EnCana generates third quarter cash flow of US$2.1 billion, or $2.77 per share down 26 percent

Thu Nov 12, 6:02 AM

CALGARY, Alberta--(BUSINESS WIRE)--EnCana Corporation (TSX & NYSE: ECA) continued to deliver strong operating and financial results in the third quarter of 2009, despite low natural gas prices. EnCana generated third quarter cash flow of US$2.1 billion, or $2.77 per share, and operating earnings of $775 million, or $1.03 per share – down 26 and 46 percent respectively compared to the third quarter of 2008. EnCana’s financial performance was significantly enhanced by commodity price hedges, which contributed $913 million in realized after-tax gains, or $1.22 per share, to cash flow in the third quarter.

Shut-in and curtailed gas coming back on this winter

To help preserve shareholder value on the expectation that natural gas prices would rise to more economic levels, EnCana curtailed or shut in about 500 million cubic feet per day (MMcf/d) of natural gas production in the third quarter. These shut-in and curtailed volumes are expected to be brought back on stream during the winter of 2009/10. Total third quarter production was about 4.4 billion cubic feet equivalent per day (Bcfe/d), down 7 percent compared to one year earlier. While natural gas production was down about 9 percent to 3.6 billion cubic feet per day (Bcf/d), oil and natural gas liquids (NGLs) production increased about 4 percent to 139,000 barrels per day (bbls/d), led by a 44 percent production increase from the Foster Creek enhanced oil project. Natural gas production in the first nine months of 2009 was 3.7 Bcf/d, which is higher than the company’s 2009 guidance of 3.6 Bcf/d. This reflects EnCana’s operational success even during a period when it chose to curtail production due to low prices.

“Our company’s solid operational and financial performance during a period of weak prices is evidence that EnCana’s strategy is working. We remain focused on being the lowest cost producer by applying advanced technologies and by pursuing operational efficiencies across all resource plays. In addition, our successful hedging program has helped us sustain strong cash flow. To help preserve the value of our resource base, we have curtailed significant natural gas production in many of our operating areas and have significant productive capacity available to bring to market as prices recover,” said Randy Eresman, EnCana’s President & Chief Executive Officer.

IMPORTANT NOTE: EnCana reports in U.S. dollars unless otherwise noted and follows U.S. protocols, which report gas and oil production, sales and reserves on an after-royalties basis. The company’s financial statements are prepared in accordance with Canadian generally accepted accounting principles (GAAP). Per share amounts for cash flow and earnings are on a diluted basis.

EnCana Third Quarter 2009 Highlights

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

Financial

  • Cash flow was $2.1 billion or $2.77 per share, a decrease of 26 percent
  • Operating earnings were $775 million or $1.03 per share, down 46 percent
  • Net earnings were $25 million or 3 cents per share
  • Capital investment, excluding acquisitions and divestitures, was $1.3 billion, down 16 percent, primarily due to lower drilling and completion expenditures as a result of fewer wells drilled and cost deflation
  • Free cash flow was $741 million, down 39 percent (Free cash flow is defined in Note 1 on page 9)
  • Realized natural gas prices were $7.31 per thousand cubic feet (Mcf), down 8 percent, and realized liquids prices were $57.39 per barrel (bbl), down 37 percent. These prices include financial hedges
  • At the end of the quarter, debt to capitalization was 25 percent and debt to adjusted EBITDA was 1.1 times. These ratios do not include the $3.5 billion of debt securities intended for use by Cenovus, the proceeds of which have been placed in escrow pending the completion of the split transaction
  • Paid a dividend of 40 cents per share
  • EnCana’s integrated oil business venture with ConocoPhillips generated $266 million in operating cash flow, including $180 million from the Foster Creek and Christina Lake upstream projects, and $86 million from the downstream business

Operating – Upstream

  • Total natural gas production was 3.6 Bcf/d, down 9 percent, primarily due to a decision to shut in or curtail about 500 MMcf/d of production because of the low price environment and natural declines in conventional properties. This reduced production was partially offset by lower royalty volumes in Alberta due to price sensitive royalty rates
  • Total oil and NGLs production was more than 139,000 bbls/d, an increase of 4 percent
  • Foster Creek and Christina Lake oil production grew 43 percent to approximately 45,000 bbls/d net to EnCana
  • Operating and administrative costs were $1.26 per thousand cubic feet equivalent (Mcfe), which is up from 79 cents per Mcfe in the third quarter of 2008, a period when there was a large recovery of long-term incentive costs as a result of a significant decline in the EnCana share price. These higher 2009 costs were offset primarily by a weaker Canadian dollar and lower purchased fuel and workover costs

Operating – Downstream

  • Refined products averaged 451,000 bbls/d (225,500 bbls/d net to EnCana), up 3 percent
  • Refinery crude utilization was 94 percent or 425,000 bbls/d crude throughput (212,500 bbls/d net to EnCana), up 3 percent
  • The Wood River coker and refinery expansion (CORE) project was approximately 62 percent complete at the end of September.
     
Financial Summary – Total Consolidated
(for the period ended September 30)

($ millions, except per share amounts)

    Q3

2009

  Q3

2008

  % ∆   9 months

2009

  9 months

2008

  % ∆
Cash flow1     2,079   2,809   -26   6,176   8,087   -24
Per share diluted     2.77   3.74   -26   8.22   10.75   -24

Operating earnings1

775 1,442 -46 2,640 3,956 -33
Per share diluted     1.03   1.92   -46   3.51   5.26   -33
Net earnings 25 3,553 1,226 4,867
Per share diluted     0.03   4.73       1.63   6.47    
Capital investment     1,338   1,588   -16   3,924   5,155   -24

 

Earnings Reconciliation Summary – Total Consolidated

Net earnings 25 3,553 1,226 4,867

Add back (losses) & deduct gains

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

(931) 2,043 (1,592) 1,071
 

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

181 (31) 178 (259)
 

Gain (loss) on discontinuance, after-tax

    -   99       -   99    

Operating earnings1

775 1,442 -46 2,640 3,956 -33

Per share diluted

    1.03   1.92   -46   3.51   5.26   -33

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

 

Price risk management affects net earnings

Operating earnings include the realized hedging gains and losses which reflect the actual value of the hedging contracts when settled. Management believes operating earnings are a better measure of performance because they remove the variability associated with unrealized mark-to-market accounting accruals. Net earnings include both realized hedging gains/losses and unrealized mark-to-market accounting gains/losses.

Net earnings in the third quarter of 2009 were affected by the combined impact of realized and unrealized hedging gains/losses which resulted in an $18 million after-tax decrease to net earnings in 2009 compared to a $1.8 billion after-tax increase to net earnings in the third quarter of 2008.

               
Production & Drilling Summary
Total Consolidated
(for the period ended September 30)

(After royalties)

    Q3

2009

  Q3

2008

 

% ∆

  9 months

2009

  9 months

2008

 

% ∆

Natural Gas (MMcf/d)     3,551   3,917   -9   3,735   3,830   -2
Oil and NGLs (Mbbls/d)     139   134   4   136   133   2
Total Production (MMcfe/d)     4,387   4,718   -7   4,554   4,627   -2
Total net wells drilled     292   730   -60   1,391   2,282   -39
             

Key resource play production

Third quarter oil and natural gas production from key resource plays decreased 7 percent to 3.4 Bcfe/d compared to 3.6 Bcfe/d in the third quarter of 2008. Key resource play oil production was up 20 percent from the third quarter of 2008 to about 81,000 bbls/d led by Foster Creek and Christina Lake. Natural gas key resource play production was down by 10 percent, to 2.9 Bcf/d, due to a decision to shut in some wells, restrict productive capacity and delay some well completions or tie-ins to sales pipelines because of lower natural gas prices. These company-wide initiatives resulted in production restrictions of about 500 MMcf/d in the quarter.

