U.S. SECURITIES AND EXCHANGE COMMISSION
FORM 40-F
(Check One)
o Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934
or
þ Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2004
Commission file number 1-15226
ENCANA CORPORATION
Canada (Province or other jurisdiction of incorporation or organization) |
1311 (Primary Standard Industrial Classification Code Number(if applicable)) |
Not applicable (I.R.S. Employer Identification Number (if Applicable)) |
1800-855 2nd Street, S.W., P.O. Box 2850, Calgary, Alberta, Canada T2P 2S5
(403) 645-2000
(Address and Telephone Number of Registrants Principal Executive Offices)
CT Corporation System,
111 8th Avenue, New York, NY 10011
(212) 894-8940
(Name, Address (Including Zip Code) and Telephone Number
(Including Area Code) of Agent For Service in the United States)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
Title of each class | Name of each exchange on which registered | |
Common Shares | New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act. None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act. Debt Securities
For annual reports, indicate by check mark the information filed with this Form:
þ Annual Information Form | þ Audited Annual Financial Statements |
Indicate the number of outstanding shares of each of the issuers classes of capital or common stock as of the close of the period covered by the annual report: 449,997,384
Indicate by check mark whether the registrant by filing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the Exchange Act). If Yes is marked, indicate the file number assigned to the registrant in connection with such rule.
Yes o No þ
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o
The Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, each of the registrants Registration Statements under the Securities Act of 1933: Form S-8 (File Nos. 333-13956 and 333-85598) and Form F-9 (File Nos. 333-113732 and 333-118737).
FORM 40-F
Principal Documents
The following documents have been filed as part of this Annual Report on Form 40-F, beginning on the following page:
(a) | Annual Information Form for the fiscal year ended December 31, 2004; | |||
(b) | Managements Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2004; and | |||
(c) | Consolidated Financial Statements for the fiscal year ended December 31, 2004 (Note 20 to the Consolidated Financial Statements relates to United States Accounting Principles and Reporting (U.S. GAAP)). |
40-F1
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i
1
2
3
Jurisdiction of | ||||||
Incorporation, | ||||||
Percentage | Continuance | |||||
Subsidiaries & Partnerships | Owned(1) | or Formation | ||||
EnCana West Ltd.
|
100 | Alberta | ||||
EnCana Oil & Gas Partnership
|
100 | Alberta | ||||
EnCana USA Holdings
|
100 | Delaware | ||||
3080763 Nova Scotia Company
|
100 | Nova Scotia | ||||
Alenco Inc.
|
100 | Delaware | ||||
EnCana Oil & Gas (USA) Inc.
|
100 | Delaware | ||||
EnCana Marketing (USA) Inc.
|
100 | Delaware | ||||
McMurry Oil
Company(2)
|
100 | Wyoming | ||||
Plaza Acquisition I
Corp.(2)
|
100 | Delaware | ||||
Tom Brown,
Inc.(2)
|
100 | Delaware | ||||
EnCana Midstream & Marketing (Holdings) Inc.
|
100 | Canada | ||||
EnCana Midstream & Marketing
|
100 | Alberta | ||||
(1) | Includes indirect ownership. |
(2) | Merged with EnCana Oil & Gas (USA) Inc. on January 1, 2005. EnCana Oil & Gas (USA) Inc. is the continuing entity. |
4
| In the first quarter of 2004, a subsidiary of EnCana completed the purchase, through two separate transactions, of additional interests in the U.K. central North Sea, for net cash consideration of approximately $131 million. |
| In May 2004, a subsidiary of EnCana completed the acquisition of Tom Brown, Inc. (Tom Brown) for total consideration of approximately $2.7 billion, including debt of approximately $406 million. Tom Brown was a resource play focused, natural gas exploration and production company headquartered in Denver, Colorado. The Tom Brown assets are located in the Piceance, Green River, Wind River, Paradox, East Texas, Permian and Western Canada Sedimentary basins. |
| In December 2004, a subsidiary of EnCana purchased natural gas assets in north Texas for approximately $251 million, subject to post-closing adjustments. |
| In February 2004, EnCana sold its 53.3 percent interest in Petrovera Resources (Petrovera), an Alberta partnership that produces heavy oil in western Canada, for net cash consideration of approximately $287 million. |
| In July 2004, a subsidiary of EnCana sold assets in New Mexico for approximately $228 million. |
| In August 2004, EnCana sold conventional natural gas properties in northeast Alberta for approximately $225 million, subject to post-closing adjustments. |
| In September 2004, the Corporation sold conventional oil and gas assets for approximately $388 million, subject to post-closing adjustments. This transaction included properties in east central and southern Alberta producing predominantly medium and heavy oil. |
| In December 2004, a subsidiary of EnCana closed the sale of all of its U.K. central North Sea assets for approximately $2.1 billion. These interests included a 43.2 percent interest in the Buzzard oil field, a 41.0 and 54.3 percent interest, respectively, in the Scott and Telford oil fields, other satellite discoveries, plus interests in exploration licences covering more than 740,000 net acres in the North Sea. As a result of this disposition, the U.K. Region is now treated as a discontinued operation for financial reporting purposes. |
5
| In January 2003, EnCana acquired reserves and production in Ecuador from Vintage Petroleum, Inc. for net cash consideration of approximately $116 million. |
| In September 2003, EnCana completed the acquisition of approximately 500,000 net acres of prospective natural gas development lands in Cutbank Ridge, which is located in the foothills of British Columbia and Alberta. EnCana purchased a majority interest in 39 parcels of land totalling roughly 350,000 net acres for approximately $270 million. The Corporation had previously acquired about 150,000 net acres through purchases and land swaps with other companies and Crown land sales. |
| In October 2003, EnCana Oil & Gas (USA) Inc. acquired natural gas and associated NGLs production, reserves and acreage from Mesa Hydrocarbons LLC for net cash consideration of approximately $100 million. The principal producing properties acquired are in the Piceance Basin of northwest Colorado. |
| In October 2003, a subsidiary of EnCana exchanged its non-operated interest in the Llano discovery in the Gulf of Mexico for an additional 14 percent interest in each of the Scott and Telford fields in the U.K. central North Sea, which were received by another subsidiary of EnCana. |
| In February 2003, EnCana sold a 10 percent interest in the Syncrude Joint Venture (Syncrude) for net cash consideration of approximately $690 million. In July 2003, EnCana sold its remaining 3.75 percent interest in Syncrude and an overriding royalty for net cash consideration of approximately $309 million. Both of these transactions are subject to post-closing adjustments. Syncrude operates a facility in northeast Alberta which produces crude oil from oilsands. |
| In May 2002, wholly owned subsidiaries of EnCana Oil & Gas (USA) Inc. acquired natural gas and associated NGLs production, reserves and acreage located in the Piceance Basin of northwest Colorado from subsidiaries of El Paso Corporation for approximately $275 million. |
| In July 2002, EnCana Oil & Gas (USA) Inc. acquired natural gas and associated NGLs production, reserves and acreage located in the Jonah natural gas field in southwest Wyoming from a subsidiary of The Williams Companies for approximately $350 million. |
6
| In March 2004, a 10 billion cubic feet expansion was completed at the Wild Goose natural gas storage facility in northern California. The expansion increased the total working gas capacity to approximately 24 billion cubic feet. |
| In June 2004, following successful completion of its open season, Entrega Gas Pipeline Inc. (Entrega), an affiliate of EnCana Oil & Gas (USA) Inc., announced that it is proceeding with its proposed natural gas pipeline project. Entrega filed its certificate application with the U.S. Federal Energy Regulatory Commission (FERC) in September 2004 for construction of the pipeline from Colorados Piceance Basin, through Wamsutter, Wyoming, to the Cheyenne natural gas trading hub in northeast Colorado. The pace of construction will be dependent upon FERC certification. If approved, the first segment of the pipeline to Wamsutter, Wyoming is expected to be on stream in late 2005, with an initial capacity of approximately 700 million cubic feet per day. |
| In November 2004, EnCana Midstream & Marketing, a wholly owned partnership of EnCana, signed a memorandum of understanding with The Premcor Refining Group Inc., an indirect wholly owned subsidiary of U.S. independent oil refiner Premcor Inc., to conduct a preliminary design and engineering study of the modifications necessary to upgrade Premcors existing refinery at Lima, Ohio to process an estimated 200,000 barrels per day of blended EnCana heavy oil supplied under a proposed long-term sales contract. The memorandum contemplates the establishment of a 50-50 joint venture which would own and operate the upgraded refinery. |
| In December 2004, EnCana sold its 25 percent non-operated partnership interest in the Kingston CoGen Limited Partnership (Kingston CoGen) for net cash consideration of approximately $25 million, subject to post-closing adjustments. Kingston CoGen owns a 110 megawatt cogeneration plant in Kingston, Ontario. |
| In December 2004, EnCana disposed of its interest in the Alberta Ethane Gathering System joint venture for approximately $108 million, subject to post-closing adjustments. |
| In October 2003, the first phase of the Countess natural gas storage facility came online, adding 10 billion cubic feet of capacity. The facility is located east of Calgary. The completion of plant facilities at Countess increased capacity to approximately 30 billion cubic feet in 2004. Utilization of the full design capacity of 40 billion cubic feet is expected in 2005, upon approval to operate at increased pressures in the reservoir. |
| In October 2003, plans to develop a new natural gas storage facility at Starks, in southwest Louisiana, were announced by a subsidiary of EnCana. An open season for capacity was held in early 2004. In October 2004, an application was filed with the FERC requesting regulatory approval. Subject to regulatory approvals and a satisfactory second open season in February 2005, the facility is expected to be in service during the third quarter of 2006 with approximately 9 billion cubic feet of initial storage capacity. Full future capacity of the Starks facility is expected to be approximately 19 billion cubic feet. |
| In January 2003, EnCana completed the sale of its indirect 70 percent interest in the Cold Lake Pipeline System for approximately $270 million. Also in January 2003, EnCana completed the sale of its indirect 100 percent interest in the Express Pipeline System (Express) for approximately $778 million, which included the assumption of approximately $385 million in debt by the purchaser. EnCana retained crude oil transportation capacity on both pipelines through its existing long-term commercial contracts. |
| All Houston-based merchant energy trading operations were discontinued following the Merger in 2002. |
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8
Developed | Undeveloped | |||||||||||||||||||||||||||
Landholdings | Acreage | Acreage | Total Acreage | Average Working | ||||||||||||||||||||||||
(thousands of acres) | Gross | Net | Gross | Net | Gross | Net | Interest | |||||||||||||||||||||
Suffield
|
942 | 930 | 275 | 271 | 1,217 | 1,201 | 99 | % | ||||||||||||||||||||
Brooks
|
1,232 | 1,206 | 183 | 170 | 1,415 | 1,376 | 97 | % | ||||||||||||||||||||
Chinook
|
1,344 | 1,317 | 300 | 279 | 1,644 | 1,596 | 97 | % | ||||||||||||||||||||
Foster Creek
|
6 | 6 | 52 | 52 | 58 | 58 | 100 | % | ||||||||||||||||||||
Christina Lake
|
4 | 4 | 68 | 62 | 72 | 66 | 92 | % | ||||||||||||||||||||
Weyburn
|
73 | 64 | 460 | 449 | 533 | 513 | 96 | % | ||||||||||||||||||||
Other
|
2,873 | 2,452 | 5,890 | 5,502 | 8,763 | 7,954 | 91 | % | ||||||||||||||||||||
Canadian Plains Total
|
6,474 | 5,979 | 7,228 | 6,785 | 13,702 | 12,764 | 93 | % | ||||||||||||||||||||
9
Natural Gas | Crude Oil and NGLs | Total Production | Total Production | |||||||||||||||||||||||||||||
Production | (MMcf/d) | (bbls/d) | (MMcfe/d) | (BOE/d) | ||||||||||||||||||||||||||||
(annual average) | 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | ||||||||||||||||||||||||
Suffield
|
241 | 230 | 26,706 | 26,945 | 401 | 391 | 66,873 | 65,279 | ||||||||||||||||||||||||
Brooks
|
474 | 434 | 15,542 | 15,295 | 568 | 526 | 94,542 | 87,628 | ||||||||||||||||||||||||
Chinook
|
356 | 329 | 7,150 | 7,342 | 399 | 373 | 66,483 | 62,175 | ||||||||||||||||||||||||
Foster Creek
|
| | 28,774 | 21,823 | 173 | 131 | 28,774 | 21,823 | ||||||||||||||||||||||||
Christina Lake
|
| | 4,364 | 3,806 | 26 | 23 | 4,364 | 3,806 | ||||||||||||||||||||||||
Weyburn
|
| | 14,200 | 10,846 | 85 | 65 | 14,200 | 10,846 | ||||||||||||||||||||||||
Other
|
203 | 188 | 30,184 | 44,171 | 384 | 453 | 64,017 | 75,504 | ||||||||||||||||||||||||
Canadian Plains Total
|
1,274 | 1,181 | 126,920 | 130,228 | 2,036 | 1,962 | 339,253 | 327,061 | ||||||||||||||||||||||||
Total | ||||||||||||||||||||||||
Producing Wells | Producing Gas Wells | Producing Oil Wells | Producing Wells | |||||||||||||||||||||
(number of wells) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
Suffield
|
7,603 | 7,510 | 641 | 639 | 8,244 | 8,149 | ||||||||||||||||||
Brooks
|
9,622 | 9,006 | 699 | 573 | 10,321 | 9,579 | ||||||||||||||||||
Chinook
|
3,134 | 3,041 | 139 | 133 | 3,273 | 3,174 | ||||||||||||||||||
Foster Creek
|
| | 36 | 36 | 36 | 36 | ||||||||||||||||||
Christina Lake
|
| | 3 | 3 | 3 | 3 | ||||||||||||||||||
Weyburn
|
| | 685 | 422 | 685 | 422 | ||||||||||||||||||
Other
|
1,888 | 1,499 | 1,322 | 937 | 3,210 | 2,436 | ||||||||||||||||||
Canadian Plains Total
|
22,247 | 21,056 | 3,525 | 2,743 | 25,772 | 23,799 | ||||||||||||||||||
10
11
Developed | Undeveloped | |||||||||||||||||||||||||||
Landholdings | Acreage | Acreage | Total Acreage | Average Working | ||||||||||||||||||||||||
(thousands of acres) | Gross | Net | Gross | Net | Gross | Net | Interest | |||||||||||||||||||||
Greater Sierra
|
464 | 397 | 2,780 | 2,424 | 3,244 | 2,821 | 87 | % | ||||||||||||||||||||
Cutbank Ridge
|
73 | 61 | 815 | 735 | 888 | 796 | 90 | % | ||||||||||||||||||||
Pelican Lake
|
83 | 83 | 135 | 135 | 218 | 218 | 100 | % | ||||||||||||||||||||
Sexsmith/ Hythe/Saddle Hills
|
288 | 194 | 242 | 178 | 530 | 372 | 70 | % | ||||||||||||||||||||
Cold Lake Air Weapons Range
|
386 | 365 | 473 | 469 | 859 | 834 | 97 | % | ||||||||||||||||||||
East Coast of Canada
|
| | 5,861 | 3,558 | 5,861 | 3,558 | 61 | % | ||||||||||||||||||||
Mackenzie Delta
|
| | 529 | 198 | 529 | 198 | 37 | % | ||||||||||||||||||||
Other
|
1,330 | 1,074 | 5,195 | 3,447 | 6,525 | 4,521 | 69 | % | ||||||||||||||||||||
Canadian Foothills & Frontier Total
|
2,624 | 2,174 | 16,030 | 11,144 | 18,654 | 13,318 | 71 | % | ||||||||||||||||||||
Natural Gas | Crude Oil and NGLs | Total Production | Total Production | |||||||||||||||||||||||||||||
Production | (MMcf/d) | (bbls/d) | (MMcfe/d) | (BOE/d) | ||||||||||||||||||||||||||||
(annual average) | 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | ||||||||||||||||||||||||
Greater Sierra
|
230 | 143 | 632 | 607 | 234 | 147 | 38,965 | 24,440 | ||||||||||||||||||||||||
Cutbank Ridge
|
40 | 3 | | | 40 | 3 | 6,667 | 500 | ||||||||||||||||||||||||
Pelican Lake
|
7 | 9 | 18,900 | 15,944 | 120 | 105 | 20,067 | 17,444 | ||||||||||||||||||||||||
Sexsmith/ Hythe/Saddle Hills
|
110 | 114 | 2,785 | 2,990 | 127 | 132 | 21,118 | 21,990 | ||||||||||||||||||||||||
Cold Lake Air Weapons Range
|
163 | 174 | | | 163 | 174 | 27,167 | 29,000 | ||||||||||||||||||||||||
Other
|
286 | 323 | 5,149 | 6,665 | 317 | 362 | 52,815 | 60,499 | ||||||||||||||||||||||||
Canadian Foothills & Frontier Total
|
836 | 766 | 27,466 | 26,206 | 1,001 | 923 | 166,799 | 153,873 | ||||||||||||||||||||||||
Total | ||||||||||||||||||||||||
Producing Wells | Producing Gas Wells | Producing Oil Wells | Producing Wells | |||||||||||||||||||||
(number of wells) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
Greater Sierra
|
559 | 516 | 2 | 2 | 561 | 518 | ||||||||||||||||||
Cutbank Ridge
|
69 | 63 | | | 69 | 63 | ||||||||||||||||||
Pelican Lake
|
15 | 15 | 514 | 514 | 529 | 529 | ||||||||||||||||||
Sexsmith/ Hythe/Saddle Hills
|
317 | 253 | 61 | 47 | 378 | 300 | ||||||||||||||||||
Cold Lake Air Weapons Range
|
608 | 583 | | | 608 | 583 | ||||||||||||||||||
Other
|
1,731 | 1,539 | 235 | 130 | 1,966 | 1,669 | ||||||||||||||||||
Canadian Foothills & Frontier Total
|
3,299 | 2,969 | 812 | 693 | 4,111 | 3,662 | ||||||||||||||||||
12
13
Landholdings | Developed Acreage | Undeveloped Acreage | Total Acreage | Average Working | ||||||||||||||||||||||||
(thousands of acres) | Gross | Net | Gross | Net | Gross | Net | Interest | |||||||||||||||||||||
Jonah
|
12 | 10 | 48 | 47 | 60 | 57 | 95 | % | ||||||||||||||||||||
Piceance
|
241 | 216 | 860 | 796 | 1,101 | 1,012 | 92 | % | ||||||||||||||||||||
East Texas
|
68 | 40 | 167 | 142 | 235 | 182 | 77 | % | ||||||||||||||||||||
Fort Worth
|
36 | 33 | 127 | 127 | 163 | 160 | 98 | % | ||||||||||||||||||||
Gulf of Mexico
|
| | 1,371 | 557 | 1,371 | 557 | 41 | % | ||||||||||||||||||||
Alaska
|
| | 1,337 | 531 | 1,337 | 531 | 40 | % | ||||||||||||||||||||
Other
|
351 | 208 | 2,615 | 2,140 | 2,966 | 2,348 | 79 | % | ||||||||||||||||||||
United States Total
|
708 | 507 | 6,525 | 4,340 | 7,233 | 4,847 | 67 | % | ||||||||||||||||||||
Natural Gas | Crude Oil and NGLs | Total Production | Total Production | |||||||||||||||||||||||||||||
Production | (MMcf/d) | (bbls/d) | (MMcfe/d) | (BOE/d) | ||||||||||||||||||||||||||||
(annual average) | 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | 2004 | 2003 | ||||||||||||||||||||||||
Jonah
|
389 | 374 | 3,294 | 3,348 | 409 | 394 | 68,127 | 65,681 | ||||||||||||||||||||||||
Piceance
|
261 | 151 | 3,074 | 2,473 | 279 | 166 | 46,574 | 27,640 | ||||||||||||||||||||||||
East Texas
|
50 | | 167 | | 51 | | 8,500 | | ||||||||||||||||||||||||
Fort Worth
|
27 | 7 | 233 | 136 | 28 | 8 | 4,733 | 1,303 | ||||||||||||||||||||||||
Other
|
142 | 56 | 6,037 | 3,504 | 179 | 77 | 29,704 | 12,837 | ||||||||||||||||||||||||
United States Total
|
869 | 588 | 12,805 | 9,461 | 946 | 645 | 157,638 | 107,461 | ||||||||||||||||||||||||
Total | ||||||||||||||||||||||||
Producing Wells | Producing Gas Wells | Producing Oil Wells | Producing Wells | |||||||||||||||||||||
(number of wells) | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||
Jonah
|
386 | 343 | | | 386 | 343 | ||||||||||||||||||
Piceance
|
2,486 | 2,065 | | | 2,486 | 2,065 | ||||||||||||||||||
East Texas
|
458 | 263 | | | 458 | 263 | ||||||||||||||||||
Fort Worth
|
399 | 366 | | | 399 | 366 | ||||||||||||||||||
Other
|
2,062 | 1,224 | 30 | 12 | 2,092 | 1,236 | ||||||||||||||||||
United States Total
|
5,791 | 4,261 | 30 | 12 | 5,821 | 4,273 | ||||||||||||||||||
14
15
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17
18
19
20
21
22
Natural Gas | Crude Oil and Natural Gas Liquids | |||||||||||||||||||||||||||||||||||||||||||
(billions of cubic feet) | (millions of barrels) | |||||||||||||||||||||||||||||||||||||||||||
United | United | United | United | |||||||||||||||||||||||||||||||||||||||||
Canada | States | Kingdom | Other | Total | Canada | States | Ecuador | Kingdom | Other | Total | ||||||||||||||||||||||||||||||||||
2002
|
||||||||||||||||||||||||||||||||||||||||||||
Beginning of year
|
3,504 | 236 | 7 | | 3,747 | 286.6 | 19.6 | | 21.6 | | 327.8 | |||||||||||||||||||||||||||||||||
Purchase of AEC reserves in place
|
2,686 | 944 | | | 3,630 | 233.7 | 6.5 | 168.4 | | | 408.6 | |||||||||||||||||||||||||||||||||
Revisions and improved recovery
|
(1,140 | ) | 731 | 7 | | (402 | ) | (15.5 | ) | 4.6 | (33.5 | ) | (9.1 | ) | | (53.5 | ) | |||||||||||||||||||||||||||
Extensions and discoveries
|
726 | 319 | 10 | | 1,055 | 96.9 | 3.3 | 31.1 | 89.2 | | 220.5 | |||||||||||||||||||||||||||||||||
Purchase of reserves in place
|
30 | 530 | | | 560 | 4.9 | 9.9 | | | | 14.8 | |||||||||||||||||||||||||||||||||
Sale of reserves in place
|
(129 | ) | (73 | ) | | | (202 | ) | (18.2 | ) | (0.7 | ) | | | | (18.9 | ) | |||||||||||||||||||||||||||
Production
|
(604 | ) | (114 | ) | (4 | ) | | (722 | ) | (46.5 | ) | (2.3 | ) | (10.2 | ) | (4.1 | ) | | (63.1 | ) | ||||||||||||||||||||||||
End of year
|
5,073 | 2,573 | 20 | | 7,666 | 541.9 | 40.9 | 155.8 | 97.6 | | 836.2 | |||||||||||||||||||||||||||||||||
Developed
|
4,139 | 1,446 | 9 | | 5,594 | 299.2 | 21.9 | 104.6 | 8.3 | | 434.0 | |||||||||||||||||||||||||||||||||
Undeveloped
|
934 | 1,127 | 11 | | 2,072 | 242.7 | 19.0 | 51.2 | 89.3 | | 402.2 | |||||||||||||||||||||||||||||||||
Total
|
5,073 | 2,573 | 20 | | 7,666 | 541.9 | 40.9 | 155.8 | 97.6 | | 836.2 | |||||||||||||||||||||||||||||||||
2003
|
||||||||||||||||||||||||||||||||||||||||||||
Beginning of year
|
5,073 | 2,573 | 20 | | 7,666 | 541.9 | 40.9 | 155.8 | 97.6 | | 836.2 | |||||||||||||||||||||||||||||||||
Revisions and improved recovery
|
73 | 1 | 3 | | 77 | 32.3 | 0.5 | 0.4 | 23.5 | | 56.7 | |||||||||||||||||||||||||||||||||
Extensions and discoveries
|
867 | 706 | | 90 | 1,663 | 110.9 | 7.4 | 11.9 | | 0.9 | 131.1 | |||||||||||||||||||||||||||||||||
Purchase of reserves in place
|
9 | 152 | 8 | | 169 | 1.3 | 0.9 | 17.3 | 7.1 | | 26.6 | |||||||||||||||||||||||||||||||||
Sale of reserves in place
|
(60 | ) | (88 | ) | | (90 | ) | (238 | ) | (0.2 | ) | (4.7 | ) | (5.1 | ) | | (0.9 | ) | (10.9 | ) | ||||||||||||||||||||||||
Production
|
(706 | ) | (215 | ) | (5 | ) | | (926 | ) | (56.8 | ) | (3.4 | ) | (18.6 | ) | (3.7 | ) | | (82.5 | ) | ||||||||||||||||||||||||
End of year
|
5,256 | 3,129 | 26 | | 8,411 | 629.4 | 41.6 | 161.7 | 124.5 | | 957.2 | |||||||||||||||||||||||||||||||||
Developed
|
3,984 | 1,833 | 13 | | 5,830 | 306.1 | 26.3 | 115.0 | 16.7 | | 464.1 | |||||||||||||||||||||||||||||||||
Undeveloped
|
1,272 | 1,296 | 13 | | 2,581 | 323.3 | 15.3 | 46.7 | 107.8 | | 493.1 | |||||||||||||||||||||||||||||||||
Total
|
5,256 | 3,129 | 26 | | 8,411 | 629.4 | 41.6 | 161.7 | 124.5 | | 957.2 | |||||||||||||||||||||||||||||||||
2004
|
||||||||||||||||||||||||||||||||||||||||||||
Beginning of year
|
5,256 | 3,129 | 26 | | 8,411 | 629.4 | 41.6 | 161.7 | 124.5 | | 957.2 | |||||||||||||||||||||||||||||||||
Revisions and improved recovery
|
67 | (252 | ) | | | (185 | ) | 31.1 | (3) | 0.2 | (11.5 | ) | | | 19.8 | |||||||||||||||||||||||||||||
Extensions and discoveries
|
1,422 | 1,009 | | | 2,431 | 93.6 | (3) | 47.6 | 21.2 | | | 162.4 | ||||||||||||||||||||||||||||||||
Purchase of reserves in place
|
65 | 1,150 | 10 | | 1,225 | 29.4 | 11.7 | | 10.1 | | 51.2 | |||||||||||||||||||||||||||||||||
Sale of reserves in place
|
(215 | ) | (82 | ) | (25 | ) | | (322 | ) | (97.3 | ) | (5.4 | ) | | (128.4 | ) | | (231.1 | ) | |||||||||||||||||||||||||
Production
|
(771 | ) | (318 | ) | (11 | ) | | (1,100 | ) | (56.6 | ) | (4.7 | ) | (28.1 | ) | (6.2 | ) | | (95.6 | ) | ||||||||||||||||||||||||
End of year before bitumen revisions
|
5,824 | 4,636 | | | 10,460 | 629.6 | 91.0 | 143.3 | | | 863.9 | |||||||||||||||||||||||||||||||||
Revisions due to bitumen price
|
| | | | | (362.7 | ) (4) | | | | | (362.7 | ) | |||||||||||||||||||||||||||||||
End of year
|
5,824 | 4,636 | (5) | | | 10,460 | 266.9 | 91.0 | (5) | 143.3 | (6) | | | 501.2 | ||||||||||||||||||||||||||||||
Developed
|
4,406 | 2,496 | | | 6,902 | 210.2 | 31.5 | 122.5 | | | 364.2 | |||||||||||||||||||||||||||||||||
Undeveloped
|
1,418 | 2,140 | | | 3,558 | 56.7 | 59.5 | 20.8 | | | 137.0 | |||||||||||||||||||||||||||||||||
Total
|
5,824 | 4,636 | | | 10,460 | 266.9 | 91.0 | 143.3 | | | 501.2 | |||||||||||||||||||||||||||||||||
(1) | Definitions: |
a. | Net reserves are the remaining reserves of EnCana, after deduction of estimated royalties and including royalty interests. | |
b. | Proved reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. | |
c. | Proved Developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. | |
d. | Proved Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. |
(2) | EnCana does not file any estimates of total net proved crude oil or natural gas reserves with any U.S. federal authority or agency other than the SEC. |
(3) | An aggregate of approximately of 75.8 million barrels of proved reserves in the Foster Creek area are subject to the revisions due to bitumen price, including approximately 5.4 million barrels under revisions and improved recovery and approximately 70.4 million barrels under extensions and discoveries. |
(4) | Removal of the Corporations Foster Creek proved bitumen reserves as described under Reserve Quantities Information. |
(5) | Includes approximately 14 billion cubic feet of natural gas and approximately 38.8 million barrels of crude oil and NGLs reserves attributable to the Corporations Gulf of Mexico assets, which EnCana plans to dispose of in 2005. |
(6) | The Corporation plans to dispose of its Ecuadorian operations in 2005. Accordingly, Ecuador is treated as a discontinued operation for financial reporting purposes. |
23
Canada | United States | Ecuador | ||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Future cash inflows
|
37,791 | 35,126 | 29,890 | 27,063 | 17,472 | 9,398 | 3,317 | 3,533 | 3,368 | |||||||||||||||||||||||||||
Future production costs
|
7,760 | 9,630 | 5,873 | 2,462 | 1,456 | 2,090 | 1,136 | 738 | 635 | |||||||||||||||||||||||||||
Future development costs
|
4,906 | 4,388 | 2,813 | 3,406 | 1,433 | 1,270 | 220 | 249 | 273 | |||||||||||||||||||||||||||
Undiscounted pre-tax cash flows
|
25,125 | 21,108 | 21,204 | 21,195 | 14,583 | 6,038 | 1,961 | 2,546 | 2,460 | |||||||||||||||||||||||||||
Future income taxes
|
6,279 | 5,874 | 6,353 | 7,021 | 4,960 | 1,504 | 342 | 536 | 585 | |||||||||||||||||||||||||||
Future net cash flows
|
18,846 | 15,234 | 14,851 | 14,174 | 9,623 | 4,534 | 1,619 | 2,010 | 1,875 | |||||||||||||||||||||||||||
Less discount of net cash flows using a 10% rate
|
6,668 | 5,219 | 6,018 | 6,686 | 4,735 | 2,383 | 417 | 643 | 617 | |||||||||||||||||||||||||||
Discounted future net cash flows
|
12,178 | 10,015 | 8,833 | 7,488 | 4,888 | 2,151 | 1,202 | 1,367 | 1,258 | |||||||||||||||||||||||||||
United Kingdom | Total | |||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||||||||||||
($ millions) | ||||||||||||||||||||||||
Future cash inflows
|
| 3,483 | 2,565 | 68,171 | 59,614 | 45,221 | ||||||||||||||||||
Future production costs
|
| 961 | 397 | 11,358 | 12,785 | 8,995 | ||||||||||||||||||
Future development costs
|
| 1,008 | 836 | 8,532 | 7,078 | 5,192 | ||||||||||||||||||
Undiscounted pre-tax cash flows
|
| 1,514 | 1,332 | 48,281 | 39,751 | 31,034 | ||||||||||||||||||
Future income taxes
|
| 456 | 483 | 13,642 | 11,826 | 8,925 | ||||||||||||||||||
Future net cash flows
|
| 1,058 | 849 | 34,639 | 27,925 | 22,109 | ||||||||||||||||||
Less discount of net cash flows using a 10% rate
|
| 493 | 438 | 13,771 | 11,090 | 9,456 | ||||||||||||||||||
Discounted future net cash flows
|
| 565 | 411 | 20,868 | 16,835 | 12,653 | ||||||||||||||||||
24
Canada | United States | Ecuador | |||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | |||||||||||||||||||||||||||||
($ millions) | |||||||||||||||||||||||||||||||||||||
Balance, beginning of year
|
10,015 | 8,833 | 3,060 | 4,888 | 2,151 | 300 | 1,367 | 1,258 | | ||||||||||||||||||||||||||||
Changes resulting from:
|
|||||||||||||||||||||||||||||||||||||
Sales of oil and gas produced during the period
|
(3,965 | ) | (3,429 | ) | (2,092 | ) | (1,474 | ) | (889 | ) | (329 | ) | (264 | ) | (258 | ) | (157 | ) | |||||||||||||||||||
Discoveries and extensions, net of related costs
|
3,562 | 1,272 | 1,293 | 2,436 | 1,381 | 293 | 236 | 126 | 330 | ||||||||||||||||||||||||||||
Purchases of proved AEC reserves in place
|
| | 6,810 | | | 1,044 | | | 1,830 | ||||||||||||||||||||||||||||
Purchases of proved reserves in place
|
531 | 26 | 93 | 2,786 | 340 | 613 | | 93 | | ||||||||||||||||||||||||||||
Sales of proved reserves in place
|
(1,579 | ) | (95 | ) | (371 | ) | (271 | ) | (108 | ) | (72 | ) | | (54 | ) | | |||||||||||||||||||||
Net change in prices and production costs
|
2,264 | 242 | 3,358 | 143 | 2,751 | 194 | (294 | ) | (47 | ) | | ||||||||||||||||||||||||||
Revisions to quantity estimates
|
546 | 416 | (1,345 | ) | (542 | ) | 4 | 667 | (125 | ) | 4 | (354 | ) | ||||||||||||||||||||||||
Accretion of discount
|
1,349 | 1,636 | 455 | 725 | 304 | 56 | 176 | 182 | | ||||||||||||||||||||||||||||
Previously estimated development costs incurred net of change in
future development costs
|
57 | 340 | 101 | 22 | 534 | 54 | 15 | 89 | | ||||||||||||||||||||||||||||
Other
|
32 | 470 | (67 | ) | (49 | ) | 157 | (51 | ) | (29 | ) | (27 | ) | | |||||||||||||||||||||||
Net change in income taxes
|
(634 | ) | 304 | (2,462 | ) | (1,176 | ) | (1,737 | ) | (618 | ) | 120 | 1 | (391 | ) | ||||||||||||||||||||||
Balance, end of year
|
12,178 | 10,015 | 8,833 | 7,488 | 4,888 | 2,151 | 1,202 | 1,367 | 1,258 | ||||||||||||||||||||||||||||
United Kingdom | Total | ||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
($ millions) | |||||||||||||||||||||||||
Balance, beginning of year
|
565 | 411 | 140 | 16,835 | 12,653 | 3,500 | |||||||||||||||||||
Changes resulting from:
|
|||||||||||||||||||||||||
Sales of oil and gas produced during the period
|
(78 | ) | (83 | ) | (81 | ) | (5,781 | ) | (4,659 | ) | (2,659 | ) | |||||||||||||
Discoveries and extensions, net of related costs
|
| | 594 | 6,234 | 2,779 | 2,510 | |||||||||||||||||||
Purchases of proved AEC reserves in place
|
| | | | | 9,684 | |||||||||||||||||||
Purchases of proved reserves in place
|
77 | 57 | | 3,394 | 516 | 706 | |||||||||||||||||||
Sales of proved reserves in place
|
(899 | ) | | | (2,749 | ) | (257 | ) | (443 | ) | |||||||||||||||
Net change in prices and production costs
|
| (119 | ) | (1 | ) | 2,113 | 2,827 | 3,551 | |||||||||||||||||
Revisions to quantity estimates
|
| 157 | (53 | ) | (121 | ) | 581 | (1,085 | ) | ||||||||||||||||
Accretion of discount
|
82 | 91 | 14 | 2,332 | 2,213 | 525 | |||||||||||||||||||
Previously estimated development costs incurred net of change in
future development costs
|
| 108 | 3 | 94 | 1,071 | 158 | |||||||||||||||||||
Other
|
| (38 | ) | (8 | ) | (46 | ) | 562 | (126 | ) | |||||||||||||||
Net change in income taxes
|
253 | (19 | ) | (197 | ) | (1,437 | ) | (1,451 | ) | (3,668 | ) | ||||||||||||||
Balance, end of year
|
| 565 | 411 | 20,868 | 16,835 | 12,653 | |||||||||||||||||||
25
Canada | United States | Ecuador | ||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Oil and gas revenues, net of royalties, transportation and
selling costs
|
4,787 | 4,189 | 2,630 | 1,861 | 1,091 | 406 | 451 | 367 | 224 | |||||||||||||||||||||||||||
Operating costs, production and mineral taxes, and accretion of
asset retirement obligations
|
822 | 760 | 538 | 387 | 202 | 77 | 187 | 109 | 67 | |||||||||||||||||||||||||||
Depreciation, depletion and amortization
|
1,752 | 1,511 | 871 | 487 | 297 | 206 | 263 | 159 | 79 | |||||||||||||||||||||||||||
Operating income (loss)
|
2,213 | 1,918 | 1,221 | 987 | 592 | 123 | 1 | 99 | 78 | |||||||||||||||||||||||||||
Income taxes
|
841 | 218 | 456 | 375 | 219 | 47 | 5 | 17 | 28 | |||||||||||||||||||||||||||
Results of operations
|
1,372 | 1,700 | 765 | 612 | 373 | 76 | (4 | ) | 82 | 50 | ||||||||||||||||||||||||||
United Kingdom | Other | Total | ||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Oil and gas revenues, net of royalties, transportation and
selling costs
|
117 | 102 | 92 | | | | 7,216 | 5,749 | 3,352 | |||||||||||||||||||||||||||
Operating costs, production and mineral taxes, and accretion of
asset retirement obligations
|
39 | 19 | 11 | 4 | 20 | 29 | 1,439 | 1,110 | 722 | |||||||||||||||||||||||||||
Depreciation, depletion and amortization
|
118 | 74 | 39 | 25 | 83 | 35 | 2,645 | 2,124 | 1,230 | |||||||||||||||||||||||||||
Operating income (loss)
|
(40 | ) | 9 | 42 | (29 | ) | (103 | ) | (64 | ) | 3,132 | 2,515 | 1,400 | |||||||||||||||||||||||
Income taxes
|
(15 | ) | 17 | 17 | | (4 | ) | | 1,206 | 467 | 548 | |||||||||||||||||||||||||
Results of operations
|
(25 | ) | (8 | ) | 25 | (29 | ) | (99 | ) | (64 | ) | 1,926 | 2,048 | 852 | ||||||||||||||||||||||
Canada | United States | Ecuador | ||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Proved oil and gas properties
|
22,455 | 18,549 | 12,504 | 7,552 | 3,485 | 2,769 | 1,784 | 1,372 | 1,000 | |||||||||||||||||||||||||||
Unproved oil and gas properties
|
1,855 | 1,981 | 1,573 | 728 | 501 | 415 | 45 | 70 | 60 | |||||||||||||||||||||||||||
Total capital cost
|
24,310 | 20,530 | 14,077 | 8,280 | 3,986 | 3,184 | 1,829 | 1,442 | 1,060 | |||||||||||||||||||||||||||
Accumulated DD&A
|
9,770 | 7,498 | 4,770 | 1,046 | 516 | 262 | 534 | 188 | 73 | |||||||||||||||||||||||||||
Net capitalized costs
|
14,540 | 13,032 | 9,307 | 7,234 | 3,470 | 2,922 | 1,295 | 1,254 | 987 | |||||||||||||||||||||||||||
United Kingdom | Other | Total | ||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Proved oil and gas properties
|
| 675 | 445 | | | | 31,791 | 24,081 | 16,718 | |||||||||||||||||||||||||||
Unproved oil and gas properties
|
| 77 | 3 | 425 | 317 | 226 | 3,053 | 2,946 | 2,277 | |||||||||||||||||||||||||||
Total capital cost
|
| 752 | 448 | 425 | 317 | 226 | 34,844 | 27,027 | 18,995 | |||||||||||||||||||||||||||
Accumulated DD&A
|
| 230 | 136 | 247 | 206 | 98 | 11,597 | 8,638 | 5,339 | |||||||||||||||||||||||||||
Net capitalized costs
|
| 522 | 312 | 178 | 111 | 128 | 23,247 | 18,389 | 13,656 | |||||||||||||||||||||||||||
26
Canada | United States | Ecuador | ||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Acquisitions
|
||||||||||||||||||||||||||||||||||||
AEC unproved reserves
|
| | 1,496 | | | 444 | | | 221 | |||||||||||||||||||||||||||
other unproved reserves
|
42 | 47 | 12 | 954 | 21 | 202 | | 80 | | |||||||||||||||||||||||||||
AEC proved reserves
|
| | 3,540 | | | 1,024 | | | 686 | |||||||||||||||||||||||||||
other proved reserves
|
204 | 207 | 78 | 2,051 | 115 | 457 | | 59 | | |||||||||||||||||||||||||||
Total acquisitions
|
246 | 254 | 5,126 | 3,005 | 136 | 2,127 | | 139 | 907 | |||||||||||||||||||||||||||
Exploration
|
555 | 846 | 403 | 164 | 187 | 226 | 28 | 20 | 35 | |||||||||||||||||||||||||||
Development
|
2,669 | 2,131 | 902 | 1,103 | 651 | 282 | 213 | 111 | 133 | |||||||||||||||||||||||||||
Total costs incurred
|
3,470 | 3,231 | 6,431 | 4,272 | 974 | 2,635 | 241 | 270 | 1,075 | |||||||||||||||||||||||||||
United Kingdom | Other | Total | ||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||
($ millions) | ||||||||||||||||||||||||||||||||||||
Acquisitions
|
||||||||||||||||||||||||||||||||||||
AEC unproved reserves
|
| | | | | | | | 2,161 | |||||||||||||||||||||||||||
other unproved reserves
|
| 16 | | | | | 996 | 164 | 214 | |||||||||||||||||||||||||||
AEC proved reserves
|
| | | | | | | | 5,250 | |||||||||||||||||||||||||||
other proved reserves
|
130 | 95 | | | | | 2,385 | 476 | 535 | |||||||||||||||||||||||||||
Total acquisitions
|
130 | 111 | | | | | 3,381 | 640 | 8,160 | |||||||||||||||||||||||||||
Exploration
|
22 | 30 | 16 | 79 | 78 | 118 | 848 | 1,161 | 798 | |||||||||||||||||||||||||||
Development
|
364 | 96 | 66 | | | | 4,349 | 2,989 | 1,383 | |||||||||||||||||||||||||||
Total costs incurred
|
516 | 237 | 82 | 79 | 78 | 118 | 8,578 | 4,790 | 10,341 | |||||||||||||||||||||||||||
27
Daily Sales Volumes 2004 | |||||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||
SALES
|
|||||||||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||||
Produced Gas (MMcf/d)
|
|||||||||||||||||||||||
Canada
|
|||||||||||||||||||||||
Production
|
2,105 | 2,106 | 2,138 | 2,177 | 2,000 | ||||||||||||||||||
Inventory withdrawal/(injection)
|
(6 | ) | (26 | ) | | | | ||||||||||||||||
Canada
Sales(1)
|
2,099 | 2,080 | 2,138 | 2,177 | 2,000 | ||||||||||||||||||
United States
|
869 | 1,007 | 958 | 824 | 684 | ||||||||||||||||||
Total Produced Gas
|
2,968 | 3,087 | 3,096 | 3,001 | 2,684 | ||||||||||||||||||
Oil and Natural Gas Liquids (bbls/d)
|
|||||||||||||||||||||||
North America
|
|||||||||||||||||||||||
Light and medium oil
|
56,215 | 52,725 | 52,824 | 64,448 | 54,940 | ||||||||||||||||||
Heavy oil
|
84,164 | 79,336 | 89,682 | 79,899 | 87,729 | ||||||||||||||||||
Natural gas liquids
|
|||||||||||||||||||||||
Canada
|
13,452 | 13,452 | 12,804 | 13,588 | 13,971 | ||||||||||||||||||
United States
|
12,586 | 13,957 | 14,363 | 12,752 | 9,237 | ||||||||||||||||||
Total Oil and Natural Gas
Liquids(2)
|
166,417 | 159,470 | 169,673 | 170,687 | 165,877 | ||||||||||||||||||
Total Continuing Operations (MMcfe/d)
|
3,966 | 4,044 | 4,114 | 4,025 | 3,679 | ||||||||||||||||||
Total Continuing Operations (BOE/d)
|
661,084 | 673,970 | 685,673 | 670,854 | 613,210 | ||||||||||||||||||
Discontinued Operations: | |||||||||||||||||||||||
Ecuador
|
|||||||||||||||||||||||
Production(3)
|
76,872 | 76,235 | 76,567 | 78,376 | 76,320 | ||||||||||||||||||
Over/(under) lifting
|
1,121 | 1,641 | (1,721 | ) | (73 | ) | 4,662 | ||||||||||||||||
Ecuador Sales (bbls/d)
|
77,993 | 77,876 | 74,846 | 78,303 | 80,982 | ||||||||||||||||||
United Kingdom (BOE/d)
|
20,973 | 13,927 | 20,222 | 26,728 | 22,755 | ||||||||||||||||||
Total Discontinued Operations (MMcfe/d)
|
594 | 551 | 570 | 630 | 623 | ||||||||||||||||||
Total Discontinued Operations (BOE/d)
|
98,966 | 91,803 | 95,068 | 105,031 | 103,737 | ||||||||||||||||||
Total (MMcfe/d)
|
4,560 | 4,595 | 4,684 | 4,655 | 4,302 | ||||||||||||||||||
Total (BOE/d)
|
760,050 | 765,773 | 780,741 | 775,885 | 716,947 | ||||||||||||||||||
(1) | Net dispositions total approximately 42 MMcf/day for the full year 2004. |
(2) | Net dispositions total approximately 15,500 bbls/day for the full year 2004. |
(3) | 2004 includes approximately 31,000 bbls/day related to Block 15. |
28
Daily Sales Volumes 2003 | |||||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||
SALES
|
|||||||||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||||
Produced Gas (MMcf/d)
|
|||||||||||||||||||||||
Canada
|
|||||||||||||||||||||||
Production
|
1,935 | 2,008 | 1,914 | 1,899 | 1,922 | ||||||||||||||||||
Inventory withdrawal/(injection)
|
30 | | | | 120 | ||||||||||||||||||
Canada Sales
|
1,965 | 2,008 | 1,914 | 1,899 | 2,042 | ||||||||||||||||||
United States
|
588 | 654 | 604 | 558 | 534 | ||||||||||||||||||
Total Produced Gas
|
2,553 | 2,662 | 2,518 | 2,457 | 2,576 | ||||||||||||||||||
