140       303       429  
Corporate & Other     958       629       5,814       4,098  
Assets of Discontinued Operations (Note 6)             -       4,666  
Total   $ 26,173     $ 31,910     $ 33,827     $ 47,247  
 
 
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 December 31, 2009, Canada Property, Plant, and Equipment and Total Assets includes EnCana's accrual to date of $427 million ($199 million at December 31, 2008) related to this offshore facility as an asset under construction.
 
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 December 31, 2009, Corporate and Other Property, Plant and Equipment and Total Assets includes EnCana's accrual to date of $649 million ($252 million at December 31, 2008) related to this office project 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. Discontinued Operations
 
As a result of the Split Transaction described in Note 4, on November 30, 2009, EnCana transferred its Downstream Refining operations to Cenovus. Downstream Refining focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. These refineries were jointly owned with ConocoPhillips.
 
Consolidated Statement of Earnings
 
The following table presents the effect of discontinued operations in the Consolidated Statement of Earnings:
 
    Three Months Ended   Twelve Months Ended
    December 31,   December 31,
    2009   2008   2009   2008
                 
Revenues, Net of Royalties   $ 955     $ 1,497     $ 4,804     $ 9,011  
                 
Expenses                
Operating     87       117       416       492  
Purchased product     849       1,960       4,070       8,760  
Depreciation, depletion and amortization     27       50       173       188  
Administrative     26       7       44       26  
Interest, net     27       45       163       184  
Accretion of asset retirement obligation     1       1       2       2  
Foreign exchange (gain) loss, net     -       -       1       -  
(Gain) loss on divestitures     -       1       -       1  
      1,017       2,181       4,869       9,653  
Net Earnings (Loss) Before Income Tax     (62 )     (684 )     (65 )     (642 )
Income tax expense (recovery)     (109 )     (292 )     (97 )     (87 )
Net Earnings (Loss) From Discontinued Operations   $ 47     $ (392 )   $ 32     $ (555 )
                 
Net Earnings (Loss) From Discontinued Operations                
per Common Share                
Basic   $ 0.07     $ (0.52 )   $ 0.04     $ (0.74 )
Diluted   $ 0.07     $ (0.53 )   $ 0.04     $ (0.73 )
 
Consolidated Balance Sheet
 
The following table presents the effect of the discontinued operations in the Consolidated Balance Sheet:
         
    As at   As at
    December 31,   December 31,
    2009   2008
         
Assets        
Current Assets        
Cash and cash equivalents   $ -   $ 29  
Accounts receivable and accrued revenues     -     132  
Inventories     -     336  
      -     497  
Property, Plant and Equipment, net     -     4,032  
Investments and Other Assets     -     137  
    $ -   $ 4,666  
         
Liabilities        
Current Liabilities        
Accounts payable and accrued liabilities   $ -   $ 423  
Income tax payable     -     (76 )
Current portion of partnership contribution payable     -     306  
      -     653  
Partnership Contribution Payable     -     2,857  
Asset Retirement Obligation     -     35  
Future Income Taxes     -     2  
      -     3,547  
Net Assets of Discontinued Operations   $ -   $ 1,119  
 
 
7. 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 Division.
 
Divestitures
Proceeds received on the sale of assets were $1,178 million (2008 - $904 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 $1,000 million (2008 - $400 million) in the Canadian Division, $73 million (2008 - $251 million) in the USA Division and $17 million (2008 - $47 million) in Canada - Other.
 
Corporate and Other
On November 3, 2009, the Company completed the sale of Senlac Oil Limited for cash consideration of $83 million.