Horn River and Haynesville shale plays continue to deliver strong drilling results

Results from drilling and completion work at EnCana’s Horn River play in northeast British Columbia continue to build the company’s confidence in the long term potential of this emerging shale gas play, where 47 gross wells have been drilled to date (23.5 net to EnCana). Performance from the first 13 gross wells completed by EnCana and its partner are very positive. Initial 30-day production rates have been between 8 million and 10 million cubic feet of gas per day. At the Haynesville play in northern Louisiana and East Texas, EnCana drilled 12 net wells and production during the quarter averaged about 80 MMcf/d. Well costs have dropped about 40 percent with EnCana’s three best wells averaging below $8 million per well.

Integrated oil business production increases

EnCana’s integrated oil business with ConocoPhillips achieved a successful third quarter generating operating cash flow of $266 million. Production at Foster Creek and Christina Lake was up 43 percent. Despite the strong production growth, upstream operating cash flow was down 2 percent to $180 million due to a 37 percent decrease in crude oil prices. The Borger and Wood River refineries generated operating cash flow of $86 million compared to a loss of $96 million in the third quarter of 2008. Higher capacity utilization and lower purchased-product and operating costs contributed to the improvement.

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

At Foster Creek, oil production from the phase D and E expansions continues to ramp up and the operation is on target to exit 2009 producing between 90,000 and 100,000 bbls/d (45,000 to 50,000 bbls/d net to EnCana). At Christina Lake, construction of phase C continues and current production is about 15,000 bbls/d (7,500 bbls/d net to EnCana).

         

Production from key North American resource plays

       
Resource Play

 

(After royalties)

    Daily Production
    2009     2008     2007
    YTD   Q3   Q2   Q1     Full Year   Q4   Q3   Q2   Q1     Full Year
Natural Gas (MMcf/d)                      
Jonah 573 521 576 623 603 573 615 630 595 557
Piceance 358 334 355 386 385 377 407 383 372 348
East Texas 339 305 304 409 334 408 339 316 273 143
Fort Worth 141 135 138 149 142 143 148 137 140 124
Greater Sierra 206 189 216 215 220 228 228 219 205 211
Cutbank Ridge 328 322 340 323 296 311 322 280 271 258
Bighorn 165 154 186 156 167 165 185 170 146 126
CBM 319 318 330 309 304 308 309 303 298 259
Shallow Gas     661   649   661   673     700   683   691   712   715     726
Total natural gas (MMcf/d)     3,090   2,927   3,106   3,243     3,151   3,196   3,244   3,150   3,015     2,752
Oil (Mbbls/d)
Foster Creek 34 39 34 28 26 29 27 21 27 24
Christina Lake 6 6 6 7 4 6 5 4 2 3
Pelican Lake 20 21 19 21 22 20 22 21 24 23
Weyburn     15   15   15   16     14   15   14   13   14     15
Total oil (Mbbls/d)1     76   81   75   72     66   71   67   59   67     65
Total (MMcfe/d) 1     3,546   3,410   3,557   3,676     3,548   3,621   3,648   3,506   3,417     3,141
% change from prior period     +0.7   -4.1   -3.2   +1.5     +13.0   -0.7   +4.1   +2.6   +2.7     +12.9

1 Totals may not add due to rounding.

 
               

Drilling activity in key North American resource plays

       
Resource Play     Net Wells Drilled
    2009     2008     2007
    YTD   Q3   Q2   Q1     Full Year   Q4   Q3   Q2   Q1     Full Year
Natural Gas                      
Jonah 85 20 30 35 175 40 43 49 43 135
Piceance 113 25 35 53 328 70 94 81 83 286
East Texas 30 4 11 15 78 23 22 22 11 35
Fort Worth 23 1 6 16 83 21 21 20 21 75
Greater Sierra 42 17 10 15 106 14 29 27 36 109
Cutbank Ridge 56 18 18 20 82 17 17 24 24 93
Bighorn 52 17 14 21 64 5 11 18 30 62
CBM 316 37 1 278 698 359 78 10 251 1,079
Shallow Gas     436   55   45   336     1,195   383   233   83   496     1,914
Total gas wells     1,153   194   170   789     2,809   932   548   334   995     3,788
Oil
Foster Creek 18 2 10 6 20 1 6 1 12 23
Christina Lake - - - - - - - - - 3
Pelican Lake 5 - 1 4 - - - - - -
Weyburn     -   -   -   -     21   3   4   5   9     37
Total oil wells     23   2   11   10     41   4   10   6   21     63
Total    

1,176

 

196

 

181

  799     2,850   936  

558

 

340

  1,016     3,851
 
             

Natural gas and oil prices

      Q3

2009

  Q3

2008

 

% ∆

  9 months

2009

  9 months

2008

 

% ∆

Natural gas ($/MMBtu)              
NYMEX 3.39 10.24 -67 3.92 9.73 -60
EnCana Realized Gas Price1 ($/Mcf)     7.31   7.94   -8   7.18   8.17   -12
Oil and NGLs ($/bbl)
WTI 68.24 118.22 -42 57.32 113.52 -50
Western Canadian Select (WCS) 58.06 100.22 -42 48.47 93.16 -48
Differential WTI/WCS 10.18 18.00 -43 8.85 20.36 -57
EnCana Realized Liquids Price1     57.39   90.88   -37   47.64   83.49   -43
Chicago 3-2-1 Crack Spread ($/bbl)     8.48   17.29   -51   9.72   12.86   -24

1 Realized prices include the impact of financial hedging.

 

Price risk management

Risk management positions at September 30, 2009 are presented in Note 17 to the unaudited Interim Consolidated Financial Statements. In the third quarter of 2009, EnCana’s commodity price risk management measures resulted in realized gains of approximately $913 million after tax, including a $916 million after-tax gain on natural gas and basis hedges and a $3 million after-tax loss on other hedges.

As of September 30, EnCana had hedged about 2 Bcf/d, of expected natural gas production for the 2010 gas year, which runs from November 1, 2009 to October 31, 2010, at an average NYMEX equivalent price of $6.08 per Mcf. EnCana also had 27,000 bbls/d of expected 2010 oil production hedged at an average fixed price of WTI $76.89 per bbl. This price hedging strategy increases certainty in cash flow to help EnCana meet its anticipated capital requirements and projected dividends. EnCana continually assesses its hedging needs and the opportunities available prior to establishing its capital program for the upcoming year.

Corporate developments

Split transaction preparation proceeding

Planning is on track to split EnCana into two independent companies: a pure-play natural gas company, EnCana, and an integrated oil company, Cenovus Energy Inc. A shareholders’ meeting to vote on the proposed transaction is set for November 25, 2009. Subject to the required shareholder and court approvals being obtained and the satisfaction of conditions, the company expects to complete the transaction on November 30, 2009.

The Arrangement Circular for the shareholders’ meeting has been mailed and is available on SEDAR’s website, www.sedar.com, on EDGAR’s website, www.sec.gov/edgar.shtml and on EnCana’s website, www.encana.com.

Fourth Quarter Dividends

EnCana intends that the initial combined dividends of EnCana and Cenovus for the fourth quarter of 2009, after the Arrangement becomes effective, will be equal to EnCana's current quarterly dividend of US$0.40 per share, to be equally apportioned between EnCana and Cenovus. It is anticipated that such dividends will be payable on December 31, 2009 to common shareholders of record, for each respective company, as of December 21, 2009. Following completion of the Arrangement, the declaration of dividends will be at the sole discretion of the EnCana Board and the Cenovus Board and no dividend policy has been adopted by either company.

EnCana completes more than $900 million of net divestitures to date in 2009

In August of 2009, EnCana completed the sale to Bonavista Energy Trust of approximately 409,000 net acres of non-core natural gas and oil producing properties for approximately $632 million. The transaction included property known as the Hoadley trend, which covers an expansive area in west-central Alberta. In early November, EnCana completed the sale of its Senlac heavy oil operation in west-central Saskatchewan, for about $83 million. In the first nine months of 2009, EnCana had net divestitures of approximately $902 million, which is in line with targeted 2009 divestitures of between $500 million and $1 billion.