Oil and Natural Gas Liquids (bbls/d)
|
|||||||||||||||||||||||
North America
|
|||||||||||||||||||||||
Light and medium oil
|
54,459 | 56,585 | 54,597 | 52,733 | 53,890 | ||||||||||||||||||
Heavy oil
|
87,867 | 95,059 | 94,985 | 82,001 | 79,171 | ||||||||||||||||||
Natural gas liquids
|
|||||||||||||||||||||||
Canada
|
14,278 | 13,348 | 13,758 | 14,740 | 15,291 | ||||||||||||||||||
United States
|
9,291 | 9,479 | 9,530 | 10,194 | 7,943 | ||||||||||||||||||
Total Oil and Natural Gas Liquids
|
165,895 | 174,471 | 172,870 | 159,668 | 156,295 | ||||||||||||||||||
Total Continuing Operations (MMcfe/d)
|
3,548 | 3,709 | 3,555 | 3,415 | 3,514 | ||||||||||||||||||
Total Continuing Operations (BOE/d)
|
591,395 | 618,138 | 592,537 | 569,168 | 585,628 | ||||||||||||||||||
Discontinued Operations: | |||||||||||||||||||||||
Ecuador
|
|||||||||||||||||||||||
Production
|
51,089 | 72,731 | 54,582 | 36,754 | 39,893 | ||||||||||||||||||
Transferred to OCP
Pipeline(1)
|
(3,213 | ) | | (4,919 | ) | (2,039 | ) | (5,941 | ) | ||||||||||||||
Over/(under) lifting
|
(1,355 | ) | 4,621 | (9,856 | ) | 2,506 | (2,679 | ) | |||||||||||||||
Ecuador Sales (bbls/d)
|
46,521 | 77,352 | 39,807 | 37,221 | 31,273 | ||||||||||||||||||
United Kingdom (BOE/d)
|
12,295 | 18,400 | 6,979 | 11,019 | 12,777 | ||||||||||||||||||
Syncrude (bbls/d)
|
7,629 | | 3,399 | 7,316 | 20,070 | ||||||||||||||||||
Total Discontinued Operations (MMcfe/d)
|
399 | 574 | 301 | 333 | 385 | ||||||||||||||||||
Total Discontinued Operations (BOE/d)
|
66,445 | 95,752 | 50,185 | 55,556 | 64,120 | ||||||||||||||||||
Total (MMcfe/d)
|
3,947 | 4,283 | 3,856 | 3,748 | 3,899 | ||||||||||||||||||
Total (BOE/d)
|
657,840 | 713,890 | 642,722 | 624,724 | 649,748 | ||||||||||||||||||
(1) | Crude oil production in Ecuador transferred to the OCP Pipeline for use by OCP in asset commissioning. |
29
Daily Sales Volumes 2002 | |||||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||
SALES
|
|||||||||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||||
Produced Gas (MMcf/d)
|
|||||||||||||||||||||||
Canada
|
|||||||||||||||||||||||
Production
|
1,717 | 1,943 | 1,959 | 1,980 | 975 | ||||||||||||||||||
Inventory withdrawal/(injection)
|
(6 | ) | 117 | (51 | ) | (90 | ) | | |||||||||||||||
Canada Sales
|
1,711 | 2,060 | 1,908 | 1,890 | 975 | ||||||||||||||||||
United States
|
337 | 516 | 423 | 345 | 58 | ||||||||||||||||||
Total Produced Gas
|
2,048 | 2,576 | 2,331 | 2,235 | 1,033 | ||||||||||||||||||
Oil and Natural Gas Liquids (bbls/d)
|
|||||||||||||||||||||||
North America
|
|||||||||||||||||||||||
Light and medium oil
|
58,328 | 55,265 | 58,321 | 58,885 | 60,903 | ||||||||||||||||||
Heavy oil
|
58,890 | 77,090 | 70,795 | 67,558 | 19,350 | ||||||||||||||||||
Natural gas liquids
|
|||||||||||||||||||||||
Canada
|
13,852 | 15,987 | 13,985 | 14,168 | 11,212 | ||||||||||||||||||
United States
|
6,407 | 10,016 | 5,901 | 6,368 | 3,274 | ||||||||||||||||||
Total Oil and Natural Gas Liquids
|
137,477 | 158,358 | 149,002 | 146,979 | 94,739 | ||||||||||||||||||
Total Continuing Operations (MMcfe/d)
|
2,873 | 3,526 | 3,225 | 3,117 | 1,601 | ||||||||||||||||||
Total Continuing Operations (BOE/d)
|
478,810 | 587,691 | 537,502 | 519,479 | 266,906 | ||||||||||||||||||
Discontinued Operations: | |||||||||||||||||||||||
Ecuador
|
|||||||||||||||||||||||
Production
|
27,625 | 34,856 | 37,447 | 37,702 | | ||||||||||||||||||
Over/(under) lifting
|
2,115 | 1,044 | 2,316 | 5,088 | | ||||||||||||||||||
Ecuador Sales (bbls/d)
|
29,740 | 35,900 | 39,763 | 42,790 | | ||||||||||||||||||
United Kingdom (BOE/d)
|
12,195 | 9,120 | 11,038 | 13,299 | 14,722 | ||||||||||||||||||
Syncrude (bbls/d)
|
23,540 | 33,918 | 35,585 | 24,152 | | ||||||||||||||||||
Total Discontinued Operations (MMcfe/d)
|
393 | 474 | 518 | 481 | 88 | ||||||||||||||||||
Total Discontinued Operations (BOE/d)
|
65,475 | 78,938 | 86,386 | 80,241 | 14,722 | ||||||||||||||||||
Total (MMcfe/d)
|
3,266 | 4,000 | 3,743 | 3,598 | 1,689 | ||||||||||||||||||
Total (BOE/d)
|
544,285 | 666,629 | 623,888 | 599,720 | 281,628 | ||||||||||||||||||
30
2004 | 2003 | 2002 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | Year | Q4 | Q3 | Q2 | Q1 | Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||||||||||||||||||||||||||||||||
(percent) | (percent) | (percent) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Produced Gas
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Canada
|
12.5 | 12.0 | 12.2 | 12.7 | 13.3 | 12.9 | 12.2 | 12.9 | 14.2 | 12.4 | 10.7 | 13.3 | 10.4 | 11.8 | 2.7 | ||||||||||||||||||||||||||||||||||||||||||||||
United States
|
19.6 | 19.8 | 18.3 | 21.1 | 19.3 | 20.0 | 19.5 | 20.2 | 20.1 | 20.5 | 21.1 | 21.1 | 23.1 | 19.4 | 19.4 | ||||||||||||||||||||||||||||||||||||||||||||||
Crude Oil
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Canada and United States
|
9.0 | 8.7 | 8.8 | 11.6 | 9.4 | 10.3 | 9.7 | 9.0 | 10.7 | 11.8 | 11.0 | 10.8 | 11.7 | 11.6 | 9.5 | ||||||||||||||||||||||||||||||||||||||||||||||
Natural Gas Liquids
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Canada
|
15.7 | 16.5 | 18.5 | 13.1 | 14.8 | 17.5 | 14.7 | 16.6 | 18.0 | 20.2 | 13.8 | 16.4 | 13.8 | 15.6 | 6.9 | ||||||||||||||||||||||||||||||||||||||||||||||
United States
|
18.7 | 21.4 | 13.6 | 20.7 | 19.2 | 17.6 | 17.5 | 17.0 | 17.3 | 18.5 | 10.8 | 13.3 | 12.0 | 10.5 | | ||||||||||||||||||||||||||||||||||||||||||||||
Total Upstream
|
13.7 | 13.8 | 13.2 | 14.1 | 13.7 | 13.8 | 13.2 | 13.4 | 14.5 | 13.9 | 12.3 | 14.1 | 12.7 | 12.8 | 5.7 | ||||||||||||||||||||||||||||||||||||||||||||||
Discontinued Operations: | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Crude Oil Ecuador
|
27.1 | 27.8 | 26.5 | 26.5 | 27.4 | 25.6 | 25.4 | 25.7 | 24.9 | 26.9 | 28.4 | 28.1 | 28.5 | 28.5 | | ||||||||||||||||||||||||||||||||||||||||||||||
Per-Unit Results 2004 | |||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||
Produced Gas Canada ($/Mcf)
|
|||||||||||||||||||||
Price
|
5.34 | 5.86 | 5.10 | 5.20 | 5.21 | ||||||||||||||||
Production and mineral taxes
|
0.08 | 0.10 | 0.09 | 0.07 | 0.08 | ||||||||||||||||
Transportation and selling
|
0.39 | 0.39 | 0.37 | 0.35 | 0.44 | ||||||||||||||||
Operating
|
0.52 | 0.55 | 0.50 | 0.49 | 0.56 | ||||||||||||||||
Netback
|
4.35 | 4.82 | 4.14 | 4.29 | 4.13 | ||||||||||||||||
Produced Gas United States ($/Mcf)
|
|||||||||||||||||||||
Price
|
5.79 | 6.53 | 5.36 | 5.72 | 5.39 | ||||||||||||||||
Production and mineral taxes
|
0.65 | 0.69 | 0.57 | 0.80 | 0.51 | ||||||||||||||||
Transportation and selling
|
0.31 | 0.27 | 0.26 | 0.34 | 0.39 | ||||||||||||||||
Operating
|
0.37 | 0.41 | 0.36 | 0.37 | 0.33 | ||||||||||||||||
Netback
|
4.46 | 5.16 | 4.17 | 4.21 | 4.16 | ||||||||||||||||
Produced Gas Total North America ($/Mcf)
|
|||||||||||||||||||||
Price
|
5.47 | 6.08 | 5.18 | 5.34 | 5.26 | ||||||||||||||||
Production and mineral taxes
|
0.25 | 0.29 | 0.24 | 0.27 | 0.19 | ||||||||||||||||
Transportation and selling
|
0.36 | 0.35 | 0.33 | 0.35 | 0.43 | ||||||||||||||||
Operating
|
0.48 | 0.50 | 0.46 | 0.46 | 0.50 | ||||||||||||||||
Netback
|
4.38 | 4.94 | 4.15 | 4.26 | 4.14 | ||||||||||||||||
Natural Gas Liquids Canada ($/bbl)
|
|||||||||||||||||||||
Price
|
31.43 | 36.73 | 33.46 | 28.48 | 27.27 | ||||||||||||||||
Production and mineral taxes
|
| | | | | ||||||||||||||||
Transportation and selling
|
0.41 | 0.47 | 0.45 | 0.35 | 0.35 | ||||||||||||||||
Netback
|
31.02 | 36.26 | 33.01 | 28.13 | 26.92 | ||||||||||||||||
31
Per-Unit Results 2004 | |||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||
Natural Gas Liquids United States ($/bbl)
|
|||||||||||||||||||||
Price
|
35.43 | 38.74 | 36.09 | 32.93 | 32.77 | ||||||||||||||||
Production and mineral taxes
|
3.82 | 3.94 | 4.05 | 3.93 | 3.09 | ||||||||||||||||
Transportation and selling
|
| | | | | ||||||||||||||||
Netback
|
31.61 | 34.80 | 32.04 | 29.00 | 29.68 | ||||||||||||||||
Natural Gas Liquids Total North America ($/bbl)
|
|||||||||||||||||||||
Price
|
33.36 | 37.75 | 34.85 | 30.63 | 29.46 | ||||||||||||||||
Production and mineral taxes
|
1.84 | 2.00 | 2.14 | 1.90 | 1.23 | ||||||||||||||||
Transportation and selling
|
0.21 | 0.23 | 0.21 | 0.18 | 0.21 | ||||||||||||||||
Netback
|
31.31 | 35.52 | 32.50 | 28.55 | 28.02 | ||||||||||||||||
Crude Oil Light and Medium North America
($/bbl)
|
|||||||||||||||||||||
Price
|
34.67 | 39.57 | 37.40 | 32.43 | 29.92 | ||||||||||||||||
Production and mineral taxes
|
0.96 | 1.38 | 0.85 | 0.79 | 0.86 | ||||||||||||||||
Transportation and selling
|
1.01 | 1.04 | 1.08 | 0.76 | 1.19 | ||||||||||||||||
Operating
|
5.85 | 6.41 | 6.49 | 4.84 | 5.87 | ||||||||||||||||
Netback
|
26.85 | 30.74 | 28.98 | 26.04 | 22.00 | ||||||||||||||||
Crude Oil Heavy North America ($/bbl)
|
|||||||||||||||||||||
Price
|
23.41 | 21.37 | 28.01 | 22.35 | 21.48 | ||||||||||||||||
Production and mineral taxes
|
0.04 | 0.04 | 0.05 | (0.01 | ) | 0.06 | |||||||||||||||
Transportation and selling
|
1.09 | (0.57 | ) | 1.63 | 1.50 | 1.69 | |||||||||||||||
Operating
|
5.32 | 6.27 | 4.79 | 4.82 | 5.44 | ||||||||||||||||
Netback
|
16.96 | 15.63 | 21.54 | 16.04 | 14.29 | ||||||||||||||||
Crude Oil Total North America ($/bbl)
|
|||||||||||||||||||||
Price
|
27.92 | 28.63 | 31.49 | 26.85 | 24.73 | ||||||||||||||||
Production and mineral taxes
|
0.41 | 0.57 | 0.34 | 0.35 | 0.37 | ||||||||||||||||
Transportation and selling
|
1.06 | 0.07 | 1.42 | 1.17 | 1.50 | ||||||||||||||||
Operating
|
5.53 | 6.33 | 5.42 | 4.83 | 5.61 | ||||||||||||||||
Netback
|
20.92 | 21.66 | 24.31 | 20.50 | 17.25 | ||||||||||||||||
Total Liquids Canada ($/bbl)
|
|||||||||||||||||||||
Price
|
28.21 | 29.36 | 31.63 | 26.99 | 24.95 | ||||||||||||||||
Production and mineral taxes
|
0.37 | 0.52 | 0.31 | 0.32 | 0.34 | ||||||||||||||||
Transportation and selling
|
1.00 | 0.11 | 1.35 | 1.10 | 1.40 | ||||||||||||||||
Operating
|
5.05 | 5.75 | 4.98 | 4.42 | 5.11 | ||||||||||||||||
Netback
|
21.79 | 22.98 | 24.99 | 21.15 | 18.10 | ||||||||||||||||
Total Liquids North America ($/bbl)
|
|||||||||||||||||||||
Price
|
28.77 | 30.20 | 32.03 | 27.43 | 25.39 | ||||||||||||||||
Production and mineral taxes
|
0.63 | 0.82 | 0.63 | 0.59 | 0.49 | ||||||||||||||||
Transportation and selling
|
0.93 | 0.10 | 1.23 | 1.02 | 1.32 | ||||||||||||||||
Operating
|
4.67 | 5.24 | 4.55 | 4.09 | 4.82 | ||||||||||||||||
Netback
|
22.54 | 24.04 | 25.62 | 21.73 | 18.76 | ||||||||||||||||
32
Per-Unit Results 2004 | |||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||
Total North America ($/Mcfe)
|
|||||||||||||||||||||
Price
|
5.30 | 5.83 | 5.22 | 5.15 | 4.98 | ||||||||||||||||
Production and mineral taxes
|
0.21 | 0.25 | 0.21 | 0.22 | 0.16 | ||||||||||||||||
Transportation and selling
|
0.31 | 0.27 | 0.30 | 0.30 | 0.37 | ||||||||||||||||
Operating
|
0.55 | 0.59 | 0.53 | 0.52 | 0.58 | ||||||||||||||||
Netback
|
4.23 | 4.72 | 4.18 | 4.11 | 3.87 | ||||||||||||||||
Discontinued Operations:
|
|||||||||||||||||||||
Crude Oil Ecuador ($/bbl)
|
|||||||||||||||||||||
Price
|
28.68 | 29.97 | 33.47 | 27.78 | 23.82 | ||||||||||||||||
Production and mineral taxes
|
2.13 | 2.73 | 2.62 | 1.84 | 1.37 | ||||||||||||||||
Transportation and selling
|
2.12 | 1.57 | 2.36 | 1.92 | 2.63 | ||||||||||||||||
Operating
|
4.39 | 5.02 | 4.35 | 4.14 | 4.04 | ||||||||||||||||
Netback
|
20.04 | 20.65 | 24.14 | 19.88 | 15.78 | ||||||||||||||||
Crude Oil United Kingdom ($/bbl)
|
|||||||||||||||||||||
Price
|
36.92 | 46.19 | 40.88 | 34.68 | 31.11 | ||||||||||||||||
Production and mineral taxes
|
| | | | | ||||||||||||||||
Transportation and selling
|
2.06 | 2.17 | 2.44 | 1.85 | 1.94 | ||||||||||||||||
Operating
|
6.75 | 5.00 | 9.98 | 7.84 | 3.86 | ||||||||||||||||
Netback
|
28.11 | 39.02 | 28.46 | 24.99 | 25.31 | ||||||||||||||||
33
Per-Unit Results 2003 | |||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||
Produced Gas Canada ($/Mcf)
|
|||||||||||||||||||||
Price
|
4.87 | 4.41 | 4.61 | 4.92 | 5.53 | ||||||||||||||||
Production and mineral taxes
|
0.07 | 0.10 | 0.08 | 0.08 | 0.02 | ||||||||||||||||
Transportation and selling
|
0.38 | 0.44 | 0.40 | 0.35 | 0.33 | ||||||||||||||||
Operating
|
0.48 | 0.45 | 0.50 | 0.47 | 0.48 | ||||||||||||||||
Netback
|
3.94 | 3.42 | 3.63 | 4.02 | 4.70 | ||||||||||||||||
Produced Gas United States ($/Mcf)
|
|||||||||||||||||||||
Price
|
4.88 | 4.71 | 4.82 | 4.74 | 5.32 | ||||||||||||||||
Production and mineral taxes
|
0.47 | 0.42 | 0.46 | 0.46 | 0.57 | ||||||||||||||||
Transportation and selling
|
0.40 | 0.51 | 0.39 | 0.36 | 0.32 | ||||||||||||||||
Operating
|
0.28 | 0.29 | 0.33 | 0.31 | 0.20 | ||||||||||||||||
Netback
|
3.73 | 3.49 | 3.64 | 3.61 | 4.23 | ||||||||||||||||
Produced Gas Total North America ($/Mcf)
|
|||||||||||||||||||||
Price
|
4.87 | 4.49 | 4.66 | 4.88 | 5.49 | ||||||||||||||||
Production and mineral taxes
|
0.16 | 0.18 | 0.17 | 0.17 | 0.14 | ||||||||||||||||
Transportation and selling
|
0.39 | 0.46 | 0.40 | 0.35 | 0.33 | ||||||||||||||||
Operating
|
0.43 | 0.41 | 0.46 | 0.43 | 0.42 | ||||||||||||||||
Netback
|
3.89 | 3.44 | 3.63 | 3.93 | 4.60 | ||||||||||||||||
Natural Gas Liquids Canada ($/bbl)
|
|||||||||||||||||||||
Price
|
24.26 | 25.13 | 23.52 | 21.02 | 27.31 | ||||||||||||||||
Production and mineral taxes
|
| | | | | ||||||||||||||||
Transportation and selling
|
0.17 | 0.13 | 0.58 | | | ||||||||||||||||
Netback
|
24.09 | 25.00 | 22.94 | 21.02 | 27.31 | ||||||||||||||||
Natural Gas Liquids United States ($/bbl)
|
|||||||||||||||||||||
Price
|
26.97 | 26.68 | 25.50 | 24.64 | 32.18 | ||||||||||||||||
Production and mineral taxes
|
2.03 | 2.69 | 2.64 | 1.21 | 1.55 | ||||||||||||||||
Transportation and selling
|
| | | | | ||||||||||||||||
Netback
|
24.94 | 23.99 | 22.86 | 23.43 | 30.63 | ||||||||||||||||
Natural Gas Liquids Total North America ($/bbl)
|
|||||||||||||||||||||
Price
|
25.33 | 25.77 | 24.33 | 22.50 | 28.98 | ||||||||||||||||
Production and mineral taxes
|
0.80 | 1.12 | 1.08 | 0.50 | 0.53 | ||||||||||||||||
Transportation and selling
|
0.10 | 0.08 | 0.35 | | | ||||||||||||||||
Netback
|
24.43 | 24.57 | 22.90 | 22.00 | 28.45 | ||||||||||||||||
Crude Oil Light and Medium North America
($/bbl)
|
|||||||||||||||||||||
Price
|
26.61 | 25.53 | 24.31 | 27.43 | 29.34 | ||||||||||||||||
Production and mineral taxes
|
0.29 | 0.73 | (1.35 | ) | 0.71 | 1.08 | |||||||||||||||
Transportation and selling
|
1.42 | 1.33 | 0.71 | 1.73 | 1.95 | ||||||||||||||||
Operating
|
6.00 | 6.28 | 5.93 | 6.07 | 5.68 | ||||||||||||||||
Netback
|
18.90 | 17.19 | 19.02 | 18.92 | 20.63 | ||||||||||||||||
Crude Oil Heavy North America ($/bbl)
|
|||||||||||||||||||||
Price
|
19.61 | 18.43 | 17.93 | 20.07 | 22.62 | ||||||||||||||||
Production and mineral taxes
|
(0.03 | ) | 0.09 | (0.49 | ) | 0.34 | (0.02 | ) | |||||||||||||
Transportation and selling
|
1.24 | 1.54 | 0.58 | 1.37 | 1.56 | ||||||||||||||||
Operating
|
5.67 | 4.95 | 5.93 | 6.18 | 5.70 | ||||||||||||||||
Netback
|
12.73 | 11.85 | 11.91 | 12.18 | 15.38 | ||||||||||||||||
34
Per-Unit Results 2003 | |||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||
Crude Oil Total North America ($/bbl)
|
|||||||||||||||||||||
Price
|
22.29 | 21.08 | 20.26 | 22.95 | 25.34 | ||||||||||||||||
Production and mineral taxes
|
0.09 | 0.33 | (0.80 | ) | 0.49 | 0.43 | |||||||||||||||
Transportation and selling
|
1.31 | 1.46 | 0.63 | 1.51 | 1.72 | ||||||||||||||||
Operating
|
5.80 | 5.45 | 5.93 | 6.13 | 5.70 | ||||||||||||||||
Netback
|
15.09 | 13.84 | 14.50 | 14.82 | 17.49 | ||||||||||||||||
Total Liquids Canada ($/bbl)
|
|||||||||||||||||||||
Price
|
22.47 | 21.41 | 20.54 | 22.76 | 25.55 | ||||||||||||||||
Production and mineral taxes
|
0.08 | 0.30 | (0.73 | ) | 0.44 | 0.38 | |||||||||||||||
Transportation and selling
|
1.21 | 1.36 | 0.62 | 1.36 | 1.54 | ||||||||||||||||
Operating
|
5.27 | 5.01 | 5.43 | 5.53 | 5.11 | ||||||||||||||||
Netback
|
15.91 | 14.74 | 15.22 | 15.43 | 18.52 | ||||||||||||||||
Total Liquids North America ($/bbl)
|
|||||||||||||||||||||
Price
|
22.72 | 21.69 | 20.81 | 22.88 | 25.88 | ||||||||||||||||
Production and mineral taxes
|
0.19 | 0.43 | (0.55 | ) | 0.49 | 0.44 | |||||||||||||||
Transportation and selling
|
1.14 | 1.28 | 0.59 | 1.28 | 1.46 | ||||||||||||||||
Operating
|
4.97 | 4.74 | 5.13 | 5.18 | 4.85 | ||||||||||||||||
Netback
|
16.42 | 15.24 | 15.64 | 15.93 | 19.13 | ||||||||||||||||
Total North America ($/Mcfe)
|
|||||||||||||||||||||
Price
|
4.57 | 4.24 | 4.31 | 4.58 | 5.17 | ||||||||||||||||
Production and mineral taxes
|
0.13 | 0.15 | 0.10 | 0.14 | 0.12 | ||||||||||||||||
Transportation and selling
|
0.33 | 0.39 | 0.31 | 0.31 | 0.31 | ||||||||||||||||
Operating
|
0.54 | 0.52 | 0.58 | 0.55 | 0.53 | ||||||||||||||||
Netback
|
3.57 | 3.18 | 3.32 | 3.58 | 4.21 | ||||||||||||||||
Discontinued Operations:
|
|||||||||||||||||||||
Crude Oil Ecuador ($/bbl)
|
|||||||||||||||||||||
Price
|
24.21 | 23.57 | 22.13 | 22.31 | 30.86 | ||||||||||||||||
Production and mineral taxes
|
1.47 | 1.06 | 0.45 | 1.11 | 4.27 | ||||||||||||||||
Transportation and selling
|
2.56 | 2.81 | 2.36 | 2.41 | 2.35 | ||||||||||||||||
Operating
|
4.84 | 4.62 | 4.33 | 5.63 | 5.09 | ||||||||||||||||
Netback
|
15.34 | 15.08 | 14.99 | 13.16 | 19.15 | ||||||||||||||||
Crude Oil United Kingdom ($/bbl)
|
|||||||||||||||||||||
Price
|
28.11 | 27.05 | 27.92 | 27.17 | 30.61 | ||||||||||||||||
Production and mineral taxes
|
| | | | | ||||||||||||||||
Transportation and selling
|
1.97 | 1.70 | 1.98 | 1.86 | 2.45 | ||||||||||||||||
Operating
|
5.09 | 6.23 | 6.55 | 4.69 | 2.92 | ||||||||||||||||
Netback
|
21.05 | 19.12 | 19.39 | 20.62 | 25.24 | ||||||||||||||||
35
Per-Unit Results 2002 | |||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||
Produced Gas Canada ($/Mcf)
|
|||||||||||||||||||||
Price(1)
|
2.86 | 3.60 | 2.29 | 2.93 | 2.25 | ||||||||||||||||
Production and mineral taxes
|
0.08 | 0.07 | 0.04 | 0.10 | 0.14 | ||||||||||||||||
Transportation and selling
|
0.24 | 0.30 | 0.21 | 0.21 | 0.22 | ||||||||||||||||
Operating
|
0.41 | 0.44 | 0.42 | 0.40 | 0.31 | ||||||||||||||||
Netback
|
2.13 | 2.79 | 1.62 | 2.22 | 1.58 | ||||||||||||||||
Produced Gas United States ($/Mcf)
|
|||||||||||||||||||||
Price(1)
|
2.96 | 3.48 | 2.78 | 2.51 | 2.36 | ||||||||||||||||
Production and mineral taxes
|
0.27 | 0.34 | 0.22 | 0.23 | 0.29 | ||||||||||||||||
Transportation and selling
|
0.47 | 0.46 | 0.76 | 0.23 | | ||||||||||||||||
Operating
|
0.28 | 0.23 | 0.28 | 0.31 | 0.60 | ||||||||||||||||
Netback
|
1.94 | 2.45 | 1.52 | 1.74 | 1.47 | ||||||||||||||||
Produced Gas Total North America ($/Mcf)
|
|||||||||||||||||||||
Price(1)
|
2.87 | 3.58 | 2.37 | 2.86 | 2.26 | ||||||||||||||||
Production and mineral taxes
|
0.11 | 0.12 | 0.08 | 0.12 | 0.15 | ||||||||||||||||
Transportation and selling
|
0.28 | 0.33 | 0.31 | 0.22 | 0.21 | ||||||||||||||||
Operating
|
0.39 | 0.40 | 0.39 | 0.39 | 0.32 | ||||||||||||||||
Netback
|
2.09 | 2.73 | 1.59 | 2.13 | 1.58 | ||||||||||||||||
Natural Gas Liquids Canada ($/bbl)
|
|||||||||||||||||||||
Price
|
17.55 | 21.75 | 17.61 | 17.41 | 11.56 | ||||||||||||||||
Production and mineral taxes
|
| | | | | ||||||||||||||||
Transportation and selling
|
| | | | | ||||||||||||||||
Netback
|
17.55 | 21.75 | 17.61 | 17.41 | 11.56 | ||||||||||||||||
Natural Gas Liquids United States ($/bbl)
|
|||||||||||||||||||||
Price
|
23.75 | 25.14 | 25.64 | 23.57 | 16.31 | ||||||||||||||||
Production and mineral taxes
|
1.02 | 0.94 | 1.32 | 1.37 | | ||||||||||||||||
Transportation and selling
|
| | | | | ||||||||||||||||
Netback
|
22.73 | 24.20 | 24.32 | 22.20 | 16.31 | ||||||||||||||||
Natural Gas Liquids Total North America ($/bbl)
|
|||||||||||||||||||||
Price
|
19.52 | 23.06 | 19.99 | 19.32 | 12.64 | ||||||||||||||||
Production and mineral taxes
|
0.32 | 0.36 | 0.39 | 0.42 | | ||||||||||||||||
Transportation and selling
|
| | | | | ||||||||||||||||
Netback
|
19.20 | 22.70 | 19.60 | 18.90 | 12.64 | ||||||||||||||||
Crude Oil Light and Medium North America
($/bbl)
|
|||||||||||||||||||||
Price
|
22.31 | 24.39 | 24.09 | 23.37 | 17.60 | ||||||||||||||||
Production and mineral taxes
|
0.65 | 0.48 | 0.51 | 0.14 | 1.44 | ||||||||||||||||
Transportation and selling
|
0.94 | 1.22 | 1.04 | 0.62 | 0.87 | ||||||||||||||||
Operating
|
4.80 | 5.15 | 4.72 | 5.29 | 4.08 | ||||||||||||||||
Netback
|
15.92 | 17.54 | 17.82 | 17.32 | 11.21 | ||||||||||||||||
(1) | Excludes the effect of $108 million increase to consolidated revenues relating to the mark-to-market value of the AEC fixed price forward natural gas contracts recorded as part of the purchase price allocation. |
36
Per-Unit Results 2002 | |||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | |||||||||||||||||
Crude Oil Heavy North America ($/bbl)
|
|||||||||||||||||||||
Price
|
17.88 | 17.38 | 19.67 | 17.76 | 13.62 | ||||||||||||||||
Production and mineral taxes
|
0.22 | 0.54 | 0.03 | 0.04 | 0.32 | ||||||||||||||||
Transportation and selling
|
0.71 | 0.93 | 0.81 | 0.48 | 0.21 | ||||||||||||||||
Operating
|
4.58 | 4.12 | 4.96 | 4.39 | 5.73 | ||||||||||||||||
Netback
|
12.37 | 11.79 | 13.87 | 12.85 | 7.36 | ||||||||||||||||
Crude Oil Total North America ($/bbl)
|
|||||||||||||||||||||
Price
|
20.08 | 20.31 | 21.67 | 20.37 | 16.64 | ||||||||||||||||
Production and mineral taxes
|
0.43 | 0.51 | 0.25 | 0.08 | 1.17 | ||||||||||||||||
Transportation and selling
|
0.82 | 1.05 | 0.92 | 0.55 | 0.71 | ||||||||||||||||
Operating
|
4.69 | 4.55 | 4.85 | 4.81 | 4.48 | ||||||||||||||||
Netback
|
14.14 | 14.20 | 15.65 | 14.93 | 10.28 | ||||||||||||||||
Total Liquids Canada ($/bbl)
|
|||||||||||||||||||||
Price
|
19.82 | 20.46 | 21.27 | 20.07 | 16.01 | ||||||||||||||||
Production and mineral taxes
|
0.39 | 0.46 | 0.22 | 0.08 | 1.03 | ||||||||||||||||
Transportation and selling
|
0.73 | 0.94 | 0.83 | 0.49 | 0.63 | ||||||||||||||||
Operating
|
4.19 | 4.06 | 4.38 | 4.32 | 3.93 | ||||||||||||||||
Netback
|
14.51 | 15.00 | 15.84 | 15.18 | 10.42 | ||||||||||||||||
Total Liquids North America ($/bbl)
|
|||||||||||||||||||||
Price
|
20.00 | 20.76 | 21.44 | 20.22 | 16.03 | ||||||||||||||||
Production and mineral taxes
|
0.42 | 0.49 | 0.27 | 0.13 | 0.99 | ||||||||||||||||
Transportation and selling
|
0.70 | 0.88 | 0.79 | 0.47 | 0.60 | ||||||||||||||||
Operating
|
4.00 | 3.80 | 4.20 | 4.14 | 3.79 | ||||||||||||||||
Netback
|
14.88 | 15.59 | 16.18 | 15.48 | 10.65 | ||||||||||||||||
Total North America ($/Mcfe)
|
|||||||||||||||||||||
Price
|
3.01 | 3.55 | 2.71 | 3.01 | 2.41 | ||||||||||||||||
Production and mineral taxes
|
0.10 | 0.11 | 0.07 | 0.10 | 0.15 | ||||||||||||||||
Transportation and selling
|
0.23 | 0.28 | 0.26 | 0.18 | 0.17 | ||||||||||||||||
Operating
|
0.47 | 0.46 | 0.48 | 0.47 | 0.43 | ||||||||||||||||
Netback
|
2.21 | 2.70 | 1.90 | 2.26 | 1.66 | ||||||||||||||||
Discontinued Operations:
|
|||||||||||||||||||||
Crude Oil Ecuador ($/bbl)
|
|||||||||||||||||||||
Price
|
22.57 | 24.02 | 22.82 | 21.11 | | ||||||||||||||||
Production and mineral taxes
|
1.24 | 1.57 | 1.49 | 0.72 | | ||||||||||||||||
Transportation and selling
|
2.00 | 1.99 | 2.47 | 1.56 | | ||||||||||||||||
Operating
|
4.86 | 5.35 | 4.12 | 5.13 | | ||||||||||||||||
Netback
|
14.47 | 15.11 | 14.74 | 13.70 | | ||||||||||||||||
Crude Oil United Kingdom ($/bbl)
|
|||||||||||||||||||||
Price
|
24.76 | 25.73 | 27.07 | 25.92 | 21.18 | ||||||||||||||||
Production and mineral taxes
|
| | | | | ||||||||||||||||
Transportation and selling
|
1.69 | 1.53 | 1.92 | 1.62 | 1.65 | ||||||||||||||||
Operating
|
3.28 | 7.07 | 3.65 | 2.01 | 1.78 | ||||||||||||||||
Netback
|
19.79 | 17.13 | 21.50 | 22.29 | 17.75 | ||||||||||||||||
37
2004 | ||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
Continuing Operations:
|
||||||||||||||||||||
Natural Gas ($/Mcf)
|
(0.22 | ) | (0.37 | ) | (0.15 | ) | (0.25 | ) | (0.08 | ) | ||||||||||
Liquids ($/bbl)
|
(7.08 | ) | (8.24 | ) | (8.75 | ) | (6.53 | ) | (4.79 | ) | ||||||||||
Total ($/Mcfe)
|
(0.46 | ) | (0.61 | ) | (0.48 | ) | (0.47 | ) | (0.27 | ) | ||||||||||
Discontinued Operations:
|
||||||||||||||||||||
Ecuador Oil ($/bbl)
|
(9.66 | ) | (14.60 | ) | (10.31 | ) | (7.13 | ) | (6.69 | ) | ||||||||||
United Kingdom Oil
($/bbl) (1)
|
(7.62 | ) | (6.34 | ) | (11.75 | ) | (7.01 | ) | (5.72 | ) | ||||||||||
2003 | ||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
Continuing Operations:
|
||||||||||||||||||||
Natural Gas ($/Mcf)
|
(0.10 | ) | 0.16 | (0.06 | ) | (0.25 | ) | (0.25 | ) | |||||||||||
Liquids ($/bbl)
|
(3.41 | ) | (3.29 | ) | (2.76 | ) | (2.08 | ) | (5.64 | ) | ||||||||||
Total ($/Mcfe)
|
(0.23 | ) | (0.04 | ) | (0.18 | ) | (0.28 | ) | (0.44 | ) | ||||||||||
Discontinued Operations:
|
||||||||||||||||||||
Ecuador Oil ($/bbl)
|
| | | | | |||||||||||||||
United Kingdom Oil ($/bbl)
|
| | | | | |||||||||||||||
2002 | ||||||||||||||||||||
Year | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||
Continuing Operations:
|
||||||||||||||||||||
Natural Gas ($/Mcf)
|
0.09 | 0.02 | 0.26 | (0.06 | ) | 0.20 | ||||||||||||||
Liquids ($/bbl)
|
(0.64 | ) | (0.73 | ) | (0.56 | ) | (0.72 | ) | (0.53 | ) | ||||||||||
Total ($/Mcfe)
|
0.03 | (0.02 | ) | 0.16 | (0.08 | ) | 0.10 | |||||||||||||
Discontinued Operations:
|
||||||||||||||||||||
Ecuador Oil ($/bbl)
|
(0.01 | ) | | | (0.03 | ) | | |||||||||||||
United Kingdom Oil ($/bbl)
|
(0.06 | ) | | | | (0.19 | ) | |||||||||||||
(1) | Excludes hedges unwound as a result of the U.K. disposition. |
38
Dry | Total Working | ||||||||||||||||||||||||||||||||||||||||||||
Gas | Oil | & Abandoned | Interest | Royalty | Total | ||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Gross | Net | |||||||||||||||||||||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||||||||||||||||||||||||||
2004:
|
|||||||||||||||||||||||||||||||||||||||||||||
Canada
|
566 | 534 | 48 | 47 | 9 | 6 | 623 | 587 | 51 | 674 | 587 | ||||||||||||||||||||||||||||||||||
United States
|
19 | 16 | 2 | | | | 21 | 16 | | 21 | 16 | ||||||||||||||||||||||||||||||||||
Other
|
| | 3 | 2 | 5 | 2 | 8 | 4 | | 8 | 4 | ||||||||||||||||||||||||||||||||||
Total
|
585 | 550 | 53 | 49 | 14 | 8 | 652 | 607 | 51 | 703 | 607 | ||||||||||||||||||||||||||||||||||
2003:
|
|||||||||||||||||||||||||||||||||||||||||||||
Canada
|
532 | 511 | 51 | 31 | 35 | 28 | 618 | 570 | 153 | 771 | 570 | ||||||||||||||||||||||||||||||||||
United States
|
40 | 35 | 7 | 2 | 4 | 2 | 51 | 39 | | 51 | 39 | ||||||||||||||||||||||||||||||||||
Other
|
1 | | | | 3 | 1 | 4 | 1 | | 4 | 1 | ||||||||||||||||||||||||||||||||||
Total
|
573 | 546 | 58 | 33 | 42 | 31 | 673 | 610 | 153 | 826 | 610 | ||||||||||||||||||||||||||||||||||
2002:
|
|||||||||||||||||||||||||||||||||||||||||||||
Canada
|
423 | 382 | 84 | 72 | 44 | 37 | 551 | 491 | 190 | 741 | 491 | ||||||||||||||||||||||||||||||||||
United States
|
12 | 12 | 2 | 1 | 3 | 1 | 17 | 14 | | 17 | 14 | ||||||||||||||||||||||||||||||||||
Other
|
| | | | 4 | 2 | 4 | 2 | | 4 | 2 | ||||||||||||||||||||||||||||||||||
Total
|
435 | 394 | 86 | 73 | 51 | 40 | 572 | 507 | 190 | 762 | 507 | ||||||||||||||||||||||||||||||||||
Discontinued Operations:
|
|||||||||||||||||||||||||||||||||||||||||||||
Ecuador 2004
|
| | 6 | 3 | | | 6 | 3 | | 6 | 3 | ||||||||||||||||||||||||||||||||||
Ecuador 2003
|
| | 3 | 2 | | | 3 | 2 | | 3 | 2 | ||||||||||||||||||||||||||||||||||
Ecuador 2002
|
| | 7 | 5 | | | 7 | 5 | | 7 | 5 | ||||||||||||||||||||||||||||||||||
United Kingdom 2004
|
| | 1 | | 4 | 2 | 5 | 2 | | 5 | 2 | ||||||||||||||||||||||||||||||||||
United Kingdom 2003
|
| | 2 | 1 | 5 | 3 | 7 | 4 | | 7 | 4 | ||||||||||||||||||||||||||||||||||
United Kingdom 2002
|
| | 7 | 3 | 2 | 1 | 9 | 4 | | 9 | 4 | ||||||||||||||||||||||||||||||||||
39
Dry | Total Working | ||||||||||||||||||||||||||||||||||||||||||||
Gas | Oil | & Abandoned | Interest | Royalty | Total | ||||||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Gross | Net | |||||||||||||||||||||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||||||||||||||||||||||||||
2004:
|
|||||||||||||||||||||||||||||||||||||||||||||
Canada
|
3,632 | 3,419 | 386 | 364 | 16 | 15 | 4,034 | 3,798 | 1,105 | 5,139 | 3,798 | ||||||||||||||||||||||||||||||||||
United States
|
600 | 515 | 1 | | 3 | 3 | 604 | 518 | | 604 | 518 | ||||||||||||||||||||||||||||||||||
Total
|
4,232 | 3,934 | 387 | 364 | 19 | 18 | 4,638 | 4,316 | 1,105 | 5,743 | 4,316 | ||||||||||||||||||||||||||||||||||
2003:
|
|||||||||||||||||||||||||||||||||||||||||||||
Canada
|
3,964 | 3,901 | 756 | 650 | 24 | 18 | 4,744 | 4,569 | 1,347 | 6,091 | 4,569 | ||||||||||||||||||||||||||||||||||
United States
|
426 | 401 | | | 1 | 1 | 427 | 402 | | 427 | 402 | ||||||||||||||||||||||||||||||||||
Total
|
4,390 | 4,302 | 756 | 650 | 25 | 19 | 5,171 | 4,971 | 1,347 | 6,518 | 4,971 | ||||||||||||||||||||||||||||||||||
2002:
|
|||||||||||||||||||||||||||||||||||||||||||||
Canada
|
1,397 | 1,340 | 433 | 349 | 30 | 23 | 1,860 | 1,712 | 690 | 2,550 | 1,712 | ||||||||||||||||||||||||||||||||||
United States
|
287 | 250 | 3 | 3 | 1 | 1 | 291 | 254 | | 291 | 254 | ||||||||||||||||||||||||||||||||||
Total
|
1,684 | 1,590 | 436 | 352 | 31 | 24 | 2,151 | 1,966 | 690 | 2,841 | 1,966 | ||||||||||||||||||||||||||||||||||
Discontinued Operations:
|
|||||||||||||||||||||||||||||||||||||||||||||
Ecuador 2004
|
| | 43 | 25 | 1 | 1 | 44 | 26 | | 44 | 26 | ||||||||||||||||||||||||||||||||||
Ecuador 2003
|
| | 53 | 39 | 6 | 6 | 59 | 45 | | 59 | 45 | ||||||||||||||||||||||||||||||||||
Ecuador 2002
|
| | 44 | 37 | 5 | 4 | 49 | 41 | | 49 | 41 | ||||||||||||||||||||||||||||||||||
United Kingdom 2004
|
| | 3 | 1 | | | 3 | 1 | | 3 | 1 | ||||||||||||||||||||||||||||||||||
United Kingdom 2003
|
| | 3 | | | | 3 | | | 3 | | ||||||||||||||||||||||||||||||||||
United Kingdom 2002
|
| | 2 | | | | 2 | | | 2 | | ||||||||||||||||||||||||||||||||||
(1) | Gross wells are the total number of wells in which EnCana has an interest. |
(2) | Net wells are the number of wells obtained by aggregating EnCanas working interest in each of its gross wells. |
(3) | At December 31, 2004, EnCana was in the process of drilling 33 gross wells (32 net wells) in Canada, 50 gross wells (45 net wells) in the United States, 4 gross wells (2 net wells) in Ecuador and no wells in other countries. |
40
Gas | Oil | Total | |||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||
Continuing Operations:
|
|||||||||||||||||||||||||
Alberta
|
29,790 | 27,943 | 4,700 | 4,151 | 34,490 | 32,094 | |||||||||||||||||||
British Columbia
|
1,329 | 1,196 | 16 | 10 | 1,345 | 1,206 | |||||||||||||||||||
Saskatchewan
|
336 | 332 | 1,177 | 515 | 1,513 | 847 | |||||||||||||||||||
Manitoba
|
| | 3 | 3 | 3 | 3 | |||||||||||||||||||
Total Canada
|
31,455 | 29,471 | 5,896 | 4,679 | 37,351 | 34,150 | |||||||||||||||||||
Colorado
|
3,902 | 3,155 | | | 3,902 | 3,155 | |||||||||||||||||||
Texas
|
1,179 | 762 | 30 | 12 | 1,209 | 774 | |||||||||||||||||||
Wyoming
|
1,493 | 874 | | | 1,493 | 874 | |||||||||||||||||||
Montana
|
42 | 37 | | | 42 | 37 | |||||||||||||||||||
Utah
|
33 | 32 | | | 33 | 32 | |||||||||||||||||||
Oklahoma
|
47 | 12 | | | 47 | 12 | |||||||||||||||||||
Louisiana
|
4 | 2 | | | 4 | 2 | |||||||||||||||||||
Gulf of Mexico
|
| | 6 | 1 | 6 | 1 | |||||||||||||||||||
Total United States
|
6,700 | 4,874 | 36 | 13 | 6,736 | 4,887 | |||||||||||||||||||
Total
|
38,155 | 34,345 | 5,932 | 4,692 | 44,087 | 39,037 | |||||||||||||||||||
Discontinued Operations:
|
|||||||||||||||||||||||||
Ecuador
|
| | 289 | 227 | 289 | 227 | |||||||||||||||||||
(1) | EnCana has varying royalty interests in 8,396 crude oil wells and 12,970 natural gas wells which are producing or capable of producing. |
(2) | Includes wells containing multiple completions as follows: 26,879 gross natural gas wells (24,441 net wells) and 1,681 gross crude oil wells (1,393 net wells). |
41
Developed | Undeveloped | Total | |||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||
(thousands of acres) | |||||||||||||||||||||||||||||
Continuing Operations: | |||||||||||||||||||||||||||||
Canada
|
|||||||||||||||||||||||||||||
Alberta
|
Fee | 4,319 | 4,319 | 2,835 | 2,835 | 7,154 | 7,154 | ||||||||||||||||||||||
Crown | 3,709 | 2,989 | 6,643 | 5,578 | 10,352 | 8,567 | |||||||||||||||||||||||
Freehold | 185 | 101 | 245 | 192 | 430 | 293 | |||||||||||||||||||||||
8,213 | 7,409 | 9,723 | 8,605 | 17,936 | 16,014 | ||||||||||||||||||||||||
British Columbia
|
Crown | 697 | 579 | 4,174 | 3,601 | 4,871 | 4,180 | ||||||||||||||||||||||
Freehold | | | 7 | 7 | 7 | 7 | |||||||||||||||||||||||
697 | 579 | 4,181 | 3,608 | 4,878 | 4,187 | ||||||||||||||||||||||||
Saskatchewan
|
Fee | 57 | 57 | 461 | 461 | 518 | 518 | ||||||||||||||||||||||
Crown | 115 | 96 | 1,064 | 1,049 | 1,179 | 1,145 | |||||||||||||||||||||||
Freehold | 13 | 9 | 104 | 97 | 117 | 106 | |||||||||||||||||||||||
185 | 162 | 1,629 | 1,607 | 1,814 | 1,769 | ||||||||||||||||||||||||
Manitoba
|
Fee | 3 | 3 | 265 | 265 | 268 | 268 | ||||||||||||||||||||||
Freehold | | | 23 | 23 | 23 | 23 | |||||||||||||||||||||||
3 | 3 | 288 | 288 | 291 | 291 | ||||||||||||||||||||||||
Newfoundland & Labrador
|
Crown | | | 4,027 | 2,514 | 4,027 | 2,514 | ||||||||||||||||||||||
Nova Scotia
|
Crown | | | 1,834 | 1,043 | 1,834 | 1,043 | ||||||||||||||||||||||
Northwest Territories
|
Crown | | | 633 | 234 | 633 | 234 | ||||||||||||||||||||||
Nunavut
|
Crown | | | 817 | 26 | 817 | 26 | ||||||||||||||||||||||
Beaufort
|
Crown | | | 126 | 4 | 126 | 4 | ||||||||||||||||||||||
Total Canada
|
9,098 | 8,153 | 23,258 | 17,929 | 32,356 | 26,082 | |||||||||||||||||||||||
42
Developed | Undeveloped | Total | |||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||
(thousands of acres) | |||||||||||||||||||||||||||||
United States
|
|||||||||||||||||||||||||||||
Colorado
|
Federal/ State Lands | 208 | 180 | 821 | 745 | 1,029 | 925 | ||||||||||||||||||||||
Freehold | 112 | 102 | 212 | 191 | 324 | 293 | |||||||||||||||||||||||
Fee | 3 | 3 | 60 | 60 | 63 | 63 | |||||||||||||||||||||||
323 | 285 | 1,093 | 996 | 1,416 | 1,281 | ||||||||||||||||||||||||
Washington
|
Federal/ State Lands | | | 459 | 456 | 459 | 456 | ||||||||||||||||||||||
Freehold | | | 199 | 199 | 199 | 199 | |||||||||||||||||||||||
Federal Acquired Lease | | | 219 | 213 | 219 | 213 | |||||||||||||||||||||||
| | 877 | 868 | 877 | 868 | ||||||||||||||||||||||||
Texas
|
Federal/ State Lands | 8 | 3 | 205 | 204 | 213 | 207 | ||||||||||||||||||||||
Freehold | 161 | 97 | 431 | 395 | 592 | 492 | |||||||||||||||||||||||
169 | 100 | 636 | 599 | 805 | 699 | ||||||||||||||||||||||||
Wyoming
|
Federal/ State Lands | 148 | 73 | 729 | 490 | 877 | 563 | ||||||||||||||||||||||
Freehold | 26 | 18 | 81 | 46 | 107 | 64 | |||||||||||||||||||||||
Bureau of Indian Affairs | 11 | 10 | 5 | 4 | 16 | 14 | |||||||||||||||||||||||
185 | 101 | 815 | 540 | 1,000 | 641 | ||||||||||||||||||||||||
Gulf of Mexico
|
Federal/ State Lands | | | 1,371 | 557 | 1,371 | 557 | ||||||||||||||||||||||
Alaska
|
Federal/ State Lands | | | 1,337 | 531 | 1,337 | 531 | ||||||||||||||||||||||
Other
|
Federal Lands | 11 | 10 | 374 | 236 | 385 | 246 | ||||||||||||||||||||||
Freehold | 19 | 10 | 22 | 13 | 41 | 23 | |||||||||||||||||||||||
Fee | 1 | 1 | | | 1 | 1 | |||||||||||||||||||||||
31 | 21 | 396 | 249 | 427 | 270 | ||||||||||||||||||||||||
Total United States
|
708 | 507 | 6,525 | 4,340 | 7,233 | 4,847 | |||||||||||||||||||||||
Chad
|
| | 108,536 | 54,268 | 108,536 | 54,268 | |||||||||||||||||||||||
Oman
|
| | 9,606 | 9,606 | 9,606 | 9,606 | |||||||||||||||||||||||
Qatar
|
| | 2,161 | 2,161 | 2,161 | 2,161 | |||||||||||||||||||||||
Greenland
|
| | 985 | 862 | 985 | 862 | |||||||||||||||||||||||
Yemen
|
| | 1,879 | 691 | 1,879 | 691 | |||||||||||||||||||||||
Brazil
|
| | 1,444 | 554 | 1,444 | 554 | |||||||||||||||||||||||
Australia
|
| | 960 | 320 | 960 | 320 | |||||||||||||||||||||||
Bahrain
|
| | 97 | 48 | 97 | 48 | |||||||||||||||||||||||
Azerbaijan
|
| | 346 | 17 | 346 | 17 | |||||||||||||||||||||||
Total International
|
| | 126,014 | 68,527 | 126,014 | 68,527 | |||||||||||||||||||||||
Total
|
9,806 | 8,660 | 155,797 | 90,796 | 165,603 | 99,456 | |||||||||||||||||||||||
Discontinued Operations: | |||||||||||||||||||||||||||||
Ecuador
|
160 | 99 | 1,243 | 795 | 1,403 | 894 | |||||||||||||||||||||||
(1) | This table excludes approximately 4.3 million gross acres under lease or sublease, reserving to EnCana royalties or other interests. |
(2) | Fee lands are those lands in which EnCana has a fee simple interest in the minerals rights and has either: (i) not leased out all of the mineral zones; or (ii) retained a working interest. In prior years, fee lands in which any zones were leased out were excluded as fee lands except with respect to lands in which EnCana retained a working interest. The current fee lands acreage summary now includes all fee titles owned by EnCana that have one or more zones that remain unleased or available for development. |
(3) | Crown / Federal / State lands are those owned by the federal, provincial, or state government or the First Nations, in which EnCana has purchased a working interest lease. |
(4) | Freehold lands are owned by individuals (other than a Government or EnCana), in which EnCana holds a working interest lease. |
(5) | Gross acres are the total area of properties in which EnCana has an interest. |
(6) | Net acres are the sum of EnCanas fractional interest in gross acres. |
43
2004 | 2003 | ||||||||||
($ millions) | |||||||||||
Upstream
|
|||||||||||
Canada
|
3,015 | 2,937 | |||||||||
United States
|
1,249 | 830 | |||||||||
International New Ventures Exploration
|
79 | 78 | |||||||||
4,343 | 3,845 | ||||||||||
Midstream & Marketing
|
64 | 223 | |||||||||
Corporate
|
46 | 57 | |||||||||
Core Capital from Continuing Operations
|
4,453 | 4,125 | |||||||||
Acquisitions
|
|||||||||||
Upstream
|
|||||||||||
Property
|
|||||||||||
Canada
|
64 | 261 | |||||||||
United States
|
300 | 138 | |||||||||
Corporate
|
|||||||||||
Savannah
|
| 91 | |||||||||
Petrovera
|
253 | | |||||||||
Tom Brown,
Inc. (1)
|
2,335 | | |||||||||
Midstream & Marketing
|
|||||||||||
Other
|
34 | 53 | |||||||||
Corporate
|
| 50 | |||||||||
Dispositions
|
|||||||||||
Upstream
|
|||||||||||
Property
|
|||||||||||
Canada
|
(877 | ) | (108 | ) | |||||||
United States
|
(266 | ) | (178 | ) | |||||||
Other Countries
|
| (15 | ) | ||||||||
Corporate
|
|||||||||||
Petrovera
|
(540 | ) | | ||||||||
Midstream & Marketing
|
|||||||||||
Property
|
(1 | ) | | ||||||||
Corporate
|
|||||||||||
Alberta Ethane Gathering System Joint Venture
|
(108 | ) | | ||||||||
Kingston CoGen Partnership
|
(25 | ) | | ||||||||
Net Acquisition and Disposition Activity from Continuing
Operations
|
1,169 | 292 | |||||||||
Proceeds of Disposition of United Kingdom
|
(2,144 | ) | | ||||||||
Discontinued Operations
|
728 | (995 | ) | ||||||||
Total Discontinued Operations
|
(1,416 | ) | (995 | ) | |||||||
(1) | Net cash consideration excluding debt acquired of $406 million. |
44
45
Number of FTE Employees | ||||
As at December 31, 2004 | ||||
Upstream
|
3,176 | |||
Midstream & Marketing
|
306 | |||
Corporate
|
608 | |||
Total
|
4,090 | |||
46
Director | ||||||
Name and Municipality of Residence | Since(13) | Principal Occupation | ||||
Michael N.