EnCana 2009 guidance and guidance for post-split companies posted on encana.com

EnCana’s 2009 guidance, which does not account for the proposed split, has been updated and the company has posted individual 2010 guidance for the post-split EnCana and Cenovus. Guidance documents are posted on the company’s website at www.encana.com.

Financial strength

EnCana has a strong balance sheet, with 95 percent of outstanding debt composed of long-term, fixed-rate debt with an average remaining term of more than 13 years. The company has an upcoming debt maturity in 2010 of $200 million. At September 30, 2009, EnCana had available $4.3 billion in unused committed bank credit facilities. EnCana manages its financial strategy to achieve a strong investment grade credit rating. EnCana targets a debt to capitalization ratio of less than 40 percent and a debt to adjusted EBITDA ratio of less than 2.0 times. At September 30, 2009, the company’s debt to capitalization ratio was 25 percent and debt to adjusted EBITDA, on a trailing 12-month basis, was 1.1 times. None of these EnCana debt measures include the debt securities arranged for Cenovus.

Cenovus Energy financing

On September 18, 2009, in preparation for the anticipated split transaction, Cenovus Energy Inc., currently a wholly owned subsidiary of EnCana, completed a private offering of debt securities for an aggregate principal amount of $3.5 billion in three tranches, which are exempt from registration requirements of the U.S. Securities Act of 1933 under Rule 144A and Regulation S. The net proceeds of the private offering were placed into an escrow account pending the completion of the split transaction. In addition, Cenovus has obtained commitments from a syndicate of banks to make available, pending the completion of the split transaction, a C$2 billion 3-year revolving credit facility and a C$500 million 364-day revolving credit facility, both for general corporate purposes. The use of these credit facilities by Cenovus is subject to customary conditions for credit facilities of this type.

2010 Preliminary Budgets

2010 post-split EnCana and Cenovus Energy budgets designed with flexibility

For 2010, EnCana and Cenovus have developed preliminary capital investment budgets aimed at maintaining financial strength and balance sheet flexibility through disciplined management of capital investment and operating expenses.

“The budgets for the two independent companies are designed to follow EnCana’s traditional investment principles. We employ a conservative and prudent approach and continually seek ways to reduce risk as we focus on our highest return opportunities in pursuit of enhancing the long-term value of every share,” Eresman said.

“While there are definite signs of a worldwide economic recovery, the commodity and financial markets continue to experience some degree of uncertainty. In order to make it easier for the individual executive teams to respond quickly to changing economic and investment circumstances, a high level of flexibility has been built into each company’s budget,” said Eresman.

It is expected that these preliminary budgets will be updated once the respective executive teams and boards of directors have had a better chance to refine individual strategies following the completion of the planned split transaction. The preliminary budgets are presented using EnCana’s current expectations and projections. The 2009 financial information for both Cenovus and post-split EnCana represents carved out data from EnCana projections including the operations, assets, liabilities and cash flows of the assets proposed for separation as well as a portion of the marketing and corporate functions of EnCana, which include some one-time transaction related costs for each company. The 2010 preliminary budget information in this news release also refers to the assets that are proposed for separation and the estimated revenues and costs associated with operating those assets.

Post-split EnCana – preliminary budget forecast summary

       
Post-split EnCana 2010 Preliminary Budget Forecast1
(US$ billions, excluding per share amounts)     2010 Forecast
Cash flow     4.0 – 4.6
Cash flow per share ($ per share diluted) 5.40 – 6.00
Capital investment 3.6 – 3.9
Total production (Bcfe/d) after royalties     3.2 – 3.3

1 2010 based on NYMEX gas of $5.50 to $6.15 per Mcf and WTI oil of $65.00 to $85.00 per bbl and the US$/C$ at $0.85 to $0.96. Cash flow and free cash flow are non-GAAP measures. See Note 1 on page 9.

 

EnCana – a leading unconventional natural gas company

“EnCana will continue to target being the best North American unconventional natural gas company. Our focus remains steadfast on being the lowest cost producer in all the fields where we operate as we employ a disciplined and methodical approach to unconventional natural gas development. We hold leading positions in key unconventional natural gas basins stretching from northeast British Columbia to east Texas and Louisiana,” Eresman said.

“In 2010, we plan to invest between $3.6 and $3.9 billion in capital and target natural gas production growth of about 10 percent. Major investments are aimed at the company’s large, early-stage opportunities in Haynesville and Horn River, as well as completion of the Deep Panuke project. Our budget is designed with the flexibility to adapt to changing economic conditions. Beyond what is currently planned, we have additional attractive investment opportunities that we may pursue if prices improve and market conditions warrant,” Eresman said.

Investment in the USA Division is expected to be about $1.9 billion, with natural gas production expected to grow about 16 percent to about 1.8 Bcf/d. Close to 40 percent of the USA budget is planned for continued production growth and land retention in the emerging Haynesville opportunity. Average 2010 production from the play is expected to be about 240 MMcf/d net to EnCana.

About $1.6 billion of investment is planned for the Canadian Division (currently the Canadian Foothills Division) and is focused on expanding the production infrastructure for longer-term growth in the Horn River basin, continued Deep Basin developments in the Cutbank Ridge (including the Montney formation) and Bighorn resource plays, the coalbed methane (CBM) resource play, plus completion of the Deep Panuke project. With sizable investments directed to longer-term projects such as Horn River and Deep Panuke, production in Canada is expected to remain steady in 2010. The lack of production growth, despite those investments, can be attributed in part to dispositions in 2009 of non-core assets in the Canadian Division and price sensitive royalty rates in Alberta.

Cenovus Energy – preliminary budget forecast summary

       
Cenovus Energy 2010 Preliminary Budget Forecast1
(US$ billions, excluding per share amounts)     2010 Forecast
Cash flow     2.3 – 2.6
Cash flow per share ($ per share diluted) 3.10 – 3.50
Capital investment

2.0 – 2.3

Foster Creek & Christina Lake oil production (bbls/d) after royalties     49,000 – 51,500

1 2010 based on WTI oil of $65.00 to $85.00 per bbl, a Chicago 3-2-1 crack spread of $7.50 to $9.50 per bbl, NYMEX gas of $5.50 to $6.15 per Mcf and the US$/C$ at $0.85 to $0.96. Cash flow and free cash flow are non-GAAP measures. See Note 1 on page 9.

 

“Cenovus Energy’s expansive, high-quality bitumen reservoirs and cost-efficient refineries offer significant opportunities for our integrated oil company to deliver long-term shareholder value for years ahead. Cenovus has 1.4 million acres of existing, high-quality leases, which the company estimates contain approximately 40 billion barrels of original bitumen in place. In 2010, we plan a year of substantial investment both upstream and downstream as we set the stage for significant future growth. About 40 percent of our capital in 2010 is directed to building productive capacity that will provide growth beyond 2010,” said Brian Ferguson, EnCana’s Chief Financial Officer and designated President & Chief Executive Officer of Cenovus.

Cenovus’s $2.0 to $2.3 billion of capital investment in 2010 is focused on increased development of the Foster Creek and Christina Lake enhanced oil operations, where 2010 production is expected to increase by 15 to 20 percent, and continued construction of the CORE project at Wood River.

Major capital investment in Cenovus’s upstream operations in 2010 will help set the stage for future phases of significant production growth. Cenovus plans to invest about $550 million in upstream production capacity expansions, largely at Christina Lake. Construction of Christina Lake’s phase C is on schedule and on budget and is expected to add about 40,000 bbls/d (20,000 bbls/d net to Cenovus) of capacity, with first production forecast in late 2011. The integrated oil business partners have sanctioned Christina Lake’s phase D and construction on this 40,000 bbls/d (20,000 bbls/d net to Cenovus) expansion is expected to begin in 2010, with first production expected in 2013. Regulatory applications for Christina Lake phases E, F and G have also been filed, with each expansion designed to add approximately 40,000 bbls/d (20,000 bbls/d net to Cenovus) of productive capacity. Ultimately, Christina Lake is expected to have productive capacity in excess of 200,000 bbls/d (100,000 bbls/d net to Cenovus).