Chernoff(2,6)
|
1999 | Corporate Director | ||||
West Vancouver, British Columbia, Canada
|
||||||
Ralph S.
Cunningham(2,3)
|
2003 | Corporate Director | ||||
Houston, Texas, United States
|
||||||
Patrick D.
Daniel(1,5)
|
2001 | President & Chief Executive Officer | ||||
Calgary, Alberta, Canada
|
Enbridge Inc. (Energy delivery) |
|||||
Ian W.
Delaney(3,4)
|
1999 | Executive Chairman | ||||
Toronto, Ontario, Canada
|
Sherritt International Corporation (Nickel/cobalt mining, oil and natural gas production, electricity generation and coal mining) |
|||||
William R.
Fatt(1,8)
|
1995 | Chief Executive Officer | ||||
Toronto, Ontario, Canada
|
Fairmont Hotels & Resorts Inc. (Hotels) |
|||||
Michael A.
Grandin(3,5,6,9)
|
1998 | Dean of the Haskayne School of Business | ||||
Calgary, Alberta, Canada
|
University of Calgary (Education) |
|||||
Barry W.
Harrison(1,4,10)
|
1996 | Corporate Director and independent businessman | ||||
Calgary, Alberta, Canada
|
||||||
Richard F.
Haskayne,
O.C., F.C.A.(3,4)
|
1992 | Chairman of the Board | ||||
Calgary, Alberta, Canada
|
TransCanada Corporation (Pipelines and energy services) |
|||||
Dale A.
Lucas(1,5)
|
1997 | Corporate Director | ||||
Calgary, Alberta, Canada
|
||||||
Ken F.
McCready(2,5,11)
|
1992 | President | ||||
Calgary, Alberta, Canada
|
K.F. McCready & Associates Ltd. (Sustainable energy development consulting company) |
|||||
Gwyn Morgan
|
1993 | President & Chief Executive Officer | ||||
Calgary, Alberta, Canada
|
EnCana Corporation | |||||
Valerie A. A.
Nielsen(2,6)
|
1990 | Corporate Director | ||||
Calgary, Alberta, Canada
|
||||||
David P.
OBrien(4,7,12)
|
1990 | Chairman | ||||
Calgary, Alberta, Canada
|
EnCana Corporation | |||||
Chairman Royal Bank of Canada |
||||||
Jane L.
Peverett(1)
|
2003 | Chief Financial Officer | ||||
West Vancouver, British Columbia, Canada
|
British Columbia Transmission Corporation (Electricity transmission) |
|||||
Dennis A.
Sharp(2,4)
|
1998 | Executive Chairman | ||||
Calgary, Alberta, Canada/
|
UTS Energy Corporation | |||||
Montreal, Quebec, Canada
|
(Oil and natural gas company) | |||||
James M. Stanford,
O.C.(1,3,6)
|
2001 | President | ||||
Calgary, Alberta, Canada
|
Stanford Resource Management Inc. (Investment management) |
|||||
47
(1) | Audit Committee. |
(2) | Corporate Responsibility, Environment, Health and Safety Committee. |
(3) | Human Resources and Compensation Committee. |
(4) | Nominating and Corporate Governance Committee. |
(5) | Pension Committee. |
(6) | Reserves Committee. |
(7) | Ex officio non-voting member of all other committees. As an ex officio non-voting member, Mr. OBrien attends as his schedule permits and may vote when necessary to achieve a quorum. |
(8) | Mr. Fatt was a director of Unitel Communications Inc. (Unitel) in 1995 when it made a filing pursuant to the Companies Creditors Arrangement Act (Canada). Unitel instituted a compromise with creditors on December 8, 1995 and Mr. Fatt resigned as a director in January 1996. |
(9) | Mr. Grandin was a director of Pegasus Gold Inc. in 1998 when that company filed voluntarily to reorganize under Chapter 11 of the Bankruptcy Code (United States). A liquidation plan for that company received court confirmation later that year. |
(10) | Mr. Harrison was a director of Gauntlet Energy Corporation in June 2003 when it filed for and was granted an order pursuant to the Companies Creditors Arrangement Act (Canada). A plan of arrangement for that company received court confirmation later that year. |
(11) | Mr. McCready was a director of Colonia Corporation when the company was placed into receivership in October 2000. The company came out of receivership in October 2001. Mr. McCready was a director, Chairman and Chief Executive Officer of Etho Power Corporation, a small private company, when it was assigned into bankruptcy on April 7, 2003. |
(12) | Mr. OBrien resigned as a director of Air Canada on November 26, 2003. On April 1, 2003, Air Canada obtained an order from the Ontario Superior Court of Justice providing creditor protection under the Companies Creditors Arrangement Act (Canada). Air Canada also made a concurrent petition under Section 304 of the U.S. Bankruptcy Code. On September 30, 2004, Air Canada announced that it had successfully completed its restructuring process and implemented its Plan of Arrangement. |
(13) | Denotes the year each individual became a director of AEC or PanCanadian, if prior to the Merger, or EnCana, if after the Merger. |
Name and Municipality of Residence | Office | |||||
Gwyn Morgan | President & Chief Executive Officer | |||||
Calgary, Alberta, Canada
|
||||||
Randall K. Eresman | Executive Vice-President & Chief Operating Officer | |||||
Calgary, Alberta, Canada
|
||||||
Roger J. Biemans | Executive Vice-President | |||||
Denver, Colorado, United States
|
||||||
Brian C. Ferguson | Executive Vice-President, Corporate Development | |||||
Calgary, Alberta, Canada
|
||||||
R. William Oliver | Executive Vice-President | |||||
Calgary, Alberta, Canada
|
||||||
Gerard J. Protti | Executive Vice-President, Corporate Relations | |||||
Calgary, Alberta, Canada
|
||||||
Drude Rimell | Executive Vice-President, Corporate Services | |||||
Calgary, Alberta, Canada
|
||||||
John D. Watson | Executive Vice-President & Chief Financial Officer | |||||
Calgary, Alberta, Canada
|
||||||
48
49
50
($ thousands) | 2004 | 2003 | ||||||
Audit
Fees(1)
|
3,177 | 1,977 | ||||||
Audit-Related
Fees(2)
|
166 | 127 | ||||||
Tax
Fees(3)
|
1,097 | 1,408 | ||||||
All Other
Fees(4)
|
24 | 26 | ||||||
Total
|
4,464 | 3,538 | ||||||
(1) | Audit fees consist of fees for the audit of the Corporations annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements. |
(2) | Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the Corporations financial statements and are not reported as Audit Fees. During fiscal 2004 and 2003, the services provided in this category included due diligence reviews in connection with acquisitions and dispositions, research of accounting and audit-related issues, review of reserves disclosure and the completion of audits required by contracts to which the Corporation is a party. |
(3) | Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2004 and 2003, the services provided in this category included assistance and advice in relation to the preparation of corporate income tax returns and expatriate tax services. |
(4) | During fiscal 2004, the services provided in this category included the payment of maintenance fees associated with a research tool that grants access to a comprehensive library of financial reporting and assurance literature and a working paper documentation package used by the Corporations internal audit group. During fiscal 2003, the services provided in this category included the review of EnCanas Corporate Responsibility Report and the payment of maintenance fees associated with a working paper documentation package used by the Corporations internal audit group. |
51
Standard & Poors | Moodys Investors | Dominion Bond Rating | ||||
Ratings Services (S&P) | Service (Moodys) | Service (DBRS) | ||||
Senior Unsecured/Long-Term Rating
|
A- | Baa2 | A (low) | |||
Commercial Paper/Short-Term Rating
|
A-1 (low) | P-2 | R-1 (low) | |||
Outlook
|
Negative | Stable | Stable | |||
52
Toronto Stock Exchange | New York Stock Exchange | |||||||||||||||||||||||||||||||
Share Price Trading Range | Share Price Trading Range | |||||||||||||||||||||||||||||||
Share | Share | |||||||||||||||||||||||||||||||
High | Low | Close | Volume | High | Low | Close | Volume | |||||||||||||||||||||||||
(C$ per share) | (millions) | ($ per share) | (millions) | |||||||||||||||||||||||||||||
2004
|
||||||||||||||||||||||||||||||||
January
|
56.00 | 51.00 | 51.58 | 36.4 | 43.43 | 39.00 | 39.10 | 9.2 | ||||||||||||||||||||||||
February
|
58.25 | 51.29 | 57.84 | 27.5 | 43.60 | 38.36 | 43.45 | 10.4 | ||||||||||||||||||||||||
March
|
59.27 | 54.22 | 56.69 | 35.5 | 44.25 | 40.62 | 43.12 | 9.9 | ||||||||||||||||||||||||
April
|
59.73 | 53.75 | 53.80 | 30.3 | 44.73 | 39.18 | 39.22 | 13.7 | ||||||||||||||||||||||||
May
|
57.70 | 52.99 | 54.55 | 29.2 | 42.05 | 38.05 | 39.35 | 12.5 | ||||||||||||||||||||||||
June
|
58.85 | 53.55 | 57.62 | 25.8 | 43.41 | 39.45 | 43.16 | 9.7 | ||||||||||||||||||||||||
July
|
60.60 | 56.55 | 58.90 | 26.3 | 45.75 | 42.83 | 44.32 | 10.7 | ||||||||||||||||||||||||
August
|
59.94 | 52.30 | 53.66 | 28.4 | 45.50 | 39.95 | 41.10 | 12.1 | ||||||||||||||||||||||||
September
|
59.46 | 53.40 | 58.35 | 26.7 | 46.92 | 41.09 | 46.30 | 10.6 | ||||||||||||||||||||||||
October
|
62.81 | 57.90 | 60.40 | 36.1 | 50.26 | 46.10 | 49.40 | 15.1 | ||||||||||||||||||||||||
November
|
68.20 | 59.61 | 67.80 | 40.5 | 57.43 | 48.85 | 57.03 | 19.8 | ||||||||||||||||||||||||
December
|
70.02 | 63.13 | 68.40 | 33.1 | 57.30 | 51.59 | 57.06 | 18.7 | ||||||||||||||||||||||||
53
Issuer | Principal Amount | Coupon | Issue Date | Maturity Date | Issue Price | |||||||||||||||
EnCana Holdings Finance
Corp.(1)
|
$1 billion | 5.80 | % | May 13, 2004 | May 1, 2014 | 99.614 | % | |||||||||||||
EnCana Corporation
|
$250 million | 4.60 | % | August 4, 2004 | August 15, 2009 | 99.838 | % | |||||||||||||
EnCana Corporation
|
$750 million | 6.50 | % | August 4, 2004 | August 15, 2034 | 99.123 | % | |||||||||||||
(1) | EnCana Holdings Finance Corp. (EHF) is an indirect, wholly owned subsidiary of EnCana Corporation. The notes issued by EHF are fully and unconditionally guaranteed by EnCana Corporation. |
54
| the Corporation is unable to produce oil or natural gas to fulfill delivery obligations; | |
| the Corporation is required to pay royalties based on market or reference prices that are higher than hedged prices; or | |
| counterparties to the Corporations hedging agreements are unable to fulfill their obligations under the hedging agreements. |
55
56
| timing and amount of capital expenditures; | |
| the operators expertise and financial resources; | |
| approval of other participants; | |
| selection of technology; and | |
| risk management practices. |
| the availability of processing capacity; | |
| the availability and proximity of pipeline capacity; | |
| the availability of equipment; | |
| the ability to access lands; | |
| inclement weather; | |
| unexpected cost increases; | |
| accidents; | |
| the availability of skilled labour; and | |
| regulatory matters. |
57
58
In Canada:
|
In the United States: | |
CIBC Mellon Trust Company
|
Mellon Investor Services LLC | |
320 Bay Street
|
44 Wall Street, 6th Floor | |
P.O. Box 1
|
New York, New York | |
Toronto, ON M5H 4A6
|
10005 | |
Tel: 1-800-387-0825
|
Tel: 1-800-387-0825 | |
Web site: www.cibcmellon.com
|
Web site: www.cibcmellon.com |
59
1. | We have evaluated the Corporations reserves data as at December 31, 2004. The reserves data consist of the following: |
(i) | estimated proved oil and gas reserve quantities as at December 31, 2004 using constant prices and costs; and | |
(ii) | the related estimates of discounted future net cash flows under the standardized measure calculation for proved oil and gas reserve quantities. |
2. | The reserves data are the responsibility of the Corporations management. Our responsibility is to express an opinion on the reserves data based on our evaluation. |
We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) with the necessary modifications to reflect definitions and standards under the U.S. Financial Accounting Standards Board policies (the FASB Standards) and the legal requirements of the U.S. Securities and Exchange Commission (SEC Requirements). |
3. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with the principles and definitions outlined above. |
4. | The following table sets forth both the estimated proved reserve quantities (after royalties) and related estimates of future net cash flows (before deduction of income taxes) assuming constant prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Corporation evaluated by us for the year ended December 31, 2004: |
Estimated Proved | Related | |||||||||||||
Reserve Quantities | Estimates of Future | |||||||||||||
After Royalty | Net Cash Flow | |||||||||||||
BTax, 10% | ||||||||||||||
Evaluator and Preparation Date of Report | Reserves Location | Gas | Liquids | discount rate | ||||||||||
(Bcf) | (MMbbl) | ($USMM) | ||||||||||||
McDaniel & Associates Consultants Ltd.
|
Canada | 3,434 | 146 | 9,770 | ||||||||||
January 14, 2005
|
||||||||||||||
Gilbert Laustsen Jung Associates Ltd.
|
Canada | 2,390 | 121 | 6,529 | ||||||||||
January 14, 2005
|
||||||||||||||
Netherland, Sewell & Associates, Inc.
|
United States | 3,946 | 49 | 9,276 | ||||||||||
January 14, 2005
|
||||||||||||||
DeGolyer and MacNaughton
|
United States | 690 | 42 | 1,907 | ||||||||||
February 3, 2005
|
||||||||||||||
Gilbert Laustsen Jung Associates Ltd.
|
Ecuador | 143 | 1,752 | |||||||||||
January 14, 2005
|
||||||||||||||
Totals
|
10,460 | 501 | 29,234 | |||||||||||
5. | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook as modified by the FASB Standards and SEC requirements. |
6. | We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates. |
60
7. | Reserves are estimates only, and not exact quantities. In addition, as the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. |
(signed) McDaniel & Associates Consultants Ltd.
|
(signed) Gilbert Laustsen Jung Associates Ltd. | |
Calgary, Alberta, Canada
|
Calgary, Alberta, Canada | |
(signed) Netherland, Sewell & Associates, Inc.
|
(signed) DeGolyer and MacNaughton | |
Dallas, Texas, U.S.A.
|
Dallas, Texas, U.S.A. |
61
(i) | proved oil and gas reserve quantities estimated as at December 31, 2004 using constant prices and costs; and | |
(ii) | the related estimates of discounted future net cash flows under the standardized measure calculation for proved oil and gas reserve quantities. |
(a) | reviewed the Corporations procedures for providing information to the independent qualified reserves evaluators; | |
(b) | met with the independent qualified reserves evaluators to determine whether any restrictions placed by management affected the ability of the independent qualified reserves evaluators to report without reservation; and | |
(c) | reviewed the reserves data as outlined in the IQRE Report with management and each of the independent qualified reserves evaluators. |
(a) | the content and filing with securities regulatory authorities of the proved oil and gas reserve quantities, related standardized measure calculation and other oil and gas activity information, contained in the annual information form of the Corporation accompanying this Report; | |
(b) | the filing of the IQRE Report; and | |
(c) | the content and filing of this Report. |
62
| Review and approve managements identification of principal financial risks and monitor the process to manage such risks. | |
| Oversee and monitor the Corporations compliance with legal and regulatory requirements. | |
| Receive and review the reports of the Audit Committee of any subsidiary with public securities. | |
| Oversee and monitor the integrity of the Corporations accounting and financial reporting processes, financial statements and system of internal controls regarding accounting and financial reporting and accounting compliance. | |
| Oversee audits of the Corporations financial statements. | |
| Oversee and monitor the qualifications, independence and performance of the Corporations external auditors and internal auditing department. | |
| Provide an avenue of communication among the external auditors, management, the internal auditing department, and the Board of Directors. | |
| Report to the Board of Directors regularly. |
| An understanding of generally accepted accounting principles and financial statements; | |
| The ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves; | |
| Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can |
63
reasonably be expected to be raised by the registrants financial statements, or experience actively supervising one or more persons engaged in such activities; | ||
| An understanding of internal controls and procedures for financial reporting; and | |
| An understanding of audit committee functions. |
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1. | Discuss and review with management and the external auditors the Corporations and any subsidiary with public securities annual audited financial statements and related documents prior to their filing or distribution. Such review to include: |
a. | The annual financial statements and related footnotes including significant issues regarding accounting principles, practices and significant management estimates and judgments, including any significant changes in the Corporations selection or application of accounting principles, any major issues as to the adequacy of the Corporations internal controls and any special steps adopted in light of material control deficiencies. | |
b. | Managements Discussion and Analysis. | |
c. | A review of the use of off-balance sheet financing including managements risk assessment and adequacy of disclosure. | |
d. | A review of the external auditors audit examination of the financial statements and their report thereon. | |
e. | Review of any significant changes required in the external auditors audit plan. | |
f. | A review of any serious difficulties or disputes with management encountered during the course of the audit, including any restrictions on the scope of the external auditors work or access to required information. | |
g. | A review of other matters related to the conduct of the audit, which are to be communicated to the Committee under generally accepted auditing standards. |
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2. | Review and formally recommend approval to the Board of the Corporations: |
a. | Year-end audited financial statements. Such review shall include discussions with management and the external auditors as to: |
(i) | The accounting policies of the Corporation and any changes thereto. | |
(ii) | The effect of significant judgements, accruals and estimates. | |
(iii) | The manner of presentation of significant accounting items. | |
(iv) | The consistency of disclosure. |
b. | Managements Discussion and Analysis. | |
c. | Annual Information Form as to financial information. | |
d. | All prospectuses and information circulars as to financial information. |
3. | Review with management and the external auditors and either approve (such approval to include the authorization for public release) or formally recommend for approval to the Board the Corporations: |
a. | Quarterly unaudited financial statements and related documents, including Managements Discussion and Analysis. | |
b. | Any significant changes to the Corporations accounting principles. |
4. | Review and discuss with management financial information, including earnings press releases, the use of pro forma or non-GAAP financial information and earnings guidance, contained in any filings with the securities regulators or news releases related thereto (or provided to analysts or rating agencies) and consider whether the information is consistent with the information contained in the financial statements of the Corporation or any subsidiary with public securities. Such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made). |
5. | Ensure that management, the external auditors, and the internal auditors provide to the Committee an annual report on the Corporations control environment as it pertains to the Corporations financial reporting process and controls. |
6. | Review and discuss significant financial risks or exposures and assess the steps management has taken to monitor, control, report and mitigate such risk to the Corporation. |
7. | Review significant findings prepared by the external auditors and the internal auditing department together with managements responses. |
8. | Review in consultation with the internal auditors and the external auditors the degree of coordination in the audit plans of the internal auditors and the external auditors and enquire as to the extent the planned scope can be relied upon to detect weaknesses in internal controls, fraud, or other illegal acts. The Committee will assess the coordination of audit effort to assure completeness of coverage and the effective use of audit resources. Any significant recommendations made by the auditors for the strengthening of internal controls shall be reviewed and discussed with management. |
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9. | Review policies and procedures with respect to officers and directors expense accounts and perquisites, including their use of corporate assets, and consider the results of any review of these areas by the internal auditor or the external auditors. |
10. | Review all related party transactions between the Corporation and any officers or directors, including affiliations of any officers or directors. |
11. | Review with the General Counsel, the head of internal audit and the external auditors the results of their review of the Corporations monitoring compliance with each of the Corporations published codes of business conduct and applicable legal requirements. |
12. | Review legal and regulatory matters, including correspondence with regulators and governmental agencies, that may have a material impact on the interim or annual financial statements, related corporation compliance policies, and programs and reports received from regulators or governmental agencies. Members from the Legal and Tax departments should be at the meeting in person to deliver their reports. |
13. | Review policies and practices with respect to off-balance sheet transactions and trading and hedging activities, and consider the results of any review of these areas by the internal auditors or the external auditors. |
14. | Ensure that the Corporations presentations on net proven reserves have been reviewed with the Reserves Committee of the Board. |
15. | Establish procedures for the receipt, retention and treatment of complaints received by the Corporation, including confidential, anonymous submissions by employees of the Corporation, regarding accounting, internal accounting controls, or auditing matters. |
16. | Review with the President & Chief Executive Officer, the Executive Vice-President & Chief Financial Officer of the Corporation and the external auditors: (i) all significant deficiencies and material weaknesses in the design or operation of the Corporations internal controls and procedures for financial reporting which could adversely affect the Corporations ability to record, process, summarize and report financial information required to be disclosed by the Corporation in the reports that it files or submits under the United States Securities Exchange Act of 1934, as amended (the Exchange Act) or applicable Canadian federal and provincial legislation and regulations within the required time periods, and (ii) any fraud, whether or not material, that involves management of the Corporation or other employees who have a significant role in the Corporations internal controls and procedures for financial reporting. |
17. | Meet on a periodic basis separately with management. |
18. | Be directly responsible, in the Committees capacity as a committee of the Board and subject to the rights of shareholders and applicable law, for the appointment, compensation, retention and oversight of the work of the external auditors (including resolution of disagreements between management and the external auditors regarding financial reporting) for the purpose of preparing or issuing an audit report, or performing other audit, review or attest services for the Corporation. The external auditors shall report directly to the Committee. |
19. | Meet on a regular basis with the external auditors (without management present) and have the external auditors be available to attend Committee meetings or portions thereof at the request of the Chairman of the Committee or by a majority of the members of the Committee. |
20. | Review and discuss a report from the external auditors at least quarterly regarding: |
a. | All critical accounting policies and practices to be used; | |
b. | All alternative treatments within generally accepted accounting principles for policies and practices related to material items that have been discussed with management, including the ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditors; and | |
c. | Other material written communications between the external auditors and management, such as any management letter or schedule of unadjusted differences. |
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21. | Obtain and review a report from the external auditors at least annually regarding: |
a. | The external auditors internal quality-control procedures. | |
b. | Any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with those issues. | |
c. | To the extent contemplated in the following paragraph, all relationships between the external auditors and the Corporation. |
22. | Review and discuss with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors independence, including, without limitation, (i) receiving and reviewing, as part of the report described in the preceding paragraph, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on the independence of the external auditors with respect to the Corporation and its affiliates, (ii) discussing with the external auditors any disclosed relationships or services that the external auditors believe may affect the objectivity and independence of the external auditors, and (iii) recommending that the Board take appropriate action in response to the external auditors report to satisfy itself of the external auditors independence. |
23. | Review and evaluate: |
a. | The external auditors and the lead partner of the external auditors teams performance, and make a recommendation to the Board of Directors regarding the reappointment of the external auditors at the annual meeting of the Corporations shareholders or regarding the discharge of such external auditors. | |
b. | The terms of engagement of the external auditors together with their proposed fees. | |
c. | External audit plans and results. | |
d. | Any other related audit engagement matters. | |
e. | The engagement of the external auditors to perform non-audit services, together with the fees therefor, and the impact thereof, on the independence of the external auditors. |
24. | Upon reviewing and discussing the information provided to the Committee in accordance with paragraphs 20 through 23, evaluate the external auditors qualifications, performance and independence, including whether or not the external auditors quality controls are adequate and the provision of permitted non-audit services is compatible with maintaining auditor independence, taking into account the opinions of management and the head of internal audit. The Committee shall present its conclusions with respect to the external auditors to the Board. |
25. | Ensure the rotation of partners on the audit engagement team in accordance with applicable law. Consider whether, in order to assure continuing external auditor independence, it is appropriate to adopt a policy of rotating the external auditing firm on a regular basis. |
26. | Set clear hiring policies for the Corporations hiring of employees or former employees of the external auditors. |
27. | Consider with management and the external auditors the rationale for employing audit firms other than the principal external auditors. |
28. | Consider and review with the external auditors, management and the head of internal audit: |
a. | Significant findings during the year and managements responses and follow-up thereto. | |
b. | Any difficulties encountered in the course of their audits, including any restrictions on the scope of their work or access to required information, and managements response. | |
c. | Any significant disagreements between the external auditors or internal auditors and management. | |
d. | Any changes required in the planned scope of their audit plan. | |
e. | The resources, budget, reporting relationships, responsibilities and planned activities of the internal auditors. | |
f. | The internal audit department mandate. | |
g. | Internal audits compliance with the Institute of Internal Auditors standards. |
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29. | Meet on a periodic basis separately with the head of internal audit. |
30. | Review and concur in the appointment, compensation, replacement, reassignment, or dismissal of the head of internal audit. |
31. | Confirm and assure, annually, the independence of the internal audit department and the external auditors. |
32. | Review and, where appropriate, approve the provision of all permitted non-audit services (including the fees and terms thereof) in advance of the provision of those services by the external auditors (subject to the de minimus exception for non-audit services described in the Exchange Act or applicable Canadian federal and provincial legislation and regulations which are approved by the Committee prior to the completion of the audit). |
33. | Review and, where appropriate and permitted, approve the provision of all audit services (including the fees and terms thereof) in advance of the provision of those services by the external auditors. |
34. | If the pre-approvals contemplated in paragraphs 32 and 33 are not obtained, approve, where appropriate and permitted, the provision of all audit and non-audit services promptly after the Committee or a member of the Committee to whom authority is delegated becomes aware of the provision of those services. |
35. | Delegate, if the Committee deems necessary or desirable, to subcommittees consisting of one or more members of the Committee, the authority to grant the pre-approvals and approvals described in paragraphs 32 through 34. The decision of any such subcommittee to grant pre-approval shall be presented to the full Committee at the next scheduled Committee meeting. |
36. | The Committee may establish policies and procedures for the pre-approvals described in paragraphs 32 and 33, so long as such policies and procedures are detailed as to the particular service, the Committee is informed of each service and such policies and procedures do not include delegation of the Committees responsibilities under the Exchange Act or applicable Canadian federal and provincial legislation and regulations to management. |
37. | Review and concur in the appointment, replacement, reassignment, or dismissal of the Chief Financial Officer. |
38. | Upon a majority vote of the Committee outside resources may be engaged where and if deemed advisable. |
39. | Report Committee actions to the Board of Directors with such recommendations, as the Committee may deem appropriate. |
40. | Conduct or authorize investigations into any matters within the Committees scope of responsibilities. The Committee shall be empowered to retain, obtain advice or otherwise receive assistance from independent counsel, accountants, or others to assist it in the conduct of any investigation as it deems necessary and the carrying out of its duties. |
41. | The Corporation shall provide for appropriate funding, as determined by the Committee in its capacity as a committee of the Board, for payment (i) of compensation to the external auditors for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation, (ii) of compensation to any advisors employed by the Committee and (iii) of ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties. |
42. | Obtain assurance from the external auditors that disclosure to the Committee is not required pursuant to the provisions of the Exchange Act regarding the discovery of illegal acts by the external auditors. |
43. | The Committee shall review and reassess the adequacy of this Mandate annually and recommend any proposed changes to the Board for approval. |
44. | The Committees performance shall be evaluated annually by the Nominating and Corporate Governance Committee of the Board of Directors. |
45. | Perform such other functions as required by law, the Corporations mandate or bylaws, or the Board of Directors. |
46. | Consider any other matters referred to it by the Board of Directors. |
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ENCANA CORPORATION
2004
Managements Discussion and Analysis
MANAGEMENTS DISCUSSION & ANALYSIS
This MD&A has been prepared in United States dollars with production and sales volumes presented on an after royalties basis consistent with U.S. protocol reporting. This MD&A is dated February 22, 2005.
SUMMARY OF KEY SECTIONS
Page | ||||
SUMMARY OF KEY EVENTS AND
FINANCIAL RESULTS IN 2004 |
M1 | |||
OVERVIEW |
M1 | |||
BUSINESS ENVIRONMENT |
M2 | |||
CONSOLIDATED FINANCIAL RESULTS |
M3 | |||
DISCONTINUED OPERATIONS |
M15 | |||
LIQUIDITY AND CAPITAL RESOURCES |
M16 | |||
OUTSTANDING SHARE DATA |
M17 | |||
CONTRACTUAL OBLIGATIONS
AND CONTINGENCIES |
M18 | |||
ACCOUNTING POLICIES AND ESTIMATES |
M19 | |||
RISK MANAGEMENT |
M21 | |||
OUTLOOK |
M23 | |||
ADVISORIES |
M24 |
Certain terms used in this MD&A (and not otherwise defined) are defined in the notes regarding Oil and Gas Information, Currency, Non-GAAP Measures and References to EnCana, found at the end of this MD&A.
SUMMARY OF KEY EVENTS AND FINANCIAL RESULTS IN 2004
| Total sales volumes increased 16 percent to 4,560 million cubic feet of gas (MMcf) equivalent per day (MMcfe/d) comprised of 2,998 MMcf/d of natural gas and 260,383 barrels per day (bbls/d) of liquids. |
| Average sales prices, excluding financial hedges, increased 12 percent for North American natural gas and 27 percent for North American liquids. |
| EnCana recorded total realized commodity and currency hedging losses of approximately $0.7 billion after tax. |
| EnCana purchased approximately 20 million shares under the Normal Course Issuer Bid for a total cost of $1 billion. |
| As part of the sharpening of EnCanas strategic focus to unconventional resource plays, the Company: |
| Acquired Tom Brown, Inc. (TBI) on May 19, 2004 for approximately $2.7 billion, contributing approximately 194 MMcfe/d to EnCanas annual production; | |||
| Sold its United Kingdom (U.K.) operations for approximately $2.1 billion on December 1, 2004; | |||
| Completed approximately $1.4 billion in mature, North American conventional property dispositions during 2004; and | |||
| Initiated a strategic review of its Ecuador assets and has announced that these assets are for sale. |
OVERVIEW
EnCana is a leading independent North American oil and gas company. EnCana pursues predictable, profitable growth from its portfolio of long-life resource plays situated in Canada and the United States. EnCanas disciplined pursuit of these unconventional resources has enabled it to become North Americas leading natural gas producer and a technical and cost performance leader in the development of oilsands through in-situ recovery.
EnCana reports the results of its continuing operations under two business segments:
| Upstream, which focuses on the Companys exploration for and development and production of natural gas, crude oil and natural gas liquids (NGLs), and other related activities. | |||
| Midstream & Market Optimization, which is conducted by the Midstream & Marketing division. Midstream focuses on natural gas storage operations, NGLs processing and power generation operations. Marketing undertakes market optimization activities to enhance the sale of Upstreams proprietary production. Market optimization results reflect third party purchases and sales of product which provide operational flexibility for transportation commitments, product type, delivery points and customer diversification. |
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M1
BUSINESS ENVIRONMENT
NATURAL GAS
Lack of overall North American industry natural gas supply combined with increasing demand and
the influence of high crude oil prices have continued to result in historically high average NYMEX
gas prices. Higher average AECO gas prices in 2004 can be attributed to an increased NYMEX index
partially offset by wider AECO differentials from NYMEX combined with the appreciation of the
U.S./Canadian dollar exchange rate. The increased AECO/NYMEX basis differential in 2004 compared to
2003 can be attributed to increased transportation differentials for the incremental sales volumes
transported from Alberta to Eastern Canada.
Natural Gas Price Benchmarks
2004 vs | 2003 vs | |||||||||||||||||||
(average for the period) | 2004 | 2003 | 2003 | 2002 | 2002 | |||||||||||||||
AECO Price (C$/Mcf) |
$ | 6.79 | 1 | % | $ | 6.70 | 65 | % | $ | 4.07 | ||||||||||
NYMEX Price ($/MMBtu) |
6.14 | 14 | % | 5.39 | 67 | % | 3.22 | |||||||||||||
Rockies (Opal) Price ($/MMBtu) |
5.23 | 27 | % | 4.12 | 103 | % | 2.03 | |||||||||||||
AECO/NYMEX Basis Differential ($/MMBtu) |
0.91 | 40 | % | 0.65 | -2 | % | 0.66 | |||||||||||||
Rockies/NYMEX Basis Differential ($/MMBtu) |
0.91 | -28 | % | 1.27 | 7 | % | 1.19 | |||||||||||||
CRUDE OIL
The West Texas Intermediate (WTI) crude oil price was significantly higher both in the fourth
quarter and for the year of 2004 compared to the corresponding periods in 2003. This was caused by
continued world oil demand strength, primarily in Asia and North America, and during the fourth
quarter, concerns over winter heating oil supplies in North America. The world oil price in the
fourth quarter was further supported by supply uncertainties in the Middle East and West Africa, as
well as reduced supply from the Gulf of Mexico, the North Sea, Russia and Canada. OPECs reaction
to high prices resulted in an increase in production over the course of the year. However, the
incremental production was a heavier and more sour blend of crude oil than WTI and put added
pressure on light to heavy oil price differentials.
The WTI/Bow River heavy oil differential widened in the fourth quarter of 2004 to record levels primarily due to the higher price for WTI, as well as wider U.S. Gulf Coast light to heavy product differentials and increased Canadian heavy crude-on-crude competition. As a percentage of WTI, Bow River Blend average sales price for the fourth quarter of 2004 was 60 percent of WTI compared to 69 percent in the fourth quarter of 2003.
On a year over year basis, the WTI/Bow River heavy oil differential was higher primarily as a result of the increase in WTI. NAPO blend in Ecuador is a heavier crude than the SOTE Oriente blend (previously the predominant crude oil from Ecuador) resulting in a wider differential to WTI. The fourth quarter and annual 2004 increases in the WTI/Oriente differential compared to the same periods in 2003 are primarily related to the increase in the WTI price as well as wider U.S. Gulf Coast light to heavy product differentials.
Crude Oil Price Benchmarks
2004 vs | 2003 vs | |||||||||||||||||||
(average for the period, unless otherwise noted) | 2004 | 2003 | 2003 | 2002 | 2002 | |||||||||||||||
WTI ($/bbl) |
$ | 41.47 | 34 | % | $ | 30.99 | 19 | % | $ | 26.15 | ||||||||||
Dated Brent ($/bbl) |
38.27 | 33 | % | 28.83 | 15 | % | 25.02 | |||||||||||||
WTI/Bow River Differential ($/bbl) |
12.82 | 60 | % | 8.01 | 35 | % | 5.93 | |||||||||||||
WTI/OCP NAPO Differential (Ecuador) ($/bbl) (1) |
14.33 | 78 | % | 8.06 | | | ||||||||||||||
WTI/Oriente Differential (Ecuador) ($/bbl) |
11.12 | 99 | % | 5.59 | 34 | % | 4.16 | |||||||||||||
(1) | The WTI/ OCP NAPO Differential was posted as of September 2003. |
U.S./CANADIAN DOLLAR EXCHANGE RATES
The 2004 year-end U.S./Canadian dollar exchange rate of US$0.831 per C$1 increased by seven
percent compared with the 2003 year-end rate of $0.774. The 2003 year-end rate increased by 22
percent when compared with the 2002 year-end rate of $0.633.
The increased value of the Canadian dollar has resulted primarily from continuing differences between Canadian and U.S. interest rates and the U.S. current account deficit.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M2
CONSOLIDATED FINANCIAL RESULTS
SUMMARY
2004 vs. 2003
Cash flow increased to $5 billion from $4.5 billion, an increase of $0.5 billion or $1.34 per share
diluted. Higher commodity prices and growth in sales volumes were partially offset by realized
financial commodity and currency hedge losses and increased expenses. Cash flow from continuing
operations also increased $0.5 billion, or $1.22 per share diluted, to a total of $4.6 billion in
2004 compared to $4.1 billion in 2003.
Net earnings increased $1.1 billion to $3.5 billion in 2004. Included in net earnings is a $1.4 billion gain on the sale of the U.K. discontinued operations. EnCanas net earnings from continuing operations in 2004 are $2.2 billion compared with $2.1 billion in 2003. Higher volumes and prices in 2004 were offset by increased expenses and increased depreciation, depletion and amortization (DD&A). Net earnings in 2004 include an unrealized after tax gain of $229 million on Canadian issued U.S. denominated debt resulting from the increase in the value of the Canadian dollar and an unrealized after tax mark-to-market accounting loss of $165 million.
2003 vs. 2002
Cash flow increased 84 percent and net earnings increased 191 percent compared with 2002 as a
result of growth in sales volumes, higher commodity prices and the inclusion of a full year of post
merger operations, partially offset by increased expenses.
Net earnings for the year also included an unrealized after-tax gain on the U.S. denominated debt issued in Canada of $433 million, or $0.90 per share diluted resulting from the increase in the value of the Canadian dollar versus the U.S. dollar, and a $359 million, or $0.75 per share diluted recovery of future income taxes resulting from reductions in the Canadian federal and Alberta corporate income tax rates.
Cash flow from continuing operations and net earnings from continuing operations increased 101 percent and 222 percent, respectively, compared to 2002.
ACQUISITIONS AND DIVESTITURES
In May 2004, the Company successfully completed its cash tender offer for all of the outstanding common shares of TBI which became an indirect wholly owned subsidiary following the merger of TBI and another of the Companys indirect wholly owned subsidiaries. The total consideration was approximately $2.3 billion plus the assumed debt of TBI of approximately $0.4 billion. The TBI assets are primarily strong growth long-life North American resource play assets, contributing approximately 194 MMcfe/d (32,300 BOE/d) to EnCanas annual production in 2004, which complement existing Company assets and are consistent with managements strategic focus.
In December 2004, a subsidiary of the Company sold its U.K. operations for approximately $2.1 billion. These assets included interests in the Buzzard, Scott and Telford oil fields, plus interests in other satellite discoveries and exploration licences in the U.K. central North Sea. In the first quarter of 2004, an EnCana subsidiary completed the purchase, through two separate transactions, of additional interests in the North Sea, for net cash consideration of approximately $131 million.
In line with the Companys strategy of focusing on its inventory of North American resource play assets in 2004, the Company disposed of a number of mature conventional producing assets. The Company recorded proceeds of approximately $1.1 billion on the sales of conventional oil and natural gas assets which were primarily located in western Canada. At the time of disposition, these assets were producing approximately 200 MMcfe/d (33,770 BOE/d).
In February 2004, the Company sold its 53.3 percent partnership interest in Petrovera Resources (Petrovera) for net cash consideration of approximately $287 million including working capital adjustments. Petroveras production was approximately 120 MMcfe/d (20,000 BOE/d) of primarily heavy crude oil at the time of disposition.
In December 2004, the Company sold its interest in the Alberta Ethane Gathering System for approximately $108 million.
Proceeds received from the non-core divestitures described above have been used to repay debt, purchase EnCana shares and for general corporate purposes.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M3
Consolidated Financial Summary | 2004 vs | 2003 vs | ||||||||||||||||||
($ millions, except per share amounts) | 2004 | 2003 | 2003 | 2002 | 2002 | |||||||||||||||
Cash Flow(1) |
$ | 4,980 | 12 | % | $ | 4,459 | 84 | % | $ | 2,419 | ||||||||||
- per share basic |
10.82 | 15 | % | 9.41 | 63 | % | 5.79 | |||||||||||||
- per share diluted |
10.64 | 14 | % | 9.30 | 63 | % | 5.72 | |||||||||||||
Net Earnings |
3,513 | 49 | % | 2,360 | 191 | % | 812 | |||||||||||||
- per share basic |
7.63 | 53 | % | 4.98 | 157 | % | 1.94 | |||||||||||||
- per share diluted |
7.51 | 53 | % | 4.92 | 156 | % | 1.92 | |||||||||||||
Operating Earnings(2) |
1,976 | 41 | % | 1,399 | 78 | % | 787 | |||||||||||||
- per share diluted |
4.22 | 45 | % | 2.92 | 57 | % | 1.86 | |||||||||||||
Cash Flow from Continuing Operations(1) |
4,605 | 11 | % | 4,135 | 101 | % | 2,059 | |||||||||||||
- per share basic |
10.00 | 15 | % | 8.72 | 77 | % | 4.93 | |||||||||||||
- per share diluted |
9.84 | 14 | % | 8.62 | 77 | % | 4.87 | |||||||||||||
Net Earnings from Continuing Operations |
2,211 | 3 | % | 2,142 | 222 | % | 666 | |||||||||||||
- per share basic |
4.80 | 6 | % | 4.52 | 184 | % | 1.59 | |||||||||||||
- per share diluted |
4.72 | 6 | % | 4.47 | 183 | % | 1.58 | |||||||||||||
Operating Earnings from Continuing Operations (2) |
1,989 | 47 | % | 1,350 | 115 | % | 629 | |||||||||||||
- per share diluted |
4.25 | 51 | % | 2.82 | 89 | % | 1.49 | |||||||||||||
Revenues, Net of Royalties |
11,810 | 22 | % | 9,686 | 63 | % | 5,928 | |||||||||||||
Total Assets |
31,213 | 29 | % | 24,110 | 21 | % | 19,912 | |||||||||||||
Long-Term Debt |
7,742 | 27 | % | 6,088 | 21 | % | 5,051 | |||||||||||||
Cash Dividends(3) |
183 | 32 | % | 139 | 29 | % | 108 | |||||||||||||
(1) | Cash Flow and Cash Flow from Continuing Operations are non-GAAP measures and are discussed under Cash Flow in this MD&A. | |
(2) | Operating Earnings and Operating Earnings from Continuing Operations are non-GAAP measures and are described and discussed under Operating Earnings in this MD&A. | |
(3) | Represents cash dividends paid to common shareholders at the rate of US$0.40 per share annually except for 2003 and 2002 which were paid at the rate of C$0.40 per share annually. |
Quarterly Summary | 2004 | 2003 | ||||||||||||||||||||||||||||||
($ millions, except per share amounts) | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | ||||||||||||||||||||||||
Cash Flow(1) |
$ | 1,491 | $ | 1,363 | $ | 1,131 | $ | 995 | $ | 1,254 | $ | 977 | $ | 1,007 | $ | 1,221 | ||||||||||||||||
- per share basic |
3.25 | 2.95 | 2.46 | 2.16 | 2.71 | 2.06 | 2.10 | 2.54 | ||||||||||||||||||||||||
- per share diluted |
3.21 | 2.92 | 2.43 | 2.13 | 2.69 | 2.04 | 2.08 | 2.52 | ||||||||||||||||||||||||
Net Earnings |
2,580 | 393 | 250 | 290 | 426 | 290 | 807 | 837 | ||||||||||||||||||||||||
- per share basic |
5.62 | 0.85 | 0.54 | 0.63 | 0.92 | 0.61 | 1.68 | 1.74 | ||||||||||||||||||||||||
- per share diluted |
5.55 | 0.84 | 0.54 | 0.62 | 0.91 | 0.61 | 1.67 | 1.73 | ||||||||||||||||||||||||
Operating Earnings(2) |
573 | 559 | 379 | 465 | 316 | 278 | 277 | 528 | ||||||||||||||||||||||||
- per share diluted |
1.23 | 1.20 | 0.81 | 1.00 | 0.68 | 0.58 | 0.57 | 1.09 | ||||||||||||||||||||||||
Cash Flow from Continuing Operations(1) |
1,429 | 1,259 | 1,021 | 896 | 1,103 | 918 | 990 | 1,124 | ||||||||||||||||||||||||
- per share basic |
3.11 | 2.73 | 2.22 | 1.94 | 2.39 | 1.94 | 2.06 | 2.34 | ||||||||||||||||||||||||
- per share diluted |
3.07 | 2.70 | 2.19 | 1.92 | 2.37 | 1.92 | 2.04 | 2.32 | ||||||||||||||||||||||||
Net Earnings from Continuing Operations |
1,188 | 432 | 265 | 326 | 447 | 266 | 801 | 628 | ||||||||||||||||||||||||
- per share basic |
2.59 | 0.94 | 0.58 | 0.71 | 0.97 | 0.56 | 1.67 | 1.31 | ||||||||||||||||||||||||
- per share diluted |
2.56 | 0.93 | 0.57 | 0.70 | 0.96 | 0.56 | 1.65 | 1.30 | ||||||||||||||||||||||||
Operating Earnings from Continuing
Operations(2) |
612 | 553 | 362 | 462 | 337 | 254 | 271 | 488 | ||||||||||||||||||||||||
- per share diluted |
1.32 | 1.19 | 0.78 | 0.99 | 0.72 | 0.53 | 0.56 | 1.01 | ||||||||||||||||||||||||
Revenues, Net of Royalties |
4,208 | 2,320 | 2,552 | 2,730 | 2,639 | 2,190 | 2,233 | 2,624 | ||||||||||||||||||||||||
(1) | Cash Flow and Cash Flow from Continuing Operations are non-GAAP measures and are discussed under Cash Flow in this MD&A. | |
(2) | Operating Earnings and Operating Earnings from Continuing Operations are non-GAAP measures and are described and discussed under Operating Earnings in this MD&A. |
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M4
CASH FLOW
EnCanas cash flow increased to $4,980 million in 2004, an increase of $521 million from 2003. This
increase reflects the Companys overall 16 percent sales volume growth, increased prices in 2004,
realized hedge losses, realized foreign exchange gains and an increase in the current income tax
provision. EnCanas discontinued operations contributed $375 million to cash flow in 2004, an
increase of $51 million from 2003.
EnCanas 2004 cash flow from continuing operations increased $470 million, or $1.22 per share diluted, to $4,605 million over 2003 with significant items as follows:
| Natural gas sales volumes increased 16 percent to 2,968 MMcf/d. | |||
| Average North American natural gas prices, excluding financial hedges, were $5.47 per Mcf in 2004 compared to $4.87 per Mcf in 2003, an increase of 12 percent. | |||
| Average North American liquids prices, excluding financial hedges, were $28.77 per bbl in 2004 compared to $22.72 per bbl in 2003, an increase of 27 percent. | |||
| Realized financial commodity and currency hedge losses included in cash flow from continuing operations were approximately $686 million ($464 million after-tax) in 2004 compared to $259 million ($164 million after-tax) for 2003. | |||
| Realized foreign exchange gains of $190 million ($154 million after-tax) on the settlement of long-term debt in 2004 compared to realized gains of $86 million ($68 million after-tax) in 2003, as a result of the rise in the U.S./Canadian dollar exchange rate and its impact on the settlement of Canadian issued U.S. denominated debt. | |||
| Current income tax provision increased by $680 million to $567 million in 2004 from a recovery of $113 million in 2003 partially offsetting increased cash flow from higher volumes and prices. |
Cash flow measures are considered non-GAAP but are commonly used in the oil and gas industry to assist management and investors to measure the Companys ability to finance its capital programs and meet its credit obligations. The calculation of cash flow is disclosed on the Consolidated Statement of Cash Flows in the Consolidated Financial Statements.
NET EARNINGS
EnCanas net earnings increased $1,153 million to $3,513 million in 2004. Included in 2004 net
earnings is a gain of $1,364 million on the sale of EnCanas U.K. operations.
EnCanas net earnings from continuing operations increased $69 million, or $0.25 per share diluted in 2004 compared with 2003. In addition to the items affecting cash flow as detailed previously, significant items are:
| Unrealized mark-to-market losses of $190 million ($116 million after-tax) are included in 2004 with no corresponding amount in 2003. | |||
| Included in 2004 is a gain due to a change in tax rates of $109 million, compared to a gain of $359 million in 2003. | |||
| A $285 million ($229 million after-tax) unrealized gain on Canadian issued U.S. dollar debt in 2004 compared to an unrealized gain of $545 million ($433 million after-tax) in 2003. This results from the continued strengthening in the year-end U.S./Canadian dollar exchange rate between December 31, 2003 and December 31, 2004 compared to the change between December 31, 2002 and December 31, 2003. |
The impacts on results from the conversion of Canadian to U.S. dollars should be considered when analyzing specific components contained in the Consolidated Financial Statements. For every 100 Canadian dollars spent on capital projects, operating expenses and administrative expenses, the Company incurred additional costs of approximately US$5.20 based on the increase in the average U.S./Canadian dollar exchange rate from $0.716 in 2003 to $0.768 in 2004. Revenues were relatively unaffected by the increase in the exchange rate since commodity prices received are largely based in U.S. dollars or in Canadian dollar prices which are closely tied to the value of the U.S. dollar.
Reconciliation of Net Earnings from Continuing Operations from 2003 to 2004 ($millions)
2003 net earnings from continuing operations |
$ | 2,142 | |||
Upstream prices |
915 | (1) | |||
Upstream volumes |
864 | ||||
Gain on disposition of investments |
112 | ||||
Realized foreign exchange gain on long-term debt |
79 | ||||
Unrealized fair value adjustment on financial contracts |
(190 | ) | |||
Unrealized foreign exchange gain on long-term debt |
(260 | ) | |||
Income tax |
(294 | ) | |||
Upstream expenses |
(344 | ) | |||
DD&A costs |
(413 | ) | |||
Realized loss on financial contracts |
(427 | ) | |||
Other |
27 | ||||
2004 net earnings from continuing operations |
$ | 2,211 | |||
(1) | Excludes the effect of upstream financial hedging. |
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M5
OPERATING EARNINGS
Summary of Operating Earnings
2004 vs | 2003 vs | |||||||||||||||||||
($ millions) | 2004 | 2003 | 2003 | 2002 | 2002 | |||||||||||||||
Net Earnings, as reported |
$ | 3,513 | 49 | % | $ | 2,360 | 191 | % | $ | 812 | ||||||||||
Deduct: (Gain) loss on discontinuance |
(1,364 | ) | (169 | ) | 12 | |||||||||||||||
Add: Unrealized mark-to-market accounting loss (after-tax)(2) |
165 | | | |||||||||||||||||
Deduct: Unrealized foreign exchange gain on translation of
Canadian issued U.S. dollar debt
(after-tax) |
(229 | ) | (433 | ) | (17 | ) | ||||||||||||||
Deduct: Future tax recovery due to tax rate reductions |
(109 | ) | (359 | ) | (20 | ) | ||||||||||||||
Operating Earnings (1)(3) |
$ | 1,976 | 41 | % | $ | 1,399 | 78 | % | $ | 787 | ||||||||||
($ per Common Share Diluted) |
||||||||||||||||||||
Net Earnings, as reported |
$ | 7.51 | 53 | % | $ | 4.92 | 156 | % | $ | 1.92 | ||||||||||
Deduct: (Gain) loss on discontinuance |
(2.92 | ) | (0.35 | ) | 0.03 | |||||||||||||||
Add: Unrealized mark-to-market accounting loss (after-tax)(2) |
0.35 | | | |||||||||||||||||
Deduct: Unrealized foreign exchange gain on translation of
Canadian issued U.S. dollar debt
(after-tax) |
(0.49 | ) | (0.90 | ) | (0.04 | ) | ||||||||||||||
Deduct: Future tax recovery due to tax rate reductions |
(0.23 | ) | (0.75 | ) | (0.05 | ) | ||||||||||||||
Operating Earnings (1)(3) |
$ | 4.22 | 45 | % | $ | 2.92 | 57 | % | $ | 1.86 | ||||||||||
(1) | Operating Earnings is a non-GAAP measure that shows net earnings excluding the after-tax gain or loss from the disposition of discontinued operations, the after-tax effects of unrealized mark-to-market accounting for derivative instruments, the after-tax gain on translation of U.S. dollar denominated debt issued in Canada and the effect of the reduction in income tax rates. | |
(2) | The Company adopted mark-to-market accounting on derivative financial instruments prospectively on January 1, 2004. See Note 2 to the Consolidated Financial Statements. | |
(3) | Unrealized (gains)/ losses have no impact on cash flow. |
Summary of Operating Earnings from Continuing Operations
2004 vs | 2003 vs | |||||||||||||||||||
($ millions) | 2004 | 2003 | 2003 | 2002 | 2002 | |||||||||||||||
Net Earnings from Continuing Operations, as reported |
$ | 2,211 | 3 | % | $ | 2,142 | 222 | % | $ | 666 | ||||||||||
Add: Unrealized mark-to-market accounting loss (after-tax)(2) |
116 | | | |||||||||||||||||
Deduct: Unrealized foreign exchange gain on translation of Canadian issued U.S. dollar debt (after-tax) |
(229 | ) | (433 | ) | (17 | ) | ||||||||||||||
Deduct: Future tax recovery due to tax rate reductions |
(109 | ) | (359 | ) | (20 | ) | ||||||||||||||
Operating Earnings from Continuing Operations (1)(3) |
$ | 1,989 | 47 | % | $ | 1,350 | 115 | % | $ | 629 | ||||||||||
($ per Common Share Diluted) |
||||||||||||||||||||
Net Earnings from Continuing Operations, as reported |
$ | 4.72 | 6 | % | $ | 4.47 | 183 | % | $ | 1.58 | ||||||||||
Add: Unrealized mark-to-market accounting loss (after-tax)(2) |
0.25 | | | |||||||||||||||||
Deduct: Unrealized foreign exchange gain on translation of Canadian issued U.S. dollar debt (after-tax) |
(0.49 | ) | (0.90 | ) | (0.04 | ) | ||||||||||||||
Deduct: Future tax recovery due to tax rate reductions |
(0.23 | ) | (0.75 | ) | (0.05 | ) | ||||||||||||||
Operating Earnings from Continuing Operations (1)(3) |
$ | 4.25 | 51 | % | $ | 2.82 | 89 | % | $ | 1.49 | ||||||||||
(1) | Operating Earnings from Continuing Operations is a non-GAAP measure that shows net earnings from continuing operations excluding the after-tax effects of unrealized mark-to-market accounting for derivative instruments, the gain on translation of U.S. dollar denominated debt issued in Canada and the effect of the reduction in income tax rates. | |
(2) | The Company adopted mark-to-market accounting on derivative financial instruments prospectively on January 1, 2004. See Note 2 to the Consolidated Financial Statements. | |
(3) | Unrealized (gains)/losses have no impact on cash flow. |
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M6
RESULTS OF OPERATIONS
UPSTREAM OPERATIONS
Financial Results from Continuing Operations
($ millions) | 2004 | 2003 | 2002 | |||||||||||||||||||||||||||||||||||||||||||||
Produced | Crude Oil | Produced | Crude Oil | Produced | Crude Oil | |||||||||||||||||||||||||||||||||||||||||||
Gas | and NGLs | Other | Total | Gas | and NGLs | Other | Total | Gas | and NGLs | Other | Total | |||||||||||||||||||||||||||||||||||||
Revenues, Net of Royalties |
$ | 5,704 | $ | 1,320 | $ | 232 | $ | 7,256 | $ | 4,447 | $ | 1,170 | $ | 180 | $ | 5,797 | $ | 2,280 | $ | 970 | $ | 76 | $ | 3,326 | ||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
270 | 41 | | 311 | 153 | 11 | | 164 | 82 | 23 | | 105 | ||||||||||||||||||||||||||||||||||||
Transportation and selling |
416 | 56 | | 472 | 360 | 69 | | 429 | 210 | 35 | | 245 | ||||||||||||||||||||||||||||||||||||
Operating |
519 | 285 | 222 | 1,026 | 402 | 300 | 170 | 872 | 290 | 201 | 71 | 562 | ||||||||||||||||||||||||||||||||||||
Operating Cash Flow |
$ | 4,499 | $ | 938 | $ | 10 | $ | 5,447 | $ | 3,532 | $ | 790 | $ | 10 | $ | 4,332 | $ | 1,698 | $ | 711 | $ | 5 | $ | 2,414 | ||||||||||||||||||||||||
Depreciation, depletion and
amortization |
2,271 | 1,900 | 1,115 | |||||||||||||||||||||||||||||||||||||||||||||
Upstream Income |
$ | 3,176 | $ | 2,432 | $ | 1,299 | ||||||||||||||||||||||||||||||||||||||||||
2004 vs. 2003
Results from continuing operations reflect a 12 percent increase in sales volumes of 418 MMcfe/d
(69,689 BOE/d) for the year ended December 31, 2004 compared with 2003.
Revenues, net of royalties, reflect the increase in natural gas and crude oil benchmark prices (see the Business Environment section of this MD&A) for the year offset by the realized hedging losses. The effect of realized commodity and currency hedging losses for the year ended December 31, 2004 was $669 million, or $0.46 per Mcfe ($2.77 per BOE), compared to $297 million or $0.23 per Mcfe ($1.38 per BOE) for 2003.
North American production and mineral taxes for produced gas increased 76 percent in 2004 compared to 2003 primarily due to increased natural gas prices and volumes in the United States and a higher effective tax rate on production growth in Colorado.
Transportation and selling expenses increased ten percent in 2004 as a result of increased natural gas volumes in the U.S. and Canada and the impact of the change in the average U.S./Canadian dollar exchange rate on Canadian dollar denominated transactions.
For the year ended December 31, 2004, operating expenses were slightly higher at $0.55 per Mcfe ($3.33 per BOE) compared to $0.54 per Mcfe ($3.26 per BOE) for the same period in 2003 due primarily to the increase in the average U.S./Canadian dollar exchange rate during 2004. Excluding the impact of foreign exchange, operating expenses in 2004 would have decreased to $0.51 per Mcfe ($3.10 per BOE) primarily as a result of increased volumes.
DD&A expense increased by $371 million in 2004 compared to 2003 primarily as a result of increased sales volumes and the impact of the higher value of the Canadian dollar compared to the U.S. dollar applied to Canadian dollar denominated DD&A expense. On a North America basis, excluding Other activities, DD&A rates were $1.53 per Mcfe ($9.20 per BOE) for 2004 compared to $1.39 per Mcfe ($8.36 per BOE) in 2003. Increased DD&A rates in 2004 were primarily the result of the increase in the average U.S./Canadian dollar exchange rate and the impact of the acquisition cost of TBI. DD&A rates for the year ended December 31, 2004 exclude impairments of exploration prospects in Ghana, Bahrain and other areas of $23 million, which were recorded in the second and fourth quarters of 2004, respectively.
2003 vs. 2002
The Companys 2003 Upstream revenues, net of royalties, increased $2,471 million, or 74 percent,
over 2002 due to the increase in commodity prices, growth in sales volumes and the inclusion of a
full year of post merger results. The 23 percent growth in sales volumes from continuing operations
of 675 MMcfe/d (112,585 BOE/d) for the year ended December 31, 2003, compared to 2002, reflected
increased production in the U.S., the addition of a full year of post merger volumes and the
expansion of production from the Companys Steam Assisted Gravity Drainage (SAGD) projects.
Production and mineral tax increases in 2003 were the result of higher prices in the U.S. and a full year of post merger results.
The increased transportation and selling expenses in 2003 were attributable to growth in North American volumes, a full year of post merger results and the effect of the change in the average U.S./Canadian dollar exchange rate on Canadian dollar denominated transportation and selling expenses.
Upstream operating costs increased 55 percent compared to 2002 due to additional production volumes, a full year of post merger results, the change in the average U.S./Canadian dollar exchange rate and its impact on Canadian dollar denominated operating expenses, as well as increased costs for maintenance, workovers, higher fuel and power expense due to higher natural gas prices and an increased proportionate share of costs from SAGD operations.
DD&A expense increased by $785 million in 2003 compared to 2002. On a North America basis, excluding Other activities, DD&A rates were $1.39 per Mcfe ($8.36 per BOE) for 2003 compared to $1.01 per Mcfe ($6.09 per BOE) in 2002. The increased DD&A rate in 2003 reflects increased future development costs related to the proved reserves added for SAGD projects and the U.S., and the effect of the increase in the average U.S./Canadian dollar exchange rate on the Canadian dollar denominated DD&A expense.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M7
Revenue Variances for 2004 compared to 2003 and 2003 compared to 2002
From Continuing Operations
($ millions) | 2004 | 2003 | ||||||||||||||||||||||||||||||
2003 | Revenue | 2004 | 2002 | Revenue | 2003 | |||||||||||||||||||||||||||
Revenues, | Variances | Revenues, | Revenues, | Variances | Revenues, | |||||||||||||||||||||||||||
Net of | in: | Net of | Net of | in: | Net of | |||||||||||||||||||||||||||
Royalties | Price(1) | Volume | Royalties | Royalties | Price(1) | Volume | Royalties | |||||||||||||||||||||||||
Produced Gas | ||||||||||||||||||||||||||||||||
Canada |
$ | 3,396 | $ | 271 | $ | 261 | $ | 3,928 | $ | 1,882 | $ | 1,075 | $ | 439 | $ | 3,396 | ||||||||||||||||
United States |
1,051 | 147 | 578 | 1,776 | 398 | 204 | 449 | 1,051 | ||||||||||||||||||||||||
Total Produced Gas |
$ | 4,447 | $ | 418 | $ | 839 | $ | 5,704 | $ | 2,280 | $ | 1,279 | $ | 888 | $ | 4,447 | ||||||||||||||||
Crude Oil and NGLs |
||||||||||||||||||||||||||||||||
Canada |
$ | 1,078 | $ | 95 | $ | (18 | ) | $ | 1,155 | $ | 914 | $ | (11 | ) | $ | 175 | $ | 1,078 | ||||||||||||||
United States |
92 | 30 | 43 | 165 | 56 | 6 | 30 | 92 | ||||||||||||||||||||||||
Total Crude Oil and NGLs |
$ | 1,170 | $ | 125 | $ | 25 | $ | 1,320 | $ | 970 | $ | (5 | ) | $ | 205 | $ | 1,170 | |||||||||||||||
(1) | Includes realized commodity and currency hedging impacts. |
The increase in sales volumes accounts for approximately 61 percent of the change in revenues, net of royalties, for 2004 compared with 2003. In the table above, impacts from price changes are reduced as a result of the year over year changes in realized commodity and currency hedge losses mentioned previously.
The Crude Oil and NGLs volume variance in Canada of $(18) million for 2004 compared with 2003 was mainly due to the dispositions of mature conventional producing assets during 2004.
Sales Volumes
2004 vs | 2003 vs | |||||||||||||||||||
2004 | 2003 | 2003 | 2002 | 2002 | ||||||||||||||||
Produced Gas (million cubic feet per day) |
2,968 | 16 | % | 2,553 | 25 | % | 2,048 | |||||||||||||
Crude Oil (barrels per day) |
140,379 | -1 | % | 142,326 | 21 | % | 117,218 | |||||||||||||
NGLs (barrels per day) |
26,038 | 10 | % | 23,569 | 16 | % | 20,259 | |||||||||||||
Continuing Operations (million cubic feet equivalent per day) (1) |
3,966 | 12 | % | 3,548 | 23 | % | 2,873 | |||||||||||||
Continuing Operations (barrels of oil equivalent per day) (2) |
661,084 | 12 | % | 591,395 | 23 | % | 478,810 | |||||||||||||
Discontinued Operations |
||||||||||||||||||||
Ecuador (barrels per day ) |
77,993 | 68 | % | 46,521 | 56 | % | 29,740 | |||||||||||||
United Kingdom (barrels of oil equivalent per day) (2) |
20,973 | 71 | % | 12,295 | 1 | % | 12,195 | |||||||||||||
Syncrude (barrels per day) |
| | 7,629 | -68 | % | 23,540 | ||||||||||||||
Discontinued Operations (million cubic feet equivalent per day) (1) |
594 | 49 | % | 399 | 2 | % | 393 | |||||||||||||
Total (million cubic feet equivalent per day) (1) |
4,560 | 16 | % | 3,947 | 21 | % | 3,266 | |||||||||||||
Total (barrels of oil equivalent per day) (2) |
760,050 | 16 | % | 657,840 | 21 | % | 544,285 | |||||||||||||
(1) | Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet. | |
(2) | Includes natural gas and liquids (converted to BOE). |
In 2004, volumes from continuing operations were higher by 12 percent, or 418 MMcfe/d (69,689 BOE/d), compared to 2003.
Canadian natural gas sales volumes increased approximately seven percent or 134 MMcf/d in 2004. This increase results mostly from successful resource play drilling programs at Greater Sierra and Cutbank Ridge in northeast British Columbia as well as Shallow Gas in southern Alberta; the increased volumes were partially reduced by the disposition of non-core properties during 2004, producing approximately 56 MMcf/d on an annualized basis. Natural gas sales volumes in the United States increased approximately 48 percent or 281 MMcf/d during 2004 primarily due to successful resource play drilling programs in the Piceance and Fort Worth basins and incremental production of 161 MMcf/d from the TBI acquisition.
In 2004, liquids sales volumes were relatively unchanged when compared to 2003. The impacts of continued development at Foster Creek, successful drilling programs at Suffield and Weyburn, and positive response from the waterflood program at Pelican Lake were offset by the Petrovera and other non-core dispositions in the first and third quarters of 2004, respectively, which reduced production by 19,800 bbls/d on an annualized basis.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M8
Highlights:
| Greater Sierra Natural gas production averaged 230 MMcf/d, an increase of 61 percent (or 87 MMcf/d) in 2004 mainly due to the success of the 2003/2004 drilling program. In 2004, 187 net wells were drilled. |
|||
| Cutbank Ridge 2004 was the first full year of operations. Natural gas production averaged 40 MMcf/d and exited the year at 47 MMcf/d. In 2004, 50 net wells were drilled. |
|||
| Coalbed Methane Natural gas production in 2004 exited the year at 30 MMcf/d and averaged 17 MMcf/d, up from 4 MMcf/d in 2003. During the year, 577 net wells were drilled. |
|||
| Shallow Gas During 2004, natural gas production increased 17 percent to 592 MMcf/d with 1,552 net wells drilled. |
|||
| Piceance Natural gas production averaged 261 MMcf/d in 2004, an increase of 73 percent or 110 MMcf/d compared to 2003. This increase is the result of a successful drilling program (250 net wells) and the TBI acquisition. |
|||
| Fort Worth EnCana acquired assets in the Fort Worth Basin in 2003 with the Savannah Energy Inc. acquisition and added to those assets as a result of a December 2004 property acquisition. Production averaged 27 MMcf/d in 2004. |
|||
| East Texas East Texas, which produced 50 MMcf/d during 2004, was acquired as part of the TBI acquisition. During 2004, 50 net wells were drilled. |
|||
| Foster Creek Completion of the first phase of facility expansion in the fall of 2003 resulted in a 32 percent increase in 2004 crude oil production to 28,800 bbls/d. |
|||
| Pelican Lake Average crude oil production in 2004 increased 19 percent to 18,900 bbls/d due to the response of the waterflood program which began in the last half of 2004. |
Per Unit Results Produced Gas ($ per thousand cubic feet)
Canada | United States | |||||||||||||||||||||||||||||||||||||||
2004 vs | 2003 vs | 2004 vs | 2003 vs | |||||||||||||||||||||||||||||||||||||
2004 | 2003 | 2003 | 2002 | 2002 | 2004 | 2003 | 2003 | 2002 | 2002 | |||||||||||||||||||||||||||||||
Price(1) |
$ | 5.34 | 10 | % | $ | 4.87 | 70 | % | $ | 2.86 | $ | 5.79 | 19 | % | $ | 4.88 | 65 | % | $ | 2.96 | ||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
0.08 | 14 | % | 0.07 | -13 | % | 0.08 | 0.65 | 38 | % | 0.47 | 74 | % | 0.27 | ||||||||||||||||||||||||||
Transportation and selling(2) |
0.39 | 3 | % | 0.38 | 58 | % | 0.24 | 0.31 | -23 | % | 0.40 | -15 | % | 0.47 | ||||||||||||||||||||||||||
Operating |
0.52 | 8 | % | 0.48 | 17 | % | 0.41 | 0.37 | 32 | % | 0.28 | | 0.28 | |||||||||||||||||||||||||||
Netback |
$ | 4.35 | $ | 3.94 | $ | 2.13 | $ | 4.46 | $ | 3.73 | $ | 1.94 | ||||||||||||||||||||||||||||
Gas Sales Volumes (MMcf per day) |
2,099 | 7 | % | 1,965 | 15 | % | 1,711 | 869 | 48 | % | 588 | 74 | % | 337 | ||||||||||||||||||||||||||
(1) | Excludes realized commodity and currency hedge activities. | |
(2) | U.S. per unit transportation and selling costs in 2004 exclude a one-time payment of $21 million made to terminate a long-term physical delivery contract. |
Benchmark natural gas NYMEX prices were higher by 14 percent compared with 2003, however this increase has been partially offset by increased natural gas price differentials in Canada. For the year ended December 31, 2004, realized commodity and currency hedging losses on natural gas were approximately $238 million, or $0.22 per Mcf compared to a loss of approximately $91 million, or $0.10 per Mcf in 2003. Certain of these hedges were put in place to secure the economics of the TBI acquisition.
Per unit production and mineral taxes in the U.S. for the year ended December 31, 2004 compared to 2003 increased 38 percent or $0.18 per Mcf due to a combination of higher gas prices and a higher effective tax rate on the significant production growth in Colorado.
Natural gas per unit transportation and selling costs for the U.S. have decreased 23 percent or $0.09 per Mcf for the year ended December 31, 2004 compared to 2003, primarily as a result of the TBI acquisition where a majority of the production is sold at the wellhead and does not incur transportation charges.
Canadian natural gas per unit operating expenses for 2004 were eight percent or $0.04 per Mcf higher compared to 2003 primarily due to the higher U.S./Canadian exchange rates. Increases in the U.S. per unit natural gas operating expenses of 32 percent or $0.09 per Mcf for the year ended December 31, 2004 compared to 2003 were a result of higher operating expenses from the TBI properties, incremental operating costs associated with waste water disposal in Colorado and other non-recurring charges related to the prior year.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M9
Average realized prices for natural gas in the U.S. and Canada for 2003 increased by approximately 65 percent and 70 percent respectively, over 2002 due to concerns about overall North American storage inventory levels and a lack of confidence concerning prospects for North American supply growth. Realized commodity and currency hedging gains in 2002 for natural gas were $66 million, or $0.09 per Mcf.
Per unit production and mineral tax expense in the U.S. was $0.20 per Mcf higher in 2003 than 2002 due to higher natural gas prices.
For Canadian produced gas operations, per unit transportation and selling costs were higher in 2003 compared to 2002 by $0.14 per Mcf due to an increased proportion of sales transported to more distant markets and the change in the U.S./Canadian dollar exchange rate.
Per unit operating expenses for Canadian produced gas were higher in 2003 compared to 2002 by $0.07 per Mcf as a result of increased maintenance, workovers, the effect of the change in the U.S./Canadian dollar exchange rate and production from higher operating cost areas.
Per Unit Results Crude Oil ($ per barrel)
North America | ||||||||||||||||||||
2004 vs | 2003 vs | |||||||||||||||||||
2004 | 2003 | 2003 | 2002 | 2002 | ||||||||||||||||
Price(1) |
$ | 27.92 | 25 | % | $ | 22.29 | 11 | % | $ | 20.08 | ||||||||||
Expenses |
||||||||||||||||||||
Production and mineral taxes |
0.41 | 356 | % | 0.09 | -79 | % | 0.43 | |||||||||||||
Transportation and selling |
1.06 | -19 | % | 1.31 | 60 | % | 0.82 | |||||||||||||
Operating |
5.53 | -5 | % | 5.80 | 24 | % | 4.69 | |||||||||||||
Netback |
$ | 20.92 | $ | 15.09 | $ | 14.14 | ||||||||||||||
Crude Oil Sales Volumes (bbls per day) |
140,379 | -1 | % | 142,326 | 21 | % | 117,218 | |||||||||||||
(1) | Excludes realized commodity and currency hedge activities. |
Increases in the average crude oil price in 2004, excluding the impact of financial hedges, reflect the increase in the benchmark WTI which increased 34 percent in 2004 compared to 2003. This increase was partially offset by the increased WTI/Bow River crude oil price differential (up approximately 60 percent) and a higher proportionate share of heavier blend oils in the product mix. Realized commodity and currency hedging losses on crude oil were approximately $431 million, or $7.08 per bbl of liquids in 2004 compared to a loss of approximately $206 million, or $3.41 per bbl of liquids in 2003.
North American per unit production and mineral taxes increased in 2004 primarily as a result of mineral tax amendments related to prior years that were recorded in the third quarter of 2003. Higher freehold mineral tax and Saskatchewan surtax in the Weyburn area resulted from higher prices and increased production.
The 2004 per unit crude oil transportation and selling expenses in North America have decreased $0.25 per bbl mainly due to an adjustment in oil transportation rates.
North American crude oil per unit operating costs for 2004 have decreased $0.27 per bbl compared to 2003 mainly due to the sale of Petrovera, which had higher operating costs relative to other properties. This reduction was partially offset by the effect of increased U.S./Canadian exchange rates and higher fuel gas costs for the SAGD projects.
Average realized crude oil prices in 2003 increased approximately 11 percent over 2002 as a result of concerns over tensions in the Middle East combined with strong Asian demand and OPECs management of its production quotas. Realized commodity and currency hedging losses in 2002 on crude oil were $32 million, or $0.64 per bbl of liquids.
Per unit transportation and selling costs were higher by $0.49 per bbl over 2002 as a result of increased heavy crude oil volumes which attract a 20 percent premium transportation charge over light crude oil combined with annual tariff increases.
The increase in per unit operating expenses of $1.11 per bbl for 2003 compared to 2002 is attributable to the increase in the U.S./Canadian dollar exchange rate, higher maintenance costs and increased production weighting of heavy oil volumes from SAGD projects, which have higher operating expenses, combined with higher fuel and electricity costs resulting from the rise in natural gas prices.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M10
Per Unit Results NGLs(1) ($ per barrel)
Canada | United States | ||||||||||||||||||||||||||||||||||||||||
2004 vs | 2003 vs | 2004 vs | 2003 vs | ||||||||||||||||||||||||||||||||||||||
2004 | 2003 | 2003 | 2002 | 2002 | 2004 | 2003 | 2003 | 2002 | 2002 | ||||||||||||||||||||||||||||||||
Price |
$ | 31.43 | 30 | % | $ | 24.26 | 38 | % | $ | 17.55 | $ | 35.43 | 31 | % | $ | 26.97 | 14 | % | $ | 23.75 | |||||||||||||||||||||
Expenses |
|||||||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
| | | | | 3.82 | 88 | % | 2.03 | 99 | % | 1.02 | |||||||||||||||||||||||||||||
Transportation and selling |
0.41 | 141 | % | 0.17 | | | | | | | | ||||||||||||||||||||||||||||||
Netback |
$ | 31.02 | $ | 24.09 | $ | 17.55 | $ | 31.61 | $ | 24.94 | $ | 22.73 | |||||||||||||||||||||||||||||
NGLs Sales Volumes (bbls per day) |
13,452 | -6 | % | 14,278 | 3 | % | 13,852 | 12,586 | 35 | % | 9,291 | 45 | % | 6,407 | |||||||||||||||||||||||||||
(1) | NGLs results include Condensate. |
NGLs realized price changes generally correlate with changes in WTI oil prices. The strong WTI oil price in 2004 positively impacted NGLs prices.
U.S. per unit production and mineral taxes for the year ended December 31, 2004 compared to 2003 increased by 88 percent or $1.79 per bbl. Higher NGLs prices in 2004 and increased production growth in Colorado, which has a higher effective production tax rate, were the key reasons for this increase.
Per unit transportation and selling costs for NGLs in Canada increased by 141 percent or $0.24 per bbl in 2004 compared to 2003 as the Company incurred a full year of trucking charges for volumes in northeast British Columbia that came onstream in the fall of 2003.
MIDSTREAM & MARKET OPTIMIZATION OPERATIONS
Financial Results
($ millions) | 2004 | 2003 | 2002 | |||||||||||||||||||||||||||||||||
Market | Market | Market | ||||||||||||||||||||||||||||||||||
Midstream | Optimization | Total | Midstream | Optimization | Total | Midstream | Optimization | Total | ||||||||||||||||||||||||||||
Revenues |
$ | 1,450 | $ | 3,299 | $ | 4,749 | $ | 1,084 | $ | 2,803 | $ | 3,887 | $ | 440 | $ | 2,154 | $ | 2,594 | ||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Transportation and selling |
| 27 | 27 | | 55 | 55 | | 87 | 87 | |||||||||||||||||||||||||||
Operating |
279 | 46 | 325 | 261 | 63 | 324 | 174 | 13 | 187 | |||||||||||||||||||||||||||
Purchased product |
1,071 | 3,205 | 4,276 | 762 | 2,693 | 3,455 | 169 | 2,031 | 2,200 | |||||||||||||||||||||||||||
Operating Cash Flow |
$ | 100 | $ | 21 | $ | 121 | $ | 61 | $ | (8 | ) | $ | 53 | $ | 97 | $ | 23 | $ | 120 | |||||||||||||||||
Depreciation, depletion and
amortization |
70 | 48 | 36 | |||||||||||||||||||||||||||||||||
Segment Income |
$ | 51 | $ | 5 | $ | 84 | ||||||||||||||||||||||||||||||
Revenues and purchased product expense in Midstream & Market Optimization operations increased in 2004 compared to 2003 due primarily to increases in commodity prices. Operating cash flow increased $68 million in 2004 to $121 million as a result of improved margins from natural gas liquids processing and gas storage optimization activities. Decreases in transportation and selling costs in 2004 compared to 2003 are primarily due to the reallocation of natural gas downstream transportation costs to the Upstream segment. Operating expenses in 2003 included a $20 million settlement with the U.S. Commodity Futures Trading Commission as described in the Contractual Obligations and Contingencies section of this MD&A.
The increase in 2004 DD&A is primarily due to a write down in the value of the Companys equity investment interest in the Trasandino Pipeline in Argentina and Chile of approximately $35 million.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M11
CORPORATE
($ millions) | 2004 | 2003 | 2002 | |||||||||
Revenues |
$ | (195 | ) | $ | 2 | $ | 8 | |||||
Expenses |
||||||||||||
Operating |
(1 | ) | | | ||||||||
Depreciation, depletion and amortization |
61 | 41 | 35 | |||||||||
Segment Income |
$ | (255 | ) | $ | (39 | ) | $ | (27 | ) | |||
Administrative |
197 | 173 | 118 | |||||||||
Interest, net |
397 | 283 | 286 | |||||||||
Accretion of asset retirement obligation |
22 | 17 | 13 | |||||||||
Foreign exchange gain |
(417 | ) | (598 | ) | (11 | ) | ||||||
Stock-based compensation |
17 | 18 | | |||||||||
Gain on dispositions |
(113 | ) | (1 | ) | (33 | ) | ||||||
Income tax expense |
658 | 364 | 317 |
Corporate revenues in 2004 include approximately $197 million in unrealized mark-to-market losses related to financial and commodity contracts. Other mark-to-market gains ($7 million) on derivative financial instruments related to interest and electricity consumption are recorded in interest, net and operating expenses respectively.
DD&A includes provisions for corporate assets such as computer equipment, office furniture and leasehold improvements. The increase in expense on a year-over-year basis is the result of higher capital spending in prior periods on corporate capital items and the impact of the change in the U.S./Canadian dollar exchange rate.
Administrative expenses increased 14 percent in 2004. The increase reflects the effect of the change in the U.S./Canadian dollar exchange rate and increased long-term compensation expenses. Administrative costs were approximately $0.12 per Mcfe in both 2004 and 2003.
The higher interest expense resulted primarily from the higher average outstanding debt level during the year as a result of the TBI acquisition in the second quarter of 2004. EnCanas weighted average interest rate on outstanding debt was marginally lower in 2004 than it was in 2003 and partially mitigated the effect of higher debt levels.
The majority of the foreign exchange gain of $417 million in 2004 resulted from the change in the U.S./Canadian dollar exchange rate during 2004 applied to U.S. dollar denominated debt issued in Canada as discussed previously in this MD&A. Under Canadian GAAP, the Company is required to translate long-term debt issued in Canada and denominated in U.S. dollars into Canadian dollars at the period-end exchange rate. Resulting foreign exchange gains or losses are recorded in the Consolidated Statement of Earnings.
During 2004, EnCana sold certain corporate investments and recorded gains of $113 million on these sales.
The effective tax rate for 2004 was 23 percent compared to 15 percent for 2003 and 32 percent for 2002. Further information regarding EnCanas effective tax rate can be found in Note 9 to the Consolidated Financial Statements. EnCanas effective rate in any year is a function of the relationship between the amount of net earnings before income taxes for the year and the magnitude of the items representing permanent differences that are excluded from the earnings subject to tax. There are a variety of items of this type, including:
| The effects of asset dispositions where the tax values of the assets sold differ from their accounting value. | |||
| Adjustments for the impact of legislative tax changes which have a prospective impact on future income tax obligations. | |||
| The non-taxable half of Canadian capital gains (losses). | |||
| Items such as resource allowance and non-deductible crown payments where the income tax treatment is different from the accounting treatment. |
The 2004 effective tax rate reflects a reduction of $109 million in future income taxes resulting from the reduction in the Alberta tax rate from 12.5 percent to 11.5 percent and Albertas retention of the resource allowance and non-deductible crown royalties regime until 2007. In 2003, the effective tax rate reflected a $359 million reduction in future income taxes resulting from the reductions in the Canadian federal and Alberta corporate income tax rates and related changes to the Canadian federal resource allowance deduction.
Current income tax expense for the year ended 2004 was $567 million compared to $(113) million in 2003 and $(66) million in 2002. As expected, current taxes increased significantly in 2004; 2003 and 2002 were abnormally low as a result of the effects of the merger with Alberta Energy Company Ltd.
The operations of the Company are complex and related tax interpretations, regulations and legislation in the various jurisdictions that the Company and its subsidiaries operate in are continually changing. As a result, there are usually some tax matters under review. The Company believes that the provision for taxes is adequate.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M12
CAPITAL EXPENDITURES
Capital Summary
2004 | 2003 | 2002(1) | ||||||||||
Upstream |
$ | 4,343 | $ | 3,845 | $ | 1,932 | ||||||
Midstream & Market Optimization |
64 | 223 | 47 | |||||||||
Corporate |
46 | 57 | 43 | |||||||||
Core Capital Expenditures |
$ | 4,453 | $ | 4,125 | $ | 2,022 | ||||||
Acquisitions |
2,986 | 593 | 748 | |||||||||
Dispositions |
(1,817 | ) | (301 | ) | (423 | ) | ||||||
Discontinued Operations |
(1,416 | ) | (995 | ) | 397 | |||||||
Net Capital |
$ | 4,206 | $ | 3,422 | $ | 2,744 | ||||||
(1) | 2002 amounts include post merger capital only. |
The Companys core capital expenditures increased approximately $0.3 billion to $4.5 billion in 2004. The increase in Upstream core capital expenditures in 2004 compared to 2003 was primarily as a result of continued development of EnCanas United States resource play properties. Net capital expenditures increased approximately $0.8 billion compared to 2003 as a result of the TBI acquisition, increased drilling in the U.S., higher cost wells drilled both in Canada and the U.S., and the impact of the higher U.S./Canadian dollar exchange rate partially offset by the sale of the U.K. operations and non-core asset dispositions. The Companys capital investment was funded by cash flow in excess of amounts paid for purchases of Common Shares under the Normal Course Issuer Bid, proceeds received on dispositions of non-core assets and debt.
UPSTREAM CAPITAL EXPENDITURES
The increase in Upstream capital expenditures in 2004 compared to 2003 reflects increased drilling
and development activities in the U.S. and the impact of the increased average U.S./Canadian dollar
exchange rate on Canadian dollar denominated expenditures. On an annual basis the change in the
average U.S./Canadian dollar exchange rate resulted in an increase on Canadian dollar denominated
core capital expenditures of approximately $230 million. Capital spending during 2004 was primarily
focused on North American resource play properties. Natural gas capital expenditures were primarily
focused on continued development of the Companys key resource plays in Greater Sierra, Cutbank
Ridge and Shallow Gas in Canada, and Piceance, Jonah, East Texas and Fort Worth in the United
States. Crude oil capital spending in 2004 was concentrated at Foster Creek, Pelican Lake and
Suffield in Alberta and Weyburn in Saskatchewan. The Company drilled 4,923 net wells in 2004
compared to 5,581 net wells in 2003.
Canadian East Coast
In 2004, the Company participated in two deep water tests at Weymouth and Crimson. Both of these
wells were plugged and abandoned. As of December 31, 2004, the Companys investment in its East
Coast assets, including Deep Panuke, is recorded at approximately $371 million. Until assessments
of the economics of the Panuke project are complete, the timing of any potential start of
production and amount of additional costs which may be incurred are not determinable.
Gulf of Mexico
During 2004, the Companys operating partner completed a well test at the Tahiti oilfield which is
located 304 kilometres southwest of New Orleans. As of December 31, 2004, the Company had invested
approximately $394 million in the Gulf of Mexico, including Tahiti. The field is expected to begin
production in 2008. The Company has announced that it intends to sell its interests in the Gulf of
Mexico.
Reserves
Each year, EnCana engages independent qualified reserve evaluators to prepare reports on 100
percent of the Corporations oil and natural gas reserves. The Company has a Reserves Committee of
independent board members which reviews the qualifications and appointment of the independent
qualified reserve evaluators. The Committee also reviews the procedure for providing information to
the evaluators. EnCanas disclosure of reserves data is covered by NI 51-101 as amended by a Mutual
Reliance Review System Decision Document dated December 16, 2003 permitting the adoption of U.S.
reporting standards, including compliance with the practices and procedures of the U.S. Securities
and Exchange Commission (SEC) and Financial Accounting Standards Board (FASB) reserve reporting
requirements, in 2003. These standards require that reserves be estimated employing the single day
field price of the commodity at the effective date of the valuation - in this case December
31, 2004.
EnCanas proved natural gas reserves as at December 31, 2004, on an SEC constant price basis, totalled 10,460 Bcf. Extensions and discoveries resulting from successful exploration and development capital programs amounted to 2,431 Bcf. Downward revisions of 252 Bcf in the United States were largely the result of reduced reserve estimates per well in the northern and southern Rockies. Net acquisitions were dominated by the purchase of TBI in May 2004.
The Companys proved crude oil and natural gas liquids reserves as at December 31, 2004, on an SEC constant price basis, totalled 501 MMbbls. Extensions and discoveries resulting from successful exploration and development capital programs amounted to 163 MMbbls. Downward revisions in Canada were dominated by a 363 MMbbls adjustment at Foster Creek necessitated by reliance on year-end prices for bitumen determined in accordance with SEC and FASB requirements. If EnCana were applying the approach set out by the Canadian Securities Administrators in their Staff Notice 51-315, dated January 20, 2005, namely the use of the average price differential for the preceding 12 months, it is expected that no negative revisions to the companys proved bitumen reserves would occur. Divestitures were dominated by the sale of all of EnCanas interests in the U.K. central North Sea and non-core interests in Western Canada.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M13
Proved Reserves by Country
Constant Prices After Royalties | Natural Gas | Crude Oil and NGLs(1) | ||||||||||||||||||||||||||||||||||||||
2004 vs. | 2003 vs. | 2004 vs. | 2003 vs. | |||||||||||||||||||||||||||||||||||||
As at December 31 | 2004 | 2003 | 2003 | 2002 | 2002 | 2004 | 2003(2) | 2003 | 2002 | 2002 | ||||||||||||||||||||||||||||||
(billions of cubic feet) |
(millions of barrels) |
|||||||||||||||||||||||||||||||||||||||
Canada |
5,824 | 11 | % | 5,256 | 4 | % | 5,073 | 267 | -58 | % | 629 | 16 | % | 542 | ||||||||||||||||||||||||||
United States |
4,636 | 48 | % | 3,129 | 22 | % | 2,573 | 91 | 117 | % | 42 | 2 | % | 41 | ||||||||||||||||||||||||||
Ecuador |
| | | | | 143 | -12 | % | 162 | 4 | % | 156 | ||||||||||||||||||||||||||||
United Kingdom |
| -100 | % | 26 | 30 | % | 20 | | -100 | % | 124 | 28 | % | 97 | ||||||||||||||||||||||||||
Total |
10,460 | 24 | % | 8,411 | 10 | % | 7,666 | 501 | -48 | % | 957 | 14 | % | 836 | ||||||||||||||||||||||||||
(1) | NGLs include condensate. | |
(2) | Year-end 2004 Canadian Crude Oil and NGLs reserves were essentially unchanged from the previous year, prior to the bitumen revisions caused by an anomalously low December 31, 2004 field price. |
Proved Reserves Reconciliation by Country
Constant Prices After Royalties | Natural Gas | Crude Oil and NGLs(1) | ||||||||||||||||||||||||||||||||||
As at December 31, 2004 | (billions of cubic feet) | (millions of barrels) | ||||||||||||||||||||||||||||||||||
Canada | USA | UK | Total | Canada | USA | Ecuador | UK | Total | ||||||||||||||||||||||||||||
Beginning of year |
5,256 | 3,129 | 26 | 8,411 | 629 | 42 | 162 | 124 | 957 | |||||||||||||||||||||||||||
Revisions and improved recovery |
67 | (252 | ) | | (185 | ) | 32 | | (12 | ) | | 20 | ||||||||||||||||||||||||
Extensions and discoveries |
1,422 | 1,009 | | 2,431 | 94 | 48 | 21 | | 163 | |||||||||||||||||||||||||||
Acquisitions |
65 | 1,150 | 10 | 1,225 | 29 | 12 | | 10 | 51 | |||||||||||||||||||||||||||
Divestitures |
(215 | ) | (82 | ) | (25 | ) | (322 | ) | (97 | ) | (6 | ) | | (128 | ) | (231 | ) | |||||||||||||||||||
Production |
(771 | ) | (318 | ) | (11 | ) | (1,100 | ) | (57 | ) | (5 | ) | (28 | ) | (6 | ) | (96 | ) | ||||||||||||||||||
End of year before bitumen revisions |
5,824 | 4,636 | | 10,460 | 630 | (3) | 91 | 143 | | 864 | ||||||||||||||||||||||||||
Revisions due to bitumen price(2) |
| | | | (363 | ) | | | | (363 | ) | |||||||||||||||||||||||||
End of year |
5,824 | 4,636 | | 10,460 | 267 | 91 | 143 | | 501 | |||||||||||||||||||||||||||
(1) | NGLs include condensate. | |
(2) | As a result of using year-end price. | |
(3) | Year-end 2004 Canadian Crude Oil and NGLs reserves were essentially unchanged from the previous year, prior to the bitumen revisions caused by an anomalously low December 31, 2004 field price. |
MIDSTREAM & MARKET OPTIMIZATION CAPITAL EXPENDITURES
Expenditures in 2004 related primarily to ongoing improvements to midstream facilities.