At Foster Creek, regulatory applications have been filed for phases F, G and H, which would each add 30,000 bbls/d of capacity, taking total expected capacity to 210,000 bbls/d (105,000 bbls/d net to Cenovus). Foster Creek and Christina Lake combined are expected to have the potential to produce more than 400,000 bbls/d (200,000 bbls/d net to Cenovus) when fully developed.

Close to one-quarter of the 2010 Cenovus capital investment, about $500 million, will be directed to the final stages of construction of the CORE project at the Wood River refinery. The CORE project is more than 65 percent complete as of the end of October and is expected to come on stream in 2011. The project is expected to increase refining capacity by 50,000 bbls/d to 356,000 bbls/d (178,000 bbls/d net to Cenovus), and more than double heavy crude oil refining capacity to 240,000 bbls/d (120,000 bbls/d net to Cenovus). Each of these enhancements is expected to increase Wood River’s operating cash flow and improve refining margins.

Cenovus plans to invest about $700 million in Canadian Plains natural gas and oil production which is expected to generate strong operating cash flow, estimated in the range of $1.9 to $2.3 billion in 2010. These assets are a reliable source of free cash flow that will help fund future growth of enhanced oil production. Cenovus’s extensive, low-cost shallow gas production also provides a natural price hedge for the natural gas volumes consumed at the company’s enhanced oil projects and refineries.

Cenovus expected to use Canadian reporting protocols

For purposes of consistency, and in keeping with EnCana’s historical reporting, all information is stated in U.S. dollars unless otherwise noted and follows U.S. protocols, which report natural gas and oil production, sales and reserves on an after-royalty basis. EnCana will continue to report using these protocols. Following the completion of the split transaction, Cenovus expects to report its results in Canadian dollars and its volumes on a before-royalty basis. This change in reporting is expected to commence with the first quarter of 2010. Each company has chosen its reporting protocols to facilitate an easier comparison with its respective industry peers.

 

CONFERENCE CALL TODAY

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

EnCana will host a conference call today Thursday, November 12, 2009 starting at 11:00 a.m. MT (1:00 p.m. ET). To participate, please dial (888) 231-8191 (toll-free in North America) or (647) 427-7450 approximately 10 minutes prior to the conference call. An archived recording of the call will be available from approximately 1:00 p.m. MT on November 12 until midnight November 19, 2009 by dialing (800) 695-9469 or (402) 220-0618 and entering passcode 26580754.

 

A live audio webcast of the conference call will also be available via EnCana’s website, www.encana.com, under Investor Relations. The webcast will be archived for approximately 90 days.

 
 

NOTE 1: Non-GAAP measures

This news release contains references to non-GAAP measures as follows:

  • Cash flow is a non-GAAP measure defined as cash from operating activities excluding net change in other assets and liabilities and net change in non-cash working capital, both of which are defined on the Consolidated Statement of Cash Flows, in this news release and interim financial statements.
  • Free cash flow is a non-GAAP measure that EnCana defines as cash flow in excess of capital investment, excluding net acquisitions and divestitures, and is used to determine the funds available for other investing and/or financing activities.
  • Operating earnings is a non-GAAP measure that shows net earnings excluding non-operating items such as the after-tax impacts of a gain/loss on discontinuance, the after-tax gain/loss of unrealized mark-to-market accounting for derivative instruments, the after-tax gain/loss on translation of U.S. dollar denominated debt issued from Canada and the partnership contribution receivable, the after-tax foreign exchange gain/loss on settlement of intercompany transactions, future income tax on foreign exchange recognized for tax purposes only related to U.S. dollar intercompany debt and the effect of changes in statutory income tax rates. Management believes that these excluded items reduce the comparability of the company’s underlying financial performance between periods. The majority of the U.S. dollar debt issued from Canada has maturity dates in excess of five years.
  • Capitalization is a non-GAAP measure defined as debt plus shareholders’ equity. Debt to capitalization and debt to adjusted EBITDA are two ratios which management uses to steward the company’s overall debt position as measures of the company’s overall financial strength.
  • Adjusted EBITDA is a non-GAAP measure defined as net earnings before gains or losses on divestitures, income taxes, foreign exchange gains or losses, interest net, accretion of asset retirement obligation, and depreciation, depletion and amortization.

These measures have been described and presented in this news release in order to provide shareholders and potential investors with additional information regarding EnCana’s liquidity and its ability to generate funds to finance its operations.

EnCana Corporation

With an enterprise value of approximately $50 billion, EnCana is a leading North American unconventional natural gas and integrated oil company. By partnering with employees, community organizations and other businesses, EnCana contributes to the strength and sustainability of the communities where it operates. EnCana common shares trade on the Toronto and New York stock exchanges under the symbol ECA.

ADVISORY REGARDING RESERVES DATA AND OTHER OIL AND GAS INFORMATION – EnCana's disclosure of reserves data and other oil and gas information is made in reliance on an exemption granted to EnCana by Canadian securities regulatory authorities which permits it to provide such disclosure in accordance with U.S. disclosure requirements. The information provided by EnCana may differ from the corresponding information prepared in accordance with Canadian disclosure standards under National Instrument 51-101 (NI 51-101). EnCana’s reserves quantities represent net proved reserves calculated using the standards contained in Regulation S-X of the U.S. Securities and Exchange Commission. Further information about the differences between the U.S. requirements and the NI 51-101 requirements is set forth under the heading "Note Regarding Reserves Data and Other Oil and Gas Information" in EnCana's Annual Information Form.

In this news release, certain crude oil and NGLs volumes have been converted to cubic feet equivalent (cfe) on the basis of one barrel (bbl) to six thousand cubic feet (Mcf). Also, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the same basis. BOE and cfe may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the well head.

ADVISORY REGARDING FORWARD-LOOKING STATEMENTS – In the interests of providing EnCana shareholders and potential investors with information regarding EnCana, including management’s assessment of EnCana’s and its subsidiaries’ future plans and operations, certain statements contained in this news release are forward-looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as “forward-looking statements.” Forward-looking statements in this news release include, but are not limited to: future economic and operating performance (including per share growth, debt to capitalization ratio, debt to adjusted EBITDA ratio, sustainable growth and returns, free cash flow, cash flow, cash flow per share, operating earnings and increases in net asset value); projections contained in the company’s and Cenovus’s guidance forecasts and the anticipated ability to meet the company’s and Cenovus’s guidance forecasts; anticipated life of proved reserves; anticipated growth and success of resource plays and the expected characteristics of resource plays; anticipated production and drilling in the Horn River and Haynesville areas; anticipated 2010 budgets for EnCana and Cenovus (including cash flow, cash flow per share, free cash flow, capital investment, divestitures and total production); anticipated allocation of capital for EnCana and Cenovus in 2010, including among various projects; the potential success of such projects as Deep Panuke, Cutbank Ridge, Bighorn and CORE at Wood River; the ability of enhancements at Wood River to increase cash flow and improve refining margins; anticipated capacities at Foster Creek and Christina Lake; planned expansion of in-situ oil production; anticipated crude oil and natural gas prices, including basis differentials for various regions; anticipated expansion and production for various phases at Foster Creek and Christina Lake; anticipated divestitures; potential dividends; anticipated success of EnCana’s price risk management strategy; anticipated hedging gains; potential demand for natural gas; anticipated drilling; estimates of original bitumen in place; potential capital expenditures and investment; potential oil, natural gas and NGLs production in 2009 and beyond; anticipated plans to bring production back on in the event of the recovery of natural gas prices; anticipated costs and cost reductions; the company’s plans for splitting into two independent companies and the conditions which may be required therefor; and references to potential exploration. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur, which may cause the company’s actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These assumptions, risks and uncertainties include, among other things: risks associated with the ability to obtain any necessary approvals, waivers, consents, court orders and other requirements necessary or desirable to permit or facilitate the planned split transaction (including regulatory and shareholder approvals); the risk that any applicable conditions of the planned split transaction may not be satisfied; volatility of and assumptions regarding oil and gas prices; assumptions based upon the company’s current guidance, as well as assumptions based upon 2010 EnCana and Cenovus guidance; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the company’s marketing operations, including credit risks; imprecision of reserves estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved reserves; the ability of the company and ConocoPhillips to successfully manage and operate the integrated North American oil business and the ability of the parties to obtain necessary regulatory approvals; refining and marketing margins; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining crude oil; risks associated with technology; the company’s ability to replace and expand oil and gas reserves; its ability to generate sufficient cash flow from operations to meet its current and future obligations; its ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the company’s ability to secure adequate product transportation; changes in royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations or the interpretations of such laws or regulations; political and economic conditions in the countries in which the company operates; the risk of war, hostilities, civil insurrection and instability affecting countries in which the company operates and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the company; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. Although EnCana believes that the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list of important factors is not exhaustive.