CORPORATE CAPITAL EXPENDITURES
Corporate capital expenditures relate primarily to spending on business information systems,
leasehold improvements and furniture and office equipment.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M14
DISCONTINUED OPERATIONS
United Kingdom and Ecuador assets are presented as discontinued operations in the Consolidated Financial Statements. EnCanas net earnings from discontinued operations are $1,302 million and include a gain of $1,364 million on the discontinuance of U.K. operations, realized financial and commodity hedge losses of $358 million and unrealized financial and commodity hedge losses of $71 million. Summary information is presented below. Additional information concerning EnCanas discontinued operations can be found in Note 5 to EnCanas Consolidated Financial Statements.
UNITED KINGDOM
2004 | 2003 | 2002 | ||||||||||
Sales volumes |
||||||||||||
Produced Gas (million cubic feet per day) |
30 | 13 | 10 | |||||||||
Crude Oil (barrels per day) |
14,128 | 9,231 | 9,733 | |||||||||
NGLs (barrels per day) |
1,845 | 897 | 795 | |||||||||
Total (million cubic feet equivalent per day) |
126 | 74 | 73 | |||||||||
($ millions) |
||||||||||||
Net earnings (loss) from discontinued operations |
$ | 1,338 | $ | (7 | ) | $ | 24 | |||||
Capital Investment |
488 | 223 | 82 |
In December 2004, a subsidiary of the Company completed the sale of its U.K. central North Sea assets, production and prospects for net cash consideration of approximately $2.1 billion, resulting in a gain on sale of approximately $1.4 billion.
Liquids sales volumes in 2004 increased to 15,973 bbls/d from 10,128 bbls/d in 2003 primarily as a result of the acquisitions of additional interests in the Scott and Telford fields in October 2003 and February 2004. Higher transportation and selling expenses in 2004 compared to 2003 of $20 million were primarily due to higher product volumes. Operating expenses increased approximately $18 million in 2004 due to a platform turnaround, higher maintenance costs and higher volumes. Increased DD&A expense in 2004 of $44 million over 2003 was primarily due to increased volumes offset by a decrease in the DD&A rate.
ECUADOR
2004 | 2003 | 2002 | ||||||||||
Sales volumes |
||||||||||||
Crude Oil (barrels per day) |
77,993 | 46,521 | 29,740 | |||||||||
($ millions) |
||||||||||||
Net (loss) earnings from discontinued operations |
$ | (33 | ) | $ | 32 | $ | 45 | |||||
Capital Investment |
240 | 367 | 169 |
At December 31, 2004, EnCana has decided to sell its Ecuador operations, and accordingly the Ecuador operations have been accounted for as discontinued operations.
Sales volumes in 2004 increased 68 percent to average approximately 78,000 bbls/d. The increased sales volumes are primarily due to the combination of available capacity on the OCP pipeline in Ecuador and increased production from Block 15.
Production and mineral taxes were $36 million higher in 2004 compared to 2003 as a result of higher realized prices and volumes on the Tarapoa block. The Company is required to pay a percentage of revenue from this block to the Ecuador government based on realized prices over a base price. Operating costs were $42 million higher in 2004 compared to 2003 due to higher workover costs and increased fuel and diesel costs and higher maintenance and personnel costs on Block 15. DD&A expense increased $104 million compared to 2003 as a result of higher crude oil volumes.
Crude oil sales volumes increased 56 percent in 2003, compared to 2002, due to the inclusion of a full year of post merger volumes and the removal of transportation capacity constraints as a result of the commencement of shipments on the OCP pipeline in September 2003. Higher production and mineral taxes in 2003, compared to 2002 resulted from increased production from the Tarapoa block and higher realized prices from Tarapoa volumes. Transportation and selling costs were higher in 2003 and reflect the higher tariff on OCP pipeline compared to the SOTE pipeline system. Operating expenses and DD&A increased in 2003 compared to 2002 primarily due to higher crude oil volumes.
Contingency information concerning Ecuador discontinued operations is included in Note 5 to EnCanas Consolidated Financial Statements.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M15
LIQUIDITY AND CAPITAL RESOURCES
EnCanas cash flow from continuing operations was $4,605 million in 2004, up $470 million compared to 2003. The increase in cash flow was primarily due to increased revenues from the growth in sales volumes and higher commodity prices offset by higher realized commodity and currency hedging losses, an increase in the current tax provision and an increase in the U.S./Canadian dollar exchange rate.
During 2004, long-term debt plus the current portion of long-term debt increased $1,555 million. This increase resulted from the acquisition of TBI and capital spending offset by proceeds of dispositions and increased cash flow during 2004, including proceeds of $2.1 billion received from the sale of the U.K. assets on December 1, which were used to repay bank and other indebtedness. EnCanas net debt adjusted for working capital was $7,184 million as at December 31, 2004 compared with $5,544 million at December 31, 2003. Working capital was $558 million and included unrealized losses on mark-to-market accounting on derivatives of $95 million and a current tax payable of $359 million. This compares to a working capital of $544 million as at December 31, 2003. Cash flow together with proceeds from dispositions were used for the purchase of shares under the Companys Normal Course Issuer Bid and capital expenditures.
Net debt to capitalization at the end of 2004 is 33 percent, unchanged from 2003. Management calculates this ratio for internal purposes to steward the Companys overall debt position as a measure of a companys financial strength.
EnCanas long term credit ratings were confirmed by Standard & Poors and Dominion Bond Rating Services credit rating agencies in October 2004. Standard & Poors has affirmed an A with a Negative Outlook and Dominion Bond Rating Services has affirmed an A(low) with a Stable Trend. Moodys long-term credit rating for EnCana remains at Baa2 Stable. The agencies are expected to continue to monitor the Companys operating and financial performance through the first quarter of 2005.
On March 23, 2004 the Company redeemed all of its Coupon Reset Subordinated Term Securities, Series A (Term Securities) which had an aggregate principal amount of approximately C$126 million. The redemption price of the Term Securities was the principal amount plus accrued and unpaid interest to the redemption date.
In March 2004, an indirect wholly owned subsidiary, EnCana Holdings Finance Corp. (EHFC), filed a shelf prospectus whereby it may issue from time to time up to $2 billion of debt securities. Debt securities issued under this shelf prospectus are unconditionally guaranteed by EnCana Corporation. On May 13, 2004 EHFC completed a $1.0 billion unsecured public debt offering in the U.S. The notes, which are due in 2014, bear interest at 5.8 percent. The net proceeds of the offering were used to fund a portion of the acquisition of TBI.
After EnCanas acquisition of TBI, TBI and a subsidiary made a consent tender offer for $225 million for their 7.25 percent Senior Subordinated Notes. A total of 98.9 percent of the notes were tendered for a total cost of approximately $258 million. Subsequently, in December 2004 and January 2005, the balance of the notes were purchased for a total cost of approximately $2.9 million.
On August 4, 2004, EnCana completed a public offering in the United States for $250 million notes due in 2009 at 4.60 percent and $750 million notes due in 2034 at 6.50 percent. The proceeds from these issues were used primarily to repay existing bank and commercial paper indebtedness.
On August 9, 2004, EnCana redeemed all of its 8.50 percent Unsecured Junior Subordinated Debentures due 2048, which had an aggregate principal amount of C$200 million, at par plus accrued interest. On September 30, 2004, EnCana redeemed all of its 9.50 percent Preferred Securities due 2048, which had an aggregate principal amount of $150 million, at par.
In September 2004, EnCana filed a multi-jurisdictional shelf prospectus whereby it may issue from time to time up to $2 billion of debt securities. This shelf prospectus replaced EnCanas previous $2 billion U.S. debt shelf prospectus which expired on September 22, 2004. No amounts have been issued under the new shelf prospectus.
In October 2004, the Company completed the refinancing of its general corporate bank credit facilities. Under this refinancing, EnCanas core bank facilities were increased in size from C$4.0 billion to C$4.5 billion, and the term of the two tranches were extended to three and five years. In December, the bank credit facilities of a wholly owned U.S. subsidiary were increased from $300 million to $600 million, all in a five year term.
As at December 31, 2004, the Company had available unused committed bank credit facilities in the amount of $2.4 billion.
In October 2004, EnCana received approval from the Toronto Stock Exchange (TSX) to continue to purchase, for cancellation, Common Shares under a Normal Course Issuer Bid (the Bid). Under the Bid, EnCana was entitled to purchase for cancellation up to five percent of its Common Shares issued and outstanding on October 22, 2004 over a 12-month period ending October 28, 2005. As of December 31, 2004, EnCana had purchased for cancellation approximately 14.8 million of its shares under the Bid. In February 2005, EnCana received approval from the TSX to amend the Bid. Under the amended Bid, EnCana is entitled to purchase up to 46.1 million Common Shares (ten percent of the public float on October 22, 2004). Purchases may be made through the facilities of the TSX and the New York Stock Exchange, in accordance with the policies and rules of each exchange.
During 2004, EnCana purchased for cancellation a total of approximately 20 million shares for a total of approximately $1 billion under the terms of its Normal Course Issuer Bids.
Normal Course Issuer Bid
(millions) | Share Purchases | Number of shares | ||||||||||||||||||
2004 | 2003 | 2002 | Total | entitled to purchase | ||||||||||||||||
Bid expiring October 2003 |
| 20.2 | | 20.2 | 23.8 | |||||||||||||||
Bid expiring October 2004 |
5.5 | 3.6 | | 9.1 | 23.2 | |||||||||||||||
Bid expiring October 2005 |
14.8 | | | 14.8 | 46.1 | |||||||||||||||
20.3 | 23.8 | | 44.1 | |||||||||||||||||
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M16
OUTSTANDING SHARE DATA
The Company is authorized to issue an unlimited number of Common Shares, an unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares. The reduction of 10.3 million Common Shares outstanding from the end of 2003 to the end of 2004 (18.3 million from the end of 2002 to the end of 2003) results from the repurchase of 20.3 million shares in 2004 (23.8 million in 2003) under the Normal Course Issuer Bid and the issuance of 9.7 million Common Shares (5.5 million in 2003) under Option plans.
Share Capital Common Shares
($ millions) | 2004 | 2003 | 2002 | |||||||||
Common shares outstanding,
end of year |
450.3 | 460.6 | 478.9 | |||||||||
Weighted average common
shares outstanding diluted |
468.0 | 479.7 | 422.6 |
As at January 31, 2005, there were 446.5 million Common Shares outstanding. There were no Preferred Shares outstanding during these periods. Employees and directors have been granted options to purchase Common Shares under various plans. These plans and their terms and outstanding balances are disclosed in detail in Note 15 to the Consolidated Financial Statements.
Effective February 22, 2005 the Companys Board of Directors resolved to recommend the split of the Corporations outstanding Common Shares on a two-for-one basis (Share Split). EnCanas shareholders will be asked to approve the Share Split at its annual and special meeting to be held on April 27, 2005. In addition to shareholder approval, the Share Split is subject to the receipt of all required regulatory approvals. If approved by shareholders, and subject to regulatory approvals, each shareholder will receive one additional common share for each common share he or she holds on the record date for the Share Split of May 12, 2005. Pursuant to the rules of the Toronto Stock Exchange, EnCanas common shares will commence trading on a subdivided basis at the opening of business on May 10, 2005, which is the second trading day preceding the record date. Also on May 10, 2005, EnCanas common shares listed on the New York Stock Exchange (NYSE) will commence trading with rights entitling holders to an additional common share for each common share held upon the commencement of trading of the common shares on a subdivided basis on the NYSE. The trading of the common shares on a subdivided basis on the NYSE will occur one day after the delivery of share certificates to registered holders of EnCanas common shares. It is anticipated that share certificates representing the additional common shares resulting from the Share Split will be delivered to registered common shareholders on or about May 20, 2005.
The Compensation Committee of the Board of Directors, in 2003, approved a long-term incentive strategy for employees throughout EnCana which includes a significantly reduced level of stock option grants to be supplemented by grants of Performance Share Units (PSUs). In 2004, the Board of Directors approved a modification to the PSU plan that provides a reduced payout if relative ranking is below median. This change applies to units granted in both 2004 and 2005. PSUs will not result in the issue of new Common Shares by the Company. Stock options granted in 2004 have an associated Tandem Share Appreciation Right (TSAR) and employees may elect to exercise either the stock option or the associated TSAR. TSAR exercises will result in either cash payments by the Company or issuance of Common Shares.
As previously detailed in the Liquidity and Capital Resources section of this MD&A, the Company obtained regulatory approval under Canadian securities laws to purchase Common Shares under three consecutive Normal Course Issuer Bids which commenced in October 2002 and may continue until October 28, 2005. Under the terms of the bids, the Company repurchased for cancellation approximately 20 million Common Shares during 2004, and as of December 31, 2004, was entitled to purchase for cancellation an additional 8 million Common Shares. On February 4, 2005, EnCana received approval from the TSX to amend the Bid and increase the number of Common Shares available for purchase from five percent of the issued and outstanding shares on October 22, 2004 to ten percent of the public float. Under the amended Bid, EnCana is entitled to purchase for cancellation up to approximately 46.1 million Common Shares. To the date of the amendment, EnCana had purchased approximately 21.2 million Common Shares under the Bid, leaving approximately 24.9 million Common Shares available for purchase through the expiry of the Bid on October 28, 2005. Shareholders may obtain a copy of the Bid documents without charge at www.sedar.com or by contacting investor.relations@encana.com
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CONTRACTUAL OBLIGATIONS AND CONTINGENCIES
The Company has entered into various commitments primarily related to debt, demand charges on firm transportation agreements, capital commitments and marketing agreements. The following table summarizes the Companys contractual obligations at December 31, 2004:
Expected Payment Date | ||||||||||||||||||||
2006 to | 2008 to | |||||||||||||||||||
($ millions) | 2005 | 2007 | 2009 | 2010+ | Total | |||||||||||||||
Long-Term Debt |
$ | 188 | $ | 487 | $ | 841 | $ | 4,434 | $ | 5,950 | ||||||||||
Asset Retirement Obligations |
2 | 13 | | 3,680 | 3,695 | |||||||||||||||
Operating Leases(2) |
42 | 84 | 65 | 152 | 343 | |||||||||||||||
Pipeline Transportation |
297 | 499 | 402 | 1,010 | 2,208 | |||||||||||||||
Capital Commitments |
190 | 63 | 4 | 38 | 295 | |||||||||||||||
Purchase of Goods and Services |
121 | 37 | 12 | 5 | 175 | |||||||||||||||
Product Purchases |
171 | 57 | 48 | 134 | 410 | |||||||||||||||
1,011 | 1,240 | 1,372 | 9,453 | 13,076 | ||||||||||||||||
Discontinued operations (3) |
99 | 185 | 189 | 876 | 1,349 | |||||||||||||||
Total Contractual Obligations(1) |
$ | 1,110 | $ | 1,425 | $ | 1,561 | $ | 10,329 | $ | 14,425 | ||||||||||
(1) | In addition, the Company has made commitments related to its risk management program. See Note 17 to the Consolidated Financial Statements. The Company also has an obligation to fund its Pension Plan and Other Post Retirement Benefits as disclosed in Note 16 to the Consolidated Financial Statements. | |
(2) | Related to office space. | |
(3) | Primarily related to long term transportation commitments. |
In addition to the long-term debt payments outlined above, at December 31, 2004 the Company had $1,914 million outstanding related to Bankers Acceptances, Commercial Paper and LIBOR loans that are supported by revolving credit facilities and term loan borrowings. The Company intends and expects that it will have the ability to extend the term of this debt on an ongoing basis. Further details regarding the Companys long-term debt are described in Note 13 to the Consolidated Financial Statements.
Additional disclosure regarding the contractual obligations outlined above is included in Note 19 to the Consolidated Financial Statements.
As at December 31, 2004, EnCana had remained a party to long-term, fixed price, physical contracts with a current delivery of approximately 48 MMcf/d with varying terms and volumes through 2017. The total volume to be delivered within the terms of these contracts is 167 Bcf at a weighted average price of $3.71 per Mcf. At December 31, 2004, these transactions had an unrealized loss of $157 million.
Commitments and Contingencies associated with Ecuador discontinued operations are included in Note 5 to EnCanas Consolidated Financial Statements.
Variable Interest Entities (VIE)
In December 2004, an EnCana subsidiary finalized the purchase of certain oil and gas properties in
Texas for approximately $251 million. The purchase was facilitated by an unrelated party, which
holds the assets in trust for the Company. EnCana operates the properties, receives all the revenue
and pays all of the expenses associated with these properties. The assets will be transferred to
EnCana at the earliest of June 15, 2005 or upon the disposition of certain natural gas and crude
oil properties by EnCana. EnCana has determined that this relationship represents an interest in a
VIE and that EnCana is the primary beneficiary of the VIE. EnCana has included these properties in
its consolidated results from the date of acquisition. This subsidiary will not hold title to these
properties until an exchange transaction has been completed.
Off-Balance Sheet Arrangements
The Company does not have any off-balance sheet arrangements that have or are reasonably likely to
have an effect on its results of operations or financial condition.
Leases
As a normal course of business, the Company leases office space for personnel who support field
operations and corporate purposes.
Legal Proceedings Related to Discontinued Merchant Energy Operations
In July 2003, the Companys indirect wholly owned U.S. marketing subsidiary, WD Energy Services
Inc. (WD), concluded a settlement with the U.S. Commodity Futures Trading Commission (CFTC) of
a previously disclosed CFTC investigation. The investigation related to alleged inaccurate
reporting of natural gas trading information during 2000 and 2001 by former employees of WDs now
discontinued Houston-based merchant energy trading operation to energy industry publications that
compiled and reported index prices. All Houston-based merchant energy trading operations were
discontinued following the merger with AEC in 2002. Under the terms of the settlement, WD agreed to
pay a civil monetary penalty in the amount of $20 million without admitting or denying the findings
in the CFTCs order.
The Company and WD are defendants in a lawsuit filed by E. & J. Gallo Winery in the United States District Court in California and, along with other energy companies, are defendants in several other lawsuits in California (many of which are class actions) and three class action lawsuits filed in the United States District Court
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in New York. A motion by the Company and WD to dismiss the Gallo complaint on the basis that the Federal Energy Regulatory Commission had exclusive jurisdiction regarding this matter was not granted. The Gallo complaint claims damages in excess of $30 million, before potential trebling under California laws.
Most of the California lawsuits were transferred by the Judicial Panel on Multidistrict Litigation on a consolidated basis to the Nevada District Court and all of the New York lawsuits were consolidated in New York District Court by the plaintiffs application. The Nevada District Court has remanded the California State Court cases back to the California State Court for hearing. The California lawsuits relate to sales of natural gas in California from 1999 to the present and contain allegations that the defendants engaged in a conspiracy with unnamed competitors in the natural gas and derivatives market in California in violation of U.S. and California anti-trust and unfair competition laws to artificially raise the price of natural gas through various means including the illegal sharing of price information through online trading, price indices and wash trading. The New York lawsuits claim that the defendants alleged manipulation of natural gas price indices resulted in higher prices of natural gas futures and option contracts traded on the NYMEX from 2000 to 2002. EnCana Corporation has been dismissed from the New York lawsuits, leaving WD and several other companies unrelated to the Company as the remaining defendants. As is customary, the class actions do not specify the amount of damages claimed.
The Company and WD intend to vigorously defend against these claims; however, the Company cannot predict the outcome of these proceedings or any future proceedings against the Company, whether these proceedings would lead to monetary damages which could have a material adverse effect on the Companys financial position, or whether there will be other proceedings arising out of these allegations.
ACCOUNTING POLICIES AND ESTIMATES
CHANGES IN ACCOUNTING PRINCIPLES AND PRACTICES
Hedging Relationships
On January 1, 2004, the Company adopted the amendments made to the Canadian Institute of Chartered
Accountants (CICA) Accounting Guideline AcG-13 Hedging Relationships. Derivative instruments
outstanding at January 1, 2004 that did not qualify as a hedge under AcG-13 or were not designated
as a hedge, were recorded using the mark-to-market accounting method whereby their fair value was
recorded on the Consolidated Balance Sheet. The impact on the Companys Consolidated Financial
Statements at January 1, 2004 was an increase in assets of $145 million, an increase in liabilities
of $380 million and a net deferred loss of $235 million. These amounts are taken into net earnings
as the contracts expire. At December 31, 2004, there remains a net gain of $72 million to be
recognized as described in Note 2 to the Consolidated Financial Statements.
Consolidation of Variable Interest Entities
On November 1, 2004, the Company retroactively adopted the new CICA Accounting Guideline AcG-15
Consolidation of Variable Interest Entities. AcG-15 defines a variable interest entity (VIE) as
a legal entity in which either the total equity at risk is not sufficient to permit the entity to
finance its activities without additional subordinated financial support provided by other parties
or the equity owners lack a controlling financial interest. The guideline requires the enterprise
which absorbs the majority of a VIEs expected gains or losses, the primary beneficiary, to
consolidate the VIE.
The retroactive adoption of AcG-15 had no effect on EnCanas prior Consolidated Financial Statements.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Management is required to make judgments, assumptions and estimates in the application of generally
accepted accounting principles that have a significant impact on the financial results of the
Company. The following discussion outlines the accounting policies and practices that are critical
to determining EnCanas financial results.
Full Cost Accounting
EnCana follows the CICA guideline on full cost accounting in the oil and gas industry to account
for oil and gas properties. Under this method, all costs directly associated with the acquisition
of, exploration for, and the development of natural gas and crude oil reserves are capitalized on a
country-by-country cost centre basis and costs associated with production are expensed. The
capitalized costs are depreciated, depleted and amortized using the unit-of-production method based
on estimated proved reserves. Reserve estimates can have a significant impact on earnings, as they
are a key component in the calculation of DD&A. A downward revision in a reserve estimate could
result in a higher DD&A charge to earnings. In addition, if net capitalized costs are determined to
be in excess of the calculated ceiling, which is based largely on reserve estimates (see asset
impairment discussion below), the excess must be written off as an expense charged against
earnings. In the event of a property disposition, proceeds are normally deducted from the full cost
pool without recognition of a gain or loss unless there is a change in the DD&A rate of 20 percent
or greater.
Oil and Gas Reserves
All of EnCanas oil and gas reserves are evaluated and reported on by independent qualified reserve
evaluators. The estimation of reserves is a subjective process. Forecasts are based on engineering
data, projected future rates of production, estimated commodity price forecasts and the timing of
future expenditures, all of which are subject to numerous uncertainties and various
interpretations. Reserve estimates can be revised upward or downward based on the results of future
drilling, testing, production levels and economics of recovery based on cash flow forecasts.
Asset Impairments
Under full cost accounting, a ceiling test is performed to ensure that unamortized capitalized
costs in each cost centre do not exceed their fair value. An impairment loss is recognized in net
earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of
the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable
if the carrying amount exceeds the sum of the
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undiscounted cash flows from proved reserves. If the sum of the cash flows is less than carrying amount, the impairment loss is limited to an amount by which the carrying amount exceeds the sum of:
i) | the fair value of proved and probable reserves; and |
|||
ii) | the costs of unproved properties that have been subject to a separate impairment test. |
Asset Retirement Obligations
The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance
Sheet when identified and a reasonable estimate of fair value can be made. Asset retirement
obligations include those legal obligations where the Company will be required to retire tangible
long-lived assets such as producing well sites, offshore production platforms and natural gas
processing plants. These obligations also include items for which the Company has made promissory
estoppel. The asset retirement cost, equal to the initially estimated fair value of the asset
retirement obligation, is capitalized as part of the cost of the related long-lived asset.
Increases in the asset retirement obligation resulting from the passage of time are recorded as
accretion of asset retirement obligation in the Consolidated Statement of Earnings. Amounts
recorded for asset retirement obligations are based on estimates of reserves and on retirement
costs which will not be incurred for several years. Actual payments to settle the obligations may
differ from estimated amounts.
Goodwill
Goodwill, which represents the excess of purchase price over fair value of net assets acquired in
the merger with AEC and the acquisition of TBI, is assessed by the Company for impairment at least
annually. Goodwill was allocated to the business segments at the time of the above transactions
based on their respective book values compared to fair values. If it is determined that the fair
value of the assets and liabilities of the business segment is less than the book value of the
business segment at the time of assessment, an impairment amount is determined by deducting the
fair value from the book value and applying it against the book balance of goodwill. The offset is
charged to the Consolidated Statement of Earnings as additional DD&A.
Derivative Financial Instruments
Derivative financial instruments are used by the Company to manage its exposure to market risks
relating to commodity prices, foreign currency exchange rates and interest rates. The Companys
policy is not to utilize derivative financial instruments for speculative purposes.
The Company enters into financial transactions to reduce its exposure to price fluctuations with respect to a portion of its oil and gas production to help achieve returns on new projects, targeted returns on new investments and steady funding of growth projects or to mitigate market price risk associated with cash flows expected to be generated from budgeted capital programs. These transactions generally are swaps, collars or options and are generally entered into with major financial institutions or commodities trading institutions.
The Company may also utilize derivative financial instruments such as interest rate swap agreements to manage the fixed and floating interest rate mix of the Companys total debt portfolio and related overall cost of borrowing. The interest rate swap agreements involve the periodic exchange of payments, without the exchange of the normal principal amount upon which the payments are based, and are recorded as an adjustment of interest expense on the hedged debt instrument.
The Company may enter into hedges of its foreign currency exposures on foreign currency denominated long-term debt by entering into offsetting forward exchange contracts. Foreign exchange translation gains and losses on these instruments are accrued under other current, or non-current, assets or liabilities on the balance sheet and recognized in foreign exchange in the period to which they relate, offsetting the respective translation losses and gains recognized on the underlying foreign currency long-term debt. Premiums or discounts on these forward instruments are amortized as an adjustment of interest expense over the term of the contract.
The Company also purchases foreign exchange forward contracts to hedge anticipated sales to customers in the United States. Foreign exchange translation gains and losses on these instruments are recognized as an adjustment of the revenues when the sale is recorded.
Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net earnings. Realized gains or losses from financial derivatives are recognized in natural gas and crude oil revenues as the related production occurs. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third party market indicators.
In 2004, the Company elected not to designate any of its current price risk management activities as accounting hedges under AcG-13 and accordingly, accounts for all derivatives using the mark-to-market accounting method.
Pensions and Other Post Retirement Benefits
The Company accrues for its obligations under its employee benefit plans and the related costs, net
of plan assets.
The cost of pensions and other retirement benefits is actuarially determined using the projected benefit method based on length of service, and reflects Managements best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on the fair value of those assets. The obligation is discounted using a market interest rate at the beginning of the year on high quality corporate debt instruments.
Pension expense includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments and the amortization of the excess of the net actuarial gain or loss over ten percent of the greater of the benefit obligation and the fair value of plan assets. The amortization period covers the expected average remaining services lives of employees covered by the plans.
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Pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plan.
Pension costs are a component of compensation costs.
Performance Share Units (PSUs)
The PSU plans provide for a range of payouts, based on EnCanas performance relative to certain
peers.
The Company expenses the cost of PSUs based on expected payouts, however, the amounts to be paid, if any, may vary from the current estimate.
RISK MANAGEMENT
EnCanas results are affected by
| financial risks (including commodity price, foreign exchange, interest rate and credit risks) | |
| operational risks | |
| environmental, health, safety and security risks | |
| reputational risks |
FINANCIAL RISKS
The Company partially mitigates its exposure to financial risks through the use of various
financial instruments and physical contracts. The use of derivative instruments is governed under
formal policies approved by senior management, and is subject to limits established by the Board of
Directors. As a means of mitigating exposure to commodity price risk, the Company has entered into
various financial instrument agreements. The Companys policy is not to use derivative financial
instruments for speculative purposes. The details of these instruments, including any unrealized
gains or losses, as of December 31, 2004, are disclosed in Note 17 to the Consolidated Financial
Statements.
The Company has in place policies and procedures with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use, in the case of commodities, to the mitigation of price risk associated with cash flows expected to be generated from budgeted capital programs and in other cases to the mitigation of price risks for specific assets and obligations.
With respect to transactions involving proprietary production or assets, the financial instruments generally used by the Company are swaps, collars or options which are entered into with major financial institutions, integrated energy companies or commodities trading institutions.
Commodity Price
To partially mitigate the natural gas commodity price risk, the Company entered into swaps which
fix the AECO and NYMEX prices and collars and put options which fix the range of AECO and NYMEX
prices. To help protect against widening natural gas price differentials in various production
areas, the Company has entered into swaps to fix the AECO and Rockies price differential from the
NYMEX price. Physical contracts relating to these activities had an unrecognized loss of $9
million.
The Company has also entered into contracts to purchase and sell natural gas as part of its daily ongoing operations of the Companys proprietary production management. Physical contracts associated with this activity had an unrecognized gain of $43 million.
As part of its gas storage optimization program, EnCana has entered into financial instruments and physical contracts at various locations and terms over the next 15 months to partially manage the price volatility of the corresponding physical transactions and inventories. The financial instruments used include futures, fixed for floating swaps and basis swaps.
For crude oil price risk, the Company has partially mitigated its exposure to the WTI NYMEX price for a portion of its oil production with fixed price swaps, three-way put spreads and put options.
The Company has a power purchase arrangement contract that expires in 2005. This contract was entered into as part of a cost management strategy.
Foreign Exchange
As a means of mitigating the exposure to fluctuations in the U.S. to Canadian exchange rate, the
Company may enter into foreign exchange contracts. The Company also enters into foreign exchange
contracts in conjunction with crude oil marketing transactions. Gains or losses on these contracts
are recognized when the difference between the average month spot rate and the rate on the date of
settlement is determined.
The Company also maintains a mix of both U.S. dollar and Canadian dollar debt which helps to offset the exposure to the fluctuations in the U.S./Canadian dollar exchange rate. In addition to direct issuance of U.S. dollar denominated debt, the Company has entered into cross currency swaps on a portion of its debt as a means of managing the U.S./Canadian dollar debt mix.
Interest Rates
The Company partially mitigates its exposure to interest rate changes by maintaining a mix of both
fixed and floating rate debt. The Company has entered into interest rate swap transactions from
time to time as a means of managing the fixed/floating rate debt portfolio mix.
Credit Risk
The Company is exposed to credit related losses in the event of default by counterparties. The
Company does not expect any counterparties to fail to meet their obligations because of credit
practices that are in place that limit transactions to counterparties of investment grade credit
quality. A substantial portion of the Companys accounts receivable is with customers in the oil
and gas industry. Credit losses on the accounts receivable may arise as a result of non-performance
by customers on their contractual obligations. To manage the Companys exposure to credit losses,
Board-approved credit policies govern the Companys credit portfolio.
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OPERATIONAL RISK
EnCana mitigates operational risk through a number of policies and processes. As part of the
capital approval process, the Companys projects are evaluated on a fully risked basis, including
geological risk and engineering risk. In addition, the asset teams undertake a process called
Lookback and Learning. In this process, each asset team undertakes a thorough review of their
previous capital program to identify key learnings, which often includes operational issues that
positively and negatively impacted the projects results. Mitigation plans are developed for the
operational issues which had a negative impact on results. These mitigation plans are then
incorporated into the current year plan for the project. On an annual basis, these Lookback results
are analyzed for the Companys capital program with the results and identified learnings shared
across the Company.
All projects include a Business Risk Burden that is intended to account for the unforeseen risks.
The amount of Business Risk Burden that is used on a particular project depends on the projects
history of Lookback results and the type of expenditure.
A peer review process is used to ensure that capital projects are appropriately risked and that
knowledge is shared across the Company. Peer reviews are undertaken primarily for exploration
projects and early stage resource plays, although they may occur for any type of project.
The Company also partially mitigates operational risks by maintaining a comprehensive insurance program.
ENVIRONMENT, HEALTH, SAFETY AND SECURITY RISK
These risks are managed by executing policies and standards that comply with or exceed government
regulations and industry standards. In addition, the Company maintains a system that identifies,
assesses and controls safety and environmental risk and requires regular reporting to senior
management and the Board of Directors. The Corporate Responsibility, Environment, Health & Safety
Committee of EnCanas Board of Directors approves environmental policy and oversees compliance with
government laws and regulations. Monitoring and reporting programs for environmental, health and
safety performance in day-to-day operations, as well as inspections and assessments, are designed
to provide assurance that environmental and regulatory standards are met. Contingency plans are in
place for a timely response to an environmental event and remediation/reclamation strategies are
utilized to restore the environment.
Security risks are managed through a Security Program designed to ensure that EnCanas personnel and assets are protected. EnCana has also established an Investigations Committee with the mandate to address potential violations of Company policies and practices.
Kyoto Protocol
The Kyoto protocol, ratified by the Canadian Federal Government in December 2002, came into force
on February 16, 2005. The protocol commits Canada to reducing greenhouse gas emissions to six
percent below 1990 levels over the period 2008 2012. It is expected that the Federal Government
will make a substantive announcement outlining its Climate Change action plan coinciding with Kyoto
coming into force. The Climate Change Working Group of Canadian Association of Petroleum Producers
is working with the Federal and Alberta governments to develop an approach for implementing targets
and enabling greenhouse gas control legislation which protects the industrys competitiveness,
limits the cost and administrative burden of compliance and supports continued investment in the
sector.
As the federal government has yet to release its Kyoto compliance plan, EnCana is unable to predict the impact of the potential regulations upon its business; however, it is possible that the Company would face increases in operating costs in order to comply with greenhouse gas emissions legislation.
REPUTATIONAL RISK
EnCana takes a pro-active approach to the identification and management of issues that affect the
Companys reputation and has established consistent and clear procedures, guidelines and
responsibility for identifying and managing these issues. Issues affecting or with the potential to
affect EnCanas reputation are generally either emerging issues that can be identified early and
then managed or unforeseen issues that arise unexpectedly and must be managed on an urgent basis.
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OUTLOOK
Volume Outlook for Continuing Operations
2005 Guidance(2) | 2004 Actual | Increase in 2005 (3) | ||||||||
Produced Gas Sales (MMcf per day) |
||||||||||
Canada |
2,200 - 2,300 | 2,099 | 7 | % | ||||||
United States |
1,150 - 1,200 | 869 | 35 | % | ||||||
Total Produced Gas Sales |
3,350 - 3,500 | 2,968 | 15 | % | ||||||
Crude Oil and NGLs (Mbbls per day) |
||||||||||
Canada |
135 - 155 | 154 | -6 | % | ||||||
United States |
12 - 14 | 12 | 8 | % | ||||||
Total Crude Oil and NGLs |
150 - 170 | 166 | -4 | % | ||||||
Total (MMcfe per day) (1) |
4,250 - 4,500 | 3,966 | 10 | % | ||||||
(1) | Liquids converted to thousand cubic feet equivalent at 1 barrel = 6 thousand cubic feet. | |
(2) | Guidance released February 23, 2005. | |
(3) | Using mid-point of guidance. |
2005 Capital Investment for Continuing Operations
($ billions) | ||
Upstream |
$4.5 - $4.8 | |
Midstream & Marketing and Corporate |
0.4 - 0.4 | |
Core Capital |
$4.9 - $5.2 | |
EnCana plans to continue to focus principally on growing natural gas production and storage capacity in North America. The Company will also continue to invest in in situ oilsands development.
Strong natural gas storage injection requirements combined with reduced U.S. and Canadian supply have tightened the balance between supply and demand resulting in higher average natural gas prices in 2004. The outlook for 2005 and beyond will be impacted by weather, timing of new supplies and economic activity.
Volatility in crude oil prices is expected to continue in 2005 as a result of market uncertainties over continued demand growth in China, the reliability of production from key producing countries, and OPEC success at managing prices and the overall state of the world economies.
The Company expects its 2005 core capital investment program, of between $4.9 billion and $5.2 billion, to be funded from cash flow.
EnCanas results are affected by external market factors, such as fluctuations in the prices of crude oil and natural gas, as well as movements in foreign currency exchange rates. The following tables provide projected estimates for 2005 of the sensitivity of the Companys 2005 net earnings and cash flow to changes in commodity prices and the U.S./Canadian dollar exchange rate.
Sensitivity of 2005 Net Earnings From Continuing Operations and Cash Flow From Continuing Operations (Including Hedges)(1)(2)
Net Earnings | Cash Flow From | |||||||
From Continuing | Continuing | |||||||
($ millions) | Operations | Operations | ||||||
$0.25 per million British thermal units increase in the NYMEX gas price |
$ | 95 | $ | 135 | ||||
$1.00 per barrel increase in the WTI oil price |
15 | 15 | ||||||
$0.01 decrease in the U.S.\ Canadian dollar exchange rate |
(20 | ) | 5 | |||||
(1) | Hedge position as at December 31, 2004. | |
(2) | Based on forward curve commodity price and forward curve estimates dated December 31, 2004. |
Sensitivity of 2005 Net Earnings From Continuing Operations and Cash Flow From Continuing Operations (Excluding Hedges)(1)
Net Earnings | Cash Flow From | |||||||
From Continuing | Continuing | |||||||
($ millions) | Operations | Operations | ||||||
$0.25 per million British thermal units increase in the NYMEX gas price |
$ | 185 | $ | 185 | ||||
$1.00 per barrel increase in the WTI oil price |
25 | 25 | ||||||
$0.01 decrease in the U.S.\ Canadian dollar exchange rate |
(20 | ) | 5 | |||||
(1) | Based on forward curve commodity price and forward curve estimates dated December 31, 2004. |
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MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
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These estimates are based on managements assumptions utilized for 2005 planning purposes, as discussed in this section. Assumptions include certain levels and profiles of capital expenditures, projected asset disposals, operating costs, projected sales volumes, tax rates, interest rates, foreign currency exchange rates, inflation rates and other assumptions that impact operations. These assumptions can vary significantly from actual events and may result in material variances from the expected results.
In determining the current income tax expense deducted in arriving at these estimates, management has assumed a combined marginal tax rate of approximately 37 percent. This tax rate is itself affected in varying degrees by the assumptions referred to in the preceding paragraph.
ADVISORIES
FORWARD-LOOKING STATEMENTS
In the interest of providing EnCana shareholders and potential investors with information regarding
the Company and its subsidiaries, including managements assessment of EnCanas and its
subsidiaries future plans and operations, certain statements contained in this MD&A constitute
forward-looking statements within the meaning of the safe harbour provisions of the United States
Private Securities Litigation Reform Act of 1995. Forward-looking statements are typically
identified by words such as anticipate, believe, expect, plan, intend, forecast,
target, project or similar words suggesting future outcomes or statements regarding an outlook.
Forward-looking statements in this MD&A include, but are not limited to, statements with respect
to: production and sales estimates for produced gas, crude oil and NGLs for 2005 and beyond;
projections regarding Canadian and U.S. supply, demand and storage requirements; the Companys
plans to focus on growing natural gas production and storage capacity in North America and medium
and long-term growth prospects internationally; projections relating to the volatility of crude oil
prices in 2005 and the reasons therefor; amounts which may be issued under the Companys
multi-jurisdictional shelf prospectus program; the Companys projected capital investment levels
for 2005 and the source of funding therefor; the effect of the Companys risk management program,
including the impact of derivative financial instruments; the Companys execution of share
purchases under its Normal Course Issuer Bid; the Companys defence of lawsuits; projections and
assumptions relating to capital expenditures, operating costs, sales volumes, tax rates, interest
rates, foreign currency exchange rates, inflation rates and other variables impacting the Company
and its operations; projections relating to expenses under the Companys Performance Share Units
plan; anticipated asset retirement obligation expenses; the impact of the Kyoto Accord on operating
costs; projected tax rates and projected current taxes payable for 2005 and the adequacy of the
Companys provision for taxes; rating agency monitoring and reviews which may occur in the future;
and the projected impact of off-balance sheet arrangements.
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 Companys 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 risks and uncertainties include, among other things: volatility of oil and gas prices; fluctuations in currency and interest rates; product supply and demand; market competition; risks inherent in the Companys and its subsidiaries marketing operations, including credit risks; imprecision of reserve estimates and estimates of recoverable quantities of oil, natural gas and liquids from resource plays and other sources not currently classified as proved; the Companys and its subsidiaries 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; the Companys ability to access external sources of debt and equity capital; the timing and the costs of well and pipeline construction; the Companys and its subsidiaries ability to secure adequate product transportation; changes in environmental and other regulations or the interpretations of such regulations; political and economic conditions in the countries in which the Company and its subsidiaries operate, including Ecuador; the risk of international war, hostilities, civil insurrection and instability affecting countries in which the Company and its subsidiaries operate and terrorist threats; risks associated with existing and potential future lawsuits and regulatory actions made against the Company and its subsidiaries; and other risks and uncertainties described from time to time in the reports and filings made with securities regulatory authorities by EnCana. Statements relating to reserves or resources or resource potential are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described exist in the quantities predicted or estimated, and can be profitably produced in the future. 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. Furthermore, the forward-looking statements contained in this MD&A are made as of the date of this MD&A, and 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 MD&A are expressly qualified by this cautionary statement.
OIL AND GAS INFORMATION
EnCanas 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
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M24
Instrument 51-101 (NI 51-101). The reserves quantities disclosed by EnCana 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 EnCanas Annual Information Form.
Crude Oil, Natural Gas Liquids and Natural Gas Conversions
In this MD&A, certain crude oil and natural gas liquids (NGLs) volumes have been converted to
millions of cubic feet equivalent (MMcfe) or thousands of cubic feet equivalent (Mcfe) 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), thousands of BOE (MBOE) or millions of
BOE (MMBOE) on the same basis. MMcfe, Mcfe, BOE, MBOE and MMBOE 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 equivalency at the
well head.
Resource Play, Estimated Ultimate Recovery and Resource Potential
EnCana uses the terms resource play, estimated ultimate recovery and resource potential. Resource
play is a term used by EnCana to describe an accumulation of hydrocarbons known to exist over a
large areal expanse and/or thick vertical section, which when compared to a conventional play,
typically has a lower geological and/or commercial development risk and lower average decline rate.
As used by EnCana, estimated ultimate recovery has the meaning set out jointly by the Society of
Petroleum Engineers and World Petroleum Congress in the year 2000, being those quantities of
petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation,
plus those quantities already produced therefrom. Resource potential is a term used by EnCana to
refer to the estimated quantities of hydrocarbons that may be added to proved reserves over a
specified period of time largely from a specified resource play or plays. EnCanas current stated
estimates of unbooked resource potential utilize a five year time frame for their specified period
of time.
CURRENCY, NON-GAAP MEASURES AND REFERENCES TO ENCANA
All information included in this MD&A and the Consolidated Financial Statements and comparative
information is shown on a U.S. dollar, after-royalties basis unless otherwise noted. Sales
forecasts reflect the mid-point of current public guidance on an after royalties basis. Current
Corporate Guidance assumes a U.S. dollar exchange rate of $0.79 for every Canadian dollar.
Non-GAAP Measures
Certain measures in this MD&A do not have any standardized meaning as prescribed by Canadian
generally accepted accounting principles (Canadian GAAP) such as Cash Flow from Continuing
Operations, Cash Flow, Cash Flow from Continuing Operations per share-basic, Cash Flow from
Continuing Operations per share-diluted, Cash Flow per share-basic and Cash Flow per share-diluted,
Operating Earnings and Operating Earnings per share-diluted, Operating Earnings from Continuing
Operations and Operating Earnings from Continuing Operations per share diluted and therefore are
considered non-GAAP measures. Therefore, these measures may not be comparable to similar measures
presented by other issuers. These measures have been described and presented in this MD&A in order
to provide shareholders and potential investors with additional information regarding the Companys
liquidity and its ability to generate funds to finance its operations. Managements use of these
measures has been disclosed further in this MD&A as these measures are discussed and presented.
References To EnCana
For convenience, references in this MD&A to EnCana, the Company, we, us and our may,
where applicable, refer only to or include any relevant direct and indirect subsidiary corporations
and partnerships (Subsidiaries) of EnCana Corporation, and the assets, activities and initiatives
of such Subsidiaries.
Additional Information
Further information regarding EnCana Corporation can be accessed under the Companys public filings
found at www.sedar.com and on the Companys website at
www.encana.com.
ENCANA CORPORATION 2004
MANAGEMENTS DISCUSSION AND ANALYSIS (PREPARED IN US$)
M25
EnCana Corporation
CONSOLIDATED FINANCIAL
STATEMENTS
Prepared in US$
For the Year Ended December 31, 2004
MANAGEMENT REPORT
The accompanying Consolidated Financial Statements of EnCana Corporation are the responsibility of Management. The financial statements have been prepared by Management in United States dollars in accordance with Canadian Generally Accepted Accounting Principles and include certain estimates that reflect Managements best judgments. Financial information contained throughout the annual report is consistent with these financial statements.
Management has overall responsibility for internal controls and has developed and maintains an extensive system of internal controls that provides reasonable assurance that all transactions are accurately recorded, that the financial statements realistically report the Companys operating and financial results and that the Companys assets are safeguarded. The Companys Internal Audit department reviews and evaluates the adequacy of and compliance with the Companys internal controls. The policy of the Company is to maintain the highest standard of ethics in all its activities and it has a written business conduct and ethics practice.
The Companys Board of Directors has approved the information contained in the financial statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee, which has a written mandate that complies with the current requirements of the United States Sarbanes-Oxley Act of 2002 and voluntarily complies, in principle, with the Audit Committee guidelines of the New York Stock Exchange and the Toronto Stock Exchange. The Audit Committee meets at least on a quarterly basis.
PricewaterhouseCoopers LLP, an independent firm of chartered accountants, was appointed by a vote of shareholders at the Companys last annual meeting to audit the Consolidated Financial Statements and provide an independent opinion.
(signed) Gwyn Morgan President & Chief Executive Officer |
(signed) John D. Watson Executive Vice-President & Chief Financial Officer |
February 7, 2005
1
AUDITORS REPORT
To the Shareholders of EnCana Corporation
We have audited the Consolidated Balance Sheets of EnCana Corporation as at December 31, 2004 and December 31, 2003 and the Consolidated Statements of Earnings, Retained Earnings and Cash Flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Companys Management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation.
In our opinion, these Consolidated Financial Statements present fairly, in all material respects, the financial position of the Company as at December 31, 2004 and December 31, 2003 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004 in accordance with Canadian generally accepted accounting principles.
(signed)
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada
February 7, 2005
Comments by Auditor for U.S. readers on Canada-U.S. Reporting Differences
In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Companys financial statements, such as the changes described in Note 2 to the Consolidated Financial Statements. Our report to the shareholders dated February 7, 2005 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors report when the change is properly accounted for and adequately disclosed in the financial statements.
(signed)
PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta
Canada
February 7, 2005
2
U.S. Dollars
EnCana Corporation
Consolidated Statement of Earnings
For the years ended December 31, | ||||||||||||||||||
($ millions, except per share amounts) | 2004 | 2003 | 2002 | |||||||||||||||
Revenues, Net of Royalties |
(Note 4) | |||||||||||||||||
Upstream |
$ | 7,256 | $ | 5,797 | $ | 3,326 | ||||||||||||
Midstream & Market Optimization |
4,749 | 3,887 | 2,594 | |||||||||||||||
Corporate |
(195 | ) | 2 | 8 | ||||||||||||||
11,810 | 9,686 | 5,928 | ||||||||||||||||
Expenses |
(Note 4) | |||||||||||||||||
Production and mineral taxes |
311 | 164 | 105 | |||||||||||||||
Transportation and selling |
499 | 484 | 332 | |||||||||||||||
Operating |
1,350 | 1,196 | 749 | |||||||||||||||
Purchased product |
4,276 | 3,455 | 2,200 | |||||||||||||||
Depreciation, depletion and amortization |
2,402 | 1,989 | 1,186 | |||||||||||||||
Administrative |
197 | 173 | 118 | |||||||||||||||
Interest, net |
(Note 7) | 397 | 283 | 286 | ||||||||||||||
Accretion of asset retirement obligation |
(Note 14) | 22 | 17 | 13 | ||||||||||||||
Foreign exchange gain |
(Note 8) | (417 | ) | (598 | ) | (11 | ) | |||||||||||
Stock-based compensation |
17 | 18 | | |||||||||||||||
Gain on dispositions |
(Note 6) | (113 | ) | (1 | ) | (33 | ) | |||||||||||
8,941 | 7,180 | 4,945 | ||||||||||||||||
Net Earnings Before Income Tax |
2,869 | 2,506 | 983 | |||||||||||||||
Income tax expense |
(Note 9) | 658 | 364 | 317 | ||||||||||||||
Net Earnings From Continuing Operations |
2,211 | 2,142 | 666 | |||||||||||||||
Net Earnings From Discontinued Operations |
(Note 5) | 1,302 | 218 | 146 | ||||||||||||||
Net Earnings |
$ | 3,513 | $ | 2,360 | $ | 812 | ||||||||||||
Net Earnings From Continuing Operations per Common Share |
(Note 18) | |||||||||||||||||
Basic |
$ | 4.80 | $ | 4.52 | $ | 1.59 | ||||||||||||
Diluted |
$ | 4.72 | $ | 4.47 | $ | 1.58 | ||||||||||||
Net Earnings per Common Share |
(Note 18) | |||||||||||||||||
Basic |
$ | 7.63 | $ | 4.98 | $ | 1.94 | ||||||||||||
Diluted |
$ | 7.51 | $ | 4.92 | $ | 1.92 | ||||||||||||
Consolidated Statement of Retained Earnings
For the years ended December 31, | ||||||||||||||||||
($ millions) | 2004 | 2003 | 2002 | |||||||||||||||
Retained Earnings, Beginning of Year |
$ | 5,276 | $ | 3,523 | $ | 2,819 | ||||||||||||
Net Earnings |
3,513 | 2,360 | 812 | |||||||||||||||
Dividends on Common Shares |
(183 | ) | (139 | ) | (108 | ) | ||||||||||||
Charges for Normal Course Issuer Bid |
(Note 15) | (671 | ) | (468 | ) | | ||||||||||||
Retained Earnings, End of Year |
$ | 7,935 | $ | 5,276 | $ | 3,523 | ||||||||||||
See accompanying notes to Consolidated Financial Statements.
3
U.S. Dollars
EnCana Corporation
Consolidated Balance Sheet
As at December 31, | |||||||||||||
($ millions) | 2004 | 2003 | |||||||||||
Assets |
|||||||||||||
Current Assets |
|||||||||||||
Cash and cash equivalents |
$ | 602 | $ | 113 | |||||||||
Accounts receivable and accrued revenues |
1,898 | 1,165 | |||||||||||
Risk management |
(Notes 2, 17) | 336 | | ||||||||||
Inventories |
(Note 10) | 513 | 557 | ||||||||||
Assets of discontinued operations |
(Note 5) | 156 | 781 | ||||||||||
3,505 | 2,616 | ||||||||||||
Property, Plant and Equipment, net |
(Notes 4, 11) | 23,140 | 17,770 | ||||||||||
Investments and Other Assets |
(Note 12) | 334 | 268 | ||||||||||
Risk Management |
(Notes 2, 17) | 87 | | ||||||||||
Assets of Discontinued Operations |
(Note 5) | 1,623 | 1,545 | ||||||||||
Goodwill |
2,524 | 1,911 | |||||||||||
(Note 4) | $ | 31,213 | $ | 24,110 | |||||||||
Liabilities and Shareholders Equity |
|||||||||||||
Current Liabilities |
|||||||||||||
Accounts payable and accrued liabilities |
$ | 1,879 | $ | 1,348 | |||||||||
Income tax payable |
359 | 32 | |||||||||||
Risk management |
(Notes 2, 17) | 241 | | ||||||||||
Liabilities of discontinued operations |
(Note 5) | 280 | 405 | ||||||||||
Current portion of long-term debt |
(Note 13) | 188 | 287 | ||||||||||
2,947 | 2,072 | ||||||||||||
Long-Term Debt |
(Note 13) | 7,742 | 6,088 | ||||||||||
Other Liabilities |
118 | 21 | |||||||||||
Risk Management |
(Notes 2, 17) | 192 | | ||||||||||
Asset Retirement Obligation |
(Note 14) | 611 | 383 | ||||||||||
Liabilities of Discontinued Operations |
(Note 5) | 102 | 112 | ||||||||||
Future Income Taxes |
(Note 9) | 5,193 | 4,156 | ||||||||||
16,905 | 12,832 | ||||||||||||
Commitments and Contingencies |
(Note 19) | ||||||||||||
Shareholders Equity |
|||||||||||||
Share capital |
(Note 15) | 5,299 | 5,305 | ||||||||||
Share options, net |
10 | 55 | |||||||||||
Paid in surplus |
28 | 18 | |||||||||||
Retained earnings |
7,935 | 5,276 | |||||||||||
Foreign currency translation adjustment |
1,036 | 624 | |||||||||||
14,308 | 11,278 | ||||||||||||
$ | 31,213 | $ | 24,110 | ||||||||||
See accompanying notes to Consolidated Financial Statements.
Approved by the Board
(signed) David P. OBrien Director |
(signed) Barry W. Harrison Director |
4
U.S. Dollars
EnCana Corporation
Consolidated Statement of Cash Flows
For the years ended December 31, | ||||||||||||||||||
($ millions) | 2004 | 2003 | 2002 | |||||||||||||||
Operating Activities |
||||||||||||||||||
Net earnings from continuing operations |
$ | 2,211 | $ | 2,142 | $ | 666 | ||||||||||||
Depreciation, depletion and amortization |
2,402 | 1,989 | 1,186 | |||||||||||||||
Future income taxes |
(Note 9) | 91 | 477 | 383 | ||||||||||||||
Unrealized loss on risk management |
(Note 17) | 190 | | | ||||||||||||||
Unrealized foreign exchange gain |
(Note 8) | (285 | ) | (545 | ) | (23 | ) | |||||||||||
Accretion of asset retirement obligation |
(Note 14) | 22 | 17 | 13 | ||||||||||||||
Gain on dispositions |
(Note 6) | (113 | ) | (1 | ) | (33 | ) | |||||||||||
Other |
87 | 56 | (133 | ) | ||||||||||||||
Cash flow from continuing operations |
4,605 | 4,135 | 2,059 | |||||||||||||||
Cash flow from discontinued operations |
375 | 324 | 360 | |||||||||||||||
Cash flow |
4,980 | 4,459 | 2,419 | |||||||||||||||
Net change in other assets and liabilities |
(176 | ) | (84 | ) | (17 | ) | ||||||||||||
Net change in non-cash working capital from continuing operations |
(Note 18) | 1,455 | (568 | ) | (889 | ) | ||||||||||||
Net change in non-cash working capital from discontinued operations |
(1,668 | ) | 497 | 104 | ||||||||||||||
4,591 | 4,304 | 1,617 | ||||||||||||||||
Investing Activities |
||||||||||||||||||
Business combinations |
(Note 3) | (2,335 | ) | | (80 | ) | ||||||||||||
Capital expenditures |
(Note 4) | (4,817 | ) | (4,627 | ) | (2,771 | ) | |||||||||||
Proceeds on disposal of assets |
(Note 4) | 1,144 | 301 | 363 | ||||||||||||||
Dispositions (acquisitions) |
(Note 6) | 386 | (91 | ) | 60 | |||||||||||||
Equity investments |
47 | (6 | ) | | ||||||||||||||
Net change in investments and other |
45 | (15 | ) | 39 | ||||||||||||||
Net change in non-cash working capital from continuing operations |
(Note 18) | (21 | ) | (113 | ) | 195 | ||||||||||||
Discontinued operations |
1,292 | 822 | (401 | ) | ||||||||||||||
(4,259 | ) | (3,729 | ) | (2,595 | ) | |||||||||||||
Financing Activities |
||||||||||||||||||
Net issuance of revolving long-term debt |
72 | 288 | | |||||||||||||||
Issuance of long-term debt |
3,761 | 500 | 1,506 | |||||||||||||||
Repayment of long-term debt |
(2,759 | ) | (142 | ) | (1,206 | ) | ||||||||||||
Issuance of common shares |
(Note 15) | 281 | 114 | 88 | ||||||||||||||
Purchase of common shares |
(Note 15) | (1,004 | ) | (868 | ) | | ||||||||||||
Dividends on common shares |
(183 | ) | (139 | ) | (108 | ) | ||||||||||||
Other |
(5 | ) | (13 | ) | (54 | ) | ||||||||||||
Discontinued operations |
| (282 | ) | 272 | ||||||||||||||
163 | (542 | ) | 498 | |||||||||||||||
Deduct: Foreign Exchange Loss (Gain) on Cash and
Cash Equivalents Held in Foreign Currency |
6 | 10 | (2 | ) | ||||||||||||||
Increase (Decrease) in Cash and Cash Equivalents |
489 | 23 | (478 | ) | ||||||||||||||
Cash and Cash Equivalents, Beginning of Year |
113 | 90 | 568 | |||||||||||||||
Cash and Cash Equivalents, End of Year |
$ | 602 | $ | 113 | $ | 90 | ||||||||||||
Supplemental Cash Flow Information |
(Note 18) |
See accompanying notes to Consolidated Financial Statements.
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are expressed in United States (U.S.) dollars. EnCana has adopted the U.S. dollar as its reporting currency since most of its revenue is closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American upstream exploration and development companies. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars.
EnCana is in the business of exploration for, production and marketing of natural gas, crude oil and natural gas liquids, as well as natural gas storage, natural gas liquids processing and power generation operations.
A) Principles of Consolidation
The 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. Information prepared in accordance with generally accepted accounting principles in the United States is included in Note 20.
Investments in jointly controlled companies, jointly controlled partnerships (collectively called affiliates) and unincorporated joint ventures are accounted for using the proportionate consolidation method, whereby EnCanas proportionate share of revenues, expenses, assets and liabilities are included in the accounts.
Investments in companies and partnerships in which EnCana does not have direct or joint control over the strategic operating, investing and financing decisions, but does have significant influence on them, are accounted for using the equity method.
B) Foreign Currency Translation
The accounts of self-sustaining operations are translated using the current rate method, whereby assets and liabilities are translated at period-end exchange rates, while revenues and expenses are translated using average rates over the period. Translation gains and losses relating to the self-sustaining operations are included as a separate component of shareholders equity.
Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated into its functional currency at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings.
C) Measurement Uncertainty
The timely preparation of the Consolidated Financial Statements in conformity with Canadian generally accepted accounting principles requires that Management make estimates and assumptions and use judgment regarding the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
Amounts recorded for depreciation, depletion and amortization, asset retirement costs and obligations and amounts used for ceiling test and impairment calculations are based on estimates of natural gas and crude oil reserves and future costs required to develop those reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs, and the related future cash flows are subject to measurement uncertainty, and the impact in the consolidated financial statements of future periods could be material.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
The values of pension assets and obligations and the amount of pension costs charged to net earnings depend on certain actuarial and economic assumptions which by their nature are subject to measurement uncertainty.
The amount of compensation expense accrued for long-term performance based compensation arrangements are subject to Managements best estimate of whether or not the performance criteria will be met and what the ultimate payout will be.
D) Revenue Recognition
Revenues associated with the sales of EnCanas natural gas, crude oil and natural gas liquids (NGLs) are recognized when title passes from the Company to its customer. Natural gas and crude oil produced and sold by EnCana below or above its working interest share in the related resource properties results in production underliftings or overliftings. Underliftings are recorded as inventory and overliftings are recorded as deferred revenue. Realized gains and losses from the Companys commodity price risk management activities are recorded in revenue when the product is sold.
Marketing revenues and purchased product are recorded on a gross basis as the Company takes title to product and has risks and rewards of ownership. Revenues associated with the services provided where EnCana acts as agent are recorded as the services are provided. Revenues associated with the sale of natural gas storage services are recognized when the services are provided. Sales of electric power are recognized when power is provided to the customer.
Unrealized gains and losses from the Companys commodity price risk management activities are recorded as revenue based on the related mark-to-market calculations at the end of the respective period.
E) Production and Mineral Taxes
Costs paid by EnCana to non-mineral interest owners based on production of natural gas, crude oil and NGLs are recognized when the product is produced.
F) Transportation and Selling Costs
Costs paid by EnCana for the transportation and selling of natural gas, crude oil and NGLs are recognized when the product is delivered and the services provided.
G) Employee Benefit Plans
EnCana accrues for its obligations under its employee benefit plans and the related costs, net of plan assets.
The cost of pensions and other retirement and post-employment benefits is actuarially determined using the projected benefit method based on length of service, and reflects Managements best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on the fair value of those assets. The obligation is discounted using a market interest rate at the beginning of the year on high quality corporate debt instruments.
Pension expense includes the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of the net transitional obligation, the amortization of adjustments arising from pension plan amendments and the amortization of the excess of the net actuarial gain or loss over 10 percent of the greater of the benefit obligation and the fair value of plan assets. The amortization period covers the expected
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
average remaining service lives of employees covered by the plans.
Pension expense for the defined contribution pension plans is recorded as the benefits are earned by the employees covered by the plans.
H) Income Taxes
EnCana follows the liability method of accounting for income taxes. Under this method, future income taxes are recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in earnings in the period that the change occurs.
I) Earnings Per Share Amounts
Basic net earnings per common share is computed by dividing the net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per share amounts are calculated giving effect to the potential dilution that would occur if stock options were exercised or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price.
J) Cash and Cash Equivalents
Cash and cash equivalents include short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased.
K) Inventories
Product inventories are valued at the lower of average cost and net realizable value on a first-in, first-out basis. Materials and supplies are valued at cost.
L) Property, Plant and Equipment
Upstream
EnCana accounts for natural gas and crude oil properties in accordance with the Canadian Institute of Chartered Accountants guideline on full cost accounting in the oil and gas industry. Under this method, all costs directly associated with the acquisition of, exploration for and the development of, natural gas and crude oil reserves, including asset retirement costs, are capitalized on a country-by-country cost centre basis.
Costs accumulated within each cost centre are depreciated, depleted and amortized using the unit-of-production method based on estimated proved reserves determined using estimated future prices and costs. For purposes of this calculation, oil is converted to gas on an energy equivalent basis. Capitalized costs subject to depletion include estimated future costs to be incurred in developing proved reserves. Proceeds from the disposal of properties are normally deducted from the full cost pool without recognition of gain or loss unless that deduction would result in a change to the rate of depreciation, depletion and amortization of 20 percent or greater in which case a gain or loss is recorded. Costs of major development projects and costs of acquiring and evaluating significant unproved properties are excluded, on a cost centre basis, from costs subject to depletion until it is determined whether or not proved reserves are attributable to the properties, or impairment has occurred. Costs that have been impaired are included in the costs subject to depreciation, depletion and amortization.
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
An impairment loss is recognized in net earnings when the carrying amount of a cost centre is not recoverable and the carrying amount of the cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of:
i. | the fair value of proved and probable reserves; and | |||
ii. | the costs of unproved properties that have been subject to a separate impairment test. |
Midstream
Midstream facilities, including natural gas storage facilities, natural gas liquids extraction plant facilities and power generation facilities, are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 20 to 25 years. Capital assets related to pipelines are carried at cost and depreciated or amortized using the straight-line method over their economic lives, which range from 20 to 35 years.
Corporate
Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from 3 to 25 years.
M) Capitalization of Costs
Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred.
Interest is capitalized during the construction phase of large capital projects.
N) Amortization of Other Assets
Amortization of deferred items included in Investments and Other Assets is provided for, where applicable, on a straight-line basis over the estimated useful lives of the assets.
O) Goodwill
Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed by the Company for impairment at least annually. Goodwill and all other assets and liabilities have been allocated to business levels, within the Companys segments, referred to as reporting units. To assess impairment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is determined by deducting the fair value of the reporting units assets and liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the book value of the reporting units goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount.
P) Asset Retirement Obligation
The fair value of estimated asset retirement obligations is recognized in the Consolidated Balance Sheet when identified and a reasonable estimate of fair value can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, offshore production platforms and natural gas processing
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
plants. These obligations also include items for which the Company has made promissory estoppel. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost.
Asset retirement costs for natural gas and crude oil assets are amortized using the unit-of-production method. Amortization of asset retirement costs are included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.
Actual expenditures incurred are charged against the accumulated obligation.
Q) Stock-based Compensation
EnCana records compensation expense in the Consolidated Financial Statements for stock options granted to employees and directors using the fair value method. Fair values are determined using the Black-Scholes option-pricing model. Compensation costs are recognized over the vesting period.
Obligations for cash payments under the Companys share appreciation rights, tandem share appreciation rights, deferred share units and performance share units are accrued as compensation expense over the vesting period. Fluctuations in the price of EnCanas common shares will change the accrued compensation expense and are recognized when they occur.
R) Derivative Financial Instruments
Derivative instruments that do not qualify as hedges, or are not designated as hedges, are recorded using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net earnings. Realized gains or losses from financial derivatives related to commodity prices are recognized in natural gas and crude oil revenues as the related sales occur. Unrealized gains and losses are recognized in revenues at the end of each respective reporting period. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third party market indications and forecasts.
Derivative financial instruments are used by EnCana to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. The Companys policy is not to utilize derivative financial instruments for speculative purposes.
EnCana has in place policies and procedures with respect to the required documentation and approvals for the use of derivative financial instruments and specifically ties their use, in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated from budgeted capital programs, and in other cases to the mitigation of market price risks for specific assets and obligations. When applicable, the Company identifies relationships between financial instruments and anticipated transactions, as well as its risk management objective and the strategy for undertaking the economic hedge transaction. Where specific financial instruments are executed, the Company assesses, both at the time of purchase and on an ongoing basis, whether the financial instrument used in the particular transaction is effective in offsetting changes in fair values or cash flows of the transaction.
S) Reclassification
Certain information provided for prior years has been reclassified to conform to the presentation adopted in 2004.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
NOTE 2. CHANGES IN ACCOUNTING POLICIES AND PRACTICES
A) Hedging Relationships
On January 1, 2004, EnCana adopted the amendments made to the Canadian Institute of Chartered Accountants Accounting Guideline 13 (AcG 13) Hedging Relationships, and Emerging Issues Committee Abstract 128 (EIC 128) Accounting for Trading, Speculative or Non Trading Derivative Financial Instruments. Derivative instruments that do not qualify as a hedge under AcG 13, or are not designated as a hedge, are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in fair value recognized in net earnings. The Company elected not to designate any of its risk management activities in place at December 31, 2003 as accounting hedges under AcG 13 and, accordingly, accounted for all these non-hedging derivatives using the mark-to-market accounting method.
The impact on EnCanas Consolidated Financial Statements at January 1, 2004, resulted in the recognition of risk management assets with a fair value of $145 million, risk management liabilities with a fair value of $380 million and a net deferred loss of $235 million. At December 31, 2004, a net unrealized gain remains to be recognized over the next four years as follows:
Unrealized Gain | ||||||||
2005 |
||||||||
3 months ended March 31 |
$ | | ||||||
3 months ended June 30 |
14 | |||||||
3 months ended September 30 |
9 | |||||||
3 months ended December 31 |
9 | |||||||
Total to be recognized in 2005 |
$ | 32 | ||||||
2006 |
$ | 24 | ||||||
2007 |
15 | |||||||
2008 |
1 | |||||||
Total to be recognized in 2006 through to 2008 |
$ | 40 | ||||||
Total to be recognized |
$ | 72 | ||||||
Total to be
recognized Continuing Operations |
$ | 73 | ||||||
Total to be
recognized Discontinued Operations |
(1 | ) | ||||||
$ | 72 | |||||||
At December 31, 2004, the remaining net deferred amounts recognized on transition are recorded in the Consolidated Balance Sheet as follows:
As at December 31 | 2004 | |||
Accounts receivable and accrued revenues |
$ | 11 | ||
Investments and other assets |
4 | |||
Accounts payable and accrued liabilities |
44 | |||
Other liabilities |
44 | |||
Total Net
Deferred Gain Continuing Operations |
$ | 73 | ||
Total Net
Deferred Loss Discontinued Operations |
(1 | ) | ||
Total Net Deferred Gain |
$ | 72 | ||
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
B) Consolidation of Variable Interest Entities
On November 1, 2004, the Company retroactively adopted the new CICA Accounting Guideline 15 (AcG 15) Consolidation of Variable Interest Entities. AcG 15 defines a variable interest entity (VIE) as a legal entity in which either the total equity at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support provided by other parties or the equity owners lack a controlling financial interest. The guideline requires the enterprise which absorbs the majority of a VIEs expected gains or losses, the primary beneficiary, to consolidate the VIE.
There was no effect on EnCanas Consolidated Financial Statements prior to the adoption of the guideline on November 1, 2004. Subsequent to November 1, 2004, the Company became the primary beneficiary of a VIE. At December 31, 2004, EnCana has consolidated this VIE as described in Note 4.
NOTE 3. BUSINESS COMBINATIONS
TOM BROWN, INC. (TBI)
On May 19, 2004, EnCana, through a wholly owned subsidiary, completed the tender offer for the shares of Tom Brown, Inc. (TBI), a Denver based independent energy company, for total cash consideration of $2.3 billion plus the assumption of $406 million of long-term debt.
As part of the acquisition, EnCana acquired certain natural gas and crude oil properties in west Texas and New Mexico and the assets of Sauer Drilling Company, a subsidiary of TBI, which were designated as assets held for sale at the date of acquisition. These assets were sold on July 30, 2004.
ALBERTA ENERGY COMPANY LTD. (AEC)
On April 5, 2002, PanCanadian Energy Corporation (PanCanadian) and Alberta Energy Company Ltd. completed a plan of arrangement (the Arrangement) under the Business Corporations Act (Alberta). The Arrangement included a common share exchange, pursuant to which holders of common shares of AEC received 1.472 common shares of PanCanadian for each common share of AEC that they held. PanCanadian then changed its name to EnCana Corporation.
These business combinations have been accounted for using the purchase method with the results of operations included in the Consolidated Financial Statements from the dates of acquisition.
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
The calculation of the purchase prices and the allocations to assets and liabilities is shown below:
TBI | AEC | |||||||
Calculation of Purchase Price: |
||||||||
Common Shares issued to AEC shareholders (millions) |
218.5 | |||||||
Price of Common Shares (C$ per common share) |
38.43 | |||||||
Value of Common Shares issued |
$ | 5,281 | ||||||
Fair value of AEC share options exchanged for share options of
EnCana Corporation (Share options) |
105 | |||||||
Cash paid for common shares of TBI |
$ | 2,341 | ||||||
Transaction costs |
13 | 94 | ||||||
Total purchase price |
$ | 2,354 | $ | 5,480 | ||||
Plus: Fair value of liabilities assumed |
||||||||
Current liabilities |
224 | 1,120 | ||||||
Long-term debt (including preferred securities) |
406 | 3,714 | ||||||
Other non-current liabilities |
39 | 180 | ||||||
Future income taxes |
774 | 1,665 | ||||||
Total Purchase Price and Liabilities Assumed |
$ | 3,797 | $ | 12,159 | ||||
Fair Value of Assets Acquired: |
||||||||
Current assets (including cash acquired) |
$ | 425 | $ | 946 | ||||
Property, plant and equipment, net |
2,890 | 8,897 | ||||||
Other non-current assets |
9 | 381 | ||||||
Goodwill |
473 | 1,935 | ||||||
Total Fair Value of Assets Acquired |
$ | 3,797 | $ | 12,159 | ||||
Goodwill Allocation: |
||||||||
Upstream |
$ | 473 | $ | 1,504 | ||||
Midstream & Market Optimization |
| 49 | ||||||
473 | 1,553 | |||||||
Discontinued Operations |
| 382 | ||||||
Total Goodwill Allocation |
$ | 473 | $ | 1,935 | ||||
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
NOTE 4. SEGMENTED INFORMATION
The Company has defined its continuing operations into the following segments:
| Upstream includes the Companys exploration for, and development and production of, natural gas, crude oil and natural gas liquids and other related activities. The majority of the Companys Upstream operations are located in Canada and the United States. International new venture exploration is mainly focused on opportunities in Africa, South America, the Middle East and Greenland. | |||
| Midstream & Market Optimization is conducted by the Midstream & Marketing division. Midstream includes natural gas storage, natural gas liquids processing and power generation. The Marketing groups primary responsibility is the sale of the Companys proprietary production. These results are included in the Upstream segment. Correspondingly, the Marketing groups also undertake market optimization activities which comprise 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 Midstream & Market Optimization segment. | |||
| Corporate includes unrealized gains or losses recorded on derivative instruments. Once amounts are settled, the realized gains and losses are recorded in the operating segment to which the derivative relates. |
Midstream & Market Optimization purchases substantially all of the Companys North American Upstream production. Transactions between business segments are based on market values and eliminated on consolidation. The tables in this note present financial information on an after eliminations basis.
Operations that have been discontinued are disclosed in Note 5.
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Results of Continuing Operations (for the years ended December 31)
Midstream & Market | |||||||||||||||||||||||||
Upstream | Optimization | ||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
Revenues, Net of Royalties |
$ | 7,256 | $ | 5,797 | $ | 3,326 | $ | 4,749 | $ | 3,887 | $ | 2,594 | |||||||||||||
Expenses |
|||||||||||||||||||||||||
Production and mineral taxes |
311 | 164 | 105 | | | | |||||||||||||||||||
Transportation and selling |
472 | 429 | 245 | 27 | 55 | 87 | |||||||||||||||||||
Operating |
1,026 | 872 | 562 | 325 | 324 | 187 | |||||||||||||||||||
Purchased product |
| | | 4,276 | 3,455 | 2,200 | |||||||||||||||||||
Depreciation, depletion and amortization |
2,271 | 1,900 | 1,115 | 70 | 48 | 36 | |||||||||||||||||||
Segment Income |
$ | 3,176 | $ | 2,432 | $ | 1,299 | $ | 51 | $ | 5 | $ | 84 | |||||||||||||
Corporate | Consolidated | ||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
Revenues, Net of Royalties |
$ | (195 | ) | $ | 2 | $ | 8 | $ | 11,810 | $ | 9,686 | $ | 5,928 | ||||||||||||
Expenses |
|||||||||||||||||||||||||
Production and mineral taxes |
| | | 311 | 164 | 105 | |||||||||||||||||||
Transportation and selling |
| | | 499 | 484 | 332 | |||||||||||||||||||
Operating |
(1 | ) | | | 1,350 | 1,196 | 749 | ||||||||||||||||||
Purchased product |
| | | 4,276 | 3,455 | 2,200 | |||||||||||||||||||
Depreciation, depletion and amortization |
61 | 41 | 35 | 2,402 | 1,989 | 1,186 | |||||||||||||||||||
Segment Income |
$ | (255 | ) | $ | (39 | ) | $ | (27 | ) | 2,972 | 2,398 | 1,356 | |||||||||||||
Administrative |
197 | 173 | 118 | ||||||||||||||||||||||
Interest, net |
397 | 283 | 286 | ||||||||||||||||||||||
Accretion of asset retirement obligation |
22 | 17 | 13 | ||||||||||||||||||||||
Foreign exchange gain |
(417 | ) | (598 | ) | (11 | ) | |||||||||||||||||||
Stock-based compensation |
17 | 18 | | ||||||||||||||||||||||
Gain on dispositions |
(113 | ) | (1 | ) | (33 | ) | |||||||||||||||||||
103 | (108 | ) | 373 | ||||||||||||||||||||||
Net Earnings Before Income Tax |
2,869 | 2,506 | 983 | ||||||||||||||||||||||
Income tax expense |
658 | 364 | 317 | ||||||||||||||||||||||
Net Earnings From Continuing Operations |
$ | 2,211 | $ | 2,142 | $ | 666 | |||||||||||||||||||
Results of Continuing Operations (for the years ended December 31)
Canada | United States | ||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
Revenues, Net of Royalties |
$ | 5,083 | $ | 4,474 | $ | 2,796 | $ | 1,941 | $ | 1,143 | $ | 454 | |||||||||||||
Expenses |
|||||||||||||||||||||||||
Production and mineral taxes |
87 | 56 | 70 | 224 | 108 | 35 | |||||||||||||||||||
Transportation and selling |
352 | 343 | 186 | 120 | 86 | 59 | |||||||||||||||||||
Operating |
685 | 642 | 456 | 119 | 60 | 35 | |||||||||||||||||||
Depreciation, depletion and amortization |
1,751 | 1,511 | 862 | 475 | 293 | 202 | |||||||||||||||||||
Segment Income |
$ | 2,208 | $ | 1,922 | $ | 1,222 | $ | 1,003 | $ | 596 | $ | 123 | |||||||||||||
Other | Total Upstream | ||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
Revenues, Net of Royalties |
$ | 232 | $ | 180 | $ | 76 | $ | 7,256 | $ | 5,797 | $ | 3,326 | |||||||||||||
Expenses |
|||||||||||||||||||||||||
Production and mineral taxes |
| | | 311 | 164 | 105 | |||||||||||||||||||
Transportation and selling |
| | | 472 | 429 | 245 | |||||||||||||||||||
Operating |
222 | 170 | 71 | 1,026 | 872 | 562 | |||||||||||||||||||
Depreciation, depletion and amortization |
45 | 96 | 51 | 2,271 | 1,900 | 1,115 | |||||||||||||||||||
Segment Income |
$ | (35 | ) | $ | (86 | ) | $ | (46 | ) | $ | 3,176 | $ | 2,432 | $ | 1,299 | ||||||||||
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Total Midstream & Market | ||||||||||||||||||||||||||||||||||||||
Midstream | Market Optimization | Optimization | ||||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||||
Revenues |
$ | 1,450 | $ | 1,084 | $ | 440 | $ | 3,299 | $ | 2,803 | $ | 2,154 | $ | 4,749 | $ | 3,887 | $ | 2,594 | ||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||
Transportation and selling |
| | | 27 | 55 | 87 | 27 | 55 | 87 | |||||||||||||||||||||||||||||
Operating |
279 | 261 | 174 | 46 | 63 | 13 | 325 | 324 | 187 | |||||||||||||||||||||||||||||
Purchased product |
1,071 | 762 | 169 | 3,205 | 2,693 | 2,031 | 4,276 | 3,455 | 2,200 | |||||||||||||||||||||||||||||
Depreciation, depletion and amortization |
68 | 40 | 24 | 2 | 8 | 12 | 70 | 48 | 36 | |||||||||||||||||||||||||||||
Segment Income |
$ | 32 | $ | 21 | $ | 73 | $ | 19 | $ | (16 | ) | $ | 11 | $ | 51 | $ | 5 | $ | 84 | |||||||||||||||||||
Upstream Geographic and Product Information (Continuing Operations) (for the years ended December 31)
Produced Gas | ||||||||||||||||||||||||||||||||||||||
Canada | United States | Total | ||||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||||
Revenues, Net of Royalties |
$ | 3,928 | $ | 3,396 | $ | 1,882 | $ | 1,776 | $ | 1,051 | $ | 398 | $ | 5,704 | $ | 4,447 | $ | 2,280 | ||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
65 | 52 | 50 | 205 | 101 | 32 | 270 | 153 | 82 | |||||||||||||||||||||||||||||
Transportation and selling |
296 | 274 | 151 | 120 | 86 | 59 | 416 | 360 | 210 | |||||||||||||||||||||||||||||
Operating |
400 | 342 | 255 | 119 | 60 | 35 | 519 | 402 | 290 | |||||||||||||||||||||||||||||
Operating Cash Flow |
$ | 3,167 | $ | 2,728 | $ | 1,426 | $ | 1,332 | $ | 804 | $ | 272 | $ | 4,499 | $ | 3,532 | $ | 1,698 | ||||||||||||||||||||
Oil and NGLs | ||||||||||||||||||||||||||||||||||||||
Canada | United States | Total | ||||||||||||||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||||
Revenues, Net of Royalties |
$ | 1,155 | $ | 1,078 | $ | 914 | $ | 165 | $ | 92 | $ | 56 | $ | 1,320 | $ | 1,170 | $ | 970 | ||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||||
Production and mineral taxes |
22 | 4 | 20 | 19 | 7 | 3 | 41 | 11 | 23 | |||||||||||||||||||||||||||||
Transportation and selling |
56 | 69 | 35 | | | | 56 | 69 | 35 | |||||||||||||||||||||||||||||
Operating |
285 | 300 | 201 | | | | 285 | 300 | 201 | |||||||||||||||||||||||||||||
Operating Cash Flow |
$ | 792 | $ | 705 | $ | 658 | $ | 146 | $ | 85 | $ | 53 | $ | 938 | $ | 790 | $ | 711 | ||||||||||||||||||||
Other | Total Upstream | ||||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
Revenues, Net of Royalties |
$ | 232 | $ | 180 | $ | 76 | $ | 7,256 | $ | 5,797 | $ | 3,326 | |||||||||||||
Expenses |
|||||||||||||||||||||||||
Production and mineral taxes |
| | | 311 | 164 | 105 | |||||||||||||||||||
Transportation and selling |
| | | 472 | 429 | 245 | |||||||||||||||||||
Operating |
222 | 170 | 71 | 1,026 | 872 | 562 | |||||||||||||||||||
Operating Cash Flow |
$ | 10 | $ | 10 | $ | 5 | $ | 5,447 | $ | 4,332 | $ | 2,414 | |||||||||||||
Capital Expenditures (Continuing Operations)
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Upstream |
||||||||||||||
Canada |
$ | 3,079 | $ | 3,198 | $ | 1,388 | ||||||||
United States |
1,549 | 968 | 1,176 | |||||||||||
Other Countries |
79 | 78 | 117 | |||||||||||
4,707 | 4,244 | 2,681 | ||||||||||||
Midstream & Market Optimization |
64 | 276 | 47 | |||||||||||
Corporate |
46 | 107 | 43 | |||||||||||
Total |
$ | 4,817 | $ | 4,627 | $ | 2,771 | ||||||||
16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
On December 17, 2004, EnCana acquired certain natural gas and crude oil properties in Texas for approximately $251 million. The purchase was facilitated by an unrelated party, Brown Ranger LLC, which holds the assets in trust for the Company. Pursuant to the agreement with Brown Ranger LLC, EnCana operates the properties, receives all the revenue and pays all of the expenses associated with the properties. The assets will be transferred to EnCana at the earlier of June 15, 2005 or upon the disposition of certain natural gas and crude oil properties by EnCana. EnCana has determined that the relationship with Brown Ranger LLC represents an interest in a VIE and that EnCana is the primary beneficiary of the VIE. EnCana has consolidated Brown Ranger LLC from the date of acquisition.
In addition to the capital expenditures, during 2004, EnCana divested of mature conventional oil and gas assets and other property, plant and equipment for proceeds of $1,144 million (2003 $301 million; 2002 $363 million).
Additions to Goodwill
There was one addition to goodwill during 2004 (2003 none) as a result of the business combination with Tom Brown, Inc. (see Note 3).
Property, Plant and Equipment and Total Assets
Property, Plant and | |||||||||||||||||||||
As at December 31 | Equipment | Total Assets | |||||||||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||||||||||
Upstream |
$ | 22,097 | $ | 16,757 | $ | 26,118 | $ | 19,416 | |||||||||||||
Midstream & Market Optimization |
804 | 784 | 1,904 | 1,879 | |||||||||||||||||
Corporate |
239 | 229 | 1,412 | 489 | |||||||||||||||||
Assets of Discontinued Operations |
(Note 5) | 1,779 | 2,326 | ||||||||||||||||||
Total |
$ | 23,140 | $ | 17,770 | $ | 31,213 | $ | 24,110 | |||||||||||||
Export Sales
Sales of natural gas, crude oil and natural gas liquids produced or purchased in Canada made
outside of Canada were $1,747 million (2003 $1,484 million; 2002 $1,333 million).
Major Customers
In connection with the marketing and sale of EnCanas own and purchased natural gas and crude oil,
for the year ended December 31, 2004, the Company had one
customer (2003 two) which individually accounted for more than 10 percent of its consolidated revenues, net of royalties. Sales to this
customer, a major international integrated energy company with a high quality investment grade
credit rating, were approximately $1,709 million (2003 $1,362 million).
NOTE 5. DISCONTINUED OPERATIONS
2004
On December 1, 2004, the Company completed the sale of its 100 percent interest in EnCana (U.K.) Limited for net cash consideration of approximately $2.1 billion. EnCanas U.K. operations included crude oil and natural gas interests in the U.K. central North Sea including the Buzzard, Scott and Telford oil fields, as well as other satellite discoveries and exploration licenses. A gain on sale of approximately $1.4 billion was recorded. Accordingly, these operations have been accounted for as discontinued operations.
At December 31, 2004, EnCana has decided to divest of its Ecuador operations and such operations have been accounted for as discontinued operations. EnCanas Ecuador operations include the 100 percent working interest in the Tarapoa Block, majority operating interest in Blocks 14, 17 and
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Shiripuno, the non-operated economic interest in Block 15 and the 36.3 percent indirect equity investment in Oleoducto de Crudos Pesados (OCP) Ltd. (OCP), which is the owner of a crude oil pipeline in Ecuador that ships crude oil from the producing areas of Ecuador to an export marine terminal. The Company is a shipper on the OCP Pipeline and pays commercial rates for tariffs. The majority of the Companys crude oil produced in Ecuador is sold to a single marketing company. Payments are secured by letters of credit from a major financial institution which has a high quality investment grade credit rating.
2003
In 2003, in two separate transactions, the Company completed the sale of its 13.75 percent working interest and a gross overriding royalty in the Syncrude Joint Venture (Syncrude) for net cash consideration of $999 million.
2002
On April 24, 2002, the Company adopted formal plans to exit from the Houston-based merchant energy operation, which were completed in 2002. These operations were included in the Midstream & Market Optimization segment. Accordingly, these operations have been accounted for as discontinued operations.
On November 19, 2002, the Company announced that it had entered into agreements to sell its discontinued pipelines operations for approximately $1 billion including the assumption of long-term debt by the purchaser. On January 2, 2003 and January 9, 2003, these sales were completed resulting in an after-tax gain on sale of $169 million.
CONSOLIDATED STATEMENT OF EARNINGS
The following tables present the effect of discontinued operations in the Consolidated Statement of Earnings:
2004
Upstream United Kingdom
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Revenues, Net of Royalties |
$ | 153 | $ | 118 | $ | 103 | ||||||||
Expenses |
||||||||||||||
Transportation and selling |
36 | 16 | 11 | |||||||||||
Operating |
36 | 18 | 11 | |||||||||||
Depreciation, depletion and amortization |
118 | 74 | 39 | |||||||||||
Interest, net |
(9 | ) | | | ||||||||||
Accretion of asset retirement obligation |
3 | 1 | | |||||||||||
Foreign exchange gain |
(2 | ) | (5 | ) | (3 | ) | ||||||||
(Gain) loss on disposition |
(1 | ) | 1 | | ||||||||||
(Gain) loss on discontinuance |
(1,364 | ) | | | ||||||||||
(1,183 | ) | 105 | 58 | |||||||||||
Net Earnings Before Income Tax |
1,336 | 13 | 45 | |||||||||||
Income tax (recovery) expense |
(2 | ) | 20 | 21 | ||||||||||
Net Earnings (Loss) From Discontinued Operations |
$ | 1,338 | $ | (7 | ) | $ | 24 | |||||||
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Upstream Ecuador
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Revenues, Net of Royalties |
$ | 471 | $ | 412 | $ | 245 | ||||||||
Expenses |
||||||||||||||
Production and mineral taxes |
61 | 25 | 14 | |||||||||||
Transportation and selling |
60 | 45 | 21 | |||||||||||
Operating |
125 | 83 | 53 | |||||||||||
Depreciation, depletion and amortization |
263 | 159 | 79 | |||||||||||
Administrative |
| | 1 | |||||||||||
Interest, net |
(3 | ) | 4 | 4 | ||||||||||
Accretion of asset retirement obligation |
1 | 1 | | |||||||||||
Foreign exchange loss |
5 | 2 | | |||||||||||
512 | 319 | 172 | ||||||||||||
Net (Loss) Earnings Before Income Tax |
(41 | ) | 93 | 73 | ||||||||||
Income tax (recovery) expense |
(8 | ) | 61 | 28 | ||||||||||
Net (Loss) Earnings From Discontinued Operations |
$ | (33 | ) | $ | 32 | $ | 45 | |||||||
2003
Upstream Syncrude
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Revenues, Net of Royalties |
$ | (1 | ) | $ | 87 | $ | 232 | |||||||
Expenses |
||||||||||||||
Transportation and selling |
| 2 | 3 | |||||||||||
Operating |
| 46 | 105 | |||||||||||
Depreciation, depletion and amortization |
| 7 | 16 | |||||||||||
Interest, net |
| | 1 | |||||||||||
Loss on discontinuance |
2 | | | |||||||||||
2 | 55 | 125 | ||||||||||||
Net (Loss) Earnings Before Income Tax |
(3 | ) | 32 | 107 | ||||||||||
Income tax expense |
| 8 | 28 | |||||||||||
Net (Loss) Earnings From Discontinued Operations |
$ | (3 | ) | $ | 24 | $ | 79 | |||||||
2002
Midstream & Market Optimization
For the years ended December 31 | Merchant Energy | Midstream Pipelines | Total | |||||||||||||||||||||||
2003 | 2002 | 2003 | 2002 | 2003 | 2002 | |||||||||||||||||||||
Revenues |
$ | | $ | 922 | $ | | $ | 135 | $ | | $ | 1,057 | ||||||||||||||
Expenses |
||||||||||||||||||||||||||
Operating |
| | | 50 | | 50 | ||||||||||||||||||||
Purchased product |
| 931 | | | | 931 | ||||||||||||||||||||
Depreciation, depletion and
amortization |
| | | 18 | | 18 | ||||||||||||||||||||
Administrative |
| 22 | | | | 22 | ||||||||||||||||||||
Interest, net |
| | | 19 | | 19 | ||||||||||||||||||||
Foreign exchange gain |
| | | (3 | ) | | (3 | ) | ||||||||||||||||||
Loss (gain) on discontinuance |
| 19 | (220 | ) | | (220 | ) | 19 | ||||||||||||||||||
| 972 | (220 | ) | 84 | (220 | ) | 1,056 | |||||||||||||||||||
Net (Loss) Earnings Before Income Tax |
| (50 | ) | 220 | 51 | 220 | 1 | |||||||||||||||||||
Income tax (recovery) expense |
| (17 | ) | 51 | 20 | 51 | 3 | |||||||||||||||||||
Net (Loss) Earnings From
Discontinued Operations |
$ | | $ | (33 | ) | $ | 169 | $ | 31 | $ | 169 | $ | (2 | ) | ||||||||||||
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Consolidated Total
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Revenues, Net of Royalties |
$ | 623 | $ | 617 | $ | 1,637 | ||||||||
Expenses |
||||||||||||||
Production and mineral taxes |
61 | 25 | 14 | |||||||||||
Transportation and selling |
96 | 63 | 35 | |||||||||||
Operating |
161 | 147 | 219 | |||||||||||
Purchased product |
| | 931 | |||||||||||
Depreciation, depletion and amortization |
381 | 240 | 152 | |||||||||||
Administrative |
| | 23 | |||||||||||
Interest, net |
(12 | ) | 4 | 24 | ||||||||||
Accretion of asset retirement obligation |
4 | 2 | | |||||||||||
Foreign exchange loss (gain) |
3 | (3 | ) | (6 | ) | |||||||||
(Gain) loss on disposition |
(1 | ) | 1 | | ||||||||||
(Gain) loss on discontinuance |
(1,362 | ) | (220 | ) | 19 | |||||||||
(669 | ) | 259 | 1,411 | |||||||||||
Net Earnings Before Income Tax |
1,292 | 358 | 226 | |||||||||||
Income tax (recovery) expense |
(10 | ) | 140 | 80 | ||||||||||
Net Earnings From Discontinued Operations |
$ | 1,302 | $ | 218 | $ | 146 | ||||||||
CONSOLIDATED BALANCE SHEET
The impact of the discontinued operations in the Consolidated Balance Sheet is as follows:
As at December 31 | 2004 | 2003 | |||||||
Assets |
|||||||||
Cash and cash equivalents |
$ | 14 | $ | 35 | |||||
Accounts receivable and accrued revenues |
124 | 202 | |||||||
Risk management |
3 | | |||||||
Inventories |
15 | 16 | |||||||
156 | 253 | ||||||||
Property, plant and equipment, net |
1,295 | 1,775 | |||||||
Investments and other assets |
328 | 298 | |||||||
$ | 1,779 | $ | 2,326 | ||||||
Liabilities |
|||||||||
Accounts payable and accrued liabilities |
$ | 96 | $ | 231 | |||||
Income tax payable |
101 | 33 | |||||||
Risk management |
72 | | |||||||
269 | 264 | ||||||||
Asset retirement obligation |
22 | 47 | |||||||
Future income taxes |
91 | 206 | |||||||
382 | 517 | ||||||||
Net Assets of Discontinued Operations |
$ | 1,397 | $ | 1,809 | |||||
The prices used in the ceiling test evaluation of the Companys crude oil reserves in Ecuador at December 31, 2004 were as follows:
% increase to | |||||||||||||||||||||||||||||
2005 | 2006 | 2007 | 2008 | 2009 | 2016 | ||||||||||||||||||||||||
Crude Oil ($/barrel) |
$ | 33.27 | $ | 29.89 | $ | 23.47 | $ | 23.43 | $ | 23.45 | 13 | % | |||||||||||||||||
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Acquisition / Disposition
On January 31, 2003, the Company acquired the Ecuador interests of Vintage Petroleum Inc. (Vintage) for net cash consideration of $116 million. During the fourth quarter of 2003, the Company disposed of its interest in Block 27 in Ecuador for approximately $14 million.