Forward-looking information respecting anticipated 2009 cash flow for EnCana is based upon achieving average production of oil and gas for 2009 of approximately 4.4 to 4.8 Bcfe/d, year-to-date actuals and forward curve estimates for commodity prices and U.S./Canadian dollar foreign exchange rate as of September 30, 2009 and an average number of outstanding shares for EnCana of approximately 750 million. Forward-looking information respecting anticipated 2010 cash flow for EnCana is based upon achieving average production of oil and gas for 2010 of approximately 3.2 to 3.3 Bcfe/d, forward curve estimates for commodity prices and an estimated U.S./Canadian dollar foreign exchange rate of $0.85 to $0.96 and an average number of outstanding shares for EnCana of approximately 750 million. Forward-looking information respecting anticipated 2010 cash flow for Cenovus is based upon achieving average production of oil and NGLs for 2010 of approximately 105,000 to 111,500 bbls/d and average production of natural gas for 2010 of approximately 720 to 740 MMcf/d, forward curve estimates for commodity prices and an estimated U.S./Canadian dollar foreign exchange rate of $0.85 to $0.96 and an average number of outstanding shares for Cenovus of approximately 750 million. Assumptions relating to forward-looking statements generally include EnCana’s current expectations and projections made by the company in light of, and generally consistent with, its historical experience and its perception of historical trends, as well as expectations regarding rates of advancement and innovation, generally consistent with and informed by its past experience, all of which are subject to the risk factors identified elsewhere in this news release.

Furthermore, the forward-looking statements contained in this news release are made as of the date of this news release, and, except as required by law, EnCana does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this news release are expressly qualified by this cautionary statement.

Further information on EnCana Corporation is available on the company’s website, www.encana.com, or by contacting:

FOR FURTHER INFORMATION:

 
Investor contact: Media contact:
EnCana Corporate Communications
Paul Gagne Alan Boras
Vice-President, Investor Relations Manager, Media Relations
(403) 645-4737 (403) 645-4747
Ryder McRitchie
Manager, Investor Relations
(403) 645-2007
Susan Grey
Manager, Investor Relations
(403) 645-4751
 

EnCana Corporation

Interim Consolidated Financial Statements

(unaudited)

For the period ended September 30, 2009

(U.S. Dollars)

Consolidated Statement of Earnings (unaudited)                                                
                               
Three Months Ended Nine Months Ended
  September 30,         September 30,
($ millions, except per share amounts)                 2009           2008           2009           2008  
 
 
Revenues, Net of Royalties (Note 5) $ 3,881 $ 10,849 $ 12,251 $ 23,705
 
Expenses (Note 5)
Production and mineral taxes 29 138 122 406
Transportation and selling 355 443 969 1,282
Operating 510 521 1,575 1,926
Purchased product 1,747 3,445 4,341 8,720
Depreciation, depletion and amortization 992 1,095 2,955 3,227
Administrative 145 18 350 399
Interest, net (Note 7) 155 147 388 428
Accretion of asset retirement obligation (Note 12) 20 20 56 61
Foreign exchange (gain) loss, net (Note 8) (114 ) 110 (116 ) 170
  (Gain) loss on divestitures       (Note 6)         (1 )         (124 )         1           (141 )
                    3,838           5,813           10,641           16,478  
Net Earnings Before Income Tax 43 5,036 1,610 7,227
  Income tax expense       (Note 9)         18           1,483           384           2,360  
Net Earnings               $ 25         $ 3,553         $ 1,226         $ 4,867  
 
 
 
Net Earnings per Common Share (Note 16)
Basic $ 0.03 $ 4.74 $ 1.63 $ 6.49
  Diluted               $ 0.03         $ 4.73         $ 1.63         $ 6.47  
 
See accompanying Notes to Consolidated Financial Statements.
 
                 

Consolidated Statement of Retained Earnings (unaudited)

                                       
     
 
Nine Months Ended
  September 30,
($ millions)                               2009           2008  
 
Retained Earnings, Beginning of Year $ 17,584 $ 13,082
Net Earnings 1,226 4,867
Dividends on Common Shares (901 ) (899 )
Charges for Normal Course Issuer Bid                     (Note 13) -           (243 )
Retained Earnings, End of Period                             $ 17,909         $ 16,807  
 
 
 
Consolidated Statement of Comprehensive Income (unaudited)                              
 
Three Months Ended Nine Months Ended
  September 30,         September 30,
($ millions)           2009         2008           2009           2008  
 
Net Earnings $ 25 $ 3,553 $ 1,226 $ 4,867
Other Comprehensive Income, Net of Tax
Foreign Currency Translation Adjustment           985         (430 )         1,630           (782 )
Comprehensive Income         $ 1,010       $ 3,123         $ 2,856         $ 4,085  
 
 
 
Consolidated Statement of Accumulated Other Comprehensive Income (unaudited)                              
 
Nine Months Ended
  September 30,
($ millions)                               2009           2008  
 
Accumulated Other Comprehensive Income, Beginning of Year $ 833 $ 3,063
Foreign Currency Translation Adjustment                               1,630           (782 )
Accumulated Other Comprehensive Income, End of Period                           $ 2,463         $ 2,281  
 
See accompanying Notes to Consolidated Financial Statements.
 
Consolidated Balance Sheet (unaudited)                          
                   
As at As at
September 30, December 31,
($ millions)                 2009         2008
 
Assets
Current Assets
Cash and cash equivalents $ 1,376 $ 383
Accounts receivable and accrued revenues 1,596 1,568
Current portion of partnership contribution receivable 325 313
Risk management (Note 17) 586 2,818
    Inventories    

(Note 10)

727         520
4,610 5,602
Property, Plant and Equipment, net

(Note 5)

38,481 35,424
Restricted Cash (Note 4) 3,619 -
Investments and Other Assets 936 727
Partnership Contribution Receivable 2,589 2,834
Risk Management (Note 17) 31 234
  Goodwill                 2,703         2,426
            (Note 5)       $ 52,969       $ 47,247
 
Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable and accrued liabilities $ 2,947 $ 2,871
Income tax payable 880 424
Current portion of partnership contribution payable 320 306
Risk management (Note 17) 12 43
    Current portion of long-term debt     (Note 11) 200         250
4,359 3,894
Long-Term Debt (Note 11) 7,963 8,755
Cenovus Notes (Note 4) 3,468 -
Other Liabilities 1,083 576
Partnership Contribution Payable 2,615 2,857
Risk Management (Note 17) 90 7
Asset Retirement Obligation (Note 12) 1,412 1,265
  Future Income Taxes               7,020         6,919
                      28,010         24,273
Shareholders' Equity
Share capital (Note 13) 4,581 4,557
Paid in surplus (Note 13) 6 -
Retained earnings 17,909 17,584
    Accumulated other comprehensive income               2,463         833
  Total Shareholders' Equity               24,959         22,974
                    $ 52,969       $ 47,247
 
See accompanying Notes to Consolidated Financial Statements.
                       
Consolidated Statement of Cash Flows (unaudited)                                        
       
Three Months Ended Nine Months Ended
  September 30,         September 30,
($ millions)                 2009           2008           2009           2008  
 
Operating Activities
Net earnings $ 25 $ 3,553 $ 1,226 $ 4,867
Depreciation, depletion and amortization 992 1,095 2,955 3,227
Future income taxes (Note 9) (294 ) 1,418 (488 ) 1,491
Cash tax on sale of assets - 25 - 25
Unrealized (gain) loss on risk management (Note 17) 1,384 (3,050 ) 2,391 (1,639 )
Unrealized foreign exchange (gain) loss (100 ) 84 (149 ) 149
Accretion of asset retirement obligation (Note 12) 20 20 56 61
(Gain) loss on divestitures (Note 6) (1 ) (124 ) 1 (141 )
Other 53 (212 ) 184 47
Net change in other assets and liabilities 10 (19 ) 33 (283 )
  Net change in non-cash working capital                 608           268           274           (992 )
  Cash From Operating Activities                 2,697           3,058           6,483           6,812  
 
Investing Activities
Capital expenditures (Note 5) (1,353 ) (2,466 ) (4,028 ) (6,369 )
Proceeds from divestitures (Note 6) 977 442 1,030 593
Cash tax on sale of assets (Note 6) - (25 ) - (25 )
Corporate acquisition (Note 6) - - (24 ) -
Restricted cash (Note 4) (3,619 ) - (3,619 ) -
Net change in investments and other 80 (157 ) (90 ) (166 )
  Net change in non-cash working capital                 64           (120 )         (215 )         71  
  Cash (Used in) Investing Activities                 (3,851 )         (2,326 )         (6,946 )         (5,896 )
 
Financing Activities
Net issuance (repayment) of revolving long-term debt (726 ) (116 ) (1,391 ) 251
Issuance of long-term debt (Note 11) - - 496 723
Issuance of Cenovus Notes (Note 4) 3,468 - 3,468 -
Repayment of long-term debt (250 ) (468 ) (250 ) (664 )
Issuance of common shares (Note 13) 2 2 23 78
Purchase of common shares (Note 13) - - - (326 )
  Dividends on common shares                 (300 )         (299 )         (901 )         (899 )
  Cash From (Used in) Financing Activities                 2,194           (881 )         1,445           (837 )
 
Foreign Exchange Gain (Loss) on Cash and Cash
  Equivalents Held in Foreign Currency                 6           (7 )         11           (10 )
 
Increase (Decrease) in Cash and Cash Equivalents 1,046 (156 ) 993 69
Cash and Cash Equivalents, Beginning of Period                 330           778           383           553  
Cash and Cash Equivalents, End of Period               $ 1,376         $ 622         $ 1,376         $ 622  
 
See accompanying Notes to Consolidated Financial Statements.
 

Notes to Consolidated Financial Statements (unaudited)

(All amounts in $ millions unless otherwise specified)

1. Basis of Presentation

The interim Consolidated Financial Statements include the accounts of EnCana Corporation and its subsidiaries ("EnCana" or the "Company"), and are presented in accordance with Canadian generally accepted accounting principles ("GAAP"). EnCana's operations are in the business of the exploration for, the development of, and the production and marketing of natural gas, crude oil and natural gas liquids ("NGLs"), refining operations and power generation operations.

The interim Consolidated Financial Statements have been prepared following the same accounting policies and methods of computation as the annual audited Consolidated Financial Statements for the year ended December 31, 2008, except as noted below. The disclosures provided below are incremental to those included with the annual audited Consolidated Financial Statements. Certain information and disclosures normally required to be included in the notes to the annual audited Consolidated Financial Statements have been condensed or have been disclosed on an annual basis only. Accordingly, the interim Consolidated Financial Statements should be read in conjunction with the annual audited Consolidated Financial Statements and the notes thereto for the year ended December 31, 2008.

2. Changes in Accounting Policies and Practices

On January 1, 2009, the Company adopted the following Canadian Institute of Chartered Accountants ("CICA") Handbook section:

  • "Goodwill and Intangible Assets", Section 3064. The new standard replaces the previous goodwill and intangible asset standard and revises the requirement for recognition, measurement, presentation and disclosure of intangible assets. The adoption of this standard has had no material impact on EnCana's Consolidated Financial Statements.

3. Recent Accounting Pronouncements

In February 2008, the CICA's Accounting Standards Board confirmed that International Financial Reporting Standards ("IFRS") will replace Canadian GAAP in 2011 for profit-oriented Canadian publicly accountable enterprises. EnCana will be required to report its results in accordance with IFRS beginning in 2011. The Company has developed a changeover plan to complete the transition to IFRS by January 1, 2011, including the preparation of required comparative information. EnCana's IFRS changeover plan also addresses the requirements of the entities that result from the proposed corporate reorganization (See Note 4). The impact of IFRS on the Company's Consolidated Financial Statements is not reasonably determinable at this time.

As of January 1, 2011, EnCana will be required to adopt the following CICA Handbook sections:

  • "Business Combinations", Section 1582, which replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of earnings. The adoption of this standard will impact the accounting treatment of future business combinations.
  • "Consolidated Financial Statements", Section 1601, which together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard should not have a material impact on EnCana's Consolidated Financial Statements.
  • "Non-controlling Interests", Section 1602, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard should not have a material impact on EnCana's Consolidated Financial Statements.

4. Proposed Corporate Reorganization

In May 2008, EnCana's Board of Directors unanimously approved a proposal to split EnCana into two independent energy companies – one a natural gas company and the other an integrated oil company. The proposed corporate reorganization (the “Arrangement”) was expected to close in early January 2009.

In October 2008, EnCana announced the proposed Arrangement would be delayed until the global debt and equity markets regained stability.

On September 10, 2009, EnCana's Board of Directors unanimously approved plans to proceed with the proposed Arrangement. The proposed Arrangement is expected to be implemented through a court approved Plan of Arrangement and is subject to shareholder and regulatory approvals. The reorganization would result in two publicly traded entities with the names of Cenovus Energy Inc. and EnCana Corporation. Under the Arrangement, EnCana Shareholders will receive one New EnCana Common Share and one Cenovus Energy Inc. Common Share in exchange for each EnCana Common Share held.

Subject to court and shareholder approval, EnCana expects to complete the reorganization on November 30, 2009 following a Shareholders' meeting to vote on the proposed Plan of Arrangement to be held on November 25, 2009.

In conjunction with the proposed Arrangement, on September 18, 2009, EnCana's wholly owned subsidiary, Cenovus Energy Inc., completed a private offering of senior unsecured notes for an aggregate principal amount of $3,500 million issued in three tranches, which are exempt from the registration requirements of the U.S. Securities Act of 1933 under Rule 144A and Regulation S.

                As at
September 30,
                    2009
U.S. Unsecured Notes
4.5% due September 15, 2014 $ 800
5.7% due October 15, 2019 1,300
  6.75% due November 15, 2039                 1,400  
3,500
Debt Discounts and Financing Costs              

 

(32 )
Cenovus Notes 3,468
Amounts on Deposit in Escrow                 151  
Restricted Cash               $ 3,619  

The notes are legal obligations of Cenovus Energy Inc. and have been disclosed on EnCana's Consolidated Balance Sheet as a separate long-term liability, net of financing costs. The net proceeds of the private offering were placed into an escrow account held by the escrow agent, The Bank of New York Mellon, pending the completion of the Arrangement, pursuant to the terms and conditions of an escrow and security agreement for the benefit of the note holders. The underwriters have deposited $3,468 million into the escrow account and Cenovus Energy Inc. has contributed $151 million into the escrow account so that, in aggregate, the total escrowed funds of $3,619 million will be sufficient to pay the special mandatory redemption price for the notes if the Arrangement does not proceed.