Commitments and Contingencies
The Company is a shipper on the OCP Pipeline and has tariff commitments as follows:
As at December 31, 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | |||||||||||||||||||||||||||
Pipeline Transportation |
$ | 99 | $ | 93 | $ | 92 | $ | 93 | $ | 95 | $ | 837 | $ | 1,309 | ||||||||||||||||||||
In Ecuador, a subsidiary of EnCana has a 40 percent non-operated economic interest in relation to Block 15 pursuant to a contract with a subsidiary of Occidental Petroleum Corporation. During the year, Occidental Petroleum Corporation filed a Form 8-K indicating that its subsidiary had received formal notification from Petroecuador, the state oil company of Ecuador, initiating proceedings to determine if the subsidiary had violated the Hydrocarbons Law and its Participation Contract for Block 15 with Petroecuador and whether such violations constitute grounds for terminating the Participation Contract.
In its Form 8-K, Occidental Petroleum Corporation indicated that it believes that it has complied with all material obligations under the Participation Contract and that any termination of the Participation Contract by Ecuador based upon these stated allegations would be unfounded and would constitute an unlawful expropriation under international treaties.
In addition to the above, the Company is proceeding with its arbitration related to value-added tax (VAT) owed to EnCana ($139 million at December 31, 2004). EnCana is also in discussions related to certain income tax matters related to the deductibility of interest expense in Ecuador.
NOTE 6. DISPOSITIONS (ACQUISITIONS)
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Acquisitions |
||||||||||||||
Petrovera Resources |
$ | (253 | ) | $ | | $ | | |||||||
Savannah |
| (91 | ) | | ||||||||||
Other |
(34 | ) | | | ||||||||||
(287 | ) | (91 | ) | | ||||||||||
Dispositions |
||||||||||||||
Petrovera Resources |
540 | | | |||||||||||
Alberta Ethane Gathering System Joint Venture |
108 | | | |||||||||||
Kingston CoGen Limited Partnership |
25 | | | |||||||||||
EnCana Suffield Gas Pipeline Inc. |
| | 60 | |||||||||||
673 | | 60 | ||||||||||||
$ | 386 | $ | (91 | ) | $ | 60 | ||||||||
On December 22, 2004 EnCana completed the disposition of its interest in the Alberta Ethane Gathering System Joint Venture for approximately $108 million, including working capital. A $54 million pre-tax gain was recorded on this sale.
On December 15, 2004, EnCana sold its 25 percent limited partnership interest in the Kingston CoGen Limited Partnership (Kingston) for net cash consideration of $25 million. A pre-tax gain of $28 million was recorded on this sale.
21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
In March 2004, the Company sold its equity investment in a well servicing company for approximately $44 million, recording a pre-tax gain on sale of $34 million.
On February 18, 2004, the Company sold its 53.3 percent interest in Petrovera Resources for approximately $287 million, including working capital adjustments. In order to facilitate the transaction, the Company purchased the 46.7 percent interest of its partner for approximately $253 million, including working capital adjustments, and then sold the 100 percent interest for a total of approximately $540 million, including working capital adjustments. In accordance with full cost accounting for oil and gas activities, proceeds were credited to property, plant and equipment.
On July 18, 2003, the Company acquired the common shares of Savannah Energy Inc. (Savannah) for net cash consideration of $91 million. Savannahs operations are in Texas, U.S.A.
In 2002, the Company sold its interest in EnCana Suffield Gas Pipeline Inc. for $60 million, recording a pre-tax gain on sale of $33 million.
NOTE 7. INTEREST, NET
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Interest
Expense Long-Term Debt |
$ | 385 | $ | 281 | $ | 252 | ||||||||
Early Retirement of Long-Term Debt |
(16 | ) | | 34 | ||||||||||
Interest
Expense Other |
42 | 20 | 10 | |||||||||||
Interest Income |
(14 | ) | (18 | ) | (10 | ) | ||||||||
$ | 397 | $ | 283 | $ | 286 | |||||||||
EnCana has entered into a series of one or more interest rate swaps, foreign exchange swaps and option transactions on certain of its long-term notes and debentures detailed below (see also Note 13). The net effect of these transactions reduced interest costs in 2004 by $22 million (2003 $23 million; 2002 $20 million).
Principal Amount | Indenture Interest | Net Swap to | Effective Rate | |||||||
8.75% due November 9, 2005 C$200 million |
US$73 million US$73 million |
C$ Fixed C$ Fixed |
US$ Fixed* US$ Floating* |
4.99% 3 month LIBOR less 4 basis points |
||||||
7.50% due August 25, 2006 C$100 million |
US$73 million | C$ Fixed | US$ Fixed* | 4.14% | ||||||
5.80% due June 2, 2008 C$225 million |
US$71 million C$125 million |
C$ Fixed C$ Fixed |
US$ Fixed* C$ Floating |
4.80% 3 month Bankers Acceptance less 5 basis points |
||||||
* These instruments have been subject to multiple swap transactions.
NOTE 8. FOREIGN EXCHANGE GAIN
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Unrealized Foreign Exchange Gain on Translation of U.S. Dollar
Debt Issued in Canada |
$ | (285 | ) | $ | (545 | ) | $ | (23 | ) | |||||
Realized Foreign Exchange (Gains) Losses |
(132 | ) | (53 | ) | 12 | |||||||||
$ | (417 | ) | $ | (598 | ) | $ | (11 | ) | ||||||
22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
NOTE 9. INCOME TAXES
The provision for income taxes is as follows:
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Current |
||||||||||||||
Canada |
$ | 594 | $ | (136 | ) | $ | (26 | ) | ||||||
United States |
(12 | ) | 39 | (31 | ) | |||||||||
Other |
(15 | ) | (16 | ) | (9 | ) | ||||||||
Total Current Tax |
567 | (113 | ) | (66 | ) | |||||||||
Future |
200 | 836 | 403 | |||||||||||
Future Tax Rate Reductions |
(109 | ) | (359 | ) | (20 | ) | ||||||||
Total Future Tax |
91 | 477 | 383 | |||||||||||
$ | 658 | $ | 364 | $ | 317 | |||||||||
The following table reconciles income taxes calculated at the Canadian statutory rate with actual income taxes:
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Net Earnings Before Income Tax |
$ | 2,869 | $ | 2,506 | $ | 983 | ||||||||
Canadian Statutory Rate |
39.1 | % | 41.0 | % | 42.3 | % | ||||||||
Expected Income Tax |
1,123 | 1,026 | 416 | |||||||||||
Effect on Taxes Resulting from: |
||||||||||||||
Non-deductible Canadian crown payments |
192 | 231 | 147 | |||||||||||
Canadian resource allowance |
(246 | ) | (258 | ) | (200 | ) | ||||||||
Canadian resource allowance on unrealized risk management losses |
(10 | ) | | | ||||||||||
Statutory and other rate differences |
(55 | ) | (45 | ) | (35 | ) | ||||||||
Effect of tax rate changes |
(109 | ) | (359 | ) | (20 | ) | ||||||||
Non-taxable capital gains |
(91 | ) | (119 | ) | | |||||||||
Previously unrecognized capital losses |
17 | (119 | ) | | ||||||||||
Tax basis retained on dispositions |
(179 | ) | | | ||||||||||
Large corporations tax |
24 | 27 | 23 | |||||||||||
Other |
(8 | ) | (20 | ) | (14 | ) | ||||||||
$ | 658 | $ | 364 | $ | 317 | |||||||||
Effective Tax Rate |
22.9 | % | 14.5 | % | 32.2 | % | ||||||||
The net future income tax liability is comprised of:
As at December 31 | 2004 | 2003 | |||||||
Future Tax Liabilities |
|||||||||
Property, plant and equipment in excess of tax values |
$ | 4,472 | $ | 3,199 | |||||
Timing of Partnership items |
1,005 | 1,162 | |||||||
Future Tax Assets |
|||||||||
Net operating losses carried forward |
(103 | ) | (99 | ) | |||||
Other |
(181 | ) | (106 | ) | |||||
Net Future Income Tax Liability |
$ | 5,193 | $ | 4,156 | |||||
23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
The approximate amounts of tax pools available are as follows:
As at December 31 | 2004 | 2003 | |||||||
Canada |
$ | 7,183 | $ | 6,904 | |||||
United States |
3,009 | 2,112 | |||||||
$ | 10,192 | $ | 9,016 | ||||||
Included in the above tax pools are $275 million (2003 $256 million) related to non-capital or net operating losses available for carry forward to reduce taxable income in future years.
The current income tax provision includes amounts payable or recoverable in respect of Canadian partnership earnings included in the Consolidated Financial Statements for partnerships that have a year end that is after that of EnCana.
NOTE 10. INVENTORIES
As at December 31 | 2004 | 2003 | |||||||
Product |
|||||||||
Upstream |
$ | 14 | $ | 6 | |||||
Midstream & Market Optimization |
497 | 546 | |||||||
Parts and Supplies |
2 | 5 | |||||||
$ | 513 | $ | 557 | ||||||
NOTE 11. PROPERTY, PLANT AND EQUIPMENT, NET
As at December 31 | 2004 | 2003 | |||||||||||||||||||||||
Accumulated | Accumulated | ||||||||||||||||||||||||
Cost | DD&A* | Net | Cost | DD&A* | Net | ||||||||||||||||||||
Upstream |
|||||||||||||||||||||||||
Canada |
$ | 24,390 | $ | (9,775 | ) | $ | 14,615 | $ | 20,607 | $ | (7,500 | ) | $ | 13,107 | |||||||||||
United States |
8,360 | (1,056 | ) | 7,304 | 4,062 | (523 | ) | 3,539 | |||||||||||||||||
Other Countries |
425 | (247 | ) | 178 | 316 | (205 | ) | 111 | |||||||||||||||||
Total Upstream |
33,175 | (11,078 | ) | 22,097 | 24,985 | (8,228 | ) | 16,757 | |||||||||||||||||
Midstream & Market Optimization |
975 | (171 | ) | 804 | 915 | (131 | ) | 784 | |||||||||||||||||
Corporate |
455 | (216 | ) | 239 | 320 | (91 | ) | 229 | |||||||||||||||||
$ | 34,605 | $ | (11,465 | ) | $ | 23,140 | $ | 26,220 | $ | (8,450 | ) | $ | 17,770 | ||||||||||||
* Depreciation, depletion and amortization
Included in Midstream is $102 million (2003 $97 million; 2002 $47 million) related to cushion gas, required to operate the gas storage facilities, which is not subject to depletion.
Included in property, plant and equipment are asset retirement costs, net of amortization, of $393 million (2003 $212 million). Administrative costs have not been capitalized as part of the capital expenditures.
24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Upstream costs in respect of significant unproved properties and major development projects excluded from depletable costs at the end of the year were:
As at December 31 | 2004 | 2003 | 2002 | |||||||||||
Canada |
$ | 1,444 | $ | 1,444 | $ | 1,035 | ||||||||
United States |
1,119 | 499 | 604 | |||||||||||
Other Countries |
177 | 112 | 111 | |||||||||||
$ | 2,740 | $ | 2,055 | $ | 1,750 | |||||||||
The costs excluded from depletable costs in Other Countries represents costs related to unproved properties incurred in cost centres that are considered to be in the pre-production stage. Currently, there are no proved reserves in these cost centres. All costs, net of any associated revenues, in these cost centres have been capitalized. Ultimate recoverability of these costs will be dependent upon the finding of proved oil and natural gas reserves. At December 31, 2004, the Company completed its impairment review of pre-production cost centres and determined that $23 million of costs should be charged to the Consolidated Statement of Earnings (2003 $85 million; 2002 nil).
The prices used in the ceiling test evaluation of the Companys crude oil and natural gas reserves at December 31, 2004 were:
% increase to | |||||||||||||||||||||||||||||
2005 | 2006 | 2007 | 2008 | 2009 | 2016 | ||||||||||||||||||||||||
Natural Gas ($/Mcf) |
|||||||||||||||||||||||||||||
Canada |
$ | 6.00 | $ | 5.34 | $ | 4.52 | $ | 4.45 | $ | 4.58 | 12 | % | |||||||||||||||||
United States |
6.24 | 5.61 | 4.35 | 4.77 | 4.77 | 13 | % | ||||||||||||||||||||||
Crude Oil ($/barrel) |
|||||||||||||||||||||||||||||
Canada |
$ | 28.66 | $ | 24.38 | $ | 17.03 | $ | 17.20 | $ | 16.88 | 7 | % | |||||||||||||||||
United States |
43.51 | 38.84 | 26.95 | 26.49 | 26.45 | 18 | % | ||||||||||||||||||||||
Natural Gas Liquids ($/barrel) |
|||||||||||||||||||||||||||||
Canada |
$ | 38.61 | $ | 33.99 | $ | 25.65 | $ | 25.41 | $ | 25.25 | 17 | % | |||||||||||||||||
United States |
38.18 | 34.54 | 26.93 | 27.14 | 27.22 | 14 | % | ||||||||||||||||||||||
NOTE 12. INVESTMENTS AND OTHER ASSETS
As at December 31 | 2004 | 2003 | |||||||
Equity Investments |
$ | 8 | $ | 57 | |||||
Marketing Contracts |
12 | 22 | |||||||
Deferred Financing Costs |
61 | 35 | |||||||
Deferred Pension Plan and Savings Plan |
64 | 53 | |||||||
Prepaid Capital and Other |
189 | 101 | |||||||
$ | 334 | $ | 268 | ||||||
Equity Investments
Included in Equity Investments is a 36 percent indirect equity investment in Oleoducto Trasandino which owns a crude oil pipeline that ships crude oil from the producing areas of Argentina to refineries in Chile. In the second quarter of 2004, a $35 million impairment charge was made to depreciation, depletion and amortization on the Companys interest in Oleoducto Trasandino.
25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
NOTE 13. LONG-TERM DEBT
As at December 31 | Note | 2004 | 2003 | ||||||||||
Canadian Dollar Denominated Debt |
|||||||||||||
Revolving credit and term loan borrowings |
B | $ | 1,515 | $ | 1,425 | ||||||||
Unsecured notes and debentures |
C | 1,309 | 1,335 | ||||||||||
Preferred securities |
D | | 252 | ||||||||||
2,824 | 3,012 | ||||||||||||
U.S. Dollar Denominated Debt |
|||||||||||||
Revolving credit and term loan borrowings |
E | 399 | 417 | ||||||||||
Unsecured notes and debentures |
F | 4,641 | 2,713 | ||||||||||
Preferred securities |
D | | 150 | ||||||||||
5,040 | 3,280 | ||||||||||||
Increase in Value of Debt Acquired |
G | 66 | 83 | ||||||||||
Current Portion of Long-Term Debt |
H | (188 | ) | (287 | ) | ||||||||
$ | 7,742 | $ | 6,088 | ||||||||||
A) Overview
Revolving credit and term loan borrowings
At December 31, 2004, EnCana had in place a revolving credit facility for $4.5 billion Canadian dollars or its equivalent amount in U.S. dollars ($3.7 billion). The facility consists of two tranches of C$1.7 billion ($1.4 billion) and C$2.8 billion ($2.3 billion) respectively. The first tranche is fully revolving for a period of three years from the date of the agreement, October 2004. This tranche is extendible annually for an additional one year period at the option of the lenders and upon notice from EnCana. The second tranche is fully revolving for a period of five years from the date of the agreement, October 2004. This tranche is extendible annually for an additional one year period at the option of the lenders and upon notice from the Company. The facility is unsecured and bears interest at either the lenders rates for Canadian prime commercial loans, U.S. base rate loans, Bankers Acceptances rates, or at LIBOR plus applicable margins.
To fund the acquisition of Tom Brown, Inc., EnCana arranged a $3 billion non-revolving term loan facility. Initially, $1.8 billion was drawn on this facility. At December 31, 2004, this facility has been completely repaid and cancelled.
At December 31, 2004, one of EnCanas subsidiaries had in place a credit facility totaling $600 million (C$722 million). The facility is guaranteed by EnCana Corporation and fully revolving for five years from the date of the Agreement, December, 2004. The facility is extendable annually for an additional one year period at the option of the lenders and upon notice from the subsidiary. This facility bears interest at either the lenders U.S. base rate or at LIBOR plus applicable margins.
Revolving credit and term loan borrowings include Bankers Acceptances and Commercial Paper of $1,559 million (2003 $1,749 million) maturing at various dates with a weighted average interest rate of 2.83% (2003 2.55%) and LIBOR loans of $355 million (2003 $65 million) with a weighted average interest rate of 2.98% (2003 1.69%). These amounts are fully supported and Management expects that they will continue to be supported by revolving credit and term loan facilities that have no repayment requirements within the next year.
Standby fees paid in 2004 relating to revolving credit and term loan agreements were approximately $5 million (2003 $3 million; 2002 $3 million).
26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Unsecured notes and debentures
Unsecured notes and debentures include medium term notes and senior notes that are issued from time to time under trust indentures. The Companys current medium term note program was renewed in 2003 with C$1 billion ($831 million) unutilized at December 31, 2004. The notes may be denominated in Canadian dollars or in foreign currencies.
EnCana has in place a shelf prospectus for U.S. Unsecured Notes in the amount of $2 billion under the Multijurisdictional Disclosure System. The shelf prospectus provides that debt securities in U.S. dollars or other foreign currencies may be issued from time to time in one or more series. Terms of the notes, including interest at either fixed or floating rates and expiry dates are determined by reference to market conditions at the date of issue. At December 31, 2004, $2 billion of the shelf prospectus remains unutilized.
EnCana has an indirect wholly owned subsidiary, EnCana Holdings Finance Corp., which has in place a shelf prospectus in the amount of $2 billion under the Multijurisdictional Disclosure System. The shelf prospectus provides that debt securities in U.S. dollars or other foreign currencies may be issued from time to time in one or more series. Terms of the notes, including interest at either fixed or floating rates and expiry dates are determined by reference to market conditions at the date of issue. The debt securities issued under this shelf prospectus are fully and unconditionally guaranteed by EnCana Corporation. EnCana has also obtained certain exemption orders from Canadian securities regulatory authorities that allow the filing of certain financial and other information of EnCana to satisfy certain continuous disclosure obligations of EnCana Holdings Finance Corp. At December 31, 2004, $1 billion of the shelf prospectus remains unutilized.
B) Canadian revolving credit and term loan borrowings
C$ Principal | |||||||||||||
Amount | 2004 | 2003 | |||||||||||
Bankers Acceptances |
$ | 615 | $ | 511 | $ | 598 | |||||||
Commercial Paper |
1,209 | 1,004 | 799 | ||||||||||
Cogeneration
Facility, matures March 31, 2016 * |
| | 28 | ||||||||||
$ | 1,824 | $ | 1,515 | $ | 1,425 | ||||||||
* On December 15, 2004, EnCana sold its limited partnership interest in Kingston. See Note 6.
C) Canadian unsecured notes and debentures
C$ Principal | |||||||||||||
Amount | 2004 | 2003 | |||||||||||
6.60% due June 30, 2004 |
$ | | $ | | $ | 39 | |||||||
7.00% due December 1, 2004 |
| | 77 | ||||||||||
5.95% due October 1, 2007 |
200 | 166 | 155 | ||||||||||
5.30% due December 3, 2007 |
300 | 248 | 232 | ||||||||||
5.95% due June 2, 2008 |
100 | 83 | 77 | ||||||||||
5.80% due June 2, 2008 |
125 | 104 | 97 | ||||||||||
5.80% due June 19, 2008 |
100 | 83 | 77 | ||||||||||
6.10% due June 1, 2009 |
150 | 125 | 116 | ||||||||||
7.15% due December 17, 2009 |
150 | 125 | 116 | ||||||||||
8.50% due March 15, 2011 |
50 | 42 | 39 | ||||||||||
7.10% due October 11, 2011 |
200 | 166 | 155 | ||||||||||
7.30% due September 2, 2014 |
150 | 125 | 116 | ||||||||||
5.50% / 6.20% due June 23, 2028 |
50 | 42 | 39 | ||||||||||
$ | 1,575 | $ | 1,309 | $ | 1,335 | ||||||||
27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
D) Preferred securities
C$ Principal | |||||||||||||
Amount | 2004 | 2003 | |||||||||||
Canadian Dollar |
|||||||||||||
7.00% due March 23, 2034 |
$ | | $ | | $ | 97 | |||||||
8.50% due September 30, 2048 |
| | 155 | ||||||||||
$ | | | 252 | ||||||||||
U.S. Dollar |
|||||||||||||
9.50% due September 30, 2048 |
| 150 | |||||||||||
$ | | $ | 402 | ||||||||||
All of the preferred securities were redeemed during 2004 at par plus accrued and unpaid interest.
E) U.S. revolving credit and term loan borrowings
2004 | 2003 | ||||||||
Commercial Paper |
$ | 44 | $ | 352 | |||||
LIBOR Loan |
355 | 65 | |||||||
$ | 399 | $ | 417 | ||||||
F) U.S. unsecured notes and debentures
C$ Amount | 2004 | 2003 | |||||||||||
Floating Rate |
|||||||||||||
8.40% due December 15, 2004 |
$ | | $ | | $ | 73 | |||||||
8.75% due November 9, 2005 |
88 | * | 73 | 73 | |||||||||
Fixed Rate |
|||||||||||||
8.75% due November 9, 2005 |
88 | * | 73 | 73 | |||||||||
7.50% due August 25, 2006 |
88 | * | 73 | 73 | |||||||||
5.80% due June 2, 2008 |
85 | * | 71 | 71 | |||||||||
4.60% due August 15, 2009 |
250 | | |||||||||||
7.65% due September 15, 2010 |
200 | 200 | |||||||||||
6.30% due November 1, 2011 |
500 | 500 | |||||||||||
7.25% due September 15, 2013 |
1 | | |||||||||||
4.75% due October 15, 2013 |
500 | 500 | |||||||||||
5.80% due May 1, 2014 |
1,000 | | |||||||||||
8.125% due September 15, 2030 |
300 | 300 | |||||||||||
7.20% due November 1, 2031 |
350 | 350 | |||||||||||
7.375% due November 1, 2031 |
500 | 500 | |||||||||||
6.50% due August 15, 2034 |
750 | | |||||||||||
$ | 4,641 | $ | 2,713 | ||||||||||
* The Company has entered into a series of cross-currency and interest rate swap transactions that effectively convert these Canadian dollar denominated notes to U.S. dollars. The effective U.S. dollar principal is shown in the table.
The 5.80% Notes due May 1, 2014 were issued by the Companys indirect wholly owned subsidiary, EnCana Holdings Finance Corp. These notes are fully and unconditionally guaranteed by EnCana Corporation.
28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
G) Increase in value of debt acquired
Certain of the notes and debentures of the Company were acquired in business combinations and were accounted for at their fair value at the date of acquisition. The difference between the fair value and the principal amount of the debt is being amortized over the remaining life of the outstanding debt acquired, approximately 22 years.
H) Current portion of long-term debt
2004 | 2003 | ||||||||
7.00% Coupon Reset Subordinated Term Securities due March 23, 2034 |
$ | | $ | 97 | |||||
6.60% Medium Term Note due June 30, 2004 |
| 39 | |||||||
7.00% Medium Term Note due December 1, 2004 |
| 77 | |||||||
8.40% Medium Term Note due December 15, 2004 |
| 73 | |||||||
5.50% / 6.20% Medium Term Note due June 23, 2028 |
42 | | |||||||
8.75% Unsecured Note due November 9, 2005 |
146 | | |||||||
Cogeneration facility |
| 1 | |||||||
$ | 188 | $ | 287 | ||||||
The 5.50% / 6.20% Medium Term Note due June 23, 2028 has a put option attached to it whereby holders of the note may require EnCana to repay the outstanding note on June 23, 2005, if the notice is given prior to June 9, 2005 that the option will be exercised. Should notice not be received, the note is then payable on June 23, 2028.
I) Mandatory debt payments
C$ Principal | US$ Principal | Total US$ | ||||||||||||
Amount | Amount | Equivalent | ||||||||||||
2005 |
$ | 50 | $ | 146 | $ | 188 | ||||||||
2006 |
| 73 | 73 | |||||||||||
2007 |
500 | | 414 | |||||||||||
2008 |
325 | 71 | 341 | |||||||||||
2009 |
300 | 250 | 500 | |||||||||||
Thereafter |
2,224 | 4,500 | 6,348 | |||||||||||
Total |
$ | 3,399 | $ | 5,040 | $ | 7,864 | ||||||||
The amount due in 2005 excludes Bankers Acceptances and Commercial Paper, which are fully supported by revolving credit and term loan facilities that have no repayment requirements within the next year.
29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
NOTE 14. ASSET RETIREMENT OBLIGATION
The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties.
As at December 31 | 2004 | 2003 | |||||||
Asset Retirement Obligation, Beginning of Year |
$ | 383 | $ | 288 | |||||
Liabilities Incurred |
98 | 45 | |||||||
Liabilities Settled |
(16 | ) | (23 | ) | |||||
Liabilities Disposed |
(35 | ) | | ||||||
Change in Estimated Future Cash Flows |
124 | | |||||||
Accretion Expense |
22 | 17 | |||||||
Other |
35 | 56 | |||||||
Asset Retirement Obligation, End of Year |
$ | 611 | $ | 383 | |||||
The total undiscounted amount of estimated cash flows required to settle the obligation is $3,695 million (2003 $3,118 million), which has been discounted using a credit-adjusted risk free rate of 6.0 percent (2003 5.9 percent). Most of these obligations are not expected to be paid for several years, or decades, in the future and will be funded from general company resources at that time.
NOTE 15. SHARE CAPITAL
Authorized
The Company is authorized to issue an unlimited number of Common Shares, an unlimited number of First Preferred Shares and an unlimited number of Second Preferred Shares.
Issued and Outstanding
As at December 31 | 2004 | 2003 | |||||||||||||||
Number | Number | ||||||||||||||||
(millions) | Amount | (millions) | Amount | ||||||||||||||
Common Shares Outstanding, Beginning of Year |
460.6 | $ | 5,305 | 478.9 | $ | 5,511 | |||||||||||
Shares Issued under Option Plans |
9.7 | 281 | 5.5 | 114 | |||||||||||||
Shares Repurchased |
(20.0 | ) | (287 | ) | (23.8 | ) | (320 | ) | |||||||||
Common Shares Outstanding, End of Year |
450.3 | $ | 5,299 | 460.6 | $ | 5,305 | |||||||||||
Normal Course Issuer Bid
On October 26, 2004, the Company received regulatory approval for a new Normal Course Issuer Bid commencing October 29, 2004. Under this bid, the Company may purchase for cancellation up to 23,114,500 of its Common Shares, representing five percent of the approximately 462.29 million Common Shares outstanding as of the filing of the bid on October 22, 2004. On February 4, 2005, the Company received regulatory approval for an amendment to the Normal Course Issuer Bid which increases the number of shares available for purchase from five percent of the issued and outstanding Common Shares to ten percent of the public float of Common Shares (a total of approximately 46.1 million Common Shares). The current Normal Course Issuer Bid expires on October 28, 2005.
On October 20, 2003, the Company received regulatory approval for a new Normal Course Issuer Bid commencing October 22, 2003. Under this bid, the Company could purchase for cancellation up to 23,212,341 of its Common Shares, representing five percent of the 464,246,813 Common Shares outstanding as of October 14, 2003.
30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
In 2004, the Company purchased, for cancellation, 19,983,600 Common Shares for total consideration of $1,004 million. Of the $1,004 million paid, $287 million was charged to Share capital, $46 million was charged to Paid in surplus and $671 million was charged to Retained earnings.
Stock Options
EnCana has stock-based compensation plans that allow employees to purchase Common Shares of the Company. Option exercise prices approximate the market price for the Common Shares on the date the options were issued. Options granted under the plans are generally fully exercisable after three years and expire five years after the grant date. Options granted under predecessor and/or related company replacement plans expire up to 10 years from the date the options were granted.
In conjunction with the business combination transaction with AEC described in Note 3, options to purchase AEC common shares were replaced with options to purchase Common Shares of EnCana (AEC replacement plan) in a manner consistent with the provisions of the AEC stock option plan. Options granted under the AEC plan prior to April 21, 1999 expire after seven years and options granted after April 20, 1999 expire after five years. The business combination resulted in these replacement options, along with all options then outstanding under the EnCana plan, becoming exercisable after the close of business on April 5, 2002.
EnCana Plan
Pursuant to the terms of a stock option plan, options may be granted to certain key employees to purchase Common Shares of the Company. Options granted prior to February 27, 1997, are exercisable at half the number of options granted after two years and are fully exercisable after three years. The options expire 10 years after the date granted. Options granted on or after February 27, 1997, and prior to November 4, 1999, are exercisable after three years and expire five years after the date granted. Options granted on or after November 4, 1999, are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire five years after the date granted. For stock options granted after February 27, 1997, and prior to November 4, 1999, the employees can surrender their options in exchange for, at the election of the Company, cash or a payment in common stock for the difference between the market price and exercise price. All options issued in 2004 have an associated Tandem Share Appreciation Right (TSAR) attached to them (see Note 16).
Canadian Pacific Limited Replacement Plan
As part of the 2001 reorganization of Canadian Pacific Limited (CPL), EnCanas former parent company, CPL stock options were replaced with stock options granted by the Company in a manner that was consistent with the provisions of the CPL stock option plan. Under CPLs stock option plan, options were granted to certain key employees to purchase common shares of CPL at a price not less than the market value of the shares at the grant date. The options expire 10 years after the grant date and are all exercisable.
Directors Plan
Effective April 5, 2002, the Company amended the director stock option plan. Under the terms of the plan, new non-employee directors were given an initial grant of 15,000 options to purchase common shares of the Company. Thereafter, there was an annual grant of 7,500 options to each non-employee director. Options, which expire five years after the grant date, are 100 percent exercisable on the earlier of the next annual general meeting following the grant date and the first anniversary of the grant date. On October 23, 2003, issuances of stock options under this plan were discontinued.
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
The following tables summarize the information about options to purchase Common Shares that have no TSAR attached to them:
As at December 31 | 2004 | 2003 | 2002 | |||||||||||||||||||||||
Stock Options | Weighted Average | Stock Options | Weighted Average | Stock Options | Weighted Average | |||||||||||||||||||||
(millions) | Exercise Price (C$) | (millions) | Exercise Price (C$) | (millions) | Exercise Price (C$) | |||||||||||||||||||||
Outstanding, Beginning of Year |
28.8 | 43.13 | 29.6 | 39.74 | 10.5 | 32.31 | ||||||||||||||||||||
Granted under EnCana Plan |
| | 6.3 | 47.98 | 12.1 | 48.13 | ||||||||||||||||||||
Granted under AEC Replacement
Plan |
| | | | 13.1 | 32.01 | ||||||||||||||||||||
Granted under Directors Plan |
| | 0.1 | 47.87 | 0.1 | 48.04 | ||||||||||||||||||||
Exercised |
(9.7 | ) | 36.63 | (5.5 | ) | 29.11 | (5.5 | ) | 25.20 | |||||||||||||||||
Forfeited |
(1.0 | ) | 47.50 | (1.7 | ) | 41.18 | (0.7 | ) | 43.81 | |||||||||||||||||
Outstanding, End of Year |
18.1 | 46.29 | 28.8 | 43.13 | 29.6 | 39.74 | ||||||||||||||||||||
Exercisable, End of Year |
10.8 | 45.09 | 15.6 | 38.92 | 17.7 | 34.10 | ||||||||||||||||||||
As at December 31 | Outstanding Options | Exercisable Options | |||||||||||||||||||
Weighted | |||||||||||||||||||||
Number of | Average | Weighted | Number of | Weighted | |||||||||||||||||
Options | Remaining | Average | Options | Average | |||||||||||||||||
Outstanding | Contractual | Exercise | Outstanding | Exercise | |||||||||||||||||
Range of Exercise Price (C$) | (millions) | Life (years) | Price (C$) | (millions) | Price (C$) | ||||||||||||||||
13.50 to 19.99 |
0.1 | 0.2 | 18.49 | 0.1 | 18.49 | ||||||||||||||||
20.00 to 24.99 |
0.6 | 3.5 | 22.69 | 0.6 | 22.69 | ||||||||||||||||
25.00 to 29.99 |
0.4 | 1.3 | 26.18 | 0.4 | 26.18 | ||||||||||||||||
30.00 to 43.99 |
0.5 | 1.7 | 40.18 | 0.4 | 39.93 | ||||||||||||||||
44.00 to 53.00 |
16.5 | 2.4 | 47.97 | 9.3 | 47.87 | ||||||||||||||||
18.1 | 2.4 | 46.29 | 10.8 | 45.09 | |||||||||||||||||
At December 31, 2004, there were 8.0 million common shares reserved for issuance under stock option plans (2003 7.8 million; 2002 12.4 million).
EnCana has recorded stock-based compensation expense in the Consolidated Statement of Earnings for stock options granted to employees and directors in 2003 using the fair value method. Compensation expense has not been recorded in the Consolidated Statement of Earnings related to stock options granted prior to 2003. If the Company had applied the fair value method to options granted prior to 2003, pro forma Net Earnings and Net Earnings per Common Share in 2004 would have been $3,476 million; $7.55 per common share basic; $7.43 per common share diluted (2003 $2,326 million; $4.91 per common share basic; $4.85 per common share diluted).
The fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model with weighted average assumptions for grants as follows:
For the years ended December 31 | 2003 | 2002 | |||||||
Weighted Average Fair Value of Options Granted (C$) |
$ | 12.21 | $ | 13.31 | |||||
Risk-Free Interest Rate |
3.87 | % | 4.29 | % | |||||
Expected Lives (years) |
3.00 | 3.00 | |||||||
Expected Volatility |
0.33 | 0.35 | |||||||
Annual Dividend per Share (C$/common share) |
$ | 0.40 | $ | 0.40 | |||||
32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
NOTE 16. COMPENSATION PLANS
A) Pensions
The most recent actuarial evaluation completed for the Company is dated December 31, 2004.
The Company sponsors both defined benefit and defined contribution plans providing pension and other retirement and post-employment benefits (OPEB) to substantially all of its employees.
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Total Expense for Defined Contribution Plans |
$ | 19 | $ | 12 | $ | 9 | ||||||||
Information about defined benefit post-retirement benefit plans, in aggregate, is as follows:
As at December 31 | Pension Benefits | OPEB | |||||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||||||
Accrued Benefit Obligation, Beginning of Year |
$ | 214 | $ | 159 | $ | 14 | $ | 8 | |||||||||
Beginning of year adjustment |
(1 | ) | | | | ||||||||||||
Current service cost |
5 | 5 | 1 | 1 | |||||||||||||
Interest cost |
13 | 11 | 1 | 1 | |||||||||||||
Benefits paid |
(10 | ) | (11 | ) | | | |||||||||||
Actuarial loss |
8 | 12 | 1 | 1 | |||||||||||||
Contributions |
1 | 1 | | | |||||||||||||
Plan amendments |
| | | 1 | |||||||||||||
Foreign exchange |
16 | 37 | 2 | 2 | |||||||||||||
Accrued Benefit Obligation, End of Year |
$ | 246 | $ | 214 | $ | 19 | $ | 14 | |||||||||
As at December 31 | Pension Benefits | OPEB | |||||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||||||
Fair Value of Plan Assets, Beginning of Year |
$ | 203 | $ | 117 | $ | | $ | | |||||||||
Beginning of year adjustment |
| (1 | ) | | | ||||||||||||
Actual return on plan assets |
19 | 16 | | | |||||||||||||
Employer contributions |
17 | 51 | | | |||||||||||||
Employees contributions |
1 | 1 | | | |||||||||||||
Benefits paid |
(10 | ) | (10 | ) | | | |||||||||||
Foreign exchange |
17 | 29 | | | |||||||||||||
Fair Value of Plan Assets, End of Year |
$ | 247 | $ | 203 | $ | | $ | | |||||||||
As at December 31 | Pension Benefits | OPEB | |||||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||||||
Funded Status Plan Assets less than Benefit Obligation |
$ | 1 | $ | (11 | ) | $ | (19 | ) | $ | (14 | ) | ||||||
Amounts Not Recognized: |
|||||||||||||||||
Unamortized net actuarial loss |
54 | 64 | 4 | 2 | |||||||||||||
Unamortized past service cost |
10 | 12 | 2 | 1 | |||||||||||||
Net transitional asset |
(11 | ) | (12 | ) | 2 | 3 | |||||||||||
Accrued Benefit Asset |
$ | 54 | $ | 53 | $ | (11 | ) | $ | (8 | ) | |||||||
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
As at December 31 | Pension Benefits | OPEB | |||||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||||||
Prepaid Benefit Cost |
$ | 54 | $ | 53 | $ | | $ | | |||||||||
Accrued Benefit Cost |
| | (11 | ) | (8 | ) | |||||||||||
Net Amount Recognized |
$ | 54 | $ | 53 | $ | (11 | ) | $ | (8 | ) | |||||||
The Companys other post employment benefit plans are funded on an as required basis.
The weighted average assumptions used to determine benefit obligations are as follows:
As at December 31 | Pension Benefits | OPEB | |||||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||||||
Discount Rate |
5.75 | % | 6.00 | % | 5.75 | % | 6.00 | % | |||||||||
Rate of Compensation Increase |
4.60 | % | 4.75 | % | 5.65 | % | 5.75 | % | |||||||||
The weighted average assumptions used to determine periodic expense are as follows:
For the years ended December 31 | Pension Benefits | OPEB | |||||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||||||
Discount Rate |
6.00 | % | 6.50 | % | 6.00 | % | 6.50 | % | |||||||||
Expected Long-Term Rate of Return on Plan Assets |
|||||||||||||||||
Registered pension plans |
6.75 | % | 6.75 | % | n/a | n/a | |||||||||||
Supplemental pension plans |
3.375 | % | 3.375 | % | n/a | n/a | |||||||||||
Rate of Compensation Increase |
4.75 | % | 4.75 | % | 5.75 | % | 5.75 | % | |||||||||
The periodic expense for benefits is as follows:
For the years ended December 31 | Pension Benefits | OPEB | |||||||||||||||||||||||
2004 | 2003 | 2002 | 2004 | 2003 | 2002 | ||||||||||||||||||||
Current Service Cost |
$ | 5 | $ | 5 | $ | 2 | $ | 1 | $ | 1 | $ | 1 | |||||||||||||
Interest Cost |
13 | 11 | 8 | 1 | 1 | | |||||||||||||||||||
Actual Return on Plan Assets |
(19 | ) | (16 | ) | 9 | | | | |||||||||||||||||
Actuarial Loss on Accrued Benefit
Obligation |
8 | 12 | 9 | 1 | 1 | | |||||||||||||||||||
Plan Amendment |
| | 9 | | 2 | | |||||||||||||||||||
Difference Between Actual and: |
|||||||||||||||||||||||||
Expected return on plan assets |
7 | 7 | (17 | ) | | | | ||||||||||||||||||
Recognized actuarial loss |
(4 | ) | (8 | ) | (8 | ) | (1 | ) | (1 | ) | | ||||||||||||||
Difference Between Amortization of
Past Service Costs and Actual Plan
Amendments |
2 | 1 | (8 | ) | (2 | ) | |||||||||||||||||||
Amortization of Transitional Obligation |
(2 | ) | (2 | ) | (2 | ) | | | | ||||||||||||||||
Curtailment Loss |
| | 1 | | | | |||||||||||||||||||
Special Termination Benefits |
| | 2 | | | | |||||||||||||||||||
Expense for Defined Contribution Plan |
19 | 12 | 9 | | | | |||||||||||||||||||
Net Benefit Plan Expense |
$ | 29 | $ | 22 | $ | 14 | $ | 2 | $ | 2 | $ | 1 | |||||||||||||
The average remaining service period of the active employees covered by the defined benefit pension plan is eight years. The average remaining service period of the active employees covered by the other retirement benefits plan is 12 years.
After the business combination transaction as described in Note 3, a number of employees were involuntarily terminated. Terminated members of the defined benefit pension plan, who were age 50 or above, could elect enhanced benefits under the registered pension plan. For pension accounting
34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
purposes, this resulted in special termination benefits being provided and a curtailment event that impacted some of the pension arrangements sponsored by the Company.
Assumed health care cost trend rates are as follows:
As at December 31 | 2004 | 2003 | |||||||
Health Care Cost Trend Rate for Next Year |
10.00 | % | 10.00 | % | |||||
Rate that the Trend Rate Gradually Trends To |
5.00 | % | 5.00 | % | |||||
Year that the Trend Rate Reaches the Rate which it is Expected to Remain At |
2015 | 2014 | |||||||
Assumed health care cost trend rates have an effect on the amounts reported for the other benefit plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
One Percentage | One Percentage | ||||||||
Point Increase | Point Decrease | ||||||||
Effect on Total of Service and Interest Cost |
$ | | $ | | |||||
Effect on Post Retirement Benefit Obligation |
$ | 2 | $ | (1 | ) | ||||
The Companys pension plan asset allocations are as follows:
% of Plan Assets at | Expected Long-Term | |||||||||||||||||||||
Asset Category | Target Allocation % | December 31 | Rate of Return | |||||||||||||||||||
Normal | Range | 2004 | 2003 | |||||||||||||||||||
Domestic Equity |
35 | 25-45 | 38 | 35 | ||||||||||||||||||
Foreign Equity |
30 | 20-40 | 28 | 29 | ||||||||||||||||||
Bonds |
30 | 20-40 | 27 | 27 | ||||||||||||||||||
Real Estate and Other |
5 | 0-20 | 7 | 9 | ||||||||||||||||||
Total |
100 | 100 | 100 | 6.75 | % | |||||||||||||||||
The expected rate of return on plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio. The objective of the asset allocation policy is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense. The long-term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate market indices. The Supplemental Pension Plan (approximately $40 million) is funded through a retirement compensation arrangement and is subject to the applicable Canada Revenue Agency regulations.
The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to individual equity investments, credit rating categories and foreign currency exposure.
The Company expects to contribute $6 million to the plans in 2005. Contributions by the participants to the pension and other benefits plans were $1 million for the year ended December 31, 2004 (2003 $1 million; 2002 nil).
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Estimated future payments for pension and other benefits are as follows:
Pension Benefits | OPEB | ||||||||
2005 |
$ | 12 | $ | | |||||
2006 |
13 | 1 | |||||||
2007 |
13 | 1 | |||||||
2008 |
14 | 1 | |||||||
2009 |
15 | 1 | |||||||
2010 2014 |
88 | 7 | |||||||
Total |
$ | 155 | $ | 11 | |||||
B) Share Appreciation Rights
EnCana has in place a program whereby certain employees are granted Share Appreciation Rights (SARs) which entitle the employee to receive a cash payment equal to the excess of the market price of the Companys Common Shares at the time of exercise over the exercise price of the right. SARs granted expire after five years.
The following tables summarize the information about the SARs:
As at December 31 | 2004 | 2003 | |||||||||||||||
Weighted | Weighted | ||||||||||||||||
Average | Average | ||||||||||||||||
Outstanding | Exercise | Outstanding | Exercise | ||||||||||||||
SARs | Price | SARs | Price | ||||||||||||||
Canadian Dollar Denominated (C$) |
|||||||||||||||||
Outstanding, Beginning of Year |
1,175,070 | 35.87 | 2,284,901 | 35.56 | |||||||||||||
Exercised |
(698,775 | ) | 35.48 | (1,101,987 | ) | 35.17 | |||||||||||
Forfeited |
(11,040 | ) | 29.25 | (7,844 | ) | 46.28 | |||||||||||
Outstanding, End of Year |
465,255 | 36.61 | 1,175,070 | 35.87 | |||||||||||||
Exercisable, End of Year |
465,255 | 36.61 | 1,175,070 | 35.87 | |||||||||||||
U.S. Dollar Denominated (US$) |
|||||||||||||||||
Outstanding, Beginning of Year |
753,417 | 28.98 | 1,346,437 | 28.52 | |||||||||||||
Exercised |
(365,647 | ) | 29.19 | (589,340 | ) | 27.91 | |||||||||||
Forfeited |
(1,840 | ) | 25.29 | (3,680 | ) | 30.73 | |||||||||||
Outstanding, End of Year |
385,930 | 28.80 | 753,417 | 28.98 | |||||||||||||
Exercisable, End of Year |
385,930 | 28.80 | 753,417 | 28.98 | |||||||||||||
36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
As at December 31 | SARs Outstanding | |||||||||||
Weighted | ||||||||||||
Average | Weighted | |||||||||||
Remaining | Average | |||||||||||
Number of | Contractual | Exercise | ||||||||||
Range of Exercise Price | SARs | Life (years) | Price | |||||||||
Canadian Dollar Denominated (C$) |
||||||||||||
20.00 to 29.99 |
225,327 | 0.153 | 26.24 | |||||||||
30.00 to 39.99 |
| | | |||||||||
40.00 to 49.99 |
238,416 | 1.190 | 46.31 | |||||||||
50.00 to 60.00 |
1,512 | 1.332 | 51.94 | |||||||||
465,255 | 0.689 | 36.61 | ||||||||||
U.S. Dollar Denominated (US$) |
||||||||||||
20.00 to 29.99 |
166,640 | 1.379 | 26.69 | |||||||||
30.00 to 40.00 |
219,290 | 1.158 | 30.39 | |||||||||
385,930 | 1.254 | 28.80 | ||||||||||
During the year, the Company recorded compensation costs of $17 million related to the outstanding SARs (2003 $12 million; 2002 $4 million).
C) Tandem Share Appreciation Rights
In 2004, all options to purchase common shares issued have an associated Tandem Share Appreciation Right (TSAR) attached to them whereby the option holder has the right to receive cash payment equal to the excess of the market price of the Companys Common Shares at the time of exercise over the exercise price of the right. These TSARs expire after five years.
The following tables summarize the information about the TSARs:
As at December 31 | 2004 | |||||||
Weighted | ||||||||
Average | ||||||||
Outstanding | Exercise | |||||||
TSARs | Price | |||||||
Canadian Dollar Denominated (C$) |
||||||||
Outstanding, Beginning of Year |
| | ||||||
Granted |
1,080,450 | 55.31 | ||||||
Forfeited |
(212,950 | ) | 54.37 | |||||
Outstanding, End of Year |
867,500 | 55.54 | ||||||
Exercisable, End of Year |
| | ||||||
As at December 31 | TSARs Outstanding | |||||||||||
Weighted | ||||||||||||
Average | Weighted | |||||||||||
Remaining | Average | |||||||||||
Number of | Contractual | Exercise | ||||||||||
Range of Exercise Price | TSARs | Life (years) | Price | |||||||||
Canadian Dollar Denominated (C$) |
||||||||||||
50.00 to 59.99 |
784,000 | 4.359 | 54.75 | |||||||||
60.00 to 70.00 |
83,500 | 4.874 | 62.91 | |||||||||
867,500 | 4.408 | 55.54 | ||||||||||
During the year, the Company recorded compensation costs of $3 million related to the outstanding
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
TSARs.
D) Deferred Share Units
The Company has in place a program whereby Directors and certain key employees are issued Deferred Share Units (DSUs), which are equivalent in value to a common share of the Company. DSUs granted to directors vest immediately. DSUs granted to Senior Executives in 2002 vest over a three year period. DSUs expire on December 15th of the year following the employees retirement or death.