Pursuant to the terms and conditions of the escrow and security agreement, neither EnCana nor Cenovus Energy Inc., or any of their subsidiaries have any rights to, access to, control of, or dominion over, the escrowed funds before the completion of the Arrangement. All amounts in the escrow account will be released to Cenovus Energy Inc. by the escrow agent promptly after the escrow agent has been notified that the Arrangement has become effective and all of the escrow conditions have been satisfied. If the Arrangement does not proceed, the notes will be subject to a special mandatory redemption at a redemption price, payable from the amounts held in escrow, equal to 101 percent of the aggregate principal amount of the notes plus a penalty payment computed with reference to the expected accrued interest.

Additional information about the calculation of the special mandatory redemption price and other effects of the proposed Arrangement can be found in EnCana's Information Circular dated October 20, 2009. The cash in escrow has been disclosed as Restricted Cash on EnCana's Consolidated Balance Sheet and is not available for current use.

Subject to the completion of the Arrangement, Cenovus Energy Inc. has obtained commitments from a syndicate of banks to make available a C$2.0 billion three-year revolving credit facility and a C$500 million 364-day revolving credit facility.

5. Segmented Information

The Company's operating and reportable segments are as follows:

  • Canada includes the Company’s exploration for, and development and production of natural gas, crude oil and NGLs and other related activities within the Canadian cost centre.
  • USA includes the Company’s exploration for, and development and production of natural gas, NGLs and other related activities within the United States cost centre.
  • Downstream Refining is focused on the refining of crude oil into petroleum and chemical products at two refineries located in the United States. The refineries are jointly owned with ConocoPhillips.
  • Market Optimization is primarily responsible for the sale of the Company's proprietary production. These results are included in the Canada and USA segments. Market optimization activities include third-party purchases and sales of product that provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment.
  • Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once amounts are settled, the realized gains and losses are recorded in the operating segment to which the derivative instrument relates.

Market Optimization sells substantially all of the Company's upstream production to third-party customers. Transactions between segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.

On December 31, 2008, EnCana updated its segmented reporting to present the upstream Canadian and United States cost centres and Downstream Refining as separate reportable segments. This resulted in EnCana presenting the Canadian portion of the Integrated Oil Division as part of the Canada segment. Previously, this was aggregated and presented in the Integrated Oil segment. Prior periods have been restated to reflect this presentation.

EnCana has a decentralized decision making and reporting structure. Accordingly, the Company is organized into Divisions as follows:

  • Canadian Plains Division includes natural gas and crude oil exploration, development and production assets located in eastern Alberta and Saskatchewan.
  • Canadian Foothills Division includes natural gas exploration, development and production assets located in western Alberta and British Columbia as well as the Company’s Canadian offshore assets.
  • USA Division includes natural gas exploration, development and production assets located in the United States and comprises the USA segment described above.
  • Integrated Oil Division is the combined total of Integrated Oil – Canada and Downstream Refining. Integrated Oil – Canada includes the Company’s exploration for, and development and production of bitumen using enhanced recovery methods. Integrated Oil – Canada is composed of EnCana’s interests in the FCCL Partnership jointly owned with ConocoPhillips, the Athabasca natural gas assets and other bitumen interests.

Results of Operations (For the three months ended September 30)

Segment and Geographic Information

      Canada         USA         Downstream Refining
      2009           2008           2009           2008           2009           2008  
                               
Revenues, Net of Royalties $ 2,101 $ 2,776 $ 1,161 $ 1,477 $ 1,610 $ 2,699
Expenses
Production and mineral taxes 12 41 17 97 - -
Transportation and selling 216 311 139 132 - -
Operating 289 273 100 127 99 116
  Purchased product   (41 )         (45 )         -           -           1,425           2,679  
1,625 2,196 905 1,121 86 (96 )
  Depreciation, depletion and amortization 537           578           373           435           49           50  
Segment Income (Loss) $ 1,088         $ 1,618         $ 532         $ 686         $ 37         $ (146 )
 
      Market Optimization         Corporate & Other Consolidated
      2009           2008           2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 381 $ 840 $ (1,372 ) $ 3,057 $ 3,881 $ 10,849
Expenses
Production and mineral taxes - - - - 29 138
Transportation and selling - - - - 355 443
Operating 11 8 11 (3 ) 510 521
  Purchased product   363           811           -           -           1,747           3,445  
7 21 (1,383 ) 3,060 1,240 6,302
  Depreciation, depletion and amortization 6           4           27           28           992           1,095  
Segment Income (Loss) $ 1         $ 17         $ (1,410 )       $ 3,032           248           5,207  
Administrative 145 18
Interest, net 155 147
Accretion of asset retirement obligation 20 20
Foreign exchange (gain) loss, net (114 ) 110
  (Gain) loss on divestitures                                           (1 )         (124 )
                                              205           171  
Net Earnings Before Income Tax 43 5,036
  Income tax expense                                           18           1,483  
Net Earnings                                         $ 25         $ 3,553  

Results of Operations (For the three months ended September 30)

Product and Divisional Information

    Canada Segment
      Canadian Plains         Canadian Foothills       Integrated Oil - Canada Total
      2009         2008         2009         2008           2009           2008           2009           2008  
                                         
Revenues, Net of Royalties $ 875 $ 1,213 $ 849 $ 1,168 $ 377 $ 395 $ 2,101 $ 2,776
Expenses
Production and mineral taxes 9 27 2 14 1 - 12 41
Transportation and selling 48 106 40 57 128 148 216 311
Operating 111 96 126 120 52 57 289 273
  Purchased product   -         -         -         -           (41 )         (45 )         (41 )         (45 )
Operating Cash Flow $ 707       $ 984       $ 681       $ 977         $ 237         $ 235         $ 1,625         $ 2,196  
 
    Canadian Plains Division
      Gas         Oil & NGLs         Other         Total
      2009         2008         2009         2008           2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 487 $ 576 $ 385 $ 633 $ 3 $ 4 $ 875 $ 1,213
Expenses
Production and mineral taxes 3 14 6 13 - - 9 27
Transportation and selling 10 18 38 88 - - 48 106
  Operating   56         44         55         51           -           1           111           96  
Operating Cash Flow $ 418       $ 500       $ 286       $ 481         $ 3         $ 3         $ 707         $ 984  
 
    Canadian Foothills Division
      Gas         Oil & NGLs         Other         Total
      2009         2008         2009         2008           2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 761 $ 982 $ 77 $ 172 $ 11 $ 14 $ 849 $ 1,168
Expenses
Production and mineral taxes 2 12 - 2 - - 2 14
Transportation and selling 38 54 2 3 - - 40 57
  Operating   118         108         5         7           3           5           126           120  
Operating Cash Flow $ 603       $ 808       $ 70       $ 160         $ 8         $ 9         $ 681         $ 977  
 
    USA Division
      Gas         Oil & NGLs         Other         Total
      2009         2008         2009         2008           2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 1,084 $ 1,263 $ 53 $ 124 $ 24 $ 90 $ 1,161 $ 1,477
Expenses
Production and mineral taxes 12 86 5 11 - - 17 97
Transportation and selling 139 132 - - - - 139 132
  Operating   78         59         -         -           22           68           100           127  
Operating Cash Flow $ 855       $ 986       $ 48       $ 113         $ 2         $ 22         $ 905         $ 1,121  
 
    Integrated Oil Division
      Oil *         Downstream Refining Other *         Total          
      2009         2008         2009         2008           2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 345 $ 362 $ 1,610 $ 2,699 $ 32 $ 33 $ 1,987 $ 3,094
Expenses
Production and mineral taxes - - - - 1 - 1 -
Transportation and selling 120 137 - - 8 11 128 148
Operating 45 42 99 116 7 15 151 173
  Purchased product   -         -         1,425         2,679           (41 )         (45 )         1,384           2,634  
Operating Cash Flow $ 180       $ 183       $ 86       $ (96 )       $ 57         $ 52         $ 323         $ 139  
 
* Oil and Other are included in Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties.

Results of Operations (For the nine months ended September 30)

Segment and Geographic Information

      Canada         USA         Downstream Refining
      2009           2008           2009           2008           2009           2008  
                               
Revenues, Net of Royalties $ 6,054 $ 8,089 $ 3,461 $ 4,356 $ 3,849 $ 7,514
Expenses
Production and mineral taxes 44 95 78 311 - -
Transportation and selling 582 915 387 367 - -
Operating 866 1,053 314 482 329 375
  Purchased product   (72 )         (126 )         -           -           3,221           6,800  
4,634 6,152 2,682 3,196 299 339
  Depreciation, depletion and amortization 1,544           1,717           1,168           1,253           146           138  
Segment Income (Loss) $ 3,090         $ 4,435         $ 1,514         $ 1,943         $ 153         $ 201  
 
      Market Optimization         Corporate & Other Consolidated
      2009           2008           2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 1,239 $ 2,112 $ (2,352 ) $ 1,634 $ 12,251 $ 23,705
Expenses
Production and mineral taxes - - - - 122 406
Transportation and selling - - - - 969 1,282
Operating 26 27 40 (11 ) 1,575 1,926
  Purchased product   1,192           2,046           -           -           4,341           8,720  
21 39 (2,392 ) 1,645 5,244 11,371
  Depreciation, depletion and amortization 15           12           82           107           2,955           3,227  
Segment Income (Loss) $ 6         $ 27         $ (2,474 )       $ 1,538           2,289           8,144  
Administrative 350 399
Interest, net 388 428
Accretion of asset retirement obligation 56 61
Foreign exchange (gain) loss, net (116 ) 170
  (Gain) loss on divestitures                                           1           (141 )
                                              679           917  
Net Earnings Before Income Tax 1,610 7,227
  Income tax expense                                           384           2,360  
Net Earnings                                         $ 1,226         $ 4,867  

Results of Operations (For the nine months ended September 30)

Product and Divisional Information

    Canada Segment
      Canadian Plains         Canadian Foothills       Integrated Oil - Canada Total
      2009         2008         2009         2008         2009           2008           2009           2008  
                                         
Revenues, Net of Royalties $ 2,470 $ 3,629 $ 2,671 $ 3,432 $ 913 $ 1,028 $ 6,054 $ 8,089
Expenses
Production and mineral taxes 30 64 13 30 1 1 44 95
Transportation and selling 163 330 115 167 304 418 582 915
Operating 322 385 389 478 155 190 866 1,053
  Purchased product   -         -         -         -         (72 )         (126 )         (72 )         (126 )
Operating Cash Flow $ 1,955       $ 2,850       $ 2,154       $ 2,757       $ 525         $ 545         $ 4,634         $ 6,152  
 
    Canadian Plains Division
      Gas         Oil & NGLs         Other         Total
      2009         2008         2009         2008         2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 1,483 $ 1,795 $ 978 $ 1,826 $ 9 $ 8 $ 2,470 $ 3,629
Expenses
Production and mineral taxes 11 32 19 32 - - 30 64
Transportation and selling 31 55 132 275 - - 163 330
  Operating   158         191         161         191         3           3           322           385  
Operating Cash Flow $ 1,283       $ 1,517       $ 666       $ 1,328       $ 6         $ 5         $ 1,955         $ 2,850  
 
    Canadian Foothills Division
      Gas         Oil & NGLs         Other         Total
      2009         2008         2009         2008         2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 2,432 $ 2,891 $ 208 $ 494 $ 31 $ 47 $ 2,671 $ 3,432
Expenses
Production and mineral taxes 11 26 2 4 - - 13 30
Transportation and selling 109 158 6 9 - - 115 167
  Operating   362         432         17         30         10           16           389           478  
Operating Cash Flow $ 1,950       $ 2,275       $ 183       $ 451       $ 21         $ 31         $ 2,154         $ 2,757  
 
    USA Division
      Gas         Oil & NGLs         Other         Total
      2009         2008         2009         2008         2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 3,246 $ 3,754 $ 132 $ 353 $ 83 $ 249 $ 3,461 $ 4,356
Expenses
Production and mineral taxes 66 280 12 31 - - 78 311
Transportation and selling 387 367 - - - - 387 367
  Operating   237         266         -         -         77           216           314           482  
Operating Cash Flow $ 2,556       $ 2,841       $ 120       $ 322       $ 6         $ 33         $ 2,682         $ 3,196  
 
    Integrated Oil Division
      Oil *         Downstream Refining Other *         Total          
      2009         2008         2009         2008         2009           2008           2009           2008  
 
Revenues, Net of Royalties $ 785 $ 898 $ 3,849 $ 7,514 $ 128 $ 130 $ 4,762 $ 8,542
Expenses
Production and mineral taxes - - - - 1 1 1 1
Transportation and selling 286 380 - - 18 38 304 418
Operating 123 133 329 375 32 57 484 565
  Purchased product   -         -         3,221         6,800         (72 )         (126 )         3,149           6,674  
Operating Cash Flow $ 376       $ 385       $ 299       $ 339       $ 149         $ 160         $ 824         $ 884  
 
* Oil and Other are included in Integrated Oil - Canada. Other includes production of natural gas and bitumen from the Athabasca and Senlac properties.

The following tables represent EnCana's and Cenovus Energy Inc.'s divisional information, post-Arrangement (See Note 4), excluding their respective share of the Market Optimization and Corporate and Other segments.

EnCana's divisions, post-Arrangement, will include Canadian Foothills and USA. Cenovus Energy Inc.'s divisions, post-Arrangement, will include Integrated Oil and Canadian Plains.

Results of Operations (For the three months ended September 30)

Divisional Information

    EnCana
        Canadian Foothills       USA         Total
        2009         2008         2009         2008         2009         2008
                               
Revenues, Net of Royalties $ 849 $ 1,168 $ 1,161 $ 1,477 $ 2,010 $ 2,645
Expenses
Production and mineral taxes 2 14 17 97 19 111
Transportation and selling 40 57 139 132 179 189
  Operating     126         120         100         127         226         247
Operating Cash Flow   $ 681       $ 977       $ 905       $ 1,121       $ 1,586       $ 2,098
 
    Cenovus
        Integrated Oil         Canadian Plains         Total
        2009         2008         2009         2008         2009         2008
 
Revenues, Net of Royalties $ 1,987 $ 3,094 $ 875 $ 1,213 $ 2,862 $ 4,307
Expenses
Production and mineral taxes 1 - 9 27 10 27
Transportation and selling 128 148 48 106 176 254
Operating 151 173 111 96 262 269
  Purchased product     1,384         2,634         -         -         1,384         2,634
Operating Cash Flow   $ 323       $ 139       $ 707       $ 984       $ 1,030       $ 1,123
 
Results of Operations (For the nine months ended September 30)
 
Divisional Information
    EnCana
        Canadian Foothills       USA         Total
        2009         2008         2009         2008         2009         2008
 
Revenues, Net of Royalties $ 2,671 $ 3,432 $ 3,461 $ 4,356 $ 6,132 $ 7,788
Expenses
Production and mineral taxes 13 30 78 311 91 341
Transportation and selling 115 167 387 367 502 534
  Operating     389         478         314         482         703         960
Operating Cash Flow   $ 2,154       $ 2,757       $ 2,682       $ 3,196       $ 4,836       $ 5,953
 
    Cenovus
        Integrated Oil         Canadian Plains         Total
        2009         2008         2009         2008         2009         2008
 
Revenues, Net of Royalties $ 4,762 $ 8,542 $ 2,470 $ 3,629 $ 7,232 $ 12,171
Expenses
Production and mineral taxes 1 1 30 64 31 65
Transportation and selling 304 418 163 330 467 748
Operating 484 565 322 385 806 950
  Purchased product     3,149         6,674         -         -         3,149         6,674
Operating Cash Flow   $ 824       $ 884       $ 1,955       $ 2,850       $ 2,779       $ 3,734
 
                       
Capital Expenditures
  Three Months Ended Nine Months Ended
September 30,       September 30,
              2009         2008         2009           2008
 
Capital
Canadian Plains $ 104 $ 173 $ 332 $ 593
Canadian Foothills 505 473 1,250 1,836
  Integrated Oil - Canada         111