The following table summarizes the information about the DSUs:
As at December 31 | 2004 | 2003 | |||||||||||||||
Outstanding | Average | Outstanding | Average | ||||||||||||||
DSUs | Share Price | DSUs | Share Price | ||||||||||||||
Canadian Dollar Denominated (C$) |
|||||||||||||||||
Outstanding, Beginning of Year |
319,250 | 48.68 | 309,167 | 48.69 | |||||||||||||
Granted, Directors |
58,931 | 54.04 | 36,402 | 48.20 | |||||||||||||
Units, in lieu of dividends |
3,208 | 59.86 | 2,723 | 46.72 | |||||||||||||
Exercised |
(6,083 | ) | 48.68 | (29,042 | ) | 48.04 | |||||||||||
Outstanding, End of Year |
375,306 | 49.61 | 319,250 | 48.68 | |||||||||||||
Exercisable, End of Year |
293,955 | 52.55 | 80,645 | 48.68 | |||||||||||||
During the year, the Company recorded compensation costs of $10 million related to the outstanding DSUs (2003 $4 million; 2002 $4 million).
E) Performance Share Units
EnCana has in place a program whereby employees may be granted Performance Share Units (PSUs) which entitle the employee to receive, upon vesting, either a common share of EnCana or a cash payment equal to the value of one common share of EnCana depending upon the terms of the PSU granted. PSUs vest at the end of a three year period. Their ultimate value will depend upon EnCanas performance measured over three calendar years. Performance will be measured by total shareholder return relative to a fixed North American oil and gas comparison group. If EnCanas performance is below the specified level compared to the comparison group, the units awarded will be forfeited. If EnCanas performance is at or above the specified level compared to the comparison group, the value of the PSUs shall be determined by EnCanas relative ranking, with payments ranging from one to two times for PSUs granted for the 2003 grant and one half to two times the PSUs granted for the 2004 grant.
PSUs granted in 2004 are to be paid in common shares (2003 paid in cash).
38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
The following table summarizes the information about the PSUs:
As at December 31 | 2004 | 2003 | |||||||||||||||
Outstanding | Average | Outstanding | Average | ||||||||||||||
PSU's | Share Price | PSU's | Share Price | ||||||||||||||
Canadian Dollar Denominated (C$) |
|||||||||||||||||
Outstanding, Beginning of Year |
126,283 | 46.52 | | | |||||||||||||
Granted |
1,690,790 | 53.95 | 128,893 | 46.52 | |||||||||||||
Forfeited |
(169,970 | ) | 53.51 | (2,610 | ) | 46.52 | |||||||||||
Outstanding, End of Year |
1,647,103 | 53.42 | 126,283 | 46.52 | |||||||||||||
Exercisable, End of Year |
| | | | |||||||||||||
U.S. Dollar Denominated (US$) |
|||||||||||||||||
Outstanding, Beginning of Year |
| | | | |||||||||||||
Granted |
250,224 | 41.12 | | | |||||||||||||
Forfeited |
(25,609 | ) | 41.12 | | | ||||||||||||
Outstanding, End of Year |
224,615 | 41.12 | | | |||||||||||||
Exercisable, End of Year |
| | | | |||||||||||||
During the year, the Company recorded compensation costs of $25 million related to the outstanding PSUs (2003 $1 million; 2002 nil).
NOTE 17. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
As a means of managing commodity price volatility, EnCana has entered into various financial instrument agreements and physical contracts. The following information presents all positions for financial instruments.
As discussed in Note 2, on January 1, 2004, the fair value of all outstanding financial instruments that were not considered accounting hedges was recorded in the Consolidated Balance Sheet with an offsetting net deferred loss amount. The deferred loss is recognized into net earnings over the life of the related contracts. Changes in fair value after that time are recorded in the Consolidated Balance Sheet with the associated unrealized gain or loss recorded in net earnings. The estimated fair value of all derivative instruments is based on quoted market prices or, in their absence, third party market indications and forecasts.
The following table presents a reconciliation of the change in the unrealized amounts during 2004:
Net Deferred | ||||||||||||
Amounts | Fair | Total | ||||||||||
Recognized on | Market | Unrealized | ||||||||||
Transition | Value | Gain/(Loss) | ||||||||||
Fair Value of Contracts, January 1, 2004 |
$ | 235 | $ | (235 | ) | $ | | |||||
Change in Fair Value of Contracts Still
Outstanding at December 31, 2004 |
| 78 | 78 | |||||||||
Fair Value of Contracts Realized During 2004 |
(307 | ) | 307 | | ||||||||
Fair Value of Contracts Entered into During 2004 |
| (339 | ) | (339 | ) | |||||||
Fair Value of Contracts Outstanding |
$ | (72 | ) | $ | (189 | ) | $ | (261 | ) | |||
Premiums Paid on Collars and Options |
110 | |||||||||||
Fair Value of Contracts Outstanding and
Premiums Paid, End of Year |
$ | (79 | ) | |||||||||
Amounts Allocated to Continuing Operations |
$ | (73 | ) | $ | (10 | ) | $ | (190 | ) | |||
Amounts Allocated to Discontinued Operations |
1 | (69 | ) | (71 | ) | |||||||
$ | (72 | ) | $ | (79 | ) | $ | (261 | ) | ||||
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
The total realized loss recognized in net earnings from continuing operations for the year ended December 31, 2004 was $464 million ($686 million, before tax).
At December 31, 2004, the risk management amounts are recorded in the Consolidated Balance Sheet as follows:
As at December 31 | 2004 | |||
Risk Management |
||||
Current asset |
$ | 336 | ||
Long-term asset |
87 | |||
Current liability |
241 | |||
Long-term liability |
192 | |||
Net Risk Management Liability Continuing Operations |
(10 | ) | ||
Net Risk Management Liability Discontinued Operations |
(69 | ) | ||
$ | (79 | ) | ||
A summary of all unrealized estimated fair value financial positions is as follows:
As at December 31 | Note | 2004 | 2003 | ||||||||||
Commodity Price Risk |
A | ||||||||||||
Natural gas |
$ | 107 | $ | (13 | ) | ||||||||
Crude oil |
(143 | ) | (174 | ) | |||||||||
Power |
2 | 4 | |||||||||||
Foreign Currency Risk |
B | | 7 | ||||||||||
Interest Rate Risk |
C | 24 | 45 | ||||||||||
Total Fair Value Positions Continuing Operations |
(10 | ) | (131 | ) | |||||||||
Total Fair Value Positions Discontinued Operations |
(69 | ) | (104 | ) | |||||||||
$ | (79 | ) | $ | (235 | ) | ||||||||
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
A) Commodity Price Risk
Natural Gas
At December 31, 2004 the gas risk management activities from financial contracts had an unrealized gain of $36 million and a fair market value position of $107 million. The contracts were as follows:
Notional Volumes (MMcf/d) |
Term | Average Price |
Fair Market Value |
|||||||||||||||||
Sales Contracts |
||||||||||||||||||||
Fixed Price Contracts |
||||||||||||||||||||
NYMEX Fixed Price |
481 | 2005 | 6.72 | US$/Mcf | $ | 81 | ||||||||||||||
Colorado Interstate Gas (CIG) |
113 | 2005 | 4.87 | US$/Mcf | (27 | ) | ||||||||||||||
Other |
110 | 2005 | 5.21 | US$/Mcf | (23 | ) | ||||||||||||||
NYMEX Fixed Price |
525 | 2006 | 5.66 | US$/Mcf | (105 | ) | ||||||||||||||
Colorado Interstate Gas (CIG) |
100 | 2006 | 4.44 | US$/Mcf | (37 | ) | ||||||||||||||
Other |
171 | 2006 | 4.85 | US$/Mcf | (59 | ) | ||||||||||||||
Collars and Other Options |
||||||||||||||||||||
Purchased NYMEX Put Options |
906 | 2005 | 5.46 | US$/Mcf | 29 | |||||||||||||||
Other |
5 | 2005 | 4.57 - 7.23 | US$/Mcf | | |||||||||||||||
NYMEX 3-Way Call Spread |
180 | 2005 | 5.00/6.69/7.69 | US$/Mcf | (13 | ) | ||||||||||||||
Purchased NYMEX Put Options |
210 | 2006 | 5.00 | US$/Mcf | 5 | |||||||||||||||
Basis Contracts |
||||||||||||||||||||
Fixed NYMEX to AECO basis |
877 | 2005 | (0.66 | ) | US$/Mcf | 70 | ||||||||||||||
Fixed NYMEX to Rockies basis |
268 | 2005 | (0.49 | ) | US$/Mcf | 19 | ||||||||||||||
Other |
442 | 2005 | (0.47 | ) | US$/Mcf | 4 | ||||||||||||||
Fixed NYMEX to AECO basis |
703 | 2006 | (0.65 | ) | US$/Mcf | 41 | ||||||||||||||
Fixed NYMEX to Rockies basis |
312 | 2006 | (0.57 | ) | US$/Mcf | 14 | ||||||||||||||
Fixed NYMEX to CIG basis |
279 | 2006 | (0.83 | ) | US$/Mcf | (9 | ) | |||||||||||||
Other |
182 | 2006 | (0.36 | ) | US$/Mcf | 2 | ||||||||||||||
Fixed Rockies to CIG basis |
12 | 2007 | (0.10 | ) | US$/Mcf | | ||||||||||||||
Fixed NYMEX to AECO basis |
345 | 2007-2008 | (0.65 | ) | US$/Mcf | 17 | ||||||||||||||
Fixed NYMEX to Rockies basis |
248 | 2007-2008 | (0.57 | ) | US$/Mcf | 14 | ||||||||||||||
Fixed NYMEX to CIG basis |
110 | 2007-2009 | (0.68 | ) | US$/Mcf | 5 | ||||||||||||||
Purchase Contracts |
||||||||||||||||||||
Fixed Price
Contract Waha Purchase |
27 | 2005 | 5.90 | US$/Mcf | (2 | ) | ||||||||||||||
Fixed Price
Contract Waha Purchase |
23 | 2006 | 5.32 | US$/Mcf | 3 | |||||||||||||||
29 | ||||||||||||||||||||
Gas Storage Optimization Financial Positions |
2 | |||||||||||||||||||
Gas Marketing Financial Positions (1) |
5 | |||||||||||||||||||
Total Unrealized Gain on Financial Contracts |
36 | |||||||||||||||||||
Premiums Paid on Options |
71 | |||||||||||||||||||
Total Fair Value Positions |
$ | 107 | ||||||||||||||||||
(1) | The gas marketing activities are part of the daily ongoing operations of the Companys proprietary production management. |
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Crude Oil
As at December 31, 2004, the Companys oil risk management activities from all financial contracts had an unrealized loss of $251 million and a fair market value position of $(212) million. The contracts were as follows:
Notional | Fair | |||||||||||||||
Volumes | Average | Market | ||||||||||||||
(bbls/d) | Term | Price | Value | |||||||||||||
Fixed WTI NYMEX Price |
41,000 | 2005 | 28.41 | $ | (209 | ) | ||||||||||
Costless 3-Way Put Spread |
9,000 | 2005 | 20.00/25.00/28.78 | (45 | ) | |||||||||||
Unwind WTI NYMEX Fixed Price |
(4,500 | ) | 2005 | 35.90 | 11 | |||||||||||
Purchased WTI NYMEX Call Options |
(38,000 | ) | 2005 | 49.76 | 13 | |||||||||||
Purchased WTI NYMEX Put Options |
35,000 | 2005 | 40.00 | 13 | ||||||||||||
Fixed WTI NYMEX Price |
15,000 | 2006 | 34.56 | (31 | ) | |||||||||||
Purchased WTI NYMEX Put Options |
22,000 | 2006 | 27.36 | (2 | ) | |||||||||||
(250 | ) | |||||||||||||||
Crude Oil Marketing Financial Positions(1) |
(1 | ) | ||||||||||||||
Total Unrealized Loss on Financial Contracts |
(251 | ) | ||||||||||||||
Premiums Paid on Options |
39 | |||||||||||||||
Total Fair Value Positions |
$ | (212 | ) | |||||||||||||
Total Fair Value Positions Continuing Operations |
$ | (143 | ) | |||||||||||||
Total Fair Value Positions Discontinued Operations |
(69 | ) | ||||||||||||||
$ | (212 | ) | ||||||||||||||
(1) | The crude oil marketing activities are part of the daily ongoing operations of the Companys proprietary production management. |
Power
EnCana has one electricity contract which expires in 2005. The contract was entered into as part of an electricity cost management strategy. At December 31, 2004, the unrealized gain on the contract was $2 million.
B) Foreign Currency Risk
Foreign currency risk is the risk that a variation in exchange rates between the Canadian dollar and foreign currencies will affect the Companys operating and financial results. The Company has significant operations outside of Canada, which are subject to these foreign exchange risks.
No forward foreign currency exchange contracts were in place to hedge future commodity revenue streams as at December 31, 2004.
C) Interest Rate Risk
The Company has entered into various derivative contracts to manage the Companys interest rate exposure on debt instruments. The impact of these transactions is described in Note 7.
42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
The unrealized gains on the outstanding financial instruments as at December 31, 2004 were as follows:
Unrealized | ||||
Gain | ||||
5.80% Medium Term Notes |
$ | 11 | ||
7.50% Medium Term Notes |
5 | |||
8.75% Debenture |
8 | |||
$ | 24 | |||
At December 31, 2004, the increase or decrease in net earnings for each one percent change in interest rates on floating rate debt amounts to $13 million (2003 $14 million).
D) Fair Value of Financial Assets and Liabilities
The fair values of financial instruments not recorded at their fair values that are included in the Consolidated Balance Sheet, other than long-term borrowings, approximate their carrying amount due to the short-term maturity of those instruments.
The estimated fair values of long-term borrowings have been determined based on market information where available, or by discounting future payments of interest and principal at estimated interest rates that would be available to the Company at year end.
As at December 31 | 2004 | 2003 | |||||||||||||||
Carrying | Fair | Carrying | Fair | ||||||||||||||
Amount | Value | Amount | Value | ||||||||||||||
Financial Assets |
|||||||||||||||||
Cash and cash equivalents |
$ | 602 | $ | 602 | $ | 113 | $ | 113 | |||||||||
Accounts receivable |
1,898 | 1,898 | 1,165 | 1,165 | |||||||||||||
Financial Liabilities |
|||||||||||||||||
Accounts payable, income taxes payable |
$ | 2,238 | $ | 2,238 | $ | 1,380 | $ | 1,380 | |||||||||
Long-term debt |
7,930 | 8,479 | 6,375 | 6,767 | |||||||||||||
E) Credit Risk
A substantial portion of the Companys accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. The Board has approved a credit policy governing the Companys credit portfolio and procedures are in place to ensure adherence to this policy. With respect to counterparties to financial instruments, the Company partially mitigates associated credit risk by limiting transactions to counterparties with investment grade credit ratings.
All foreign currency agreements are with major financial institutions in Canada and the United States or with counterparties having investment grade credit ratings.
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
NOTE 18. SUPPLEMENTARY INFORMATION
A) Per Share Amounts
The following table summarizes the Common Shares used in calculating Net Earnings and Cash Flow per Common Share.
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Weighted
Average Common Shares Outstanding Basic |
460.4 | 474.1 | 417.8 | |||||||||||
Effect of Stock Options and Other Dilutive Securities |
7.6 | 5.6 | 4.8 | |||||||||||
Weighted
Average Common Shares Outstanding Diluted |
468.0 | 479.7 | 422.6 | |||||||||||
B) Net Change in Non-Cash Working Capital from Continuing Operations
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Operating Activities |
||||||||||||||
Accounts receivable and accrued revenues |
$ | 665 | $ | (107 | ) | $ | (276 | ) | ||||||
Inventories |
14 | (241 | ) | (64 | ) | |||||||||
Accounts payable and accrued liabilities |
601 | (252 | ) | (14 | ) | |||||||||
Income taxes payable |
175 | 32 | (535 | ) | ||||||||||
$ | 1,455 | $ | (568 | ) | $ | (889 | ) | |||||||
Investing Activities |
||||||||||||||
Accounts payable and accrued liabilities |
$ | (21 | ) | $ | (113 | ) | $ | 195 | ||||||
C) Supplementary Cash Flow Information Continuing Operations
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Interest Paid |
$ | 401 | $ | 284 | $ | 261 | ||||||||
Income Taxes Paid (Received) |
$ | 148 | $ | (127 | ) | $ | 567 | |||||||
NOTE 19. COMMITMENTS AND CONTINGENCIES
Commitments
As at December 31, 2004 | 2005 | 2006 | 2007 | 2008 | 2009 | Thereafter | Total | |||||||||||||||||||||||||||
Pipeline Transportation |
$ | 297 | $ | 262 | $ | 237 | $ | 220 | $ | 182 | $ | 1,010 | $ | 2,208 | ||||||||||||||||||||
Purchases of Goods and Services |
121 | 23 | 14 | 9 | 3 | 5 | 175 | |||||||||||||||||||||||||||
Product Purchases |
171 | 32 | 25 | 24 | 24 | 134 | 410 | |||||||||||||||||||||||||||
Operating Leases |
42 | 43 | 41 | 36 | 29 | 152 | 343 | |||||||||||||||||||||||||||
Capital Commitments |
190 | 41 | 22 | 4 | | 38 | 295 | |||||||||||||||||||||||||||
Total |
$ | 821 | $ | 401 | $ | 339 | $ | 293 | $ | 238 | $ | 1,339 | $ | 3,431 | ||||||||||||||||||||
Product Sales |
$ | 502 | $ | 56 | $ | 58 | $ | 61 | $ | 33 | $ | 275 | $ | 985 | ||||||||||||||||||||
In addition to the above, the Company has made commitments related to its risk management program (see Note 17).
44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Contingencies
Legal Proceedings
The Company is involved in various legal claims associated with the normal course of operations. The Company believes it has made adequate provision for such legal claims.
Discontinued Merchant Energy Operations
In July 2003, the Companys indirect wholly owned U.S. marketing subsidiary, WD Energy Services Inc. (WD), concluded a settlement with the U.S. Commodity Futures Trading Commission (CFTC) of a previously disclosed CFTC investigation. The investigation related to alleged inaccurate reporting of natural gas trading information during 2000 and 2001 by former employees of WDs now discontinued Houston-based merchant energy trading operation to energy industry publications that compiled and reported index prices. All Houston-based merchant energy trading operations were discontinued following the merger with Alberta Energy Company Ltd. in 2002. Under the terms of the settlement, WD agreed to pay a civil monetary penalty in the amount of $20 million without admitting or denying the findings in the CFTCs order.
The Company and WD are defendants in a lawsuit filed by E. & J. Gallo Winery in the United States District Court in California and, along with other energy companies, are defendants in several other lawsuits in California (many of which are class actions) and three class action lawsuits filed in the United States District Court in New York. A motion by the Company and WD to dismiss the Gallo complaint on the basis that the Federal Energy Regulatory Commission had exclusive jurisdiction regarding this matter was not granted. The Gallo complaint claims damages in excess of $30 million, before potential trebling under California laws.
Most of the California class action lawsuits were transferred by the Judicial Panel on Multidistrict Litigation on a consolidated basis to the Nevada District Court and all of the New York lawsuits were consolidated in New York District Court by the plaintiffs application. The Nevada District Court has remanded the California State Court cases back to the California State Court for hearing. The California lawsuits relate to sales of natural gas in California from 1999 to the present and contain allegations that the defendants engaged in a conspiracy with unnamed competitors in the natural gas and derivatives market in California in violation of U.S. and California anti-trust and unfair competition laws to artificially raise the price of natural gas through various means including the illegal sharing of price information through online trading, price indices and wash trading. The New York lawsuits claim that the defendants alleged manipulation of natural gas price indices resulted in higher prices of natural gas futures and option contracts traded on the NYMEX from 2000 to 2002. EnCana Corporation has been dismissed from the New York lawsuits, leaving only WD and several other companies unrelated to EnCana as the remaining defendants. As is customary, the class actions do not specify the amount of damages claimed.
The Company and WD intend to vigorously defend against these claims; however, the Company cannot predict the outcome of these proceedings or any future proceedings against the Company, whether these proceedings would lead to monetary damages which could have a material adverse effect on the Companys financial position, or whether there will be other proceedings arising out of these allegations.
Asset Retirement
The Company is responsible for the retirement of long-lived assets related to its oil and gas properties and Midstream facilities at the end of their useful lives. The Company has recognized a liability of $611 million based on current legislation and estimated costs. Actual costs may differ from those estimated due to changes in legislation and changes in costs.
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
Income Tax Matters
The operations of the Company are complex, and related tax interpretations, regulations and legislation in the various jurisdictions that the Company operates in are continually changing. As a result, there are usually some tax matters under review. The Company believes that the provision for taxes is adequate.
NOTE 20. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING
The Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in Canada (Canadian GAAP) which, in most respects, conform to accounting principles generally accepted in the United States (U.S. GAAP). The significant differences between Canadian and U.S. GAAP are described in this note.
RECONCILIATION OF NET EARNINGS UNDER CANADIAN GAAP TO U.S. GAAP
For the years ended December 31 | Note | 2004 | 2003 | 2002 | ||||||||||||||
Net Earnings Canadian GAAP |
$ | 3,513 | $ | 2,360 | $ | 812 | ||||||||||||
Less: |
||||||||||||||||||
Net Earnings
From Discontinued Operations Canadian GAAP |
1,302 | 218 | 146 | |||||||||||||||
Net Earnings From Continuing Operations Canadian GAAP |
2,211 | 2,142 | 666 | |||||||||||||||
Increase (Decrease) under U.S. GAAP: |
||||||||||||||||||
Revenues, net of royalties |
B | 243 | (101 | ) | (174 | ) | ||||||||||||
Operating |
B | (3 | ) | | | |||||||||||||
Depreciation, depletion and amortization |
A,G | 31 | 14 | (41 | ) | |||||||||||||
Interest, net |
B | (41 | ) | 70 | 126 | |||||||||||||
Accretion of asset retirement obligation |
G | | | 13 | ||||||||||||||
Stock-based compensation |
C | (5 | ) | (1 | ) | (3 | ) | |||||||||||
Income tax expense |
E,G | (73 | ) | 7 | 21 | |||||||||||||
Net Earnings From Continuing Operations U.S. GAAP |
2,363 | 2,131 | 608 | |||||||||||||||
Net Earnings From Discontinued Operations U.S. GAAP |
1,370 | 152 | 146 | |||||||||||||||
Net Earnings Before Change in Accounting Policy U.S. GAAP |
3,733 | 2,283 | 754 | |||||||||||||||
Cumulative Effect of Change in Accounting Policy, net of tax |
G | | 66 | | ||||||||||||||
Net Earnings
U.S. GAAP |
$ | 3,733 | $ | 2,349 | $ | 754 | ||||||||||||
Net Earnings
per Common Share Before Change in Accounting Policy U.S. GAAP |
||||||||||||||||||
Basic |
$ | 8.11 | $ | 4.82 | $ | 1.81 | ||||||||||||
Diluted |
$ | 7.98 | $ | 4.76 | $ | 1.78 | ||||||||||||
Net Earnings per Common Share Including Cumulative Effect
of Change in Accounting Policy U.S. GAAP |
||||||||||||||||||
Basic |
$ | 8.11 | $ | 4.95 | $ | 1.81 | ||||||||||||
Diluted |
$ | 7.98 | $ | 4.90 | $ | 1.78 | ||||||||||||
46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
CONSOLIDATED STATEMENT OF EARNINGS U.S. GAAP
For the years ended December 31 | Note | 2004 | 2003 | 2002 | ||||||||||||||
Revenues, Net of Royalties |
B | $ | 12,053 | $ | 9,585 | $ | 5,754 | |||||||||||
Expenses |
||||||||||||||||||
Production and mineral taxes |
311 | 164 | 105 | |||||||||||||||
Transportation and selling |
499 | 484 | 332 | |||||||||||||||
Operating |
B | 1,353 | 1,196 | 749 | ||||||||||||||
Purchased product |
4,276 | 3,455 | 2,200 | |||||||||||||||
Depreciation, depletion and amortization |
A,G | 2,371 | 1,975 | 1,227 | ||||||||||||||
Administrative |
C | 197 | 173 | 121 | ||||||||||||||
Interest, net |
B | 438 | 213 | 160 | ||||||||||||||
Accretion of asset retirement obligation |
G | 22 | 17 | | ||||||||||||||
Foreign exchange gain |
(417 | ) | (598 | ) | (11 | ) | ||||||||||||
Stock-based compensation |
22 | 19 | | |||||||||||||||
Gain on dispositions |
(113 | ) | (1 | ) | (33 | ) | ||||||||||||
Net Earnings Before Income Tax |
3,094 | 2,488 | 904 | |||||||||||||||
Income tax expense |
E | 731 | 357 | 296 | ||||||||||||||
Net Earnings From Continuing Operations U.S. GAAP |
2,363 | 2,131 | 608 | |||||||||||||||
Net Earnings From Discontinued Operations U.S. GAAP |
A,B | 1,370 | 152 | 146 | ||||||||||||||
Net Earnings Before Change in Accounting Policy U.S. GAAP |
3,733 | 2,283 | 754 | |||||||||||||||
Cumulative Effect of Change in Accounting Policy, net of tax |
G | | 66 | | ||||||||||||||
Net Earnings U.S. GAAP |
$ | 3,733 | $ | 2,349 | $ | 754 | ||||||||||||
Net Earnings From Continuing Operations per Common Share
U.S. GAAP |
||||||||||||||||||
Basic |
$ | 5.13 | $ | 4.49 | $ | 1.46 | ||||||||||||
Diluted |
$ | 5.05 | $ | 4.44 | $ | 1.44 | ||||||||||||
Net Earnings
per Common Share Before Change in Accounting Policy U.S. GAAP |
||||||||||||||||||
Basic |
$ | 8.11 | $ | 4.82 | $ | 1.81 | ||||||||||||
Diluted |
$ | 7.98 | $ | 4.76 | $ | 1.78 | ||||||||||||
Net Earnings per Common Share Including Cumulative Effect
of Change in Accounting Policy U.S. GAAP |
||||||||||||||||||
Basic |
$ | 8.11 | $ | 4.95 | $ | 1.81 | ||||||||||||
Diluted |
$ | 7.98 | $ | 4.90 | $ | 1.78 | ||||||||||||
STATEMENT OF OTHER COMPREHENSIVE INCOME
For the years ended December 31 | Note | 2004 | 2003 | 2002 | ||||||||||||||
Net Earnings U.S. GAAP |
$ | 3,733 | $ | 2,349 | $ | 754 | ||||||||||||
Change in Fair Value of Financial Instruments |
B,F | | 4 | (7 | ) | |||||||||||||
Foreign Currency Translation Adjustment |
D | 420 | 1,046 | 136 | ||||||||||||||
Other |
| 6 | (6 | ) | ||||||||||||||
Other Comprehensive Income |
$ | 4,153 | $ | 3,405 | $ | 877 | ||||||||||||
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
CONDENSED CONSOLIDATED BALANCE SHEET
As at December 31 | 2004 | 2003 | |||||||||||||||||||||
Note | As reported | U.S. GAAP | As reported | U.S. GAAP | |||||||||||||||||||
Assets |
|||||||||||||||||||||||
Current Assets |
A,B | $ | 3,505 | $ | 3,497 | $ | 2,616 | $ | 2,676 | ||||||||||||||
Property, Plant and Equipment, net |
A,G | 23,140 | 23,044 | 17,770 | 17,644 | ||||||||||||||||||
Investments and Other Assets |
B | 334 | 330 | 268 | 271 | ||||||||||||||||||
Risk Management |
B | 87 | 87 | | 85 | ||||||||||||||||||
Assets of Discontinued Operations |
1,623 | 1,623 | 1,545 | 1,545 | |||||||||||||||||||
Goodwill |
2,524 | 2,524 | 1,911 | 1,911 | |||||||||||||||||||
$ | 31,213 | $ | 31,105 | $ | 24,110 | $ | 24,132 | ||||||||||||||||
Liabilities and Shareholders Equity |
|||||||||||||||||||||||
Current Liabilities |
A,B | $ | 2,947 | $ | 2,942 | $ | 2,072 | $ | 2,435 | ||||||||||||||
Long-Term Debt |
7,742 | 7,742 | 6,088 | 6,088 | |||||||||||||||||||
Other Liabilities |
B | 118 | 64 | 21 | 8 | ||||||||||||||||||
Risk Management |
B | 192 | 192 | | 10 | ||||||||||||||||||
Asset Retirement Obligation |
G | 611 | 611 | 383 | 383 | ||||||||||||||||||
Liabilities of Discontinued Operations |
A,B | 102 | 102 | 112 | 82 | ||||||||||||||||||
Future Income Taxes |
E,G | 5,193 | 5,118 | 4,156 | 4,054 | ||||||||||||||||||
16,905 | 16,771 | 12,832 | 13,060 | ||||||||||||||||||||
Share Capital |
C | 5,299 | 5,316 | 5,305 | 5,318 | ||||||||||||||||||
Share Options, net |
10 | 10 | 55 | 55 | |||||||||||||||||||
Paid in Surplus |
28 | 28 | 18 | 18 | |||||||||||||||||||
Retained Earnings |
7,935 | 7,955 | 5,276 | 5,076 | |||||||||||||||||||
Foreign Currency Translation Adjustment |
D | 1,036 | | 624 | | ||||||||||||||||||
Accumulated Other Comprehensive Income |
| 1,025 | | 605 | |||||||||||||||||||
14,308 | 14,334 | 11,278 | 11,072 | ||||||||||||||||||||
$ | 31,213 | $ | 31,105 | $ | 24,110 | $ | 24,132 | ||||||||||||||||
The following table summarizes the assets and liabilities of discontinued operations included in current assets and current liabilities:
As at December 31 | 2004 | 2003 | |||||||||||||||||||||
Note | As reported | U.S. GAAP | As reported | U.S. GAAP | |||||||||||||||||||
Assets of Discontinued Operations |
A,B | $ | 156 | $ | 159 | $ | 781 | $ | 781 | ||||||||||||||
Liabilities of Discontinued Operations |
A,B | 280 | 315 | 405 | 500 | ||||||||||||||||||
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS U.S. GAAP
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Operating Activities |
||||||||||||||
Net earnings from continuing operations |
$ | 2,363 | $ | 2,131 | $ | 608 | ||||||||
Depreciation, depletion and amortization |
2,371 | 1,975 | 1,227 | |||||||||||
Future income taxes |
164 | 470 | 362 | |||||||||||
Unrealized (gain) loss on risk management |
(15 | ) | 31 | 48 | ||||||||||
Unrealized foreign exchange gain |
(285 | ) | (545 | ) | (23 | ) | ||||||||
Accretion of asset retirement obligation |
22 | 17 | | |||||||||||
Gain on dispositions |
(113 | ) | (1 | ) | | |||||||||
Other |
98 | 57 | (163 | ) | ||||||||||
Cash flow from discontinued operations |
375 | 324 | 360 | |||||||||||
Net change in other assets and liabilities |
(176 | ) | (84 | ) | (17 | ) | ||||||||
Net change in non-cash working capital from continuing operations |
1,455 | (568 | ) | (889 | ) | |||||||||
Net change in non-cash working capital from discontinued
operations |
(1,668 | ) | 497 | 104 | ||||||||||
Cash From Operating Activities |
$ | 4,591 | $ | 4,304 | $ | 1,617 | ||||||||
Cash Used in Investing Activities |
$ | (4,259 | ) | $ | (3,729 | ) | $ | (2,595 | ) | |||||
Cash From (Used in) Financing Activities |
$ | 163 | $ | (542 | ) | $ | 498 | |||||||
Notes:
A) Full Cost Accounting
The full cost method of accounting for crude oil and natural gas operations under Canadian and U.S. GAAP differ in the following respects. Under U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum of the present value, discounted at 10 percent, of the estimated unescalated future net operating revenue from proved reserves plus unimpaired unproved property costs less future development costs, related production costs and applicable taxes. Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that cash flows from proved reserves are undiscounted and utilize forecast pricing to determine whether impairment exists. Any impairment amount is measured using the fair value of proved and probable reserves.
In computing its consolidated net earnings for U.S. GAAP purposes, the Company recorded additional depletion in 2001 and certain years prior to 2001 as a result of the application of the ceiling test. These charges were not required under the Canadian GAAP ceiling tests. As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes.
Effective January 1, 2004, the Canadian Accounting Standards Board amended the Full Cost Accounting Guideline. Under Canadian GAAP, depletion charges are calculated by reference to proved reserves estimated using estimated future prices and costs. Under U.S. GAAP, depletion charges are calculated by reference to proved reserves estimated using constant prices.
B) Derivative Instruments and Hedging
On January 1, 2004, the Company implemented under Canadian GAAP, EIC 128 Accounting For Trading, Speculative or Non-Hedging Derivative Financial Instruments which requires derivatives not designated as hedges to be recorded in the balance sheet as either assets or liabilities at their fair value. Changes in the derivatives fair value are recognized in current period earnings. Under the transitional rules any gain or loss at the implementation date is deferred and recognized into revenue
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
once realized. Currently, Management has not designated any of the financial instruments as hedges.
The adoption of EIC 128 at January 1, 2004 resulted in the recognition of a $235 million deferred loss which will be recognized into earnings when realized. As at December 31, 2004, under Canadian GAAP a $72 million deferred gain remains, of which a $1 million deferred loss has been classified in liabilities of discontinued operations.
For U.S. GAAP, the Company adopted Statement of Financial Accounting Standards (FAS) 133 effective January 1, 2001. FAS 133 requires that all derivatives be recorded in the balance sheet as either assets or liabilities at their fair value. Changes in the derivatives fair value are recognized in current period earnings unless specific hedge accounting criteria are met. Management has currently not designated any of the financial instruments as hedges for U.S. GAAP purposes under FAS 133.
Realized and unrealized gain/(loss) on derivatives related to:
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Commodity Prices (Revenues, net of royalties) |
$ | 76 | $ | (205 | ) | $ | (174 | ) | ||||||
Interest and Currency Swaps (Interest, net) |
(29 | ) | 70 | 126 | ||||||||||
Total Unrealized Gain (Loss) |
$ | 47 | $ | (135 | ) | $ | (48 | ) | ||||||
Amounts Allocated to Continuing Operations |
$ | 15 | $ | (31 | ) | $ | (48 | ) | ||||||
Amounts Allocated to Discontinued Operations |
32 | (104 | ) | | ||||||||||
$ | 47 | $ | (135 | ) | $ | (48 | ) | |||||||
As at December 31, 2004, it is estimated that over the following 12 months, $3 million ($2 million, net of tax) will be reclassified into net earnings from other comprehensive income.
C) Stock-based Compensation CPL Reorganization
Under Canadian GAAP, compensation costs have been recognized in the financial statements for stock options granted to employees and directors in 2003. For the effect of stock-based compensation on the Canadian GAAP financial statements, which would be the same adjustment under U.S. GAAP, see Note 15.
Under Financial Accounting Standards Board (FASB) Interpretation No. 44 Accounting for Certain Transactions involving Stock Compensation, compensation expense must be recorded if the intrinsic value of the stock options is not exactly the same immediately before and after an equity restructuring. As part of the corporate reorganization of Canadian Pacific Ltd., an equity restructuring occurred which resulted in CPL stock options being replaced with stock options granted by EnCana as described in Note 15. This resulted in the replacement options having a different intrinsic value after the restructuring than prior to the restructuring. Canadian GAAP does not require revaluation of these options.
D) Foreign Currency Translation Adjustments
U.S. GAAP requires gains or losses arising from the translation of self-sustaining operations to be included in other comprehensive income. Canadian GAAP requires these amounts to be recorded in Shareholders Equity.
E) Future Income Taxes
Under U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted tax rates.
50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
The future income tax adjustments included in the Reconciliation of Net Earnings under Canadian GAAP to U.S. GAAP and the Condensed Consolidated Balance Sheet include the effect of such rate differences, if any, as well as the tax effect of the other reconciling items noted.
The following table provides a reconciliation of the statutory rate to the actual tax rate:
For the years ended December 31 | 2004 | 2003 | 2002 | |||||||||||
Using Canadian GAAP: |
||||||||||||||
Net Earnings Before Income Tax |
$ | 2,869 | $ | 2,506 | $ | 983 | ||||||||
Canadian Statutory Rate |
39.1 | % | 41.0 | % | 42.3 | % | ||||||||
Expected Income Tax |
1,123 | 1,026 | 416 | |||||||||||
Effect on Taxes Resulting from: |
||||||||||||||
Non-deductible Canadian crown payments |
192 | 231 | 147 | |||||||||||
Canadian resource allowance |
(246 | ) | (258 | ) | (200 | ) | ||||||||
Canadian resource allowance on unrealized risk management losses |
(10 | ) | | | ||||||||||
Statutory and other rate differences |
(55 | ) | (45 | ) | (35 | ) | ||||||||
Effect of tax rate reductions |
(109 | ) | (359 | ) | (20 | ) | ||||||||
Non-taxable capital gains |
(91 | ) | (119 | ) | | |||||||||
Previously unrecognized capital losses |
17 | (119 | ) | | ||||||||||
Tax basis retained on dispositions |
(179 | ) | | | ||||||||||
Large corporations tax |
24 | 27 | 23 | |||||||||||
Other |
(8 | ) | (20 | ) | (14 | ) | ||||||||
658 | 364 | 317 | ||||||||||||
U.S. GAAP Adjustments to Net Earnings Before Income Tax |
225 | (18 | ) | (79 | ) | |||||||||
Expected Income Tax |
88 | (7 | ) | (33 | ) | |||||||||
Other |
(15 | ) | | 12 | ||||||||||
73 | (7 | ) | (21 | ) | ||||||||||
Income Tax U.S. GAAP |
$ | 731 | $ | 357 | $ | 296 | ||||||||
Effective Tax Rate |
23.6 | % | 14.3 | % | 32.7 | % | ||||||||
The net future income tax liability is comprised of:
As at December 31 | 2004 | 2003 | |||||||
Future Tax Liabilities |
|||||||||
Property, plant and equipment in excess of tax values |
$ | 4,436 | $ | 3,152 | |||||
Timing of partnership items |
1,005 | 1,162 | |||||||
Future Tax Assets |
|||||||||
Net operating losses carried forward |
(103 | ) | (99 | ) | |||||
Other |
(220 | ) | (161 | ) | |||||
Net Future Income Tax Liability |
$ | 5,118 | $ | 4,054 | |||||
F) Other Comprehensive Income
U.S. GAAP requires the disclosure, as other comprehensive income, of changes in equity during the period from transaction and other events from non-owner sources. Canadian GAAP does not require similar disclosure. Other comprehensive income arose from the transition adjustment resulting from the January 1, 2001 adoption of FAS 133. At December 31, 2004, accumulated other comprehensive income related to these items was a loss of $9 million, net of tax.
G) Asset Retirement Obligation
In 2003, the Company early adopted the Canadian accounting standard for asset retirement obligations, as outlined in the CICA handbook section 3110. This standard is equivalent to U.S. FAS
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
143 Accounting for Asset Retirement Obligations, which was effective for fiscal periods beginning on or after January 1, 2003. Early adopting the Canadian standard eliminated a U.S. GAAP reconciling item in respect to accounting for the obligation, however a difference is created in how the transition amounts are disclosed.
U.S. GAAP requires the cumulative impact of a change in an accounting policy be presented in the current year Consolidated Statement of Earnings and prior periods not be restated. The following table illustrates the pro forma impact on the Companys financial results under U.S. GAAP if the prior periods had been restated:
For the year ended December 31 | As Reported | Change | As Restated | |||||||||
2002 Consolidated Statement of Earnings |
||||||||||||
Net Earnings |
$ | 754 | $ | 34 | $ | 788 | ||||||
Net Earnings per Common Share Diluted |
$ | 1.78 | $ | 0.08 | $ | 1.86 | ||||||
H) Consolidated Statement of Cash Flows
Under U.S. GAAP, separate subtotals within cash flow from operating activities are not presented.
I) Recent Accounting Pronouncements
During 2004, the following new standards were issued:
Share-Based Payment
In 2004, FASB issued revised FAS 123 Share-Based Payment. This amended statement eliminates the alternative to use Accounting Principles Board (APB) Opinion No. 25s intrinsic value method of accounting, as was provided in the originally issued Statement 123. As a result, public entities are required to use the grant-date fair value of the award in measuring the cost of employee services received in exchange for an equity award of equity instruments. Compensation cost is required to be recognized over the requisite service period. For liability awards, entities are required to re-measure the fair value of the award at each reporting date up until the settlement date. Changes in fair value of liability awards during the requisite service period are required to be recognized as compensation cost over the vesting period. Compensation cost is not recognized for equity instruments for which employees do not render the requisite service. This amended statement is effective the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Company is currently assessing the impact of this amendment.
Exchange of Non-monetary Assets
In 2004, FASB issued FAS 153 Exchange of Non-monetary Assets. This statement is an amendment of APB Opinion No. 29 Accounting for Non-monetary Transactions. Based on the guidance in APB Opinion No. 29, exchanges of non-monetary assets are to be measured based on the fair value of the assets exchanged. Furthermore, APB Opinion No. 29 previously allowed for certain exceptions to this fair value principle. FAS 153 eliminates APB Opinion No. 29s exception to fair value for non-monetary exchanges of similar productive assets and replaces this with a general exception for exchanges of non-monetary assets which do not have commercial substance. For purposes of this statement, a non-monetary exchange is defined as having commercial substance when the future cash flows of an entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for non-monetary asset exchanges which occur in fiscal periods beginning after June 15, 2005 and are to be applied prospectively. Earlier application is permitted for non-monetary asset exchanges which occur in fiscal periods beginning after the issue date of this statement. Currently, this statement does not have an impact on EnCana;
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PREPARED USING CANADIAN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
ALL AMOUNTS IN US$ MILLIONS, UNLESS OTHERWISE INDICATED
however, this may result in a future impact to the Company if EnCana enters into any non-monetary asset exchanges.
53
ADDITIONAL DISCLOSURE
Certifications and Disclosure Regarding Controls and Procedures.
(a) | Certifications. See Exhibits 99.1 and 99.2 to this Annual Report on Form 40-F. | |||
(b) | Disclosure Controls and Procedures. As of the end of the registrants fiscal year ended December 31, 2004, an evaluation of the effectiveness of the registrants disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) was carried out by the registrants principal executive officer and principal financial officer. Based upon that evaluation, the registrants principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, the registrants disclosure controls and procedures are effective to ensure that information required to be disclosed by the registrant in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to the registrants management, including its principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. | |||
It should be noted that while the registrants principal executive officer and principal financial officer believe that the registrants disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the registrants disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. | ||||
(c) | Changes in Internal Control Over Financial Reporting. During the fiscal year ended December 31, 2004, there were no changes in the registrants internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants internal control over financial reporting. |
Notices Pursuant to Regulation BTR.
None.
Audit Committee Financial Expert.
The registrants board of directors has determined that Jane L. Peverett, a member of the registrants audit committee, qualifies as an audit committee financial expert (as such term is defined in Form 40-F).
40-F2
Code of Ethics.
The registrant has adopted a code of ethics (as that term is defined in Form 40-F), entitled the Business Conduct and Ethics Practice (the Code of Ethics), that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions (together, the Financial Supervisors).
The Code of Ethics is available for viewing on the registrants website at www.encana.com.
Since the adoption of the Code of Ethics, there have not been any amendments to the Code of Ethics or waivers, including implicit waivers, from any provision of the Code of Ethics.
Principal Accountant Fees and Services.
The required disclosure is included under the heading Audit Committee Information-External Auditor Service Fees in the registrants Annual Information Form for the fiscal year ended December 31, 2004, filed as part of this Annual Report on Form 40-F.
Pre-Approval Policies and Procedures.
The required disclosure is included under the heading Audit Committee Information-Pre-Approval Policies and Procedures in the registrants Annual Information Form for the fiscal year ended December 31, 2004, filed as part of this Annual Report on Form 40-F.
Off-Balance Sheet Arrangements.
The required disclosure is included under the heading Off-Balance Sheet Arrangements in the registrants Managements Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2004, filed as part of this Annual Report on Form 40-F.
Tabular Disclosure of Contractual Obligations.
The required disclosure is included under the heading Contractual Obligations and Contingencies in the registrants Managements Discussion and Analysis of Financial Condition and Results of Operations for the fiscal year ended December 31, 2004, filed as part of this Annual Report on Form 40-F.
Identification of the Audit Committee.
The registrant has a separately-designated standing audit committee established in accordance with section 3(a)(58)(A) of the Exchange Act. The members of the audit
40-F3
committee are: Patrick D. Daniel, William R. Fatt, Barry W. Harrison, Dale A. Lucas, Jane L. Peverett, James M. Stanford and David P. OBrien (ex officio).
Disclosure Pursuant to the Requirements of the New York Stock Exchange.
Presiding Director at Meetings of Non-Management Directors
The registrant schedules regular executive sessions in which the registrants non-management directors (as that term is defined in the rules of the New York Stock Exchange) meet without management participation. Mr. David P. OBrien serves as the presiding director (the Presiding Director) at such sessions. Each of the registrants non-management directors is unrelated as such term is used in the rules of the Toronto Stock Exchange.
Communication with Non-Management Directors
Shareholders may send communications to the registrants non-management directors by writing to the Presiding Director, c/o Kerry D. Dyte, General Counsel and Corporate Secretary, EnCana Corporation, 1800, 855 2nd Street S.W., Calgary, Alberta, Canada, T2P 2S5. Communications will be referred to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the board of directors as appropriate.
Corporate Governance Guidelines
According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics. Such guidelines are required to be posted on the listed companys website. The registrant operates under corporate governance principles that are consistent with the requirements of Section 303A.09 of the NYSE Listed Company Manual, and which are described under the heading Statement of Corporate Governance Practices in the registrants Information Circular in connection with its 2005 Annual Meeting. However, the registrant has not codified its corporate governance principles into formal guidelines in order to post them on its website.
Board Committee Mandates
The Mandates of the registrants audit committee, human resources and compensation committee, and nominating and corporate governance committee are each available for viewing on the registrants website at www.encana.com, and are available in print to any shareholder who requests them. Requests for copies of these documents should be made by contacting: Kerry D. Dyte, General Counsel and Corporate Secretary, EnCana Corporation, 1800, 855-2nd Street S.W., P.O. Box 2850, Calgary, Alberta, Canada T2P 2S5. Alternatively, requests for these documents may be made by contacting the registrants Corporate Development Department at (403) 645-2000 (Fax: (403) 645-4617).
40-F4
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
A. Undertaking.
The registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Securities and Exchange Commission (the Commission) staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.
B. Consent to Service of Process.
The Company has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.
Any change to the name or address of the agent for service of process of the registrant shall be communicated promptly to the Securities and Exchange Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.
SIGNATURES
Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 25, 2005.
EnCana Corporation | ||
By: /s/ Thomas G. Hinton | ||
Name: Thomas G. Hinton | ||
Title: Treasurer | ||
By: /s/ Gerald T. Ince | ||
Name: Gerald T. Ince | ||
Title: Assistant Treasurer |
40-F5
EXHIBIT INDEX
Exhibit | Description | |
99.1
|
Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 | |
99.2
|
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14 of the Securities Exchange Act of 1934 | |
99.3
|
Section 1350 Certification of Chief Executive Officer | |
99.4
|
Section 1350 Certification of Chief Financial Officer | |
99.5
|
Consent of PricewaterhouseCoopers LLP | |
99.6
|
Consent of McDaniel & Associates Consultants Ltd. | |
99.7
|
Consent of Netherland, Sewell & Associates, Inc. | |
99.8
|
Consent of DeGolyer and MacNaughton | |
99.9
|
Consent of Gilbert Laustsen Jung Associates Ltd. |